[USA] PJM forecasts long-term electricity demand growth through 2039

On January 8, 2024, PJM Interconnection released its long-term load forecast, which laid out its predictions for estimated electricity demand growth.[1] The forecast estimated a 1.7% annual demand growth for summer peaks, 2% for winter peaks, and 2.4% for net energy over a 10-year planning horizon starting in 2024. The 2024 summer peak load is 151,254 MW, increasing to 178,895 MW in 2034 and 193,123 in 2039. Peak winter load is forecasted at 134,663 MW for the 2023–2024 winter, increasing to 164,824 MW in 2034 and 178,241 in 2039. Overall, total annual energy use throughout the PJM footprint is expected to increase nearly 40% by 2039, from 800,000 GWh to about 1.1 million GWh.

According to the long-term forecast, rising energy demand in PJM’s footprint, which includes all or part of 13 states and the District of Columbia, is increasingly driven by the development of data centers throughout the PJM footprint. Further, the acceleration of the accelerating electrification of transportation and industry is a big factor. Currently, PJM has about 500,000 light-duty electric vehicles (EVs) as of 2024, and S&P Global is forecasting about 23 million light-duty EVs by 2039, a growth rate of just under 30% annually during that period. Also, PJM has about 25,000 medium- and heavy-duty EVs as of 2024, and S&P Global is forecasting about 1.45 million medium- and heavy-duty EVs by 2039, 30% annual growth rate.

[1] https://insidelines.pjm.com/pjm-publishes-2024-long-term-load-forecast/

[USA] EPSA study examines system-wide costs of integrating energy resources in PJM

On December 18, 2023, the Electric Power Supply Association (EPSA) released a new analysis that looks at the impacts of different energy resource options on the reliability of the electric grid.[1] The report is an effort to better look at the “full-cycle” levelized cost of electricity (LCOE), including the impact of regional costs, interconnection costs, curtailment costs, and the cost of ensuring that all units can provide an equivalent level of resource adequacy to the grid. It also seeks to provide a fuller picture of the true costs of integrating different energy resources onto the grid—with important implications for policymakers, regulators, and voters. The analysis was conducted by FTI Consulting on behalf of EPSA and utilized publicly available data from PJM Interconnection, which covers more than 65 million Americans across 13 states and the District of Columbia. The metric was developed using PJM’s cost and demand forecasts looking ahead to 2026.

A key finding of the study was that the cost of providing resource adequacy services is more than 100% of the traditional LCOE cost of wind and solar units. In addition, while traditional LCOE is lower for wind and solar units compared to combined cycle natural gas units in PJM in 2026, when accounting for the full cost of connecting to the system and providing resource adequacy services, natural gas plants are more competitive. The study also found that tax credits are crucial for making carbon capture and storage (CCS)-equipped units economical, even at the low technology costs assumed by the National Renewable Energy Laboratory (NREL). Further, small modular nuclear (SMR) nuclear units are competitive with other forms of non-emitting generation when accounting for the full cost of connecting to the system and providing resource adequacy services at the technology costs assumed by NREL.

[1] https://epsa.org/new-analysis-examines-system-wide-costs-of-energy-transition/

[USA] PJM proposes nearly $5 billion in transmission projects

On October 31, 2023, PJM Interconnection staff recommended about $4.9 billion in transmission projects to help address reliability concerns related to data center growth, generator retirement, and new generation resource capacity in the Mid-Atlantic region.[1] As part of its planning process, the grid operator, which covers 13 states and Washington, D.C., establishes “windows” for transmission developers to offer solutions to certain transmission reliability needs. These needs are based on standards established by the North American Electric Reliability Corporation (NERC). Planning Window 3 sought proposals to address impacts to the grid from new electricity demand. The grid saw a 7,500 MW increase in demand due to data center additions to the system in Virginia and Maryland. The grid is also facing widespread effects of the retirement of more than 11,000 MW of generation across PJM’s footprint.

PJM’s recommended proposal was selected based on four criteria: effectiveness to meet system needs through 2028; ability to expand to meet system needs beyond 2028; minimizing of local impacts by using existing rights of way, where possible; and confidence in costs. PJM received 72 proposals from 10 entities, including six incumbent transmission owners. Under the recommendations, Dominion Energy would build transmission projects totaling about $2.5 billion, Exelon’s Potomac Electric Power would build projects totaling about $653 million, and Public Service Electric & Gas would build a $447 million project. FirstEnergy, LS Power, NextEra, and Transource would build other parts of the recommended plan. The proposal is set to be reviewed by the committee again at a December 5, 2023, meeting before going to the board.

[1] https://www.pjm.com/-/media/committees-groups/committees/teac/2023/20231031/20231031-item-15---reliability-analysis-update.ashx

[USA] PJM releases report finding gas-fired generation accounted for 70% of unplanned outages during Winter Storm Elliott

According to a report released by PJM Interconnection on July 18, 2023, during the peak of Winter Storm Elliott in December 2022, 24% of the grid operator’s generating capacity was unexpectedly offline.[1] Of the generating capacity that was offline, gas-fired power plants made up about 70% of unplanned outages. The report states that generators that failed to meet their capacity obligations during Winter Storm Elliott face about $1.8 billion in non-performance charges, about 45% of the nearly $4 billion in capacity revenue for this capacity year.

The non-performance charges represent 83% of the nearly $2.2 billion in capacity payments earned by the resources facing penalties. Resources that provide more power than their obligations receive bonus payments funded by the penalties. The grid operator stated that, on average, 80% of bonus megawatts were produced by generation, 10% came from net imports from outside its footprint, energy efficiency resources produced 5%, and demand response and price responsive demand resources produced 5%. Nuclear power plants received 34.5% of the bonus pool for generators, followed by gas at 29.2%, coal at 17.3%, and wind at 13.7%. In its report, PJM offered 30 recommendations in response to operations during Winter Storm Elliott. Many of these recommendations are being addressed in its Critical Issue Fast Path – Resource Adequacy process or through other forums.

[1] https://pjm.com/-/media/library/reports-notices/special-reports/2023/20230717-winter-storm-elliott-event-analysis-and-recommendation-report.ashx

[USA] PJM asks FERC to help resolve generator complaints about Winter Storm Elliott penalties

On April 14, 2023, PJM Interconnect asked the Federal Energy Regulatory Commission (FERC) to help lead discussions to resolve eight pending complaints against the grid operator by power plant owners over penalties for failing to meet their capacity obligations during December 2022 Winter Storm Elliott.[1] At the peak of Winter Storm Elliott, about 57,000 MW were offline in PJM’s footprint.[2] About 63% of all outages were natural gas-fired power plants, 28% coal, 4% oil, 2% nuclear, 1% hydroelectric, and about 1% other. According to a fact sheet released by PJM, about 200 market participants face roughly $1.8 billion in performance penalties for falling short of their required power deliveries on December 23 and 24.

In the request, PJM said FERC should appoint one or more settlement judges to help PJM, the complainants, and the intervenors resolve as many of the non-performance charge disputes as possible. PJM said it plans to answer each complaint and show that in each case, the assessed non-performance charges follow its tariff; that the relevant tariff provisions are just and reasonable, assuming they are even open to challenge; and that PJM properly invoked its emergency procedures. However, PJM noted that it recognizes there are benefits to a quick resolution to the dispute.

[1] https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20230414-5132&optimized=false

[2] https://www.pjm.com/-/media/markets-ops/winter-storm-elliott/faq-winter-storm-elliott.ashx

[USA] Report: PJM interconnection costs have grown rapidly

On January 19, 2023, the Lawrence Berkeley National Laboratory (LBNL) released a report analyzing interconnection costs in the PJM Interconnection[1] territory.[2] The report found that interconnection costs have substantially increased in parallel with the tremendous growth of PJM’s interconnection queue in recent years. At the end of 2021, PJM had 259 GW of generation and storage capacity actively seeking grid interconnection, nearly twice as large as PJM’s peak load in recent years (~155 GW). Capacity in the queue includes solar (116 GW), standalone battery storage (42 GW), solar-battery hybrids (32 GW), and wind (39 GW). 2021’s active queue increased by 240% compared to year-end 2019. PJM reformed its interconnection process in 2022 due to the substantial growth of interconnection requests, along with lengthy study timelines and high project withdrawal rates. The ISO adopted a “first-ready, first-served” cluster study approach.

LBNL found that PJM interconnection costs have grown across the board. For example, mean costs for active projects[3] have grown from $29/kW to $240/kW (2017-2019 vs. 2020-2022. The main driver behind these increases has been broader network upgrade costs, which have risen sharply since 2019. Notably, average interconnection costs have been significantly lower for natural gas ($24/kW) than for storage ($335/kW), solar ($253/kW), or wind ($136/kW for onshore, $385/kW for offshore). The PJM brief is the second in a series analyzing interconnection costs in wholesale electricity markets. LBNL released an October 2022 study about the Midcontinent Independent System Operator (MISO) containing similar findings. LBNL will publish analyses of New York ISO (NYISO), ISO New England (ISO-NE), and Southern Power Pool (SPP) in the coming months.

[1] PJM serves all or parts of serving all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.

[2] https://emp.lbl.gov/news/pjm-data-show-substantial-increases

[3] Active projects refers to projects working through the interconnection process.

[USA] PJM to request a mid-auction capacity market rule change

During a presentation on the status of PJM’s 2024/2025 Base Residual Auction on December 21, 2022, Stu Bresler, Sr. Vice President of Market Services, stated that the grid operator plans to ask the Federal Energy Regulatory Commission (FERC) to approve a rule that would allow it to change a capacity auction parameter that led to anomalous results in its auction.[1] In the case of a small locational deliverability area (LDA) like Delmarva Power South, additions of large and/or intermittent units can lead to an increase in the area’s reliability requirement because capacity transfers are needed to account for times when the resources are not available. According to Bresler, when PJM determined how much capacity it would need, it assumed a mix of generators would offer about 1,000 MW in the Delmarva Power South area[2] because they had signed interconnection agreements. However, those generators didn’t bid into the auction, resulting in the LDA being short and the market clearing at an unjustly high price because of the increased reliability requirement.

Through a Section 205 filing[3], PJM plans to ask FERC to approve a rule change that would allow it to lower an area’s reliability requirement during the auction process if generators don’t bid into the auction as expected. PJM intends to ask FERC to make a decision on the proposal within 60 days. The grid operator expects to issue two sets of auction results on January 3, 2022. One set will show the results under existing rules, while the other will show results under the proposed rule. PJM will wait for FERC approval before clearing the auction. Joseph Bowring, President of Monitoring Analytics, PJM’s Independent Market Monitor, expressed his support for PJM’s actions.

[1] https://insidelines.pjm.com/pjm-updates-members-on-2024-2025-capacity-auction-results/

[2] Delmarva Power South covers part of Delaware, Maryland, and Virginia.

[3] In a Section 205 filing, the gird operator submits a new document containing or affecting a rate, term or condition of a FERC-jurisdictional service or charge with FERC for approval.

[USA] FERC approves PJM’s first-ready, first-served plan to address transmission queue

On November 29, 2022, the Federal Energy Regulatory Commission (FERC) approved PJM Interconnection’s plan to move to a “first-ready, first-served” interconnection review process that groups proposals and assigns upgrade costs in clusters.[1] According to PJM, the largest grid operator in the U.S., the plan is a response to the huge influx of interconnection requests over the last few years within its footprint. The grid operator had 2,700 projects in its interconnection queue, representing more than 250 GW. The proposed reforms aim to speed up the interconnection process by allowing projects that are more ready to be processed before other more speculative projects. Speculative projects that withdraw late in the review process can create delays, creating a need to redo the review process. PJM’s plan was widely supported in an 18-month stakeholder development process.

In its decision, FERC said the reforms should provide PJM the ability to reduce its interconnection backlog more quickly than possible under its current rules and will speed the review of new interconnection requests. Under the new plan, PJM won’t review new interconnection requests until early 2026 while it addresses its pending backlog of interconnection requests. The plan also includes a transition phase that will prioritize about half the pending projects, including a “fast-lane” process for projects to help clear the existing backlog. PJM expects to start the transition phase in early 2023.

[1] https://insidelines.pjm.com/ferc-approves-interconnection-process-reform-plan/

[USA] PJM releases Phase 1 of its Offshore Wind Transmission Study

On October 19, 2021, PJM Interconnection[1], the largest regional transmission organization (RTO) in the U.S., published the Phase 1 results of its Offshore Wind Transmission Study.[2] In the study, PJM partnered with state agencies in Delaware, Maryland, New Jersey, North Carolina, and Virginia to identify transmission solutions across the RTO’s footprint to deliver offshore wind generation. Current offshore wind policy targets among PJM’s member states total 14,268 MW. In addition, within PJM, ten states and the District of Columbia have mandatory Renewable Portfolio Standard (RPS) targets.

In the study, PJM analyzed offshore wind injection totals ranging from 6,416 MW to 17,016 MW, as well as modeling state RPS targets. Of the five scenarios analyzed in Phase 1, one scenario was short-term, modeling out to 2027, while the remaining four scenarios were long-term, modeling out to 2035. The estimated cost to upgrade existing onshore transmission ranged from $627.34 million in the short-term scenario to $2.16 billion to $3.21 billion in the long-term scenarios. While the states in PJM’s footprint each have different offshore wind goals and policies, the report determined that coordinated planning among states could be a more efficient path to achieving these objectives than each state working independently.

[1] PJM serves all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia.

[2] https://www.pjm.com/-/media/library/reports-notices/special-reports/2021/20211019-offshore-wind-transmission-study-phase-1-results.ashx

[USA] Report: Transmission for renewables and offshore wind in PJM may cost as much as $3 billion

According to a study published by PJM Interconnection on August 10, 2021, an estimated $627.3 billion to $3.2 billion of transmission upgrades will be necessary to help states in the region meet their offshore wind goals and renewable procurement standard (RPS) requirements over the next decade and a half.[1] The study is in response to a 2019 request by the Organization of PJM States, a group of regulators that represents the 13 states[2] within PJM’s footprint. The study aimed to identify the cost and location of the transmission upgrades needed to support the renewable energy buildouts required to meet states’ clean energy goals. The PJM study simulated the transmission investments required to meet state goals in 2027 and 2035, with six scenarios overall.

The study does not quantify the benefits of transmission upgrades, but it does mention that the transition to cleaner energy will reduce greenhouse gases and lead to consumer benefits through lower energy costs. PJM also noted that while the study includes the costs of onshore transmission, it does not include lead lines or other offshore facilities. PJM highlighted that transmission investments increase significantly between the 2027 and 2035 scenarios in line with state RPS requirements.

[1] https://www.pjm.com/-/media/committees-groups/committees/teac/2021/20210810/20210810-item-10-offshore-transmission-study-group-phase-1-results.ashx

[2] PJM is in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

[USA] New Jersey regulators to collaborate with PJM on developing offshore wind transmission solutions

The New Jersey Board of Public Utilities (BPU) announced on November 18, 2020 that it has submitted a solicitation to develop offshore wind transmission solutions in 2021 with PJM Interconnection, which makes New Jersey the first state to engage in this type of transmission planning.[1][2] The State Agreement Approach (SAA), a new type of solicitation established by FERC Order 1000, is intended to explore new frameworks to advance offshore wind energy. The SAA, which was unanimously approved by the BPU, requests PJM to incorporate New Jersey's offshore wind public policy objectives into its transmission planning process starting in the first quarter of 2021 and authorizes PJM to solicit potential offshore wind transmission solutions from developers on behalf of BPU. Under this solicitation process, the BPU will examine details on ready-to-build transmission options, including key considerations such as cost, siting, environmental impacts, and the timeframe for construction. The results of the 2021 solicitation will be revealed by PJM later in 2021 in collaboration with New Jersey.

New Jersey’s goal of generating 7.5 GW of power from offshore turbines by 2035 is second only to New York and will rapidly expand the state’s renewable energy. During the state’s first two offshore wind solicitations, BPU staff recommended a coordinated approach to generation and transmission. However, with the resource set to expand substantially, the BPU recognizes that there needs to be an integrated transmission plan early in the planning process so that there is no double building or unnecessary environmental disruption.

[1] https://www.nj.gov/bpu/pdf/boardorders/2020/20201118/8D%20-%20ORDER%20Offshore%20Wind%20Transmission.pdf

[2] https://www.bpu.state.nj.us/bpu/newsroom/2020/approved/20201118a.html

[USA] PJM MOPR could cost market consumers up to $2.6B annually according to new report

According to a May 2020 report released by consulting firm Grid Strategies, the Federal Energy Regulatory Commission’s (FERC) 2019 Minimum Offer Price Rule (MOPR) decision could cost customers in the PJM Interconnection from $1 billion to $2.6 billion annually.[1] The new estimate updates a previous cost analysis done by the group in August 2019 which found the MOPR could cost up to $5.7 billion per year.[2] The newest analysis finds the rule could cost consumers nearly $24 billion over the next nine years if FERC adopts minimum bid levels closer to PJM’s initial proposal rather then its most recent finding. Under that scenario, it is likely that subsidized nuclear units in Illinois, New Jersey, and Ohio will not be able to clear the capacity market. Under another scenario that assumes FERC adopts more recent PJM minimum bid levels, Grid Strategies still estimates that the rule will cost customers $10 billion over the same period. In this scenario, it is still possible that some units would not clear under PJM’s newest bid numbers.

Grid Strategies’ analysis comes in the midst of efforts by PJM to negotiate with stakeholders concerned by the MOPR’s potential impacts on state resource goals. Maryland and New Jersey have stated that they are looking at pursuing a Fixed Resource Requirement alternative which would allow parts or all of their state to secure capacity outside the wholesale market.[3]

[1] https://gridprogress.files.wordpress.com/2020/05/a-moving-target-paper.pdf

[2] https://gridprogress.files.wordpress.com/2019/08/consumer-impacts-of-ferc-interference-with-state-policies-an-analysis-of-the-pjm-region.pdf

[3] https://www.bpu.state.nj.us/bpu/pdf/boardorders/2020/20200325/3-27-20-2H.pdf

[USA] New Jersey looks to exit PJM capacity market, worried the MOPR will impede its 100% carbon-free goals

In response to the Federal Energy Regulatory Commission’s (FERC) December 2019 decision to expand the Minimum Offer Price Rule (MOPR) in the PJM capacity market, the New Jersey Board of Public Utilities (BPU) launched an investigation on March 27, 2020 to look into how that can achieve its clean energy objectives, including its goal of reaching 100% carbon-free energy by 2050.[1] [2] FERC’s MOPR rule raises the floor prices for state-subsidized resources which clean energy advocates believe could prevent new renewable resources from competing in the wholesale market, making it harder for states like New Jersey to achieve their clean energy goals.

The investigation will consider several questions, including whether a Fixed Resource Requirement (FRR) alternative can satisfy the state's resource adequacy needs, and if modifications to the state's default Basic Generation Service construct, the service provided to consumers who do not choose a third-party supplier, could facilitate resource adequacy procurements aligned with its clean energy objectives. An FRR approach would mean New Jersey withdraws one or more service areas from the broader PJM capacity market. An additional alternative to the capacity market would be to adopt a statewide clean energy standard that would require load-serving entities to source increased percentages of renewable or other clean energy.

[1] https://www.bpu.state.nj.us/bpu/pdf/boardorders/2020/20200325/3-27-20-2H.pdf

[2] https://assets.documentcloud.org/documents/6589824/20191219-3124-33920957.pdf

[USA] “PJM Files Capacity Market Proposals on Generator Subsidies- Seeks to Protect Benefits of Competition While Accommodating States’ Policies”

[PJM, 9 April2018]

PJM has requested FERC to identify how the wholesale electricity capacity market should respond to state subsidies of energy generators. In their filing, PJM has included two proposed solutions: 1) PJM’s recommended solution, Capacity Repricing, would “create a two-stage capacity auction process to accommodate state subsidies without distorting market prices;” and the other proposal 2) MOPR-Ex, which (as the name implies) extends the Minimum Offer Price Rule (MOPR) to “require a subsidize generation resource to remove the effect of the subsidy” from its capacity market bid. PJM has requested FERC make a decision on its subsidized proposals by June 29. A decision by this date would see tariff changes implemented by January 2019 and thereby allow the chosen proposal to take effect by the May 2019 annual capacity auction.