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.”
WASHINGTON — FERC commissioners told Congress yesterday the grid is not facing a national security emergency, as the Trump administration has claimed in its call for saving at-risk coal and nuclear generation.
At an oversight hearing before the Senate Energy and Natural Resources Committee, Sen. Martin Heinrich (D-N.M.) asked the five commissioners whether any of them believed there is a national security emergency in the wholesale power markets.
When Sen. John Barrasso (R-Wyo.) asked whether the commissioners agreed on the need to keep coal in the generation mix, Chairman Kevin McIntyre responded by reiterating his support for “an all-of-the-above strategy.”
McIntyre also agreed under questioning from Sen. Joe Manchin (D-W.V.) that Energy Secretary Rick Perry has the authority to issue emergency orders under the Federal Power Act and Defense Production Act of 1950. “There’s no question that the secretary does,” McIntyre said.
The two and a half-hour hearing — the first Senate oversight hearing involving all the FERC commissioners in a decade, according to Chair Lisa Murkowski (R-Alaska) — also touched on LNG and pipeline project licensing and the Public Utility Regulatory Policies Act (PURPA).
Most Democrats, led by ranking member Maria Cantwell (D-Wash.), blasted the proposal. LaFleur and Commissioners Richard Glick and Rob Powelson were the most outspoken in their opposition to the subsidies.
Commissioner Neil Chatterjee was somewhat more sympathetic, saying some critics had been too quick to dismiss DOE’s draft memo, which seeks to justify capacity and energy payments to prevent plant retirements.
“There are a number of points in the memo that are thoroughly well cited and researched,” he said. “I think we can have disagreements about what the remedy may be, but I think they raise a real issue … that we need to look at.”
While acknowledging the vast majority of outages are the result of distribution and transmission failures rather than losses of generation, Chatterjee added, “We shouldn’t assume that that good fortune will continue.”
‘Policy Vacuum’
Murkowski acknowledged, “I have my concerns with the steps the Department of Energy is reported to be considering.” But she said DOE was trying to fill a “policy vacuum” created by FERC’s failure to act more quickly on resiliency concerns.
“In my view, FERC should be pointing the way on policy improvements that address grid vulnerabilities, while reaffirming our commitment to competition in wholesale power markets. Frankly, as one who has been concerned about this issue for years now, I find it unfortunate that prior commissions did not lead more effectively,” she said. “We must increase the light and lower the heat in policy debates about price formation, state resource preferences and subsidies.”
LaFleur, the commission’s longest-serving member, defended the commission’s work in navigating the shift to more gas and renewable generation.
“We work to ensure resilience by overseeing market changes to increase compensation to resources that are on line in times of system stress and extreme weather, including baseload resources. In the energy market, we [have] worked on a number of steps since 2014 to improve price formation to make sure the markets send the correct price signals,” she said.
LaFleur said the commission should continue to craft “tailored regional solutions” to address tensions between wholesale markets and state policy favoring certain generators.
“Indeed, I believe the resource turnover we’re experiencing is an expected consequence of markets and technological change, and the lower prices that result from well-functioning markets are a benefit to consumers — not a problem to be solved, unless reliability is compromised,” she said.
“We cannot try to stop the natural evolution of this industry by claims there’s a national security emergency unless there is evidence to suggest an emergency actually exists,” said Glick. “… We need to keep on being vigilant and keep monitoring the situation. But we also need to be wary of people using the situation — or the potential situation — as an excuse to achieve market changes they haven’t been able to achieve otherwise.”
Cantwell said the administration’s “radical” plan could cost consumers billions, telling the commissioners that maintaining “‘just and reasonable’ [rates is] your job … That is why we have a FERC.”
But Sen. Joe Manchin (D-W.V.) dismissed concerns that the subsidies would raise prices. He noted that the draft DOE memo envisioned subsidies for two years while the agency studies grid risks. “You’re acting like it’s going to be forever,” he told the commissioners.
When he pressed the commissioners to identify any generation sources other than coal and nuclear that can provide 24/7 “baseload” power, Glick mentioned “some hydropower,” while Powelson volunteered natural gas.
‘Human Impact’
Sen. Shelley Moore Capito (R-W.V.) complained that renewable subsidies and environmental regulations had “led to a failure that has been punishing” coal generation and the communities that depend on them.
Glick and Chatterjee expressed sympathy for those who have lost their jobs due to coal and nuclear plant closures. But they said providing relief to such workers is the job of Congress and state legislators, not FERC.
Chatterjee said he understood the “human impact” of plant closures because of his visits to West Virginia coal country with Capito and the Colstrip coal plant with Sen. Steve Daines (R-Mont.).
“That is not something that we factor into our record. We will look at plants like Colstrip and make a determination based on … whether there would be threats to reliability in the event the plants shut down,” he told Daines. “But that’s certainly something that’s well within your purview.”
Texas Governor Greg Abbott on Monday appointed ERCOT Director of Communications and Government Affairs Shelly Botkin to fill the final vacancy on the state’s Public Utility Commission. Her term expires Sept. 1, 2019.
Botkin
Botkin’s appointment will bring the three-person commission back to full strength. She will fill the position vacated by Brandy Marty Marquez’ departure in March. (See Marquez to Depart Texas PUC.)
Botkin will be sworn in Wednesday and attend her first PUC open meeting Thursday.
The 46-year-old Botkin has been with ERCOT since 2010. She spent the previous 10 years as a senior policy analyst in the Texas Senate and House of Representatives.
ERCOT CEO Bill Magness said in the statement the ISO looks forward to working with Botkin.
“Shelly’s knowledge of electric market policy and the regulatory and legislative process has been a tremendous asset to ERCOT over the last eight years,” he said.
The Texas Governor’s Office is in the state capitol building, constructed from 1882 to 1888.
The PUC has seen a complete turnover of commissioners in little more than a year. Donna Nelson and Ken Anderson, the two longest-serving commissioners, both left the agency last year. They were replaced by Chair DeAnn Walker and Arthur D’Andrea, respectively.
