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November 13, 2024

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Brattle Study Finds EDAM Gains, Markets+ Losses for BPA, Pacific NW

The Bonneville Power Administration would earn $65 million in annual benefits from joining CAISO’s Extended Day-Ahead Market but face $83 million in increased yearly costs from participating in SPP’s Markets+, according to a new Brattle Group study that is sure to further inflame the ongoing debate over day-ahead markets in the West.

The BPA Day-Ahead Market Participation Benefits Study, which examines scenarios for 2032, extends similar findings to the rest of the Pacific Northwest (PNW) system.

“We find that if most of the Pacific Northwest, including BPA, joined EDAM, customers in the region would see a cost reduction of $430 million per year,” Brattle Principal John Tsoukalis, lead author of the study, said in an Oct. 9 press release accompanying the study.

By contrast, PNW net system costs would collectively increase by $18 million under a situation in which most of the region’s entities participate in Markets+, Brattle found.

In the study, the PNW system includes BPA, Avista, PacifiCorp’s West balancing authority area, Portland General Electric (PGE), Puget Sound Energy, Seattle City Light and the numerous public utility districts that largely rely on BPA for low-cost power to serve electricity customers in mostly rural areas of Oregon and Washington.

The report is the latest in the series of Western day-ahead market studies performed by Brattle, the most recent being a white paper comparing key features of the EDAM and Markets+. (See Brattle Study Likely to Fuel Debate over EDAM, Markets+.) It was not commissioned by BPA, but rather by a group of Northwest-based EDAM proponents, including the Northwest & Intermountain Power Producers Coalition (NIPPC), NW Energy Coalition (NWEC), PNGC Power and Renewable Northwest, as well as GridLab.

Those organizations have been firmly in the camp of electricity sector stakeholders who have argued that the West must create a market with the largest possible footprint — and that pointedly includes CAISO — to allow participants to fully tap the “diversity benefit” of resources and loads that would become available from such an arrangement. The Brattle BPA study throws its weight behind that argument.

“The key benefit differentiator in customer cost savings between the two markets is the diversity of the generation resource mix available in an EDAM footprint, which includes the Pacific Northwest as well as parts of the Southwest,” Brattle said in its press release.

Study Structure

The BPA study participants included the Balancing Authority of Northern California, El Paso Electric, Idaho Power, Los Angeles Department of Water and Power, NV Energy, PGE, PacifiCorp, Public Service Company of New Mexico, Sacramento Municipal Utility District and other utilities, transmission owners and independent power producers.

Those participants “helped refine our model by performing full reviews of relevant modeling assumptions including transmission rights, transmission costs, load forecasts, fuel prices, generation mix and costs, etc.,” Brattle said, calling out PacifiCorp and PGE among the “several” reviewers that “were able to provide details relevant to BPA’s system.”

Brattle worked with the Northwest Power and Conservation Council to fine-tune its flexibility modeling of BPA’s hydroelectric system, assuming the federal power agency’s ability to dispatch its fleet would be the same across all market scenarios.

The BPA study was conducted “using a nodal production cost model of the [Western Interconnection] with added markets, transmission rights and contract-path trading functionality.” It chose 2032 as the study year “to reflect the first decade of markets operations, representing an intermediate year that captures known changes in resource mix and transmission infrastructure.”

The study models a “business as usual” (BAU) case that reflects current utility participation in markets and the known decisions on day-ahead markets (all for EDAM at this point), as well as two “market participation” cases. In the Markets+ case, BPA and almost all utilities presently uncommitted to a day-ahead market join the SPP market, while an EDAM case shows all existing Western Energy Imbalance Market (WEIM) participants either remaining in that market or joining EDAM.

The study also models two extreme weather events, each based on a historic cold snap and heat wave.

“These events are modeled as single weeks in which we increase modeled loads (peak and energy) and gas prices, including gas price volatility beyond typical weather-normalized values to reflect the increased strain on the system and the ability of markets for addressing such strain,” the study said.

The study’s transmission assumptions include a “detailed view of the physical transmission system and long-term (contractual) transmission rights”; multiple trade type options between BAAs; and “GHG unit-type-specific trading structure which closely mimics the unit-specific GHG import tracking and charge structures in the EDAM and Markets+ designs.” It also assumes participants will make all their transmission available to the market, except where study participants have called out specific carveouts.

‘Key Differentiators’

BPA’s $65 million estimated benefit from participating in EDAM came down to two key factors, Brattle said.

The first is the expectation that BPA will reduce its adjusted production costs (APC) by $43 million in the CAISO market because of increased sales revenues stemming from higher prices in EDAM during the hours when the agency usually sells power.

The second factor is a projected increase in BPA’s congestion revenue from zero in the BAU case to $166 million in EDAM, a product of “the amount of transmission BPA brings to the market, its advantageous position in the EDAM footprint, and price deltas between” California and the Pacific Northwest.

While the study found that BPA’s congestion would average about $4/MWh in both markets, the agency’s congestion revenues in EDAM would be double those of Markets+ because of its higher trading volumes in the CAISO-run market.

On the downside, Brattle found BPA’s EDAM benefits would be partially offset by a $114 million loss in bilateral trading revenues and $37 million loss (to $2 million) in short-term wheeling revenues — the outcome of declining bilateral activity.

“Bilateral trading revenue falls more in [the] EDAM [case] as almost all of BPA’s trading partners are in the EDAM,” the study found.

In the Markets+ case, BPA’s increased costs stem in part from a projected $87 million drop in bilateral trading revenues, the result of many — although not all — BPA trading partners joining the agency in the market.

But the key difference between the two cases relates to production costs. In Markets+, BPA’s APC is projected to increase by $72 million because of slightly lower prices in that market during some intervals when the agency sells its power.

“The impact on prices is mostly in overnight hours, driven by the higher opportunity for increased thermal resource dispatch efficiency during these hours in the Markets+ footprint relative to the EDAM or BAU cases, which is driven by higher gas prices in the Pacific Northwest compared to the Southwest and Rocky Mountain regions,” the study said, adding that the opportunity for that kind of dispatch efficiency isn’t available under BAU because of “trading hurdles” between the Northwest, Southwest and Rockies region.

“The increased thermal dispatch efficiency and lower prices in the Markets+ footprint benefit net buyers in the PNW through reduced purchase costs but reduces sale revenues to the detriment of net sellers in the PNW such as BPA.”

On the plus side, Markets+ would increase BPA’s congestion revenues by $88 million, while short-term wheeling revenues would remain nearly flat, at an estimated $38.9 million.

“Market congestion, bilateral trading revenues, short-term wheeling revenues, and APC savings are the key differentiators of BPA’s net benefits between EDAM and Markets+,” the study said.

PNW Findings

The Brattle finding that EDAM’s benefits for the full PNW system would far outpace those of Markets+ could be the most significant point of the study for many in the region. It could also stir the most controversy in the debate over the two markets.

The study found that the $430 million in savings in EDAM derive from a $171 million reduction in APC, “driven mainly by higher sales revenues in EDAM for the region” and $651 million in EDAM congestion revenues. Those benefits would be offset by a $283 million decline in bilateral trading revenues and a $66 million loss in short-term wheeling revenues.

The cost increase for the Northwest under the Markets+ case was largely attributed to lower sales revenues, which left the region’s APC net of revenues $18 million higher than in the BAU case.

Reached for comment, BPA spokesperson Doug Johnson said, “BPA did not participate in and has not yet reviewed the study. We will attend the Oct. 17 webinar hosted by the study’s authors and will comment on the results after we better understand the study’s methodology, inputs and findings.”

SPP spokesperson Meghan Sever said the RTO was preparing a statement on the Brattle study.

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NYPA Enters Renewable Development with 3.5-GW Plan

The New York Power Authority (NYPA) has compiled a 3.5-GW package of 40 potential projects as it moves into its new role as a renewable energy developer. 

NYPA issued a draft of its first Renewables Strategic Plan at its Oct. 8 board of directors meeting. It lays out basic details of the 40 projects, 30 of which would be undertaken by private sector entities in partnership with NYPA, 10 by NYPA itself. 

The plan also recaps changes the authority has made in the 18 months since being vested with increased responsibility in the state’s clean energy transition. 

The 40 proposals entail solar and battery energy storage systems and span every corner of the state, though few would be placed in the densely populated New York City region. 

The proposals are open to a 60-day public comment period, and their viability will be assessed through review of their economics, community impacts and real estate considerations before being added to the portfolio. 

NYPA expects substantial attrition, however. The report did not quantify this, but a NYPA executive at the meeting said attrition is likely to be in the 80 to 85% range for early stage projects, which is in line with industry averages. More mature projects could see 30 to 60% attrition. 

This was quite a letdown for advocates who had pressed long and hard for the state to take a more active role in renewable development.  

The New York State Energy Research and Development Authority (NYSERDA) has extensive involvement in promoting and facilitating renewable development but does not itself undertake projects. 

NYSERDA has achieved mixed results in a state where energy development has long been known to be expensive and slow. These chronic factors were joined with acute national and international financial factors that led to mass cancellations of renewable contracts in New York in the past year.  

NYSERDA is attempting to pull off a turnaround but has a long way to go. 

As a result, the state is on course to miss its goal of 70% renewables by 2030, possibly by a wide margin. 

The Public Power NY coalition and other advocates had long sought to shift some of the emphasis in renewables away from the private sector and toward the public sector.  

They succeeded during negotiations for the 2023/24 state budget, which included provisions authorizing and/or directing NYPA to develop renewables alone or in partnership, conduct workforce training for the renewables industry, set up a bill credit system for low- and middle-income utility ratepayers and shut down its fossil-burning peaker plants. 

Public Power had been optimistic that NYPA could achieve results faster and at lower cost than the private sector, given NYPA’s access to low-cost capital and its independence from investors demanding return on their capital.  

“NYPA has had over a year to plan for these contingencies, and should have planned to build enough capacity to account for attrition,” Public Power said in a prepared statement. “By only proposing 3.5 gigawatts, NYPA is setting the stage to fail to meet their own inadequate targets.” 

The coalition said: “The Renewables Strategic Plan is an abrogation of NYPA’s responsibility to ensure that the state reaches 100% renewables by 2040, and their duty to New Yorkers to build a better future for future generations.” 

‘All Hands on Deck’

Asked for comment, NYPA did not directly address the suggestion that the fate of the energy transition depends on its actions, but said it was proceeding with due diligence. 

The Strategic Plan does lay out actions NYPA has undertaken in the past 18 months — created a new business unit, recruited personnel to run it, made regulatory filings, formed a subsidiary, issued a $100 million bond, and sought partners and proposals.  

The document indicates the 40 projects are only the initial tranche; the plan must be updated every other year, and NYPA plans to develop as much renewable capacity as its funds allow. 

This expanded role for NYPA was not supported by the energy industry. The Alliance for Clean Energy New York, for example, said it would place NYPA in unfair competition with the private sector. ACE NY pressed instead for NYPA to concentrate on developing transmission, a chokepoint in renewables development. 

(NYPA, the nation’s largest state public power organization, operates more than 1,550 circuit-miles of transmission lines.) 

ACE NY Executive Director Marguerite Wells said via email that the draft plan was comprehensive and could move the state closer to its clean energy goals and that partnering with private developers where possible is the right move for NYPA.  

She added: “We don’t want to create scenarios where NYPA is competing with private developers on new projects, but we know there is going to be enough demand in the coming years and decades [and] we will need all hands on deck, and all ideas on how to build renewables faster are welcome.” 

NYPA would not say what percentage of the 40 projects are new and how many are reboots of projects that previously held contracts issued by NYSERDA. 

NYPA said project costs were not known at this early stage and estimates would not be made public. It also could not say which projects would support Renewable Energy Access and Community Help, the mechanism by which it will assist lower-income ratepayers, because that program still is in development. 

The 10 self-developed projects NYPA is proposing would all be solar arrays. They would total 203.9 MW and be completed from late 2027 to late 2028. 

More than 170 entities responded to NYPA’s request for information to identify parties interested in collaborating with NYPA. So far, NYPA has qualified 84 developers and investors and has negotiated with several of them.  

Nine entities are listed as co-developers with NYPA on the 30 projects: Acquest Development, Boralex, ConnectGen/Repsol, CS Energy, Forward Power, NextEra Energy Resources, Oriden, Teaches Energy and YSG Solar. 

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NYISO Extends Reliability Needs Assessment Comment Period

In response to stakeholder criticism, NYISO has updated its draft Reliability Needs Assessment to include an executive summary and appendices, and extended the comment period on the report to Oct. 14.  

“We definitely heard stakeholders’ concerns about not having enough time to review the complete report with the executive summary,” Ross Altman, senior manager of reliability planning for NYISO, told the Transmission Planning Advisory Subcommittee on Oct. 9. “So, we tried to shift the schedule up a little bit on that.” 

Altman said NYISO would try to address the comments for the next version of the RNA, to be presented Oct. 21 to the Electric System Planning Working Group meeting and Oct. 24 to the Operating Committee. 

“As one of the people who asked for more time, I want to say thank you for giving us a little bit more time; it’s appreciated,” said Kevin Lang of Couch White. 

Stakeholders spent most of the meeting discussing the results of the RNA, which predicted that on a peak summer day with expected weather conditions (95 degrees Fahrenheit), New York City would be deficient by 17 MW for one hour in 2033, rising to 97 MW for three hours in 2034. The analysis suggests that the ISO needs to declare an official reliability need for the city’s capacity zone. (See NYISO Draft RNA Finds Reliability Need for New York City.) 

The discussion focused on whether that was actually significant, or if it was a result of uncertainties in NYISO’s data and assumptions. 

“So the results point to a 17-MW, one-hour deficiency 10 years from now?” asked Marc Montalvo, CEO of Daymark Energy Advisors. “Is that statistically different from zero?” 

Montalvo pointed out that the given the magnitude of the system and the uncertainties, 17 MW might just be statistical “noise.” He asked Altman how to interpret that “in an actionable way.” 

“Do we run out and do something, or do we say, ‘Look, this needs five more years of information before we even start to worry about it’?” he asked. 

Altman said that before any solution was solicited, NYISO would re-evaluate if the need still existed based on updated information. He pointed out that there were resources in development that could come online in the next 10 years but were not far enough along to meet NYISO’s base case assumptions. 

“We have an opportunity to re-evaluate next year to see if the updates would make the problem go away,” Altman said. “And then in the evaluation of solutions, we do consider which solutions are best suited for meeting this need, but we have to have a solution. … We can’t just show there’s a reliability violation and do nothing about it.” 

Crypto Companies Pivoting to AI

Stakeholders also revisited NYISO’s assumption about the flexibility of cryptocurrency mining and hydrogen-producing loads.  

The ISO had issued a preliminary finding of a statewide shortfall of as much as 1 GW by 2034, but it revised its assumptions about the flexibility of such large loads during peak hours, which reduced the loss-of-load expectation to below 0.1. (See NYISO: Large Load Flexibility Eliminates 2034 Shortfall Concern.) 

But there is a very real possibility that these loads will not be as flexible as NYISO assumes. Cryptominers are increasingly shifting their facilities’ operations to training artificial intelligence. 

“There is an increasing interest among cryptocurrency mining facilities to actually switch over to doing AI, which, because of their service level agreements, is much less flexible,” one stakeholder noted. “Their willingness to do one and not the other depends on, to a large extent, the price of Bitcoin or whatever other cryptocurrency they’re mining.” A data center’s stated purpose as a cryptomining operation had very little bearing on whether it would remain as one in the future, they said. 

Reuters reported in August that technology companies are seeking the energy assets held by crypto miners as they race to secure electricity supply for AI and cloud data centers, estimating that about 20% of cryptocurrency could pivot to AI by the end of 2027. 

“We do monitor [that], but we do recognize that we don’t know exactly how they continue to evolve,” Altman said. “Any specifics you have on that, or research you’d like to share, please email” the ISO. 

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NERC Examining Lessons from IBR Standard Development

NERC’s staff are working on a “postmortem” examining the development of the ERO’s recently approved reliability standard setting ride-through requirements for inverter-based resources to identify lessons for the future, the organization’s vice president of engineering and standards told its Board of Trustees. 

“We’re trying to comprehensively map out a plan forward for the next year,” Soo Jin Kim told trustees at a special board meeting Oct. 8, referring to the work needed to meet the next milestone in FERC Order 901. The order, passed last year, requires NERC to submit standards to improve the reliability of IBRs in three tranches between 2024 and 2026. According to Milestone 3, the ERO must file standards addressing data-sharing and model validation for all IBRs by Nov. 4, 2025. (See NERC Submits IBR Work Plan to FERC.) 

Milestone 2 covered performance requirements and post-event performance validation for registered IBRs, and the standards for this segment must be submitted to FERC by Nov. 4 of this year. Those standards were the main reason for the Oct. 8 board meeting, with trustees unanimously voting to adopt the standards: 

    • PRC-024-4 — Frequency and voltage protection settings for synchronous generators, Type 1 and Type 2 wind resources, and synchronous condensers.  
    • PRC-028-1 — Disturbance monitoring and reporting requirements for inverter-based resources.  
    • PRC-002-5 — Disturbance monitoring and reporting requirements.  
    • PRC-030-1 — Unexpected inverter-based resource event mitigation. 
    • PRC-029-1 — Frequency and voltage ride-through requirements for IBRs. 

All five standards will be submitted to FERC for final approval. 

Kim said NERC’s developers will look to streamline the development cycle for the upcoming milestones by examining their experience on the Milestone 2 standards — especially PRC-029-1, which met significant opposition by industry stakeholders in multiple formal ballot rounds.  

The standard’s failure to achieve the required two-thirds segment weighted approval led the board to exercise for the first time its authority under Section 321 of NERC’s Rules of Procedure to streamline the stakeholder approval process. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) Trustees directed the ERO’s Standards Committee to convene a technical conference to hear feedback from industry, use that input to revise the standard and post the updated standard for another ballot round.  

Board Chair Ken DeFontes praised the work of NERC’s staff adapting to these directives, which required the entire process to be carried out within 45 days (though NERC did extend balloting for PRC-029-1 to give industry more time to review the changes, meaning the results came in several days after the 45-day limit).  

Kim said NERC found the technical conference helpful to identify issues that kept industry from supporting previous versions. She suggested that when developing the Milestone 3 standards, the ERO will proactively call for similar gatherings to “get ahead of several of the technical issues that we see, particularly with regard to modeling.” 

“We’re going to try to have, not just a technical conference, but a working session where we will have breakouts, learn from what transpired during the second milestone, and try to get to the heart of the matter with regards to certain changes that need to be applied to some of the standards,” Kim said. “We agree in concept on what needs to occur with regards to modeling, [but] there’s going to be several technical sessions.” 

The board also voted to accept revisions to the charter of NERC’s Reliability and Security Technical Committee that are intended to improve the balance of industry representation at committee meetings. 

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Panel Calls for Greater Interregional Planning Across the Northeast

Unlocking the full potential of Quebec hydropower to balance renewables through the Northeast will require major efforts to overcome barriers to transmission planning and development, speakers at a webinar led by the Acadia Center emphasized Oct. 9.

While studies have shown increased bidirectional transmission capacity between the Eastern Canadian provinces and the Eastern U.S. could significantly reduce the costs of decarbonizing the grid, such transmission projects so far have struggled. (See Québec, New England See Shifting Role for Canadian Hydropower and National Grid Backs out of Twin States Clean Energy Link Project.)

The webinar kicked off with pre-recorded remarks from U.S. Sen. Ed Markey (D-Mass.), who said “the clean energy revolution is here at our doorstep,” but “our grid is an inaccessible, one-lane road from the Model T era.”

Markey highlighted his proposed legislation that would direct FERC to require RTOs to regularly engage in interregional planning and establish independent transmission monitors. (See Dems Introduce Bill on Transmission Planning, RTO Transparency.)

Despite the significant up-front costs of major new transmission lines, grid modeling indicates that “in a low-carbon system in New England and Québec, building more bi-directional transmission lowers the cost of electricity,” said Emil Dimanchev, a research affiliate at the MIT Center for Energy and Environmental Policy Research.

Increased bi-directional transmission would reduce the need to curtail renewables during periods of excess generation, Dimanchev said. It also would reduce reliance on gas resources by enabling hydro to take a greater balancing role paired with intermittent renewables.

Along with cost savings, increased interregional transmission also could provide significant reliability benefits.

“Transmission gives us this ability to combine wind resources from both sides of the border, which together are much more reliable,” Dimanchev said.

Adrienne Downey, principal engineer at the floating offshore wind developer Hexicon, said offshore wind pairs particularly well with hydropower when there is enough transmission capacity to enable hydro to firm up the intermittencies of wind.

“Offshore wind is pretty much a match made in heaven with this load growth, these winter peaks … and looking at hydro and the opportunity to replenish reserves,” Downey said.

Hexicon is part of a coalition that has proposed a “shared offshore backbone transmission corridor” to connect offshore wind resources along the northern Atlantic coast, reaching shore in both New England and Nova Scotia.

The proposal likely would pay for itself through reduced power costs but remains “really a question of proactive planning,” Downey said.

Additional interregional transmission capacity also would help to even out localized weather patterns as weather-dependent renewables make up a larger portion of the generation mix, said Hannes Pfeifenberger of the Brattle Group.

About 4 GW to 7 GW of transmission capacity likely will be needed and would be “cost effective” between Canada and both New England and New York, but “the reality is there are significant barriers,” Pfeifenberger said. A lack of trust between regions, inadequate planning tools and regulatory constraints all pose challenges.

“You need everybody at the table, which is why it’s so challenging,” Pfeifenberger said. He emphasized the need to build understanding around the importance of interregional planning to lay the groundwork for agreements regarding specific transmission needs and cost allocation frameworks.

Downey said grid operators, lawmakers and officials must work to expand beyond often-ingrained habits of hyper-focusing on the local grid, while also respecting the cultural differences in how regions approach their power system.

“To bridge that, and to have these broader regional discussions, there’s some cultural sensitivities,” Downey said. “It’s important that we think about this as a social and cultural exchange with related co-benefits.”

Beyond just adding new lines, transmission planning could help identify opportunities to increase line capacity when conducting asset condition upgrades, Pfeifenberger said.

Costs associated with maintaining the aging New England grid have accelerated in recent years, putting pressure on ratepayers and causing friction between the states and transmission owners, who have proposed several infrastructure projects costing hundreds of millions of dollars. (See New England States Raise Alarm on Eversource Asset Condition Project.)

Increasing line capacity could cost more in the short term but could provide significant long-term savings, Pfeifenberger said.

“We have an existing grid that was built in the ’60s and ’70s,” Pfeifenberger said. “We can save money and reduce community impacts by better planning.”

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EIA: Colder Weather and Lower Fuel Prices Likely Mean Flat Bills This Winter

The U.S. Energy Information Administration expects consumers will spend roughly the same on winter heating this year as they did last year, according to its Winter Fuels Outlook. 

“Overall, we expect that there’s going to be, generally speaking, lower fuel prices that are going to be offset by higher consumption this winter,” EIA Administrator Joseph DeCarolis said in an Oct. 9 webinar. 

The two biggest sources of space heating across the country are natural gas and electricity, at 45 and 43% of all households. On average, bills for both sources should go up slightly this winter. 

The Midwest is expected to see higher bills than last year, as consumers there are expected to spend 11% more on natural gas, compared to the 1% national average, and 6% more on electricity, compared to the 2% national average. The Midwest had an exceptionally mild winter last year, so the return to more normal temperatures in the region is expected to lead to a bigger jump in demand for heating, the outlook said. 

While wholesale prices have fallen this year, weather forecasts call for more cold, with EIA expecting heating degree days to tick up 5% compared to last year. But it still is expected to be a generally mild winter, with the forecast calling for heating degree days to be 2% below the average of the previous decade, DeCarolis said. 

For the first time, EIA broke out the share of the average bill for each fuel that goes toward space heating. While customers spend more on electric bills overall, the space heating portion of EIA’s estimates are almost the same as those for natural gas, though the South has the biggest share of electric heating. 

Temperatures can have a big effect on winter prices, though when it comes to electricity and natural gas, the effect is felt more in the wholesale markets. The impact lags on retail prices because, for the most part, they are overseen by state regulators, EIA analysts said in the webinar. 

The prices for propane, which is used by 5% of households concentrated in the Midwest, and heating oil, used by 3% of total households almost entirely in the Northeast, vary more significantly with temperature because wholesale prices are more closely linked to residential prices. 

Some five major storms have led to major effects on natural gas and power systems over the past 15 years, but those are difficult for EIA to predict. (See Déjà Vu as FERC, NERC Issue Recommendations over Holiday Outages.) 

“Something like a major winter storm or an acute weather event is difficult to build into our forecast because the impact on price is of something like that would be highly dependent on where the storm hits,” EIA’s Corrina Ricker said. “For example, if it were to impact production, or if it’s close to large demand centers, those types of factors would really play into how the natural gas price would be impacted.” 

Winter storms can cause major price spikes, but those are short-lived, and their effect on residential prices usually is felt later when regulators allow utilities to recover costs from such events, she added. 

A major trend in home heating is the adoption of heat pumps. But given how many other factors beyond the equipment can affect a home heating bill, EIA wasn’t able to tease out any differences between that technology and traditional electric heating. EIA said it was working on how to isolate the effect of different heating equipment on consumer utility bills.  

“The consumption and expenditures associated with these technologies depend to a large extent on household characteristics and the climate in which they are located,” the winter outlook said. “For example, an electric resistance heater used in a small, well-insulated home in the South could result in lower expenditures than an air source heat pump placed in a larger, drafty home in the Northeast.” 

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IEA Expects 5.5 TW of New Renewables by 2030

The world is on track to expand its renewable energy capacity 2.7 times by 2030, the International Energy Agency reports. 

That is enough to outpace the national goals of many countries but not quite enough to meet the target established at the COP28 climate summit: tripling the capacity by 2030. However, the IEA said, tripling still is possible with bold near-term action by governments. 

In “Renewables 2024,” its flagship annual report released Oct. 9, IEA projects more than 5,500 GW of new capacity coming online by 2030. 

Photovoltaic panels and wind turbines account for the vast majority: 80% and 15%, respectively. 

Hydropower capacity growth is expected to remain stable while renewables such as bioenergy, geothermal, concentrated solar and ocean energy are expected to decline without greater policy support. 

IEA attributes the growth to climate and energy security policies in nearly 140 countries that, combined with favorable economics, have made renewables cost-competitive with fossil-fired generation and fostered new demand from the private sector. 

The report projects that nearly 70 countries accounting for 80% of global generation capacity are on track to reach or exceed their 2030 goals. 

China is the standout among them, expected to account for 60% of the global expansion through 2030 thanks to its comprehensive support for utility-scale and distributed generation across all renewable technologies. 

In all, renewables would account for nearly half of global electricity generation by 2030. 

Potential stumbling blocks include high cost of capital in developing economies, weak grid infrastructure, inadequate auction visibility, unstable policy environments and curtailment of installed resources due to lagging grid investments and system integration. 

Also, at least 1,650 GW of renewable capacity in advanced stages of development is waiting for grid connection worldwide; some early-stage projects are dropping out of the queue due to lack of progress. 

And kinks remain in the supply chain: Record-low prices, a supply glut and manufacturing overcapacity exist for the solar industry, while the wind turbine sector is crimped by limited investment in new capacity. 

Finally, beyond power generation, fossil fuel demand continues to grow in the transport, industry and buildings sectors, the report states; almost 80% of total energy demand worldwide still will be met by fossil fuels in 2030, down from 87% in 2023. 

In the news release, IEA Executive Director Fatih Birol said: 

“Renewables are moving faster than national governments can set targets for. This is mainly driven not just by efforts to lower emissions or boost energy security — it’s increasingly because renewables today offer the cheapest option to add new power plants in almost all countries around the world. 

“This report shows that the growth of renewables, especially solar, will transform electricity systems across the globe this decade. Between now and 2030, the world is on course to add more than 5,500 gigawatts of renewable power capacity — roughly equal [to] the current power capacity of China, the [EU], India and the United States combined. By 2030, we expect renewables to be meeting half of global electricity demand.” 

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Report Examines Grid Planning for Building Electrification

A new report argues that discussions about building electrification largely leave out one key issue: how to prepare the grid for the higher demand and new consumption patterns associated with the shift.

The Energy Systems Integration Group’s (ESIG) “Grid Planning for Building Electrification” report seeks to start that conversation, with a focus on the increasing share of home heating being served by the grid, which has the biggest impact on overall demand patterns.

“Building electrification gets a lot of attention in the industry, but little information is available about what grid planners should do about it today,” said Sean Morash, chair of ESIG’s Grid Planning for Building Electrification Task Force. “This report bridges the gap between building energy modelers and grid planners, providing insights that will shape the distribution and bulk power systems that support our energy transition.”

The effects of load growth on the distribution system are often only a minor consideration, but the long lead time and extended life of power infrastructure means that decisions today will support society into the 2060s, the report said.

“Load impacts from building electrification will increase the seasonality and weather dependence of loads, as well as increase the vulnerability of the power system to extreme weather, largely due to heating demand,” the report said.

Building electrification promises one major shift for the grid: as electricity is increasingly used for heating, many regions will shift from summer to winter peaks. Increased adoption of heat pumps, which tend to be more efficient than air conditioners, mean that summer peaks could decline in some regions. And while solar output aligns with gross peaks in the summer, winter peaks happen just before the sun comes up.

The report cites priority areas to improve distribution system planning in the face of growing electrification.

The first is to improve forecasting because the load shape impacts of building electrification will vary by location.

Areas such as the Southeast and Texas, where a lot of heating is already electrified, could see overall use decline as more energy-efficient heat pumps replace less efficient older units, or resistance heaters. But when it comes to winter peak demands for those states, cold snaps plus even more electrified homes could cause them to be higher.

“On the other hand, the adoption of electric heating in areas predominantly served with fossil fuels could result in a doubling of electricity use, affecting both peak power and total electricity needs,” the report said.

Distribution system planners will need a more granular understanding of technology adoption, such as the rates of electrification, what kinds of heat pumps are being adopted, and what that means for the local climate zone. Planners should also develop a solid baseline of current building demand broken down by end use because electrification will impact some significantly and others not at all.

Increased Winter Risk

Because electrification will make the grid more vulnerable to extreme temperatures, planners must consider extreme events, which includes factoring how climate change can impact those events over time, according to the report.

Traditional planning has centered around one peak demand event, but severe weather — especially in winter — can cause longer-duration stress by increasing loads for prolonged periods. Electrification of heating will exacerbate that stress, but it can be planned for by switching to a “time-series analysis” that assesses risk across multiple hours of the year and the efficacy of solutions for those intervals.

Distribution system equipment has some universal engineering standards, but local utilities embed their own assumptions about system conditions, demand diversity and load growth.

“However, past practices may not be well suited for electrification-driven load growth, which may have different hourly load impacts,” the report said. “Distribution system planners will need to reevaluate the underlying assumptions that drive equipment standards.”

The shift to longer-duration winter peaks can impact grid-edge equipment, which is typically designed to serve peak demands for short durations and can lead to component failures.

“Overload failures can occur throughout the grid, including in distribution systems, where equipment is often unmonitored,” the report said. “Grid failures during extreme winter weather events pose much more risk to human health and wellbeing than do summer peaks.”

The industry could avoid the largest impacts from electrification by relying more heavily on energy efficiency and demand management practices, the report said.

“In the context of building electrification, the most important energy efficiency measures are those that maintain building temperature with minimal input from the grid, because of the long duration of winter reliability events,” the report said.

Thirty percent of thermostats are “smart,” and actively tapping those and other demand resources can greatly help in reliably electrifying buildings, the report said.

To some extent, utilities can predict when some areas in their service territories are going to electrify because some programs target specific neighborhoods or are focused on low-income customers. They should then plan ahead and upgrade infrastructure with an eye to growing future demand.

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Wash. Kicks off Cap-and-Invest Electricity Forum

Washington’s Department of Ecology kicked off its first virtual electricity forum Oct. 3 to provide updates on recent electricity-related rulemaking efforts related to the state’s carbon market and to give stakeholders a chance to discuss those initiatives.

The state’s Cap-and-Invest Electricity Forum aims to allow parties to discuss policy issues related to Washington’s cap-and-invest program and greenhouse gas emissions reporting programs.

The Ecology Department has moved forward with amending several electricity provisions in its rules. The rulemaking closest to completion concerns centralized electricity markets, such as CAISO’s Western Energy Imbalance Market/Extended Day-Ahead Market and SPP’s Markets+.

The rule establishes a framework for accounting for “specified” electricity imported through centralized markets and defines the electricity importer for specified electricity imported through a centralized market. The update is anticipated to go into effect in January.

The agency is also working on “linkage” rulemaking to align cap-and-invest program regulations with California and Québec as Washington looks to join the larger shared carbon market. (See Calif., Quebec, Wash. to Explore Linking Carbon Markets.) The recently enacted Senate Bill 6058 allows Ecology to adjust the cap-and-invest program by, for example, aligning allowance purchase limits for auctions across jurisdictions and having the same compliance period dates.

“This rulemaking may also be used as an opportunity to address other electricity sector topics, including centralized electricity markets,” Camille Sultana, senior environmental planner at the Ecology Department, noted during the meeting.

Sultana added that Ecology will provide more information on the bill’s implementation later this fall. The goal is to publish a proposed linkage rule in spring 2025 and put it up for adoption later that year. However, the timeline is subject to change as the agency must consider anticipated updates to California and Québec’s respective cap-and-trade programs.

The department also opened the floor for participants to chime in on GHG issues related to centralized electricity markets, such as accounting for emissions from electricity from “unspecified” resources, emissions leakage and accounting for energy flowing from centralized markets with different operators.

Clare Breidenich, assistant executive director of the Western Power Trading Forum, said the agency should define surplus energy in the context of GHG accounting in centralized markets.

“I think by establishing clear requirements and conditions for what Ecology thinks is appropriate for those markets, that will give the guidance to the market operators and help them to align their approaches,” Breidenich said.

Participants also discussed emissions reporting requirements and the transition from netting to a wheel-through framework under SB 6058.

As defined in the bill, “‘electricity wheeled through the state’ means electricity that is generated outside the state of Washington and delivered into Washington with the final point of delivery outside Washington including, but not limited to, electricity wheeled through the state on a single NERC e-tag, or wheeled into and out of Washington at a common point or trading hub on the power system on separate e-tags within the same hour.”

Alisa Kaseweter, climate change strategist at Bonneville Power Administration, said the definition “seems to conflate what the industry would think of as a standard wheel-through which happens on a single e-tag with perhaps some netting.”

Sultana noted that SB 6058’s definition of a wheel-through “might not directly align with industry standard.” She added that Ecology’s “ability to modify this definition in ways that are not aligned with what’s already there in statute is beyond our authority.”

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Vermont PUC Rejects Heating Fuel Credit Trading Concept

The Vermont Public Utility Commission has published a draft of the Clean Heat Standard mandated by a landmark decarbonization law but declined to include the specified credit-trading system. 

In a report accompanying the draft, the PUC said it makes no sense for a single small state to create such a costly and complex system. It is looking instead at other options to reduce the greenhouse gas emissions produced by heating fuels and will propose an alternative mechanism before the January deadline set by the legislature. 

Vermont Act 18 became law in May 2023 when the legislature overrode a veto by Gov. Phil Scott (R), who cited cost concerns. (See Vermont Governor to Veto Building Decarbonization Measure.) He had vetoed a similar measure in 2022. 

Act 18’s full title — “An act relating to affordably meeting the mandated greenhouse gas reductions for the thermal sector through efficiency, weatherization measures, electrification and decarbonization” — summarizes the intent of the 41-page measure. 

There is much to reduce. Like residents of the two other northern New England states, Vermonters rely heavily on delivered fossil fuel to heat their homes. The U.S. Energy Information Administration reports that 59% of housing units in Vermont were heated with kerosene, propane or fuel oil as of 2020, compared with 13% nationwide. 

The use of electric heat pumps is gradually increasing in Vermont. (See Vermont Heating Fuel Sales Decreasing in Recent Years and Vermont Gas Utility Explains its Effort to Electrify Customers.) 

But many people still rely on fossil fuels to heat their homes through what historically have been long, cold winters. As elsewhere, there are concerns about equity: Those unable to afford electrification of their homes may be most vulnerable to the added costs resulting from policies that attempt to speed electrification. 

The legislature sent the matter to the PUC to research (23-2221-INV) and codify (23-2220-RULE). The commission issued its draft CHS rule on Oct. 1 and set an Oct. 30 public hearing on the document. Also on Oct. 1, the PUC issued a companion report explaining the 16 months of work that produced the draft. 

After the hearing, the PUC must, by Jan. 15, 2025, submit the draft rule to the legislature, which then will decide whether and how to implement the CHS. 

Central to the CHS’ goal of reducing greenhouse gas emissions from heating fuel is a requirement that entities importing heating fuel into Vermont reduce their emissions by generating or purchasing clean heat credits earned from delivery of clean heat measures. These can include weatherization, heat pumps, advanced wood heat and biofuels. At least 32% of annual clean heat credits were mandated to come from customers with low or moderate income. 

Given the substantial cost and complexity of developing a credit management platform, the PUC did not create or recommend such a mechanism until the legislature decided whether and how to continue develop a CHS. 

But the PUC’s companion report cast doubt on the very idea of a Vermont-based credit-trading system. Among other things, it would involve participation and regulatory oversight of hundreds of fuel dealers and other entities not historically regulated by the PUC, and the potential would exist for market manipulation or outright fraud, the authors wrote. 

“Our work over the past year and a half on the Clean Heat Standard demonstrates that it does not make sense for Vermont, as a lone small state, to develop a clean heat credit market and the associated clean heat credit trading system to register, sell, transfer and trade credits,” the report says. “Because the Clean Heat Standard introduces these additional regulatory hurdles and costs, the commission is considering other options to achieve Vermont’s greenhouse gas emission-reduction goals for the thermal sector.” 

The PUC said one of those options is a new thermal energy benefit charge on sale of fuel oil, propane and kerosene, with proceeds going directly to fossil fuel-reduction efforts such as weatherization and electrification.