RENSSELAER, N.Y. — NYISO stakeholders are being asked to weigh in on how effectively the external Market Monitoring Unit (MMU) is performing its duties before the ISO considers whether to renew its contract.
The ISO’s Management Committee (MC) on Wednesday received the annual solicitation of market participant input on the MMU’s performance. Shaun Johnson, NYISO director of market mitigation and analysis, said the three-year MMU contract with Potomac Economics runs through March 31, 2019. The ISO’s Tariff calls for the Board of Directors to oversee and review the MMU’s performance.
The MMU’s duties include attending meetings with stakeholders; ensuring wholesale markets function efficiently and appropriately; and identifying market violations, design flaws and power abuses. The unit also evaluates significant proposed revisions to NYISO’s market rules.
An example of the detailed analysis performed by NYISO’s MMU. | Potomac Economics
The Monitor must additionally produce annual and quarterly state of the market reports assessing the performance of New York’s electrical markets. (See “Potomac Economics 2017 State of the Market Report” in NYISO Business Issues Committee Briefs: May 16, 2018.)
As presented at the Sept. 11, 2017, Budget and Priorities Working Group, the MMU budget for this year is $4.1 million, a $600,000 increase over the previous year to cover added cybersecurity costs and support capacity market enhancements.
Potomac Economics also monitors the ERCOT and MISO markets.
NYISO will accept stakeholder comments on the MMU’s performance until June 21, 2018. They can be submitted to Johnson at sjohnson@nyiso.com and Leigh Bullock at lbullock@nyiso.com. All written comments will be treated as confidential to protect commercially sensitive matters.
PJM is pressing FERC to make a decision on the RTO’s “jump ball” capacity filing, arguing that the commission is within its authority to do so and pointing out what it considers to be hypocrisy in opponents’ criticism of the filing (ER18-1314).
The RTO’s 38 pages of comments filed May 25 pushed back on widespread condemnation of PJM’s proposal that FERC choose between two plans to isolate subsidized resources within its capacity auction in order to prevent them from suppressing prices. (See PJM Capacity Proposals Widely Panned.)
PJM reiterated its claim that the “status quo is not an option,” arguing that either its own capacity repricing proposal or the MOPR-Ex developed largely by PJM’s Independent Market Monitor would be reasonable. It also addressed concern about asking FERC to choose between the proposals, contending that it could have filed its repricing proposal first and — if rejected — then filed the MOPR-Ex.
The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | BHI Energy
But PJM neglected to address the question of how it would have prioritized which of the proposals would’ve been filed first. The RTO received significant criticism for filing its own proposal — which would give subsidized units a capacity obligation but remove their influence from the calculation of the clearing price — without stakeholder support. MOPR-Ex, which would extend PJM’s existing minimum offer price rule to bar subsidized resources from receiving a capacity commitment, garnered more stakeholder support but ultimately failed in an endorsement vote.
PJM argued that the decision is within FERC’s authority and represents an important issue for the commission, noting the commission’s recent approval of “MOPR-style rules” in ISO-NE, a reference to its Competitive Auctions with Sponsored Policy Resources (CASPR).
“Ample precedent makes clear that PJM’s 2018 wholesale capacity market rules fall squarely within the commission’s exclusive jurisdiction, leaving no room for argument that changes to the offer price and clearing price rules somehow exceed the commission’s authority or rob states of their authority,” PJM wrote. “Restoring wholesale prices to just and reasonable levels — meaning a price higher than the price that would have resulted had the state program been ignored — is not an intrusion into state prerogatives.”
The RTO’s comments frequently cast the criticisms of its efforts as hypocritical.
“The commission should consider carefully each of these narratives, which in essence amounts to two sides of a single coin,” PJM said. “A curious outcome of all the advocacy around price consequence is discovery that the same parties claiming PJM’s prices are too low, in the next breath, argue for state and federal subsidy programs because such programs will prevent PJM’s prices from rising.”
PJM identified those parties as “several companies owning legacy coal and nuclear generation.” The RTO also disparaged a Brattle Group report on the price impacts from closing nuclear plants in Ohio and Pennsylvania as “so astonishingly incomplete they leave no doubt as to the political calculation behind their preparation.”
PJM noted that clearing prices were higher in its Base Residual Auction for delivery year 2021/22 and that roughly 7,000 MW of nuclear power failed to clear. The higher prices helped the resources that did clear.
“The nearly 20,000 MW of nuclear resources that did clear this year’s auction, along with legacy coal, gas, and renewable resources, all had their future financial picture improve markedly based on weaker units failing to clear and clearing prices responding,” PJM said.
PJM suggested that they could pay “subsidized resources a different price, recognizing their different circumstances … to alleviate the price objections some have leveled against capacity repricing.”
PJM also disputed an Exelon argument that FERC should factor in environmental externalities such as carbon, saying FERC “is not an environmental regulator.”
“Let’s be honest, or at least more direct. The PJM state programs in question are designed to retain particular nuclear resources,” PJM fired back at critics. “If the more generic goal was to reward resources for their carbon free attributes, these programs would compensate all (not just financially challenged) nuclear plants, traditional renewable resources, demand response, and new investment, including new nuclear, that furthered the carbon free goal.”
FERC on Tuesday rejected a MISO proposal to streamline the RTO’s process to define and qualify its network resources, saying the changes would cause Tariff discrepancies.
“MISO’s proposed revisions … lead to inconsistencies in its Tariff,” FERC said in denying the filing without prejudice (ER18-502).
MISO filed the change in December to eliminate a requirement that Network Resource Interconnection Service (NRIS) generators must be qualified as a designated network resource in the RTO’s Open Access Same-Time Information System (OASIS). MISO also proposed to remove a provision requiring network customers to “un-designate” extra capacity on OASIS before offering it into the RTO’s markets and annual capacity auction.
The revisions would have reduced the information customers have to provide on Network Integration Transmission Service applications, including maintenance records and whether a unit will be an internal resource. MISO characterized the requirements as nothing more than “administrative steps.”
MISO said NRIS resources already demonstrate their deliverability publicly, adding that it generally doesn’t perform an additional study when network load designates a resource with NRIS. The RTO said the move would cut down on the amount of “duplicative information” it receives and increase efficiency for itself and market participants. MISO added it had “no downstream processes that rely on the designation information of NRIS resources.”
But FERC said MISO’s plan as worded could introduce confusion among its customers.
The commission noted MISO’s proposed changes interchangeably use the terms “network load,” “transmission provider’s network load” and “network customer’s network load.” FERC had originally asked for clarification on the filing in February on similar use of the terms, and MISO responded by taking out some, but not all, of the language.
“These changes could lead to a misunderstanding of the ownership of network load,” the commission said in the May 29 order.
The Missouri Joint Municipal Electric Utilities Commission and WPPI Energy protested MISO’s filing, saying the proposed changes appeared to “erode” and “hollow out” the RTO’s current obligation to plan and provide for the firm delivery of network resources to network load economically dispatched and regulated by network customers who pay MISO’s load-ratio network service charge.
FERC said it would not address those concerns since MISO could not demonstrate its revisions were just and reasonable. MISO had contended that the two organizations misunderstood its revisions.
Trees contacting Pacific Gas and Electric distribution lines caused four Northern California wildfires last year that burned about 9,400 acres, state investigators said.
After “extensive and thorough investigations,” the California Department of Forestry and Fire Protection (CalFire) determined PG&E lines sparked the LaPorte Fire in Butte County (which burned 8,400 acres), the McCourtney Fire in Nevada County (76 acres), the Lobo Fire in Nevada County (821 acres) and the Honey Fire in Butte County (76 acres).
CalFire determined that trees contacted PG&E power lines, causing the LaPorte, McCourtney, Lobo and Honey wildfires
Tree limbs contacting lines caused the Lobo and Honey fires, and a tree falling onto power lines caused the McCourtney Fire, CalFire said in statement. The LaPorte Fire occurred after branches fell onto a PG&E power line.
While CalFire found no violation of state law related to the La Porte Fire, the other three fires were allegedly due to the utility not adequately trimming vegetation near its lines.
“The McCourtney, Lobo [and] Honey investigations have been referred to the appropriate county district attorney’s offices for review,” CalFire said.
The agency said the fires, which were among the smaller of the more than 170 fires that burned about 245,000 acres in Northern California last October, were the first to be investigated. The four fires caused structural damage but injured no civilians or firefighters.
Map showing locations of 2017 California wildfires
Wildfire liability has become a major issue for PG&E as it fights civil lawsuits and lobbies the state for a change in laws related to blazes stemming from utility equipment. The utility, as well as Southern California Edison and San Diego Gas & Electric, said they cannot be held solely responsible for increasingly high-risk fire conditions, including climate change and drought. (See Profits Down, PG&E Fights Wildfire Liability, Edison International Presses Wildfire Cost Recovery.) Aside from civil lawsuits faced by the utilities, the California Public Utilities Commission has denied SDG&E recovery for some wildfire costs.
Last month, state Sen. William Dodd (D) introduced a bill (SB 1088) that would allow utilities to recover wildfire costs if they conform to state-regulated safety plans. (See Calif. Legislation Shields Utilities from Wildfire Costs.) The Senate Appropriations Committee issued a “do pass” recommendation for the legislation on May 25. The bill was recently amended with provisions requiring that utility safety plans include a program to evaluate technological solutions such as distributed energy and allowing a utility to contract with a distributed energy operator if the operator meets insurance requirements to cover direct damages caused by failure of the distributed facilities to comply with contractual terms.
NERC: ERCOT, CAISO Face Summer Reliability Concerns
By Tom Kleckner
NERC said Wednesday that its annual summer reliability assessment indicates ERCOT and CAISO will face operational challenges and potential reliability concerns this summer, thanks to the two ISOs’ respective loss of baseload generation and lack of fuel assurance.
According to the agency’s summer assessment, ERCOT faces a generation shortfall “due in part” to the retirement of about 4.5 GW in coal-fired generation last fall and construction delays of about 2.1 GW in new resources. California is facing a limit on natural gas output due to Aliso Canyon storage facility constraints, NERC said.
“It’s very important to focus on the operational aspect,” said Thomas Coleman, NERC’s director of reliability assessments, during a conference call with reporters Wednesday. “We can’t do much at this point [about resource adequacy]. We want to draw attention to how we are prepared … from an operational standpoint.”
FERC earlier this month said it would be closely monitoring ERCOT and Southern California for reliability issues this summer. Both regions lie in a portion of the Western United .States. expected to be warmer than usual. (See FERC Keeps Eye on ERCOT, CAISO as Hot Summer Approaches.)
Coleman said the majority of NERC’s assessment areas “maintain sufficient resources” to meet their reference planning reserve margins this summer. The exception is ERCOT, which saw its reserve margins drop from 18% last year to a projected 10.9% this year with the coal plant retirements and delay in new resources. Given the ISO’s 13.75% planning reserve margin, ERCOT faces a capacity shortfall of 2 GW, NERC said.
No Cause for Alarm?
A Texas Reliability Entity assessment expects the ISO could be required to deploy ancillary services and contracted load control programs during peak demand periods. NERC’s study cautions that “typical generator outages expected under normal conditions” could limit ERCOT’s ability to maintain operating reserves.
Coleman said NERC took it one step further and ran an operational risk analysis that looked at typical maintenance or forced outages, extreme forced outages, extreme weather and a low-wind scenario.
“Any one of those events would drop [ERCOT] below its operating reserve margin” (of 2.3 GW) and lead to energy emergency alerts,” Coleman said, noting that operational challenges occur during times of peak demand, low wind output, and generator outages.
“When we don’t have the wind available, those are the types of scenarios we want to pay attention to,” he said.
NERC’s study finds the risk of load shedding caused by insufficient reserves in ERCOT’s footprint would increase under extreme summer conditions, such as above-normal temperatures and higher-than-expected generation outages.
However, the Texas grid operator has assured stakeholders there is no reason for alarm, and said it plans to address the projected generation shortfall by seeking voluntary load reductions from utilities, if needed. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
Asked about a repeat of severe weather, as ERCOT experienced last August with Hurricane Harvey, Coleman said NERC was “encouraged by the level of resilience in the system last year.”
“We’ve gotten better about handling those types of events,” he said, noting most outages occur at the distribution level and don’t affect the bulk electric system. “During hurricanes, when we have distribution outages, there’s less load, so that doesn’t necessarily pose challenges.”
California Challenges
Coleman said NERC feels “very comfortable” about CAISO’s reserve margins, but also noted the Aliso Canyon operational constraint continues to affect the availability of natural gas in Southern California, increasing ramping requirements. Below-normal hydro generation is also projected to exacerbate the potential reliability concern, according to the NERC assessment.
“If we don’t have [the] ability to get the fuel there, we could have operational challenges,” Coleman said.
NERC said the need for fast-ramping gas generation and other flexible resources across California also presents a reliability challenge for the bulk power system this summer because of the state’s high penetration of renewables. CAISO in March set an all-time record when 49.95% of demand was served by transmission-connected solar.
The California grid declared its first stage 1 emergency in 10 years last May. In October, it activated demand response measures, but did not require any load shed.
NERC’s study saysid MISO has a summer reserve margin of 19.1%, above its target reserve margin of 17.1%, due to increased forced outage rates. It is expected to increasingly rely increasingly on emergency operating procedures to access resources needed to meet load and operating reserves.
MISO’s actions are anticipated to provide sufficient energy or load relief to cover the normal forecasted system conditions, the agency said. Coleman said the ISO acknowledges a 79% chance it will experience at least one level 1 emergency this summer.
NERC conducts its reliability assessments to “provide a high-level view of resource adequacy and to identify issues that have the potential to impact bulk power system planning, development and system analysis over the summer months.” The summer assessment covers June through September.
California will need between 229,000 and 279,000 electric vehicle chargers at locations other than single-family homes by 2025 to meet the state’s goals for adoption of zero-emission vehicles, the Energy Commission said in a new report.
The higher range of the estimate includes 133,000 workplace and public chargers, 9,000 to 25,000 fast chargers and 121,000 chargers at multifamily dwellings, the commission said. The numbers do not include chargers in single-family homes.
There is a projected need in California for up to 279,000 non-single family home chargers by 2025.
A March 2012 order by Gov. Jerry Brown directed the commission to support the goal of 1.5 million zero-emission vehicles on state roadways by 2025. Another January 2018 order by Brown called for the construction and installation of 250,000 zero-emission vehicle chargers, including 10,000 DC fast chargers, by 2025.
According to the new CEC study, the state’s goal is to allow drivers to maximize the number of electric miles they can drive, provide guidance on plug-in electric vehicle (PEV) and plug-in hybrid charging, and ensure the effectiveness of private and public sector investments. As of the end of last year, the state had about 14,000 public chargers — 1,500 of them DC fast chargers — serving 350,000 PEVs.
For the study, CEC staff worked with the National Renewable Energy Laboratory to develop a computer simulation tool known as the Electric Vehicle Infrastructure Projection Tool (EVI-Pro). The commission plans to add an EVI-Pro portal to its website to allow users to view charging station quantities, load shapes, infrastructure cost estimates and other information.
At a CEC workshop on Tuesday, analysts discussed three central questions around charging infrastructure: how many chargers to deploy, what kind of chargers and where to locate them. A big part of determining where to place chargers is understanding the behavior of vehicle operators and studying patterns such as worker commutes and rural versus urban settings.
“What we’re really talking about is trying to reduce range anxiety as a barrier to increased PEV sales,” NREL’s Eric Wood, one of the study’s authors, said at the workshop.
EVI-Pro focuses on behaviors of mainstream drivers, such as origins, destinations and schedules, as opposed to those of early EV adopters. Mainstream drivers are more likely to favor convenience and less likely to alter driving habits, for example. The modeling also studied how different charging locations such as home or work might be chosen based on the price of electricity, and how users charging for free at work might block other chargers and drive up costs of workplace charging.
The study used four major inputs: vehicle attributes, charger attributes, county-level household travel data and composition of the vehicle fleet. It calculated several charger-per-1,000-PEVs ratios under differing technology and market scenarios.
The transportation sector is the largest polluter in California, responsible for 80% of nitrogen oxide emissions and 90% of diesel particulates. Including indirect emissions from fuel refining and production, transportation accounted for “nearly half” of the state’s greenhouse gas emissions as of 2015, the report said.
The study showed that weekday charging peaks occur when vehicles arrive at work in mornings and when they arrive home in evenings. By 2025, workplace chargers on weekdays will draw more than 200 MW at 9 a.m. and residential chargers nearly 900 MW at 8 p.m. By 2025, aggregate demand from residential, workplace and fast-chargers will push up demand by 500 MW from 4 to 7 p.m., with a maximum demand of nearly 1,000 MW before 8 p.m.
The commission said that an important conclusion of the study is assuring drivers that charging infrastructure will be visible, accessible and reliably maintained, with real-time networking technologies being a valuable tool. Networked technologies will enable shared usage of chargers and reduce the size of the network needed to support the growing electric fleet.
CAISO’s first-quarter revenues were $1.2 million more than it had budgeted, primarily because of entrance fees it collected for the Western Energy Imbalance Market, the ISO reported last week.
About $1.6 million in EIM entrance fees were partially offset by grid management charge (GMC) revenues that were $400,000 less than budgeted. CAISO did not specify from whom it had collected the EIM fees, but Idaho Power and Canadian power marketer Powerex both began transacting in the market last month. (See Idaho Power, Powerex Begin Trading in Western EIM.)
CAISO’s total market settlement collections in 2017 were about $4 billion.
The ISO’s operating costs, capital expenditures, debt service and an operating reserve are recovered through the GMC. Most charges other than the GMC collected by the ISO are distributed to the appropriate market participants.
CAISO “monitors changes in GMC revenues and will adjust rates, if necessary, to align actual GMC revenues closer to budget, as required by the Tariff,” the ISO said in its first-quarter report.
Total market settlement transactions collected by the ISO were about $4 billion last year, including about $3.8 billion in market settlements and $200 million collected through the GMC, according to the ISO’s continuing disclosure report posted May 22. This compared with $3.4 billion in settlements and GMCs collected in 2016.
| CAISO
CAISO reported audited operating income of $26 million for the year, compared with $14 million in 2016. Operating expenses were at $195 million, “other expenses” were $5 million and operating revenues were $221 million.
The ISO in February had reported unaudited operating income of $47.4 million for 2017. (See CAISO Sees 2017 Revenue Boost.) The new operating income figure of $26 million includes depreciation and amortization of about $29 million.
Each year, CAISO establishes a revenue requirement that is allocated to the three GMC service categories: market services, system operations and congestion revenue rights services. Other financial collections come from EIM participants, generator interconnection studies and for operation of the California-Oregon Intertie.
The two largest of the 160 participants in the market, Pacific Gas and Electric and Southern California Edison, paid a little more than half of GMC revenue in 2017. The 10 largest participants were responsible for about 75% of the charge and the top 25 participants paid 89%. These levels have remained about the same since 2015.
Operating expenses last year included $118 million in salaries and benefits, $20 million in communications and technology costs, $18 million legal and consulting and $12 million in leases, facilities and administrative costs.
The ISO increased its number of full-time employees to 599 in 2017 from 584 in 2016.
CAPE NEDDICK, Maine — New England state regulators agreed last week that their region faces a growing winter reliability challenge but expressed skepticism over ISO-NE’s proposed solutions.
Speaking at the New England Conference of Public Utilities Commissioners’ (NECPUC) 71st annual symposium May 21, a panel of regulators pressed ISO-NE CEO Gordon van Welie on the need for an out-of-market contract for Exelon’s Mystic Generating Station, asking why it can’t be replaced through the capacity market and its Pay-for-Performance program.
The proposed Mystic contract represents the first of ISO-NE’s “three-track” plan for addressing its winter fuel reliability concerns. Last week, dozens of intervenors filed comments in response to the RTO’s request for a Tariff waiver needed to authorize the procurement, most of them in opposition (ER18-1509). (See related story, Mystic Waiver Request Spurs Strong Opposition.)
‘A Point at Which We Can’t Hold Things Together’
Van Welie said that Pay-for-Performance — which was premised on gas plants adding oil-fired capability — has been hampered by its stop-loss provisions and states’ resistance to oil-fired generation.
The CEO also said there isn’t enough oil storage or allowable air permits to rely on the fuel as the region’s backstop. During the Dec. 26-Jan. 8 cold snap, oil prices fell below gas, making oil-fired generation effectively baseload for two weeks, he said. The region burned about 2 million barrels of oil during that period — more than it used in all of 2016 and 2017 — drawing down supplies from 68% of tank capacity on Dec. 1 to 19% by Jan. 9. “The ISO had to step into the market to slow down the burn rate,” he noted.
Fuel delivery logistics also are a concern. Heating customers get priority for oil as well as gas. Oil deliveries can be delayed by storms and drivers’ working hour limits.
Van Welie said the RTO must firm up fuel deliveries and ensure that the market “uniformly” values all resources with such service, including its Millstone and Seabrook nuclear plants, which produce one-quarter of the region’s power during winter.
In addition to the region’s precarious fuel infrastructure, ISO-NE is concerned that state-sponsored renewable resources will reduce energy market revenues, causing increases in capacity market costs and plant retirements.
“Our concern is there’s a point at which we can’t hold things together,” van Welie told the regulators.
ISO-NE is seeking to delay Mystic’s retirement because its analysis indicated the loss of Units 8 & 9’s 1,700 MW of combined cycle capacity that don’t rely on pipeline gas would leave the RTO depleting its 10-minute operating reserves “on numerous occasions” — a violation of NERC reliability rules. The analysis also predicts load shedding during the winters of 2022/23 and 2023/24.
The RTO has asked FERC to waive its Tariff to retain resources to address fuel security risks — an option currently allowed only for local transmission security issues (Track 1). It hopes to file a Tariff change by the end of the year to make fuel security a reason resources can be retained (Track 2). In addition, the RTO is seeking a long-term plan to ensure sufficient firm energy for winter that would compensate needed resources through the market rather than reliability contracts (Track 3).
A Menu, not a To-Do List
Despite the hand he’s been dealt by the region’s resistance to oil generation, additional gas pipelines and electric transmission, van Welie was careful to couch his comments not as a “To Do” list but as a series of questions and menu choices for the states.
“We are an energy-constrained region. Do we want to maintain that constraint going forward, or do we want to do something about that? And specifically, can the states shape their resource procurements … in a way that they get at the winter constraint? Because I think in doing that the states can help us as well as maintaining or meeting their other policy goals.”
“The magnitude of that problem is in [question] but there is a problem,” said Bob Stein, vice chair of the New England Power Pool’s Reliability Committee, who joined regulators on the panel.
NEPOOL has “a range of positions [on the RTO’s plans], and they’re not fully formed,” said Stein, principal of Signal Hill Consulting Group. The range, he noted, is framed by the two types of NEPOOL members: “Those that are long and those that are short. And you can instantly tell what people are going to say by where they are.”
Maine Public Utilities Commission Chairman Mark Vannoy and other commissioners pressed the RTO for a “definition” of the problem, saying he is concerned that “New England is on a course to a very expensive future.”
“I’m not arguing that there is not a problem,” Vannoy said. “But we need to define what the problem is and then — if our intent is to use market mechanisms to solve that — we have to be precise … so that we can move to those market solutions.
“We have a very complex and dynamic market, and as price signals drive fuel procurement questions … [as fuels] substitute for other fuels … we need to understand how that dynamic market reacts before we move to the Markets Committee for a solution.”
Vannoy said New England helped create its dilemma by “separat[ing] itself from the rest of the country’s energy … potentially, to our economic peril.” He cited states using their EPA-delegated authority under the Clean Air Act to prevent access to Marcellus shale and other gas supplies.
As an example, Vannoy later cited the Atlantic Bridge pipeline project. In the face of local opposition, Massachusetts officials said in December that they would take up to a year to review the impact of a compressor station in Weymouth, Mass., that is part of the project.
Seeking an Honest Conversation
Angela O’Connor, chair of the Massachusetts Department of Public Utilities, called for an “honest” conversation.
“Whether you want to reduce greenhouse gases or simply reduce the rising outrageous cost of energy … burning 2 million barrels of oil in five days and killing baby seals to get to expensive Russian gas cannot and should not be part of any intelligent conversation about energy policy in this region,” she said. “It clearly does not meet any of our New England collective goals for the states. We need to have an intelligent and honest — emphasis on honest — conversation to develop the right solutions, and we need to do it all together.”
Is Pay-for-Performance Broken?
New Hampshire Public Utilities Commissioner Kathryn Bailey said her state is not convinced that the out-of-market contract with Mystic is the only possible solution to the region’s near-term concerns. She said the Operational Fuel-Security Analysis released by ISO-NE in January suffered from “problems with the assumptions and the lack of analysis on how likely scenarios are to play out.” (See Report: Fuel Security Key Risk for New England Grid.)
She said maintaining Mystic could create incentives for other non-gas generators to seek cost-of-service agreements.
“I have to ask: What happened to the market-based solution to fuel security? Just a few short years ago, ISO-NE reported to FERC that Pay-for-Performance was a long-term, market-based solution designed to address generator availability concerns and the region’s vulnerability to interruptions in gas supply. … What changed? Why does the ISO think it won’t work, even before the incentives take effect next month? Where’s the analysis that demonstrates it won’t work? When the ISO originally brought this plan to FERC, there was a lot of analysis.
“If Pay-for-Performance had worked as expected … and Mystic announced its retirement, prices in [Forward Capacity Auction] 13 would likely separate to provide incentive for new resources to take on the supply obligation in that zone. But apparently Pay-for-Performance can’t work.”
Bailey also noted “the irony that ISO-NE refused to allow a 200-MW renewable exemption backstop to integrate state public policies because of the impact it would have on the market. But now they want to waive the Tariff and allow a 1,700-MW out-of-market contract.”
In a period of low gas and renewable prices and flat load growth, Connecticut Public Utilities Regulatory Authority Chair Katie Dykes asked: “Why is everybody so unhappy?”
Her theory: “Legacy” deals, conflicting state policies, and overlapping jurisdictional authority between FERC, state legislators, state commissions, siting councils and the courts make it difficult for economic regulators to achieve the “fairness” they seek.
“We were one of a few states that got our legislature to give us fresh, brand new authority to procure not only gas pipelines but LNG storage. We got all of that authority. We opened a [request for proposals]. …
“We opened up the bids. We were ready to go. [Then] we looked at the costs and we realized that if we didn’t have all the states moving with us that Connecticut was going to pay 100% of the cost of these resources and only get 25% of the benefit because that’s our share of load. And so, the bids are still sitting in a desk drawer somewhere.
“The challenge of the multi-jurisdictional process is it is guaranteed to be unfair to some parties. … There’s a temptation to retreat within our own borders and pursue this sort of righteous unilateralism. … But that’s not really an acceptable tactic. If it comes to those outcomes, everyone in this room is going to be blamed for that occurring. No matter how hard you’ve been working on this issue, no matter how small your slice of the jurisdictional pie is, you’re all going to share responsibility for [reliability problems], which will hurt people and drive businesses out of New England,” she said, raising her arms like a cheerleader waving pom-poms. “So, what we really need to do is buck up, little soldiers. We can do this. This is New England.”
Rhode Island Public Utilities Commissioner Abigail Anthony stressed affordability, saying customers are best served by investments that “prioritize highly cost-effective measures that improve the reliability resiliency of both the distribution system and the [transmission] system.”
“So, the resources that we invest in need to do double or even triple duty to improve the energy system on multiple levels,” she said. She added, “Some of the best solutions to maintaining and improving reliability resiliency and affordability may lie outside the power system.”
She noted that 16,000 of her state’s residential electric accounts were terminated for nonpayment in 2016. “Rhode Island’s experience, consistent with national data, shows that the vast majority of customer outages are the result of disruptions of the distribution system or due to affordability,” she said.
Vermont Public Utility Commissioner Sarah Hofmann said she would like more data on resilience risks, the costs of reducing them and residential customers’ willingness to accept outages.
“The tolerance of consumers for the bad thing happening, such as rolling blackouts, that’s a conversation that … I don’t think we have as much as maybe we should, in terms of what can a residential customer tolerate as opposed to … a commercial customer.”
Enough LNG? Rewrite Capacity Market?
Van Welie said the two top sensitivities for its fuel study was the timing of retirements of its non-gas fleet and the size of LNG injections.
Over the last five winters, ISO-NE says the region has received an average LNG injection of 0.2 Bcfd, only occasionally spiking to the 1-Bcfd level assumed in the baseline case. In its recent analysis, Synapse Energy Economics said import terminals could handle 1.5 Bcfd.
ISO-NE CEO Gordon van Welie says New England’s growing price volatility since the winter of 2012-13 reflects the region’s increasingly constrained fuel infrastructure. | ISO-NE
“We’re talking about unprecedented levels of LNG imports into this region,” van Welie said. “And the big question is: Is the market signal strong enough to incent that behavior?”
Of New England’s 17 GW of combined cycle capacity, only 5 GW have dual-fuel capability. “There are three with large tanks. The biggest one is 10 days’ [capacity]. The next one down is five or six days. The next one down from that is three days. The tanks that are being built, if they do get built today, are [only] two days.”
“So, the issue is, Pay-for-Performance was calibrated to the economics around dual fueling, [which] may not be a good assumption in the long term.”
Van Welie also questioned Pay-for-Performance’s annual and monthly stop-loss limits for generators that fail to perform, which he said has many of them rolling the dice that they won’t need firm fuel. “Is that the right incentive to send generators? That they could end up still collecting capacity payments without necessarily having to feel that they need to run for the winter?”
Van Welie also said the decisions the RTO made when it designed its capacity market 14 years ago need to be reconsidered. The market’s design is based on meeting the summer peak rather than the winter peak, which is now the bigger risk. A seasonal construct that acquires resources separately for the winter and summer would be preferable, he said.
“Do we throw out the capacity market — go back to blank sheet of paper and redesign the seasonal capacity market? Or do we … do something complimentary, really specifically targeting … the firmness of energy that we required during the winter period?
“We have not landed on … the specific solution to this problem. … But we recognize that … some of the things that we assumed as far back as 14 years ago may not be valid.”
AUSTIN, Texas — It’s finally official. Southwestern Public Service can now begin construction on its 478-MW wind farm in West Texas.
The state’s Public Utility Commission on Friday quickly approved a second draft order of the utility’s request for a certificate of convenience and necessity and a power purchase agreement with Bonita Wind Energy. The commissioners had given their verbal approval in April but delayed a final order to allow parties in the docket additional time to provide written responses to their questions (No. 46936). (See Texas PUC Delays Final Approval of SPS Wind Farm.)
“We’re just pleased we now have a resolution in hand and a final order,” said SPS CEO David Hudson, noting it was the fourth time the utility has appeared before the commission in hopes of receiving a final order. “We can now begin construction on the Hale [County] project and the Sagamore project” in New Mexico.
SPS expects to have the Hale project in service no later than 2019, at a cost of $769 million, so that it will be able to receive 100% of its federal production tax credits.
PUC Chair DeAnn Walker had expressed concerns over SPS’ proposal to recover costs by flowing PTCs through fuel, but she was satisfied with the parties’ responses.
The wind farm is part of a 1.23-GW project by SPS parent Xcel Energy that will provide renewable energy to SPS customers in Texas and New Mexico. The utility says the project will save its retail customers about $1.6 billion in energy costs over its 30-year life.
SPS had reached a settlement agreement in February with all parties in the docket but two, the International Brotherhood of Electric Workers Local 602 and Lea County Electric Cooperative. However, neither opposed the settlement.
Commission Streamlines Smart Meter Texas Portal
The PUC also approved a final order streamlining Smart Meter Texas (SMT), the state’s web portal, and aligning it with national data-transfer standards (Docket No. 47472).
SMT is maintained by utilities AEP Texas, CenterPoint Energy Houston Electric, Oncor and Texas-New Mexico Power. It allows customers to download and view their energy data or share them with competitive service providers (CSPs), companies that market energy efficiency, demand response, distributed generation and other services.
Transmission and distribution providers are prohibited from selling, sharing or disclosing advanced meter data but are required to provide “convenient, secure, read-only access” to a customer, the customer’s retail electric provider and other entities authorized by the customer. The data include meter readings used to calculate charges for service, historical load and other proprietary customer information.
The order requires the utilities to support the portal’s home area network (HAN) functionality through their advanced metering systems. It also forbids them from disconnecting an existing HAN device from the meter without the customer’s requests. The HAN devices are costly and have had few takers for their services.
PUC staff last year requested the commission determine what changes, if any, should be made for SMT’s continued operation while its contract was being renegotiated. The four utilities signed a joint development and operations agreement for SMT that dates back to December 2008.
The utilities reached a unanimous settlement agreement in January, with the only contested issue related to the maximum time period that a residential customer or smaller commercial customer may grant a CSP access to the customer’s SMT data, without the customer affirmatively renewing the access.
The commission adopted an administrative law judge’s recommendation that the maximum time period remain 12 months.
PUC to Intervene in SPP-AEP Filing Before FERC
Following its executive session, the PUC moved to intervene in SPP’s recent FERC filing on behalf of American Electric Power (ER18-1541, ER18-1542).
SPP made a compliance filing on May 8 to revise AEP West’s transmission formula rate to reflect the recent change in the federal corporate income tax rate (ER18-63). The filing was made on behalf of AEP Service Corp. and its AEP Oklahoma Transmission and AEP Southwestern Transmission affiliates.
The Oklahoma Municipal Power Authority and DC Transco have already intervened.
AUSTIN, Texas — ERCOT’s legal department again delayed votes endorsing final changes to the grid operator’s bylaws and articles of incorporation, saying it needed additional time to evaluate a last-minute comment from Luminant.
Assistant General Counsel Vickie Leady told the Technical Advisory Committee last week that legal staff would delay final votes on the revisions until the August set of leadership meetings. She said ERCOT and Luminant are “on the same page,” but they are trying to figure out the language.
“We appreciate having people poke holes in the language,” Leady told the TAC during its May 24 meeting. “Given the importance and relative permanence of the language, we need more time to address it. Once we put stuff in the bylaws, it’s there for a long, long time.”
Legal staff had originally planned to put the proposed changes up for votes in April but pushed the final recommendation back to the June Board of Directors meeting. (See “ERCOT Legal Staff Delays Bylaw Revisions,” ERCOT Technical Advisory Committee Briefs: March 22, 2018.)
Luminant sent its comments after working hours on May 23, suggesting clarifications to the proposed affiliate definition. The generating company added language to the definition that read:
“A person who is not controlling, controlled by or under common control with another person as described above may nonetheless be determined to be an affiliate of another person, if ERCOT or a member alleges that such exercises directly or indirectly, through one or more intermediaries, substantial influence over another person. Such a determination may be made by the board only after notice and an opportunity for hearing at an ERCOT board meeting. The burden of proof to show substantial influence is on ERCOT or the member alleging such influence.”
Luminant’s Ian Haley apologized for the late filing, saying it was the first time the company had been able to gather together its legal counsel.
The company also suggested a central repository for the various clean and red-lined documents, which Leady said ERCOT would follow. Legal staff also plan to hold a workshop following the June board meeting to “facilitate a final set of comments.”
Leady said she has received no stakeholder comments on the articles of incorporation but that they should “travel together” with the bylaw changes.
Southern Cross Transmission (SCT) also filed comments requesting a delay of a decision regarding in which market segment it should be placed. SCT believes it should be included in a newly created DC Tie Operator segment.
Cratylus Advisors’ Mark Bruce, who represents the project’s developers, said SCT hopes that when the market segment question is revisited, “greater stakeholder familiarity with the SCT project will ease some of the controversy currently associated with the question of the appropriate market segment assignment for DC tie operators.”
Bruce wrote that he saw no harm in delaying the membership decision. Leady said staff would “reinitiate” stakeholder discussion of the segment definition “upon further certainty that the SCT project will be interconnected” to ERCOT.
Texas’ Public Utility Commission last year directed ERCOT to address several issues as a condition for energizing SCT’s project. The conditions include determining “the appropriate market participation category for [SCT] and for any other entity … for which a new market-participant category may be appropriate” (Project No. 46304).
Staff Recommend 2 Transmission Projects
The committee endorsed staff’s recommendation of a $327.5 million Oncor project that addresses reliability concerns in ERCOT’s Far West region.
If approved by the Board of Directors in June, Oncor’s work will include building 40 miles of new 345-kV lines on double-circuit structures, adding two new 600-MVA, 345/138-kV autotransformers at a switch station, installing a second 345-kV circuit between Odessa and Riverton, and building two 20-mile segments of 138-kV line on double-circuit structures.
Construction is expected to begin next year, with completion in 2023.
Staff said the project will provide operational flexibility and resolve potential reliability issues in the face of oil and gas-related load growth.
Staff also shared with TAC members an additional study evaluating a Rayburn Country Electric Cooperative proposal to transfer its existing facilities and load into ERCOT, a plan filed last year with the PUC (Docket No. 47342).
The ISO said it is now recommending a “modified alternative option” to integrating Rayburn’s load, following an Oncor study of a transmission alternative than eliminated a 345-kV interconnection.
Staff concluded the second option, which still includes two 138-kV interconnections, has “similar reliability and long-term load-serving capability.” However, the modified alternative has a lower estimated capital cost of $31.7 million, leading ERCOT to propose the Oncor suggestion.
Staff’s initial study indicated capital costs of $41.7 million.
Rayburn, which sits on the ERCOT-SPP seam in East Texas, has proposed transferring load and transmission facilities into ERCOT. The co-op is an SPP member, but only about 150 MW (or less than 20%) of its load and 160 miles of its transmission sit in the Eastern Interconnection. (See “ERCOT, SPP Agree to Rayburn Country Migration Studies,” Public Utility Commission of Texas Briefs: Aug. 31, 2017.)
Members Approve Subcommittee’s Restructuring
Members unanimously approved a task force’s recommendation to designate the Commercial Operations Subcommittee (COPS) and several of its working groups as inactive, agreeing that it has reached a “steady state” situation concerning market communication and settlement issues.
The Wholesale Market Subcommittee will inherit the Settlement Working Group and the Commercial Operations (COP) Market Guide, while the Retail Market Subcommittee will pick up the Profiling Working Group, Load Profiling Guide and market communications.
The TAC Subcommittee Restructuring Task Force brought its recommendations to the committee in February. (See “Committee Endorses Task Force Restructuring Recommendations,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)
The restructuring will require the following changes for the COP Market Guide and the Load Profiling and Retail Market guides:
COPMGRR047: Relocates the COP guide to the WMS, moves other portions of the manual to the retail guide and removes language that is no longer applicable from the COP guide.
LPGRR064: Moves the Load Profiling Guide and load-profiling responsibilities from COPS to the RMS and removes language from the guide that no longer applies.
RMGRR151: Incorporates the market notice communication process and renewable energy credit information from the COP guide into the retail guide.
The task force will continue its development of a “three strikes” attendance policy for TAC and its subcommittees, whereby seated segment representatives that miss three meetings or fail to assign an alternate for those meetings will lose their seats. It will also aid the RMS with moving RMGRR151’s market notice process language into a standalone Other Binding Document.
TAC Re-elects Helton as Chairman
TAC once again elected Bob Helton as its chair, an action required following the latest change in his employment status and market segments.
Helton moved from ENGIE to Dynegy last year when the latter bought the former’s 17 U.S. power plants. He left Dynegy when it was subsequently acquired by Vistra Energy, recently rejoining ENGIE as its director of government and regulatory affairs.
“I know you guys may not know this person, and I know we’ve elected him three times in the last seven months,” began Sharyland Utilities’ B.J. Flowers as she teasingly nominated Helton for the vacant chair position.
Helton thanked the members for their support, saying he hopes to finish out the year as committee chair.
“Of course, you never know, the way jobs change around here,” he joked.
Committee Endorses 4 NPRRs, 7 Other Changes
The committee endorsed four Nodal Protocol revision requests, a revision to the Nodal Operating Guide, a pair of Other Binding Document revisions, two changes to the Planning Guide and two changes to the Verifiable Cost Manual.
NPRR847: Incorporates an intraday or same-day weighted average fuel price into the mitigated offer cap to ensure that resources are capped at the appropriate cost during high fuel price events and LMPs reflect the true incremental cost of fuel.
NPRR851: Establishes a clearly defined disconnection process within the market rules applicable to a transmission voltage connection to the grid that uses one electrical connection for both generation and load services.
NPRR867: Caps the amount of each counterparty’s available credit limit locked for congestion revenue rights auctions at the pre-auction screening credit exposure amount.
NPRR870: Deletes the gray-boxed requirement for ERCOT to post a forward adjustment factors summary report on the Market Information System’s certified area. The information in this report is already provided on each counterparty’s estimated aggregate liability summary report.
NOGRR176: Clarifies that all transmission owners and qualified scheduling entities representing resources can participate in ERCOT hotline calls.
OBDRR004: Revises the risk-weighting factors available for assignment to each emergency response service (ERS) time period; describes the process for updating the ERS time period expenditure limits for any subsequent standard contract terms (if money is needed to fund) and the ERS renewal contract period; and updates a table to reflect the risk-weighting factors’ proposed changes.
OBDRR005: Revises the generic transmission constraint (GTC) shadow price cap that is used in SCED for base case constraints from $5,000/MWh to $9,251/MWh. The revision also updates the associated examples in SCED and makes an administrative edit to a protocol reference.
PGRR059: Includes Regional Planning Group-related changes intended to improve and clarify existing processes.
PGRR060: Updates the reliability performance criteria by defining a DC tie’s unavailability as a new contingency and clarifies the voltage level of transformers referred to in the reliability performance criteria.
VCMRR020: Delays VCMRR014’s sunset date to permit stakeholders additional time to find a long-term solution that determines an appropriate adder for coal- and lignite-fired generation resources.
VCMRR021: Aligns the VCM with the language proposed in NPRR847 by removing language providing for make-whole payments for exceptional fuel costs. The costs will be recovered in NPRR847.
