FERC last week ordered settlement procedures over Pioneer Trail Wind Farm’s request to recover $826,926 annually to provide reactive supply and voltage control in MISO.
The commission said the amount requested by the 150-MW Illinois wind project could be unjust and unreasonable but allowed the rate schedule to go into effect July 1 subject to refund (ER18-1473).
Construction of Pioneer Trail Wind Farm in 2011 | White Construction
“Pioneer Trail appears to have incorporated costs that may be unrelated to the provision of reactive service, including portions of ‘Turbine Generator Erection,’ ‘Turbine Generator Options’ and ‘[Supervisory Control and Data Acquisition System]’ costs in its accessory electric equipment cost category,” FERC explained.
Pioneer Trail, owned by E.ON Climate & Renewables North America, said it followed the reactive power rate methodology approved by FERC in 1999 for American Electric Power. The facility’s generation interconnection agreement with Ameren Illinois stipulates that it must provide reactive service, but Pioneer Trail claims it has been providing reactive power support to MISO without compensation since beginning commercial operation in 2012. It said it meets MISO testing requirements for voltage control capability because its turbines contain a power electronics system that regulates voltage and power in real time, allowing them to perform like a conventional synchronous generator.
“Pioneer Trail notes that there are differences in the types and quantities of equipment providing reactive power support between synchronous and non-synchronous generators, such as a wind turbine generator, but argues that, in both types of facilities, the costs of the generators/exciters, [generator step-up] transformers and accessory electric equipment can be separated from the remaining plant investment, and the portion of those costs attributable to the production of reactive power can be determined by applying an allocation factor,” FERC said.
Pioneer Trail pointed out that FERC has accepted reactive service rate schedules “for several similar non-synchronous wind generation facilities,” including three in the MISO footprint. The wind farm also acknowledged that its turbines will have a higher reactive power revenue requirement than traditional synchronous generators because there’s more equipment involved.
Ameren challenged Pioneer Trail’s revenue requirement filing, saying the calculation includes several errors and “over $19 million of indirect costs that are largely unexplained,” including about $13 million of network upgrade costs that “are not properly included in the calculation of reactive power rates.” Ameren also said Pioneer Trail’s calculation does not use FERC’s Uniform System of Accounts and contended the wind farm erred in only using 2017 operations and maintenance costs, instead of multiple years.
One thing is certain about the fuel security study PJM has begun: Many will be upset with the results no matter how it turns out.
In fact, just about everyone seemed unhappy with the scope and assumptions PJM officials outlined Thursday during a special Markets and Reliability Committee conference call.
Exelon’s Sharon Midgley urged PJM officials to broaden its proposed scope, while Calpine’s David “Scarp” Scarpignato lobbied for a narrower focus. James Wilson, a consultant for state consumer advocates, expressed concern that RTO officials were already moving on to potential “solutions” before understanding the problem.
The range of comments echoed the larger resilience debate sparked by the Trump administration’s bid to provide subsidies to struggling coal and nuclear plants.
The RTO said the goal of the study is identifying locations with fuel delivery risks, evaluating how resources can reduce them and determining the need for additional mitigation efforts.
PJM Vice President of Operations Mike Bryson and other RTO officials told stakeholders the study is a continuation of resilience efforts since the 2014 polar vortex, which led to tougher nonperformance penalties under Capacity Performance.
Under the revised plan described by officials last week, PJM will use a base load scenario with a 50/50 peak for winter 2023/24 (134,435 MW). The extreme winter case will be based on the three cold spells in the past 45 years that each lasted for 14 days (1989, 1994 and 2017/18).
| PJM
It will look at two “credible” pipeline disruption scenarios: a “medium impact” disruption that cuts downstream capacity by 50% and a “high impact” event eliminating downstream flows.
During last week’s two-hour meeting, Exelon, the nation’s largest nuclear operator, and Calpine, the largest natural gas generator, took opposing views of the appropriate scope.
Exelon’s Midgley said PJM’s analysis should look at the entire winter period rather than just a two-week cold spell. For example, she said, if oil inventory is depleted during a cold snap, the system may have difficulty meeting load later in the season. “We don’t want to cast the net too narrow … as we’re trying to think about the realm of possibilities,” she said.
Calpine’s Scarp responded that PJM should avoid overly extreme scenarios. “If you want to get really extreme, you can say it’s really cold out, a meteor strikes and there’s a tsunami that hits all at once,” he said. “At some point you’ve got to draw a line. [Consumers are] only willing to pay so much for this.”
Midgley said exclusively focusing on extreme weather would be too narrow. “Cyber and physical attacks can create fuel disruptions far more catastrophic than those caused by the recent bomb cyclone,” she said.
9/11 Invoked
In its written comments last month, Exelon invoked the terrorist attacks of Sept. 11, 2001, to make a similar point. “Constraining the study assumptions to the severity and duration of recent historical weather events is the equivalent of what the government and the airline industry did on Sept. 10, 2001, and fails to reflect all realistic potential scenarios that PJM could face,” it said.
It also said PJM should analyze “simultaneous weather and man-made infrastructure/cyber events,” suggesting that terrorists might wait for a lengthy cold spell to launch an attack. “The highest stress resilience scenarios arise when extreme weather co-occurs with an infrastructure disruption. Therefore, any baseline scenario should jointly consider the extreme weather scenario as occurring simultaneous with a high-impact, 90-day infrastructure disruption scenario.”
And it asked the RTO to evaluate “a realistic but extreme” scenario “that disrupts 80% of the natural gas pipeline infrastructure across the entire PJM region for six months,” representing “the severe threat that a major state adversary might pose.”
An Exelon spokesman said later that PJM’s proposed scope “gravely underestimates the resilience risks facing” the region.
“At a minimum, PJM needs to look at a case where all financially stressed nuclear units will retire to better understand and potentially mitigate resilience risks,” he said.
Premise Questioned
In their joint written comments, the Sierra Club and four other environmental organizations questioned the focus on fuel, noting that most outages result from transmission and distribution problems, not generation.
The environmental groups also challenged PJM’s proposed base capacity portfolio, which assumes an installed reserve margin of 16.6% — the minimum requirement in the RTO’s 2017 Reserve Requirement Study — rather than the 23.9% margin that resulted from the 2017 Base Residual Auction or the 22% margin from the 2018 BRA.
PJM also proposed a “stressed portfolio” that would have included additional coal and nuclear retirements beyond the base case and a “high-stressed” portfolio with still more coal and nuclear retirements that are replaced with natural gas.
Casey Roberts, senior attorney in the Sierra Club’s Environmental Law Program, said she was relieved that PJM has eliminated, for now, the “high stress” portfolio scenario “that had no basis in fact.”
“However, PJM couldn’t give a clear answer as to whether fuel-free resources (renewable energy and demand-side) would qualify as fuel-secure,” she said in an email after the meeting. “They also don’t seem to be taking stakeholder input seriously, as demonstrated by their lack of plans to respond to specific comments, and failure to reach out to groups with expertise on demand response and [energy efficiency resources] that participate in wholesale markets.”
The environmentalists and Advanced Energy Economy said that while PJM promised a “fuel-neutral” analysis, its proposal favors solid and liquid fuels and ignores the resilience contributions of renewables and demand-side resources.
Use of Confidential Intelligence
Roberts and consultant Rob Gramlich of Grid Strategies also questioned PJM’s plans to incorporate in the analysis confidential information from the Department of Energy on cyber and physical threats to fuel delivery infrastructure.
“The suggestion that DOE’s natural gas disruption scenarios will not be reviewable by stakeholders or even all of the PJM staff involved is also highly concerning, particularly if those disruption scenarios will be the basis for profound changes to [the capacity market] with enormous impacts on consumers,” Roberts said.
“There is a ‘credible’ scenario and then a DOE scenario,” said Gramlich, who coauthored a study asserting that resilience is more a function of transmission and distribution than generation. (See Report: Customer Needs Should Lead Resilience Effort.)
“I don’t think DOE should get to plug in assumptions if other interested parties don’t — certainly not ones the consumers who might be forced to pay more don’t get to see,” he said.
Consultant James Wilson said that although PJM’s approach to the analysis is appropriate, “they seem fixated on a particular approach to addressing the problem that may be costly and inefficient.”
In later comments to Bryson, Wilson questioned PJM’s statement in a FAQ document that the study will identify “the adequate level of required fuel security.”
“The study cannot do this,” Wilson said. “Only policymakers can make this call.”
Wilson said fuel security risks can be broken into three groups: plant outages, weather-related load levels and others “for which there is substantial historical data”; a second group regarding whether plants have firm gas transportation or oil backup, which he said “are uncertain but … are rather easily influenced by incentives”; and a third group that includes pipeline failures and cyber or terrorist attacks.
“There is no history upon which to base any assigned probability” to the third category, Wilson said.
Thus, he told Bryson, PJM should focus on evaluating scenarios and potential resilience metrics, “and not try to quantify unconditional risk (you can’t), or identify a ‘required level’ of something, or otherwise get too far ahead in selecting a particular extreme scenario for planning purposes.”
Exelon Seeks Distance from Coal
Like Exelon, FirstEnergy Solutions also argued in its written comments that PJM should consider more extreme scenarios, including a “pipeline failure impact on a large number of plants.”
“Any criteria to assess fuel security that are broad enough such that resources of all technologies and fuels can qualify as being ‘fuel secure’ will likely result in a system less secure than the status quo with natural gas as an even more dominant fuel source,” said FES, whose coal and nuclear plants could benefit from fuel security payments.
| PJM
Exelon, however, called for a broader resilience focus that does not lump coal and nuclear together, saying fossil fuels “stand to exacerbate the severe weather events that are interrupting electric service to customers in the first place.”
“If PJM plans to meet its fuel security challenges by retaining resources that burn coal or by incentivizing the addition of oil storage, it will be contributing to the very problem it is trying to solve,” Exelon said. “Planning a generation system that is resilient must include planning for a system that is both able to withstand interruptions and also does not contribute to interruptions by exacerbating climate change.”
Next Steps
PJM officials said they hope to complete Phase I of the study — the identification of potential system vulnerabilities and development of criteria to address them — by late July or early August. They will provide an update on their progress at a special MRC meeting July 26.
The completion of the initial analysis will lead to Phase II, a stakeholder process expected to run through October to develop methodology to incorporate vulnerabilities into PJM’s markets “if needed.”
In Phase III, the RTO said it will seek to address specific security concerns identified by federal and state agencies. Officials said any proposed capacity market changes would need to be filed with FERC by January to be in effect for the 2019 BRA.
POUGHKEEPSIE, N.Y. — Artificial intelligence, transmission needs and markets versus mandates topped the discussion at the Renewable Energy Conference hosted by the Business Council of New York State, the Hudson Renewable Energy Institute and Marist College’s School of Management.
AI will transform society and the energy sector, said John E. Kelly III, senior vice president for cognitive solutions and research at IBM.
“When I joined the company in 1980, my first job was to figure out how do we put 1,000 transistors on a tiny chip for our mainframes; today, we put 15 billion transistors on a chip the size of your fingernail,” Kelly said.
He shared how the benefits of AI stem from the exponential curve in data growth. He described how IBM’s Watson platform can absorb 30 years of data in a few minutes and then continue to “learn” as it interacts with people and individual case decisions, whether in health care or the energy industry.
The world’s fastest supercomputer requires 12 MW to mimic what the human brain performs on 20 W of electricity, Kelly said, but AI can spot what no human could. For example, when Australian energy giant Woodside adopted Watson, the computer determined that most hand injuries occurred around 11 a.m., so the company now sends text messages to rig workers at 10:45 a.m. to remind them to take a break or have a cup of coffee, reducing the accident rate.
“You are going to be disrupted and transformed by this technology,” Kelly said. “We’re finally going to be able to take advantage of the integration of renewable energy and traditional energy in ways that we couldn’t before.”
The industry spent many years talking about smart meters and gathering data, but not much was being done with the information, he said. AI can make sense of the high volumes of data produced by smart grids and distributed energy resource sensors, which can overwhelm the capabilities of human programmers.
“These machines will recognize patterns of disruption, predict capability for your equipment and your power lines, and I think ultimately it’s going to lead to a seamless distribution and storage of energy among all sources, and there will be very few humans involved in that real-time optimization and predictive capability,” Kelly said.
Darren Suarez, director of government affairs for the Business Council, asked whether the state will deliver on its energy policy promises, including 3 GW of solar by 2023; 1.5 GW of energy storage by 2025; and a 40% reduction in greenhouse gas emissions, 2.4 GW of offshore wind and 50% of electricity coming from renewable sources by 2030. (See NY Releases ‘Roadmap’ for 1,500-MW Storage Goal.)
The council emphasizes the importance of relying on markets rather than mandates to achieve the state’s environmental goals, Suarez said.
The state’s many programs, such as Reforming the Energy Vision, have been driven by the executive branch, led by Gov. Andrew Cuomo since 2013, rather than the legislature, which entails risks for longevity, Suarez said.
The state’s environmental targets might “have no staying power” if another governor with contrary ideas comes to office, as has happened at the federal level with President Trump pulling out of the Paris Agreement on climate change, Suarez said.
Consolidated Edison’s consultant IHS anticipates U.S. renewable volumes will double by 2040, driven by solar and land-based wind, said Joseph P. Oates, chairman of Con Ed’s non-utility businesses.
Oates oversees 1,100 MW of renewable energy projects around the country, ranging from a 1-MW behind-the-meter solar project in Brooklyn to the 350-MW Copper Mountain 3 solar project near Las Vegas, which covers 8 square miles.
“If you were going to power New York City’s load just with solar, you’d have to cover the five boroughs with panels,” Oates said. Alternatively, relying solely on offshore wind would require more than 800 of the newest 12-MW turbines.
State and regional efforts to decarbonize the economy are driving renewable energy growth in the Northeast, but in New York, “you need to do some energy efficiency, and that’s really a key strategy because it is the least expensive way to decarbonize,” Oates said.
“Today we’re at a little over 1,700 MW of renewables in New York state,” NYISO CEO Brad Jones said. “We need to get to 17,000 more by 2030. We think about 14,000 of that is going to be solar and wind upstate because land is cheaper — and available.”
If that forecast is accurate, “we have got to make sure we have enough transmission available to move that energy downstate to our load centers; otherwise we won’t get the benefits of it,” Jones said, who noted the state is “making some good progress” on projects that improve transmission flows from the western to central part of the state. The ISO is also seeking board approval for another line that will approve transfer capability in the Lower Hudson Valley. (See NYISO MC Supports AC Transmission Projects.)
New York hasn’t built much transmission since the 1980s, with 80% of the state’s transmission assets built prior to 1980, he said.
“The system’s quite old, so we need to develop the system in order to bring more renewables downstate,” Jones said.
The 2,400 MW of offshore wind being planned in New York “comes in at a great location in the state, on the backside of our load, so it’s a fantastic location, but we have to figure out how to bring that wind onshore, how to distribute it appropriately, so we don’t have great impacts on the system,” Jones said.
Kevin T. Knobloch, president of New York OceanGrid, owned by Anbaric Development Partners, made a case for planning “open access” offshore wind energy transmission before the first turbines go in the water.
Anbaric has filed HVDC interconnection requests for 800 MW into the Farragut substation in Brooklyn and for 800 MW into the Ruland Road substation on Long Island for its hoped-for offshore wind grid.
Knobloch, who served as chief of staff at the U.S. Department of Energy from 2013 to 2017 and is a former president of the Union of Concerned Scientists, said, “New York can and should design and build a planned open-access offshore wind transmission system in which generation and transmission are separately constructed and owned.
“There’s a concern that if you follow our recommendation and plan it out from the start, that will slow down the process. We disagree and believe there’s a missed opportunity if regulators ask the first offshore wind generation developers … to also build transmission and run their own direct cables to shore,” Knobloch said.
Long-term planning from the start not only minimizes environmental impacts of laying unnecessary cables but also sends a signal to investors that the state is serious about this new multibillion dollar industry, he said.
Order 888 in 1996 showed that “FERC, from a public policy perspective, has long had concerns about monopolistic disincentives that don’t necessarily align with the public interest, or frankly, that of the grid operators,” Knobloch said.
“It’s no accident that Texas has the greatest amount of installed wind capacity in the country, and it has a lot to do with Competitive Renewable Energy Zones,” Knobloch said. “They figured out pretty early on that we have a good sense of where our wind resources are. We have a pretty good sense of where we need to deliver that clean electricity to the demand zones — let’s map it out, let’s plan it ahead of time, and the wind generators get to plug into this backbone.”
Dennis Phayre, business development director for EnterSolar, a commercial and industrial solar developer based in New York City, said, “Most of the generation that’s going to need to get built in order to reach these goals is going to be utility-scale, and it’s going to be upstate, so the need for transmission does not go away with renewables.”
The intermittency of wind and solar has become much less unpredictable, with new tools like Watson allowing forecasts of output 24 — or even 48 — hours in advance with up to 97% accuracy, so the “problem” of intermittency has largely been solved, Phayre said.
“There’s certainly some tension between transmission and renewables, but there’s probably more complement than there is tension,” Phayre said. “The question is, what complementary value does on-site generation provide at the right locations?”
“There’s no doubt that transmission infrastructure is required, which is easier to say than do,” said Craig Orchant, managing partner of investment banking firm Ansonia Partners. “The challenge is, you really can’t invest money in power generation unless you know you can deliver it. Transmission is a huge requirement, and it’s been to a large degree unanswered, not just in New York state, but across the region, throughout New England and a lot of other places throughout the U.S. Horror stories you read in PJM in terms of how they’re trying to allocate transmission improvement charges to individual participants in the market is a good example.”
On the plus side, energy projects “have a tremendous amount of capital looking to go to work in them,” Orchant said. “The amount of money that has been raised, and the knowledge base of institutional capital to invest in this industry is really phenomenal. I’ve been doing this for 30 years … and there’s never been so much money looking to go to work.”
Couch White attorney Michael Mager, who represents a coalition of large industrial, commercial and institutional energy customers, said many of the state’s programs and mandates require long-term commitments of customer money.
“For large-scale renewables, we’re looking at 20-year contracts, for offshore wind we’ve been talking about 25-year contracts,” Mager said. “The programs continue going to 2030, so we’re potentially making commitments now to go to 2050 or 2055, so we are making decisions that our grandchildren will be paying for.
“This is not to knock any specific program,” many of which have a lot of benefits, Mager said. “On an individual basis you could probably make a case for every single one of them, including what they may or may not cost, but no one is looking at the total costs.
“Even though we have more and more renewables, and we have a lot of nuclear, the marginal unit for the vast majority of hours is gas-fired, so right now we have low electricity prices primarily because we have low gas prices,” he said. “When we have higher gas prices at some point in the future, then the impacts of all of these programs and long-term commitments layered on top of that, we are concerned it will not be a pretty picture,” Mager said.
Mager was also concerned that every program relies on mandatory customer payments.
“When the Public Service Commission adopted the renewable portfolio standard in 2004, the order said, ‘We believe an important part of the RPS program is to stimulate and complement voluntary, competitive renewable energy sales and purchases, or free markets, so that these competitive markets, not government mandates, sustain renewable activity after the RPS program ends,’” Mager said.
“The RPS program ended a while ago, and we have more mandates than ever before.”
In 2018, it is rare to find someone that has not had multiple generations of a smartphone, adopting newer technology as it improves — ultimately making users’ lives easier and more efficient. However, in the world of rapidly modernizing infrastructure, the U.S. electric transmission system — part of the greatest engineering achievement of the 20th century — remains largely unchanged.
In Australia and the U.K., the story is somewhat different. Regulatory bodies in these countries recognize the radical evolution occurring in the energy industry — such as the growth of distributed generation, the proliferation of electric vehicles and the electrification of heat — is creating unprecedented uncertainty in a historically stable industry. Regulators want electricity providers to engage more effectively with their customers and other stakeholders to understand their needs and how they may change in the future. By instituting innovative incentives and frameworks, Australian and U.K. regulators are rewarding utilities that anticipate and respond to future uncertainty by leveraging innovative tools and business practices. These regulatory bodies have set up structures that encourage utilities to develop a more flexible and forward-looking approach.
In the U.K., for example, the RIIO framework — that is “Revenue = Incentives + Innovation + Output” — is the British energy regulator’s (Ofgem) performance-based framework for setting price controls and ensuring consumers pay fair prices. The RIIO framework financially rewards companies that innovate and run their networks to better meet the needs of customers, specifically focusing on increasing transfer capacity in the most efficient way possible. For example, for National Grid Electricity Transmission (NGET), Ofgem established a baseline ($/MW) that they anticipate network companies having to pay to increase transfer capacity across a specific boundary. However, if network companies develop a more efficient or lower-cost way to provide that same system improvement, half of the savings go to consumers and half of the savings go to the network shareholders. In this way, RIIO is encouraging network companies to think about their business differently than just making investments to add to the rate base.
Corrieyairack Pass Towers on Beauly-Denny transmission line | Scottish and Southern Electricity Networks
RIIO allocates incentives based on a utility’s ability to deliver specific, agreed-upon outputs in categories including safety, reliability, network availability, customer satisfaction, network connections and environmental. RIIO differs from past frameworks in that it establishes longer (eight-year) price controls and expands programs that encourage the growth of smart grids.
In Australia, the Network Capability Incentive Parameter Action Plan (NCIPAP) provides financial incentives to network businesses to improve usage of existing grid assets through low-cost projects. As a part of the plan, which is driven by the transmission owners, the Australian Energy Market Operator (AEMO) conducts independent analysis of network limitations, considering historical congestion, future network flows, and reliability and security implications — ultimately prioritizing the NCIPAP projects that deliver the best value for money for customers. NCIPAPs are intended to reduce congestion and drive reduced wholesale energy prices by alleviating existing transmission bottlenecks without investment in large infrastructure projects, and transmission companies earn 50% greater rate of return on these projects, which are capped at $6 million (AUD) capital spend.
500kv transmission lines in Australia
Conversely, from a U.S. perspective, while a number of proven, advanced technologies exist that can help optimize the existing transmission grid, proliferation has not occurred as utilities are often reticent to adopt emerging technology. From a regulatory perspective, there is limited incentive to choose efficient, low-cost options instead of adding traditional large capital projects to the rate base. This ultimately contributes to the sluggish pace of innovation and propagation of new technology needed to modernize a 21st century grid.
According to the Working for Advanced Transmission Technologies (WATT) Coalition, many of the U.S.’ existing regulatory structures are designed to directly or indirectly incentivize bigger capital investments and projects. This can result in disincentivizing investment in more relatively low-cost technologies that offer significant operational benefits and consumer savings; this is what both RIIO and NCIPAP are trying to address. WATT estimates that if advanced transmission technologies were adopted and deployed broadly, customers could see the cost of electricity reduced by as much as $2 billion per year.
The Energy Policy Act of 2005 has made strides toward policies to progress grid modernization, but it has not necessarily resulted in regulations that encourage the deployment of proven, newer technologies that would benefit grid operations and reduce costs. Instead, incentives are offered for advanced technology only if it is part of a grid expansion proposal and has demonstrated that there is some risk to its deployment. This is a challenge for utilities to embrace, as they will always prioritize reliability and safety over innovation.
Perhaps American policymakers would benefit from looking to our friends in Australia and Europe and how they have established frameworks that incentivize innovation in the electric utility space. Many hardware and software products exist today that can help improve existing transmission grid infrastructure, such as those that uncover and utilize hidden transmission capacity, reduce or reroute power flow on overburdened lines, and reconfigure existing grid elements to optimize various operational scenarios. When adopted and implemented, these technologies will result in consumer savings and improvements to reliability and resiliency — something regulators around the world continue to strive for.
Maggie Alexander is Director of the Western Region at Smart Wires, a modular, scalable, redeployable powerflow control technology company based in Northern California.
FERC on Monday approved part of PJM’s cost responsibility assignments for its updated Regional Transmission Expansion Plan but rejected allocations for four cross-border projects, instituting a Section 206 proceeding to revise the RTO’s Tariff language to address the reasons for its rejection (EL18-173, ER18-614, et al.).
The commission approved 41 projects, but rejected the allocations for the Targeted Market Efficiency Projects b2971, b2973, b2974 and b2975. PJM transmission owners had argued that PJM erred in not allocating project costs to Hudson Transmission Partners and Linden VFT, which operate merchant lines into New York City and had recently converted their firm transmission withdrawal rights to non-firm rights. Those lines would benefit from the TMEPs, other TOs contended.
| Fré Sonneveld/Unsplash
FERC rejected PJM’s argument that the Hudson and Linden facilities should be exempt, noting that PJM’s Tariff says, “Transmission congestion charges are incurred in the zones and merchant transmission facilities in which market buyers experienced net transmission congestion charges, regardless of whether the merchant transmission facility has firm or non-firm transmission withdrawal rights.”
PJM also recognized its requirement to assign TMEP costs in the zones and merchant facilities “shown to have experienced net positive congestion over a two-year historical period as determined by PJM and MISO” but didn’t allocate any costs to Linden or Hudson, nor provide any explanation, the commission said.
It also said Schedule 12 in PJM’s Tariff, which outlines cost allocations, is ambiguous about whether merchant facilities should be exempt from allocations, which PJM argued they should be.
“We therefore find that the most reasonable interpretation of the PJM Tariff is to allocate within PJM its share of the costs of TMEPs to those zones and merchant transmission facilities in PJM that are shown to have experienced net positive congestion over the two historical years, as determined by a TMEP study conducted by MISO and PJM,” the commission said.
FERC denied PJM’s use of two commission opinions and its decision to grant the requests from Linden and Hudson to convert their firm withdrawal rights to non-firm transmission withdrawal rights, saying they provide no guidance because they focus on different issues.
The commission ordered PJM to file new cost assignments that “must reflect Hudson’s and Linden’s pro rata share of the sum of the net transmission congestion charges paid by market buyers of the zones and merchant transmission facilities in which market buyers experienced net transmission congestion charges, as identified through the TMEP study.” PJM has 30 days to clarify the Schedule 12 language or show cause why it shouldn’t be revised.
FERC set the 206 proceeding to adjust Schedule 12 to conform with its interpretation in the order. Parties interested in being involved have 21 days to register. FERC set the refund date for when the proceeding is published in the Federal Register.
FERC also rejected protests from the Public Power Authority of New Jersey, the New Jersey Board of Public Utilities and Dominion, saying PJM adequately addressed them.
FERC on Monday denied ISO-NE’s request for a Tariff waiver to keep Exelon’s Mystic generating plant running, instead ordering the RTO to revise its rules to allow cost-of-service agreements for facilities needed to address fuel security issues (ER18-1509).
The commission’s July 2 show cause order instituted a Section 206 proceeding (EL18-182), finding that ISO-NE’s Tariff is not just and reasonable because the RTO lacks a way to address fuel security concerns that it said could result in reliability violations as soon as 2022. The Tariff currently allows cost-of-service agreements only to respond to local transmission security issues.
FERC ordered the RTO to submit interim Tariff revisions for a short-term, cost-of-service agreement for Mystic within 60 days, and permanent Tariff revisions to address future fuel security needs by July 1, 2019.
The commission also pushed back the deadline for Exelon to submit its retirement decision for Mystic Units 8 and 9 for Forward Capacity Auction 13 from July 6 to Jan. 4, 2019 — one month before the auction.
Commissioners Cheryl LaFleur and Neil Chatterjee wrote concurring opinions, while Commissioners Robert Powelson and Richard Glick dissented in part.
| ISO-NE
The RTO filed its waiver request on May 1, after Exelon said in March that it would retire the 2,274-MW plant when its capacity obligations expire on May 31, 2022.
Exelon later said it “may reconsider” the decision to retire Mystic if the markets could properly value the plant’s contributions to reliability and regional fuel security. (See Mystic Closure Notice Leaves Room for Reversal.) On the same day it issued the retirement notice, the company also announced it would purchase the Everett Marine (Distrigas) Terminal from ENGIE North America “to ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating.”
The commission agreed with the RTO that its January Operational Fuel-Security Analysis (OFSA) demonstrated that the loss of Mystic 8 and 9’s 1,700 MW would lead to 87 hours of depletion of 10-minute operating reserves and 24 hours of load shedding during the winters of 2022/23 and 2023/24. (See Report: Fuel Security Key Risk for New England Grid.)
The commission rejected the contention of some intervenors that the RTO had failed to demonstrate a compelling need for out-of-market action. (See Mystic Waiver Request Spurs Strong Opposition.)
‘Inappropriate Vehicle’
But the commission said that the waiver request was “an inappropriate vehicle” because it “effectively creates an entire process that is not in the ISO-NE Tariff” for cost-of-service agreements addressing fuel security. “Such new processes may not be effectuated by a waiver of the ISO-NE Tariff; they must be filed as proposed tariff provisions under [Federal Power Act] Section 205d,” the commission said.
Mystic Generating Station, on the Mystic River in Everett, Massachusetts. A wind turbine owned by the local water authority to power a pumping station is on the right.
Powelson said he “strongly” supported denying the waiver request, “which, if granted, would have amounted to an end-run around” the RTO’s stakeholder process.
“I cannot, however, support prematurely clearing a path towards out-of-market, cost-of-service payments to generators without having fully exhausting all other alternatives,” Powelson said in his dissent. “Unfortunately, rather than working through the stakeholder process, ISO New England acceded to the demands of Exelon and chose to file a tariff waiver.”
Powelson acknowledged that New England states have prevented investors from responding to market price signals by blocking new transmission and gas pipelines.
“While I agree that states have certainly interfered with market outcomes, by no means is this indicative of a market failure, nor does it justify a logical leap to the conclusion that out-of-market support to retain certain existing resources may be necessary,” Powelson said.
Glick called the ruling a “rush to judgment,” noting that the reliability concerns identified by ISO-NE are at least four years away.
“Instead of rushing to install new tariff provisions years before the fuel security concern may arise, the commission, ISO-NE and stakeholders should engage in a thorough process to evaluate potential fuel security problems and identify durable solutions rather than another series of Band-Aids,” he said.
Glick said the commission “has not clearly defined the fuel security problem” it is trying to address, quoting from the majority’s acknowledgement that that “fuel security analyses do not currently have an established methodological framework and that there are no industry standards or best practices for conducting such an analysis.”
He said although the commission’s order allows ISO-NE to argue that its existing Tariff is not unjust and unreasonable, “it is clearly a show cause order in name only.”
“In so doing, the commission cuts off an opportunity for a real debate about what the ISO-NE analysis actually tells us about fuel security. We can expect that ISO-NE will submit Tariff revisions based on that same analysis, without any further discussion of how that analysis should be used or how it could be improved.”
Glick said FERC and ISO-NE could find other solutions to their concerns, such as modifying the RTO’s transmission planning process to incorporate fuel security or “reforms to improve the utilization of existing pipeline capacity, which could potentially include additional hourly nomination service to increase both the transparency of market demand and provide improved price discovery.”
He said he agreed with Powelson that the order could undermine the RTO’s capacity market and its Competitive Auctions with Sponsored Policy Resources construct, approved in March. “By requiring ISO-NE to develop generic tariff provisions for cost-of-service treatment for resources needed for fuel security, the order provides an incentive for resources to seek that treatment rather than retire once uneconomic,” Glick wrote. “At a minimum, we should expect that retiring resources will use the prospect of a full cost-of-service arrangement as little more than leverage in order to extract a large ransom payment for exiting the market.”
LaFleur: No Precedent
Chatterjee wrote a concurrence saying the RTO’s predicament illustrates the need for the interim out-of-market measures he proposed when the commission rejected the Department of Energy’s request for bailouts of coal and nuclear generators. The commission instead initiated its resilience docket (AD18-7).
“Had a majority of my colleagues supported that position, we could by now have measures in place to address near-term fuel security and resilience risks in ISO-NE and other RTOs/ISOs,” Chatterjee said.
But LaFleur said that while she supported the waiver denial, “today’s order does not lend credence to a generic or national resilience need, or an approach to address that need. Rather, today’s order rightly responds to documented and specific regional challenges in New England, including its dependence on a unique generation facility that can be served only by imported LNG.”
Rising state subsidies for renewable and nuclear power require PJM to revamp its minimum offer price rule (MOPR) to address price suppression in its capacity market, FERC ruled Friday.
The commission ruled 3-2 that the rule, which now covers only new gas-fired units, must be expanded to all new and existing capacity receiving out-of-market payments, such as renewable energy credits and zero-emission credits for nuclear plants. Democrats Cheryl LaFleur and Richard Glick dissented, calling the ruling hasty and counterproductive.
The commission’s ruling — a rejection of PJM’s April “jump ball” capacity filing (ER18-1314) and a partial grant of a 2016 complaint led by Calpine (EL16-49) — initiated a Section 206 proceeding in a new docket (EL18-178).
The commission rejected both PJM’s capacity repricing proposal and the Independent Market Monitor’s MOPR-Ex proposal, saying neither was just and reasonable. It agreed with Calpine that the existing MOPR was also unjust and unreasonable but declined to adopt the company’s proposed remedy.
Instead it consolidated the two cases into the new docket for a “paper hearing” on an alternative approach in which PJM would expand the MOPR to all subsidized resources with “few to no exemptions.” FERC also recommended creating a mechanism similar to the fixed resource requirement (FRR) allowing states to pull subsidized resources — and associated loads — from the capacity auction.
Comments on the commission’s proposal are due in 60 days, with reply comments 30 days after that. The commission said it hoped to issue a final ruling by Jan. 4, 2019, in time for the 2019 Base Residual Auction.
PJM spokesman Jeff Shields released a statement saying the RTO “is pleased that the commission is taking action to address the price-suppressive impacts of resources that receive out-of-market payments.”
“The order appears to be a positive step to change competitive electric market design while recognizing the important role states play in influencing the resource mix through retail energy policies,” it continued. “We will begin work immediately to develop the kind of bifurcated capacity construct envisioned by the commission and actively engage stakeholders, including the states, within the timetable laid out by the commission. We seek to ensure markets continue to deliver reliability at the lowest cost, drive investment without imposing risk on consumers, align generator performance with grid operations, support economic development and encourage technology innovation.”
The commission said PJM’s capacity market has become “untenably threatened” by out-of-market payments resulting from state initiatives.
“What started as limited support primarily for relatively small renewable resources has evolved into support for thousands of megawatts of resources ranging from small solar and wind facilities to large nuclear plants,” the commission said. “As the auction price is suppressed [by subsidized resources], more generation resources lose needed revenues, increasing pressure on states to provide out-of-market support to yet more generation resources that states prefer, for policy reasons, to enter the market or remain in operation. With each such subsidy, the market becomes less grounded in fundamental principles of supply and demand.”
All PJM states excluding West Virginia, Kentucky and Tennessee have renewable mandates or goals.
| PJM
According to an analysis by Anthony Giacomoni, PJM senior market strategist for emerging markets, the percentage of the RTO’s load subject to renewable portfolio standards has risen to 8% from 2.15% in 2009. Giacomoni said the percentage will reach almost 13.5% in 2033, with New Jersey, Maryland, Delaware and Illinois hitting 25% and D.C. rising to 50%.
PJM’s Board of Managers submitted the “jump-ball” filing after stakeholders lobbied against capacity repricing, under which the RTO would have accepted bids from subsidized resources in its capacity auctions but then isolate them during a second stage and reset the price without them. Stakeholders were more supportive of the Monitor’s MOPR-Ex proposal, which would have extended the MOPR to all units indefinitely, with carve-outs for states’ renewable portfolios and public power self-supply. (See PJM Capacity Proposals to Duel at FERC.)
Capacity Repricing
The commission said the capacity repricing plan would disconnect the determination of price and quantity in the BRA, undermining its price signals.
“Though the second stage price may not be suppressed by uncompetitive offers from resources receiving out-of-market support, the higher price — created by repricing — would signal that the market would buy capacity from higher-cost resources than actually clear the market and receive capacity commitments,” FERC said. “This would make it more difficult for investors to gauge whether new entry is needed, or at what price that new entry will clear. … Market participants would see the final, second-stage clearing price but would have limited information on which resources received commitments and the first-stage price.”
The commission said the plan would result in a “windfall” to subsidized resources, which “would not only receive the same clearing price as competitive resources, but would then further benefit from the higher price set in stage two of the auction.”
“PJM’s proposal therefore will increase prices for load … [and create] an unjust and unreasonable cost shift to loads who should not be required to underwrite, through capacity payments, the generation preferences that other regulatory jurisdictions have elected to impose on their own constituents.”
The commission rejected PJM’s contention that its approach was similar to ISO-NE’s Competitive Auctions with Sponsored Policy Resources, a two-stage capacity auction to accommodate state renewable energy procurements, which FERC approved in March. (See Split FERC Approves ISO-NE CASPR Plan.) “CASPR does not allow [subsidized] resources unfettered access to the market, [and] it retains and strengthens ISO-NE’s MOPR for all new resources by phasing out the renewable technology resource exemption,” FERC said.
The commission also found that PJM failed to support its proposed materiality threshold for initiating repricing, which it set as either 5,000 MW of unforced capacity across the region or 3.5% of the reliability requirement for any locational deliverability area.
MOPR-Ex
The Monitor’s MOPR-Ex proposal would have extended MOPR to all fuel types while exempting self-supply, public power and electric cooperative resources — which the RTO said were unlikely to suppress prices — along with RPS resources.
The commission said PJM failed to justify the RPS exemption.
PJM said the 5,000 MW of renewables needed to meet RPS requirements in 2018 will grow to 8,000 MW by 2025. The RTO also said the Illinois and New Jersey ZEC programs could subsidize 4,760 MW of nuclear generation and that New Jersey and Maryland have authorized a total of 1,350 MW of offshore wind procurements.
10 of 13 PJM states and D.C. have renewable portfolio standards or goals. | NCSL
“PJM has not shown that the exempted resources have a different impact on its capacity market than those which are not exempted. Moreover, PJM’s assertion that the RPS exemption was based on deference to public policies favoring renewable generation resources is inconsistent with the well-established desire of some states in PJM to support other resources, such as nuclear plants,” FERC said. “In addition … it is unclear why state programs limited to offshore wind should not be eligible for the RPS exemption given that such resources would likely have a market impact similar to other exempted state-sponsored renewable resources.”
The commission acknowledged that it has approved MOPR exemptions for renewables in NYISO and ISO-NE but said those grid operators minimized price suppression by capping the amount of generation eligible for their set-asides.
Calpine Complaint
The commission agreed with a 2016 complaint by Calpine and 10 other generating companies, which alleged PJM’s MOPR was unjust and unreasonable because it failed to address price suppression by existing subsidized resources. (See Generators to FERC: Expand MOPR for Subsidized FE, AEP Plants.)
The company filed the complaint in response to ratepayer-funded subsidies then under consideration in Ohio. Although the Ohio subsidies were later withdrawn, Calpine amended its complaint in response to Illinois’ ZECs program.
“The increase in programs providing out-of-market support, such as ZEC programs, has changed the circumstances in PJM, such that it is no longer possible to distinguish the treatment of new and existing resources in the context of PJM’s MOPR,” FERC said.
But the commission rejected Calpine’s proposal that it immediately extend the MOPR to additional resources and direct PJM to conduct a stakeholder process to develop a long-term solution.
Addressing Double Payments
Although it has previously approved ways for customers to avoid paying twice for capacity because of state policy decisions, the commission cited appellate court rulings that it is not required to do so. “Nonetheless, we do not take this concern — or the states’ right to pursue valid policy goals — lightly,” FERC said.
As a result, it proposed a resource-specific “FRR Alternative” option allowing the removal of subsidized resources from the capacity market along with a commensurate amount of load.
FERC said its approach will improve transparency.
“Though the capacity market side of the bifurcated capacity construct will be relatively smaller, the expanded PJM MOPR will ensure that all resources participating in the capacity market, whether or not these resources receive out-of-market support, offer competitively. Further, the bifurcated capacity construct should make more transparent which capacity costs are the result of competition in the capacity market and which capacity costs are being incurred as a result of state policy decisions. Finally, depending on how load is selected for the new resource-specific FRR Alternative, this capacity construct should help confine the cost of a particular state policy decision to consumers within the state that made that policy decision, whereas the status quo requires consumers in some PJM states to subsidize the policy decisions of other PJM states.”
Dissents
The majority opinion quoted LaFleur’s earlier warning of “‘unplanned reregulation,’ one subsidy and mandate at a time.”
But LaFleur dissented from the ruling, calling the rejection of PJM’s current rules “a troubling act of regulatory hubris that could ultimately hasten, rather than halt, the reregulation of the PJM market.”
LaFleur said 90 days was insufficient time to determine “the most sweeping changes” to PJM’s capacity construct since its inception 12 years ago. She said she would have rejected capacity repricing while calling for further development of MOPR-Ex.
The FRR Alternative “presents resource owners and states with choices that could be difficult to make in advance of the May 2019 BRA, particularly given that some of the state programs are statutory in nature and could require legislative action to reform,” LaFleur wrote. “I do not share the majority’s confidence that this proposal is the obvious solution to the challenge before us, in no small part because it is not clear to me how this construct will actually work.”
In a separate dissent, Glick said the commission rejected PJM’s current Tariff based on “theory alone.” The RTO’s capacity surplus suggests prices are too high, not too low, he said.
He called the commission’s solution “arbitrary and capricious,” reciting a list of federal and state policies that subsidize or reduce the costs of nuclear power and fossil fuels.
“The commission’s real aim is to support certain resources that do not benefit from state efforts to address environmental externalities,” he wrote. “Doing so puts the commission on the wrong side of history in the fight against climate change.”
Commissioner Robert Powelson, who sided with Chairman Kevin McIntyre and Commissioner Neil Chatterjee in the majority, wrote a concurrence defending the ruling as long overdue.
“The issue of out-of-market support for preferred resources is not a new one. In 2013, the commission opened a proceeding to discuss the interplay between state public policy decisions and wholesale markets. In May 2017, the commission continued that effort by holding a two-day technical conference to further explore the issues. After years of open dialogue unconstrained by ex parte restrictions, the commission failed to provide guidance on one of the most pressing issues facing wholesale electricity markets,” he said. “Failure to take decisive action would be a disservice to PJM, its stakeholders and ultimately consumers.”
Next Steps
The commission acknowledged many details remain to be determined, inviting comment on issues including:
The scope of out-of-market support to be mitigated by the expanded MOPR, and how resources become eligible for the FRR Alternative.
How to identify the load removed from the capacity auction.
What MOPR exemptions should be permitted. “For example, should an exemption be included for self-supplied resources used to meet loads of public power entities? Alternatively, should those resources have the option to use the resource-specific FRR Alternative? What, if any, exceptions should be added to the MOPR for existing resources in the capacity auction?”
The length of time resources choosing the FRR Alternative must remain outside the capacity market and the mechanism by which they can return.
How the FRR Alternative would accommodate required reserves and whether any changes to the demand curve are necessary.
Whether federal sources of out-of-market support should be addressed by the commission and how the capacity market changes will interact with PJM’s fuel security initiative.
The commission acknowledged the magnitude of the changes it proposed and said PJM may request a waiver to delay the 2019 BRA, as it did in 2015 during development of Capacity Performance.
CAISO projects it will cost as much as $18.5 million to provide reliability coordinator (RC) services to areas outside its balancing authority, up from an estimate of $12.5 million in its original straw proposal.
The projected head count for the ISO’s RC services also jumped from 31 to 36 full-time employees — and from 50 to 55 full-time equivalents, including contributions from staff in other ISO divisions. The RC program would represent its own cost category within the ISO, alongside system operations, market services and congestion revenue rights services, but some functions would overlap.
By comparison, Peak Reliability, the Western Interconnection’s current RC, had a $45 million budget for 2018, which it said would fall to $31.2 million under a “transitional RC” plan, or $28.7 million if CAISO leaves the organization and all other funders remain. (See Peak Details Vision for ‘Transitional’ RC.)
Reliability Coordinator services will represent a new line of business with its own cost category for CAISO. | CAISO
CAISO attributed its increased estimates, in large part, to the high level of interest in its RC services. (See Most of West Signs up for CAISO RC Services.) The ISO plans to implement the RC program in its own balancing authority area in July 2019, followed by a rollout to other parts of the West starting two months later.
Under the $18.5 million scenario, 9% of CAISO’s $205 million in annual costs would be attributable to RC services, although those costs would be fully offset by fees paid by RC customers. The ISO estimates that RC customers will be charged 3 to 4 cents/MWh.
“This is a [financial] model including a significant portion on the Western Interconnection,” CAISO CFO Ryan Seghesio told stakeholders during a June 27 meeting to discuss the ISO’s draft final RC proposal. Seghesio noted the ISO has received letters of intent from a large share of the BAAs in the interconnection, while also acknowledging the nonbinding nature of those documents — and that some of the BAs have also submitted LOIs to SPP.
“If everybody in the Western Interconnection were to sign up for the ISO, would $18.5 million cover it?” asked Jim Shetler, general manager of the Balancing Authority of Northern California.
“This is the model, yes,” Seghesio said.
Getting the Rate Right
Deb Scott, senior attorney with Salt River Project, asked about the impact on the RC rate if CAISO attracts “less than a significant portion” of the interconnection to its RC services.
Seghesio explained that CAISO will file two different rate structures in its Tariff next year. The first will reflect the implementation of RC services for the existing CAISO footprint, which will not incur significant costs because the ISO already performs many of the reliability functions for its members.
But costs for the services will ramp up after the first non-CAISO members come on board, whether in September 2019 or later in the year, which will trigger use of the second higher-level cost structure for all RC customers, he said. The second structure will be scaled to align with the number of actual customers, so it may not hit the $18.5 million estimate.
Scott pressed for more details on how and when the RC rates would be set considering the uncertainty around the final customer base.
“FERC’s going to approve the rate design,” Seghesio said. “The actual rates won’t be determined until we do the revenue requirement each year, so when we get to the end of 2018, we’ll take the revenue requirement to the [CAISO Board of Governors] for approval, [and] that will kind of set this initial amount. By then we would have a better picture of what the service area will look like, and that will kind of set the rates.”
Gary Tarplee, principal adviser with Southern California Edison, asked whether CAISO’s 55-FTE estimate represents the top-end staffing requirement for an RC covering the full Western Interconnection, or if the number could exceed that.
“This is the full-cost model, whether it’s a significant portion or everybody, this model will work. We’re showing really what the highest cost would be,” Seghesio said.
He later clarified that the full-cost model is driven more by geographical diversity of the customer base than by its size.
“If we get some members in the Southwest and members in the Northwest, we really get to that full-cost model, because that determines the number of desks we really need,” Seghesio said. He said a larger customer base will reduce the rate “because you’re going to have more volume dividing into that $18.5 million.”
Billing Details
CAISO says it would levy a minimum $5,000 annual charge for RC customers with zero to low megawatt-hour volumes because they still require a “constant, although minimal, amount of attention.”
Seghesio also noted that, in response to stakeholder requests, the ISO is proposing to bill customers annually for services.
“The big push [among stakeholders] was not to go to a monthly process,” he said.
In cases of non-payment, the ISO would notify the rest of its RC customers of a pending default (and a potential supplemental bill), and inform the Western Electricity Coordinating Council and NERC.
“We would retain the ability to suspend the customer’s RC services, but we realize that would lead to reliability issues, so I think the plan is that we know we’re going to have to continue to provide reliability services for that entity so it doesn’t impact the overall reliability of the grid,” Seghesio said. “But we would notify WECC that we are no longer the RC of record for that entity.”
The ISO is proposing an 18-month initial commitment for new members to ensure recovery of integration costs, with a 12-month notice required for exiting after the initial period. The proposal calls for one annual onboarding and exit window each April.
CAISO plans to take its RC proposal to its board on July 25. It hopes to execute agreements with members by Nov. 15.
Just the third executive director in GCPA’s 35 years, Foreman has helped guide the organization as it has expanded its regional presence and developed a program geared toward women. The organization has added events in recent years in Louisiana, Arkansas and Mexico, and held its fourth emPOWERing Women’s leadership conference in January.
“With six grandkids scattered across the U.S., it is time to prioritize life,” Foreman told RTO Insider. “I need the time to enjoy them, and they me, while we can. Definitely a hard decision, but I know it is the right one.”
In announcing a series of breakfast seminars in Mexico City, Foreman pointed out last year that the organization is focused on the Gulf Coast.
“The last I checked,” Foreman said, “Mexico is on the Gulf too.”
Robert Downing, a Greenberg Traurig attorney deeply involved in the Mexican market, cited GCPA’s seminars and conferences south of the border as having “encouraged the exchange of knowledge and business contacts between Mexico and Texas.”
“Tom took the initiative to establish strong relationships with power industry professionals involved in Mexico’s historic energy reform,” he said. “These efforts formed the basis for continuing dialogue between industry experts from both the U.S. and Mexico.”
Foreman has been active in the GCPA since its founding in 1983. He joined the organization’s board of directors in 1996, becoming president in 2011 and then being named the executive director in 2013.
“The GCPA board and Advisory Board are deeply grateful to Tom for his exceptional leadership and management, demonstrated by the organization’s accomplishments during his tenure,” Clark Hill Strasburger’s Mark Walker, board president, wrote in an email to the membership.
Katie Coleman, a partner with Thompson & Knight and the board’s treasurer, said Foreman’s announcement was not “entirely unexpected.” Upon taking the leadership position, he told the board he planned to work for five to seven years.
“Tom is going to be hard to replace,” Coleman said. “As a former board member, he has been key in maintaining institutional knowledge. His skill in keeping everyone organized and on schedule has been important to GCPA’s growth.”
The organization has added 13 corporate members during Foreman’s tenure, increasing that number to 132. GCPA claims more than 300 individual members.
“He embodies the core principles of GCPA with his passion to promote healthy and sustainable competitive markets by providing GCPA members with top quality programs, events and business development opportunities,” Walker said. “He has also built a solid professional team at GCPA that shares his enthusiasm and is key to its many successes.”
Walker credited Foreman for the GCPA’s recent growth, citing a doubling of annual scholarships provided to college and trade school students seeking careers in the industry and the development of the GCPA emPOWERing Foundation, which supports women, students, young professionals and leaders in the industry.
Foreman has helped organize and host as many as six major annual conferences and dozens of smaller events that provide education and network opportunities to 4,200 attendees each year, Walker said.
A Houston native, Foreman holds a master’s in engineering and a bachelor’s in electrical engineering from the University of Texas at Austin. He has worked for Gulf States Utilities, the Lower Colorado River Authority (LCRA) and as a consultant to rural electric cooperatives and municipalities. He retired from LCRA in 2012.
The ERCOT system set a new record for June peak demand last week, reaching 69 GW on June 27 during the hour ending 5 p.m.
That shattered the previous record of 67.9 GW, which was set on June 1. The new record withstood strong challenges the following two days, with demand reaching 68.6 GW on June 28 and 68.4 GW on June 29.
ERCOT’s control room | ERCOT
Demand broke the pre-2018 record of 67.6 GW during eight hourly intervals over the three-day span. Real-time average prices only broke triple digits once during that time, hitting $128.98/MWh in the interval ending at 1:30 p.m. on June 29.
Temperatures climbed into the 100s F in much of Texas last week, with heat indexes approaching 110.
ERCOT has projected a summer peak of 72.8 GW in August, which would break the 2016 record of 71.1 GW. It says it has 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
