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October 31, 2024

CPV: Subsidies, not Gas Fears, Challenge for New Plants

By Michael Brooks

Competitive Power Ventures, which last week celebrated the opening of its new 805-MW combined cycle gas-fired power plant in Oxford, Conn., would like to build more gas plants. But it said it is wary of subsidized competitors.

The company announced Thursday that is has begun selling power in ISO-NE from its Towantic Energy Center, which uses two GE Power 7HA.01 combined cycle, dual-fuel turbines, one of the most efficient designs in the world, with up to 64% efficiency.

ferc competitive power ventures cpv towantic energy center
CPV Towantic Energy Center in early May, with construction nearly complete. | CPV

The plant represents the 26th HA unit to go online, GE said. The HA series is air-cooled, which CPV says “saves as much as 90% of the water used by similar” steam-cooled designs. Poor sales of its previous steam-cooled H-class turbines prompted GE to switch to condensed air, which allows for a simpler configuration that is not only more efficient but more economic to construct as well, the company says.

ferc competitive power ventures cpv towantic energy center
A construction worker looks up at the plant’s air-cooled condenser, the design of which “saves as much as 90% of the water used by similar wet-cooled facilities,” according to CPV. | CPV

The turbines’ efficiency will give Towantic an advantage in ISO-NE’s energy market, said Tom Rumsey, CPV senior vice president of external and regulatory affairs. With no load growth in New England, new plants must be more efficient to be profitable, he said.

The plant officially began generating power May 21, just in time for the June 1 start of the 2018/19 capacity commitment period. CPV sold 750 MW of capacity into ISO-NE’s ninth Forward Capacity Auction in 2015.

It gets its fuel primarily from the Algonquin Gas Transmission pipeline and interconnects to the grid through Eversource Energy’s 115-kV Baldwin Junction-Beacon Falls circuit.

Rumsey said the company expects the plant to be a baseload resource, and it isn’t worried about there being gas shortages for the plant because it can also burn ultra-low-sulfur diesel fuel. In the 2014 polar vortex and this year’s bomb cyclone events, “it wasn’t that you couldn’t get gas. It was that gas was so expensive,” he said.

CPV is concerned, however, about state-subsidized resources disrupting the markets, Rumsey said. The company is looking to build more gas plants in New York, Illinois and New Jersey, all of which have enacted zero-emission credit programs for at-risk nuclear plants. They “represent the biggest challenge to the competitive markets since they began,” Rumsey said.

He cited the brief FERC and the Justice Department filed with the 7th U.S. Circuit Court of Appeals in the challenge over Illinois’ program, which argued that it was not pre-empted by the Federal Power Act under the Constitution’s Supremacy Clause. (See Analyst: FERC Asserts Role in Handling Nuke Subsidies.)

CPV also opposed PJM’s capacity market repricing proposals to address subsidies, instead joining Calpine and Eastern Generation to propose a “clean” minimum offer price rule applicable to all subsidized resources. (See Gas Gens Ask FERC for ‘Clean MOPR’ in PJM.)

“Accommodating these resources is the wrong way to go,” Rumsey said.

Combined with the Department of Energy’s latest plan to bail out uneconomic coal and nuclear plants, “it’s all coming to a head at FERC this year.”

MISO Seeking SPP Tx Penalty Compromise

By Amanda Durish Cook

CARMEL, Ind. — MISO says it will seek to alter SPP’s practice of levying unreserved transmission use penalties on MISO load-serving entities when the charges pose a deterrent to building interregional projects.

spp transmission penalty load serving entities
Thoms | © RTO Insider

Eric Thoms, MISO manager of interregional planning and coordination, last week said the RTO’s other contract path sharing agreements with PJM and Ontario’s Independent Electricity System Operator allow for use of transmission service when a normal feed is open and joint contract path capacity is used to serve load.

It likewise does not charge for transmission service when non-MISO LSEs use its transmission under contract path sharing.

But SPP does not acknowledge contract path sharing, instead issuing MISO LSEs bills for transmission service and unreserved usage penalties. Thoms said MISO is concerned those charges could extend to future interregional projects cost-shared between the two RTOs.

Thoms likened SPP’s charges to the early days of cellphone contracts before shared plans, when bandwidth could be exceeded only with bill increases.

“Should MISO and SPP approve an interregional project, under certain qualifying conditions, MISO members could be expected to acquire transmission service or be subject to unreserved usage penalties in addition to MISO’s cost of an interregional project,” Thoms said during a June 13 Planning Advisory Committee meeting. He recommended that the RTOs seek a compromise in the JOA that exempts MISO members from SPP’s additional transmission service or unreserved usage penalties for any future interregional projects.

“We got a shadow of evidence that this could be an issue in the last [coordinated system plan] study,” Thoms said, saying that considerable MISO load on one proposed interregional project could have seen SPP charging transmission fees on MISO LSEs.

MISO and SPP have never approved an interregional project, despite conducting two coordinated system plan studies. Thoms said stakeholders attending the PAC have suggested that SPP’s current practices “may be an impediment to interregional projects with SPP.” Some MISO stakeholders in public meetings have said a first-ever interregional project will continue to be elusive until RTOs have comparable transmission usage charges.

Thoms said some stakeholders have suggested MISO “reciprocate” and use SPP’s interpretation of transmission charges, but he discouraged the idea.

“That would also have broader implications on how contract paths are interpreted,” Thoms said. “This is in the spirit of trying to remove impediments to mutually beneficial interregional projects.”

Thoms said MISO staff will next approach the MISO-SPP Joint Planning Committee to seek a negotiation of the unreserved use charge practice with respect to interregional projects.

David Kelley, SPP director of seams and market design, said his RTO’s Seams Steering Committee is aware of MISO’s position on the “potential unreserved use charges under SPP’s Tariff and their perceived impact to future SPP-MISO interregional projects.”

“SPP looks forward to further discussions with SPP and MISO stakeholders during future [Interregional Planning Stakeholder Advisory Committee] meetings as we continue to look for ways to remove barriers to developing mutually beneficial transmission projects,” Kelley told RTO Insider.

MISO-SPP Interregional Changes

Meanwhile, MISO is still committed to making its interregional project process with SPP more scalable by removing the $5 million cost threshold and the RTOs’ joint model requirement, while adding an avoided cost benefit metric in addition to the adjusted production cost savings for interregional projects. (See MISO, SPP Look to Ease Interregional Project Criteria.)

“It’s a herculean effort to build a joint model. It takes several months, and it’s essentially another screen,” Thoms said, adding that MISO hopes to file a JOA change with FERC by the end of the year.

MISO and SPP said the 15 stakeholders that provided feedback to a spring survey were divided over whether to eliminate the joint model.

“Several stakeholders believed removing the joint model would eliminate barriers and streamline the process. Others expressed concern about equitable cost allocation, lack of joint collaboration and study timelines,” MISO said.

MISO also noted a majority of the stakeholders responding to the survey support removing the $5 million cost threshold.

MISO and SPP stakeholders will have a chance to discuss the proposed JOA changes at a July IPSAC meeting, for which no date has been set.

Gas Costs Drive Sharp Gain in CAISO 2017 Prices

By Jason Fordney

CAISO wholesale prices jumped 25% last year on higher natural gas costs stemming from tight supplies in Southern California, where the region’s main pipeline operator has no timetable for returning a critical line back into service.

The ISO’s total cost to serve load in 2017 was $9.3 billion, or $42/MWh, compared with $34/MWh in 2016, its Department of Market Monitoring estimated.

Regional spot gas prices increased 27% last year, helping to drive up electricity prices, the department said Thursday. It calculated the prices based on the average of the SoCal Citygate and Pacific Gas and Electric Citygate delivery hubs. Without factoring the gas price increases and greenhouse gas compliance costs, ISO prices rose by a much lower 4%.

natural gas caiso wholesale market
CAISO quarterly prices, system energy, all hours | © CAISO Department of Market Monitoring

Power prices received an additional boost from reduced energy supplies in the day-ahead market, a rising need for ancillary services and increased transmission congestion, the Monitor said in its 2017 Annual Report on Market Issues & Performance.

2017 wholesale prices “reflect the efficient and competitive conditions that exist during most hours of the year. However, DMM notes that the tightening of supply and demand conditions observed in 2017 has created the increased potential for uncompetitive market outcomes in 2018 and beyond.”

About 3,000 MW of gas-fired generation retired in 2017, the largest one-year volume in the ISO’s history. Another 600 MW has announced retirement in 2018, while about 770 MW of summer peak generating capacity was added, mostly solar.

The day-ahead market comprises most of the total wholesale market and remained structurally competitive, except for 36 hours, or 0.4% of intervals, when there was a single pivotal supplier needed to meet demand. The two largest suppliers were pivotal in 128 hours (1.6% of intervals), while the three largest suppliers were pivotal during 336 hours (3.8%).

Day-ahead prices spiked past $770/MWh on Sept. 1 and were greater than $200/MWh for a four-hour period.

natural gas caiso wholesale market
Erik Hildebrandt, CAISO Market Monitor | © RTO Insider

“These high day-ahead prices reflect a tightening of supply conditions during peak ramping hours that DMM expects will continue in 2018 and the coming years,” the Monitor said. Conditions were also competitive in the Western Energy Imbalance Market and its expansion and performance improved efficiency for the CAISO real-time market and other balancing areas.

Ancillary service costs increased to $172 million from $119 million in 2016 and $62 million in 2015 on tight supply conditions and higher operating reserve requirements during the summer. CAISO this week described how a problem with solar inverters led to a need to increase operating. (See Solar Inverter Problem Leads CAISO to Boost Reserves.)

The DMM is continuing its campaign against CAISO’s congestion revenue rights auction, saying payouts to CRR holders exceeded auction revenues by more $100 million in 2017 and $42 million in the first quarter of 2018. The ISO is working to overhaul to the CRR auction process. (See CAISO Developing New CRR Proposal.)

SoCalGas Says ‘No Timetable’ for Line 235

Southern California’s tight gas supplies were largely driven by the loss of Southern California Gas’ Line 235-2, which ruptured on Oct. 1, 2017, also taking nearby Line 4000 out of service. The company told RTO Insider there is “no timeline” for the return to service of the pipe, characterized as a “backbone” facility at certain points in the region.

natural gas caiso wholesale market
Site of the Line 235-2 rupture | © California Public Utilities Commission

Another factor: a restriction on withdrawals at the Aliso Canyon storage field, leading SoCalGas to warn of possible supply problems and curtailments for gas-fired plants this summer. The company has been seeking to regain full use of the facility, which has been on restricted status since a large methane release in October 2015. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.) Residents near the facility are pushing for its closure, saying they are still suffering negative health impacts, and Gov. Jerry Brown has also called for its eventual closure.

To study the capacity issue, CAISO, the California Public Utilities Commission, the California Energy Commission and others formed the Aliso Canyon Technical Assessment Group, which has determined about 500 MMcf of line capacity is missing per day compared with last year at this time, with about 2,655 MMcf available on May 1. The Line 235-2 outage will require SoCalGas to draw more from storage.

Those factors have led CAISO to warn of tight generation supplies this summer. SoCal Gas said that it has concerns the technical assessment done by the state agencies is “overly optimistic.”

“Service reductions or interruptions to electric generators may be necessary this summer and withdrawals from Aliso Canyon may be required to prevent more extensive customer outages,” the company said. No cause has been publicly identified for the Oct. 1 rupture and subsequent 5-acre fire, which occurred the day after the expiration of an CPUC-approved agreement between SoCalGas and CAISO that allowed the company to increase injections into Aliso Canyon.

PJM: Stakeholders Safe from Defaulting Member

By Rory D. Sweeney

PJM said Wednesday that it has terminated electricity supplier AMERIgreen Energy’s membership, assuring stakeholders they won’t be exposed to the company’s financial woes.

But the RTO’s actions might be the least of AMERIgreen’s concerns.

PJM announced Tuesday that the company was in default for failing to pay its May month-to-date weekly invoice, which severed its access to the RTO’s markets, rights to transmission service and ability to participate in committee meetings. But that won’t matter much as the company has crumbled seemingly overnight amid a cloud of fraud accusations and the mysterious disappearance of its CEO.

AMERIgreen Energy
PJM canceled the membership of AmeriGreen, which was owned by the Pennsylvania company Worley & Obetz, after it defaulted on paying its bill.

AMERIgreen provided electricity service to commercial and residential customers as an subsidiary of Worley & Obetz, a fuel supplier based in Lancaster County, Pa. The parent company’s issues became public on May 31 when it announced via Facebook two rounds of layoffs, the “disappearance” of CEO Jeff Lyons and a law enforcement investigation into “potentially fraudulent activity.”

On the same day, three regional banking companies alerted the Securities and Exchange Commission that they will likely lose more than $60 million combined on loans to an unnamed company, according to local media reports. One of the banks accidentally implied the defaulting company was Worley & Obetz, and another one confirmed it several days later as the saga wore on. In that time, a fourth bank disclosed additional likely losses to the SEC, saying they “resulted from fraudulent activities believed to be perpetrated by one or more executives employed by the borrower and its related entities.”

Two weeks earlier, the Pennsylvania State Police announced they were looking for Lyons because he was reported missing by his family. The CEO, a 22-year veteran at the company, had left home without his wallet or credit cards and turned off his cellphone. He missed a meeting with the company’s vice chairman and a large commercial customer, where he was expected to discuss financial records he had previously been reluctant to disclose. He was terminated for cause later that day.

Police announced two days later that he had been located but that, because he wasn’t in danger, they couldn’t provide more information. According to media reports, a family member announced on Facebook that he was found in Minnesota.

The company then attempted to secure credit for restructuring, but the banks refused the plan. The company announced it was shutting its doors last Monday and has since filed for bankruptcy as “a direct result of the fraudulent actions of Jeffrey B. Lyons.”

AMERIgreen’s nosedive was abrupt. On Wednesday, it was still offering electricity contracts serviced through Texas-based TriEagle Energy, but it has since ceased.

In announcing the membership cancellation, PJM assured market participants that they won’t be liable for the default.

“PJM projects it holds sufficient financial security from AMERIgreen to cover both its outstanding charges and any anticipated remaining charges related to their default,” PJM said. “Therefore, PJM does not anticipate there will be a default allocation assessment to PJM members resulting from AMERIgreen’s default.”

PJM spokesperson Jeff Shields said the RTO’s credit requirements are designed for this issue.

“All members are required to provide credit based on their recent historical invoice activity, so more members buying more energy would be required to provide more collateral. Some members also engage in market activities that are screened, such as [financial transmission rights] and virtual transactions, and those other market activities have additional requirements,” he said via email. “PJM allows a limited amount of unsecured credit for investment-grade members; all activity exceeding that level must be collateralized.”

The company’s load is being transitioned to applicable electric distribution companies. The terms of service for such customers is set by state regulators, Shields said.

MISO Intervenes in IPL Storage Appeal

MISO this week filed to intervene in Indianapolis Power & Light’s appeals challenging FERC decisions on energy storage compensation and dispatch within the RTO.

IPL Storage Energy Storage MISO FERC
IPL Harding Street Station battery interior | IPL

In a June 11 filing, MISO said it had “direct, substantial and legally protectable interest that would be subject to impairment” by IPL’s litigation. The RTO also said its independence from its members ensures “no other party can adequately represent” its interest in the case that could force changes to its Tariff (18-2104).

The case is pending before the 7th U.S. Circuit Court of Appeals after IPL filed a petition for review in mid-May, challenging FERC orders stemming from the company’s 2016 complaint that MISO’s Tariff unreasonably limited energy storage participation. (See FERC OKs MISO Plan to Expand Storage.)

IPL Storage Energy Storage MISO FERC
IPL Harding Street Station battery facility | IPL

In its petition for review, IPL pointed out that FERC’s original order on its complaint in early 2017 was issued two days before the commission lost its quorum and was reduced to just two commissioners.

— Amanda Durish Cook

MISO Planning Advisory Committee Briefs: June 13, 2018

CARMEL, Ind. — MISO is moving ahead with a plan to address delays in its interconnection queue by reducing the number of project studies and making generation owners more accountable for site control.

The RTO in May proposed to remove its transient-stability, short-circuit and affected-system studies from the first phase of the definitive planning phase (DPP) of the queue and require customers to demonstrate ownership, lease interest or land rights on a project’s site before entering the queue. (See MISO Proposal Aims to Speed Up Queue Process.)

June 13 MISO Planning Advisory Committee | © RTO Insider

MISO is now proposing to eliminate its proposed requirement that a developer have 100% site control upon entering the queue. A revised plan would instead increase the deposit due when entering the queue from $100,000 to anywhere between $500,000 and $2 million in cash, depending on the megawatt size of the project. The larger deposit would only become refundable if the proposed project makes it to the generator interconnection agreement step.

Under the plan, a project owner would have to demonstrate full site control by the second decision point of the interconnection queue, MISO Planning Manager Neil Shah said during a June 13 Planning Advisory Committee meeting. Any owner unable to provide proof of site control by then must forfeit the larger deposit and withdraw their interconnection application, he said, adding that MISO plans to hire consultants to validate site control demonstrations.

Shah | © RTO Insider

Stakeholders — particularly renewable developers — said the proposed site control requirements were still too high.

But Shah noted that in April alone, an additional 40 GW entered the interconnection queue, with around 75% of project owners electing to pay the current $100,000 refundable deposit instead of securing site control.

“The bar is too low for entering the queue,” Shah explained. “The intent is to raise the bar, so we have reasonably high requirements that do not harm ready projects because of the entry of the non-ready projects.”

Shah said MISO intends to file Tariff changes with FERC sometime in July.

5 Focus Areas in Market Congestion Planning Study

MISO has slimmed 116 new project ideas down to five areas of focus in this year’s footprint-wide market congestion planning study.

The Market Congestion Planning Study (MCPS) has so far identified four project candidates in four separate locations in MISO Midwest, and five projects to remedy one area of concern in MISO South.

Midwest candidates for MCPS | MISO

In MISO South, five projects ranging from $8 million to $40 million with estimated benefit-cost ratios ranging from 1.10:1 to 3.27:1 are contenders to alleviate congestion on the 115-kV Natchez line at the Mississippi-Louisiana border.

In MISO Midwest, two projects focus on upgrading 138-kV facilities while two others are 161-kV solutions:

  • A rebuild of the Wabaco-Rochester 161-kV line in southern Minnesota at an estimated $20.1 million, yielding a 3.62:1 benefit-cost ratio.
  • A project to add a series reactor on the Forest Junction-Elkhart Lake 138-kV line in eastern Wisconsin for $2 million, resulting in a 3.7:1 benefit;
  • A reconductor project on the Michigan City-Trail Creek-Bosserman and LNG-Maple 138-kV lines in northern Indiana for an estimated $8.5 million, with a 1.42:1 benefit.
  • A new 161-kV line with a reconductor of an existing 161-kV line near the towns of Paradise and Wilson in southern Indiana for $33 million with a 1.59:1 benefit.

MISO Manager of Economic Studies Zheng Zhou said all cost estimates are planning-level estimates and are subject to change.

MISO’s MCPS study seeks to identify both near-term congestion-relieving transmission projects and long-term economic projects. Last year’s MCPS focused exclusively on MISO South and did not produce a single project recommendation.

Zhou said MISO will present final project recommendations from the MCPS at the September Planning Advisory Committee meeting.

— Amanda Durish Cook

WAPA Formally Requests SPP’s RC Services

By Tom Kleckner

The Western Area Power Administration said Wednesday it has submitted a formal request to SPP for reliability coordinator (RC) services on behalf of its Upper Great Plains West and Western Area Colorado Missouri balancing authorities.

WAPA said the two BAs are considering taking SPP’s RC services in early 2020, contingent on the RTO gaining certification and meeting other conditions. The BAs encompass WAPA’s Pick-Sloan Missouri Basin Program in the Western Interconnection, Loveland Area Projects and part of its Colorado River Storage Project Management Center territory.

“We are excited about this opportunity and look forward to more detailed negotiations with SPP,” WAPA CEO Mark Gabriel said in an announcement.

SPP said the request was the first of what it hopes will be many since it announced June 5 that it intends to provide RC services in the Western Interconnection by late 2019. (See Westward Ho: SPP Plans to Become RC in West.)

The RTO said it has received 28 letters of intent from utilities expressing interest in the service but noted that WAPA’s letter was special.

SPP WAPA reliability coordinator
Monroe | © RTO Insider

“Our agreement with WAPA is distinct in that it’s the first — of many, we anticipate — to go a step further and commit to the preparation of an actual service agreement,” COO Carl Monroe said in an emailed statement to RTO Insider.

Monroe said the letters of intent “have established partnerships in which SPP will assist each of them in evaluations of the costs and benefits of our provision of reliability coordination service.”

Peak Reliability current provides WAPA’s RC services, but the agency said in February it had sent withdrawal notices to Peak, effective Sept. 2, 2019. WAPA is considering both SPP and CAISO, which also plans to become an RC. The Alberta Electric System Operator already provides reliability coordination in the West.

SPP WAPA reliability coordinator
WAPA Regions | WAPA

The Western Electricity Coordinating Council has asked its BAs and transmission operators to confirm which RC they will be using by Sept. 4.

“We continue to engage with neighboring utilities and Mountain West Transmission Group participants on the future of energy markets and RC services in the West,” Gabriel said.

A WAPA spokesperson said the agency has asked SPP to submit a proposal for terms and conditions under which its BAs would receive RC services.

WAPA is one of four power marketing administrations within the Department of Energy. It encompasses a 15-state region of the central and western U.S. and has a 17,000-mile system that carries electricity from 56 federal hydropower plants.

MISO, PJM Downplay M2M Error Impacts

By Amanda Durish Cook

MISO and PJM this week challenged the contention by MISO’s Independent Market Monitor that PJM’s two long-term market-to-market errors have cost MISO millions, calling the financial impacts “minimal.”

In a document circulated this week, the RTOs said their analysis found the potential joint operating agreement settlement impacts associated with the flowgates amounted to less than $100,000, and that they considered the two issues resolved.

For more than a decade, PJM had been overstating its own transmission loading relief (TLR) because of a calculation error and since 2009 had failed to order mandated tests required to define M2M constraints between the two RTOs.

MISO PJM m2m market-to-market David Patton
Patton at MISO Board Week in March | © RTO Insider

Late last year, MISO Monitor David Patton said that PJM had knowingly violated the JOA, likely costing MISO millions of dollars. (See MISO Board, Monitor Seek Response to PJM M2M Missteps.)

But the RTOs said a joint investigation of the errors found “there was minimal and/or undeterminable impact,” although PJM admitted that the TLR error did constitute a JOA violation.

Only 2 Flowgates

Based on after-the-fact analysis, the RTOs said “only two potential flowgates requested by MISO for testing” may have qualified for the neglected tests to define M2M constraints.

However, the RTOs acknowledged — as did the MISO Monitor late last year — that the actual impacts of the missed tests are difficult to quantify.

“System conditions that represent the two potential flowgates cannot be fully duplicated and, therefore, the actual impacts, if any, of these two flowgates cannot be confirmed. However, the estimated PJM impact was minimal. … Because of the minimal impact, PJM and MISO consider this investigation closed at this time,” the RTOs said.

PJM added that it does not believe that it committed any JOA violations by overlooking the test.

But Patton said PJM did not study a long enough period to accurately estimate impacts stemming from the neglected test.

“Whether the impacts are large or small is an empirical question,” Patton said in a statement to RTO Insider. “PJM studied only a little more than a year even though they had not performed [the test] ever since the JOA with MISO was implemented. The impacts may well have been small in the period PJM studied but could have been larger in other periods.”

Patton also said he and his staff continue to be “confident” that the failure to perform the test was a known violation of both PJM’s Tariff and the JOA.

“Regardless of the effects of the violation, this raises questions regarding the culture of compliance at PJM,” Patton said.

FERC Report over TLR Issue

PJM said that “an incorrect line of code” was to blame for its underreporting of available market flow during certain TLR events. In that case, PJM acknowledged that it violated the congestion management agreement section of the JOA. PJM said it self-reported to FERC over the issue.

“PJM is also conducting an internal apparent cause analysis for the event in order to determine root causes, develop recommendations and implement process updates designed to help avoid a reoccurrence,” the RTOs said.

Similar to the test error, PJM and MISO said the overstatement of TLR “cannot be retroactively determined” and that the JOA does not provide guidance on resettlement opportunities related to TLR activities.

“Importantly, system operations aligned with prices,” the RTOs said.

During a May 30 Joint and Common Markets meeting, executives from both RTOs said they considered the matter closed because of their minimal impacts.

“We’ve made sure the issues are corrected going forward,” said Ron Arness, MISO seams management expert.

But Patton again said MISO and PJM could not determine the size of the impacts with any certainty.

“We believe the second issue likely had sizable adverse effects over almost a decade on MISO, its customers, and others obligated to respond to TLRs. PJM does not suggest that these effects are small, just that they are indeterminable,” Patton said.

He added that it was “unfortunate” for those affected by the longstanding error that the JOA does not provide a remedy for such situations.

Please Feel Free to Surprise Us

By Steve Huntoon

As bailout hour approaches for coal and nuclear units — Rick Perry doesn’t want to be the next Jeff Sessions — let’s recap highlights from the Department of Energy’s leaked memo and a Trump official’s comments.

ferc doe coal nuclear bailout
Huntoon

As all of us in the industry know, the 40-page memo is a ludicrous attempt to put lipstick on a $65 billion pig.[1] I’m not going to waste your time on how ludicrous the substance is — if you don’t know already you can go to my prior columns[2] and to the informed commentary of just about every unbought person in the industry (like former FERC chairs and commissioners, the RTOs themselves and, indeed, The Wall Street Journal in a lead editorial).

I will offer a couple comments on the supposed legal support. Defense Production Act Section 101b says that power under Section 101 can only be exercised when the subject material is “scarce,” and of course electric generation resources aren’t scarce at all.[3] Federal Power Act 202c applies only to emergency, shortage and temporary situations, so invoking it here would require lying about all three prerequisites.

The DOE memo’s authors are presumably lawyers (maybe DOE lawyers, maybe not) and know that these legal requirements can’t be met, so the memo relies on what might be called the spaghetti approach — throw everything against the wall and hope something sticks. And if it doesn’t stick in court Trump can always blame evil judges and the nefarious Deep State. But meanwhile, creating massive chaos and distracting us from serious matters. Sad.

ferc doe coal nuclear bailout
Menezes | © RTO Insider

Let me turn to DOE Undersecretary Mark Menezes’ remarks to reporters at a conference the other day.[4] I’ll quote the remarks and offer some thoughts in italics.

“It is the premature closing of baseload that is really upsetting the industry,” Menezes said. This short sentence has three total untruths. First, the retiring units are not retiring “prematurely” — they are old. Second, the retiring coal units are not baseload (high capacity factor) units — they are inefficient, low capacity factor units. My prior column discussing the rampant abuse of the words “premature” and “baseload” is posted.[5] Trump officials are simply parroting FirstEnergy and Robert Murray untruths.

ferc doe coal nuclear bailout
FirstEnergy’s coal-fired Pleasants Power Station in West Virginia

The third untruth is a claim that the industry is “upset” by retirements. Nothing could be further from the truth. Clunkers are retiring as part of a natural, orderly, market-driven process that has been going on for decades. The retiring units are three times less reliable than new units, which means that keeping the old ones, and thus keeping out new units, actually makes the grid less reliable.

The industry is upset, but only about the prospect of a Trump bailout that has no legitimate basis whatsoever and would cause major if not permanent damage to the electricity markets that have served us so well.

“We are not talking about disrupting the markets.” Of course Trump and his acolytes are talking about disrupting the markets — that’s the whole idea. This is universally understood, even by those who want a bailout.

“It is more than the markets. The markets don’t exist everywhere in the country. These markets have not been mandated by Congress. They are voluntary. They are approved by FERC.” His point seems to be that utilities can leave RTOs, perhaps if states are not happy with an RTO. This is legally true but apropos of nothing. And no utility that joined an RTO has left an RTO except for a couple Kentucky utilities more than 10 years ago. These remarks are vacuous on multiple levels.

“The RTOs … are not natural markets. In fact, electricity is a natural monopoly.” Electric generation is not a natural monopoly, which is why an RTO like PJM has dozens of competing electric generation suppliers and has had for decades.

There’s no legal justification or public policy justification for the Trump bailout. We all know that.

“Profiles in Courage During the Trump Administration” is the world’s shortest book. Perry could contribute a first chapter by reprising his vital role in the development of Texas’ electric market and just say no to a bailout (and nationwide $65 billion rate increase).

If Trump insists, Perry could invoke Davy Crockett’s immortal words: “You may all go to hell and I will go [back] to Texas.”

We’re not holding our collective breaths but, hey, please feel free to surprise us.

  1. Industry expert Rob Gramlich provided this annual cost estimate in Capitol Hill testimony last week, based on an analysis by PJM’s Independent Market Monitor. https://science.house.gov/sites/republicans.science.house.gov/files/documents/HHRG-115-SY20-WState-RGramlich-20180607.pdf (page 12).
  2. http://energy-counsel.com/recent-publications.html.
  3. As Gramlich testified, “Each region already has a Strategic Generation Reserve. It’s called a reserve margin.”
  4. See FERC Blindsided by Half-Baked Trump Order.
  5. http://energy-counsel.com/docs/Clunker-Poster-Child.pdf.

ERCOT Board of Directors Briefs: June 12, 2018

ERCOT CEO Bill Magness assured his Board of Directors on Tuesday that the grid operator is prepared for the summer heat, despite the retirement of 4 GW of coal-fired capacity since last summer.

Magness highlighted a plethora of meetings staff have held in recent weeks with regulators, media, information officers from state utilities, pipeline and gas companies, transmission owners and other stakeholders. He also noted new demand records set in May and June, which the ISO managed without emergency alerts or conservation appeals.

ERCOT Senior Meteorologist Chris Coleman checks his mike with CEO Bill Magness looking on at the June ERCOT Board of Directors meeting. | AdminMonitor

ERCOT recorded new monthly demand records of 67.3 GW on May 29 and 67.9 GW on June 1. Magness told the directors May was the hottest ever recorded in the United States, and the second-hottest in Texas.

“We saw it on the system,” he said. “We’re just getting into summer. Here we go!”

Staff has projected a new summer peak of 72.8 GW in August. It says it has 78.2 GW of capacity available and continues to expect to have enough resources to serve load. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)

Senior Meteorologist Chris Coleman pointed out that heat records in May don’t necessarily equate to a “blazing” summer. He said Texas’ hottest May in 1996 was followed by the 76th hottest summer on record. Of the 20 hottest Mays dating back to 1895, only five were followed by one of the 20 hottest summers.

Coleman | AdminMonitor

“We’ll be hotter than last summer, which won’t take a lot,” Coleman said, referring to the 50th hottest summer on record.

Coleman said the expected rains from Gulf of Mexico and Pacific storms over the next week will help tamp down temperatures in the weeks that follow.

“We’ll always take more rain, but substantial rain leads to soil moisture and water in the reservoirs,” he explained. “That will tone down the extreme heat this summer. That’s the type of thing that prevents 2011 from happening again.”

That year remains the state’s hottest on record. The Dallas-Fort Worth Metroplex recorded 40 straight days of 100-degree temperatures — and 71 overall — in 2011.

Coleman is looking at 2013 and 2006 — Texas’ 21st and 42nd hottest summers — as indications of what to expect this summer, and he said there is a two-in-three chance that temperatures will end up between those two years.

He also predicted less hurricane activity than last year, when Hurricane Harvey dumped 52 inches of rain on the Houston area. Coleman said without the La Nina of 2017 or an El Nino, overall activity will probably be at the lower end of the National Oceanic and Atmospheric Administration’s predicted range of 10 to 16 named storms and five to nine hurricanes.

The good news with May’s summer heat?

ERCOT’s year-to-date net revenues have a favorable variance of $8.3 million, and a favorable year-end forecast of $12.3 million.

IMM’s Garza Calls for Evaluation of Local Signals

Beth Garza, director of ERCOT’s Independent Market Monitor, said the ISO should evaluate the market’s ability to send local signals.

IMM Director Beth Garza | AdminMonitor

As she reviewed the Monitor’s annual State of the Market report, Garza reminded the board that price signals that incent new generation are a fundamental aspect of a “sustainable, ongoing market.” She said that net revenues (revenues in excess of assumed production costs) over the past six years are far less than the costs of building a new peaking unit, a result of the market’s capacity surplus.

“We have a market that continues to grow and with requirements continuing to increase, which requires sufficient resources to meet those,” Garza said. “But since the start of the nodal market in 2011, the net revenues have not been sufficient to pay the fixed costs of new generation.”

Net revenues in the market were around $110/kW in 2011, but only broke $40/kW last year — and only in the Houston region. The Monitor has estimated the cost of new entry between $80 and $95/kW, based on the value of simple cycle gas turbines.

ERCOT summer peak bill magness
Net Revenues by Year and ERCOT Zone | Potomac Economics

“I don’t have a lot of precision, hence the range,” Garza told the board. “We’ve been so far under for so long, it’s hard to get focused on whether [the point of entry] should be $82/kW or $95/kW. I don’t know what that ratio is, but we have certainly seen a half-dozen years or so of very low contributions toward net revenues.”

Garza said congestion costs increased 95% to $967 million over 2016 because of wind generation exports from the Texas Panhandle, construction of the Houston Import projects and Harvey’s aftermath. She expects the Panhandle congestion costs to continue to increase as more wind is built in West Texas without a commensurate addition of transmission infrastructure.

“The Panhandle … contributes to those high costs because of the large differential in generation costs on either side of that constraint,” Garza said. “Wind generation in the Panhandle is at zero or below. The average cost on the ERCOT side is at 20, 30, 40 dollars. That spread is much higher than other constraints.”

The Monitor again included real-time co-optimization on its annual list of market improvement recommendations. (See “Monitor Says Wholesale Market ‘Performed Competitively’ in 2017,” ERCOT Briefs.)

Garza said that real-time co-optimization would make better use of the system’s resources, lower costs, allow for efficient shortage pricing when the market can’t satisfy any of its energy or reserve needs, and allow all supply to participate in the ancillary services markets.

$327M in Tx Projects will Meet Permian Basin’s Load Growth

The board unanimously approved $327.5 million in West Texas transmission projects to address congestion from increasing oilfield load growth in the Permian Basin.

The Far West Texas Regional Planning Group Projects include new construction and upgrades of three 345-kV lines — Riverton-Sand Lake, Sand Lake-Solstice and Solstice-Bakersfield — that staff recommended be designated as critical to system reliability. The board agreed with the recommendation.

ERCOT summer peak bill magness
ERCOT’s Far West Texas Projects | ERCOT

Jeff Billo, ERCOT’s senior manager of transmission planning, told directors the projects will allow the region to handle up to 1.7 GW of load. Staff’s independent review of the two Oncor projects indicated local load projections of 880 MW and 1,013 MW for 2019 and 2022, respectively. A year ago, load projections for 2021 came in at 553 MW.

Billo said the region has added 80 rigs in the last year. “It’s the hot spot of hot spots,” he said.

IHS Markit, a global data firm, has predicted the Permian Basin in Texas and New Mexico will become the world’s third-largest producer of oil, behind only Saudi Arabia and Russia. The firm projects production will double to almost 5.4 million barrels a day between 2017 and 2023.

Construction on the Far West Texas projects is expected to begin next year, with completion in 2023.

Board Approves 8 Change Requests

The board remanded back to the Technical Advisory Committee a nodal protocol revision request (NPRR) incorporating an intraday or same-day weighted average fuel price into the mitigated offer cap.

The City of Dallas’ Nick Fehrenbach, representing the commercial consumer segment, had the change pulled off the consent agenda, saying its language was unclear. “I think at best the language is vague and confusing. At worst, it’s an unenforceable clause,” he said.

Fehrenbach said he was unable to come up with a solution with ERCOT staff. Market participants won’t be harmed, he said, because the ISO already uses a manual workaround for exceptional fuel prices.

NPRR847, which cleared the TAC unanimously, is meant to ensure resources are capped at the appropriate cost during high fuel-price events and that LMPs reflect the true incremental cost of fuel.

The board also tabled an accompanying verifiable cost manual revision request (VCMRR021), which aligns the manual with NPRR847 by removing language providing for make-whole payments for exceptional fuel costs.

The board approved four other NPRRs, a pair of other binding document revisions (OBDRRs) and two changes to the Planning Guide (PGRRs):

  • NPRR837: Updates the Regional Planning Groups’ tier classification rules, among other related improvements and clarifications, to ensure the RPG and ERCOT are reviewing the most appropriate subset of transmission projects.
  • 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.
  • 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 security-constrained economic dispatch 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 RPG-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.

— Tom Kleckner