MISO last week announced that it will hold its second Market Symposium in downtown Indianapolis on Aug. 15-16.
This year’s theme is “Markets in 3D: Preparing for Digitalization, De-marginalization and Decentralization,” and the two-day event includes industry experts discussing how wholesale market design and technology may change with increasing use of connected devices, distributed energy resources and renewable generation with near-zero marginal costs.
“The MISO team is working to create a forum for industry leaders at the forefront of future market design to explore longer-term challenges and opportunities,” MISO CEO John Bear said in a statement. “The symposium will provide a venue to interact with thought-leaders, explore emerging technologies and build relations with decision-makers and innovators who are at the helm of a changing industry.”
The symposium will feature FERC Commissioner Richard Glick as special guest speaker, and MISO has again partnered with the Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E) to host the event.
This year’s symposium also includes an emerging technology and market solution showcase. MISO is currently accepting applications for booth exhibits and five-minute presentations on industry innovations on the main stage.
“We know our industry is transforming,” said MISO Research and Development Director Jessica Harrison. “We want to foster thought-provoking discussions so that the industry can meet future challenges with innovative solutions that ultimately improve service and value for consumers.”
CAISO’s Board of Governors on Wednesday approved new provisions to account for errors in load forecasts by allowing grid operators to manually update the forecasts to deal with changing conditions on the grid.
At its May 16 meeting in Folsom, Calif., the board also heard from CEO Steve Berberich about the tight supply conditions the ISO foresees this summer, as well as what he called “a very serious issue” regarding inverters that caused an 860-MW loss of solar resources on April 20.
The board approved the new “imbalance conformance” rules that allow the ISO to account for errors in renewable energy forecasts or instances when generators deviate from their dispatch orders. The Energy Imbalance Market Governing Body approved the rules last month. (See EIM Body Approves Imbalance Conformance Rules.)
The board also approved alterations to the Imbalance Conformance Limiter, an ISO software tool designed to prevent price spikes caused by imbalance conformance adjustments. The limiter keeps the market from trying to dispatch more supply than is available in a particular dispatch interval to account for imprecision in the adjustments.
CAISO Department of Market Monitoring Director Eric Hildebrandt told the board that while the department supports the changes, the magnitude of load adjustments has increased dramatically, doubling between 2016 and 2017. The adjustments should be more random in nature and not used as systematically as they have been, he said.
In his presentation, Hildebrandt said “the ISO appears to use load conformance as means to procure additional imports in the hour-ahead process to ensure more ramping capacity is available in the 15-minute and five-minute markets.”
The Monitor recommends the ISO focus on how it can reduce the need for operators to make manual adjustments in real time.
Southern California Edison opposed the changes, saying that the new limiter enhancements should be implemented in addition to the old limiter logic in order to maintain price stability. Powerex also opposed the measures, saying they might suppress scarcity pricing in some situations, according to a presentation from CAISO Vice President of Market Infrastructure Keith Casey. FERC must approve the changes before they take effect.
Warnings of Tight Supply, Inverter Issues
Berberich explained to the board that on April 20, the Mira-Loma-Vincent 500-kV line in the SCE service territory relayed, causing 860 MW of solar to trip off because of voltage fluctuations.
“It’s a really exciting event down in the control room when we lose 860 MW,” Berberich said during his CEO report.
CAISO has been trying to reprogram inverter settings so they can ride through the relays and is working with NERC to create an appropriate industry-wide standard to address the problem. While the ISO has been able to reprogram some inverters, others cannot be reprogrammed, leading it to rely other resources at certain times.
“We are going to keep a close eye on this issue,” Berberich said, adding that the ISO views the new NERC standard as an important goal. He said public calls for demand reductions will be key in managing grid conditions this summer.
“We expect to have very tight conditions this summer,” Berberich said, adding that the gas system is operating at a “bare minimum.”
An ISO presentation showed that after modeling 2,000 scenarios, it was found there is a 50% probability of a Stage 2 emergency for at least one hour this summer. CAISO declares a Stage 2 emergency when it becomes clear that operating reserves will be less than 5% after dispatching all resources, including demand response. The ISO did not include in its modeling the gas supply limitations from restricted use of Aliso Canyon, which it said could represent further reliability risk. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)
ALBANY, N.Y. — About 194,000 customers in New York were without electric power in the state after a series of thunderstorms hit on May 15, the Public Service Commission heard Thursday.
The outages were mostly in the Lower Hudson Valley, the same area that suffered severe outages in March, said Michael Worden, director of the commission’s Office of Electric, Gas and Water.
“We have about 5,550 [full-time equivalents] of line, tree and service crews there providing support to the area,” Worden said. “That includes on the order of 1,250 out-of-state, out-of-region crews, and also includes a large contingent of New York crews that have been redeployed from, for example, Western New York. So there’s a significant recovery effort going on.”
By Saturday, most customers had had their power restored, with only about 13,600 still out, according to PowerOutage.us, which aggregates utility-reported outage data.
The commission is continuing to investigate the various utilities’ March outages and storm response efforts, Worden said.
Grid Ready for Summer
New York’s bulk electric system is prepared to reliably meet this summer’s load forecast, according to the Department of Public Service.
Department staff based its assessment on a review of utility data and meetings with individual utilities and NYISO, Vijay Puran, DPS senior engineer for electric transmission planning, told the commission.
| NY Department of Public Service
“Utilities will complete all planned major reinforcements, inspections and repairs prior to the start of the summer season, and they have adequate spare equipment on hand to meet unforeseen circumstances,” Puran said during a presentation.
The ISO predicts demand will peak at 32,904 MW this summer. With a total resource capability of 42,169 MW on hand, the grid’s margin of safety comfortably exceeds the 18.2% required installed reserve margin, Puran said.
| NYISO
Peak demand forecasts have dropped by more than 3,000 MW since 2015, which the ISO “attributes to the positive effects of the state’s energy programs and to underlying forecast econometric growth rates,” he said.
Puran said hundreds of megawatts of load reduction are available to Consolidated Edison through its demand response programs, and other utilities have similar load-relief measures they can turn to if needed.
DPS staff expect the cost for electricity this summer to be higher than last year but 9 to 12% below the five-year average.
“I hear this as an outlook that is good news for New Yorkers, giving us comfort that we can confidently expect adequate supply and reasonable costs,” PSC Chair John B. Rhodes said.
National Grid Utilities Audit
In its consent agenda, the commission ordered a management and operations audit of three National Grid USA subsidiaries: Niagara Mohawk Power, Brooklyn Union Gas and KeySpan Gas East (18-M-0195). The effort will focus on construction program planning and operational efficiency.
“The audit will include an assessment of the utilities’ readiness to respond to the Reforming the Energy Vision initiative and closely examines how the utilities plan for and manage information systems projects,” Rhodes said in a statement. “The audit will also address issues from previous management audits that require follow-up review, such as organizational structure, project estimating processes and work management processes.”
Gov. Andrew Cuomo in 2013 highlighted the importance of management and operations audits of the state’s utilities, and introduced — and subsequently signed — legislation that required utilities to file plans for implementing audit recommendations.
This is the fourth comprehensive audit since 2013, and three additional audits are underway, the commission said.
“To date, these audits have recommended numerous productivity enhancements, better risk mitigation strategies, and improved planning processes, as well as other operational improvements at New York’s utilities,” the commission said. “These process improvements result in savings for customers over time, and those savings are captured in rate cases.”
The House Energy and Commerce Committee last week heard testimony on Republican-backed legislation that could allow power plants and industrial boilers to avoid expensive upgrades under EPA’s New Source Review (NSR) program.
Facilities are subject to NSR if they make non-routine modifications that increase annual emissions; such plants must use the “best available control technology” to minimize the emissions increase.
The bill, written by Rep. Morgan Griffith (R-Va.), would amend the definition of “modification” under Clean Air Act Section 111a to mean any alteration to a facility that increases its hourly pollutant emission rate.
| EPA
The modification clause does not specify how a facility’s emissions should be measured to determine if a change would result in a pollution increase, which has led to multiple lawsuits since the clause was added in 1970. Under the NSR program, EPA has used a projection of annual emissions based on the modification.
“This type of annual emissions projection approach necessitates the consideration of complex factors such as projecting future demand of the product being produced and the selection of baseline emissions to use as a comparison point,” committee Republicans said in a memo ahead of a Environment Subcommittee hearing on the bill Wednesday. “Additionally, in certain instances, this type of emissions projection results in an overestimation of emissions, which is shown by comparing the projected emissions with a source’s true emissions after the fact.”
The bill would also exempt from NSR any modification that “reduces the amount of any air pollutant emitted by the source per unit of output or is designed to restore, maintain or improve the reliability or safety of the source.” Republicans said that NSR has impeded or canceled projects intended to reduce a facility’s pollution. The law already exempts routine maintenance or repair from review.
Support
At Wednesday’s hearing, Bill Wehrum, assistant administrator of EPA’s Office of Air and Radiation, told the subcommittee that the Trump administration does not have an official position on the bill. “Having said that, I strongly support the overall goals of the discussion draft,” he said. “The principal focus of the discussion draft on refining the definition of ‘modification’ in the Clean Air Act would go a long way towards simplifying application of the NSR program.”
Wehrum praised the bill’s exemption of pollution-reducing additions, noting that, “sometimes, the operation of such equipment, while it results in tremendous emissions reductions for some pollutants, may in some instances actually lead to increases in the emissions of other pollutants.” He said EPA had attempted to implement such a provision but was overruled by the D.C. Circuit Court of Appeals.
Kirk Johnson, senior vice president of government relations for the National Rural Electric Cooperative Association, said NSR has “more often served as an impediment, rather than an enhancement, to maintaining and improving efficiency at power plants.”
“One significant obstacle of the NSR permitting program is its application to equipment repair and replacement as well as even routine maintenance activities at existing generating units,” Johnson said. “Although routine maintenance, repair and replacement are supposedly excluded from being considered as ‘major modifications’ — and thus not subject to NSR — what qualifies as these NSR exemptions often changes with shifting EPA interpretations. This has led to utilities performing what they thought qualified as routine maintenance, repair and replacement, only to be cited for NSR violations years after the fact.”
Opposition
Paul D. Baldauf, assistant commissioner of the New Jersey Department of Environmental Protection, however, said Griffith’s bill could increase out-of-state emissions and extend the life of older generators, causing the state to fall out of attainment for the National Ambient Air Quality Standards (NAAQS). Baldauf cited as an example a generator that undergoes changes to increase its efficiency while also increasing the maximum heat input — the amount of fuel burned per hour — to increase electric output.
“This project would decrease the pounds of CO2 and some other pollutants emitted per megawatt-hour but would increase the megawatts generated,” he said. “Without additional controls, such a project would result in both increased hourly and annual emissions of all its pollutants, including CO2, criteria pollutants and air toxics, resulting from the increased fuel use. These increased emissions could likely result in adverse health impacts despite the increase in efficiency of the unit.”
Environmental consultant Bruce C. Buckheit, who served as director of EPA’s Air Enforcement Division during the Clinton and George W. Bush administrations, also opposed the bill. “The draft is not needed by the regulated community for any purpose and would not advance one of the fundamental purposes of the Clean Air Act — to eliminate, over time, the disparate treatment of new and existing sources,” he said. “It would severely impair the ability of the modification rules to effect this purpose and would exacerbate the current barrier to investment in new manufacturing and electric generating facilities created by the difference in the treatment of new and existing facilities.”
Democrats are likely to oppose the bill. “Without a firm requirement that facilities reduce the levels of all the dangerous pollution they emit, they simply will be allowed to pollute more,” Rep. Frank Pallone (D-N.J.), ranking member of the full committee, said in a statement. “That’s what the language in the bill on ‘maximum achievable hourly emission rate’ is all about.”
FERC’s Republican majority on Friday narrowed the circumstances under which it will estimate greenhouse gas emissions from natural gas pipeline projects, sparking dissents by its two Democratic commissioners.
The commission unanimously rejected a rehearing request by conservation organization Otsego 2000, which contended FERC had not conducted a sufficient environmental review in its 2016 approval of Dominion Energy Transmission’s New Market Project. The project includes two new compressor stations and upgrades to three others in upstate New York (CP14-497-001).
Wetland at existing Borger Compressor Station | Dominion Transmission
But Democrats Cheryl LaFleur and Richard Glick dissented from the commission’s declaration that it will no longer prepare upper-bound estimates of GHG emissions when “the upstream production and downstream use of natural gas are not cumulative or indirect impacts of the proposed pipeline project.” They instead contended the decision effectively eliminates any consideration of GHG emissions associated with a project.
Republicans Kevin McIntyre, Neil Chatterjee and Robert Powelson said they were taking the action to “avoid confusion as to the scope of our obligations under [the National Environmental Policy Act] and the factors that we find should be considered” when determining whether a project is in the public convenience and necessity under the Natural Gas Act.
NEPA requires FERC to prepare an environmental impact statement for pipelines that may significantly impact the environment but allows for a less detailed environmental assessment if it determines the project is not likely to have significant adverse effects.
Notice of Inquiry
In separate partial dissents, LaFleur and Glick said they were disappointed that the majority initiated the policy shift just a month after issuing a Notice of Inquiry to reconsider the commission’s 1999 policy statement on gas pipeline permitting (PL18-1). (See FERC Outlines Gas Pipeline Rule Review.)
LaFleur said the new policy reverses the commission’s practice since late 2016 of including more information on upstream and downstream GHG emissions in its pipeline orders. That included “upper-bound” estimates of downstream emissions that assumed all the gas transported by the project would be burned for electric generation, heating and other purposes.
“The commission placed caveats on the information and analysis, stating generally that the downstream impacts do not meet the definition of an indirect impact and are not mandated as part of the commission’s NEPA review,” LaFleur acknowledged. “The commission nonetheless made a full-burn calculation to determine an upper-bound GHG emissions amount, unless it had specific information to calculate net and gross GHG emissions.”
The commission used Department of Energy studies for generic estimates of the impact of projects on upstream natural gas production, including production-related GHG emissions.
LaFleur said the commission’s obligations increased under the D.C. Circuit Court of Appeals’ August 2017 Sabal Trail ruling, which found that the emissions resulting from burning the natural gas transported by a commission-approved project are an indirect impact. (See FERC Must Consider GHG Impact of Pipelines, DC Circuit Rules.)
“Today, however, the majority has changed the commission’s approach for environmental reviews to do the exact opposite. Rather than taking a broader look at upstream and downstream impacts, the majority has decided as a matter of policy to remove, in most instances, any consideration of upstream or downstream impacts associated with a proposed project,” LaFleur wrote. “The majority’s reasoning for excluding the information and calculations is generally that it is inherently speculative and does not meaningfully inform the commission’s project-specific review. I disagree.
“At a time when we are grappling with increasing concern regarding the climate impacts of pipeline infrastructure projects, the commission should not change its policy on upstream and downstream impacts to provide less information and be less responsive,” she added.
‘Remarkably Narrow’
Glick criticized the majority for what he called a “remarkably narrow view of its responsibilities under NEPA and the NGA’s public interest standard.”
“The principal reason that the commission does not have … ‘meaningful information’ [on GHG impacts] is that the commission does not ask for it,” Glick said, noting that FERC could require pipeline developers to provide information about the source of the gas to be transported and its end use.
“A simple data request would seem to fall easily within what constitutes the commission’s ‘best efforts,’” Glick said. “In the absence of any such efforts, the commission should not be able to rely on the lack of ‘meaningful information’ to satisfy its obligations under NEPA and the NGA to identify the reasonably foreseeable consequences of its actions.”
“There will undoubtedly be some cases where those emissions are, in fact, too speculative to be considered ‘reasonably foreseeable,’” he continued. “But there may also be others, such as Sabal Trail, where an adequate record would provide sufficient information to make those emissions reasonably foreseeable.”
Glick said he was not suggesting that the commission stop approving new pipeline projects. “What I am arguing is that, as a result of the commission’s new policy, we frequently will not know whether the benefits outweigh the costs because the commission is not asking enough questions or doing enough analysis.”
Dissents ‘Mischaracterize’ Shift
The majority said the dissents “mischaracterize” the policy shift as changing the commission’s public interest and environmental review.
“Our decision does not in any way indicate that the commission does not consider, or is not cognizant of, the potentially severe consequences of climate change,” the majority wrote. “We will continue to analyze upstream and downstream environmental effects when those effects are sufficiently causally connected to and are reasonably foreseeable effects of the proposed action.”
They also said the order does not “prejudge or preclude the [commission] from considering the questions on greenhouse gas emissions posed in the Notice of Inquiry.”
The Republicans said that even if the commission presumed a causal relationship between the New Market Project and upstream production, “the scope of the impacts from any such production is too speculative and thus not reasonably foreseeable.”
“Neither the commission nor the applicant generally has sufficient information to determine the origin of the gas that will be transported onto a pipeline. We disagree with the dissent’s assertion that we lack information about specific upstream production or downstream uses simply because we ‘did not ask for it.’ To be clear, the commission only has jurisdiction over the pipeline applicant, whose sole function is to transport gas from and to the contracted for delivery and receipt points. While the shippers might contract with a specific producer for their gas supply, the shipper would not know the source of the producer’s gas, and, for that matter, producers are not required to dedicate supplies to a particular shipper and thus likely will not know in advance the exact source of production. In short, ‘just ask[ing] for it’ would be an exercise in futility.”
FERC on Thursday rejected a second attempt by several Pacific Gas and Electric transmission customers to potentially receive a larger-than-normal refund related to a rate increase the utility submitted in 2016 for its 18th transmission owner tariff filing (TO18) (EL17-59).
But in a separate decision (EL17-95), the commission also ruled that a complaint by the same customers about PG&E’s TO19 rate filing be subject to hearing and settlement judge procedures and consolidated it with the ongoing proceeding covering the TO18 complaint (ER17-2154).
In EL17-59, the complainants — which include the Transmission Agency of Northern California; the city of Santa Clara; M-S-R Public Power Agency; State Water Contractors; the California Public Utilities Commission; Modesto Irrigation District; and Sacramento Municipal Utility District — had requested a rehearing of FERC’s November denial of their initial complaint over TO18.
While the TO18 rate increase is the subject of an ongoing proceeding on tariff revisions PG&E wants approved (ER16-2320), FERC shut down the complaint and an alternative request for consideration of supplemental evidence. It rebuffed the argument that its initial rejection failed to provide the complainants protection to receive the refund that they argued they could proved justifiable if the complaint was accepted.
FERC rejected a second attempt by transmission customers to potentially receive a larger-than-normal refund related to a California TO’s requested rate increase.
The complaint stemmed from PG&E’s request to increase its wholesale base transmission revenue requirement from $1.319 billion, as set in its previous rate case, to $1.705 billion, and boost its retail base transmission revenue requirement from $1.331 billion to $1.718 billion. The complainants had argued that they could show through discovery that PG&E actually required less revenue than it is already approved to collect, that FERC should allow for refunds below the current $1.319 billion revenue requirement and that their complaint should be consolidated with the rate increase proceeding.
FERC denied the complaint, saying the complainants failed to show that their proposed rate adjustments would result in a revenue requirement below $1.319 billion, leaving the standard refund protection intact. The complainants responded that not providing them the opportunity to prove their case through discovery in the proceeding “arbitrarily and capriciously deprived” them of protections in the Federal Power Act, but FERC said they must show evidence of the problem as part of the complaint, not ask the commission to trust them to prove it later.
FERC also rejected an alternative request, which asked the commission to consider evidence from PG&E’s ongoing tariff proceeding.
“The commission’s longstanding policy is to not accept additional evidence at the rehearing stage of a proceeding, absent a compelling showing of good cause,” it said. “Because other parties are precluded … from filing answers to requests for rehearing, allowing complainants to introduce new evidence at this stage would raise concerns of fairness and due process for other parties to the proceeding.”
TO19 Complaint
The commission accepted PG&E’s TO19 filing last September but suspended it for five months to become effective on March 1, 2018, subject to refund and the establishment of settlement judge procedures.
In EL17-95, the complainants alleged that PG&E failed to justify the proposed TO19 rate increase, which forecast a retail network transmission revenue requirement of $1.8 billion and a wholesale network transmission revenue requirement of $1.78 billion.
The complainants contended that PG&E overstated its proposed rates with inappropriate expenses, an excessive wholesale network transmission revenue requirement; a return on equity inconsistent with commission precedent; and an excessive composite depreciation rate. They claimed the utility failed to be transparent on expenses and made errors in its capital structure and cost of debt that require adjustment.
They also said that formal discovery should provide for additional adjustments to reduce PG&E’s rates below the last clean rate established in the TO17 settlement.
Complainants alleged that reducing PG&E’s proposed rates by $511.4 million, based on supporting materials, would bring the final rate below the last clean rate.
In addition, the amended complaint alleged the need to reduce PG&E’s federal corporate income tax rate from 35% to 21%, consistent with the recently enacted Tax Cuts and Jobs Act, which it said effectively made PG&E’s TO19 rate unjust and unreasonable.
PG&E countered that the complainants should not be allowed to attack the settled TO17 rate, that granting the complaint will make reaching a settlement in future rate cases more difficult and would be contrary to the policy behind the last clean rate doctrine.
Specifically, PG&E said that the last clean rate doctrine “prevents retroactive ratemaking and avoids penalizing a company for filing a rate increase,” which would happen if the commission granted the complaint.
PG&E also argued that complainants failed to carry their burden of proof under Section 206 of the FPA.
The commission’s May 17 order found “that the complaint raises issues of material fact that cannot be resolved based on the record before us.”
“We are unpersuaded by PG&E’s arguments that complainants have failed to meet their burden under Section 206 of the FPA, and find that complainants’ allegations, as amended, are sufficient to initiate an investigation into PG&E’s rates,” the commission said.
FERC emphasized “that we are not here making a finding on the merits of complainants’ arguments in their amended complaint; rather, we are simply finding that complainants have made a prima facie case warranting further investigation by providing sufficient support for their allegation.”
The commission said it was likewise unpersuaded by PG&E’s policy arguments.
“Specifically, we find that the complaint does not request that the commission reject the settled TO17 rates, nor does it seek to undo the results of any compromise reflected among the parties to the settlement,” it said.
The TO17 rates were in effect from March 1, 2016, through Feb. 28, 2017, when they were superseded by PG&E’s proposed TO18 rates, and therefore remain unaffected by this complaint for that period, the commission said.
“Here, complainants are using new data provided by PG&E in its TO19 rate case to allege that PG&E’s TO19 rates are overstated to such an extent that the final just and reasonable rates will be below those agreed to in the TO17 rate case,” the commission said. “The TO17 rates are thus relevant only to the extent that they establish the last clean rate and the floor below which additional refund protection is necessary.”
Based on its review of the record, the commission expects that the presiding judge should be able to render a decision within approximately 12 months of the commencement of hearing procedures, or May 17, 2019.
“Thus, we estimate that, absent settlement, we would be able to issue our decision within approximately 12 months of the filing of briefs on and opposing exceptions, or by July 17, 2020,” the commission said.
FERC took another step Thursday in its efforts to protect the grid from geomagnetic disturbance events (GMDs), proposing to approve a revised reliability standard but directing NERC to also require mitigation of vulnerabilities to localized events (RM18-8).
The commission’s Notice of Proposed Rulemaking would approve reliability standard TPL-007-2 (Transmission System Planned Performance During Geomagnetic Disturbances), which revises the definition of GMDs, requires grid operators to collect certain data and imposes deadlines for corrective actions, as the commission directed in Order 830 in 2016. (See FERC Approves GMD Reliability Standard.)
GMD storm in Fairbanks, Alaska, April 2011 | NASA
GMDs occur when the sun ejects charged particles that cause changes in the earth’s magnetic fields, potentially causing geomagnetically induced currents that can cause voltage instability or collapse and damage connected equipment.
The rule would require planning coordinators and transmission planners to conduct supplemental GMD vulnerability and thermal impact assessments that go beyond NERC’s original “benchmark” GMD event definition that is based on spatially averaged data.
NERC defined the “supplemental” GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform” with localized peaks that could affect reliability.
The supplemental GMD event is defined by a “reference peak geoelectric field amplitude” of 12 V/km versus the 8 V/km used in the original spatially averaged definition. Both are intended to reflect a one-in-100-year occurrence and use scaling factors to account for local geomagnetic latitudes and earth conductivity. They also employ a “locally enhanced reference geomagnetic field time series or waveform” to analyze the impact of the GMD on equipment.
Mitigation Directive
NERC’s standard requires mitigation of vulnerabilities to the benchmark event, setting a one-year deadline for the completion of corrective action plans and two- and four-year deadlines to complete mitigation actions involving non-hardware and hardware mitigation, respectively.
But NERC rebuffed FERC’s call for mitigation of risks from supplemental events. NERC’s proposed standard would only require applicable entities to make “an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s)” if a supplemental GMD event is assessed to result in cascading outages.
Potential GMD impacts on the transmission system | PJM
NERC told FERC that its standard drafting team determined that requiring corrective action plans in response to supplemental GMD event vulnerabilities was premature because the supplemental definition is based on small number of observed events “that provide only general insight into the geographic size of localized events during severe solar storms.” NERC also said current tools are inadequate to realistically model localized events.
But the commission said NERC’s position ignored its directives in 2013’s Order 779, which were reiterated in Order 830.
“NERC’s proposal to modify the benchmark, but then allow applicable entities the discretion to take corrective action based solely on the results of the spatially averaged benchmark analysis while taking under advisement (‘an evaluation of possible actions’) the results of the supplemental assessment, does not satisfy the clear intent of the commission’s directive. …
“We are not persuaded by NERC’s reasoning that … existing technical limitations, specifically the limited number of observations used to define the supplemental GMD event and the availability of modeling tools to assist entities in assessing vulnerabilities, make requiring mitigation premature at this time.”
Deadline Extensions
NERC also diverted from Order 830’s directive that it consider extensions of the corrective action deadlines on a case-by-case basis.
Instead, NERC would allow entities to unilaterally revise their corrective action plan if events beyond its control — such as delays from regulatory and stakeholder processes, equipment lead times or inability to acquire rights of way — prevent implementation within the original timetable.
“Given the complexities and potential novelty of steps applicable entities may take to mitigate the risks of GMDs, we agree with NERC that there should be a mechanism for allowing extensions of corrective action plan implementation deadlines,” FERC said. “However, we would like to avoid unnecessary delay in implementing protection against GMD threats.”
The NOPR seeks comment on whether the standard should permit these “self-declared extensions” or be revised to require NERC’s case-by-case approval. “Under either option, the commission proposes to direct NERC to submit a report regarding how often and why applicable entities are exceeding corrective action plan deadlines,” FERC said.
WASHINGTON — FERC will be closely monitoring ERCOT and Southern California for reliability issues this summer as most of the country faces the likelihood of above-normal temperatures, staff said at the commission’s open meeting Thursday.
Both regions lie in a portion of the Western U.S. expected to be warmer than usual, according to the National Oceanic and Atmospheric Administration. But each faces a unique challenge.
FERC’s summer reliability assessment report shows that ERCOT has a 10.92% reserve margin — compared to a 13.75% reference level — in the wake of about 4.5 GW in coal-fired generation retirements last winter and construction delays for about 2.1 GW in new resources. However, the grid operator has assured stakeholders there is no reason for alarm, noting that the current expected reserve margin is up from the 9.3% originally projected in December. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
“ERCOT expects to have sufficient operational tools to manage tight reserves and maintain system reliability,” FERC noted. “Those operational tools include deploying ERCOT-contracted load resources and emergency response services, using a previously mothballed unit expected to return to service in May 2018, requesting power across the existing DC ties, calling on generating resources that can switch between the Eastern Interconnection and ERCOT, and block-load transfers with SPP and MISO.”
Although FERC does not regulate ERCOT, Chairman Kevin McIntyre said the commission would be watching to see how the grid operator deals with any problems that arise.
Meanwhile, several disruptions to Southern California’s natural gas pipeline network mean CAISO will not be able to depend on natural gas generation to make up for a decrease in hydropower because of a lack of snowfall last winter. The state reached just 57% of normal snowpack, according to FERC, and the higher temperatures will reduce the level more quickly than normal.
Summer 2018 Outlook | NOAA
Operations at the Aliso Canyon gas storage facility outside Los Angeles are still limited. While the California Public Utilities Commission last week allowed Southern California Gas to temporarily increase injections, it denied a request to increase the facility’s allowable capacity. (See CPUC OKs Temporary Increase in Aliso Canyon Injections.)
In his comments on the report, FERC Commissioner Robert Powelson said, “I am deeply troubled by California policymakers’ refusal to support Aliso Canyon as a reliable storage facility to deal with critical backup storage, not only at the [local distribution company] level, but more towards merchant power resources in the market. … We’re getting away from economic dispatch, and we’re causing tremendous cost to consumers in the California marketplace.”
Further complicating California’s situation is the anticipated near-record-breaking demand for gas across the U.S. The Energy Information Administration expects gas burn to average 35.16 Bcfd in June-August, just 0.3 Bcfd less than the record set in 2016 and 3 Bcfd more than last year, FERC said.
“The addition of over 16,000 MW of new capacity to the natural-gas fired generator fleet since the record highs in 2016 and relatively low natural gas prices contribute to expectations for strong natural gas generation this summer,” the report said. As of March 23, Henry Hub summer futures prices were $2.76/MMBtu, down 52 cents (16%) compared to last year, according to Intercontinental Exchange.
McIntyre said that “on my personal to-do list is to drill further into” whether there’s anything more FERC can do to address California’s challenges with gas.
On May 9, CAISO warned that it this summer faces a 50% chance of a Stage 2 emergency, in which customers that have signed up for incentive rates would be required to use less power during peak demand times.
FERC based much of its report on NERC’s summer reliability assessment, which hadn’t been published as of press time.
FERC will review how it enforces the 1978 Public Utility Regulatory Policies Act, with the commission’s treatment of the 1-mile rule a likely focus, commissioners said Thursday.
Speaking at FERC’s open meeting, Chairman Kevin McIntyre announced FERC would “re-energize” the review it began in 2016 in response to pressure from state regulators and congressional Republicans.
Republicans now hold a 3-2 edge with the additions of McIntyre and Commissioners Neil Chatterjee and Robert Powelson.
McIntyre insisted he has “an open mind” on the need for change. He said the “format, scope and timing” of the review are to be determined and that “the process will allow for robust stakeholder input.”
Eager to Act
But Chatterjee and Powelson made clear they are eager to act.
Powelson called for an “expedited” review, noting the record the commission compiled in the technical conference and the post-conference comments on the 1-mile rule — the presumption that generators beyond 1 mile of each other are separate facilities.
In its request for comments following the technical conference, FERC asked for input on whether the 1-mile presumption should be made rebuttable and whether the burden of proof should fall on the interconnecting utility or the qualifying facility. It also asked whether it should set minimum contract length or other provisions in PURPA purchase contracts (AD16-16). Despite continued grumbling by Congress and state regulators, the commission made no rule changes following the inquiry.
FERC ruled in January 2016 that Entergy did not have to purchase power from Occidental Chemical’s Taft plant in Louisiana because the PURPA generator had unconstrained transmission access and could sell its output in the MISO wholesale market. | Occidental Chemical
“There are things we know full well — from the 1-mile rule to QF reform — that we can address rather quickly,” said Powelson, who noted his background as a former “impatient” Pennsylvania regulator.
“This is an issue that has been top of mind to me since coming to the commission,” Chatterjee said. “Today’s energy landscape is profoundly different from that of the late 70s when PURPA was enacted. And because of this, many have rightly voiced their desire for a fresh look at existing policy.”
Still Important for Developers
Democratic Commissioner Richard Glick said he was open to the review but insisted the law is still needed, despite the growth in renewable generation.
“PURPA has, and continues to play, an important role in promoting competition within the utility sector in ensuring the qualifying facilities have access to the market,” he said. “If we do decide changes to our regulations are in order, we must address the concerns raised not only by industry but also by qualifying facility developers — and there were quite a few concerns that were raised during that 2016 tech conference.”
Democrat Cheryl LaFleur, the only commissioner who remains from the beginning of the commission’s review, gave no indication of her leaning on the topic, saying only that the review is “very timely.”
2005 Amendments, Order 688
The commissioners noted that fundamental changes to the law would require congressional action.
Congress amended PURPA in the 2005 Energy Policy Act, allowing utilities to be relieved of PURPA’s mandatory purchase obligation upon FERC’s finding that QFs have nondiscriminatory access to transmission and energy and capacity markets.
In response, the commission amended its regulations in Order 688 in 2006. The order found that MISO, PJM, ISO-NE and NYISO provided markets that meet the law’s criteria for relief from the purchase obligation. It also established a rebuttable presumption that QFs above 20 MW have nondiscriminatory access to those markets.
In other regions, the commission established a rebuttable presumption that QFs of 20 MW and above have nondiscriminatory access to markets if they are eligible for service under a commission-approved open access transmission tariff.
To prevent gaming of the 20-MW threshold, the commission said it would look beyond the 1-mile rule. “If parties are concerned that a QF has engaged in such gaming with regard to the certification or siting of a particular facility, we encourage those parties to bring their concerns to our attention. In any such proceeding, we will consider all relevant factors, including, but not limited to, ownership, proximity of facilities and whether facilities share a point of interconnection,” the commission said.
Since then, the commission has repeatedly relieved utilities of must-purchase obligations from QFs above the 20-MW threshold.
Complaints Continue
But that did not end complaints over the law. In November 2015, Republican congressional leaders called on FERC to hold a technical conference to “identify any potential administrative or legislative reforms that may be necessary,” noting the falling prices of natural gas and renewable energy since the 2005 amendments. They cited congressional testimony from Berkshire Hathaway Energy complaining that it was required to sign a PURPA contract at rates that are 43% above market prices, costing customers an extra $1.1 billion over 10 years.
Travis Kavulla, vice chairman of the Montana Public Service Commission, told the technical conference that PURPA issues consume more than one-quarter of his commission’s time on electric utility regulation.
Democrats responded to FERC’s notice of the technical conference with a letter to the commission saying the act “remains a singular federal backstop to support renewable energy in parts of the country that may otherwise have significant barriers.”
In December 2017, the National Association of Regulatory Utility Commissioners called on the commission to “align” its interpretation of the act “with modern realities.” NARUC called for new criteria for determining whether a single project has been disaggregated to create multiple QFs under the 20-MW threshold. (See NARUC Calls for PURPA Reforms, Outlines Proposed Changes.)
CARMEL, Ind. — MISO’s proposal to redesign its cost allocation process for market efficiency projects (MEPs) has encountered conflicting stakeholder feedback on how to allocate costs for lower-voltage interregional projects, stakeholders learned Wednesday.
The RTO is proposing to eliminate its footprint-wide postage stamp rate and lower its current 345-kV cost allocation threshold to cover 230-kV MEPs. Staff have said the change would capture a reality in which 230-kV lines are prevalent in the RTO’s footprint, especially in MISO South.
The proposal would also make cost sharing available to projects 100 kV and above along the PJM seam, respecting a 2016 FERC order requiring MISO to lower its voltage threshold to 100 kV for interregional projects with its eastern neighbor. (See Stakeholders Debate MISO Cost Allocation Plan.)
MISO is currently exploring a new option for MISO-SPP small interregional project cost allocation and plans to finalize the cost allocation proposal at the June Regional Expansion Criteria and Benefits Working Group (RECBWG) meeting.
MISO said stakeholders are split over whether it should extend the 100-kV threshold mandated by FERC for MISO-PJM projects to interregional projects with SPP. MISO had originally proposed that both PJM and SPP interregional projects would both be cost shared down to 100 kV.
When the RTO revealed interregional cost allocation details in March, some stakeholders urged it to adopt a consistent 100-kV threshold for internal and interregional projects.
MISO Planning Coordinator Davey Lopez told the RECBWG that stakeholder differences over the issue has prompted the RTO to consider applying a local allocation to SPP interregional projects between 100 kV and 230 kV and a regional allocation to shared projects above those levels.
ITC Holdings’ Cynthia Crane asked why MISO is proposing two distinct interregional allocations based on RTO.
“Some said, ‘well, the seams are different.’ They don’t have to have the same allocation rule,” Lopez said during a May 16 RECBWG meeting.
Missouri Public Service Commission economist Adam McKinnie asked what is significantly different between the PJM and SPP seams.
“I’m not sure that we see something inherently different. We’re just laying out a different option based on stakeholder feedback,” Lopez said.
FERC’s order requires MISO to file an allocation plan for cost-shared interregional efficiency projects with PJM down to 100 kV by Oct. 31.
More Metrics
MISO also told the RECBWG that it is still exploring how to incorporate more benefit metrics into its MEP cost allocation.
The RTO currently uses a single metric, adjusted production cost savings, to determine transmission project cost responsibility among its cost allocation zones.
Director of Strategy Jesse Moser said MISO now seeks to include multiple metrics in the calculation, which will be summed and weighed against the RTO’s 1.25:1 benefit-to-cost ratio requirement to allocate costs on a proportional basis to allocation zones with net positive benefits.
MISO is currently considering using avoided transmission investments as a new potential benefit metric, after obtaining agreement about avoided projects through a stakeholder review. The RTO will finalize more detailed metrics sometime in August.
MISO is additionally considering a Tariff change that would create a new category of local economic transmission projects below 230 kV, Moser said. The small projects would have the same 1.25:1 benefit-to-cost ratio and benefit metrics as MEPs but cost allocated to the local zone. The new category would likely replace MISO’s current “Economic Other” transmission project category, which is not Tariff-defined and does not have a local cost allocation methodology.
WEC Energy Group’s Chris Plante expressed concern that the new project type could elicit FERC complaints if a lower-voltage project can demonstrate regional benefits but only has access to a local cost allocation.
Some stakeholders said MISO’s suggestion of the new project type provided further evidence for lowering the RTO’s regional MEP voltage threshold to 100 kV.
“This demonstrates that you’re willing to do the analysis on [sub-230-kV] projects,” LS Power’s Pat Hayes said.
Moser said MISO would have to review the project type for unintended consequences.
[Editor’s Note: An earlier version of this story incorrectly reported that MISO and the RECBWG intended to have a final draft of the MEP cost allocation proposal by May 16. The two plan to have a finalized cost allocation plan in June. ]
