Lessons from the Jan. 17 MISO South emergency resulted in smoother management of the Sept. 15 emergency in the region, RTO officials told stakeholders last week. MISO this week pledged more training and more vendor outreach during another post-mortem of last month’s emergency.
MISO had better awareness of its contract limit on SPP transmission linking its Midwest and South regions during the emergency, Senior Real Time Operations Engineer Steve Swan told the Reliability Subcommittee meeting Oct. 5.
“Overall, performance that day between MISO and our joint parties was a lot better than the January maximum generation event,” Swan said, adding that the RTO communicated often with SPP about flows to South, which exceeded the 3,000-MW north-to-south sub-regional contract limit on the SPP line for about 15 minutes.
MISO is pledging to do more in time for the next emergency, including conducting drills on emergency purchases with external entities and continuing to work with SPP on managing the North-South contract path.
MISO analyst Dustin Grethen said the Sept. 15 emergency could probably have been helped by a reserve capacity product. The RTO hopes to complete a conceptual design of a short-term capacity reserve project by the end of the year or early 2019. It is developing a capacity product with a 30-minute ramp response time furnished by units that are both online and offline.
In September, MISO Executive Director of Market Development Jeff Bladen said that he expected the product to become “a very valuable part of MISO’s portfolio.” He said the 30-minute time span will be useful for system flexibility because wind forecasts become “very, very accurate” 30 minutes out.
Weather Forecasts
Swan said a missed weather forecast led to a 1.8-GW load forecast error in MISO South on Sept. 15. The RTO ultimately had to commit 1.1 GW above the day-ahead commitment for South after a 1.4-GW generator in the region unexpectedly tripped off late on Sept. 14.
“This is one of the worst days we’ve had for our load forecast error historically. It seemed to be a one-off,” Swan said.
The RTO was in “constant contact” with its two weather forecast vendors throughout the day of the emergency, Swan said. The vendors continued to stand by their afternoon forecasts hours before the emergency. However, hotter-than-expected weather materialized quickly, and an expected cloud cover never appeared.
After stakeholder questioning, Swan said MISO had “no reason to believe” that missed forecasts would become more common.
Some stakeholders argued that local meteorologists saw the extreme heat, asking MISO to include local forecasts in their weather predictions. We Energies’ Tony Jankowski asked the RTO to consider hiring an in-house meteorologist. However, RTO staff maintained that even local weather forecasters underestimated the heat that day. Staff said aggregate load forecasts from local balancing authorities were actually lower than MISO’s load forecast for the day.
Michigan Public Service Commission staffer Bonnie Janssen asked if MISO could work with the forecasting vendors more closely. She said it’s not uncommon for surrounding regions to experience unusual weather patterns as hurricanes make landfall. Hurricane Florence had arrived at North Carolina a day earlier on Sept. 14.
Swan said the RTO is continuing to work with the vendors on communication protocols.
2 LMRs Disqualified
Meanwhile, MISO disclosed that it had disqualified two load-modifying resources (LMRs) from providing capacity for the remainder of the 2017/18 planning year because of nonperformance during the mid-January emergency.
MISO analyst Scott Thompson said the LMRs had not updated their availability through the entire month of January or throughout the 2017 summer. They also did not respond to MISO’s scheduling instructions during the January event, nor did they participate in earlier LMR drills, he said.
“They weren’t making the effort to show up. They thought the capacity payment was good enough, but they didn’t hold up their end of the equation,” Thompson said.
At an Oct. 4 Reliability Subcommittee meeting, Chris Miller, FERC’s liaison to MISO, reminded stakeholders that the commission’s action is simply an inquiry, not enforcement. Miller said MISO and other RTOs seemed to better handle communication during high temperatures this summer and severe weather from Florence.
FERC last week denied a rehearing request by SPP transmission owners of its earlier decision on the allocation of transmission costs, saying the TOs had not shown the RTO’s provisions had become unjust and unreasonable (EL18-20).
The commission’s Oct. 3 order affirmed its March decision, which rejected the TOs’ complaint that SPP unfairly allocates costs to incumbent TOs when a new owner is integrated into an existing transmission pricing zone.
The companies had argued that a “loophole” in SPP’s Tariff forces customers within an existing zone to pay a share of the legacy costs for transmission lines newly integrated into the zone. That practice, the complainants said, runs counter to the “no legacy cost shift” protections SPP has established. (See FERC Rejects TO Complaint on SPP Zonal Placements.)
SPP transmission zones | SPP
In the March ruling, the commission said the TOs failed to carry the burden of proof to support their request for a prohibition on cost shifts. In last week’s order, FERC said the TOs also failed to prove that SPP’s Tariff is unjust and unreasonable because it lacks provisions dictating what information RTO must include in filings to add a new TO to an SPP zone to justify cost shifts.
“As the commission noted in the March 15 order, SPP will need to make an [Federal Power Act] Section 205 filing to add the ATRR [annual transmission revenue requirement] of a new transmission owner to an existing zone’s ATRR,” the commission said. “The fact that SPP’s Tariff does not expressly require this filing to justify any potential cost shifts does not change the commission’s obligation to determine that the revised ATRR is just and reasonable. … SPP, and any other proponents of the revised ATRR, still has the burden of proof to demonstrate that the rate is just and reasonable and must ensure that there is a sufficient evidentiary record for the commission to make a reasoned decision. Likewise, the fact that SPP’s Tariff does not specify that SPP must justify any potential cost shifts in its filing with the commission does not prevent parties from arguing that the allocation of the costs of a new transmission owner’s facilities to existing customers in the zone in which SPP proposes to place those facilities renders the revised ATRR unjust and unreasonable under the circumstances of the case.”
The commission noted that it considered information regarding cost shifts in its May 17 ruling on SPP’s placement of Tri-State Generation and Transmission Association in existing transmission pricing Zone 17 (ER16-204). (See FERC Rejects NPPD Objection to Tri-State Zonal Placement.)
The order “provides further assurance that the case-by-case approach to assessing the implications of cost shifts espoused in the March 15 order will not result, as indicated SPP transmission owners fear, in rate impacts being excluded from the commission’s consideration or in protesters bearing an unreasonable burden of proof,” FERC said.
The commission also reiterated its conclusion that the TOs failed to prove that cost shifts create a disincentive to RTO membership. “Indicated SPP transmission owners caution that transmission owners may be reticent to join SPP due to the potential that their customers’ rates may one day increase if other transmission owners join and are placed in the same zone. However, as the commission noted in the March 15 order, not all cost shifts will benefit the new transmission owner, and some could even benefit the existing transmission owner and its customers.”
The filing TOs were American Electric Power, on behalf of Public Service Company of Oklahoma and Southwestern Electric Power Co.; City Utilities of Springfield (Mo.); Kansas City Power & Light; KCP&L Greater Missouri Operations Co.; Nebraska Public Power District; Oklahoma Gas & Electric; Omaha Public Power District; Southwestern Public Service; Sunflower Electric Power; Mid-Kansas Electric; Westar Energy; and Western Farmers Electric Cooperative.
Climate change could have catastrophic effects sooner than previously thought and preventing them will require cooperation on an unprecedented global scale, according to a new report by the U.N.’s Intergovernmental Panel on Climate Change.
The study, released on Sunday from Incheon, South Korea, examined the effects of a 1.5-degree Celsius (2.7-degree Fahrenheit) increase in the global average temperature from 1850-1900 levels. If the current rate of global warming continues, the average temperature would hit 1.5 C by 2040, according to the report.
Observed global temperature change and modeled responses to stylized anthropogenic emission and forcing pathways | IPCC
“It’s like a deafening, piercing smoke alarm going off in the kitchen. We have to put out the fire,” The Washington Postquoted Erik Solheim, executive director of the U.N. Environment Program. He said the world must either stop carbon emissions entirely by 2050 or find some way to remove them. “Net zero must be the new global mantra.”
The report estimates that temperatures have increased by about 1 C (1.8 F) so far, and that the impacts of that increase are already being felt in increased storm intensity, precipitation, wildfires and heat waves; rising sea levels from melting polar ice; and the nearing extinction of several species, including coral. Such impacts could disrupt the global food supply chain and cause mass migration and increased poverty, the report says.
“Extra warming on top of the ~1 degree C we have seen so far would amplify the risks and associated impacts, with implications for the world and its inhabitants,” the IPCC said in a FAQ. “This would be the case even if the total warming is held at 1.5 degrees C, just half a degree above where we are now, and would be further amplified at 2 degrees C global warming.”
The report is a result of a provision in the 2015 Paris Agreement, which saw 195 countries, including the U.S., agree to reduce their carbon dioxide emissions by 26% from 2005 levels by 2025 to prevent a 2-degree Celsius (3.6-degree Fahrenheit) increase. It was added at the request of small island nations in the tropics, which wanted the effects of a 1.5-degree increase to be studied, as they are more susceptible to rising sea levels.
To prevent a 1.5-degree increase, global CO2 emissions would need to be reduced by 45% from 2010 levels by 2030 and 100% by 2050, according to the report. This is still possible, the authors say, but it would require a massive undertaking by the entire world.
“The speed and scale of transitions and of technological change required to limit warming to 1.5 degrees C has been observed in the past within specific sectors and technologies,” the report says. “But the geographical and economic scales at which the required rates of change in the energy, land, urban, infrastructure and industrial systems would need to take place are larger and have no documented historic precedent.”
For the electricity industry, this means dramatically reducing the use of coal and increasing the use of renewable resources for generation. This is true under every scenario, or “pathway,” studied by the report’s authors.
Coal’s share of the resource mix would need to drop to 1 to 7% by 2050, compared to 40% now, and only if large-scale carbon capture and sequestration technology is developed by then. Natural gas-fired generation would also have to be reduced by as much as 60% (though it could increase with the use of CCS), and renewables’ share would need to increase to as much as two-thirds.
The report is less sure about nuclear power. Under some scenarios global nuclear capacity increases, while it decreases in others. The report attributes this to the high cost of building nuclear plants and political opposition stemming from perceived safety risks. While some countries may elect to rely on nuclear for emission-free power, it may not be feasible for developing countries, the researchers said.
President Trump in June 2017 announced he intended to withdraw the U.S. from the Paris Agreement. The earliest the country can do so is Nov. 4, 2020. (See Trump Pulling U.S. Out of Paris Climate Accord.)
The New England Power Pool Participants Committee last week approved new penalties for ISO-NE market participants that fail to cover their capacity supply obligations (CSOs) when a new resource is delayed.
For delivery years before June 1, 2022, the monthly $/kW-month charge will be the higher of the capacity clearing price and the clearing price in any Annual Reconfiguration Auction for that year. After June 1, 2022, the charge will be based on the outcome of a second run of the third ARA, using the unproven CSO quantities as a demand bid.
The rule changes are designed to shift the responsibility for covering CSOs to participants, which ISO-NE says have the best information about projects’ development schedule and potential delays.
Market participants will still be compensated for their CSOs and continue to have Pay-for-Performance risk.
The RTO said it was acting because of the time lag between its last critical path schedule (CPS) meetings with participants in early January and the beginning of the capacity commitment period in June.
Current rules require ISO-NE to assess a new resource’s likelihood of meeting its CSO and submitting a demand bid if it is in doubt. The new rules will eliminate mandatory demand bids by the RTO for resources unable to satisfy all CPS milestones by the start of the delivery year.
The monthly charge would apply unless the participant covers the shortfall through a bilateral contract or with a resource that was previously counted as a capacity resource. Previous resources can be used for up to two years.
The changes were approved by voice vote after members rejected a proposal by PSEG Energy Resources & Trade to allow a three-month grace period before applying the charge for each year between June 2019 and May 2022. PSEG’s proposal failed with a 47.77% vote in favor (Generation Sector – 14.68%; Transmission Sector – 6.71%; Supplier Sector – 15.48; AR Sector – 5.23%; Publicly Owned Sector – 0%; End User Sector – 5.59%; and Provisional Group Member – 0.067%).
For delivery years beginning in June 2022, the monthly charge rate for resources unable to meet their capacity supply obligations will be based on clearing prices in the third Annual Reconfiguration Auction (ARA #3). A resource that submits and clears a demand bid in ARA3 will pay P1 (ARA3 clearing price). A resource that maintains their CSO and has unproven CSO quantities will pay the P2 rate, which will always be greater than or equal to P1. | ISO-NE
The approval completed Phase I of ISO-NE’s two-phase review of rules governing late projects in the FCM. Phase II will take a broader look at the participation of new resources in the market, the RTO said.
As of June 30, ISO-NE said it had identified 26 resources representing almost 30 MW of “unproven” capacity, including almost 28 MW of demand capacity and 2.1 MW of generating capacity. Last month, ISO-NE asked FERC to terminate the CSO of Invenergy’s 485-MW Clear River Energy Center Unit 1 in Rhode Island because it will not be operating in time for the delivery year beginning June 1, 2019 (ER18-2457). (See ISO-NE Asks FERC to End Clear River CSO.)
ICR Values for FCA 13
In a related matter, the Participants Committee also approved by a show of hands a net installed capacity requirement of 33,770 MW for Forward Capacity Auction 13 next year (delivery years 2022-2023). In a separate vote, the committee also approved a 33,750 MW net ICR that will be used if FERC approves the termination of Clear River Unit 1’s CSO.
Net ICRs exclude the Hydro-Quebec interconnection capability credit (HQICC), which members agreed to set at 969 MW. Including the HQICC, ISO-NE projects a reserve margin of 19.3%.
The committee also approved Tariff changes on assumptions used in the ICR calculation. One revision will reduce from 1.5% to 1.0% the amount of load relief assumed from a 5% voltage reduction. A second revision changes the assumption used for the availability of peaking resources in the transmission security analysis from a deterministic derate factor to an equivalent forced outage rate-demand for individual resources, based on their most recent five-year average.
2019 Budgets
In other action, the committee also endorsed the 2019 ISO-NE operating ($198 million) and capital ($28 million) budgets. The operating budget is up $2.9 million (1.5%) from 2018 but down $1.4 million from the preliminary budget presented in August. Including true-ups, the revenue requirement for the operating budget will drop 3.5% from the amount projected to be collected in 2018.
The capital budget is unchanged from 2018.
The committee also endorsed the New England States Committee on Electricity’s 2019 operating budget of $2.35 million, a $45,000 reduction from the five-year pro forma projections endorsed by the committee in June 2017 and accepted by FERC.
Energy Emergency Forecasting
Members unanimously approved changes to Operating Procedure 21 and its Appendix A to create an energy emergency forecasting and reporting process. It includes forecast alert thresholds, criteria for declaring energy alerts and energy emergencies and related data collection provisions.
ISO-NE said the changes are intended to improve market signals for incentivizing resource preparedness before winter 2018/19.
The energy alert thresholds will be based on an assessment of fuel and emissions availability over the next 21 days of operation.
Conforming changes to ISO-NE manuals on price responsive demand, Pay-for-Performance, real-time reserve designation and settlement rules and the Forward Capacity Market; and
Revisions to provisions regarding deposits for participating in cluster transmission studies.
Chadalavada said higher-than-forecasted temperatures and dew points, particularly in the afternoon of Sept. 3, caused the RTO’s load served to peak at 22,956 MW (23,174 MW including active DR), almost 2,400 MW (11.5%) above its load forecast.
Underforecasts of temperatures and dew points resulted in an underforecast of load for ISO-NE on Labor Day, Sept. 3. | ISO-NE
During the 4-5 p.m. hour, the RTO fell 718 MW below the 24,775 net capability required, which includes operating reserves of 2,108 MW.
The RTO purchased 150 MW from New Brunswick between 4:20 and 5:14 p.m. and 229 MW between 5:14 and 6. NYISO provided 251 MW from 5 to 5:30 and 150 MW from 5:30 to 6.
Real-time hub five-minute LMPs ranged from $19.79 to $2,677.05/MWh for the day, with an average of $262.61.
The real-time net commitment-period compensation was the fifth highest for the year and the highest of the summer at $1.9 million, including $1.1 million in economic payments, $540,000 in dispatch lost opportunity costs and $210,000 in rapid-response pricing opportunity costs.
The high prices during the event will increase the peak energy rent adjustment by $7 million each month, for a total of $56 million, through May 31, 2019, RTO officials said.
The PER adjustment is intended as a hedge for load and a tool to discourage capacity suppliers from creating price spikes through economic or physical withholding.
The increased adjustment will affect generators, imports and active demand resources. Self-supply and passive demand resources are excluded.
ISO-NE is eliminating the PER adjustment beginning June 1. The RTO says Pay-for-Performance and changes to the day-ahead energy market made the adjustment unnecessary beyond that date. (See FERC Rejects NESCOE Request on Scarcity Rules.)
MISO last week said its grid can currently sustain 20% renewable penetration without damaging frequency response, the latest findings from its ongoing renewable integration impact study.
The RTO in spring published study results showing that increased renewable integration — especially solar generation — will shift peak load to evening hours, with a spikier but shorter daily loss-of-load risk. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)
MISO later daily peak under renewable integration | MISO
The same study now concludes that MISO can more than double its current 8% renewable share of the resource mix while still maintaining a satisfactory frequency performance. Frequency response decreases slightly but is steady up to a 20% renewable mix, with the system remaining stable after the simultaneous loss of large generators up to 4,500 MW, Jordan Bakke, MISO policy studies manager, said during an Oct. 5 Reliability Subcommittee meeting.
Some stakeholders said the study doesn’t contemplate that future storage resources could help improve frequency response.
“I think it’s important to point out that this study doesn’t include storage, and I think storage could really help the system,” said Dave Johnston, an Indiana Utility Regulatory Commission staffer.
Bakke said the study was conducted with the assumption that frequency response services will continue to go uncompensated.
“To the point we’ve gotten so far, storage hasn’t been needed to solve an identified [frequency response] issue,” Bakke said.
Early this year, FERC declined to order the RTO to compensate providers of primary frequency response, as Indianapolis Power and Light had requested. (See FERC OKs MISO Plan to Expand Storage.)
Coalition of Midwest Transmission Customers attorney Jim Dauphinais pointed out that FERC’s Order 842 requires new generators to be capable of providing primary frequency response as a condition of interconnection.
Bakke said MISO’s study did assume new generators “could provide it, but they won’t because there’s no incentive to provide.”
MISO will continue to work on its renewable integration study through early next year. Bakke said the RTO will likely convene a stakeholder workshop on study results so far in November.
Eric Gimon | Energy Innovation Policy & Technology
It’s easy to love electricity markets. Mathematical algorithms efficiently, safely and transparently dispatch grid resources to match supply and demand. Market signals drive the most valuable grid additions and retirements over time, providing customer savings and a stable investment environment incorporating technology and input cost changes.
PJM has led power market development, embracing rising trends like demand response and grid-scale battery storage. But lately, PJM has doubled down on a “solution” leading down an ever-more complicated and fractious path: its Reliability Pricing Model capacity market.
Electricity power markets are not perfect; critics often cite the “missing money” problem, which contends — with only marginal justification — that price signals balance markets but do not sustain adequate system resources to guarantee supply matches demand. To address this, PJM created a singular “capacity” commodity traded in the RPM, which loads must purchase.
While the RPM has been a boon for some resources, a singular definition of capacity never fairly captures everything the grid needs, and the RPM is open to three criticisms:
First, it tends to overpay some resources without offering premiums to ones that provide more grid services than just megawatts. Imagine forcing a museum to purchase insurance on its art collection with a flat rate on a Rembrandt or a painting from a local artist.
Second, with the RPM, PJM is eschewing part of its system optimizer role by requiring individual or self-assembled coalitions of resources to provide capacity products instead of assembling a diverse set of resources to meet reliability needs.
Third, a conservative organization like PJM naturally tends to forecast higher demand, just in case, effectively forcing customers to buy too much insurance.
Predictably, the RPM has cannibalized energy market revenues in favor of capacity markets and allowed uneconomic legacy coal and nuclear assets to create a large capacity overhang (>30% reserve margin in summer 2018 against a desired ~16%).
Eric Gimon | Energy Innovation Policy & Technology
Today’s power markets are also flawed by not pricing externalities. Seeing nuclear generators, which have provided free emissions mitigation, on the verge of going under, states like Illinois decided to provide direct financial support. These “out-of-market subsidies” (terminology that ignores other existing direct and indirect subsidies) became PJM’s new bugbear, which contends state-sponsored resources drive prices “too low.”
Last June, PJM wanted to double down on capacity markets by re-engineering them to force some resources to overbid at minimum offer prices to “mitigate” impacts of state policies, making customers double-pay for capacity instead of allowing markets to re-equilibrate by closing uneconomic resources.
Because of push back from FERC, which wants to allow matched resources and load to opt out of the RPM, PJM is doubling down again, striving to protect existing resources at all costs by proposing a two-stage capacity market called the extended Resource Carve-Out (RCO).
Extended RCO forces certain resources to offer into the capacity market at a higher price than their direct costs if they want to participate, or “allows” those resources to opt out of RPM by offering into the auction at a zero price. After this first stage of the two-stage capacity market, PJM determines which resources clear. In the second stage of the two-stage capacity market, PJM would then carve-out the opt-out resources and rerun the auction with the same demand curve to determine a higher clearing price to be paid to all non-carve-out resources that cleared in the first stage.
This would cause serious — and unnecessary — additional consumer expense.
Furthermore, extended RCO has yet another component: a payment to resources that would have cleared the second auction but not the first (the one that identified the actually needed capacity resources). This proposal extravagantly pays these so-called inframarginal resources even though they neither incur a capacity obligation nor provide capacity to PJM customers.
PJM committed the original sin of getting into capacity markets (Band-Aid solutions FERC historically expected to wither away). Over time, these capacity markets cannibalized energy markets, required constant “fixing,” and became the last refuge of increasingly uneconomic legacy assets.
When low natural gas prices and states interested in shaping their resource mixes started to fray this safety line, PJM took a protectionist line and started treating states like monopsonist market manipulators. Then, when FERC — unfortunately sympathetic to these protectionist views — tried to offer a fig leaf to states with opt-out, PJM doubled down on its twisted economic logic to make even that unworkable and expensive.
What should PJM do instead? At the very least, it should allow loads and grid resources to sort out capacity needs bilaterally and unfettered if the RPM seems unfair.
But when you’re in a hole, stop digging! Instead of doubling down on unworkable capacity constructs, PJM should double down on real markets and seek a new paradigm, working with states, that gets it out of the capacity business altogether.
Eric Gimon is a senior fellow with Energy Innovation Policy & Technology, which “works with national and regional decision makers to develop policies that will manage the grid’s transition to a cleaner, lower-carbon resource mix.” Eric holds a B.S. and M.S. from Stanford University in mathematics and physics, and a Ph.D. in physics from UC Santa Barbara.
On Capacity Pricing Reform: PJM is Doubling Down on the Wrong Solution
By Eric Gimon
It’s easy to love electricity markets. Mathematical algorithms efficiently, safely and transparently dispatch grid resources to match supply and demand. Market signals drive the most valuable grid additions and retirements over time, providing customer savings and a stable investment environment incorporating technology and input cost changes.
PJM has led power market development, embracing rising trends like demand response and grid-scale battery storage. But lately, PJM has doubled down on a “solution” leading down an ever-more complicated and fractious path: its Reliability Pricing Model capacity market.
Electricity power markets are not perfect; critics often cite the “missing money” problem, which contends — with only marginal justification — that price signals balance markets but do not sustain adequate system resources to guarantee supply matches demand. To address this, PJM created a singular “capacity” commodity traded in the RPM, which loads must purchase.
While the RPM has been a boon for some resources, a singular definition of capacity never fairly captures everything the grid needs, and the RPM is open to three criticisms:
Predictably, the RPM has cannibalized energy market revenues in favor of capacity markets and allowed uneconomic legacy coal and nuclear assets to create a large capacity overhang (>30% reserve margin in summer 2018 against a desired ~16%).
Today’s power markets are also flawed by not pricing externalities. Seeing nuclear generators, which have provided free emissions mitigation, on the verge of going under, states like Illinois decided to provide direct financial support. These “out-of-market subsidies” (terminology that ignores other existing direct and indirect subsidies) became PJM’s new bugbear, which contends state-sponsored resource drive prices “too low.”
Last June, PJM wanted to double down on capacity markets by re-engineering them to force some resources to overbid at minimum offer prices to “mitigate” impacts of state policies, making customers double-pay for capacity instead of allowing markets to re-equilibrate by closing uneconomic resources.
Because of push back from FERC, which wants to allow matched resources and load to opt out of the RPM, PJM is doubling down again, striving to protect existing resources at all costs by proposing a two-stage capacity market called the extended Resource Carve-Out (RCO).
Extended RCO forces certain resources to offer into the capacity market at a higher price than their direct costs if they want to participate, or “allows” those resources to opt out of RPM by offering into the auction at a zero price. After this first stage of the two-stage capacity market, PJM determines which resources clear. In the second stage of the two-stage capacity market, PJM would then carve-out the opt-out resources and rerun the auction with the same demand curve to determine a higher clearing price to be paid to all non-carve-out resources that cleared in the first stage.
This would cause serious — and unnecessary — additional consumer expense.
Furthermore, extended RCO has yet another component: a payment to resources that would have cleared the second auction but not the first (the one that identified the actually needed capacity resources). This proposal extravagantly pays these so-called inframarginal resources even though they neither incur a capacity obligation nor provide capacity to PJM customers.
PJM committed the original sin of getting into capacity markets (Band-Aid solutions FERC historically expected to wither away). Over time, these capacity markets cannibalized energy markets, required constant “fixing,” and became the last refuge of increasingly uneconomic legacy assets.
When low natural gas prices and states interested in shaping their resource mixes started to fray this safety line, PJM took a protectionist line and started treating states like monopsonist market manipulators. Then, when FERC — unfortunately sympathetic to these protectionist views — tried to offer a fig leaf to states with opt-out, PJM doubled down on its twisted economic logic to make even that unworkable and expensive.
What should PJM do instead? At the very least, it should allow loads and grid resources to sort out capacity needs bilaterally and unfettered if the RPM seems unfair.
But when you’re in a hole, stop digging! Instead of doubling down on unworkable capacity constructs, PJM should double down on real markets and seek a new paradigm, working with states, that gets it out of the capacity business altogether.
Eric Gimon is a senior fellow with Energy Innovation Policy & Technology, which “works with national and regional decision makers to develop policies that will manage the grid’s transition to a cleaner, lower-carbon resource mix.” Eric holds a B.S. and M.S. from Stanford University in mathematics and physics, and a Ph.D. in physics from UC Santa Barbara.
AUSTIN, Texas — The Gulf Coast Power Association’s 33rd Annual Fall Conference & Exhibition attracted more than 640 registered attendees for three days of workshops and discussions on the issues facing the ERCOT market. DeAnn Walker, chair of Texas’ Public Utility Commission, delivered the keynote address, while panels examined the evolution of the wholesale and retail markets, grid resilience, cyber and physical security, renewable generation sources and ERCOT’s fuel mix.
While October marks the beginning of ERCOT’s fall season, many minds were still on the grid operator’s performance during the summer of 2018, Texas’ fifth-hottest on record. The lead-off panel credited ERCOT’s preparedness and engagement with the market, the availability of wind and traditional generating units during peak-demand periods, and the lack of extended extreme heat with overcoming the retirement of more than 4 GW of coal-fired generation in 2017.
ERCOT survived the summer heat without making conservation calls or issuing alerts, despite recording 14 system demand peaks above the previous record set in 2016. All 14 peaks came during the summer’s lone period of extreme heat (July 18-23). (See ERCOT: Market Performed ‘as Expected’ During Summer Heat.)
The grid operator went into the summer with a planning reserve margin of 11%, below its target of 13.75%. Generator outages were half of what staff projected, doubling operating reserves to more than 2 GW, despite a peak demand 552 MW above forecast.
“This summer was a good example, or illustration, of how our expectations are related to ERCOT forecasts,” said former PUC staffer Julia Harvey, now director of regulatory affairs for Texas Electric Cooperatives.
Resmi Surendran, Shell Energy North America’s senior director of regulatory policy, pointed to renewable energy’s capacity contributions, which met peak demand of over 5 GW.
“We were extremely lucky, especially because of the wind generation,” she said. “All the major events happened for only one week; the generators operated throughout July. … If we had had extreme weather in August, I don’t know how that would have affected us.”
Luminant Energy Vice President of Origination and Pricing Claudia Morrow reminded the audience that the company’s Comanche Peak Nuclear Power Plant was offline for several months in the summer of 2017.
“Nobody is more pleased and happy than Luminant that our units were all online and performed as expected,” she said. “That just illustrates everything went really well, as best as could be expected.”
Panel moderator Beth Garza, director of ERCOT’s Independent Market Monitor, said average real-time prices were up 25% over 2017 at $36.2/MWh, but reliability unit commitments were a rarity. “That’s a credit to ERCOT and ERCOT operators,” she said. “It would be easy on some days, to say, ‘Wow, I’m really nervous. It would be great to get more capacity.’”
“Fortunately, we didn’t have to use all those [processes] we practice for,” ERCOT COO Cheryl Mele said.
A second panel, focused on a market design that is supposed to incent generation investments, discussed the grid operator’s ability to manage slim reserve margins and the effect on future decisions.
“This [summer] gave one more reason for the forward market to not price scarcity,” said Orion Energy CEO Nazar Massouh. “We had scarcity, but no forward reaction.”
“The summer of 2018 was not performing in a manner consistent with what people thought from coiling the spring a little tighter” through retirements, Merrill Lynch Commodities Managing Director Mark Egan said. “As prices fall on the spot market and forward market, it does serve to effectively push us down the curve. Some fossil asset investment decisions get deferred.”
Walker Expects 2019 Summer to be ‘More Difficult’
Walker agreed with the lead-off panel, saying everything worked out as well as it could have.
But that said, “Next summer will be more difficult,” she predicted, pointing to the state’s increasing demand and potential retirements and mothballing of aging plants. “What does that mean for 2019? We already know we need to make changes.”
Walker said the PUC and ERCOT are already planning for next summer, rather than starting in early March. The commission has scheduled an Oct. 25 workshop to review the summer’s events and determine improvements for next year. ERCOT hopes to see all plant maintenance completed by May 15.
“I encourage you to offer suggestions on what we could do better,” Walker said, noting final input is due Oct. 18 (Project 48551).
Walker expects ERCOT’s reserve margin to remain tight in the short term. She discovered this year that planning to have units in neighboring regions help the grid operator “in a crunch” is “more difficult than I thought,” so she is working on reliability coordinator agreements to resolve the situation.
“It’s not my intent to have MISO or SPP give those units’ control to ERCOT. My intent is to be more orderly than that,” she said. “We have issues to work through. I would like these processes to be in place by next summer, but it’s going to take some Protocol changes.”
Is There a Place for Distribution Assets in ERCOT?
During a panel discussion on “non-wire alternatives,” AEP Texas President Judith Talavera and NRG Energy Director of Regulatory Affairs Bill Barnes debated AEP’s proposal to install a pair of utility-scale lithium-ion batteries to solve distribution reliability needs in its West Texas service territory.
AEP’s plan to classify the facilities as distribution assets and include them in cost-of-service rates sparked broad opposition within the market. The PUC rejected the proposal in January, but it opened a rulemaking to address “non-traditional technologies in electric delivery service” (Project 48023). (See PUC Opens Rulemaking on Distributed Battery Storage.)
Talavera said the numbers — $2.3 million in costs for the battery facilities, as compared to $11.3 million to $22.5 million for “traditional” wires solutions — “demonstrated a battery was a much more cost-effective solution” in dealing with outages and other reliability concerns in the tiny towns of Woodson (estimated population in 2016: 246) and Paint Rock (287).
“We strongly believe [energy storage] has to be a tool. It’s no different than a transformer or any other distribution asset,” she said. “We view this as a distribution asset we will be adding to our system, and the rules don’t require a [certificate of convenience or necessity] for a distribution asset you’re adding or building.
“When the laws were written, we didn’t have these types of technologies,” Talavera said. “At the end of the day, we have a responsibility to serve everybody on our system.”
“Where we differ is how we see those non-wires alternatives come to be,” Barnes said. He said units that provide ancillary services such as batteries are generating assets. Ancillary services are defined in the ERCOT Protocols as any service needed to serve the transmission of load, he noted.
Barnes proposed extending transmission-level prices to the distribution system, “so you have distribution prices and distribution nodes.”
“That would create incentives for suppliers to locate batteries on the grid where you have reliability problems,” he said. “We create economic signals; we allow private investment to come into the market to solve those problems. For products that might not be priced, like voltage and stability, you create markets for them that ERCOT facilitates, like the existing ancillary services markets.”
“Judith owns the storage,” said panel moderator Bob King, president of Good Company Associates. “It’s not clear [who pays if] she can charge or discharge, but it’s clear she can’t participate in the wholesale market.”
“And we’re not trying to,” Talavera responded.
“The ultimate issue is the cost … is still funded through the rate base,” Barnes said. “If you’re awarded the [project], you’re happy. If you’re everyone else, you’re not. The cost is funded through noncompetitive revenue, and you still have distortion in the market. If customers want that reliability, they can pay for it.”
“Given the declining cost of batteries and the growing maturity of technology over the last few years, we identified two great options to help us provide reliable service,” Talavera said. “We didn’t get the approval, but I do think it helped open the conversation we’re having today. I feel energy storage can provide real, quantifiable benefits for the customer and our distribution system.”
Kenneth Medlock primed the pump for a panel discussion of ERCOT’s retail market by sharing the results of a residential pricing study that covered a 14-year span following the onset of customer choice in January 2002.
Medlock, senior director of the Center for Energy Studies at Rice University’s Baker Institute, stressed that sample averages don’t “tell the whole story,” but that price dynamics matter. He said prices fell in the state’s competitive areas but rose in the noncompetitive areas (Austin, San Antonio and other municipalities and cooperatives). Residential rates in competitive areas were 2 cents less than those in noncompetitive areas in 2002, but those rates were on par with each other by 2016.
“If you’re in a system with limited choice because you have one retail provider, then you don’t understand what individual consumer groups prefer,” Medlock said. “If you want to enhance the competitive paradigm, it’s important that you remain transparent and open. That’s the only way consumers can access enough information and data to make decisions in their best interest. Players in the market are forced to differentiate themselves in different ways, which introduces an entrepreneurial paradigm that can lower prices.”
Chris Brewster, a principal with law firm Lloyd Gosselink Rochelle & Townsend, said the retail market’s strength is rooted in the wholesale market.
“That’s what ERCOT, the stakeholders and the PUC want. It works smoothly,” he said. “We have a wholesale market that is very liquid and easy to transact in. It doesn’t impose a lot of administrative requirements. We have a true market. We have a wholesale market that transacts in a commodity, and a retail market that specializes in a customized service for customers.”
Connie Corona, the PUC’s director of competitive markets, said “the consistent small changes made to the market have been critical.”
“There’s a balance in this market between certainty [about how things operate] and the ability of the policymakers, the stakeholders and market participants [to adjust] the Protocols,” she said. “As a market, we’ve taken the opportunity to recognize how this and that could work better. Everyone has been open to examining that, from the Legislature on down to the subcommittee of the working group at ERCOT.”
Shell Energy North America’s Greg Thurnher, moderating a discussion of ERCOT’s fuel mix, recalled a not-so-distant past when the grid operator had 8 GW of wind, a 15% reserve margin, no major retirements, gas in the $10 to $13/MMBtu range, and construction of new nuclear and coal generation was expected.
Ten years later, ERCOT has 1 GW of solar, 21 GW of wind and another 13 GW planned, while coal capacity has dropped by more than 4 GW, noted Thurnher, Shell’s manager of real-time trading.
“Rather than say the resource mix is changing, it has changed, and the change is here to stay,” Thurnher said.
Clif Lange, manager of wholesale marketing for South Texas Electric Cooperative (STEC), said his business is investing in quick-start gas units, rather than renewables — or rather, because of renewables.
“The ability to be there quickly and, frankly, the ability to shut down quickly has provided a lot of value to STEC and ERCOT,” Lange said. “How do you make a thermal generator effective in a market where you have seen depressed pricing for so long? The ability to react quickly to market signals has provided a great benefit. We can respond very quickly to transmission constraints that pop up very quickly or disappear very quickly. When you’re not in the money, it’s very important to be able to take that unit offline.”
McCall Johnson, senior manager of government affairs for solar developer Recurrent Energy, said utility-scale solar will be essential to the future because of its ability to provide predictable power during the afternoon peak.
“Those [solar] megawatts are not causing a lot of operational issues,” she said. “We see that peak power, which is really cost-effective, driving a lot of interest. Solar … seems a more sophisticated purchase of renewables. You get a peak hedge. We all know when the sun is going to shine, and it’s easy to predict.”
Maura Yates, managing member of the Mothership Energy Group, which calls itself “a boutique group of female-owned energy solutions companies,” reminded the panel and audience to not forget about rooftop solar, “a silent asset happening behind the meter.”
“We have a lot of data in the market, important data driving the generation stack. But you don’t have an idea of how many behind-the-meter rooftop solar systems there are,” Yates said. “It’s a blind spot. It’s really important to get a hold of that data, because it’s driving the wholesale side now. Consumers want to be more involved and engaged. They’re an asset class themselves.”
Opinions Vary on Grid Resilience
Several transmission operators opened their panel discussion by recounting the Department of Energy’s proposal to prop up coal and nuclear generation and FERC’s definition of resilience: “The ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event” (RM18-1).
“It does align itself to the Baskin-Robbins 31 flavors of resiliency,” CenterPoint Energy Associate General Counsel Patrick Peters said of FERC’s definition. “[Resilience] started with solid fuels and nuclear but has now evolved into other topics. The definition covers just the normal day-to-day work of operating the electric grid. When I think of resiliency, I think of out-of-the-box planning to ensure the grid stays reliable if you lose a piece of equipment.”
“One of the things I love about working in this industry is we’re not afraid to take on hard projects, and this is one,” said Southern Co.’s Katherine Prewitt, vice president of transmission. “We need to ensure we don’t have a one-size-fits-all approach. We can’t lose sight of our customers’ needs. We have to talk to them, understand what they need and help them understand the impact of what they’re asking for. There’s always a cost for the ask. We have to ensure we don’t over-engineer it and put ourselves in a position where we have unintended consequences.”
“Our view is the markets work best,” said John Gunn, vice president of regulatory affairs for ExxonMobil’s gas and power marketing unit. “The power industry does have to comply with a whole lot of regulations. We’ve seen that in reliability improvements and [its] ability to respond in natural disaster.”
CARMEL, Ind. — MISO leadership has not yet decided on how it can improve resource availability, though it is evaluating several possible remedies, the RTO told stakeholders last week.
MISO Executive Director of Market Development Jeff Bladen told an Oct. 4 Reliability Subcommittee that the RTO will return in November with a narrowed list of short-term solutions for review with stakeholders. MISO said it will work with its Steering Committee to assign longer-term recommendations to the RTO’s larger stakeholder groups for further development.
The RTO published a white paper last month focusing on four areas: improving its outage planning; studying characteristics of different resources to see how it can best incentivize them to perform; re-examining resource accreditation in the Planning Resource Auction; and reassessing what availability should be required of resources — especially load-modifying resources (LMRs). (See MISO Moving to Combat Shifting Resource Availability.)
Outage Control
Lately, MISO has been deliberating with stakeholders over whether it should ask FERC for more authority over outage scheduling to better manage reserves. (See Advisory Committee Divided on MISO Outage Authority.) Stakeholders generally agreed last month that MISO should keep the status quo while it works on process improvements.
Some stakeholders said MISO’s challenges may resolve themselves as large transmission buildout from its 2011 multi-value project portfolio begins to come online.
“So maybe it’s a bit of a wait-and-see as the processes we’ve been working on for years begin to bear some fruit,” Bladen said.
“There’s a cyclical nature to this discussion,” Minnesota Public Utilities Commission staff member Hwikwon Ham commented. He said he remembered similar discussions on reserve shortages in the industry around 2005 and 2006.
“This is not a new problem; we can handle it,” Ham said.
Bladen said MISO could require a minimum notice time for market participants taking planned outages. If owners cannot meet the requirement, their outages may be counted as forced outages in their resource’s capacity accreditation. In the long term, MISO said it might consider establishing an outage rights market like the financial transmission rights market that already exists.
MISO reports that about 70% of planned outages during peak months are scheduled with less than a week of notice, based on a three-year average.
“This is surprisingly high,” Bladen said. “There are several planned outages taken very, very close to the operating time frame. Maybe we should put a finer point on what the NERC standard for planning ‘well in advance’ in the MISO context will be.”
Bladen also said MISO could improve the specificity of data it provides to market participants on its nonpublic Maintenance Margin tool, which supplies market participants with projected capacity availability margins to assist them in selecting outage dates.
But MISO’s Independent Market Monitor criticized the Maintenance Margin as clunky, saying market participants are scheduling outages with vague information. Monitor David Patton said the Maintenance Margin information is “high-level and does not convey coincidental transmission outages or generator-specific details that may otherwise impact participants’ planning decisions.”
Historical, not Optimized
Bladen said MISO may begin using historical outage data to inform its planning reserve margin. Such a change could cause an increase to the planning reserve margin, he said.
“We currently anticipate in our planning reserve margin that outages are optimally coordinated. … We may need to plan for outages that are less optimally coordinated,” Bladen said.
Seasonal Auction
However, Patton said a four-season capacity auction with distinct seasonal availabilities assigned to resources would be “far simpler” than adjusting MISO’s existing outage planning.
“The megawatts that are available are the megawatts that matter, no matter why they’re available,” Patton said. “Our [seasonal] deratings are as big as our outages, and many of those go unreported.”
Patton said a four-season capacity auction is “one of the only” possible solutions MISO could explore to better align resource availability with energy needs. The RTO’s current capacity construct socializes the costs of outages and derates by raising capacity procurements, he said.
LMRs
For MISO’s LMRs, stakeholders and the Monitor suggested implementing lead time thresholds.
Bladen said stakeholders suggested MISO reduce capacity accreditation for long-lead resources and incentivize shorter lead time LMRs. Some said MISO should implement a cutoff on response time for a unit to be considered an LMR.
“We have a gamut of lead times in MISO; some are very long leads, some are medium leads and some are short response time. And we don’t think about those as different capacity values,” Bladen said.
MISO should only allow full capacity accreditation to emergency-only resources that can be ready for dispatch within one to two hours and are available beyond the summer season, Patton said. Currently, MISO’s LMRs do not have an obligation to respond to emergencies outside of the summer months.
Current MISO emergency process | MISO
“Do we have access to the planning resources we procured when we need them … and if not, why don’t we?” Patton asked stakeholders.
Planning studies of LMRs “don’t look anything like” the real-time response of LMRs during emergencies, Patton said. He also said some emergency-only resources’ long lead times render them “essentially unavailable in an emergency” because operators typically don’t see shortages more than a few hours in advance.
“I don’t have anything against LMRs … but if they don’t meet the needs of the system when we procure them in the capacity auction, then we shouldn’t pretend that they do,” Patton said.
Some stakeholders pointed out that MISO can call on LMRs only after it declares emergency conditions. Customized Energy Solutions’ Ted Kuhn said the RTO should consider sending notification to LMRs when emergency conditions are likely but haven’t yet emerged.
“You should be able to notify them that they might be needed, and earlier in the process,” Kuhn said.
MISO’s white paper suggests reordering the steps in its emergency declaration process as a potential solution.
Century Aluminum’s Brian Helms said MISO’s participant communication system should include more information to allow LMRs to decide when to reduce load for either economic reasons or as “the last stop before load shedding.” He also said MISO’s communication system is difficult for owners to navigate.
“Whoever created that, you didn’t get your money’s worth,” Helms said.
“You don’t know what we spent on it,” Bladen responded jokingly.
Reliability Subcommittee Vice Chair Ray McCausland reminded MISO that LMRs were once called “interruptibles.”
“And boy, they complained when you used them,” he said, warning that frequent deployment of LMRs will discourage loads from volunteering to provide the service.
Bladen agreed that MISO’s frequency of LMR use is a delicate balance. He encouraged stakeholders to send in more written suggestions on outage planning, LMR rules and a seasonal capacity auction.
He also stressed that any upcoming recommendations would be technology-agnostic in nature.
“Any technology that can provide solutions will have a shot,” he said.
In the run-up to the Kavanaugh denouement, our industry was not spared claims of disaster from confirmation.
In our case, the claim was that Judge Brett Kavanaugh had it in for independent regulatory agencies like FERC, and the implication was that he might somehow persuade four other justices to override many decades of Supreme Court precedent upholding the constitutionality of such agencies.
Now, whatever else the merits or lack thereof of Kavanaugh as a Supreme Court justice (and no, I’m not going there, so please put the ricin away),[1] this particular claim is basically wrong.
Brett Kavanaugh | D.C. Circuit Court of Appeals
The claim is grounded in Kavanaugh’s opinion in PHH Corp. v. Consumer Financial Protection Bureau, in which a mortgage lender challenged the delegation of executive branch powers to an agency headed by a single person — instead of to a multi-member agency.
Some press promoted the notion that this opinion is an existential threat to all independent regulatory agencies. Utility Dive,[2] for example, quotes Joel Eisen, an energy law professor at the University of Richmond, as saying: “In that opinion, he called into question the entire concept of the modern independent regulatory agency, and of course FERC is one such agency.” Now, of course, Eisen is entitled to his opinion, but the referenced Kavanaugh opinion, read in its entirety, does not support that sweeping interpretation.
In fact, quite the opposite. The opinion repeatedly stressed the difference between multi-member agencies and those headed by a single person:
“In other words, to help preserve individual liberty under Article II, the heads of executive agencies are accountable to and checked by the president, and the heads of independent agencies, although not accountable to or checked by the president, are at least accountable to and checked by their fellow commissioners or board members. No head of either an executive agency or an independent agency operates unilaterally without any check on his or her authority. Therefore, no independent agency exercising substantial executive authority has ever been headed by a single person.
“Until now. …
“Because the CFPB is an independent agency headed by a single director and not by a multi-member commission, the director of the CFPB possesses more unilateral authority — that is, authority to take action on one’s own, subject to no check — than any single commissioner or board member in any other independent agency in the U.S. government. Indeed, as we will explain, the director enjoys more unilateral authority than any other officer in any of the three branches of the U.S. government, other than the president.”
FERC got an honorable mention as a multi-member agency Kavanaugh did not have a problem with:
“Have there been any independent agencies headed by a single person? Prior to oral argument, in an effort to be comprehensive, the court issued an order asking the CFPB for all historical or current examples it could find of independent agencies headed by a single person removable only for cause. The CFPB found only three examples … the three examples are different in kind from the CFPB and other independent agencies such as the FCC, the SEC and FERC” (emphasis added).
Kavanaugh emphasized this distinction, again mentioning FERC, on the second day of his confirmation hearing in response to questions from Sen. Amy Klobuchar (D-Minn.), saying in that opinion “all I was talking about was a single-headed independent agency,” and distinguishing that agency from the “SEC, FTC, FERC, NLRB, the Fed” that “are all multi-member agencies.”[3]
Over the decades Congress has assigned Executive Branch powers to dozens of independent regulatory agencies.[4] In our ever increasingly complex society we are ever increasingly reliant on these agencies to perform countless governmental functions.
The notion that we could or would ever return to a time when Congress passed highly prescriptive legislation on everything so the Executive Branch would just perform ministerial administration is a joke.
Judge, now Justice, Kavanaugh knows that, and so does every other justice on the Supreme Court.
So FERC, and all of us who rely on and respect you, sleep soundly. The keg is half full.
For anyone who does not know where the keg reference comes from, please see one of the funniest SNL sketches with Matt Damon as Kavanaugh here, https://www.youtube.com/watch?v=VRJecfRxbr8. Again, I’m not taking a position on his confirmation, but hysterical is hysterical. ↑
From the opinion: Interstate Commerce Commission (1887), Federal Reserve Board (1913), Federal Trade Commission (1914), U.S. International Trade Commission (1916), Federal Deposit Insurance Corporation (1933), Federal Communications Commission (1934), National Mediation Board (1934), Securities and Exchange Commission (1934), National Labor Relations Board (1935), Federal Maritime Commission (1961), National Transportation Safety Board (1967), National Credit Union Administration (1970), Occupational Safety and Health Review Commission (1970), Postal Regulatory Commission (1970), Consumer Product Safety Commission (1972), Nuclear Regulatory Commission (1974), Federal Energy Regulatory Commission (1977) [somehow ignoring the creation of predecessor Federal Power Commission in 1920 – ouch!], Federal Mine Safety and Health Review Commission (1977), Federal Labor Relations Authority (1978), Merit Systems Protection Board (1978), Defense Nuclear Facilities Safety Board (1988), National Indian Gaming Commission (1988), Chemical Safety and Hazard Investigation Board (1990), Surface Transportation Board (1995), and Independent Payment Advisory Board (2010). ↑
