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.”
FERC last week approved a settlement that will grant a NextEra Energy subsidiary congestion revenue rights (CRRs) that CAISO denied the company in 2015.
The agreement among the ISO, Southern California Edison and NextEra Desert Center Blythe allocates Desert Center CRRs created by its investment in a Southern California transmission project (EL15-47).
The Interim West of Devers (IWOD) project is meant to move renewable energy from eastern Riverside County to the Los Angeles area, and includes the removal and upgrade of 140 miles of existing 220-kV transmission lines.
CAISO, NextEra and Southern California Edison settled a case involving congestion revenue rights for the West of Devers transmission upgrade project in Southern California’s Riverside and San Bernardino counties. | CPUC
In denying Desert Center the CRRs in 2015, CAISO contended that its Tariff awards CRRs under only two circumstances: for facilities proposed and evaluated under the ISO’s transmission planning process; and for network upgrades identified in the generator interconnection process, when the generator funding the upgrades elects to receive the CRRs in lieu of a cash payment.
CAISO said the temporary upgrades for the IWOD — a project undertaken before construction of a permanent transmission solution — did not arise out of either circumstance.
FERC subsequently denied NextEra’s complaint and its request for a rehearing. In January 2016, NextEra filed a petition for review of the commission’s orders in the D.C. Circuit Court of Appeals, and in April 2017, the court remanded the matter to the commission.
Afterward, the parties engaged in settlement talks and came to an agreement, which FERC approved Oct. 4. The settlement stipulates that the CRR entitlements begin Jan. 1, 2019, and will remain in place as long as the IWOD project stays in service.
“For purposes of clarity, no merchant transmission CRRs will be awarded retroactively to Desert Center or SCE for the period of time that the IWOD project was in service prior to Jan. 1, 2019,” the settlement states.
MISO and PJM have whittled 20 prospective transmission projects down to two in their search for small interregional upgrades that relieve congestion on market flowgates.
If approved, the two targeted market efficiency projects (TMEPs) will be mostly paid for by MISO, which stands to reap the lion’s share of project benefits, stakeholders learned during an Oct. 5 conference call held by the RTOs’ Interregional Planning Stakeholder Advisory Committee (IPSAC).
MISO and PJM began the study process in spring, identifying 61 facilities that amassed about $500 million in congestion over 2016 and 2017. (See “Possible Interregional Projects,” FERC OKs MISO-PJM Double Charge Fix for Pseudo-ties.)
A TMEP must cost less than $20 million, completely cover its installed capital cost within four years of service and be in service by the third summer peak from its approval. The process has a shorter outlook than the RTOs’ interregional market efficiency project process, which evaluates projects over a 15-year timeline.
Alex Worcester, PJM interregional planning engineer, said the two projects that meet TMEP criteria will be recommended to the RTOs’ boards in December:
An upgrade on terminal equipment on the Marblehead 138/161-kV transformer in southeastern Michigan to increase its summer emergency rating. The facility has had $15.5 million in historical congestion. The RTOs said a $175,000 upgrade could yield $12.4 million in benefits within four years of service. MISO would pay for the entire project because it would reap all the project’s benefits, Worcester said.
A $4.3 million substation equipment upgrade to the Gibson-Petersburg 345-kV facility in southwestern Indiana. The tie has experienced $9.8 million in historical congestion over 2016 and 2017, and the project could provide a $19.5 million benefit within four years. MISO would cover 93% of the project cost, and PJM would cover the balance, pursuant to RTO benefits.
Worcester said the 18 remaining project candidates were disqualified from the TMEP process either because upgrades were already planned, upgrade costs were too high, the flowgate congestion was merely outage-driven or the issue was alleviated by the April retirement of We Energies’ Pleasant Prairie coal plant in southeastern Wisconsin.
MISO and PJM congested facilities on flowgates | IPSAC
MISO and PJM also said two northern Indiana flowgates that were being investigated for potential TMEPs — the Dumont-Stillwell 345-kV tie linking Northern Indiana Public Service Co. and American Electric Power territories, and NIPSCO’s Michigan City-Trail Creek 138-kV line — may be eligible in a future study to identify a larger interregional MEP project.
The New England Power Pool is trying to “have it both ways” in claiming FERC lacks jurisdiction to overturn the RTO’s press and public ban while holding special privileges as ISO-NE’s stakeholder body, RTO Insider said in filings Friday.
The publication’s filings followed NEPOOL’s Oct. 1 answer to protests that joined RTO Insider in calling for open stakeholder meetings. New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.
Many of NEPOOL’s meetings are held at the Westborough, Mass., DoubleTree Hotel. | Google
“While the opposition pleadings mostly repeat arguments previously made by RTO Insider, the opposition pleadings also seek to relitigate whether New England arrangements satisfy the commission’s Order No. 719 requirements,” NEPOOL said, referring to filings by New Hampshire Consumer Advocate D. Maurice Kreis, the Reporters Committee for Freedom of Press and a joint filing by the Sustainable FERC Project, Conservation Law Foundation, Earthjustice and Natural Resources Defense Council.
NEPOOL said preventing the public and press from attending and reporting on stakeholder meetings was necessary to ensure the meetings are “efficient and productive.”
“NEPOOL fully expects that if press reporters are present in NEPOOL meetings, interested members would continue to advocate their positions. But NEPOOL also expects that an increased amount of such advocacy would largely take place outside of NEPOOL meetings. The presence of press reporters in meetings, undeniably, would erode the confidence built among NEPOOL members over its almost five decades of successful history that specific statements made by others in NEPOOL meetings will not be published publicly.”
NEPOOL said its opponents are wrong in citing Order 719 as justification for opening its meetings. The commission said the order was intended to “establish a means for customers and other stakeholders to have a form of direct access to RTO/ISO boards of directors, and thereby increase the boards of directors’ responsiveness to those entities.”
“The ‘access’ referred to that of RTO/ISO customers and stakeholders to RTO/ISO boards. Press is neither a customer nor stakeholder, and they certainly are not a direct representative of either,” NEPOOL said. “Further, NEPOOL is not the RTO/ISO board. As such, any reliance on Order 719 is misplaced.”
On Aug. 13, NEPOOL asked FERC to approve amendments to its Agreement to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings (ER18-2208). The group drafted the revisions after RTO Insider reporter Michael Kuser applied for membership in NEPOOL’s Participants Committee as an End User customer in March.
Conditioning Authority
RTO Insider responded to NEPOOL’s filing with a Section 206 complaint Aug. 31 asking the commission to overturn the organization’s ban or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196).
RTO Insider said NEPOOL’s claims that it is not a public utility is “incompatible with having the NEPOOL Agreement on file with the commission, with NEPOOL making [Federal Power Act] Section 205 filings with the commission as a filing party, with NEPOOL having ‘jump ball’ Section 205 filing rights, and with commission orders involving NEPOOL governance,” RTO Insider attorney Steve Huntoon wrote. “NEPOOL’s attempt to avoid commission oversight while enjoying vast powers, privileges and subsidies is a classic case of trying to have it both ways.”
In making its jurisdictional argument, NEPOOL cited the D.C. Circuit Court of Appeals’ 2004 order rejecting FERC’s attempt to force CAISO to replace its governing board. Huntoon said NEPOOL ignored commission precedent in a 2016 ruling approving funding for PJM’s state consumer advocates (ER16-561-001). The commission in that order ruled that the “PJM stakeholder process is a practice that directly affects wholesale rates, and thus approval of a proposal that would enhance that process falls within the commission’s jurisdiction under Section 205a.” (See FERC Upholds PJM Advocates’ Funding.)
Even if the commission determines it lacks authority to force NEPOOL to change its rules, “the CAISO opinion was clear that the commission retains conditioning authority,” Huntoon said. “In CAISO, the court cited with approval a prior decision, Central Iowa Power Cooperative v. FERC, in which ‘FERC conditioned the approval of the power pool on removal of the membership criteria, rather than ordering the power pool to change those criteria directly.’”
Insiders and Outsiders
RTO Insider’s filing included letters submitted by six U.S. senators and 12 members of the House of Representatives calling on FERC to open the meetings. (See Wood, Brownell: Unaware of Press Ban When OK’d NEPOOL.)
Public Citizen filed comments Oct. 3 challenging NEPOOL’s claim that its members “voted overwhelmingly against having press reporters as NEPOOL members” at the June 26 Participants Committee meeting. Only 115 of NEPOOL’s more than 500 members were present or had proxies at the meeting.
While 32 votes were cast in favor of the press ban, 24 members were opposed and 59 abstained. In addition, NEPOOL records show that six officers or their associates represented companies that provided 21 of the 32 votes for the ban.
The six have conflicts of interest in voting for the ban because they earn income selling “intelligence” about NEPOOL proceedings, said Tyson Slocum, director of Public Citizen’s Energy Program.
“When deliberative bodies are transparent and open to the public, information resources regarding details of their proceedings are inexpensive, reflecting the ease with which the information can be obtained and disseminated,” Slocum wrote. “But restricting participation, and making access to deliberations more exclusive, bestows ‘financial market opportunities’ for those granted special access. Those participants on the ‘inside’ can sell their services to those on the ‘outside.’”
The Sustainable FERC Project, Natural Resources Defense Council and Conservation Law Foundation filed a joint motion also opposing NEPOOL’s motion to dismiss RTO Insider’s complaint.
“An RTO/ISO’s formal engagement with stakeholders is … squarely within the commission’s jurisdiction, and the commission should intervene when an opaque stakeholder process that completely excludes the press decreases stakeholder input, decreases public understanding and transparency, and creates a needless risk to the legitimacy of important RTO/ISO decisions,” they said.
