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%.
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.
“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.
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 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.
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 this week filed to intervene in Indianapolis Power & Light’s appeals challenging FERC decisions on energy storage compensation and dispatch within the RTO.
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 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.
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.)
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.
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.
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.
“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.
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 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.
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.
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.
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, TheWall 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.
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.
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.
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.
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’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.
New England’s offshore wind industry got another boost Wednesday as Connecticut officials announced they will purchase 200 MW of output from Deepwater Wind’s Revolution Wind project, adding to Rhode Island’s 400-MW procurement.
Rhode Island announced its selection of Revolution last month at the same time Massachusetts agreed to procure 800 MW from Vineyard Wind. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)
“With demand for 1,400 MW of U.S. offshore wind announced in less than a month, there’s a golden opportunity for heavy manufacturing companies and shipbuilders to invest in American jobs, factories and infrastructure,” said Nancy Sopko, director of offshore wind for the American Wind Energy Association.
The Connecticut Department of Energy and Environmental Protection also announced awards for 52 MW of fuel cells and a 1.6-MW anaerobic digestion project Wednesday.
Maxed out on Offshore Wind
The 200 MW in offshore wind is equal to 3% of Connecticut’s load, the maximum officials were permitted to procure under state law. Combined, the renewable energy procurements are equal to 4.7% of Connecticut’s load.
The selected projects will seek to reach agreements on 20-year contracts with the state’s electric distribution utilities, Eversource Energy and United Illuminating. The contracts will be subject to approval by the Public Utilities Regulatory Authority.
The Revolution project will be in federal waters about halfway between Montauk, N.Y., and Martha’s Vineyard, Mass. Deepwater, majority owned by The D.E. Shaw Group, also is the owner of the 30-MW Block Island Wind Farm, the first U.S. offshore wind project. The company also is pursuing a project off New Jersey in a partnership with Public Service Enterprise Group.
As part of the Connecticut procurement, Deepwater agreed to economic development commitments in New London, including the investment of at least $15 million in the New London State Pier to allow “substantial” portions of the project to be constructed and assembled in the city. It also agreed to contract with a Connecticut-based boat builder to construct one of the project’s crew transfer vessels in the state. This project is expected to spur more than 1,400 direct, indirect and induced jobs, officials said.
Vineyard Wind, which had also bid into the Connecticut procurement, said it will continue work on its Massachusetts project, with construction projected for 2019 and full operations in 2021. “We also will continue to develop the remainder of our commercial lease site with the goal of providing New England states with additional wind energy solutions in the near future,” the company said in a statement.
Fuel Cells
Wednesday’s announcement will double the installed capacity of fuel cells in Connecticut to about 100 MW. State officials said the addition will put the state in the forefront of fuel cell adoption, along with California (210 MW installed capacity) and New York (20 MW).
Doosan fuel cell | Doosan Fuel Cell America
The largest fuel cell (19.98 MW) selected was Doosan Fuel Cell America’s for the Energy and Innovation Park in New Britain. The project, the first phase of an economic development project, will use combined heat and power for heating and cooling businesses, including a Stanley Black & Decker manufacturing plant.
Others selected were Bloom Energy (a 10-MW project in Colchester) and FuelCell Energy (a 7.4-MW project in Hartford and a 14.8-MW project in Derby).
DEEP noted the average price in the fuel cell procurements was 11.6 cents/kWh, down from 15.6 cents/kWh in its 2011/12 procurement.
The Turning Earth Anaerobic Digestion Project in Southington will convert 54,000 tons of food waste and 15,000 tons of yard and woody waste into 90,000 cubic yards of compost and mulch annually.
FERC sufficiently justified its decision to revise how PJM allocates revenues from transmission congestion and its subsequent move to reject requests to rehear the issue, the D.C. Circuit Court of Appeals ruled Tuesday (17-1101).
Several PJM stakeholders had petitioned the court to overturn FERC’s January 2017 order that upheld a September 2016 ruling that modeling assumptions the RTO adopted to address financial transmission rights revenue inadequacy had resulted in unwarranted cost shifts between auction revenue rights holders and FTR holders.
The D.C. Circuit Court meets in the E. Barrett Prettyman Federal Courthouse | HSU Builders
The petitioners included Old Dominion Electric Cooperative, American Municipal Power, PJM’s Independent Market Monitor, the New Jersey Board of Public Utilities and the Delaware Public Service Commission. PJM and several stakeholders involved in its FTR markets intervened, including Exelon, Elliott Bay Energy Trading, several Public Service Enterprise Group companies, Appian Way Energy Partners, NRG Power Marketing, DC Energy, Boston Energy Trading and Marketing, Vitol and J. Aron & Co.
The court noted in its decision that between 2010 and 2014, PJM could only fund between 69 and 85% of the prevailing-flow FTRs, so FTR payments were reduced pro rata. That, in turn, reduced the value of ARRs because FTRs were worth less at auction.
PJM’s stakeholders were unable to find consensus on how to address the issue, so the RTO asked FERC to settle it by declaring the current market design unjust and unreasonable. FERC held a technical conference in 2016 and granted PJM’s request, ordering several design modifications. After FERC rejected a request for rehearing, the petitioners appealed the decision to the D.C. Circuit.
The court sided with FERC on all three of the petitioner’s challenges. It ruled that excluding balancing congestion from the funding formula for FTRs was reasonable because including it “reduces the efficacy of FTRs as a hedge.” FERC was also reasonable in requiring the entire market, rather than FTR holders, to bear the costs of the congestion because “FTR holders do not cause and cannot predict the level of balancing congestion” and “are not the sole beneficiaries of balancing congestion,” the court said.
Additionally, the court decided petitioners provided no support for their view that FERC’s actions might endanger FTRs’ exemption at the Commodity Futures Trading Commission.
FERC’s rationale for continuing to net prevailing-flow and counterflow FTRs was also sufficient, the court said. The commission had doubted that “the elimination of netting would improve FTR funding” because that would simply “reallocate FTR revenue inadequacy among various market participants without actually addressing the fundamental issues associated with FTR revenue inadequacy.” The commission also reasoned that netting is “the functional equivalent of applying the same payout ratio to both prevailing-flow and counterflow FTRs,” so all FTRs are treated equally.
Finally, the court rejected the argument that FERC should not have eliminated outdated transmission paths from the formula used to allocate ARRs. While petitioners instead wanted FERC to artificially increase growth forecasts, the commission “adequately explained why it preferred to rectify the root cause of the problem rather than pursue a remedy that could distort the planning process, such that transmission planning is not based on expected system conditions,” the court said.
The court also said it saw “no cause to displace FERC’s considered policy judgment on this matter.”
