Bruce Rew, SPP’s senior vice president of operations, predicted a year ago that there was “a good chance” the RTO would reach the 70% barrier for renewable energy penetration.
Rew’s prognostication skills are not in doubt. The RTO tweeted last week that it met 73.67% of its demand Wednesday with wind, hydro and other non-fossil resources.
| SPP
The mark came at 2:14 a.m. CT, when SPP’s load was 22.5 GW. Renewable resources suppled 16.5 GW of that power, with wind supplying 65.4% and hydro 8.3%. The grid operator also set a record for wind generation on Sept. 30, when it produced 17,109 MW at 12:30 a.m. That broke the previous mark of 16,972 MW, set Sept. 11.
ERCOT, which has 22,313 MW of installed wind capacity, holds the RTO high for wind generation, set in January at 19,672 MW.
An important fall pastime, along with baseball playoffs, is to look back to see which electric market design model performed best over the summer. For the last several summers, a lot of eyes have been on the ERCOT market, given its relatively low reserve margins and lack of a mandatory forward capacity market. The results are in. There was no firm load shed because of supply shortages, and ERCOT’s 2019 Summer Operational and Market Review stated, “Overall, the market outcomes supported the reliability needs.” My colleagues and I at Grid Strategies ran the revenue adequacy numbers and found that prices did what they should, providing appropriately strong signals to attract new market entry while charging customers only for what they needed.
The key distinction between ERCOT and regions with a capacity market or resource adequacy requirement is that in ERCOT, responsibility for assessing the level of supply and demand need for investment lies with market participants, not the grid operator itself. Other regions are charging customers more than 20% of the total cost of energy, capacity and ancillary services through capacity markets. In contrast, ERCOT focuses on grid operations more like an air traffic controller, saving consumers that money. It uses spot energy and reserves prices to accurately value energy over time and at each location, and lets market participants handle their own price risk management and supply assurance through bilateral contracts. Spot energy values at times of scarcity are allowed to reach $9000/MWh — reflective of true consumer valuation of supply at that time and place — and the value of reserves, which is based on a downward sloping operating reserve demand curve. By keeping dollars in spot markets as opposed to a capacity market, this market design attracts flexibility from demand response, storage, hydro and any other source that delivers when it is needed. There are no drawn out subjective debates with RTO management and stakeholders about what resources should count how much toward the elusive concept of “capacity,” and what public policies should be mitigated, as is the case in the Northeast. (See our paper showing how the minimum offer price rule costs PJM consumers $5.7 billion extra per year.)
One would expect that when the system is low on capacity — as it was this summer with around an 8% reserve margin — prices would occasionally be very high and on average equal or exceed the amount that efficient new units need annually to recover their capital investment cost. In economic theory terms, in an efficient market at equilibrium, over the course of the year there would be enough “rent,” or profit earned from prices that exceed generators’ operating costs, that new generators see enough profit incentive to enter. So the question is, were prices over the last year high enough to attract and retain needed units? Our analysis below indicates the answer is YES.
Let’s take a look at the prices in 2019 so far (see our blog for data, assumptions and methodologies). The figure below uses ERCOT historical real-time ORDC data generated during each security-constrained economic dispatch interval to display the number of hours that prices have exceeded generators’ operating cost from January through September.
ERCOT price duration curve analysis (January to September) | ERCOT
As shown above, prices have been consistently higher this year than in previous years. So far, prices have already exceeded $200/MWh for 95 hours, with four hours and 10 minutes reaching the systemwide offer cap price. This September alone, with the most record-high temperature days since 2011, was responsible for 10 minutes worth of prices at the offer cap and 20 hours worth of prices above $200/MWh. For reference, 2018 saw 54 hours over $200/MWh and only 10 minutes at the offer cap. Since the creation of the ORDC in June 2014, ERCOT only saw prices hit the offer cap one other time in 2016 for five minutes.
So prices have been higher, but were they high enough to attract entry? To answer that question, we can look at net margin for different units. In Grid Strategies’ analysis of year-to-date data, efficient new peakers earned 35% above what they need to earn in an average year to pay for the capital cost of building the units, and combined cycle units earned 25% above that target. In most prior years when reserve margins were higher, they earned less than this target level.
Peaker net margin analysis | Potomac Economics
These high spot prices signal to retail electric providers to go out and sign more contracts with generators so they can shield themselves from high spot market prices in the future. Those long-term power purchase agreements are then used by prospective generators to finance their new plants. An influx of 4,000 MW of solar and 5,000 MW of wind plants expected by next summer will likely take care of much of this need. Market participants also have clear responsibility and incentives to seek sources that shield them from high prices when wind and solar output is low. The Public Utility Commission of Texas reviews those entities’ creditworthiness to make sure they are financially equipped to serve the load they commit to serve — an important and often forgotten regulatory responsibility of state commissions. Few customers actually had to pay the high spot prices, as they were covered by contracts signed well in advance, and the prices withstood the mild political opposition without regulatory intervention.
This year may have been the best test to date of the ERCOT market design. The results so far indicate that despite the hot summer and low reserve margin, no firm load was shed because of supply shortages, while the system did provide sufficient price signals to attract and retain needed resources. High spot prices did not attract political intervention, and consumers only paid for what they needed. ERCOT’s 2019 experience should answer a lot of questions about whether ERCOT’s unique market design works. One thing is for sure though: Our October pastime of reviewing the past summer’s power market results will come again as surely as the sun rises or the baseball playoffs begin.
Rob Gramlich is founder and president of Grid Strategies LLC, a clean energy grid consulting firm.
The latest salvo was Rocky Mountain Institute’s claim that the bulk of new natural gas generation is/will be uneconomic. As I said before, perhaps the advocates hope that if gas investment is scared off, then renewables and batteries become a fait accompli.
The first major flaw was that 40 to 50% of RMI’s “clean energy portfolio” (CEP) comes from demand response and energy efficiency. It assumed large amounts of those resources are available at low cost.
And, importantly, it assumed that these hypothetical low-cost resources were only available to its renewables/battery CEP portfolio and not to a gas portfolio. As a result, the economics that RMI attributed to its renewables/battery portfolio actually came from mixing in low-cost DR and EE that are not unique to that portfolio.
The second major flaw was that in its modeling, RMI used traditional fossil generation to recharge the batteries. Yes, ironically, traditional fossil generation was supplying a “clean energy portfolio.” And, most dramatically, in a last hour of covering peak load, the equivalent of a 1.5-GW gas generator was matched by: zero wind and a negligible amount of solar; batteries charged with traditional fossil generation; and huge amounts of DR and EE, neither of which are unique to a renewables/battery scenario. In other words, renewables contributed virtually nothing to matching the 1.5-GW gas generator.
RMI says investors are “taking notice,” pointing out that final investment decisions for new gas plants have declined since 2014. But at this level, they are the same as they were in 2010. Trend or cycle? And RMI is not correct that the capacity factor of combined cycle gas plants is declining; in fact, the article cited by RMI has a chart clearly showing the opposite.[efn_note]https://www.spglobal.com/marketintelligence/en/news-insights/trending/Pu5fAcJoqopojxYhGN0tMw2.[/efn_note]
Just as Energy Information Administration data show that the capacity factor of combined cycle gas plants is at a record[efn_note]EIA Electric Power Monthly, Table 6.7.A, for August 2019 and August 2014, available here, https://www.eia.gov/electricity/monthly/epm_table_grapher.php?t=epmt_6_07_a.[/efn_note] high:
Natural gas combined cycle average annual capacity factors | based on EIA data
Even if RMI were right about such things as capacity factors, none of it is really reflective of investor sentiment. The real indicators are things like the share price of NRG Energy — the best proxy for competitive fossil generation (about half of which is gas) — which is up from $11/share to $40/share in the last three years. And RMI’s own statement that there is “more than $100 billion in planned gas infrastructure investment through 2025.”
If gas is a bad investment, Wall Street didn’t get the memo. RMI may suggest its study is the memo, so that takes us back to the study itself.
RMI’s Reply on Assuming and Co-opting the Low-cost Resources
RMI’s aggressive assumption on lots of available DR and EE cannot be sustained by referring, as RMI does, to “definitive resource potential assessments” (my emphasis). Potential is just that.
But more important, RMI admits that it assumed the availability of (low-cost) DR and EE for its renewables/battery portfolio and not for its gas portfolio. It now says that’s OK because its study showed that DR and EE are “natural complements to zero-marginal-cost generation from wind and solar.”
I can’t find anything in the study that remotely supports that proposition. I can’t even find the words “complement” or “zero” in a word search. Please note that RMI saying in its study that it optimized resources in its modeling should not be confused with a showing that certain resources complement each other better than others.
Bottom line: The RMI study’s co-option of low-cost DR and EE resources for its CEP portfolio is a fundamental, unsupported flaw.
Low-cost Resources Threat to Gas?
RMI says that the implication of my critique is that inexpensive DR and EE are themselves a threat to gas investment. A clever thought. But too clever by half. It’s RMI, not me, that assumes vast availability of low-cost DR and EE.
And if DR and EE are a threat to gas, then they must be a bigger threat to more-expensive renewables. Is RMI warning Wall Street about renewable investment? No, I didn’t think so.
The CEP Dependency on Fossil Generation
RMI does not deny that in the last hours of peak conditions, fossil units are providing needed generation via batteries, and renewables are providing virtually nothing. RMI says that just reflects the leveraging of available fossil generation for the foreseeable future.
Fair enough I guess. So long as everyone understands that RMI’s modeling is not of a sustainable equilibrium condition. Instead, it depends on fossil generation sticking around so when solar and wind aren’t generating, the system can still serve load reliably. And as I’ve pointed out, if new gas generation is scared off, then the old fossil with much higher carbon emissions will be what carries the CEP portfolio.
Finally, RMI goes on to overplay its hand by claiming that nothing undermines its central finding “that CEPs can compete and win on gas plants’ own turf.” No. In its modeling, RMI’s CEP portfolio is undeniably dependent on fossil generation. RMI admits that. The converse is not true: A fossil fleet is dispatchable and is not dependent on renewables/batteries, as decades of reliability grid operation without renewables or batteries attest.
In the first 16 months after its creation in 2017, NERC’s Inverter-Based Resource Performance Task Force produced four disturbance reports, two alerts, several webinars and a reliability guideline. Its latest creation could be considered its Greatest Hits.
The task force began disseminating a 98-page inverter performance guideline a little over a year ago.
“Our recommendation to transmission owners is you need to be familiar with the guideline and incorporate what’s in [it] in your interconnection requirements,” Bauer said. “We got a lot of feedback from the industry, and they said, ‘What are the critical pieces in the performance guideline that we should include in our interconnection agreements?’ That’s really what spawned this latest guideline.”
Although many of the task force’s recommendations apply to balancing authorities, reliability coordinators or transmission operators, they are generally addressed to the TO, which is responsible for maintaining interconnection requirements under reliability standard FAC-001 and for conducting interconnection studies under FAC-002.
The new 52-page publication seeks to cover the growing number of inverter-based generator interconnections that fall between the distribution system and the bulk electric system (BES) threshold (capacity of 75 MVA and voltages of 100 kV) that is subject to NERC’s standards. The task force says “the vast majority of solar PV plants connected to the BPS [bulk power system], totaling over half the capacity, are not considered BES and are therefore not subject to NERC reliability standards.”
“Maybe it’s connected at less than 100 kV, but it’s more than 75 MVA. Maybe it connects at 69 or 92 kV. Or maybe it connects at greater than 100 kV, but it’s less than 75 MVA. Those are [what] I call the ‘tweener’ interconnections,” said Bauer, NERC’s associate director of reliability risk management.
“While each individual resource may not have a substantial impact to the BES, the overall response, behavior and control of these resources impact BPS reliability and stability,” the guideline says. “It is therefore critical to have consistency across the generating fleet.”
A growing number of inverter-based generator interconnections fall between the distribution system and the bulk electric system (BES) threshold (capacity of 75 MVA and voltages of 100 kV). | NERC Inverter-Based Resource Performance Task Force
If widely adopted, the guideline could act as a de facto standard. Although interconnections outside the BES definition are not directly subject to NERC standards, the task force realized it could still influence them indirectly: The guideline includes 18 recommendations for interconnection requirements and six for modeling.
The task force said the guidelines will serve as a “bridge” to the Institute of Electrical and Electronics Engineers’ P2800 effort to standardize the performance and capability of newly interconnecting BPS-connected inverter-based resources (IBRs). Completing the standard and getting it adopted by relevant authorities is expected to take about two years.
“A significant portion of [the 2018 performance guideline] looks a lot like an equipment specification, and NERC standards [have] never really delved into the area of providing equipment specifications,” Bauer said. “We recognized this fairly early on and … that’s what spawned this IEEE 2800 project.”
Unlike a NERC standard, which would cover legacy equipment, the new guideline is intended to apply only to new and “materially modified” interconnections involving IBRs. IBRs are not “brand-new” to the bulk system, said NERC’s Ryan Quint, citing wind farms installed since the 1980s.
The majority of solar PV resources are connected at voltage levels less than 100 kV and are sized at less than 75 MW in capacity, making them exempt from NERC reliability standards. | NERC Inverter-Based Resource Performance Task Force
“There is a lot of legacy equipment out there. Not all of that the legacy equipment can meet the recommended performance that we’re seeking today,” said Quint, senior manager of advanced analytics and modeling.
Grid operators need more granular data because of the growing penetration of IBRs, he said.
“Clarity and consistency [are] needed for inverter-based resources because their electrical response and behavior when they’re connected to the grid is dominated by controls rather than physics,” Quint said. “The inverters, the plant-level controllers, the communication — all the stuff that interacts to make the plant behave the way it does — is all based on a control system … that can be [programmed] to some extent to meet certain performance requirements and ensure reliability of the grid. … The goal is not to have expensive, overbearing requirements for inverter-based resources. It’s just to bring clarity to what the grid really needs.”
Monitoring
In producing reports on the August 2016 Blue Cut Fire, the October 2017 Canyon 2 fire, and the 2018 Angeles Forest and Palmdale Roost disturbances, the task force discovered that some of the IBR facilities “lacked the data we really needed to analyze those events in great detail,” Bauer said.
He said investigators need high-resolution, time-synchronized data. “We actually recommend where we would take measurements at. Of course, we would want a measurement at the point of interconnection, but there’s also a really big need to see data down in the plant … down at the individual inverter level.”
Weak Grid
Bauer said a recent incident in the U.K. has highlighted the need to understand how inverters affect the grid’s short-circuit strength.
The U.K. grid lost 800 MW of generation, shedding load to 1 million customers, after the voltage-regulating control on a very large wind facility became unstable.
“Make sure you study all potential configurations on your system to ensure that you can’t end up in a weak grid situation, because that’s in essence what happened in the U.K.,” Bauer said. “They had some planned maintenance outages, which put them in a weak grid situation … and that’s what caused their control to go unstable.”
“Weak grid” concerns are on the mind of engineers in New England, ISO-NE associate engineer Brad Marszalkowski said. “Lately we’ve been doing [electromagnetic transient modeling] for every interconnection request because they’re all inverter-based resources,” he told the webinar. “We see a lot of these weak grid issues.”
Be Proactive
Jeff Billo, ERCOT’s senior manager of transmission planning and the task force’s vice chair, also offered some lessons learned during the webinar.
ERCOT, which has 22 GW of wind and almost 2 GW of utility-scale solar, could add another 10 GW of wind and about 4 GW of solar in the next 15 months, if all the signed interconnection agreements backed with financial security postings come to fruition.
ERCOT, which has 22 GW of wind and almost 2 GW of utility-scale solar, could add another 10 GW of wind and about 4 GW of solar in the next 15 months, if all the signed interconnection agreements backed with financial security postings come to fruition. | ERCOT
The Texas grid operator recently created a new task force in response to interconnection requests for “multi-hundred-megawatt” batteries, Billo said. (See “TAC Approves Task Force to Study Battery Energy Storage,” ERCOT Technical Advisory Comm. Briefs: Sept. 25, 2019.)
Billo cited Texas’ IBR growth “to emphasize how important the work is at IRPTF to ERCOT and why we’re taking this as seriously as we are.”
ERCOT has banned IBRs from using momentary cessation since 2015, he said. “However, we were surprised when we got the survey responses back from the second NERC alert last year. There were some of the newer solar resources that were using that momentary cessation. We’ve identified that we need to clarify our requirements.
“We don’t want to wait until we start seeing problems on our grid before we start to implement some of these requirements,” he continued. “We’ve found it’s really important to be proactive in getting the requirements out, because once you have a problem on your system, it’s really too late. It’s near impossible to go back and retrofit the equipment that’s already in the field.”
California officials on Monday continued to heap criticism on Pacific Gas and Electric for initiating a massive blackout across much of its territory last week, with the state’s top regulator ordering “immediate corrective actions” to the company’s policies and Gov. Gavin Newsom calling for refunds to the 738,000 customers affected.
In a letter to PG&E CEO Bill Johnson, California Public Utilities Commission President Marybel Batjer condemned the utility for “failures in execution” during the largest public safety power shutoff (PSPS) in the state’s history, while directing the company’s top executives and board members to attend an emergency meeting Friday to share what they learned from the controversial shutoff and how they plan avoid a repeat.
“It is critical that PG&E, along with all the other utilities in the state, learn from this event and take steps now to ensure mistakes and operational gaps are not repeated,” Batjer said.
Batjer’s letter followed her harsh comments during last week’s CPUC voting meeting, saying PG&E’s “absolutely unacceptable” measures cannot become the “new normal” for the state. (See PG&E Restores Power amid Backlash.)
PG&E has said it recorded about 50 instances of damage to its equipment in areas affected by last week’s PSPS, including these downed lines in Shasta County. | PG&E
The tone of the Oct. 14 letter was more conciliatory, with Batjer commending the cooperation and transparency of PG&E staff who “worked to overcome challenges” during the event. But she also called out PG&E on several shortcomings, including its failure to heed recommendations from state and local agencies, which contributed to a critical breakdown of public communication and coordination. Those recommendations included establishing a communication structure that allows emergency personnel to receive information outside general updates to local governments, developing lists of critical facilities with county and tribal governments, identifying critical fuel-supply needs and coordinating with local governments to select PSPS-specific community resource centers.
Batjer pointed to the performance of PG&E’s website — a “cornerstone” of the company’s public information effort, which crashed within 24 hours of the PSPS declaration. That left PG&E staff struggling “to provide necessary information to their customers, the public and frontline safety officials with affected state, county and tribal governments.”
Batjer also faulted PG&E for failing to scale its operations to meet the increased customer inquiries precipitated by the event. In response, she ordered the company to identify the maximum outage that could occur during a PSPS and ensure “commensurate bandwidth requirements” for web and call services to be available at all times.
Other corrective actions required by the CPUC include:
Accelerating the restoration of power, with a goal of less than 12 hours — similar to the requirement after major storms;
Taking steps to minimize the magnitude of future PSPS events;
Establishing a more effective communication structure with county and tribal government emergency management personnel;
Improving processes and systems for distributing maps to counties and tribal governments showing the boundaries of the most recent PSPS-affected areas;
Developing a list of existing and possible future agreements for on-call resources that can be called upon in an emergency;
Ensuring PG&E personnel involved in PSPS response in emergency operations centers are trained in California’s Standardized Emergency Management System.
‘Right Decision’
In a letter to Batjer Monday, Gov. Newsom lauded the CPUC for its “swift response” to his request for an immediate “comprehensive inquiry” into the PG&E’s blackout event.
But a separate letter to PG&E Corp. CEO Bill Johnson had sharper words, with the governor castigating the company over the “unacceptable scope and duration” of the outages, which he said were “the direct result of PG&E prioritizing profit over public safety, mismanagement, inadequate investment in fire safety and fire prevention measures and neglect of critical infrastructure.”
Newsom also echoed Batjer’s criticism of PG&E for its failure to heed the recommendations of public agencies in executing its PSPS measures.
“PG&E’s lack of preparation and poor performance is particularly alarming given that, prior to the event, top executives responded to the scrutiny and questioning of state and local agencies by asserting that PG&E could handle a public safety power shutoff event,” Newsom wrote. “And PG&E turned down recommendations and offers of assistance from public agencies that are experts in crisis management, including the Governor’s Office of Emergency Services [OES].”
Newsom urged Johnson to have PG&E refund $100 to each residential customer affected by the blackout and $250 to each small business customer.
“This refund should be funded by shareholders, not ratepayers,” Newsom said.
Johnson defended PG&E’s actions, saying the company “closely” coordinated its activities with the CPUC, OES and the California Department of Forestry and Fire Protection before and during the event.
“Representatives from those agencies were embedded in our Emergency Operations Center and we welcomed and accepted their help and counsel, and PG&E employees were also embedded at Cal OES in Sacramento,” Johnson said in a statement. “We also worked closely with county and local officials throughout the PSPS.”
But he also acknowledged there were “areas” where PG&E “fell short of its commitment to serving our customers during this unprecedented event,” specifically in its customer communications.
Still, Johnson pointed to what he considered a key — and positive — outcome of the PSPS: that no fires were sparked in PG&E’s territory. The company has said it recorded about 50 instances of weather-related damage to its equipment in PSPS-impacted areas, including downed lines and vegetation making contact with wires.
“We appreciate the significant impact that turning off power for safety has on our customers and the state. While we recognize this was a hardship for millions of people throughout Northern and Central California, we made that decision to keep customers and communities safe,” Johnson said. “That was the right decision.”
A proposed merger of two Northwest transmission planning groups has won the endorsement of state regulators, but a prominent independent transmission developer is calling on FERC to convene a technical conference to scrutinize the effort before signing off.
In a limited protest submitted to FERC on Oct. 7, LS Power says it agrees in principle with the consolidation of ColumbiaGrid and Northern Tier Transmission Group (NTTG) into a single regional planning organization (RPO) called NorthernGrid (ER19-2760, et al.). But the company also questioned whether the new entity will be any more successful than its predecessors at producing the kind of regional transmission projects envisioned by the commission’s Order 1000.
In that landmark 2011 order, FERC mandated that transmission providers participate in processes that produce a regional transmission plan and amend their tariffs to include procedures for public policy requirements. The order also sought to open projects identified in those regional plans to competition by non-incumbent transmission developers.
“To date, neither ColumbiaGrid nor NTTG have selected a single regional solution to transmission needs identified in the respective planning processes by individual transmission owners,” LS Power wrote in its filing. “While LS Power is generally supportive of the endeavor to combine the two regions, it also believes that this is an opportunity to establish a transmission planning region that engages in meaningful regional planning that leads to the identification of more efficient and cost-effective transmission solutions rather than simply rolling up local transmission plans.”
If approved by the commission, NorthernGrid’s planning territory would encompass parts of California, Idaho, Oregon, Montana, Nevada, Washington, Wyoming and the entire state of Utah. Members would include ColumbiaGrid’s Avista, Bonneville Power Administration, Chelan Public Utility District, Puget Sound Energy, Seattle City Light and Snohomish Public Utility District, along with NTTG’s Deseret Power, Idaho Power, Enbridge, NorthWestern Energy, PacifiCorp, Portland General Electric and Utah Associated Municipal Power Systems.
In line with current practice, BPA and the publicly owned utilities — all non-jurisdictional to FERC — would be considered “non-enrolled” members in the new RPO. The RPO would coordinate their planning with their investor-owned neighbors, but they would not be subject to federal authority or Order 1000.
A Plan for Planning
The proposed merger is the result of a four-year effort to replace ColumbiaGrid and NTTG, the proponents noted in their Sept. 6 filings, which requested FERC approve the new RPO effective Jan. 1, 2020.
They said the merger will allow for “collaborative” regional planning on a single timeline, reduce member expenses through broader sharing of administrative expenses and reduce the interregional coordination requirements for all Western RPOs by eliminating one region. Membership would be open to any entity that owns or operates transmission facilities in the Western Interconnection, is electrically connected to an existing member or proposes to build a project making such a connection.
The new NorthernGrid regional planning organization would consolidate the areas currently covered by ColumbiaGrid and Northern Tier Transmission Group. | ColumbiaGrid
NorthernGrid would follow a two-year transmission planning cycle. The process would kick off with a gathering of input on study scope, including local transmission plans, new proposed projects (including Order 1000 candidates) and public policy requirements. Later during the first year, the RPO would develop the study scope and methodology and perform technical analysis and coordination with other regions. It would complete the year by issuing a draft regional plan.
Year 2 of the cycle would start with a review of the draft plan and an update of data points, followed by an update of the regional study scope and development of cost allocation solutions. The process would wrap up later that year with a review of the final regional plan, allocation of cost responsibility for regional projects and plan approval.
‘Fundamental Issues’
LS Power contends that NorthernGrid’s planning process “raises fundamental issues about how the planning process should be structured,” pointing out that the proposed process largely draws from existing processes used by ColumbiaGrid and NTTG — one the company said has been unsuccessful for independent developers.
“To properly evaluate whether the new NorthernGrid proposal will meet the commission’s goals, the commission must look at whether the previously approved ColumbiaGrid and NTTG processes effectively met those goals,” the company said. “Although those proposals were approved as compliant with Order No. 1000, the proponents now have at least five years of data available to test the effectiveness of the regional planning.”
LS Power offered its own verdict: “To date, neither ColumbiaGrid nor NTTG have authorized a competitively determined transmission addition under their Order No. 1000 process.”
The company also contends that “aspects of the proposal show that the planning process favors local transmission planning.” It asked FERC to require NorthernGrid to engage in transmission planning that leads to the evaluation of projects that may be more efficient or cost-effective than local solutions.
LS Power said FERC should consider imposing additional requirements on NorthernGrid, including:
giving developers and other stakeholders an opportunity to propose regional needs and solutions after NorthernGrid has finalized the study scope;
clarifying when the region will determine whether a project proposed for regional cost allocation is a more efficient or cost-effective solution than a local project;
revising the non-enrolled developer agreement to allow a developer to seek resolution at FERC through a complaint under Section 206 of the Federal Power Act;
altering the governance structure to allow stakeholders to vote and ensure greater independence from incumbent transmission providers; and
developing a pro forma agreement laying out the rights and obligations of a developer whose regional project is selected by the RPO.
LS Power also said the filing is deficient because NorthernGrid did not include a copy of its planning agreement with the non-enrolled members, such as BPA, whose transmission facilities “interconnect or are intertwined” with the systems of the RPO’s “enrolled” members.
“The NorthernGrid filers intend to coordinate planning with non-enrolled nonpublic utility transmission providers. To that end, they developed a separate planning agreement that is substantially similar to the planning that occurs within Attachment K [of a transmission provider’s tariff], but excludes the cost allocation provisions,’” LS Power said.
The company argues that FERC should hold a technical conference to evaluate how well ColumbiaGrid and NTTG have identified projects that solved their regions’ needs “and, if those entities were not successful in identifying regional projects, whether that is due to flaws in the planning process that should be corrected so that the flaws will not carry over to the new (and combined) NorthernGrid.”
“The commission should not accept the new Attachment K until these issues are better fleshed out. Commission precedent shows that a technical conference is good vehicle for fleshing out issues of this type,” the company said.
Proposal Addresses ‘Key Concern’ for States
The NorthernGrid proposal has earned the backing of a key constituency: state utility commissioners, who applauded the group for providing states with a “meaningful role” in planning through the appointment of two representatives from each state on an Enrolled Parties and States Committee.
“There, state entities and jurisdictional members may collaborate to form perspectives on the study scope and plan that the committee’s co-chairs will carry forward to the NorthernGrid planning committee,” commissioners from Idaho, Oregon, Washington and Wyoming wrote in joint comments filed with FERC.
The role of states in NorthernGrid had been a “key concern” for regulators because ColumbiaGrid had “no formal role for states distinct from other stakeholders,” while utility regulators do have formal roles on NTTG’s Steering Committee, they said.
The commissioners said they “appreciate the willingness of the NorthernGrid entities to work toward a solution that recognizes the important role of states and accommodates many state priorities, even within a complex organizational structure.” They pointed out that the footprints of the two planning regions already represent “an interconnected region with significant overlap” in customers, generation and transmission. Their combination “will better reflect the scope of the regional benefits of transmission solutions being evaluated, as well as produce administrative cost efficiencies that benefit customers across the region,” they said.
They also contend that the “best regional solutions” will depend on investor-owned utilities collaborating with BPA and the region’s publicly owned utilities.
“Navigating the legal and administrative complexity of an organizational structure that accommodates both Order 1000 entities and non-jurisdictional entities is difficult but necessary to achieve broad regional collaboration,” they wrote.
The commissioners acknowledged that their concerns were centered on NorthernGrid’s governance and that FERC must deal with many other organizational details in its review process. “Although we do not intend to take positions on any other issues that may arise, we do encourage FERC to evaluate the filing as expeditiously as possible, so that transition to the new organization can align efficiently with the beginning of the next two-year planning cycle,” they concluded.
CARMEL, Ind. — MISO is planning a spring filing with FERC to implement a payment structure for resources that re-energize islanded areas of the grid following a blackout.
“It’s interesting to stand up here and talk about something that we hope never happens. But we do see value in having a process,” Director of Settlements Laura Rauch told stakeholders at Thursday’s meeting of the Market Subcommittee.
MISO’s preliminary proposal stipulates that, as a starting point for pricing, compensation for restoration energy will rely on resources’ last submitted offers before an emergency strikes, resulting in unique costs based on each resource rather than a uniform clearing price. The RTO will allow for recovery of start-up costs, emergency purchases and resource-specific energy costs. It will also include recovery for any unusual costs incurred during operation, provided they can be verified by the Independent Market Monitor. The RTO will also accept after-the-fact updates of offers.
Restoration pricing differs from MISO’s existing black start services definition because black start resources derive their revenues from the capacity they provide, not the energy market.
Rauch said restoration events will be considered over when the day-ahead market once again takes over economic dispatch of resources in the islanded area.
“We’ll need to define the area of impact and the island,” she added.
Rauch said MISO realizes load and generation totals during a restoration event “may be imbalanced” but said total generation costs will be allocated on a load-ratio share. The RTO had originally considered allocating resource costs based on local balancing authority boundaries, but this summer it said load ratio would be simpler to implement.
RTO officials have also said a fixed-price compensation approach for restoration energy would be a blunt instrument that would at times result in under- or over-collection by generators.
“The downside is that it’s much more complex,” MISO Director of Market Services John Weissenborn said in June of a unit-by-unit pricing calculation and settlement based on offers.
MISO Preps Tariff for Short-term Reserves
Although MISO filed with FERC on Oct. 4 to include a short-term reserve product definition in its Tariff (ER20-42), stakeholders shouldn’t expect generators to fire up to furnish the reserves until late 2021.
The RTO asked that the commission act on its request by Jan. 31 but make the revisions effective Dec. 7, 2021, seeking a waiver of FERC’s 120-day maximum notice requirement to give its Monitor and stakeholders “adequate time to budget for in advance and develop and test significant software and other operational adjustments.”
MISO said it’s already begun working with tentative market platform replacement vendor General Electric on software design details.
The reserves are meant to supply energy within 30 minutes to meet reliability needs and reduce make-whole payments, and MISO expects them to be especially useful in portions of MISO South, where the RTO’s subregional transmission limit restricts imports.
MISO expects the short-term reserves product to clear $4 million in revenue annually when it goes live in 2021. It also estimates an approximate $5 million annual net production benefit when the reserves are used. Part of the savings will result from RTO operators taking fewer out-of-market actions, for which it must make revenue sufficiency guarantee payments. (See “Short-term Reserves,” Stakeholders Confused over MISO Roadmap.)
CARMEL, Ind. — MISO is hoping to avoid the need for a sixth straight waiver of its $1,000/MWh offer cap this winter, filing a year ahead of a FERC deadline to double its hard cap.
The RTO on Oct. 1 filed for the third time a proposal to adopt a $1,000/MWh soft cap and a $2,000/MWh hard cap on energy offers — and make corresponding changes to its demand curves (ER20-11).
MISO had until Oct. 1, 2020, to implement a $2,000/MWh hard cap for verified cost-based incremental energy offers after FERC last year said its plan still needed a few tweaks. While the commission accepted much of MISO’s plan to permanently double its hard offer cap, it also required the RTO to pledge to apply the new hard cap to adjusted energy offers from fast-start resources. (See FERC OKs MISO’s Doubled Offer Cap, Orders Alterations.) The new filing is considered a “true-up” filing rather than a compliance filing, the RTO said.
MISO plans to go live with the new offer cap by Dec. 1, having completed “two or three back-and-forths with FERC,” Senior Market Engineer Chuck Hansen said at Thursday’s Market Subcommittee meeting.
Executive Director of Market Operations Shawn McFarlane said he hoped the filing would supplant the need to request a sixth waiver of its $1,000/MWh offer cap this winter. (See MISO Gets 5th Winter Waiver of Offer Cap.)
Hansen said MISO was able finish its offer cap work ahead of deadline because it and market platform vendor General Electric found themselves with more time while they await a FERC order on the RTO’s plan to incorporate energy storage resources into its markets. MISO originally asked for an order on energy storage compliance by July 1 while anticipating “significant” software work thereafter on a storage participation model.
Hansen also said additional staff time was freed up because FERC has yet to issue a final rule for RTOs to craft a participation model for distributed energy resources.
Hansen said MISO will only seek a sixth waiver if FERC rejects the filing. That waiver would closely resemble the last five it filed, he said, with verified energy costs above $1,000/MWh recovered via revenue sufficiency guarantee payments.
MISO’s offer cap plan specifies that all resources, regardless of type, are eligible to submit cost-based energy offers above $1,000/MWh. This time, it added that fast-start resources will not be able to set prices above the $1,000/MWh soft cap or above the $2,000/MWh hard cap without offers first being verified or mitigated by the Independent Market Monitor.
Along with the higher caps, MISO has added a $2,100/MWh prolonged step to its operating reserve demand curve (ORDC) so that resources will receive nearly double the energy price when supply is scarce.
New MISO ORDC | MISO
The ORDC will begin at $3,300/MWh, dropping to $2,100/MWh for much of the curve when the RTO clears 8% of its requirement level. At 89%, the level falls to MISO’s original $1,100, remaining there until 96% or more of the requirement is cleared, when the curve flattens at $200.
MISO is planning to maintain its $3,500/MWh cap on the value of lost load (VoLL) over the Monitor’s longstanding criticism that VoLL could be pushed as high as $12,000/MWh to create a more sloped contingency reserve demand curve.
Hansen said MISO still plans to work with stakeholders in the coming months to recast VoLL limits.
SPP staff told the Seams Steering Committee on Wednesday that MISO is pursuing a number of transmission projects to help it escape from under a settlement agreement that governs the connection between its two regions.
MISO said in July that it is evaluating nine projects to supplement or substitute for the contract path that links its Midwest and South regions over SPP’s system. (See MISO Studying Projects to Cut North-South Tx Reliance.)
“MISO wants to get rid of the settlement agreement — specifically, the $27 million in transmission payments they’re making,” Casey Cathey, SPP’s manager of reliability planning and seams, told the committee during its monthly meeting. “They have a stack of projects they’ve looked at. … They’re being very transparent.”
MISO Midwest and South footprints | MISO
Cathey said MISO intends to fold the projects into its planning efforts, which will be completed by the end of 2020. Similarly, he said, SPP would like to incorporate MISO’s work into its own planning processes and into the RTOs’ next coordinated system plan.
“This is an opportunity for us to have a coordinated plan to meet both MISO and the members’ intentions, but also for SPP to have a portfolio developed that addresses needs along the seam through a series of flowgates that help us to run the market more efficiently,” he said.
Cathey said he would be able to bring more details to the SSC’s December meeting.
Under the terms of a settlement agreement reached in 2015, MISO’s flows on the contract path are capped at 3,000 MW north to south and 2,500 MW in the opposite direction. MISO compensates SPP and six independent transmission owners party to the agreement — Southern Co., Tennessee Valley Authority, Associated Electric Cooperative Inc., Louisville Gas and Electric, Kentucky Utilities and PowerSouth Energy Cooperative — by applying a capacity factor for flows exceeding the previous 1,000-MW contract path in the RTOs’ joint operating agreement.
The settlement agreement expires in January 2021. At that time, the parties can give notice to terminate or revisit the settlement provisions. FERC approved the settlement in 2016. (See FERC OKs MISO-SPP Transmission Settlement.)
RSC-OMS Liaison Group Looks for Answers
Adam McKinnie, an economist with the Missouri Public Service Commission, said SPP and MISO state regulators have gathered initial feedback on the RTOs’ interregional planning processes and will spend the next couple of months evaluating that input.
Commissioners on SPP’s Regional State Committee plan to attend the Organization of MISO States meeting Oct. 24 in New Orleans. The SPP RSC-OMS Liaison Committee will also meet Nov. 17 in San Antonio during the first day of the National Association of Regulatory Utility Commissioners’ annual meeting, McKinnie said.
The Liaison Committee has commissioned an independent analysis to determine whether the RTOs are leaving efficiencies and benefits behind in their interregional planning processes. (See MISO, SPP States Ponder Look at Interregional Planning.)
Stakeholders responded to a request for information in September. Eight of the 14 stakeholders who submitted responses believe an interregional planning analysis will help the committee. Three others suggested additional work on current processes.
Stakeholders have been frustrated by the RTOs’ interregional work, which has yet to result in a joint project.
The commissioners “are looking for information to see what the effects would be from different changes,” McKinnie said. “They didn’t start with a solution. They said, ‘Hey, we need information.’”
The committee has also asked the RTOs’ market monitors to study the grid operators’ markets and operations issues. That work will be delivered by the end of November.
NERC’s Stakeholder Engagement Team (SET) has finalized its proposal to merge the Planning, Operating and Critical Infrastructure Protection committees, setting the stage for expected approval by the Board of Trustees on Nov. 5.
“That [demand from members] was pretty loud and clear,” Greg Ford, chairman of the Member Representatives Committee, said Thursday at the MRC’s premeeting informational conference call.
A new Reliability and Security Technical Committee (RSTC) would replace the Operating, Planning and Critical Infrastructure Protection committees under a plan the NERC board will consider next month. | NERC
The SET also eliminated a requirement that committee members have executive-level experience.
The membership also will include representation from each interconnection. “That was a request that came through load and clear as well,” Ford said.
The transition from the three committees to the new Reliability and Security Technical Committee (RSTC) — a revised name from the original proposal, which some stakeholders feared would be confused with the Reliability Issues Steering Committee (RISC) — was also extended into June.
Under the new schedule:
Nov. 5: The board will consider the proposal and RSTC charter and transition plan. If approved, the board will appoint the new committee’s chair and vice chair at the same time.
Nov. 6 to Dec. 6: Nominations will be open for sector representatives, with sector elections, if necessary, conducted by Dec. 20.
Dec. 9 to Jan. 3, 2020: At-large nominations will be accepted, with the Nominating Committee developing a slate of at-large members by Jan. 15 for presentation to the board.
Feb. 6: Board appoints RSTC sector and at-large members.
Feb. 7 to May 29: RSTC develops transition plan and work plans for RSTC and subcommittees.
March 3-4: OC, PC and CIPC meet. The RSTC will hold its first meeting March 4 to establish the Nominating Subcommittee, Executive Committee and perform other administrative items.
June 2020: OC, PC and CIPC will meet for final work plan approvals and to complete any other approvals. The RSTC will hold initial regular meeting with subcommittee reports and other agenda items.
Terms for the new committee members will expire in June of alternating years. The initial membership will be split between two- and three-year terms, after which terms will run for two years.
The proposed changes didn’t come without misgivings from some stakeholders. (See NERC Board Hears Debate over Committee Reorg.) But Ford said he was happy with the way the process played out.
“There was a lot of open, honest, good discussion all the way back to the first meeting [the SET] had,” he said. “I feel like we’re in a good place.”
He had special praise for the work of Exelon’s Jennifer Sterling and NERC Chief Engineer Mark Lauby. “I thought you herded us cats very well,” he joked.
MRC Governance Guidelines, EMP Task Force
Thursday’s preview of the MRC’s Nov. 5 meeting also included a discussion of revised Governance Guidelines, which were developed to reduce the number of documents guiding the committee to just two: the guidelines and the NERC Bylaws. The Approved Policy on Minutes of MRC Meetings, Framework for the Operation of the MRC and NERC MRC Reference Document would be eliminated.
NERC Director of Engineering and Standards Howard Gugel also provided a brief update on the Electromagnetic Pulse (EMP) Task Force’s Strategic Recommendations Report.
