Page 1369 – RTO Insider

June 1, 2018May 8, 2025

Trump Orders Coal, Nuke Bailout, Citing National Security

By Rich Heidorn Jr. and Michael Brooks

President Trump directed Energy Secretary Rick Perry Friday to force grid operators to provide a lifeline to struggling coal and nuclear plants, saying their retirements threaten national security.

FERC NERC Donald Trump clean power plan coal nuclear power national security

Trump | © RTO Insider

The Department of Energy had not issued an order as of Friday afternoon. But a 40-page draft memo described as an “addendum” includes a reference to the order and describes the department’s legal foundation, saying the closures threaten military bases and the nation’s nuclear workforce. The memo was first reported by Bloomberg, which said it was prepared for a Friday meeting of the National Security Council.

The memo said DOE would be directing RTOs and ISOs “to purchase or arrange the purchase of electric energy or electric generation capacity from a designated list of Subject Generation Facilities (SGFs) sufficient to forestall any further actions toward retirement, decommissioning or deactivation” for 24 months — the time it said the department and its and National Laboratories will need to identify “Critical Defense Facilities” served by “Defense Critical Electric Infrastructure (DCEI).”

“To identity DCEI facilities, additional analysis will be required to gain a more detailed understanding of location-specific security vulnerabilities in our energy delivery systems, including the interdependencies associated with electric generation and transmission, and natural gas and petroleum pipelines, as well as their supply chains,” the memo said. “In the meantime, DOE’s order provides a temporary stop-gap measure to prevent the further permanent loss of the fuel-secure electric generation capacity for the grid upon which our national security depends.”

cost-of-service payments doe ferc resilience

Perry | © RTO Insider

DOE said it also is directing SGFs outside RTO/ISO territories “to continue generation and delivery of electric energy according to their existing or recent contractual arrangements with load-serving entities.” The draft did not identify the generators that would benefit from the order.

The president’s long-awaited and highly controversial action was announced by Press Secretary Sarah Huckabee Sanders. “Unfortunately, impending retirements of fuel-secure power facilities are leading to a rapid depletion of a critical part of our nation’s energy mix and impacting the resilience of our power grid,” Sanders said in a statement. “President Trump has directed Secretary of Energy Rick Perry to prepare immediate steps to stop the loss of these resources and looks forward to his recommendations.”

It is the administration’s second bid for a coal and nuclear bailout. In January, FERC rejected Perry’s Notice of Proposed Rulemaking to subsidize coal and nuclear plants with onsite fuel. The commission instead initiated a rulemaking on grid resilience (AD18-7). (See Don’t Rush on Resilience, Commenters Urge.)

‘Tipping Point’

DOE warns of a “tipping point” in the loss of “fuel-secure” generation, citing the retirements of 59 GW of coal capacity between 2002 and 2016, the loss of 15 nuclear plants since 1990 and announced retirements of 12 nuclear units representing 11 GW.

It cites a 2008 Defense Science Board report that concluded Defense Department installations are “99% dependent on the commercial power grid.”

In addition to the purported risk to DOD facilities, the memo also cited the need for a “robust civilian nuclear industry” to support the “entire U.S. nuclear enterprise — weapons, naval propulsion, nonproliferation, enrichment, fuel services and negotiations with international partners.”

“Without a strong domestic nuclear power industry, the U.S. will not only lose the energy security and grid resilience benefits but will also lose its workforce technical expertise, supply chain and position of clean energy leadership,” it said.

DOE said it supports FERC’s actions, including its opening of the resilience docket in January, but that “too little progress has been made, while the risk of high-impact events, especially those caused by intentional attacks, continues to grow.”

“Given the need to safeguard the existence of fuel-secure generation facilities to promote our national defense and to maximize domestic energy supplies, DOE is compelled to exercise its authorities to avert a serious supply disruption in the wake of a natural disaster, an adversarial attack or some combination of the foregoing.”

It quotes from a 2017 NERC report that said increased “reliance on natural gas exposes electric generation to fuel supply and delivery vulnerabilities” and that “premature retirements of fuel-secure baseload generating stations reduces resilience to fuel supply disruptions.”

It also cites NERC’s November 2017 report on potential disruptions to the natural gas system, which noted that some regions rely on gas for more than 60% of their peak electric demand.

DOE also cites the threat of cyberattacks on the grid, saying, “To avoid and recover from blackouts, it is essential that the system have adequate generation and transmission capacity broadly dispersed.” It notes that only nuclear generators maintain “the kinds of ‘guns, guards and gates’ and other physical and cyber-hardening measures that would be needed in the event of a major attack.”

Legal Challenges Likely

Observers Friday differed over whether the administration’s action will survive almost certain legal challenges.

In rebuffing Perry’s NOPR in January, FERC said DOE had failed to show that existing RTO tariffs were unjust and unreasonable under Section 206 of the Federal Power Act.

The DOE memo claims different legal authority, citing the Defense Production Act of 1950 (DPA) and Section 202c of the FPA, which allows the energy secretary to issue emergency orders during shortages of electric energy, facilities or fuel.

The memo cited DPA Section 101c, which gives the secretary authority to issue orders based on findings that energy supplies “are scarce, critical and essential” and needed for “maintenance of energy facilities [and] cannot reasonably be accomplished without exercising [this] authority.”

DOE said the legislative history of Section 202c shows that “Congress contemplated the use of the provision not merely to react to actual disasters, but to act in a preventive manner. A variety of man-made and natural threat conditions require … a federal agency ready to do all that can be done in order to prevent a breakdown in electric supply.”

The department says it has deployed FPA Section 202c on eight occasions. However, those were in response to regional energy challenges; it has not previously been applied nationwide.

During the Western Energy Crisis in late 2000, DOE issued an order to ensure gas supplies to Pacific Gas and Electric, then on the verge of bankruptcy. In several instances, the department has ordered temporary interconnections to provide supplies to regions following blackouts or natural disasters, including hurricanes Katrina and Rita.

The law was invoked on three prior occasions to require operation of generation facilities to prevent energy or reactive power shortages.

In 2005, DOE granted the D.C. Public Service Commission’s request to order Mirant Corp. to continue running its Potomac River Generating Station despite its inability to meet EPA’s National Ambient Air Quality Standards, finding that the region otherwise faces a “reasonable possibility” of extended blackouts.

Most recently, DOE granted PJM’s request to order Dominion Energy Virginia to continue running its Yorktown Power Station despite its violation of EPA’s Mercury and Air Toxics Standards, finding reliability could be at risk during summer peaks.

coal nuclear power trump national security

Yorktown Generating Station | Dominion

To minimize conflicts with environmental regulations, DOE noted, it limited its orders to having the generators serve only as backup power if other sources were unavailable.

ClearView Energy Partners analyst Christine Tezak noted in a bulletin to clients Friday that the DPA gives DOE “significant authority to determine and respond to national security impairments, even in peacetime, and thus far the courts have been reluctant to intervene.”

“Unless and until critics marshal counterarguments to the concerns DOE has presented in [its] memo, we will continue to assign low probabilities to successful judicial intervention or reversal,” she added.

Rabeha Kamaluddin, a partner at Dorsey & Whitney, predicted in an interview that the courts will reject DOE’s claim that the subsidies are justified by 202c. But, she said, “you can expect anything in today’s political landscape.” DOE “may have a leg to stand on” using the DPA in combination with the FPA, she added.

“Combining [202c with] the DPA provides more room for DOE to make creative legal arguments,” said Ari Peskoe, director of the Electricity Law Initiative at Harvard. “It’s still far from clear that the proposal would be upheld by a court.”

“There is no grid emergency that justifies this,” tweeted Joel B. Eisen, law professor at the Richmond School of Law. “Nor does the combo of two laws, neither of which is appropriate in its own right, add any further support.”

“202c gives pricing authority to FERC,” said Avi Zevin of the New York University School of Law’s Institute for Policy Integrity. “FERC has already said market rates are sufficient to meet reliability and resilience. So, I’m still not clear how we get around that even when you add DPA into the mix.”

FERC’s role in implementing the order is unclear. While 1977 amendments to the FPA transferred the emergency declaration authority under 202c to the energy secretary from the Federal Power Commission — FERC’s predecessor — the commission still has dominion over rates under FPA Sections 205 and 206, Kamaluddin said.

FERC declined to comment.

Bailout Costs

The bailouts could cost from $311 million to $900 million annually in PJM, ISO-NE, NYISO and MISO alone, according to Energy Innovation Policy & Technology, which supports policies reducing greenhouse gas emissions. The low estimate represents the out-of-market payments needed to bring units with negative net cash flows up to zero. The upper limit adds capital recovery and a rate of return on undepreciated capital and future capital expenditures.

The group compiled the estimates based on the rejected DOE resilience NOPR. “There are, of course, important differences between the resilience NOPR and the 202c actions being discussed by the Trump administration, but our study is a good rough estimate of the cost to keep the same group of uneconomic plants online,” said Robbie Orvis, director of energy policy design for the group.

More than 80% of the coal subsidies would go to five companies (NRG Energy, Dynegy, FirstEnergy, American Electric Power and Talen Energy), while 90% of the nuclear price supports would go to five companies (Exelon, Entergy, Public Service Enterprise Group, NextEra Energy and FirstEnergy), the group said.

Industry Reaction

The renewable energy and natural gas industries united with consumer groups to condemn the bailout. Representatives of 10 trade groups — Advanced Energy Economy, the American Council on Renewable Energy, American Petroleum Institute, American Wind Energy Association, Business Council for Sustainable Energy, Electricity Consumers Resources Council, Electric Power Supply Association, Energy Storage Association, Natural Gas Supply Association and Solar Energy Industries Association — released a joint statement calling the move an unprecedented overreach that would distort competitive markets.

“There was no emergency when coal and nuclear interests sought federal relief, and there is none today that justifies such unprecedented executive branch intervention in the economic life of the country,” EPSA CEO John Shelk said.

| © martin33 / 123RF Stock Photo

“The administration’s plan to federalize the electric power system is an exercise in crony capitalism,” said Malcolm Woolf, AEE senior vice president of policy.

John P. Hughes, CEO of the Electricity Consumers Resource Council, which represents industrial consumers, said the threats cited are “phony” and that the costs could cripple U.S. manufacturers. “The federal government should not use the pretext of ‘national security’ to pick winners and losers in the energy markets, and it must certainly not treat U.S. manufacturing jobs as inferior to the jobs at uneconomic power plants,” he said.

The American Coalition for Clean Coal Electricity praised the action, noting that “almost 40% of the nation’s coal fleet has shut down or is expected to close.”

PJM said Friday that the grid is “more reliable than ever,” and that its recently announced fuel security initiative will ensure grid resilience without upsetting its markets. (See PJM Seeks to Have Market Value Fuel Security.)

“Any federal intervention in the market to order customers to buy electricity from specific power plants would be damaging to the markets and therefore costly to consumers. There is no need for any such drastic action.”

In response to an inquiry, ISO-NE spokeswoman Marcia Blomberg said “it’s too early to comment on a draft proposal that has just been revealed.”

“MISO is monitoring the reports of the potential Department of Energy action along with our ISO/RTO counterparts,” spokesman Mark Brown said. “At this time, we have seen no official communication from DOE.”

Other grid operators did not respond to requests for comment. DOE and NERC also did not respond to inquiries.

Requests from Murray Energy, FirstEnergy

Although Trump promised during his campaign to end the “war on coal” and put miners back to work, the Sierra Club says retirements have continued unabated since he took office. “In the first two months of 2018, we’ve already retired more coal that we did in three of the Obama years, and we’re on track for our second biggest year of coal retirements ever,” the group said in March.

Coal mining chief executive Robert Murray and FirstEnergy, his company’s biggest customer, have lobbied relentlessly for subsidies. (See Photos Show Murray’s Role in Perry Coal NOPR.) FirstEnergy asked Perry to invoke 202c in a letter in March. (See FES Seeks Bankruptcy, DOE Emergency Order.) FirstEnergy lobbyist Jeff Miller, who ran Perry’s unsuccessful 2016 presidential campaign, reportedly made the case to Trump over dinner in April.

Exelon, the nation’s largest nuclear generator, has largely focused its lobbying efforts on winning state subsidies for endangered reactors.

Despite news of the administration’s action, Exelon saw shares drop 1% Friday, while FirstEnergy was down 0.6% on the day.

Shares of mining company Peabody Energy rose 4.6%, while Arch Coal was up 2%.

May 31, 2018

NYISO Ready to Meet Summer Demand

NYIS O said Wednesday it is prepared to meet peak demand this summer, with a total of 42,169 MW of power resources available to cover an expected peak of 32,904 MW — 2.9% above the long-term average.

Demand last summer peaked at 29,699 MW on July 19, coming in 7% below the 10-year average of 31,968 MW. New York set its record peak of 33,956 MW at the end of a week-long heat wave in July 2013.

NERC standards mandate that each ISO/RTO secure enough day-ahead capacity to meet the single largest contingency. The ISO’s summer capacity assessm e nt used a “deterministic approach” to approximate capacity margins and operating reserves for baseline and extreme weather conditions, according to Wes Yeoman, NYISO vice president of operations. The assessment uses a set of projected derates based on five-year Equivalent Forced Outage Rate demand averages.

At baseline peak weather conditions, the ISO forecasts 1,599 MW of capacity margin surplus, which is above the baseline peak load, plus 2,620 MW of required operating reserves. The baseline peak forecast is up 1,214 MW over last year’s forecast.

nyiso peak demand extreme weather — | *NYISO*

For the 90th percentile forecast of extreme weather conditions, the ISO projects a capacity margin shortfall of 241 MW, an increase of 1,683 MW over last year’s extreme weather forecast.

The ISO reported 39,325 MW of generating capacity available from power plants in New York and 1,219 MW of demand response resources plus another 1,625 MW available from neighboring regions.

“Based on historical performance, the net resources projected to be available to serve during the summer peak total 37,123 MW,” said the report.

New York’s 2018 operating reserve requirement of 2,620 MW is based on the potential loss of the system’s largest single resource. Peak demand combined with operating reserves translate into a total capacity requirement of 35,524 MW.

— Michael Kuser

May 31, 2018

NERC: ERCOT, CAISO Face Summer Reliability Concerns

By Tom Kleckner

NERC said Wednesday that ERCOT and CAISO will face operational challenges and potential reliability concerns this summer because of the Texas grid’s loss of baseload generation and California’s lack of fuel assurance.

According to the organization’s summer reliability assessment, ERCOT faces a generation shortfall “due in part” to the retirement of about 4.5 GW in coal-fired generation last fall and delays in the construction of about 2.1 GW in new resources. California is facing a limit on natural gas output because of 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 West 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. 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 will 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.

ERCOT CAISO Summer Reliability Assessment Reserve Margin — | *NERC*

“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.

Reserve Margin ERCOT CAISO NERC Summer Reliability Assessment — | *CAISO*

The ISO declared its first Stage 1 emergency in 10 years in May 2017. In October, it activated demand response measures but did not require any load shed.

NERC’s study says MISO has a summer reserve margin of 19.1%, above its target reserve margin of 17.1%. It is expected to 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 RTO 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.

May 31, 2018

NYISO Management Committee Briefs: May 30, 2018

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.

NYISO MMU market monitoring unit — 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 C o mmittee 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.

— Michael Kuser

May 30, 2018March 25, 2025

PJM Urges FERC to Act on ‘Jump Ball’ Despite Criticism

By Rory D. Sweeney

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.”

May 30, 2018

FERC Rejects MISO Network Resource Process Streamlining

By Amanda Durish Cook

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 (ER 1 8-502).

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.

ferc miso network resources — | © *RTO Insider*

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.

May 30, 2018

CalFire Says PG&E Caused 4 Wildfires Last Year

By Jason Fordney

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 pge california wildfires — 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 s a id in state m ent. 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.

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 Fi g hts Wildfire Liability, Edison International P resses 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 1 0 88) that would allow utilities to recover wildfire costs if they conform to state-regulated safety plans. (See Calif. Legislation Shie l ds 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.

May 30, 2018

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 assess m ent, 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.

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 K eeps 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 En t ity 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.

“When we don’t have the wind available, those are the types of scenarios we want to pay attention to,” he said.

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 A d ditional 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.”

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.

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.

May 28, 2018

Texas PUC Issues Final Order for SPS Wind Farm

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.)

ercot puct sps wind farm — SPS CEO David Hudson (left), legal counsel Ron Moss | © *RTO Insider*

“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.

— Tom Kleckner

May 28, 2018

ERCOT Technical Advisory Committee Briefs: May 24, 2018

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.

ercot technical advisory committee tac — May’s ERCOT Technical Advisory Committee meeting | © *RTO Insider*

“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.

Southern Cross is a proposed HVDC transmission project in East Texas that would be capable of shipping more than 2 GW of energy between the Texas grid and Southeastern markets. (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

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.

— Tom Kleckner