Page 1139 – RTO Insider

August 21, 2018

MISO Mulls Rules for Storage as Transmission

By Amanda Durish Cook

MISO is probing what eligibility requirements it should establish before allowing electric storage resources to function as transmission assets.

The RTO is considering study processes, modeling, cost recovery and retirement rules, all raised with stakeholders during a special Aug. 17 Planning Advisory Committee conference call to discuss the issue.

MISO is leaning toward requiring a storage resource to complete the interconnection queue if it wishes to provide market services, regardless of whether a resource has already been approved as transmission through the annual Transmission Expansion Plan (MTEP).

miso mtep energy storage — Webb | © *RTO Insider*

The RTO has so far only connected storage to its system through its generator interconnection procedures, and the procedures do not contemplate electric storage resources as transmission assets, MISO Director of Planning Jeff Webb said.

“We have connected batteries recently through Attachment X. However, that process doesn’t contemplate these devices being solely used for transmission services or mixed services,” Webb said.

“One of the complaints for having them go through the queue is a timeline and compatibility process,” he said, explaining that a transmission-use storage resource would likely have to wait through a few MTEP cycles before it could become eligible through the interconnection process. The annual MTEP reliability modeling considers only generators already approved for interconnection, not future resources.

Webb said some storage owners might ask why their resource will have to undergo reliability studies as part of the interconnection queue when they’re already operational under the MTEP assessment.

“Would the subsequent interconnection process be superfluous? What function would it serve?” Webb asked rhetorically. “Maybe there’s a type of expedited interconnection. I don’t know.” He asked stakeholders for their ideas.

American Transmission Co.’s Bob McKee predicted that MISO will see many storage resources connecting under mixed-use market and transmission functions.

“To get the value out of that device, you’re going to use it for as many services as you can. I think we’re really going to have to make sure the process doesn’t impede the value for the customer.” He warned against completing separate assessments simply for the sake of following MISO’s current process.

Some stakeholders asked if it was a matter of treating all generation fairly as a matter of principle, or necessary to allowing storage’s possibly superior capabilities to compete in more than one area. Others said MISO may need to complete queue analyses with and without the presence of storage resources to find out whether storage as transmission is truly as reliable as traditional transmission.

Webb said MISO will likely make special modeling considerations for storage resources beyond traditional wires modeling.

“When we’re talking about wires or transformers or cap banks, those are available all day, every day to provide for any and all reliability issues or conditions on the grid that they can assist with. Storage as transmission would similarly be called upon by MISO to address any reliability issues they would be effective for,” Webb said.

He said storage as transmission in particular would have to be under some form of MISO control to make sure it is charged to perform its reliability functions over peak hours, for example. MISO plans to notify the resources when and at what charge state they will be needed to provide transmission reliability services and will provide enough time to ensure the resource can reach the necessary state of charge.

Webb said that if MISO chooses to defer a 40-year transmission project in favor of a storage solution, it must also gauge the anticipated life of a device for modeling, considering which major components will likely have to be replaced and when. He said MISO may find itself approving the original deferred transmission project if a storage asset doesn’t stand up over decades.

MISO must also decide how storage assets will recover costs so that customers don’t pay twice for the same services, Webb said, paying particular attention to the treatment of market revenues if either partial or full revenue requirements are recovered under cost-based transmission rates. Storage asset owners might decide to recover only a portion of transmission rates so the asset can compete with a cheaper wires solution, Webb said.

MISO is currently considering at least three approaches to cost recovery:

Full cost-based recovery for transmission reliability services, with full crediting of market revenues;
Partial cost-based recovery for transmission reliability services, calculated as asset cost minus asset owner-estimated market revenues with crediting proportional to cost-based revenue; or
Partial cost-based recovery for transmission reliability services, calculated as asset cost minus asset owner-estimated market revenues with no crediting of market services revenues because the amount was estimated to be necessary to recover asset costs.

Storage resources would also likely have to be registered in the MISO market for charging and discharging, even if they are strictly treated as transmission, Webb said. The question also remains about what storage assets would pay and be paid for energy used for charging and discharging when they must operate for transmission system reliability under MISO instruction. Webb said in those cases, storage owners could either be price-takers in the market, charged and paid at LMPs for injections and withdrawals, or they could be neither paid nor charged for such injections and withdrawals. He also said MISO and stakeholders could come up with a third option for consideration.

The RTO is also looking to draft a storage-as-transmission retirement process, Webb said. Traditional wires assets are rarely decommissioned in the footprint, according to MISO, and Webb said storage resources may become subject to system support resource studies or an equivalent to discern whether the devices are necessary for reliability purposes.

Webb also said stakeholders raised an issue of MISO investigating whether there are possible conflicts of interest if a transmission owner is also allowed to become a market participant operating a storage resource for market services. However, Webb said MISO did not think the issue was markedly different than utility-owned generation participating in the market today.

MISO will continue to discuss policy for storage-as-transmission at the September PAC meeting. Webb asked for stakeholder suggestions through Sept. 7.

August 21, 2018

Reports: CPP Replacement to Give States Control

The Trump administration’s replacement for the Clean Power Plan will require modest efficiency improvements that could boost the output of coal-fired generators while giving states discretion over enforcement, according to published reports.

The New York Times, The Washington Post, Politico and Bloomberg all reported that the replacement will be announced this week, perhaps at a Trump campaign rally in West Virginia coal country Tuesday. The Wall Street Journal reported Monday evening that acting EPA Administrator Andrew Wheeler had signed the new plan, which EPA has dubbed the “Affordable Clean Energy” (ACE) rule.

According to the reports, EPA has decided not to seek reversal of the 2009 finding that greenhouse gases endanger public health, as coal magnate Robert Murray and others have urged. Leaving the endangerment finding in place means the agency must address CO₂emissions. Wheeler is a former Murray Energy lobbyist.

The reports said EPA will order that individual coal plants make heat rate improvements to increase the electricity produced from the same amount of coal — reducing carbon emissions per megawatt-hour. Observers say that could increase coal plants’ dispatch as their lower production costs make them more competitive.

epa trump clean power plan cpp — | *Energy Information Administration Annual Energy Outlook 2018*

‘Inside the Fence Line’

The Obama administration’s plan would have required utilities to switch from coal to gas and renewables to produce a 32% cut in power sector carbon emissions below 2005 levels by 2030. The Trump administration says the CPP overstepped EPA’s authority by imposing regulations “beyond the fence line” of individual plants. (See EPA to Announce Clean Power Plan Repeal.)

The U.S. Supreme Court stayed the CPP pending legal challenges in February 2016. The D.C. Circuit Court of Appeals heard arguments in the case, but Trump’s EPA asked the court to delay its ruling so it could rewrite the rule. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)

EPA previously estimated that “inside-the-fence-line” plant modifications, such as equipment upgrades and adoption of best practices, would improve average coal plant heat rates by 4%.

Politico reported that the White House Office of Management and Budget finished reviewing the draft and sent it back to EPA last week.

The plan reportedly would allow states to decide whether to adopt changes to “New Source Review,” a policy that requires power plants to adopt pollution controls when they make upgrades that could increase emissions.

The CPP replacement, following the proposed rollback of automobile efficiency standards, is another indication of the Trump administration’s determination to reverse Obama-era environmental policies and its reluctance to address climate change. EPA says transportation (26%) and electric generation (30%) are responsible for more than half of all greenhouse gas emissions in the U.S.

On Aug. 2, EPA and the National Highway Traffic Safety Administration announced they would cap fuel economy requirements at a fleet average of 37 mpg starting in 2020. Under the Obama rules, the standard had been set to rise to about 47 mpg by 2025.

Bloomberg noted that the release of the CPP replacement “comes during a summer dominated by wildfires and hotter-than-normal weather. Northern Europe has withered in a deadly heat wave. California recorded its hottest July on record as its forests burned on an unprecedented scale. At least 116 people in Japan have died this summer, with the country posting its highest-ever temperatures in July. Meanwhile, parts of India are dealing with the worst flooding in a century.”

Reduced Reductions

The Energy Information Administration says carbon emissions were 27% below 2005 levels at the end of 2017 and will drop another percentage point to 28% through 2030 without the CPP.

The Washington Post reported that the plan would allow the release of at least 12 times the amount of carbon dioxide into the atmosphere compared with the Obama rule over the next decade.

By 2030, the Post said, the new proposal would cut CO₂ emissions from 2005 levels by 0.7 to 1.5%, compared with business-as-usual. The CPP would have cut carbon emissions by about 19% by the end of the next decade.

EPA’s new plan would reduce sulfur dioxide and nitrogen oxides that help form smog by 1 to 2% each from 2005 levels over the same time period. Cuts under the CPP for those pollutants would have been 24% and 22%, respectively, the Post said.

The new proposal, which is subject to a 60-day comment period, will almost certainly face legal challenges from environmentalists.

The Environmental Defense Fund said EPA should be more, not less, aggressive in reducing emissions despite industry trends favoring gas and renewable generation over coal.

“To be clear, we need the long-term regulatory signal established by the Clean Power Plan in order to ensure these trends continue — and to secure the full benefits of the pollution reduction that the Clean Power Plan would require,” wrote Rama Zakaria, EDF’s senior manager for regulatory policy and analysis, in a blog post last week. “If acting EPA Administrator Wheeler decides to replace the Clean Power Plan, EPA must fulfill its legal imperative to establish carbon pollution limits that achieve maximum feasible pollution control and adequately address the urgent threat of climate change.”

— Rich Heidorn Jr.

August 21, 2018

EPA: CPP Replacement Could Boost Coal-Fired Power by 6%

By Rich Heidorn Jr.

The EPA on Tuesday announced its replacement for the 2015 Clean Power Plan, saying it will be cheaper and give states more control while producing similar CO₂emission reductions even as it increases coal-fired electric generators’ market share.

“The CPP exceeded the agency’s legal authority, which is why 27 states, 24 trade associations and 37 rural electric coops and three labor unions challenged the rule,” Acting EPA Administrator Andrew Wheeler said during a press briefing announcing the Affordable Clean Energy (ACE) rule. “… The era of top-down, one-size-fits-all federal mandates is over.”

Compared to the CPP, EPA says the ACE rule will result in 0.2% to 0.5% lower electric prices in 2025 while increasing coal production for power sector use by 4.5% to 5.8%.

The ACE rule defines the “best system of emission reductions” (BSER) as heat-rate efficiency improvements that can be achieved at individual coal plants, in contrast with the CPP, which set state emissions limits and encouraged switching to natural gas and renewables.

The new plan will cover about 600 coal-fired generating units at 300 facilities. EPA is not proposing a BSER for natural gas-fired combined cycle plants. Instead, the agency is seeking comment on available emission reductions for them.

PJM Capacity Performance CP IMEA cpp epa coal ace rule — IMEA owns 12% of LG&E and KU’s Trimble County 1, a 514-MW coal-fired unit between Louisville and Cincinnati. | *LG&E-KU*

The rule also slows down the implementation schedule and introduces a new test for determining whether physical or operational changes to a power plant qualify as a “major modification” triggering New Source Review.

EPA’s regulatory impact analysis (RIA) for the proposal concludes that ACE will cut compliance costs by up to $400 million annually compared to CPP while reducing 2030 carbon emissions by up to 1.5% from projected levels without the CPP. “When states have fully implemented the proposal, U.S. power sector CO₂ emissions could be 33% to 34% below 2005 levels, higher than the projected CO₂ emissions reductions from the CPP,” EPA said in a press release.

EPA notes that power sector emissions have declined without the CPP due to industry trends favoring increased natural gas and renewable generation. “The ACE rule will continue this trend,” EPA said.

Yet Assistant EPA Administrator Bill Wehrum undercut the agency’s projection, telling reporters that the flexibility being afforded states makes predictions difficult. “We believe the law requires states to have primary authority for implementing this program and determining what emission limitations or other measures actually should be applied at the power plants within their jurisdiction. That flexibility and that latitude means, beyond a certain point, it’s difficult to predict what states are going to do,” said Wehrum, who heads the Office of Air and Radiation.

EPA’s RIA calculated benefits and costs of three replacement scenarios and one repeal scenario, all of which would result in CO₂ emission reductions from current levels. “The RIA projects small increases in emissions of CO₂, sulfur dioxide (SO₂) and nitrogen oxides (NOX) under all four scenarios compared to CPP,” EPA said. “However, comparing the replacement scenarios to the full repeal scenario shows a replacement would lead to significant reductions in emissions for these pollutants in the future.”

`Overly Burdensome’

EPA said it would be “overly burdensome” to require states to evaluate all options for reducing emissions.

Instead, the agency identified a list of the “most impactful” heat rate improvement measures states should consider. EPA’s list of “candidate technologies” includes: improved operating and maintenance; boiler feed pumps; air heater and duct leakage controls; variable frequency drives; blade path upgrades for steam turbines; redesign or replacement of economizers and “neural network/intelligent soot blowers.”

epa cpp coal ace rule — Leaking steam valves | *Electric Power Research Institute*

“Opportunities for heat rate improvements are source-specific and dependent upon the individual unit’s design, configuration, age and operating and maintenance history,” EPA said.

States’ Role

The rule will allow states to establish “standards of performance” based on the emission limitations achievable through the BSER. “EPA is not setting a presumptive standard of performance. States will be given the flexibility to design a plan that, in the state’s judgment, will work best under its particular circumstances,” the agency said, citing as considerations the plant’s current technology and practices and its remaining useful life.

States will have three years from the date of the final rule to submit their plans EPA approval, compared with nine months under the CPP. EPA will have 12 months to approve or reject state plans, up from four months under CPP. For states that fail to submit an approvable plan, EPA will have two years to develop its own plan, up from six months.

coal epa cpp ace rule — Coal Heat Rates by State | *EIA*

Because efficiency upgrades reduce the amount of coal burned — and CO₂ released — per unit of electricity generated, the rule will improve the plants’ competitiveness against alternative fuels, potentially increasing coal’s share of the generation mix.

The RIA’s scenario assuming 4.5% heat rate improvement at $50/kW projects coal production for power sector use will be 5.8% higher than under CPP by 2025, rising to 9.5% by 2035 — the same as the 2035 scenario with no CPP.

A scenario assuming the same heat rate improvement at a cost of $100/kW would see coal’s use increase 4.5% in 2025, rising to 7.4% in 2035.

“The Clean Power Plan would have caused more fuel-secure coal-fired power plants to retire prematurely even though policy makers have become increasingly concerned that coal retirements are a threat to grid resilience and national security,” said Michelle Bloodworth, CEO of the pro-coal group ACCCE, which estimates almost 40% of the nation’s coal fleet has retired or plans to do so.

Changes to New Source Review

EPA proposes allowing states to adopt an hourly emissions increase test for determining whether power plant upgrades are a “major modification” triggering New Source Review under Clean Air Act Section 111(d).

Only projects that increase a plant’s hourly rate of pollutant emissions would need to undergo a full NSR analysis, which could result in additional pollution controls.

Under current rules, NSR review can be triggered if annual emissions increase because of increased dispatch even if hourly emissions drop.

“Existing plants might therefore forego investing in efficiency improvement projects, rather than risk triggering NSR by undertaking such projects,” EPA said. “Worst case, if compelled to undertake efficiency improvement projects in order to comply with state-developed standards of performance, some existing facilities might choose to shut down altogether, in advance of the end of their expected useful life.”

EPA will accept comments on the proposal for 60 days after publication in the Federal Register.

The CPP would have required a 32% cut in power sector carbon emissions below 2005 levels by 2030. The Trump administration says the CPP overstepped EPA’s authority by imposing regulations “beyond the fence line” of individual plants.

The U.S. Supreme Court stayed the CPP pending legal challenges in February 2016. The D.C. Circuit Court of Appeals heard arguments in the case, but Trump’s EPA asked the court to delay action so it could rewrite the rule. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)

Reaction

Some conservatives were disappointed in the new rule, urging instead that the administration seek reversal of the 2009 finding that greenhouse gases endanger public health.

But their criticism was muted compared to that from CPP supporters.

“The administration’s own analysis shows this proposal would be wholly ineffective in addressing carbon pollution from power plants, and therefore harmful to our citizens, who are already suffering from the dangerous impacts of climate change,” officials from 14 states said in a letter to Wheeler.

“In regulating greenhouse gas pollution, the EPA is legally required to use the ‘best system of emission reduction,’ not a mediocre or downright counterproductive system of emission reduction,” said Richard Revesz, director of New York University’s Institute for Policy Integrity. “This proposal is an enormous step backwards, and it will have severe repercussions for public health and the climate.”

But Tracy Terry, director of energy at the Bipartisan Policy Center, said the rule “isn’t necessarily a slam dunk for coal,” noting that plants’ fates will depend on the aggressiveness of their state’s implementation plan. “There are a number of coal-heavy states with gubernatorial elections in November. The outcomes of those races could have an impact on how the rule is eventually implemented,” Terry said.

Attorney Timothy McMahan, chair of Stoel Rives’ Climate Change Practice Initiative, predicted Pacific states will erect a “green wall” against the Trump administration’s efforts.

He noted that California’s cap and trade has been extended through 2030. “As the fifth largest economy in the world, California’s efforts are a significant test case for the premise that carbon regulation can coexist with economic growth and jobs creation,” he said in a statement. “This summer, in both Oregon and Washington, the groundwork is being laid to enact sweeping new greenhouse gas legislation. … With other states pursuing their own climate legislation, and given market forces making coal investments questionable, the impact of the ACE rule to reverse state efforts is uncertain, particularly if states will truly be free to enact their own legislation free from administration efforts to manipulate energy markets in favor of coal generation.”

Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School, tweeted that “GHGs, the Clean Power Plan, and 111(d) are the distractions in today’s proposal.

“Rewriting the New Source Review regards will likely result in far more emissions,” he said.

David Doniger, senior strategic director of the Natural Resources Defense Council’s Climate and Clean Energy Program, responded to Peskoe, noting that Wehrum, while a member of the George W. Bush EPA, “tried this loophole before.

“Lost in court,” Doniger said. “Won’t go better this time.”

August 20, 2018

PJM MRC/MC Preview: Aug. 23, 2018

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:20)

Members will be asked to endorse the following manual change:

A. Manual 14C: Generation & Transmission Interconnection Facility Construction. Revisions developed to clarify procedures.

3. Market Efficiency Process Enhancement Proposal (9:20-9:50)

Members will be asked to endorse the market efficiency phase 1 proposal developed at the Market Efficiency Process Enhancement Task Force (MEPETF), along with the associated revisions to the Operating Agreement and Manual 14B: PJM Region Transmission Planning Process. The changes would exclude from the base case those units with facility study agreements (FSAs) and suspended interconnection service agreements and their associated network upgrades at the time of the case build, unless they are needed for reliability. (See “Market Efficiency,” PJM PC/TEAC Briefs: July 12, 2018.)

Members also will be asked to endorse revisions to Manual 14F: Competitive Planning Process adding language identifying eligible congestion drivers and clarifying language regarding benefit/cost analyses. (See “Manual 14F Changes,” PJM PC/TEAC Briefs: Aug. 9, 2018.)

4. Order 1000 Transmission Project Cost Containment Provisions (9:50-10:20)

Members will be asked to endorse a proposal to extend by one year the implementation deadlines for the cost containment comparative framework for competitive transmission projects. The proposal is being offered by the proponents of the cost-containment proposal that the MRC endorsed in May. (See Cost Containment Clears MC Vote Despite PJM Plea.)

5. FTR Liquidation Process (10:20-11)

Members will be asked to endorse a proposed problem statement and issue charge related to PJM’s problems with liquidating a large financial transmission rights portfolio on which GreenHat Energy defaulted. Members will also receive an update on alternatives for handling the liquidation.

If the problem statement and issue charge are approved, stakeholders plan to seek a vote on a motion to request that PJM ask FERC for permission to discontinue liquidating any positions in the defaulted portfolio through Nov. 30. The motion is intended to give stakeholders time to develop new liquidation rules for submission to FERC. (See PJM Reeling from Major FTR Default.)

6. Transmission Replacement Process (11-11:40)

Members will be asked to endorse a proposal from American Municipal Power for ensuring that PJM’s planning process for facilities at the end of their life are transparent and consistent and give stakeholders an opportunity for input under FERC Order 890. The proposal will require changes only to Manual 14B. Stakeholders will also hear PJM’s perspective. (See PJM Stakeholders End Tx Replacement Task Force.)

Members Committee

1. FTR Liquidation Process (1:15-1:30)

Members will be asked to approve a motion requesting that PJM ask FERC for permission to discontinue liquidating positions in GreenHat Energy’s defaulted FTR portfolio through Nov. 30. (See MRC item 5 above.)

— Rory D. Sweeney

August 20, 2018

Sept. 4 Key Date for Potential Western RC Providers

By Tom Kleckner

CALGARY, Alberta — Where once there was one, there will now be several players offering reliability coordinator (RC) services for most of the Western Interconnection.

How many RCs there will be, and who they are, should come into better focus on Sept. 4. That’s the unofficial deadline NERC and the Western Electricity Coordinating Council (WECC) have placed on Western balancing authorities and transmission owners to declare their RC.

The only certainty is that it won’t be Peak Reliability, which has been providing the RC function for the entire interconnection except Alberta since WECC was bifurcated in 2014, with WECC retaining Regional Entity functions. Peak announced last month that it will wind down its services by the end of 2019, having determined it will be financially unable to compete with CAISO’s and SPP’s RC services.

caiso spp wecc reliability coordinator rc — WECC CEO Melanie Frye | © *RTO Insider*

“Things have been moving quickly,” WECC CEO Melanie Frye told NERC’s Board of Trustees last week. “We’re hoping to get a bit more clarity on where everybody is looking to go, and whether they’re intending to go with [CAISO] or SPP, or whether some other option will emerge.

“That will allow us to see where the seams start to emerge and whether it will result in swiss cheese, where you have a small BA choosing one RC provider, but everyone else around them choosing another,” she said during the board’s Aug. 16 meeting.

Both CAISO and SPP have been aggressively pursuing potential members. CAISO said in January it will become its own RC and offer that function to other Western entities. SPP, which still hopes to integrate some of the Mountain West Transmission Group into its RTO, has filed a request with WECC to provide RC services to two Western Area Power Administration companies and says it has received interest from 26 other parties. (See WAPA Formally Requests SPP’s RC Services.)

North of the border, the Alberta Electric System Operator (AESO) already handles its own RC services, while BC Hydro is “leaning to forming” its own RC in British Columbia, Frye said.

“Ultimately, it will be the BAs and the transmission owners that make sure they have a certified RC,” Frye said. “I think we’re making progress there. We’ve had very good engagement with all of the potential RC providers. At a technical level, a lot of that planning is starting to take place, and that’s very healthy.”

As the RE for the Western Interconnection, WECC has hosted a series of stakeholder forums to discuss a future with multiple RCs. The agency will be responsible for ensuring the RCs are certified to perform the registered function; ensuring the BAs and TOs are aligned with a certified RC; and monitoring compliance with reliability standards. WECC has scheduled on-site certification visits with CAISO for March and SPP next summer.

The loss of a Western-wide RC has several stakeholders concerned.

Utah Public Service Commissioner David Clark said it was his “personal hope” that whichever entity handles the RC function has “a governance structure that is independent and a process that’s transparent.”

“However this settles out, I hope the function will be performed in a way that is transparent … particularly to state energy advisers and state regulators and consumer advocates,” he said.

“I understand there are market considerations involved, but this has to be done very carefully,” warned NERC Trustee Dave Goulding, who chairs the organization’s Enterprise-wide Risk Committee. “As NERC, we don’t want to get into a situation where reliability is compromised.”

Not to worry, Frye said. “The focus on WECC’s work and NERC’s work will be on the intricacies of the interconnection and making sure that reliability across the seams with the RCs is maintained,” she told RTO Insider.

To that end, Frye, who is just completing her first month as WECC’s CEO, said the RE will be asking for a variance to the reliability standard that requires Western RCs to model the entire interconnection and all its remedial action schemes.

“We’ve started to engage this week at an executive level with the utilities, to ensure we have that connection-wide view,” she said.

Frye and WECC have the support of NERC and its CEO, Jim Robb, Frye’s predecessor at the RE. Robb joked that Frye is a “complete upgrade over the previous guy,” and he listed reliability coordination in the West as the second of four priorities that NERC is focused on in addressing industry risk.

“WECC and NERC are approaching this completely in lockstep around the changes that are happening in the West and [ensuring] that the resulting infrastructure works as well as possible, as with [the] same heightened performance as a single RC,” he said. “We’re working very hard with WECC to understand the needs they have for these RCs.”

CAISO has notified WECC that it intends to seek certification as an RC. Frye said the ISO intends to go live within its BA footprint on July 1, 2019, and it will add its new members later in the fourth quarter. CAISO is meeting with Peak to coordinate data exchange and operations.

SPP also plans to go live with its RC functions in the last quarter of 2019. The RTO already has a West-wide model in its energy management system.

“SPP is proceeding along a slower timeline, but obviously, both need to be up and running before the December date Peak has announced,” Frye said.

August 20, 2018February 3, 2024

NERC OKs Utilities’ Transfer to ReliabilityFirst

David Ortiz, FERC’s Office of Electric Reliability’s acting director, briefs NERC stakeholders on the latest regulatory issues. | © RTO Insider

CALGARY, Alberta — The NERC Board of Trustees last week approved Wisconsin Public Service Corp.’s (WPSC) and Upper Michigan Energy Resources’ requests to move to ReliabilityFirst from Midwest Reliability Organization. NERC staff determined the transfer of the companies’ facilities would have a negligible impact on other grid users and operators, noting that the two utilities’ facilities have more geographic and electrical boundaries with RF than MRO.

Wisconsin Electric Power Co. acquired WPSC in 2015 and established UMERC as a new company in 2017. It applied for the registration transfer request in December.

NERC’s Board of Trustees gathers for its August quarterly meeting. | © RTO Insider

The board also approved the 2019 Electric Reliability Organization enterprise business plan and budget and the budgets for the seven Regional Entities; approved a requirement that transmission and generation owners provide NERC with their geomagnetic monitoring data to support ongoing research and analysis of geomagnetic disturbance risks; and adopted three reliability standards:

BAL-002-3, Disturbance Control Standard-Contingency Reserve for Recovery from a Balancing Contingency Event: Modifies the standard in response to FERC Order 835 to require that responsible entities coordinate with reliability coordinators upon circumstances preventing compliance with the 15-minute area control error recovery period. (See FERC Acts on ACE Recovery; Remedial Schemes.)
CIP-012-1, Cyber Security, Communications between Control Centers: Requires the protection of sensitive bulk electric system data communicated between control centers.
VAR-001-5, Voltage and Reactive Control: Eliminates a duplicative variance requirement and makes minor conforming language changes.

— Tom Kleckner

August 20, 2018

MISO Planning Subcommittee Briefs: Aug. 14, 2018

MISO is planning to file with FERC in October a proposal to create two new benefit metrics to appraise new market efficiency transmission projects.

Following on its promise to create more specific benefit metrics, the RTO will propose to consider the cost of avoided reliability projects and reduced settlement payments on SPP’s transmission between MISO Midwest and South. (See “New Benefit Metrics,” MISO Planning Subcommittee Briefs: June 12, 2018.)

ferc miso planning subcommittee — Moser | © *RTO Insider*

“We’re looking for physical reductions at this point,” MISO Director of Strategy Jesse Moser said during an Aug. 14 Planning Subcommittee meeting. He said MISO is initially seeking a “straightforward” approach to determining whether a project will reduce annual payments to SPP for flows above the contract path capacity between Midwest and South. MISO may be open to more in-depth analyses on contract path reductions in the future, he added.

Moser said transmission owners and state regulators must be able to work together to allow MISO to use avoided reliability projects to gauge the monetary value of an MEP.

“You’re really asking a transmission owner to take a project off their books,” which requires regulator approval, Moser said.

Moser said if a TO is unwilling to drop a project, MISO members could always pursue the RTO’s alternative dispute resolution process.

“We don’t expect that to occur, frankly,” he added.

Inverter Connections Testing?

MISO is debating which route it should take to ensure that inverter-based generation interconnecting to weaker sections of its grid doesn’t disrupt operations.

After reviewing stakeholder suggestions, MISO said it could require inverter-based generators to conduct their own Electromagnetic Transients Program (EMTP)-type study and perform to a standard. It could also revise its own generator interconnection agreement to disallow “momentary cessation” of active power output from inverter-based resources in order to prevent them from tripping offline unnecessarily.

Generator interconnection engineer Warren Hess said MISO is seeking the best approach to prove the system won’t suffer degraded reliability from inverter-based generation interconnections.

“We do want you to demonstrate that your machine can operate with no adverse impacts,” Hess said.

In feedback, multiple stakeholders said MISO should require a test for inverter-based generation, with some saying each interconnection customer be required to provide under- and over-voltage trip settings as part of their definitive planning phase application process of the queue.

But some stakeholders said requiring an EMTP study by default could become a burden, claiming that some inverter-based generation will connect to a strong point on the system and won’t require testing.

“These studies can be time-consuming and costly … it’s not just a simple thing,” said Wind on the Wires’ Rhonda Peters.

Others pointed out that allowing too many inverter-based generators on the system aggravates reliability issues.

MISO Frequency Performance up to Snuff

Final results from MISO’s NERC-required under-frequency load shedding study show that generators are performing to standard.

The RTO studied seven under-frequency load-shedding islands in MISO Midwest and initially found that the frequency performance in four exceeded the NERC requirement. (See “Generators Miss 1st Pass in Under-frequency Study,” MISO Planning Subcommittee Briefs: June 12, 2018.)

All seven islands now meet both a frequency and volts-per-hertz performance threshold, said Anton Salib of the RTO’s expansion planning group. MISO tested the islands by simulating a disturbance to cause imbalance between generation and load, Salib said.

As a result, MISO said no changes are needed to its current treatment of the islands.

MISO will conduct its next under-frequency load shedding study in 2020, when MISO South is due for five-year testing.

— Amanda Durish Cook

August 20, 2018

Intervenors Slam New England EDCs’ Gas Play at FERC

By Michael Kuser

Critics are attacking the motives of New England’s major utilities, which last month asked FERC to clarify its July 2 order denying an ISO-NE request to waive certain Tariff provisions to keep Exelon’s Mystic generating plant running.

The RTO filed the request after Exelon said in March that it would retire the 2,274-MW plant when its capacity obligations expire on May 31, 2022. (See NEPOOL Debates Fuel Security, Cost Allocation.) In rejecting the request, the commission ordered ISO-NE to revise its rules to allow cost-of-service agreements for plants needed to address fuel security issues (ER18-1509).

On Aug. 1, National Grid and Eversource Energy, on behalf of their electric distribution companies (EDCs), filed a motion for clarification and expedited action on the commission’s waiver order.

The utilities said the commission “must clarify that the central purpose of ISO-NE’s July 1, 2019, filing of permanent Tariff revisions is to assure that New England adds needed new infrastructure to address the fuel supply shortfalls and associated threats to electric reliability.”

In comments filed with FERC, critics of the EDCs’ request were blunt in their opposition.

Massachusetts Attorney General Maura Healey on last week submitted an answer to what she termed the EDCs’ “self-serving” motion.

“Eversource and National Grid — both of whom could profit significantly from potential investment in pipeline infrastructure in the ISO-NE region — encouraged the commission to address the issues outlined in the waiver petition by mandating ‘investment in new infrastructure — in the case of New England, namely natural gas pipeline capacity,’” Healey said.

iso ne ferc exelon mystic edc fuel security — natural gas compressor station | *Metropolitan Engineering*

Eversource and National Grid are co-developers with Spectra Energy Partners on the Access Northeast project, a proposed $3.2 billion expansion of the Algonquin Gas Transmission pipeline in New England. (See DC Circuit Denies Rehearing on Algonquin Pipeline.)

Procedural Grounds

The Environmental Defense Fund (EDF) filed comments asserting that “FERC should reject the EDCs’ motion on procedural grounds alone. … The commission is not obligated to accept a filing solely based on the party-bestowed title. Instead, FERC examines the substance of the pleading.”

EDF said the utilities correctly identify a fundamental misalignment between the gas and electric markets, but that their proposed cure would exacerbate the disconnect.

“Imposing long-term financial obligations on captive ratepayers for costly long-lived infrastructure would contravene the commission’s pro-competition regulatory model and upset the price signals sent by a rational market, undercutting the investment expectations upon which billions in recent energy infrastructure was underwritten,” the group said.

EDF also argued the utilities are seeking to impede that stakeholder process, saying the RTO “has already refined its thinking on fuel security issues, revising its nomenclature from ‘fuel security’ to ‘energy security.’ This is an important recognition of the role that resources such as demand response, variable energy resources and storage can provide. The [utilities] give short shrift to these alternatives, summarily dismissing their potential contributions.”

NextEra Energy Resources also filed an answer saying the utilities’ motion “is a procedurally impaired request for rehearing or complaint and seeks a remedy that is beyond the commission’s statutory authority under the Federal Power Act.” The EDC proposal would undermine the role of ISO-NE as a neutral market operator and “result in New England wholesale energy market outcomes that are unjust and unreasonable,” the company said.

The Conservation Law Foundation contended that the EDCs cited no legal error or new facts but nonetheless requested “major additional — and quite novel — determinations of law and fact about which the commission has received no argument or supporting evidence.”

The CLF contested the utilities’ assertion that natural gas pipeline constraints are the cause of the fuel security situation in New England, citing testimony of ISO-NE Vice President of System Operations Peter Brandien, who said fuel supply issues result from a broad set of operational concerns and factors that are potentially responsive to a broad range of market solutions that the RTO and its stakeholders are only now beginning to explore and discuss.

‘Expensive Approach’

“In addition to not disclosing their interest in the Access Northeast project, the EDCs also do not disclose the significant body of evidence submitted in past state proceedings on the need for added pipeline capacity, which is far from conclusive,” NextEra said.

The company said that if the potential need for new pipeline capacity is limited to a few peak days each year, “as projected by the Eversource EDCs’ own expert,” the proposed new pipeline capacity would be “a very expensive approach to addressing a winter peak resource sufficiency concern, with the Eversource EDCs’ expert projecting a $526 million annual cost, after taking into account the return on the capital investment and [operations and maintenance] costs annually to operate the capacity.”

The New England Power Generators Association filed an answer calling “absurd” the utilities’ contention that long-term cost-of-service contracts are a form of market design improvement.

“The EDCs’ requests for findings are outside the scope of this proceeding and are more properly styled as a complaint or request for rehearing rather than a motion for clarification,” NEPGA said.

The commission ordered improvements to the market design and reaffirmed its support for market solutions but “provided no further direction with respect to the longer-term market improvements, much less that they include long-term pipeline capacity contracts,” NEPGA said.

Healey asked the commission to summarily dismiss the clarification motion and see it “for what it is — a bald attempt by monopoly utilities that stand to profit from new pipeline infrastructure trying to saddle electric ratepayers with the costs of a pipeline that private investors are unwilling to fund.”

August 20, 2018

Overheard at MISO Market Symposium

INDIANAPOLIS — For years, MISO executives have been warning about the coming of a future electric grid that upends traditional utility operations. The time of reckoning may be close at hand, according to industry experts speaking last week at the RTO’s second biennial Market Symposium.

miso market symposium electrification — MISO Market Symposium underway | © *RTO Insider*

MISO billed the event as a preparation for wholesale market design that includes the trends of “digitalization, de-marginalization and decentralization.”

CEO John Bear said that when he tells people he works in the energy industry, few are “wowed” by how fast the technology and innovation moves.

“But that’s changing,” Bear said, adding that 88% of MISO’s 90-GW interconnection queue is composed of renewable generation.

“The future is really already here in varying degrees,” said MISO board member Mark Johnson. “The bulk electric system, depending on where you live, already operates differently. … Bidirectional flows on the grid are more prevalent and will continue to occur.”

‘Fork in the Road’ for Markets

FERC Commissioner Richard Glick said the industry is at “the proverbial fork in the road in how we view markets.”

Glick said he is astounded at today’s wind penetration levels, which exceed any forecasts he provided while working as a wind energy lobbyist. “Lobbyists don’t lie, but you know, we pick the highest [statistics],” he joked.

Today’s energy industry is divided into two camps, Glick said, with one supporting returning to a centralized grid with an emphasis on older-technology power plants that offer resilience.

“The other camp is saying you can’t put the genie back in the bottle. … And I’m certainly in that particular camp,” he said, adding that “people just aren’t investing” in centralized power plants. “I hope we move forward, and don’t move back to the system of the past.”

However, Glick thinks the transmission system will remain a key factor in future markets.

“Decentralization doesn’t mean no transmission system,” Bear agreed. “It means a different transmission system.”

Transmission and Distribution Blurring

Several speakers agreed that transmission will become increasingly synonymous with the distribution system.

Gabe Murtaugh, CAISO regulatory policy developer, said the future transmission system will “connect households instead of a power plant that’s 500 to 1,000 miles away for load.”

“We’ve spent the last several years making sure there’s a bright white line between T&D, and that’s changing,” said ScottMadden partner Cristin Lyons.

Rocky Mountain Institute’s Mark Dyson said blockchain technology deployed at scale in the grid will further blur transmission and distribution. Other speakers said MISO could eventually become a founder network for blockchain technology.

But Grid Strategies President Rob Gramlich said he thought the RTO could use more transmission infrastructure first, but only if it aligns its interconnection queue and transmission planning process.

Electrification and Data

Experts agreed that there’s a natural role for electrification in the future grid.

“We’re looking at a world of declining load, and utilities are looking at their bottom lines and saying, ‘Holy cow, either my rates have to go up or my load has to go up,’” Lyons said.

“We’ve seen stagnant load growth for the past 15 years, but I think that’s about to change,” said Andy Lubershane, director of research at Energy Impact Partners. He predicted that electrification of transportation, space heating and indoor agriculture will soon drive up load.

Rob Threlkeld, General Motors global manager of renewable energy, said the utility and the automotive industries are more aligned than they ever have been because of the innovations disrupting both.

Responding to an audience question, Threlkeld said he’s not sure if GM will pivot to producing home storage batteries, styling itself after Tesla, but added he wouldn’t be surprised if his company eventually develops them.

Threlkeld said customers are used to managing several activities via smart phone applications, but that same understanding does not yet apply to distributed energy resources: “The electricity market is really new to them.”

Lubershane said data can reveal what motivates customers to purchase smart devices, and they’re not always energy management reasons. He said while Ecobee customers mostly give the smart thermostat verbal commands to adjust the temperature, the second-most used command is to play music.

“I don’t know if disruption is really the word. It’s more an evolution,” said Ryan Wartena, president of energy software company Geli. “If we don’t have metering on the low-voltage distribution system, it’s going to make this [evolution] difficult.”

Georgia Institute of Technology professor Pascal Van Hentenryck said coordination of DER optimization is a major challenge facing energy markets.

Panelists debated the role of the vertically integrated utility in a world where load has leveled off and new generation is often not utility-owned. Some said it was the role of utilities to aggregate and optimize use of DERs and behind-the-meter resources. Wartena said DER aggregators should eventually be able to hand control of DER aggregations over to MISO to shape the load.

Other panelists said now is the time for RTOs to standardize data collection and maintain open architecture computer programs to increase visibility of DERs. Sandia National Labs’ Jean-Paul Watson pointed out that MISO’s markets are currently inhibited by computer programs devised in the late 1990s.

Kate Sherwood, 3M senior director of grid modernization, said data are needed to forecast use of harder-to-control distributed renewables.

“Uncontrolled environments require more data to manage,” Sherwood said.

Lyons predicted it will take another 10 years before the industry can realize the benefits of collecting so much data by turning them into actionable grid insights and better managed energy use. “In five years, we’re going to have a lot of data, but we won’t have cracked the code,” Lyons said. She also said states are taking a lead in creating privacy provisions for customers so their home patterns are aggregated for analysis and not individually revealed.

Dyson said MISO is in the thick of a retirement movement. “I think what we’re seeing today is a trend of retirements — coal retirements. And we’re asking if we can replace that generation with renewables. My answer is ‘yes,’ but you’re asking the wrong question,” he said. “The question is not, ‘Can I replace the coal-fired asset?’ The question is, ‘Can I provide all of the services that the coal asset provided?’ And the answer to that question is ‘certainly, and at a lower cost.’”

Dyson said that within a few years it will be difficult to justify the costs of natural gas-fired water heaters in homes. He predicted heat pumps at a neighborhood level could save consumers millions of dollars.

Propped Up Pricing?

Michael Hogan, senior adviser for the Regulatory Assistance Project, said there’s a “real risk” that electrification becomes difficult to manage for grid operators in terms of pricing.

“We’ve gotten away so far with pricing wholesale energy very simply. … We need to talk about security-constrained economic dispatch, not simple economic dispatch,” Hogan said.

“I think the ISOs are getting caught between a rock and a hard place,” said Lawrence Makovich, IHS Markit vice president and senior energy adviser, pointing to renewable incentives, subsidies for some non-carbon-emitting generators and not others, and carbon credits in only some states.

“I see serious market distortions as a result of this. … We’ve gotten to a point where we’ve suppressed prices. If we didn’t have distorted markets, you wouldn’t have to pay for flexibility,” he said, referring to pricing for ramping capability.

Makovich said California can either be cited as a roadmap or a cautionary tale because the state’s carbon emissions have not decreased from 2002 levels despite renewable adoption because artificial market forces rendered zero-emission nuclear plants uneconomic.

“It’s easy to paint a horror picture of California, and I can do the same of Germany,” Hogan responded. He said ERCOT is a better example of renewable integration because its transmission system is truly an energy island. Despite a record-setting summer, ERCOT has not had to curtail load, he noted.

“We’re not seeing ERCOT trying to move in and patch this and patch that … with micro-procurement policies. They’re getting the prices right,” Hogan said.

Makovich agreed that pricing from ERCOT’s operating reserve demand curve seemed to work this summer, raising prices enough to allow some generators to postpone retirement. But he cautioned that the attractive prices might keep more clunky and expensive generation in the market too long.

Hogan agreed that previous generation investments must be jettisoned before the new crop of investment resources can move in. “There’s a problem that market prices are paying for the wrong resources. … We do have a problem of [needing to move] uneconomic resources out of the market before we see real pricing emerge.”

No Operator Bots

Alberto Ruocco, a partner at research firm Gartner, cautioned against artificial intelligence making grid decisions autonomously.

“I think, wisely, the industry has come back and said that’s not the goal,” Ruocco said. He said that while machine learning can work through a lot of data, human operators should be on hand to make decisions. “I don’t think we should abdicate something as important as the operation of the grid. … I think complete delegation of control is not realistic.”

But more digitalization is inevitable, panelists said.

“It’s not ‘if,’ but ‘when’ you need to adapt your digital business model,” said Stephanie Woerner, a research scientist at the MIT Sloan Center for Information Systems Research. She said her recent research found that digital disruptions could threaten an average 28% of future revenues for companies across all industries.

Richard Doying, MISO executive vice president of market development strategy, said it has now become risky to postpone decisions to accommodate new technologies in the energy market.

Bear summed up the discussion by quoting President Dwight D. Eisenhower: “Plans are worthless, but planning is everything.”

— Amanda Durish Cook

August 20, 2018

Canadians Seek Inclusion in Cybersecurity Meetings

By Tom Kleckner

CALGARY, Alberta — Canadian Electricity Association CEO Sergio Marchi took advantage of several opportunities during last week’s NERC Board of Trustees meeting to complain that he and other Canadian stakeholders have been excluded from Department of Homeland Security cybersecurity briefings.

Canadian Electricity Association’s Sergio Marchi | © *RTO Insider*

“We’re forbidden to participate because we are considered, quote unquote, foreigners,” said Marchi, whose association represents integrated utilities, independent power producers, transmission and distribution companies, power marketers and industry suppliers. “The irony is most of our CEO representatives happen to be American citizens.”

Marchi said that over the last year, he and the two Canadian CEOs on the Electricity Subsector Coordinating Council (ESCC), ENMAX’s Gianna Manes and Hydro One’s Mayo Schmidt, have been shut out of the classified briefings.

NERC responded that the Canadians have been excluded because they don’t have the proper security clearance. It added that it is working with industry and government partners to increase the functionality of the Electricity Information Sharing and Analysis Center (E-ISAC) portal, which gathers, analyzes and shares security data across the North American grid.

“NERC as a private company does not have authority to grant or sponsor clearances or to provide access to classified briefings in the United States or in Canada,” CEO Jim Robb said in a statement provided to RTO Insider. “However, NERC will ensure that all NERC events are inclusive of all our North American stakeholders. Simply getting information is only piece of the security pie, and the E-ISAC is in a unique place to analyze and triangulate information to identify threats and mitigation actions to share information that North American stakeholders need to protect their systems.”

Marchi told RTO Insider that the exclusion from the ESCC briefings has become more of an issue under the Trump administration.

“It’s frustrating, and whether it’s NERC or Bruce Walker [the Department of Energy’s NERC representative], they haven’t been able to pinpoint who is blocking us and why,” he said. “This is an example, where everyone says we should be in the meeting, but we don’t know who [is preventing us] and why we are kept out of the meeting. We’re hopeful we can make progress, and the next time the council meets, we can be on the same team.”

Robb acknowledged the issue while briefing trustees on the ESCC’s recent discussions. He said improving information sharing with Canadian industry members is “complicated territory.”

Marchi said the CEA was willing to give Robb a “proper runway” to improve the process.

A former member of the Canadian Parliament and cabinet minister, Marchi also objected to what he said was a 25% budget increase for the E-ISAC as part of NERC’s overall 9.5% budget increase.

“Our Canadian utilities receive the same information from Canadian sources, but it’s quicker and of higher quality,” Marchi said. “Why should we pay twice for information that is of less quality, and that is late on arrival?”

In his statement, Robb pointed out that Canadian stakeholders were able to file comments on the 2019 budget and business plan as part of NERC’s “open and transparent” budget process. He said the organization takes their concerns seriously.

“[We] had multiple meetings, phones calls and written exchanges with [Canadian stakeholders] to discuss the 9.5% increase,” Robb said. “While we acknowledge [their] concerns, we believe the budget approved by the NERC Board of Trustees is the right answer for industry based on all feedback we received.”

Robb acknowledged that the Canadian government has, at times, “authorized release of information to Canadian industry sooner than the U.S. government.” He said NERC recently executed a memorandum of understanding with the Canadian Cyber Incident Response Centre to help improve E-ISAC access to the Canadian government’s security information.

Marchi said the CEA will monitor the next budget cycle and “consider our options” at that time. He said the E-ISAC’s relationship with U.S. security organizations is “an important piece of that puzzle.”

“It’s very important those relationships are picture perfect, if a new investment to the E-ISAC will create the outcomes they’re intended to,” he said. “We need to continue to work closely as our industry evolves at a rapid pace and cyberattacks continue at a great pace. This work must be done in a cost-effective and efficient manner, because both regulators and customers demand and expect it.”

NERC Board Chair Roy Thilly said improving the involvement of Canadian utilities in the E-ISAC “is a very high priority” for the trustees. “We ask the Canadian utilities to work with us to help you provide that value.”

Earlier in the week, the NERC board and Canadian regulators held their annual meeting. NERC said Canadian regulators were briefed on cybersecurity, including the E-ISAC long-term strategic plan and the organization’s reliability assessment and performance analysis capabilities.

Robb Reflects on Cross-border Interconnections

Robb noted several significant milestones during his president’s report, pointing to NERC’s 50th anniversary and the 15th anniversary of the 2003 blackout in the Northeast. As Robb put it, a vegetation contact in Ohio led to power failures in Ontario and “returned the favor” for 1965, when a transmission line tripped in the Canadian province and blacked out Manhattan.

“These anniversaries and our meeting in Canada have given me a chance to reflect on the interconnected nature of our grid and the importance of our international collaboration,” he said. “The Electric Reliability Organization [ERO] is an agency for driving a common approach to reliability and security. We have a tremendous amount of work to do together, and it is a high priority for all of us.”

In addition to establishing reliability coordination services in the West, Robb listed as top issues security, integrating new technology, and a changing resource mix that could halve the U.S.’ coal fleet by 2030. (See related story, Sept. 4 Key Date for Potential Western RC Providers.)

Robb said the early returns on NERC’s six-month-old, five-year strategic plan have been “very positive,” but that there is a “tremendous amount of work to do.”

“It’s a very complex system to defend,” he said of the grid.

The continuing retirements of coal- and nuclear-fired generation, combined with the rapid deployment of variable resources and natural gas plants, is a problem “no one agency or individual forum can solve,” Robb said.

He said NERC has started work on a guideline to bring “greater clarity” regarding what kind of contingencies need to be studied.

“There are serious issues in the Northeast and desert areas of the Southwest,” Robb said. “We need to move along very quickly on this.”

CEO: AESO’s Challenges Same as Everyone Else’s

The Alberta Electric System Operator (AESO) faces steep challenges in meeting legislative mandates to phase out its coal-fired generation — which accounts for 40% of its installed capacity — and produce 30% of its energy from renewables by 2030. Adding to the challenge, it has very little hydro and no nuclear power in its generation mix.

But that’s no different than the challenges facing other jurisdictions, CEO David Erickson said.

AESO CEO Dave Erickson (left) and DOE’s Catherine Jereza | © *RTO Insider*

“With the integrated nature of the grid in North America, working together to solve those problems is important,” he said. “That’s the only way to get through this transformation, with the increasing penetration rate of renewables, cyber threats and changing generation mix. Those are real challenges we need to work together to solve. The ISO/RTO community has a big role.

“That said, NERC has an enormous role to get through this. I encourage the industry, I encourage NERC to work together. Whether we like it or not, we’re in this together. There’s a better path that’s more efficient and a lot more effective, if we do this together.”