Published: March 24, 2025
By Danielle Powers and Mark Karl
Key Takeaways:
- While capacity markets have historically played an important role in supporting grid reliability, their foundational design no longer reflects the realities of today’s power grid. These markets were built around a generation fleet dominated by dispatchable resources, yet the current mix increasingly includes intermittent renewables and resources shaped by policy objectives.
- Some of the core assumptions embedded in capacity market structures, such as the idea that all capacity resources contribute equally to reliability or that investment will consistently respond to price signals, have been called into question. Recent experiences with price volatility, shifting accreditation standards, and out-of-market interventions have raised concerns about whether these markets are sending the right signals to support long-term investment in reliability.
- These challenges have prompted a broader conversation about whether the existing capacity market framework is sufficient on its own, or whether alternative models should be considered. Options such as bilateral contracting, centralized procurement, or new reliability products that reflect the specific attributes needed to operate the grid may offer more tailored solutions for today’s changing landscape.
For decades, capacity markets have played a central role in the design of wholesale power markets in the United States, particularly in regions such as PJM, ISO-New England, and NYISO. These markets were originally established to help ensure grid reliability by securing adequate generation to meet peak demand. However, as resource portfolios evolve, renewable energy grows in prominence, and policy priorities shift, questions have emerged about whether existing capacity market structures remain well-suited to today’s energy landscape. These developments have prompted discussion around whether incremental adjustments are sufficient, or if more substantial reforms may be necessary.
The Origins and Evolution of Capacity Markets
Capacity markets were introduced in the late 1990s and early 2000s as part of deregulation efforts in the energy sector. Their purpose was to address the missing money problem, which is the gap between the revenue that generating resources need to cover their fixed costs and the revenue they actually earn in the energy and reserves markets. Capacity markets were introduced as a solution to this problem, providing an additional stream of revenue to ensure sufficient investment in generation capacity and long-term grid reliability.
The fundamental assumption was that all power plants contributed equally to system reliability, that all megawatts were created equal, and that a simple auction-based market could incentivize investment in new resources as older ones retired. However, this model was built around a system dominated by traditional, dispatchable power plants—coal, natural gas, and nuclear generators—which provided energy and essential grid services such as voltage control, frequency stability, and inertia. These plants could be counted on to supply power and gird services whenever demand required it.
Another foundational element of capacity market design was that new generation entry would come as a result of a market signal for the needed capacity. The rapid expansion of renewable resources, along with the policies designed to incent and, in some cases, subsidize these resources, has upended these foundational assumptions. In addition, the price volatility and rule instability that result from constant “tweaking” of the design in an attempt to address shortcomings as they arise makes it difficult to support substantial investment.
Why Capacity Markets No Longer Work
Why are capacity markets increasingly seen as unsustainable in their current form? The reasons are simple: the foundational assumptions on which capacity markets were created no longer hold true.
- Mismatch Between Capacity Markets and Modern Energy Resources
The original design of capacity markets assumed that all qualified capacity megawatts were functionally equivalent. This is no longer the case. The modern energy mix includes a growing share of intermittent renewables like wind and solar, which do not always generate electricity when needed. Capacity markets have attempted to adapt through mechanisms like the Effective Load Carrying Capability (ELCC) rating process, performance incentives, and fuel supply requirements, but these changes are incremental fixes that fail to address the full reliability need and fail to address the larger issue: capacity markets are designed for a power grid and a supply resource mix that no longer exists. - Distortion from Public Policy Interventions
The rise of state-level clean energy mandates and direct subsidies for renewables has further complicated capacity markets. Many new renewable projects are entering the market not because of price signals, but because they receive out-of-market financial support to achieve specific policy goals. All else being equal, this artificially suppresses capacity prices, making it even harder for traditional generators to remain viable. As a result, necessary resources are being pushed toward retirement, even when they are still essential for reliability. Capacity markets were never designed to accommodate these policy-driven shifts, and they have proven ineffective at integrating them into the broader reliability framework. - Failure to Account for Essential Grid Services
Traditional power plants provided a “bundle” of reliability attributes beyond just megawatts of capacity. They offered fuel security, , frequency regulation, and fast-ramping capabilities. Although different resource technologies provided different quantities of these attributes, for the most part, they provided the full “bundle.” New capacity resources, particularly renewables, do not inherently provide all these same services, yet capacity markets still treat them as interchangeable with traditional generators. This has led to reliability gaps, forcing grid operators like PJM to intervene with out-of-market payments to keep critical plants from shutting down. If grid operators must frequently override market outcomes to ensure reliability, it is a clear indication that the market is failing. - Increasing Market Volatility and Inefficiencies
Capacity market prices have become increasingly unstable, fluctuating from near-zero levels in oversupplied years to dramatic spikes when retirements accelerate. The most recent PJM Base Residual Auction saw prices jump nearly tenfold, largely due to resource retirements and new constraints placed on capacity accreditation. Such volatility discourages long-term investment in new generation, as developers cannot count on stable revenue streams. This instability undermines the very purpose of capacity markets, which is to provide financial certainty for generators and ensure long-term resource adequacy. - Inability to Adapt to Rapid Changes in Demand
Since capacity markets were first introduced, electricity demand in the U.S. has grown modestly overall. From the early 2000s to the mid-2010s, total electricity consumption remained relatively flat, influenced by improvements in energy efficiency, a shift toward a more service-based economy, and the decline of energy-intensive manufacturing. As a result, capacity markets provided sufficient incentive for the construction of new generation resources. However, the demand for electricity from data centers is expected to grow significantly in the coming years due to the rapid expansion of cloud computing, artificial intelligence (AI), cryptocurrency mining, and the electrification of the economy. According to the NERC 2024 Long-Term Reliability Assessment, summer peak demand for the U.S. is expected to grow by 132 GW over the next 10 years, significantly greater than the 80 GW projected in the 2023 assessment. Given the substantial challenges faced in recent years in meeting even modest load growth, it is extremely unlikely the current capacity construct and markets will be capable of delivering the resources needed in time to meet the projected increase.
What Comes Next? Alternatives to Capacity Markets
To borrow a phrase from FERC Chair Mark Christie, “we have a rendezvous with reality”. It is time to move beyond incremental adjustments to capacity markets and begin exploring alternative approaches to ensuring grid reliability. We can’t afford to continue to put reliability at risk when “baseload” retirements are happening faster than dispatchable generation can be added. As Chair Christie recently stated in comments made at CERAWeek when stressing the need for dispatchable resources to maintain grid reliability, “we’re simply not ready to run a grid where we don’t have dispatchable resources”. How can the current capacity market design incent dispatchable gas-fired resources critical to ensuring reliability when these resources might operate for a handful of peak hours during the year?
There are market designs, such as those used in MISO and ERCOT, that provide useful models. MISO relies on load-serving entities (LSEs) to demonstrate sufficient resource adequacy through bilateral contracts and self-supply options. ERCOT operates an “energy-only” market, where real-time prices reflect scarcity conditions and encourage investment in new capacity when needed.
Another viable approach is the creation of a centralized procurement agency—such as a state or regional power authority—that would oversee long-term reliability contracts. It is important to recognize that the creation of such an agency need not represent the abandonment of wholesale electricity markets. Certainly, the energy and reserves markets need not change, and can continue to provide the same efficiency benefits they do today.
The power authority need not own or operate supply resources either. Such an entity could competitively procure the right mix of resources on a contract basis from independent owners and operators to balance dispatchability, fuel security, reliability, affordability, and policy goals, rather than relying on an outdated market mechanism that no longer serves its intended purpose. The procurement process could also allow for self-supply by load serving entities, utilities, or municipal systems and would provide a more stable revenue stream to facilitate lower cost financing.
Conclusion
The electricity system is undergoing a fundamental transformation, and capacity markets are failing to keep pace. Designed for a different era, they no longer align with the realities of modern energy markets, technological advancements, and policy objectives. Instead of continuing to modify an outdated system, policymakers and grid operators should move toward market structures that better reflect today’s energy needs. Whether through direct procurement, LSE-led resource planning, or new reliability products that disaggregate the attributes currently assumed in the current capacity product, the time has come to move beyond capacity markets and embrace a model that ensures a reliable, cost-effective, and sustainable energy future.
Links to Cited Sources:
2024 Long-Term Reliability Assessment. North American Electric Reliability Corporation
“US Grid Must Embrace Natural Gas in ‘Rendezvous with Reality’: FERC Chair.” Upstreamonline.com
All views expressed by the authors are solely the authors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The authors’ views are based upon information the authors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
On February 20, 2025, the Federal Energy Regulatory Commission (“FERC”) issued a highly anticipated order under Section 206 of the Federal Power Act addressing concerns related to large loads co-located at generating facilities within the PJM Interconnection. The growing interest in co-location arrangements, particularly involving data centers and industrial facilities, has raised questions about how interconnected generators should serve these co-located loads when they are physically connected to an existing or planned generator on the generator side of the point of interconnection. These arrangements have introduced issues around potential cross-subsidization, cost shifting, grid reliability, resource adequacy, and jurisdictional boundaries.
In this show-cause order (“Order”), FERC found PJM’s Tariff to be potentially unjust, unreasonable, unduly discriminatory, or preferential for lacking explicit provisions on co-location arrangements. The Order highlighted several key issues:
1. Jurisdictional Debate:
Co-located arrangements introduce jurisdictional questions. Some stakeholders have argued that FERC’s jurisdiction should be limited to interstate wholesale transactions and that states should retain control over retail sales and behind-the-meter arrangements. Others argue that load served directly by a generator is analogous to behind-the-meter generation and is exempt from FERC oversight. PJM and others maintain that co-located loads still benefit from grid services and should thus fall under FERC’s oversight when those services affect wholesale rates and grid reliability.
2. Cost Allocation and Grid Services:
A significant concern is whether co-located loads can fully isolate from the electric grid and avoid paying their share of costs for transmission services and for ancillary services from PJM. PJM and its market monitor have argued that co-located loads should be treated like other grid-connected loads and should pay for network services, ancillary services, and capacity. Other stakeholders have countered that since co-located loads can fully isolate and not draw power from the grid, they should not incur transmission service charges.
3. Reliability and Resource Adequacy:
Several parties have highlighted potential risks that co-located loads might impose on grid stability, particularly when large loads bypass the traditional planning process. For example, sudden shifts in demand or the loss of a co-located generator could compromise grid stability. PJM emphasized that the rapid growth of such loads could strain existing capacity reserves and suggested that planning frameworks need adjustments to incorporate these arrangements effectively. However, proponents of co-located load arrangements have argued that such configurations can offer benefits like reducing grid congestion, easing interconnection backlogs, and energizing data centers more quickly.
In the Order, FERC directed PJM and the Transmission Owners to provide justifications for the current tariff or suggest changes within 30 days. These justifications must address concerns related to jurisdiction, cost allocation, reliability, and potential discriminatory practices. FERC requested answers to approximately 40 questions related to jurisdictional principles, the type of transmission service used under various configurations, cost allocation, and the impacts on the wholesale market and ancillary services.
Concentric Energy Advisors’ Wholesale Energy Markets practice helps utilities, independent power producers, and government entities shape and understand wholesale electric market design and operational issues. Contact Danielle Powers, Chief Executive Officer, at dpowers@ceadvisors.com or 508.263.6219 to learn more about our services.
— All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
Published: November 8, 2024
By Concentric Staff Writer
After over-riding its membership, on November 4, the national organization responsible for the reliability of the bulk power grid filed with federal energy regulators a suite of proposed new standards for inverter-based resources (IBRs) such as solar, batteries, and wind, to address problems with these systems in recent years.
On November 4, the North American Electric Reliability Corporation (NERC) made four separate filings to the Federal Energy Regulatory Commission (FERC) related to IBRs. NERC filed a petition for approval of two standards related to IBR ride-through performance during system disturbances (PRC-024-4, PRC 029-1); another requiring analysis and mitigation of IBR performance issues (PRC 030-1); a petition for approval of the proposed definition of the new term “Inverter-Based Resource”; and another establishing requirements of disturbance monitoring requirements for IBRs (PRC-028-1 and PRC-002-5).
“The proposed reliability standards are an integral part of NERC’s proposed framework to address IBR performance issues in a comprehensive and holistic manner,” the organization said in the filing for disturbance monitoring requirements for IBRs. “[T]he proposed reliability standards are part of a set of standards that collectively respond to the Commission’s directives for requirements addressing IBR ride-through settings, ride-through performance, data recording, and analysis and mitigation of unexpected IBR performance,” NERC said.
NERC said there has been widespread loss of generating resources—solar photovoltaic, wind, synchronous generation, and battery storage—across multiple “system events.” For example, the Blue Cut Fire in August 2016 in San Bernardino County, California, and the Canyon 2 Fire in October 2017 in Orange County, California, demonstrated a risk to grid reliability as IBRs were unable to ride-through the events. In 2022, NERC analyzed more than 10 grid disturbances involving widespread loss of IBRs, it said.
FERC in its Order No. 901 [RM22-12], approved in October 2023, had required NERC to file the IBR standards by Nov. 4 of this year. After disagreement among members, the NERC Board of Trustees in October invoked the special authority in order to allow the organization to meet the deadline, it said.
That lack of consensus led a NERC committee during an earlier August meeting to recommend that the board invoke its special authority “to ensure that systemic reliability issues associated with IBRs are addressed in a timely manner,” according to NERC documents.
In the Western Interconnection — the power grid that spans several western U.S. states, Canada, and parts of Mexico —IBRs are on the upswing, but they have introduced a number of challenges to reliability. IBRs lack the physical inertia that is inherent to traditional synchronous resources such as coal, gas, and nuclear, creating problems such as fault-induced delayed voltage recovery. IBRs also have trouble with the frequency response that traditional generation provides to the grid.
NERC’s Board of Trustees at an October 8 technical conference successfully revised the IBR standard, allowing it to be approved under a reduced voting threshold compared to its normal voting procedures. At an August meeting in Vancouver, NERC membership was unable to reach consensus on how stringent the standards should be.
FERC’s Order No. 901 required NERC to file the standards on a three-year staggered time frame. The commission required NERC to file IBR disturbance-monitoring data sharing, post-event performance validation, and ride-through performance requirements by November 4, 2024; IBR data and model validation by November 4, 2025; and planning and operational studies for IBRs by November 4, 2026. The Commission also directed NERC to develop and submit a work plan to develop new and revised reliability standards to address the IBR issues in accordance with that timeframe.
According to minutes from the October 8 NERC technical conference, Board of Trustees member Kenneth DeFontes recommended that the board use the special authority in order to file the standards in compliance with FERC’s November 4 deadline.
“[DeFontes] reported that while much of the hard work of NERC’s stakeholders is paying off, with progress made on important IBR reliability standards through the usual standard development process, NERC does not have a clear path forward on the IBR grid disturbance ride through standard,” the minutes say.
DeFontes said the board must consider its options to meet its regulatory responsibilities but noted that the board “does not consider these options lightly.” He also recommended continued participation by NERC members and industry representatives on the standard.
The board approved a package of Milestone 2 standards for IBR “ride-through,” which refers to the capability of solar, wind, and battery devices to continue operating during temporary disturbances or faults on the electrical grid. Inverters will ride-through the disturbance and remain connected to the grid instead of disconnecting immediately when voltage or frequency deviates from normal ranges.
The Milestone 2 standards were approved under NERC’s Project 2020-02, an initiative to develop and update standards for IBRs. NERC had identified that there was a gap in existing reliability standards, which were developed for traditional synchronous generation resources such as coal, gas, and nuclear.
The goals of Project 2020-02 are to update existing standards such as protection and controls, modeling, data, and analysis to make them more suitable for IBRs. These include requirements for more accurate modeling, performance verification, and coordination of protection systems. The initiative also has the goal of defining and enhancing ride-through requirements to establish clear and consistent requirements for IBRs to ride through system disturbances without tripping off.
NERC also has the goal of ensuring an accurate representation of IBRs in grid models, seen as critical for planning and analysis of operational reliability. This includes requirements for verifying that IBR models reflect their performance in the real world.
NERC’s Project 2020-02 included modifications to the PRC-024-4 standard and the development of the PRC-029-1 standard to initiate its development (frequency and voltage ride-through requirements for inverter-based resources), but the latter standard failed to achieve consensus through the usual standard-development process, NERC said.
The NERC board discussed issues surrounding the FERC Order No. 901 directives, including whether or not the proposed reliability standard PRC-029-1 is “just, reasonable, not unduly discriminatory or preferential, in the public interest, helpful to reliability, practical, technically sound, technically feasible, and cost-justified,” according to a NERC memorandum.
On Jan. 17, NERC also submitted its Order No. 901 work plan, which consists of key milestones to meet the FERC directives by the filing deadlines. The Milestone 2 standards, in progress, focus on the development of reliability standards to address disturbance monitoring, performance-based ride-through requirements, and post-event performance validation for registered IBRs by the Nov. 4 deadline.
While Project 2020-02, which addressed generator ride-through directives from FERC Order No. 901 had created controversy, Projects 2021-04 and 2023-02 are on track for timely completion through the usual NERC standard development process, the memorandum says.
FERC’s Order No. 901 cited multiple reports of events with IBRs as the reason NERC should have reliability standards for ride-through frequency and voltage system disturbances. The standards should permit tripping of IBRs only to protect the IBR equipment in scenarios similar to when synchronous generation resources use tripping as protection from internal faults, FERC said. Exceptions should be applied to certain IBRs, and finding consensus around those directives was a part of the main issues addressed during the technical conference, according to NERC.
FERC said NERC must require registered IBRs to continue to perform frequency support during any bulk-power system disturbance and that any new or modified reliability standard must also require registered IBR generator owners and operators to prohibit momentary cessation in the no-trip zone during disturbances.
Under FERC’s order, NERC was required to submit new or modified reliability standards that establish IBR performance requirements, including requirements addressing frequency and voltage ride-through, post-disturbance ramp rates, phase lock loop synchronization, and other known causes of IBR tripping or momentary cessation.
“Therefore, we direct NERC through its standard development process to determine whether the new or modified reliability standards should provide for a limited and documented exemption for certain registered IBRs from voltage ride-through performance requirements. Any such exemption should be only for voltage ride-through performance for those existing IBRs that are unable to modify their coordinated protection and control settings to meet the requirements without physical modification of the IBRs’ equipment,” FERC said in the order.
During deliberations among NERC members, many argued that the proposed PRC-029-1 definition was too broad and ambiguous, particularly the inclusion of phrases like “entire” and “in its entirety,” when referring to a generating plant or facility. Those parties recommended revisions to clarify the definition and ensure it aligns better with Institute of Electrical and Electronics Engineers Standard 2800, which covers interconnection and interoperability of IBRs, and interconnection with associated transmission systems.
Project 2020-02 will enhance reliability by requiring entities to perform energy reliability assessments to evaluate energy assurance and develop corrective action plans to address identified risks, NERC said. These energy reliability assessments should evaluate energy assurance across operations planning, near-term transmission planning, and long-term transmission planning or equivalent time horizons by analyzing the expected resource mix availability and flexibility and the expected availability of fuel during the study period.
According to NERC, IBRs are still being designed and installed without setting their protection and controls in accordance with their physical capabilities.
NERC had solicited comments from the industry as well as original equipment manufacturers on any information on hardware-based limitations that would prevent IBRs from meeting the proposed frequency criteria within PRC-029-1. The organization said 21 individual comments were received, including six from different original equipment manufacturers of IBRs. There were concerns that a draft of PRC 029-1 proposed frequency criteria that went beyond those established in IEEE 2800-2022 and there was a concern that IBR operators would not be able to meet those proposed frequency criteria, as IBR capability limits were hardware-based and inherent to manufacturer design.
Though the organization had failed to reach consensus among its members on some of the standards, the filing of NERC’s new standards will hopefully address the issues with IBRs that have raised their head in the Western Interconnection in recent years.
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All views expressed by the contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
Published: October 3, 2024
By: Concentric Staff Writer
Interconnection queue backlogs around the country are making it much more challenging to develop new generation projects, such as zero-emission resources needed to meet national decarbonization goals.
However, Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) that manage massive electrical grids around the country are responding, as is the federal government, to address the problem and make reforms. A key element of this response is Federal Energy Regulatory Commission (FERC) Order 2023, issued in July 2023, which aims to address interconnection queue backlogs, improve certainty for developers and others, and prevent undue discrimination towards new technologies.
Danielle Powers, Chief Executive Officer at Concentric Energy Advisors, is working on the front lines of the issue. Part of the solution, according to Powers, is to implement stricter requirements for demonstrating project “readiness” in order to decrease the number of speculative projects entering the interconnection queues.
“The independent system operators are taking steps to make the commitment to entering the queue more real, in terms of physical control and deposits, penalties or withdrawal fees,” Powers said.
A major concern that remains is the inability of many projects in interconnection queues to get built due to siting difficulties. This remains a challenge in ensuring that the resources needed to meet reliability and public policy goals actually get built.
Other than new zero-emission projects such as solar, solar/battery, and wind, other infrastructure such as data centers and electric vehicle charging stations are increasing demand at a time when an increasing amount of variable-output energy resources are being added.
In interconnection queue processes performed by ISOs, RTOs, and individual utilities, projects seeking interconnection must undergo a series of studies before they can be built. The studies determine which network upgrades are needed to interconnect, and the associated costs. Projects must also meet certain milestones and make payments to stay in the queue—the list of projects waiting to interconnect.
With the massive build-out of renewable generation happening on the U.S. grid, there were about 12,000 projects representing 1,570 GW of generator capacity and 1,030 GW of storage seeking interconnection at the end of 2023, according to Lawrence Berkeley National Laboratory (LBNL). Solar, storage, and wind projects make up about 95 percent of capacity in queues around the country.
Among a subset of queues for which data are available, about 19 percent of projects, or 14 percent of the capacity requesting to interconnect between 2000 and 2018, reached commercial operation by the end of 2023, LBNL said in its “Queued Up: 2024 Edition” report. Solar projects had a 14 percent completion rate, and storage projects had an 11 percent completion rate.
The average time projects spent in queues before being built has increased sharply, with the typical project built in 2023 taking about five years from the interconnection request to commercial operation, compared to three years in 2015 and two years in 2008, LBNL said.
FERC’s Order 2023 is meant to develop a new approach to interconnection as massive amounts of new resources come online.
“The growth of new resources seeking to interconnect to the transmission system and the differing characteristics of those resources have created new challenges for the generator interconnection process,” FERC said in the Order. “These new challenges are creating large interconnection queue backlogs and uncertainty regarding the cost and timing of interconnecting to the transmission system, increasing costs for consumers.”
Backlogs in interconnection queues also create reliability concerns, FERC said, as new generating facilities are unable to come online in an efficient and timely manner. More reforms are needed even after the issuance of FERC Order No. 845 , the agency said. FERC Order No. 845 adopted “reforms that are designed to improve certainty for interconnection customers, promote more informed interconnection decisions, and enhance the interconnection process.” FERC said.
Order No. 2023 implemented a “first-ready, first-served” cluster study process, which FERC said increases access to information prior to entering the queue; creates a mechanism to study interconnection requests in groups where all interconnection requests in the groups are equally queued and of equal study priority; and increases financial commitments and readiness requirements to enter and proceed through the queue.
The rule requires transmission providers to publicly post available information pertaining to generator interconnection and developers to use cluster studies as the interconnection study method.
The rule also requires transmission providers to allocate cluster study costs on a pro rata and per capita basis and to allocate network upgrade costs based on a proportional impact method. Interconnection customers must pay study and commercial readiness deposits as part of the cluster study process, as well as demonstrate site control at the time of submission of the interconnection request.
Transmission providers must also impose withdrawal penalties to interconnection customers for withdrawing from the interconnection queue, with certain exceptions. FERC also required transmission providers to adopt a transition process to move from the existing serial interconnection process to the new cluster study process.
Order no. 2023 will “increase the speed of interconnection queue processing and incorporate technological advancements into the interconnection process,” FERC said.
In the Pacific Northwest, the Bonneville Power Administration (BPA) switched to a “first-ready, first-served” interconnection queue process, a change from the “first-come, first-served” approach it previously used. Developers now must show they have site control and meet commercial-readiness requirements that include a cash deposit, an irrevocable letter of credit, or a deposit into an escrow account. BPA had 376 projects in its queue as of June, according to BPA materials.
In California, where a substantial amount of new zero-emission resources are coming online, queue reforms are underway to address the fact that only about 10 percent of projects in the queue come to fruition. Developers are faced with extremely long timelines for project development and a “stop-start” situation that makes it difficult in terms of site security, financing, and other areas.
CAISO’s normal level of about 113 interconnection requests per year grew to 373 in 2021, with more than 150 GW of projects sitting in its Cluster 14. CAISO went as far as requesting that FERC pause new interconnection requests, which FERC approved in March.
CAISO launched a series of reforms known as its Interconnection Process Enhancements, which it said were needed to avoid CAISO becoming out of compliance with Order. No. 2023 or being forced to file for a waiver. CAISO filed the tariff changes for the enhancements with FERC on Aug. 1.
“The CAISO interconnection queue now contains more than three times the capacity expected to achieve California public policy objectives for the next two decades and far exceeds the ability of available and planned transmission to deliver power from all of these projects to customers,” CAISO said in the filing.
CAISO said its reforms maintain open access in the region and that the ISO will now identify the most viable and needed projects and allow them to advance through the queue. This will be done in zones with sufficient transmission capacity, providing resource diversity and availability in the queue.
CAISO noted that clogged queues create “unsustainable strain” on planning and engineering resources and that interconnection study results lose accuracy, meaning, and utility when the level of interconnection requests far exceeds the existing or planned transmission capacity in a given area. It is impossible to allocate deliverability, or the transmission capacity needed to deliver a generator’s energy to load during various system conditions, to all of the interconnection requests currently in the CAISO queue, the grid operator said.
FERC, in November 2022, also approved an interconnection process reform filing by the PJM Interconnection, which covers 13 mid-Atlantic states and Washington D.C. The filing transitions PJM’s queue from a serial “first-come, first-served” approach to a “first-ready, first-served” approach.
PJM has expressed concern about having enough generation to meet demand. The interconnection queue reform process will help clear the backlog of requests and get generation online more quickly, PJM officials said. The effort includes a “Queue Scope tool” that allows resource developers to more effectively assess the engineering and financial impacts of a project at various locations on their own before they formally enter the interconnection queue.
PJM had about 62 GW of projects that completed its study process by the end of 2023 and expects that number to be about 100 GW by the end of 2025. However, in 2022, only about 2 GW of new projects came online, with only about 700 MW of that being renewables. The grid operator had about 265 GW of projects seeking to interconnect in 2023, about 95 percent of which were renewables.
Reforms are also underway in the Midcontinent Independent System Operator (MISO), which covers 15 states. FERC in February approved MISO’s filing to re-work its queue process, which includes increasing milestone payments, adopting an automatic withdrawal penalty, revising withdrawal penalty provisions, and expanding site control requirements. Historically, about 70 percent of projects in MISO’s queue have never come to fruition, resulting in the need to restudy projects with lower queue positions.
MISO increased its Milestone 2 (M2) payment from $4,000 per MW to $8,000 per MW; its Milestone 3 (M3) from the greater of 20 percent of network upgrade costs minus the M2 payment or $1,000 per MW; and its Milestone 4 payment to 30 percent of network upgrade costs minus M2 and M3 payments.
MISO increased Point of Interconnection (POI) site control requirements to 50 percent site control from generator site to POI upon application, or $80,000 per mile for the entire line mileage to POI. It also required 50 percent site control from generator site to POI and 50 percent of interconnection switchyard, if necessary, prior to Phase 2. 100 percent site control is required from generator to POI, including interconnection switchyard, if necessary, prior to the execution of a generator interconnection agreement or within 180 days of execution with an approved exception.
It also imposed a new escalating automatic penalty upon withdrawal and an adjustment to the calculation for harm imposed by a withdrawal. These range from 10 percent of the Milestone 1 payment at decision point 1 of the process to 100 percent of Milestone 2 during generator interconnection agreement negotiations.
“These reforms are needed to reduce the number of queue requests withdrawing from the process,” MISO said on its web site. “The fewer projects in studies, the quicker it takes to complete; the fewer projects that withdraw, the more certain phase 1 and 2 study results are.”
In Texas, the growth of interconnection requests was noted by Oncor CEO Allen Nye in a recent second-quarter earnings call, during which he noted that interconnection requests in Oncor territory increased by about 100, or 13 percent from the second quarter of last year. The Electric Reliability Council of Texas projects that its peak load in 2030 will nearly double to 152 GW, compared to the current record of 85.5 GW, which was set in August 2023.
As Concentric’s Chief Executive Officer, Danielle Powers, noted, it’s a bit soon to see how much of a difference the ongoing efforts at the federal level and by RTOs and ISOs to reduce interconnection queue levels will make, but it’s clear that much work is underway.
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
Published: August 9, 2024
By: Concentric Staff Writer
Extreme weather has developed into the primary reliability threat to the Bulk Power System (BPS), although there were minimal severe weather threats to the grid last year, national reliability officials say.
Other than severe weather, other reliability threats pointed out by the North American Electric Reliability Corporation (NERC) are increased demand, problems with inverter-based resources (IBRs) such as solar and wind, and a rise in forced-outage rates for generation resources.
NERC recently issued a set of “actionable recommendations” from workshops held in March 2024 in conjunction with the National Academy of Engineering regarding electric reliability criteria for planning resource and transmission adequacy. Resource and transmission planning will be increasingly important as the grid transforms to cleaner, but more intermittent, renewable generation, the organization said.
NERC said there is a need for additional criteria, actionable short- and long-term recommendations, and next steps. The workshop concentrated on two broad topics: capacity vs. energy and planning the evolving transmission grid, the organization said in a report, entitled Evolving Planning Criteria for a Sustainable Power Grid.
Planning needs to evolve past the traditional loss-of-load standard of one day in ten years, which focuses on peak load, because this approach does not account for the growing risk in all hours that results from the increased variability and uncertainty caused by renewable generation, as well as increasing demand levels, NERC said.
NERC suggested that other methods, such as the Regional Energy Shortfall Threshold (REST), are being explored by the Independent System Operator New England, which reflects the region’s risk tolerance in regard to energy shortfalls during extreme weather. This is particularly relevant during extreme weather when impacted areas are highly reliant on long-distance transfers from other areas that have greater fuel diversity and sufficient resources to serve demand, NERC said.
The organization said extreme weather events are disrupting electricity supplies at “unacceptable levels,” citing the 2020 heat dome in California and Mexico, Winter Storm Uri in 2021, and Winter Storm Elliott in 2022.
“Given that electricity plays an essential role in modern society, energy adequacy is a critical complementary consideration of resource adequacy to ensure overall system reliability,” NERC said in the report.
A major factor affecting reliability is the growth of data centers and cryptocurrency mining, which NERC said can have a significant effect on demand and resource projections as well as system operation. Cryptocurrency mining refers to the way cryptocurrency coins are created and how transactions are verified. The process involves blockchain and a decentralized ledger to verify that a sender has adequate funds and is not “double-spending” coins. Cryptocurrency mining requires solving complex mathematical puzzles and is designed to require substantial computational effort, which increases as more miners join the network. Miners need to run their computers 24-7, creating massive energy demand.
The Electric Reliability Council of Texas (ERCOT), for instance, has a huge number of interconnection requests from cryptocurrency miners, with nine gigawatts (GW) worth of approved planning studies and 41 GW of studies currently requested, NERC said in its 2023 Long-Term Reliability Assessment.
“This new category of large flexible loads is leading some areas to update load forecasting methods to capture the flexibility and price-responsiveness of cryptocurrency mining operations,” NERC said in the assessment. “In anticipation of further growth in large flexible loads, ERCOT and its stakeholders are assessing further operational issues that could emerge, such as the effect on system frequency of sudden changes in large flexible loads.”
In another report, the 2024 State of Reliability Overview, NERC noted that the Texas Interconnection has improved greatly in reliability by using battery energy storage to support system frequency. Texas can no longer meet summer and winter peak demand with only conventional generation “and has demonstrated how these challenges can be successfully managed while at the same time encountering new ones.”
California has been adding an unprecedented amount of energy storage to its grid, helping it to meet peak summer demand. The California Independent System Operator said that the amount of energy storage is approaching 10 GW, which has helped it manage the grid this summer.
Coal unit retirements and the impact of IBRs such as solar and wind continue to impact the BPS; for example, disturbances to battery energy storage in California (March and April 2022) and solar in Utah (April 2023). Disturbances in IBRs are no longer limited to solar generation, the organization said in the State of Reliability Overview.
As a result, the Federal Energy Regulatory Commission in October 2023 directed NERC to develop new reliability standards for IBRs, saying they will help the reliability of the grid by accommodating the rapid growth in solar photovoltaic, wind, fuel cell, and battery storage that is due to form a large proportion of new generation resources coming online over the next 10 years.
“Over the past several years, a handful of extreme weather events has increasingly been the largest challenge to BPS reliability, and the unprecedented magnitude of these events has dominated reliability trends,” NERC said in the State of Reliability Overview.
However, in 2023, the weather was less extreme, although there were still incidents such as flooding in California in January through March, winter storms and cold waves in the Northeast in February, Hurricane Idalia on the Gulf Coast in March, as well as tornadoes, heat storms and drought in various regions of the county. There were also record-setting wildfires in Canada that caused short-term outages on the transmission system.
Overall, Severity Risk Index days decreased in 2023, illustrating the ability of the BPS to withstand severe weather and the importance of advanced preparation, active management of the grid during extreme weather, and rapid response to events, NERC said.
Forced outages of generation units on the U.S. grid were at historic highs in 2023, exceeding rates for all years prior to 2021. Forced outages refer to unexpected events that disrupt the normal output of the unit, such as failures due to mechanical, electrical, or control systems, as well as natural events.
Despite no occurrence of major events comparable to Winter Storms Uri (February 2021) or Elliott (December 2022), the weighted equivalent of forced-outage rates for coal and cycled natural gas units remained high in 2023, NERC said. Forced-outage rates for hydroelectric units were also high, but this generation remains a much smaller portion of the fleet. NERC found that the decreasing reliability of coal generation, along with an increase in variable generation, will necessitate larger reserve margins going forward.
There is a correlation between the forced-outage rates for coal generation and the overall forced-outage rate for all types of generation, NERC said. The correlation includes the age of coal units and their outage rates, but the outage rate for coal units is affected more by an increase in needed maintenance and a reduction in service hours as these units age and face retirement. As coal units retire, they are increasingly being replaced by IBRs such as solar, NERC said.
Forced outages also continue to increase for wind generation, rising to 18.9 percent in 2023, compared with 18.1 percent in 2022, NERC said. While there is not an exact comparison to outage rates for conventional generation units, “the continued increase is of concern given the growth in wind generation over recent years,” the report says. New, expanded reporting requirements for both conventional and renewable generation went into effect in 2024, which will allow for expanded analysis of the performance of both IBRs and conventional generation in future years, NERC said.
Other emerging issues for the grid include the state of blackstart resources—specialized power plants that can start without any external electricity supply—that are critical in cases of outages. They often use auxiliary power sources such as batteries or diesel generation. Recent extreme winter weather events have exposed vulnerability to generating units and fuel sources that are not adapted to low temperatures, which raises issues regarding blackstart unit readiness, NERC said.
“The changing resource mix is cause for additional awareness of blackstart capabilities. Currently, few IBRs on the system are capable of grid forming control, one of the necessary components for blackstart resources”, NERC said in the Long-Term Reliability Assessment.
Another rising problem is that distribution transformers are in short supply nationally, with manufacturers unable to keep up with demand. Lead times for transformers are often longer than two years, and low inventories of replacement resources and lack of skilled labor have the potential to slow restoration efforts following hurricanes and other severe weather events. Access to grain-oriented electrical steel used in power transformers is another constraint, and new efficiency standards for distribution transformers proposed by the U.S. Department of Energy could worsen the challenges because they set up requirements that manufacturers are not set up to handle, NERC said.
Finally, local load growth is occurring, including industrial and commercial development, which includes data centers, smelters, manufacturing centers, hydrogen electrolyzers, and port electrification. New load being added to the system, such as data centers, require more heating and cooling than other commercial buildings, creating challenges in load forecasting and localized transmission development, NERC said.
The NERC reports provide a window into the challenges facing the grid, including weather, growing load, and other factors that ensure grid planners will have their hands full in meeting demand in coming years.
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
Published: July 2, 2024
By: Concentric Staff Writer
A proposal for a special arrangement whereby a planned Amazon data center would be directly supplied by a co-located nuclear power plant in Pennsylvania sent rapid ripples across the industry this month. Other users of the transmission system are sounding the alarm over its possible effects on other customers and the precedent it could set, supported by Concentric Energy Advisors (Concentric).
There has been a quick line-up of parties filing to intervene in reaction to the proposal filed on June 3 with the Federal Energy Regulatory Commission by the PJM Interconnection LLC (PJM), the grid operator of the mid-Atlantic region including 13 states and the District of Columbia. The deal concerns a data center campus formerly owned by Talen Energy that the company sold to Amazon Web Services for $650 million earlier this year and sits next to the 2,514-megawatt (MW) Susquehanna Steam Electric Station, which Talen Energy also owns. Amazon plans to develop a large data center at the site to be powered by the close-by nuclear plant, which would be the largest such installation in U.S. history.
The proposal filed by and for PJM as transmission provider, Susquehanna Nuclear LLC as interconnection customer, and PPL Electric Utilities Corporation would amend the existing interconnection service agreement (ISA) to raise from 300 megawatts to 480 MW the amount of co-located load from the data center and make other revisions and changes [Docket No. ER24-2172].
Concentric is among the commenters; on June 24 filing an affidavit from Chairman of the Board, John Reed and Chief Executive Officer, Danielle Powers. Concentric, drawing from its decades of experience in utility regulation, filed the affidavit in support of a protest of PJM’s filing that was submitted to FERC by Exelon Corporation (Exelon) and American Electric Power Service Corporation (AEP).
“The significance of this case lies in its potential to set far-reaching precedents for how similar situations will be handled in the future,” the Concentric filing says. “The sheer scale of the Co-Located Load presents unique challenges and complexities that have not been encountered before on such a magnitude.”
Ms. Powers, in an interview, said that the proposed amendment to the ISA provided little detail on the costs to other customers. It is this lack of detail and impact on customers that are so important to understand and why FERC must set this matter for hearing, she said.
“We need to understand what the issues are and what you are requiring of both the generator and the co-located load,” Ms. Powers said of the amended ISA. “Since the load is located behind the generator, there are many unanswered questions around how much and how the generator offers its capacity and energy into the PJM wholesale markets, and what the co-located load will or should pay under the PJM Open Access Transmission Tariff.” She also said that PJM and market participants have been involved in lengthy discussions on how to deal with co-located load and have been unable to come to a consensus. A filing places these unresolved issues in front of the FERC, she said.
The Concentric affidavit says there are substantial implications for the case as it could “fundamentally impact the regulatory landscape, influencing how regulators address cost allocation and rate design.” If the agreement results in significant avoided costs it could lead to other similar arrangements, leading to widespread cost-allocation issues and leaving unresolved questions of cost responsibility for using the electric grid, the filing says. The cost shift could be up to $140 million per year and the avoided transmission component makes up approximately 98 percent of the avoided costs, Concentric said.
In the protest filed by Exelon and AEP, the two companies said the matter must be set for hearing because of many unresolved facts and that it includes “by the filing’s own admission, an ISA that establishes novel configuration.” If FERC does not set the matter for hearing, it should reject the ISA amendment because it amounts to an “end run” around PJM’s stakeholder process and violates PJM’s tariff by creating a new type of load, the protest says.
“The Parties’ non-conforming ISA must be set for hearing because it raises more questions than it answers,” Exelon and AEP said. “Given the scant information provided in the transmittal, absent further factual development, the Commission will be unable to make an informed decision whether to accept the ISA and parties to the proceeding will be denied necessary notice and opportunity to raise informed protests before the Commission.”
There are huge financial consequences around the filing as there are likely to be many other similar situations, the protest says, and in the absence of other precedent, it is reasonable to think that other parties could take a similar approach.
“The number of expected, non-conforming ISAs that the filing anticipates could have a profound effect on the market,” the protest says. “Should large quantities of load rush to co-locate with generation on terms that bear even a resemblance to the ISA at issue here, PJM capacity markets will have steadily decreasing volume as the capacity resources flee to serve load that uses and benefits from—but does not pay for—the transmission system and the ancillary services that keep the system running.”
But Talen Energy (Talen) fired back in the public arena, on June 27 issuing a press release characterizing the proposal as a new way to deal with rising data center demand. Powering this new category will require both metered and behind-the-meter solutions, the company said.
“Exelon and AEP’s protest of the Susquehanna ISA is a misguided attempt to stifle this innovation by interfering with an ISA amendment agreed to and supported by all impacted parties – which Exelon and AEP decidedly are not,” the press release says. “The factual recitations in the protest are demonstrably false. The legal positions are demonstrably infirm.”
Nearly all of the issues raised by Exelon and AEP are not even subject to FERC oversight, Talen argued, because transmission is not implicated, and Talen has a right to contract with Amazon for long-term, committed power. It also said that PPL agrees that Talen has the right to sell power directly to Amazon, and the filing is supported by PJM, it said.
The proposal to FERC by PJM and others involved in the co-located data center/power plant project raises many new questions regarding what is being recognized as a new frontier in energy infrastructure development. As of June 29, there were 33 motions to intervene filed in the docket.
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
Published: February 27, 2024
By: Concentric Staff Writer
National reliability officials recommended a study of whether additional natural gas infrastructure, including new interstate pipelines and storage, is needed to maintain electric grid reliability in severe cold, among the lessons learned from Winter Storm Elliott that occurred in December 2022.
The study of additional infrastructure to support natural gas local distribution companies (LDC) was among the recommendations in the Joint Report on Winter Storm Elliott, which analyzed the severe cold weather event that took 1,700 generation units offline in the Eastern Interconnection. The report was jointly issued by the North American Electric Reliability Corporation (NERC), an industry-based group responsible for creating and enforcing national reliability standards, and the Federal Energy Regulatory Commission (FERC), an agency tasked with enabling reliable, safe, and economic energy service for U.S. consumers.
The NERC/FERC report recommends that an independent research group, such as national laboratories from the U.S. Department of Energy, should study possible infrastructure build-out as well as the associated costs.
“The purpose of the study would be to identify additional natural gas infrastructure needs, if any, needed to ensure the continued reliability of the electric and natural gas systems, and the preferred locations of such infrastructure, if applicable, including pipeline infrastructure, natural gas storage, and other supporting systems,” the report says. The study should also consider the needs in light of coincident peaks of LDC demand for natural gas for heating, as well as for demand from natural gas-fired power plants during long periods of abnormally cold weather, officials said.
“The study should analyze needs on a regional basis and consider current as well as forecast future needs, in light of our evolving and interdependent energy,” the report says. It should also look at whether there will be adequate natural gas infrastructure to accommodate the intermittence of new renewable energy resources and retirement of thermal generation resources, as well as recent patterns of natural gas production declines during severe weather events.
Other recommendations in the joint report include “prompt development and implementation” of revisions to reliability standards to strengthen generators’ performance during extreme cold weather; identification of generation units that are at the highest risk of problems in cold weather; assessments of freeze protection measure vulnerability; and engineering design reviews of units that have experienced cold weather outages. Also recommended is the identification of root causes of generation failures and a NERC/FERC study of the overall availability of “black-start” resources—units that can return to service quickly after a complete or partial shut-down.
Winter Storm Elliott, which plunged 18 percent of the Eastern Interconnection into outages, was just one of a series of major cold weather outages that struck the U.S. in recent years. While Elliott was the largest load shedding event in the Eastern Interconnection, the largest single such event was Winter Storm Uri in February 2021, which caused 20 gigawatts (GW) of load shedding by grid operators, mainly in Texas, and took out power for 4.5 million people, causing hundreds of deaths.
But the joint FERC/NERC report on Winter Storm Elliott points out that the situation in Texas during Winter Storm Uri and nearly a year later in the East during Elliott involved very different grids. What is more surprising is that the Winter Storm Elliott outages occurred in the highly connected Eastern Interconnection, unlike Texas, which has a grid almost completely isolated from both the Eastern Interconnection and Western Interconnection.1
“The quantity of firm load shed during Winter Storm Elliott was not as large as in the Winter Storm Uri event, but it is especially disconcerting that it happened in the Eastern Interconnection which normally has ample generation and transmission ties to other grid operators that allow them to import and export power,” the report says.
Winter Storm Elliott was characterized as both a bomb cyclone and an extra-tropical cyclone, moving from Upper Plains states in late December 2022, and hitting the East Coast on December 23 and 24. The cold and outages coincided with a spike in electricity usage causing many balancing areas in the East to declare energy emergencies (EEA). The 90.5 GW of unplanned outages stretched from Georgia to the Canadian border in the East and across the central U.S.
Similar to Uri, Elliott froze up natural gas system wellheads and other equipment, while the weather made maintenance and response impossible, leading to significant declines in natural gas production. There were reductions in gas pipeline pressure and 14 declarations of force majeure—unforeseen events that affect shippers’ ability to deliver gas on pipelines. Eight of 15 interstate pipelines queried for the report said there were 53 instances of power loss at facilities, totaling almost 467 hours. Outages averaged a few hours, although some went on for several days.
In the Northeast, pipeline operators reduced flows to other regions during Elliott and increased imports from Canada, while in the Southeast they increased outflows to the Midwest, decreased liquified natural gas (LNG) exports, and saw access to Northeast supply throttled. The Northeast in recent years has increased its production of natural gas, which normally leads to typical outflows of about 12.5 billion cubic feet per day (Bcf/d), but which were reduced to about 5.3 Bcf/d.
There were also some close calls. On the morning of December 24, Con Edison began experiencing drops in pipeline pressure and declared a gas system emergency, which included implementing specifications for curtailing users and reactivating an LNG regasification plant. Con Edison was in danger of cutting off some or all of its system users; even an outage of about 130,000 customers would have taken five to seven weeks to restore depending on the availability of mutual aid.
“Had it lost the majority of its system, over a million customers in New York City and nearby areas would have been unable to heat their apartments and houses while the outside temperature was in the single digits, for months,” the joint report says.
Outages at generation units are divided into broad categories in the report, including mechanical and electrical issues such as equipment failures, which formed 72 percent of these problems, and control system issues, which accounted for 12 percent. No other single sub-cause materially contributed to lost generation, the report says. Generators lost power as the coldness increased, including situations where generator gas or oil temperature became too low, metal components shrank, and oil viscosity in wind generators increased. The report notes that “a substantial majority” of generation units that reported freezing issues were operating at temperatures that were above the documented operating temperature requirements.
On December 24, 2022, gas production in the lower 48 states dropped to a low of 82.5 Bcf/d, a 16 percent decrease from December 21. The greatest declines in gas production were in the Marcellus and Utica shale formations. Generation outages began in the territory of the Southwest Power Pool (SPP) and MidContinent Independent System Operator (MISO). Neither regional transmission organization had to shed load, but SPP twice curtailed non-firm exports on December 23 because of lower reserves, and MISO and SPP began coordinating on regional directional transfer limits.
MISO declared an EEA 1 and EEA 2 on December 23. Tennessee Valley Authority (TVA) saw a rapid increase in generation unit outages early on December 23 and had lost 5 GW of generation by 6 a.m., causing it to declare EEA 1 and EEA 2. TVA began obtaining emergency power from Duke Energy, Southern Company, the PJM Interconnection, and MISO, but “this solution was short-lived,” the report says. These factors caused TVA to order firm load shed of 1,500 MW, about 5 percent of its system peak load.
Impacts on grid reliability due to cold weather are nothing new, and NERC has repeatedly warned of the risk. For instance, NERC and FERC in August 2011 issued a detailed joint analysis of an outage in Texas in February of that year that affected 1.3 million customer accounts, the “2011 Southwest Cold Weather Event.” 2 In an event similar to Winter Storm Uri that would occur a decade later, more than 4.4 million customer accounts were affected between February 2 and February 4, 2011, an event that also saw extreme natural gas delivery curtailments that were longer than electric customer outages because gas-fired equipment had to be relit.
More than 50,000 gas customers were affected in the 2011 outage, including more than 30,000 in New Mexico, along with customers in Arizona and Texas. That year, FERC and NERC launched a joint task force to inquire about the outages.
NERC and FERC listed capacity awareness, gas and electricity interdependency, transformer oil issues during cold weather, air duct icing, wind farm winter storm issues, rotational load shed, transmission facilities, and other factors as “lessons learned” from the 2011 Southwest Cold Weather Event.
In the joint NERC/FERC report issued in August of 2011, recommendations included that balancing authorities, reliability coordinators, transmission operators and generation owners and operators, in Texas and the Southwest view preparedness for winter as important as preparing for summer.
“The large number of generating units that failed to start, tripped offline, or had to be derated during the February event demonstrates that the generators did not adequately anticipate the full impact of the extended cold weather and high winds,” NERC and FERC said in the 2011 report. “While plant personnel and system operators, in the main, performed admirably during the event, more thorough preparation for cold weather could have prevented many of the weather-related outages.”
In a July 2013 report on previous cold weather events stretching back to 1983, NERC described six previous cold weather events in 1983, 1989, 2003, 2006, 2008, and 2010. There were also five cold weather experiences that caused operational challenges in February 1989, January 1994, January 2004, February 2006, and January 2007.
NERC and FERC said there were only three events that were comparable to the February 2011 Cold Weather Event in terms of load loss and generation outages. Those occurred in December 1983, December 1989, and January 1994.
In all the above events, however, there were two common themes observed: constraints on natural gas supply to power plants as well as generating unit trip-offs, derates, or failures to start due to cold weather due to problems like frozen sensing lines.
The first time ERCOT implemented load shedding region-wide was on December 21–24, 1989, when the grid operator shed 1.7 GW of firm customer load and curtailed natural gas supplies to generation units. The demand peak that occurred on December 22, 1989 was 12.4 percent above what was forecast. The temperatures during the 1989 cold weather event were the lowest in more than 100 years.
During those same days in December 1989, Florida also experienced extremely cold weather, which led to the curtailment of natural gas supplies. Record load of 34.7 GW due to the cold, combined with numerous generation units that were offline for maintenance, resulted in rolling blackouts of five to eight hours maximum. In both Texas and Florida, “the circumstances, size, geographic area, and impact on the bulk power system (BPS) of this event were deemed to be very similar to the February 2011 Cold Weather Event.,” NERC said.
NERC identified several familiar issues regarding the two incidents, including inadequate cold weather preparation, frozen ancillary plant equipment, fuel oil problems, and natural gas delivery curtailments. There were “numerous recommendations” for utilities in Florida and Texas, and certain corrective actions were undertaken by utilities.
NERC in the 2013 report said that common issues in the cold weather include the interdependence of the natural gas and electric systems, which continues to grow. Compressors used in the production and transportation of natural gas require electricity to operate.
Also, most generators purchase “non-firm” capacity, exposing them more to curtailments when supplies are tight, and there is competition between natural gas supply for electricity and natural gas for heating.
The cold weather outages that have struck the U.S. over the years have led to the development of cold weather reliability standards, which were issued by FERC in February 2023. The standards were developed from recommendations flowing from the joint inquiry into Winter Storm Uri to prevent such widespread outages from occurring again. NERC proposed the standards in October 2022, which include generator freeze-up protection measures, enhanced cold-weather preparedness plans, identification of freeze-sensitive equipment in generators, corrective actions for equipment freeze-ups, annual training for generator maintenance and operations personnel, and procedures to improve the coordination of load reduction measures during a grid emergency.
The FERC order implemented about half of the recommendations from the Winter Storm Uri FERC/NERC joint inquiry, and NERC is developing a second phase of the standards.
Though overall usage of natural gas for power generation might decline because of the transition to renewable energy such as solar and wind, the necessity of gas to balance the system against intermittent renewables could increase, the American Gas Association (AGA) said in a 2021 report entitled “How the Gas System Contributes to US Energy System Resilience.” But the current compensation model for gas is tied to the volume of gas delivered to power plants, which creates a disconnect between the value of the service and its compensation.
Natural gas infrastructure and replacement programs were designed to enhance reliability and safety, and have also contributed to “resilience,” defined as “as a system’s ability to prevent, withstand, adapt to, and quickly recover from system damage or operational disruption. Resilience is defined in relation to a high-impact, low-likelihood events.” The most common events that require a resilient grid are extreme weather events, the AGA report says.
The resilience needed to meet these challenges will be accomplished “through a diverse set of integrated assets,” the report says, adding that policies need to focus on optimizing the characteristics of both the electric and gas systems.
“Ensuring future energy system resilience will require a careful assessment and recognition of the contributions provided by the gas system,” the report says. “Utilities, system operators, regulators, and policymakers need new frameworks to consider resilience impacts to ensure that resilience is not overlooked or jeopardized in the pursuit to achieve decarbonization goals.”
Aside from the need for more natural gas system infrastructure for energy grid reliability and resilience, new pipelines are under construction to transport gas for export. There is more than 20 million Bcf/d of natural gas pipeline capacity under construction, partly completed or already approved to deliver gas to five liquefied natural gas export terminals that are under construction on the Gulf Coast, according to the U.S. Energy Information Administration.
FERC recently recognized the need to expand the natural gas system, approving in October a request by Gas Transmission Northwest LLC (GTN) to build and modify gas compressor facilities in Idaho, Washington, and Oregon (CP22-2).
“The proposed project will enable GTN to provide up to 150,000 [dekatherms per day] of firm transportation service on its existing system for delivery into Idaho and Pacific Northwest markets. We find that GTN has demonstrated a need for the GTN Xpress Project, that the project will not have adverse economic impacts on existing shippers or other pipelines and their existing customers, and that the project’s benefits will outweigh any adverse economic effects on landowners and surrounding communities,” FERC said in the order.
Another topic that has arisen in the wake of the outages is the need for reliability standards for the gas system, similar to what is in place for the electric system.
When FERC and NERC issued the final report on Winter Storm Elliott, FERC Chairman Willie Phillips in a written statement said: “I want everyone to take time during this Reliability Week to read this report and begin implementing these recommendations, particularly those addressing the interdependence of gas and electricity. The report highlights what I’ve called for before: Someone must have authority to establish and enforce gas reliability standards.”
NERC President and Chief Executive Officer Jim Robb said that the industry needs to implement the recommendations from the joint report as soon as possible.
“I echo the Chairman’s call for an authority to set and enforce winterization standards for the natural gas system upstream of power generation and local distribution,” Robb said in a written statement. “The unplanned loss of generation due to freezing and fuel issues was unprecedented, reflecting the extraordinary interconnectedness of the gas and electric systems and their combined vulnerability to extreme weather.”
1The three main components of the U.S. electric grid are the Eastern Interconnection, the Western Interconnection, and ERCOT.
2 Also referred to as the “February 2011 Cold Weather Event.”
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
Published: July 6, 2023
By: Concentric Staff Writer
Texas Governor Greg Abbott signed new legislation reforming the state’s utilities and allocating reliability costs to intermittent generation sources in the same week a searing heat wave set in and set electricity prices skyward.
Governor Abbott on June 9 signed HB 1500, a “sunset” bill, which is a regular reauthorization of the Public Utility Commission of Texas (PUCT), and includes several provisions to shore up grid reliability. The bill drew a negative reaction from some renewable energy interests over provisions they say are aimed at hindering clean-energy resources.
Reliability has become more of a discussion topic in Texas since February 2021 when Winter Storm Uri caused widespread outages and hundreds of deaths, mostly due to freeze-ups of natural gas infrastructure. Summer reliability risks include grid impacts due to high electricity load and hot weather—the Electric Reliability Council of Texas (ERCOT) issued a voluntary conservation call on June 20 from 4 p.m. to 8 p.m. central time that followed a “weather watch” from June 15–21.
The HB 1500 legislation requires generation resources, other than battery storage facilities, to demonstrate to the PUCT that they will be available to operate when called upon during times of highest reliability risk. The owner or operator must be able to meet the requirement by January 1, 2027, by supplementing or contracting with on-site or off-site resources, including energy storage. The legislation directs the PUCT to determine the average capability based on “expected resource availability” and seasonal-related capacity on a standalone basis.
HB 1500 also requires establishing an ancillary services program to procure energy for dispatchable reliability reserve services on a day-ahead and real-time basis to account for market uncertainty. It also requires a determination of the quantity of services necessary based on historical variations in generation availability for each season, based on a targeted reliability standard or goal. This includes the intermittency of non-dispatchable generation facilities—wind and solar—and forced outage rates for dispatchable generation facilities.
Under the new law, the PUCT cannot require any retail customer or load-serving entity in the ERCOT power region to purchase credits designed to support a required reserve margin or other capacity or reliability requirement unless the PUCT ensures that the net cost of the credits to the ERCOT market does not exceed $1 billion annually, less the cost of any interim or bridge solutions. The credits are available only for dispatchable generation and the credits must be obtained centrally to prevent market manipulation. A generator also cannot receive credits that exceed the amount of its generation bid into the forward market.
Generation units can receive a credit only for being able to perform in real-time during the tightest intervals of low supply and high demand on the grid, to be defined annually by the PUCT. The bill also establishes a penalty for generators that bid into the forward market but do not meet their assumed obligation. The bill also establishes a single ERCOT-wide clearing price for the credits program that does not differentiate payments or credit values based on locational constraints.
A new Grid Reliability Legislative Oversight Committee was also created through the new law, which will oversee the PUCT’s implementation of legislation related to the regulation of the Texas electricity market enacted by the 87th and 88th Legislatures. The eight-member committee will be composed of three members from the Senate, three from the House, and the Senate and House chairs having “primary jurisdiction over matters relating to the generation of electricity.”
The legislation requires the PUCT to file a report no later than December 1 each year that includes the annual costs incurred by load-serving entities that back up dispatchable and non-dispatchable generation resources to guarantee that a firm amount of electric energy will be available to the Texas power grid.
Following a review of the report, the PUCT will determine whether specific transmission or distribution system constraints or bottlenecks in Texas give rise to market power in specific geographic markets. If there is a finding that such constraints give rise to market power, the PUCT can order reasonable mitigation by requiring utilities and others to construct additional transmission or distribution capacity or both.
Environment Texas Executive Director Luke Metzger issued a statement in opposition to the passage of HB 1500, saying it favors fossil-fuel-powered generators and will lead to higher transmission costs for renewables.
“We need, and Texans want, more clean energy, not less,” Metzger said. “There is strong support for more wind and solar energy, more battery storage, more energy efficiency, and more interconnection with the national grid. Unfortunately, the Legislature ignored these solutions to strengthen our electric grid while protecting consumers and the environment.”
However, Brent Bennett, policy director with the Texas Public Policy Foundation, lauded passage of the bill.
“We commend the legislature for passing HB 1500, which renews the Public Utility Commission on the condition that they take up needed market reforms, including Governor Abbott’s 2021 directive to ‘allocate reliability costs to generation resources that cannot guarantee their availability,’ and to ‘ensure that all power generators can provide a minimum amount of power at any given time.’ These reforms are critical in light of the federal government’s profligate spending on unreliable energy sources and onslaught of regulations on reliable energy sources,” Bennett said.
The new legislation coincided with a heat dome that hit the state in recent weeks, which will increase electricity demand for air-conditioning. Early in the week of June 25, Texas was under a hazardous heat warning, with afternoon temperatures of 104 degrees Fahrenheit recorded on June 27.
ERCOT broke its peak demand record on June 19 at 79,304 MW surpassing the previous June’s record of 76,718 MW. ERCOT set 11 peak demand records in the summer of 2022, typically in the late afternoon and evening hours. The grid operator said it was using tools such as reserve power, calling for large customers to reduce usage and bringing more generation online sooner. ERCOT said that other than extreme heat and record demand, it was experiencing outages of thermal power plants, declines in solar in the evening hours and low performance from wind during the summer peak.
The conditions on the grid led to extreme wholesale market prices in excess of $5,000 per MWh[1] on June 20.
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
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[1]“ERCOT: Real-Time Price – LCG Consulting.” EnergyOnline, www.energyonline.com/Data/GenericData.aspx?DataId=4. Accessed 29 June 2023.
Published: May 12, 2023
By: Danielle Powers, Chief Executive Officer
There is no question that expanding the electric transmission system is a key factor in achieving the nation’s clean energy goals. The most efficient way to ensure that this happens, however, is being strongly debated.
FERC Order 1000 established reforms in transmission planning and cost allocation, and eliminated the Right of First Refusal (ROFR) for those incumbent utilities involved in regional or inter-regional infrastructure construction, with limited exceptions.1 In Order 1000, FERC reasoned that by eliminating long-standing monopolies, competition would be created, and innovation and cost savings would result. In eliminating utilities’ monopoly over regional transmission, however, FERC expressly left it to states to enact their own ROFR laws.
Utilities in Kansas, Missouri, Oklahoma, Mississippi, and Montana have successfully persuaded lawmakers to prioritize ROFR legislation. Indiana recently passed ROFR legislation, and legislation is anticipated in other midwestern states this year. States including North and South Dakota, Nebraska, Texas, Iowa, and Michigan have ROFR laws in place.
ROFR issues are also being re-examined at the federal level. Questions around the effectiveness of competition in transmission have prompted the FERC to consider giving incumbent utilities the right to build regional transmission if they partner with one or more unaffiliated, non-incumbent partners.
Critics of the ROFR argue that it can limit competition and innovation in the industry. By granting the incumbent transmission provider the first opportunity to continue providing service, it can create a barrier to entry for other providers who may be better suited to meet the needs of the market. Additionally, the ROFR can limit consumers’ ability to access alternative sources of energy and limit the development of renewable energy sources.
These arguments have recently carried the day in Iowa, where the battle over who should be able to build and own the regional transmission projects necessary to support grid reliability and the shift toward renewable energy is currently playing out.
The Iowa Supreme Court recently halted a 2020 order giving incumbent utilities in Iowa the right of first refusal to build proposed transmission projects. Stating that the 2020 law would stifle competition and harm the business interests of out-of-state companies, the Iowa Supreme Court sent the case back to the district court to decide whether the ROFR is unconstitutional. The temporary injunction affects five transmission projects totaling about $2.64 billion that ITC Midwest, MidAmerican Energy and Cedar Falls Utilities intend to build in Iowa. The projects are part of the Midcontinent Independent System Operator’s Long Range Transmission Planning Tranche 1 projects, approved last year.
The battle over who builds the grid of the future will continue to be fiercely debated. Protracted debate, however, risks the grid transformation necessary to enable a clean energy future.
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
1 An incumbent utility is defined as an entity that develops a transmission project within its own retail distribution service territory or footprint.
Published: March 16, 2023
By: Danielle Powers, Chief Executive Officer
The Massachusetts Department of Energy Resources (“MA DOER”) issued the framework for its proposed Forward Clean Energy Market (“FCEM”) in January of 2023, and invited written comments on the proposal. Comments were submitted by numerous interested parties, including market participants, utility ratepayers, advocacy groups, and concerned citizens. A review of the submitted comments revealed some common themes.
One of the most consistently submitted comments was the desire for a robust stakeholder process. Many parties requested that the MA DOER work with other New England states to establish a formal public stakeholder process to consider, discuss and debate the FCEM proposal via technical conferences and public comment periods. The parties reasoned that this would allow the involvement of stakeholders not directly involved in the energy markets (e.g., ratepayers, community groups, and environmental advocates) and give a voice to those ineligible to participate in meetings involving the design and operation of the New England energy markets. An open and transparent stakeholder process is critical in moving a proposal forward and designing a market with the greatest chance of success.
In addition, several parties recognized that the proposed market design is highly complex. This complexity can potentially restrict competition by developers and clean-energy resource suppliers, and substantially limit the possible benefits of the proposed market. In addition, it will take years to resolve questions and details around jurisdiction, governance structure, interaction with existing wholesale markets, multiple products and multiple commitment periods, and the auction mechanism.
The existing capacity market took dozens of meetings among over 80 stakeholders for almost two years to finalize and implement, and the proposed FCEM is far more complex than the current market. It is reasonable to assume that this market would not be implemented until 2025 for a 2028 delivery period at best. This delay is a critical issue in achieving the objectives of the FCEM.
The comments submitted also recognized the importance of alignment between the FCEM and the existing regional wholesale markets. For the FCEM to successfully meet region-wide policy goals and reliability needs, the market must be compatible with the existing wholesale markets administered by ISO New England. While this does not require FCEM and current wholesale market integration, the need to consider the obligations, requirements, and revenues associated with the FCEM in the existing wholesale markets is unavoidable.
Finally, several comments on the proposed FCEM centered around the failure of the existing capacity market in New England in advancing the state’s climate mandates and integrating these mandates into the competitive markets. This criticism is unfounded. The competitive energy markets are designed to provide reliable wholesale electricity at competitive prices, not to address public policy mandates.
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All views expressed in this summary are solely the current views of the Author and do not necessarily reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, and related companies, and the clients of Concentric Energy Advisors. The Author’s views are based upon information the Author considers reliable at the time of publication.