Page 1127 – RTO Insider

November 4, 2018

Few Clear Lines in MISO Storage as Tx Plan

By Amanda Durish Cook

CARMEL, Ind. — A recent MISO workshop on storage providing transmission services made clear how much the technology is blurring the once clear lines between generation and transmission.

In opening the Oct. 31 workshop, MISO Director of Planning Jeff Webb jokingly nodded to the industry’s choice of “SATA” as shorthand for “storage as a transmission asset,” saying: “Happy Halloween. Welcome to what we’re calling SATAN’s workshop.”

MISO last month detailed how SATA would be evaluated in its annual Transmission Expansion Plan reliability studies compared with traditional solutions. The RTO is proposing that costs for storage projects selected as a preferred transmission solution would be recovered in local transmission zonal rates while avoiding double recovery for the same service in the energy market. (See MISO Contemplates Storage as Tx Reliability Asset.)

“I don’t expect … that we’re going to have a lot of energy storage resources that we’re going to consider to be the preferred option,” Webb said.

For now, MISO is only proposing a model for storage to act as a transmission reliability solution, solving thermal, voltage or stability issues. Beyond that, Webb said the RTO will have to pick through more complex Tariff issues.

He said it will hold off on discussions around evaluating storage as economic transmission, competitive storage projects and how regional cost sharing for high-voltage transmission projects applies to storage.

The Interconnection Question

MISO has laid out potential paths for interconnecting SATA, including only requiring the MTEP process — not the interconnection queue — for transmission-only assets. An interconnection queue requirement would kick in if a storage owner decides to begin offering market services.

Alternatively, MISO could require entering the interconnection queue for all SATA, even for assets that don’t plan on participating in the energy market, Webb said. Some stakeholders also contend that SATA providing some market services should not be subject to a queue requirement unless it plans to offer capacity.

For a storage asset that has completed the interconnection queue, MISO has proposed that the owner could decide to provide market services when the RTO doesn’t need transmission services. Webb said it’s “you’re a wire unless we say you’re not” philosophy, similar to CAISO’s approach. (See CAISO Updates Storage as Transmission Asset Plan.) MISO must also determine how registration should differ between transmission and generation storage assets.

“There seems to be a fair amount of passion around these issues, particularly around interconnection issues,” Webb said. “There are those that say if you’re going to treat it as a wire, treat it as a wire. Don’t treat it the way it acts; treat it the way it’s categorized.”

Webb said that if storage-as-wires is required to enter the interconnection queue, it may have to compete for scarce transmission capacity with other proposed generation, potentially disadvantaging other generators.

He also noted that the approximately three-year backlog in the queue might hinder the ability for storage resources to go in service more quickly than traditional transmission lines. He said MISO could also add steps to the MTEP process that consider the potential impact of SATA on queued generation. Webb said MTEP studies could capture even the benefits of energy withdrawals to potential generation.

“That unloading of the line will probably be beneficial for generations seeking to load up that line,” Webb said. “Part of the problem with getting your head around these devices … is optimal location on the system.”

MISO has said that if storage would “negatively impact potentially interconnecting generation in the area, it is not a good MTEP solution.”

But Customized Energy Solutions’ David Sapper said that statement could use more clarity.

“That sounds good on a bumper sticker, but we don’t know what ‘negatively’ means. We don’t know what ‘potentially’ means. We don’t know what ‘area’ means,” he said.

Webb said MISO will offer more detail and that it is more focused on finding the grid locations that would benefit most from SATA characteristics.

CleanGrid Alliance’s Rhonda Peters said the queue should be required even for transmission-only storage, unless MISO can “clearly demonstrate” that the storage projects would “never inject during times of congestion.”

Great River Energy’s Angela Maiko said MISO should evaluate both charging and discharging scenarios as part of MTEP’s no-harm evaluations, to find the “worst-case scenario.”

Webb said MISO should also compare the lifespan of storage devices against lines, evaluating a battery’s possible 10-year lifespan with the average 40-year lifespan of traditional transmission.

But stakeholders also said MISO might consider the evolving grid and the risk that traditional transmission may well become a stranded asset as the energy landscape changes.

Market Control?

Webb said MISO is still contemplating whether it should adopt control of SATA through market commitment and dispatch because storage injects and withdraws energy, unlike traditional wires. He said the extra control might be needed “primarily for energy balance and orderly control of the asset.”

Entergy’s Yarrow Etheredge, representing MISO’s Transmission Owners sector, said there’s no need for the RTO to create a new process to functionally control SATA, suggesting that current transmission operating procedures can be used.

Steve Swan, MISO senior real-time operations engineer, said transmission owners’ control of storage devices likely won’t affect the short-term energy balance, but an imbalance could develop once 500 MW of SATA interconnects because the RTO won’t have enough regulating reserves.

Other stakeholders countered that transmission operators would not operate their assets in a way that would harm the MISO system. Still others pointed out that today, transmission operators don’t have a role that involves injection of energy and that such injections must be accounted for in the energy market.

MISO will continue to discuss the finer points of how storage will function as a reliability transmission asset through early next year. The RTO has not committed to a date for when it will release a draft proposal.

November 4, 2018

Nearing 1-Year Mark, Glick Rejects ‘National Security’ Grid Risk

By Rich Heidorn Jr.

WASHINGTON — Nearing the end of his rookie year, FERC Commissioner Richard Glick last week reiterated his opposition to the Trump administration’s efforts to protect coal and nuclear generation, rejecting the notion that national security is at stake.

The luncheon speaker for the second day of the Energy Bar Association’s Mid-Year Energy Forum, Glick opened his address with wishes for a “speedy recovery” for Commissioner Kevin McIntyre, who stepped down from the chairmanship Oct. 24 after disclosing a “serious setback” in his battle with a brain tumor. McIntyre last appeared in public at the commission’s July meeting. “We hope he’s back at 888 First St. [FERC headquarters] as soon as possible,” Glick said.

After that, Glick reflected on his first 11 months in office and the “resilience” debate sparked by the Department of Energy’s proposals to deliver on Trump’s campaign promise to save the coal industry. Last month, the administration reportedly dropped DOE’s proposal to invoke emergency powers to provide price supports for “fuel secure” generation following opposition from the National Security Council and National Economic Council. (See Chatterjee Dodges as DOE Spins on Coal Bailout.)

“Fortunately, at least according to press reports, that particular approach may be waning,” Glick said. “It’s hard to tell … we still hear from the secretary of energy … and others in the Department of Energy — suggesting that we have a national security emergency. The concern I have — and both parties do this — people overuse the term ‘national security.’”

Glick, a Democrat, agreed that policymakers “should be prepared for low-frequency, high-impact events” such as extreme storms and cyberattacks. “This isn’t a new issue … [NERC has] been looking at this issue for a number of years. They haven’t always been calling it ‘resilience.’”

If gas pipelines are at risk from cyberattacks, “let’s try to figure out how to solve the cybersecurity problem,” he said. “We should figure that out, not try to figure out some other solution that seems to be aimed elsewhere. And I think everyone recognizes if we do have issues with blackouts … the issues are mostly going to be in transmission and distribution, not necessarily generation.”

The commissioner rejected the argument that the Supreme Court’s 1944 Federal Power Commission v. Hope Natural Gas Co. ruling ensures generation owners will not lose money on their investments. “I don’t think that’s what Hope said, especially in a competitive market. … Not everyone can make money. There’s going to be some companies that do well, and some aren’t.”

Glick also noted the commission’s April order making it easier for renewables to interconnect with the grid (RM17-8) and said he hoped it will act soon on an order to encourage aggregation of distributed energy resources in wholesale markets. “I think that has the potential to be a big boon, both for reliability but also for those technologies and certainly for green energy,” he said. (See Ready to Act on DERs, FERC Tells Congress.)

November 4, 2018

PSEG, GridLiance Spar over Order 1000

By Rich Heidorn Jr.

WASHINGTON — Public Service Electric and Gas has never been a fan of FERC Order 1000. No wonder.

In 2014, PJM staff selected PSE&G to construct a $300 million transmission upgrade for Artificial Island — the RTO’s first competitive project — only to have the RTO’s Board of Managers reopen the bidding following protests from spurned bidders and others. PJM later awarded most of the project to LS Power. (See PJM Board Puts the Brakes on Artificial Island Selection.)

“I’d like to see the whole thing repealed,” Larry Gasteiger, chief of federal regulatory policy for PSE&G’s parent, Public Service Enterprise Group, said during a panel discussion on the landmark order at the Energy Bar Association’s Mid-Year Energy Forum last week.

Gasteiger, a former FERC chief of staff, acknowledged that that outcome is unlikely. He noted that the commission has taken no action to change the rule in the two years since it convened a technical conference to review its performance. (See Five Years Later, FERC Takes Another Look at Order 1000.)

But he said it has not met the commission’s hopes for creating competition. “Outside of the organized markets there has not been any competitive transmission bidding opportunities. Within the organized markets, it’s been mixed … to say the least. SPP’s Walkemeyer project is almost a poster child: spending $5 million on the competitive process for an $8 million project … that got canceled.” (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

He said relying on least-cost transmission solutions is akin to buying a $3,990 Yugo, the boxy import car mocked in the 1980s for its low quality.

Justin M. Campbell, chief development officer for GridLiance, a transmission developer backed by the private equity firm Blackstone Group, conceded the order has resulted in cumbersome solicitation processes.

But he said competition is essential to keeping transmission costs — which have risen to 10% of customers’ bills, from 6% in 2006 — under control. He cited LS Power’s winning bid on MISO’s Duff-Coleman project, which came in at $50 million, well below the projected $58.6 million.

He said competition has been hamstrung by state policies driven by incumbent transmission owners and RTOs’ “categorical” exemptions from competition for certain types of projects, such as those for reliability, projects whose costs are allocated locally or solutions below 300 kV.

Campbell rejected Gasteiger’s Yugo comparison, saying the developers competing for projects are not “two-men-and-a-laptop type of outfits.”

“What you’re going to see is Duke [Energy,] Edison [International and] American Electric Power. You’re going to see companies that own tens of thousands of miles of transmission and are fully capable — just like the incumbents,” he said, adding that competitors use many of the same engineering procurement construction (EPC) contractors as incumbents.

“The way we’re able to save cost is in more efficient design. It’s in how we handle the risk allocation between the customer and developer and EPC contractor. So, it’s things like that that [allow savings], not lowballing construction or anything like that.”

He cited a study the Brattle Group did for GridLiance and LS Power that found competitive projects — which often include cost caps or other cost controls — have averaged 40% below initial project cost estimates and could ultimately produce savings of 55%. The report said ratepayers in the U.S. and Canada could save $8 billion over five years if ISOs and RTOs increased the share of transmission investments opened to competition to 33%, up from 2% currently.

Transmission Planning: How Low Can You Go?

Other panelists discussed transmission planning and rates.

Theodore Paradise, ISO-NE | © *RTO Insider*

Theodore Paradise, ISO-NE’s assistant general counsel for operations and planning, said the rise of behind-the-meter generation and distributed resources may require a rethinking of transmission planning and the distinction between federally regulated transmission and state-regulated distribution. “Maybe it’s time for all of us to figure out where the power system is going as we do system planning looking out 10 years. Do we need to plan down to 115 [kV] for transmission?”

Consultant Paul Dumais, a former Avangrid executive, praised FERC’s Oct. 16 order changing how the commission sets TOs’ return on equity rates, a change expected to increase the ROE cap for Avangrid and other New England Transmission Owners (NETOs). (See FERC Changing ROE Rules; Higher Rates Likely.)

Paul Dumais, Dumais Consulting | © *RTO Insider*

When FERC approved incentive ROE adders for a $1.5 billion Avangrid project about 10 years ago, he said, “it really changed things in the company. There was a focused effort to make sure that capital was appropriated. … And in large part I believe it was due to the fact that there were incentives given for the particular risks and challenges of that project.”

When FERC reduced the NETOs’ ROE cap, however, Avangrid could only collect half of the incentive, Dumais said.

“The Iberdrola folks in Spain [then Avangrid’s parent company] felt they had been bait-and-switched.”

Dumais said he was hopeful that the commission’s new policy will allow it to resolve ROE complaints within the 15- month limit on refunds. Maine regulators, he noted, complete full utility rate cases in 12 months.

November 4, 2018

FERC Again Denies MISO Wind Developers’ Queue Complaint

By Amanda Durish Cook

FERC last week again declined to modify MISO’s interconnection queue rules, rejecting rehearing requests from wind developers who say the RTO is moving too slowly for them to meet the federal production tax credit deadline.

The Oct. 31 order is the second time FERC has denied EDF Renewable Energy’s request that MISO be required to devise a fast-track option in its interconnection queue for projects that can demonstrate readiness for development (EL18-55-001). (See FERC Sides with MISO in Queue Design Dispute.)

FERC once again declined to modify MISO’s interconnection queue rules | *E.ON Climate and Renewables*

E.ON Climate and Renewables, Invenergy, Tenaska Wind Holdings and Project Resources Corp. had joined EDF in seeking rehearing. The companies argued that FERC rendered a decision without addressing the situation’s harm to consumers or analyzing the need for a one-time departure from queue rules considering the 2020 PTC deadline.

But FERC said EDF still has not met its burden of proof to show that that MISO’s queue design is unreasonable, unjust or discriminatory. The commission also said “some of EDF’s claims about queue delays were overstated,” as the RTO said that most interconnection customers would complete the queue in time to begin commercial operation before Dec. 31, 2020, the deadline for receiving the full PTC. In any case, FERC said queue delays that might preclude some interconnection customers from the full advantage of a tax credit “does not amount to MISO’s failure to make reasonable efforts under its Tariff.”

“Delays in the interconnection process can be due to actions outside of MISO’s control, such as customer withdrawals and actions of affected systems,” FERC pointed out.

But, as with the last order, the commission ended with a warning for the RTO to improve its queue practices: “We strongly urge MISO, along with its stakeholders, to make addressing MISO’s interconnection queue processing delays a priority. We urge MISO to look to the other RTOs for best practices, closely examine the resources it is dedicating to the interconnection study process and consider whether additional resources would alleviate queue delays, as well as fully consider other approaches for improvement.”

MISO’s queue contains about 490 projects totaling more than 80 GW, down from 90 GW earlier in the fall.

The RTO has been working to speed up the queue through more stringent site control requirements and increased milestone payments. Staff say the changes will encourage stalled projects to withdraw from the queue earlier in the process. (See “MISO to File Queue Changes,” MISO Queues up Interconnection Options.)

The RTO has also eliminated the dynamic stability, short-circuit and affected-system analyses from the first phase of the queue’s definitive planning phase. The studies are repeated in the queue’s later phases. (See MISO Plan to Reduce Queue Studies Gets FERC Nod.)

November 4, 2018

Overheard at EBA’s Mid-Year Energy Forum

By Rich Heidorn Jr.

WASHINGTON — The Energy Bar Association’s Mid-Year Energy Forum last week rekindled long-running debates over FERC Order 1000, state-federal jurisdiction, utility rate structures and the Public Utility Regulatory Policies Act. And this year, there was a relatively new issue of contention: grid resilience.

Here’s the highlights of what we heard.

Resilience Debate Comes to EBA

Kim Smaczniak, Earthjustice | © *RTO Insider*

Kim Smaczniak, an attorney for Earthjustice, debated attorney William Scherman over whether the retirement of coal and nuclear generation is undermining the grid’s resilience.

“Is there a resilience crisis in the bulk power system? The answer is no,” Smaczniak said. “There is no data that has demonstrated a crisis on the bulk power system today.”

She contended the grid’s biggest resilience threat is climate change, citing National Oceanic and Atmospheric Administration data that seven of the 10 costliest storms in U.S. history occurred in the last 10 years. “That’s not going away,” she said. “That’s climate change.”

Scherman, a former FERC general counsel who now represents natural gas pipelines and utilities such as FirstEnergy at Gibson, Dunn & Crutcher, said policymakers must practice the “electric utility version of the Hippocratic Oath” in ensuring reliable service above all else.

William Scherman, Gibson, Dunn & Crutcher | © *RTO Insider*

“We are losing fuel-secure, diverse generation in the country every day, and nothing is being done about it because the mantra is ‘That is the will of the market. We should allow the markets to operate.’ … I sure hope these damn markets are right, because when we finally get to the point of figuring out that they’re not, it will be too late to do anything about it.”

Scherman praised FERC’s ruling declaring PJM’s capacity market not just and reasonable because of price suppression from subsidized renewables and nuclear power. (See FERC Orders PJM Capacity Market Revamp.)

But he said the commission should also have required changes to the RTO’s ancillary services and energy markets because they are interrelated — and that other regions should do similar examinations.

“We have to have a full, comprehensive and holistic review of whether these markets are continuing to work,” he said.

Candice Castaneda, NERC | © *RTO Insider*

Candice Castaneda, a legal and regulatory counsel for NERC, also sparred with Scherman over his contention that reliability is different from resilience.

“Resilience is an inherent characteristic of reliability. … Resilience is a time-based component of reliability,” she said.

“I know of no NERC standard that assesses and defines resiliency standards,” Scherman responded.

Another Plea for PURPA Reform

Idaho Public Utilities Commissioner Kristine Raper and Adam Benshoff, executive director of regulatory affairs for the Edison Electric Institute, called on FERC to address above-market costs and gaming by qualifying facilities under PURPA. FERC in May said it would review how it enforces the 1978 law. (See FERC Sets PURPA Review; Powelson Targets 1-Mile Rule.)

Benshoff said customers of PacifiCorp and Duke Energy both paid more than $1 billion in above-market costs over the last 10 years.

Adam Benshoff, Edison Electric Institute | © *RTO Insider*

He said FERC should reduce the 20-MW limit on QFs in organized markets and change the burden of proof, which is currently on challengers to QF self-certifications. “We’re not advocating for a specific number. … Something less than 20, something higher than zero probably makes sense right now given open access, given the sophistication of the folks that are participating in this process.”

Raper said that although half of Idaho Power’s generation mix is hydro, it must curtail that energy during the shoulder months when its peak is 1,300 MW or less. “They have more PURPA [resources] on the system than that. And this is must-purchase energy. … You’re not utilizing hydro, which is a virtually free resource, and you’re paying anywhere between $30 and $200[/MWh] for PURPA generators. It totally blows away the resource stack and the whole theory of running the least-cost resource. … It’s not fair to ratepayers.”

Kristine Raper, Idaho Public Utilities Commission | © *RTO Insider*

She said FERC’s 1-mile rule is a “red herring” because QF developers are also disaggregating projects to drop below the PURPA limit by registering them as multiple limited liability companies.

She said FERC should allow states more discretion in blocking such gambits by allowing them to treat as a single project those sharing owners, interconnection agreements, facilities, contractors and financing.

Amanda Rome, Xcel Energy | © *RTO Insider*

In a separate panel, Amanda Rome, Xcel Energy’s managing attorney for federal and state regulatory policy, touted Colorado regulators’ policy, which frees utilities from must-purchase requirements for PURPA projects larger than 100 kW unless the project wins a competitive solicitation. The policy is the subject of a federal court challenge.

The most recent PURPA applications, filed last month, sought prices as high as $34/MWh for wind and $63/MWh for solar, she said. In contrast, Public Service Company of Colorado’s most recent all-source solicitation produced 350 renewable bids with median prices of $19.30/MWh for wind and $30.96/MWh for solar.

The solicitation will give the utility a total of more than 5,000 MW of renewables, “and 70% of those are projects that could qualify as QF,” she said.

Collaboration Sought on State-Federal Issues

Former FERC Commissioner Colette Honorable, center, insists “fire tornadoes” are a thing. Listening skeptically are, from left, moderator Matthew Price, Jenner & Block; FERC General Counsel James Danly; Amanda Rome, Xcel Energy; and MISO General Counsel Andre Porter. | © *RTO Insider*

FERC General Counsel James Danly had some advice for his colleagues: Don’t count on the Supreme Court’s Hughes v. Talen ruling for jurisdictional challenges to state energy policies.

The 2016 ruling rejected Maryland regulators’ attempt to subsidize a combined cycle plant, saying it interfered with FERC’s jurisdiction. But the court also said its ruling should not be interpreted as preventing states from supporting generation resources through measures “untethered to a generator’s wholesale market participation.”

“A lot of people enjoy hanging their hat on Hughes. Hughes shouldn’t be read for much more than it really states,” Danly said, echoing an interpretation former General Counsel Max Minzner shared with EBA attendees in 2016. (See Court’s Reticence Frustrates Energy Bar.)

Former FERC Commissioner Colette Honorable, now a partner with Reed Smith, noted states’ increasing activism on energy policy. “It’s not just New York and California anymore,” she said.

In Washington state, for example, voters will be asked Nov. 6 whether they support imposing a $15/metric ton charge on carbon emissions by large emitters such as refineries, power generators, and oil and gas producers.

Colette Honorable, Reed Smith | © *RTO Insider*

Honorable said she is not optimistic that federal policymakers will adopt carbon pricing. “I’m really a positive person, but I will say I don’t see it on the horizon any time soon,” she said. “We desperately need it.”

She agreed with MISO General Counsel Andre Porter on the need for collaboration among states, RTOs and federal officials. With the threat of year-round forest fires in the West and cyberattacks on utilities, “it’s a new day. It requires our collective thinking,” she said.

Porter said issues as important as reliability, resource adequacy and market efficiency should not be decided in the courts through adversarial processes. “I think there’s a more collaborative, and likely better, way to go about addressing these issues,” he said, citing MISO’s “abundantly transparent” stakeholder process and its work with FERC and the Organization of MISO States.

He cited as an example jurisdiction over sales for resale on the distribution grid. “I’ve often heard people say, ‘Who wins in this debate over federal and state jurisdiction?’ I actually hope no one wins. … It’s not a competition. … The focus through all this has to be continued collaboration to ensure we’ve got a reliable, efficient and adequate grid.”

November 2, 2018

NYISO Management Committee Briefs: Oct. 31, 2018

By Michael Kuser

AC Tx Project Under Board Review

RENSSELAER, N.Y. — NYISO’s Board of Directors continues to perform due diligence on the AC Public Policy Transmission Project and could issue a decision at its Dec. 6 meeting or early next year, interim CEO Robert Fernandez told the Management Committee on Wednesday.

The MC in June approved a staff report that recommended joint proposals by North America Transmission and the New York Power Authority to build two 345-kV transmission projects that could cost $900 million to $1.1 billion. (See NYISO MC Supports AC Transmission Projects.)

Any board amendments to the report would require stakeholder review, Fernandez said. Former CEO Brad Jones informed the MC last month that the board had asked for additional data on the project.

Fernandez also announced that Deputy General Counsel Karen G. Gach is now the ISO’s acting general counsel.

NYISO Strategic Plan 2019-2023

Rich Dewey, NYISO executive vice president, asked MC participants for feedback on the ISO’s five-year strategic plan, “which is illustrative of NYISO’s plans to respond to industry changes including evolving policies and disruption brought on by new technologies.”

“Front and center to the discussion was how do we prioritize these changes,” Dewey said.

The plan identifies six strategic initiatives to address the evolving nature of New York’s power grid as large-scale renewables and distributed energy resources connect and place new demands on electricity markets and grid operations, Dewey said.

The initiatives are: grid reliability and resilience; efficient markets; new resource integration; integration of public policy; technology and infrastructure investment; and an efficient and flexible business model.

“This plan is a confirmation by the board that energy markets are more effective in setting the price signals needed to incent new investment,” Dewey said.

Takeaways from a June 12 joint board/MC meeting were to continue exploring fuel security issues and how DER and storage can help provide resilience, as well as to consider what alternative market changes might protect system reliability and revenue adequacy in the event that the cost of carbon is not incorporated into the wholesale energy markets.

Con Ed’s Quin New MC Vice Chair

The MC elected Jane Quin, director of the energy markets policy group for Consolidated Edison, as vice chair.

“I view the stakeholder process as a keystone of NYISO’s success and am looking forward to playing a more significant role in contributing to that success,” Quin said.

Before serving in her current role, Quin was executive assistant to the CEO of Con Ed from 2013 to 2015.

2019 Budget

The MC approved a 2019 budget totaling $168.2 million, including an 8.03% increase in revenue requirement from this year’s budget and a 0.45% decrease in projected megawatt-hours, for an overall Rate Schedule 1 increase of 8.51%.

Alan Ackerman of Customized Energy Solutions, chair of the Budget and Priorities Working Group, presented the budget, which the board will consider Nov. 13.

Repayment of a $30 million loan to finance an energy management system/business management system upgrade project is driving up spending, Ackerman said. The ISO plans to add 15 new positions over the coming year.

Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said the group had decided “with regret” to oppose the 2019 budget because it “could not get comfortable” with a budget increase of more than 8.5%.

Improving Public Policy Tx Planning

The MC approved Tariff revisions to improve the efficiency of the ISO’s short-term Comprehensive System Planning Process, with the board expected to vote on the issue at its Nov. 13 meeting.

The revisions would eliminate the requirement that the Public Service Commission issue an order before the ISO begins evaluating transmission solutions, a regulatory “pause” that is often too long, according to the grid operator.

Yachi Lin, senior transmission planning manager, presented the same report she did at the Business Issues Committee meeting earlier in October. (See “Improving Public Policy Tx Planning,” NYISO Business Issues Committee Briefs: Oct. 10, 2018.)

Multiple Intervenors and the city of New York opposed the changes.

Under the proposal, the PSC continues to retain the ability to cancel or modify an identified public policy transmission need prior to the ISO’s selection of the more efficient or cost-effective solution, which would halt the evaluation or result in an out-of-cycle process to address the modified need.

November 2, 2018

ERCOT Takes Healthy Reserves into Winter, Spring

By Tom Kleckner

Having successfully met system demand this summer despite tight reserve margins, ERCOT said Thursday it will have “sufficient” generation to meet smaller load during the upcoming winter and spring.

According to the grid operator’s final seasonal assessment of resource adequacy (SARA) for winter (December-February), operators will have almost 80 GW of capacity available to meet a projected peak of 61.8 GW. The forecast is based on normal weather conditions during peak periods from 2002 to 2016.

The Papalote Creek Wind Farm rises about the plains of South Texas. | © *RTO Insider*

ERCOT has added 325 MW of capacity since its last SARA, including 72 MW of winter capacity from two wind farms and 219 MW of gas-fired generation expected to be in service for the winter.

Pete Warnken, ERCOT’s manager of resource adequacy, cautioned reporters during a conference call against taking a rosy outlook based on reserve generation. In 2011, the grid operator was forced to resort to rolling blackouts when freezing temperatures knocked generation offline in the face of increasing demand.

“Winter can be very volatile, as far as temperatures and demand, and we account for that in our extreme [planning] scenarios,” Warnken said.

ERCOT’s preliminary spring SARA (March-May) forecasts a seasonal peak of 61.6 GW, with an additional 1.1 GW of capacity from a mixture of gas, wind and solar projects expected to be available. The final spring SARA will be released in early March.

System demand peaked at a spring record of 67.3 GW on May 29. The grid operator was also able to meet a record system demand of 73.3 GW this summer.

“We look to the market to add generation resources in response to increasing load,” Warnken said.

The SARA report is based on an assessment of generation availability and expected peak demand conditions. It takes into account expected generation outages that typically occur during each season for routine maintenance, as well as a range of generation outage scenarios and weather conditions that could affect seasonal demand.

November 2, 2018

PJM Begins Campaign for ‘Fuel Security’ Payments

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — PJM on Thursday began its campaign to compensate generators based on their “fuel security,” releasing an eight-page summary of a study that showed the RTO could face outages under extreme winter weather, gas pipeline disruptions and “escalated” resource retirements.

The study, which evaluated more than 300 winter scenarios, was a “stress test … intended to discover the tipping point when the PJM system begins to be impacted,” the RTO said.

“It is clear that key elements, such as availability of non-firm gas service, oil deliverability, pipeline design, reserve level, method of dispatch and availability of demand response become increasingly important as the system comes under more stress,” it said.

PJM said it will publish a paper detailing the study in December and plans to introduce a problem statement and issue charge in the first quarter of 2019, with the filing of any proposed market rule changes with FERC in early 2020.

PJM CEO Andy Ott presents the RTO’s fuel security study at the National Press Club in D.C. | © *RTO Insider*

At a press conference at the National Press Building, CEO Andy Ott said the study was intended to address the concerns of governors and other policymakers about how soon the continued retirement of coal and nuclear units and the increasing reliance on natural gas could result in reliability risks.

Ott said the RTO could consider compensating fuel security through either the capacity market or as a winter reserve product in the energy market. “We feel strongly that … solutions to any dependency or any risk that we see is best done through defining it as an attribute in the markets. We think government intervention is unnecessary … it would be inefficient and more costly. We think a market solution would be best.”

RTO officials on Thursday also gave a briefing on the study during a three-and-a-half-hour special meeting of the Markets and Reliability Committee in Valley Forge, Pa., where several stakeholders urged consideration of the potential costs of the proposal. The study received forceful pushback from former PJM Chief Economist Paul Sotkiewicz, who called the RTO’s plan to offer a problem statement “premature” because the study failed to model existing market rules and operational capabilities that could address the risks, including reserve shortage pricing, industrial load reductions in response to higher prices or increased new resource entry.

“Without any showing that the market rules themselves have failed us — which there is none at this point — why would we go through a problem statement?” he said. “In fact, I can argue that [with] the market design, if allowed to work, we don’t have to worry about any of these issues.”

PJM CFO Suzanne Daugherty, who led the MRC meeting, responded that the RTO was not saying its “market rules are broken.” Ott, however, said the RTO must consider rule changes now that it has evidence that an unpriced attribute such as fuel security can affect reliability. Officials noted that 16,000 MW of the RTO’s 70,000 MW of gas-fired capacity lacks firm gas contracts. PJM’s Capacity Performance rules have encouraged such generators to maintain up to three days of fuel but don’t provide enough revenue to guarantee the two-week span envisioned in the study, Ott said.

“Hope is not a good strategic plan,” he said. “These are attributes that we depend on in [operations] and we’re not paying for them. I don’t think that’s sustainable.”

Ott also said the study would provide insights for the resilience docket FERC opened in January (AD18-7). (See Don’t Rush on Resilience, Commenters Urge.) “We really have no specific standard for this term ‘resilience’ in the industry,” Ott said. “There’s nothing in the [NERC] reliability standards that says I have to look at these scenarios today.”

FERC may say “you’re way overemphasizing these risks. … On the other hand, people could say these risks are more severe than you’re accounting for. That’s the conversation we’re going to have. We’re going to have more scenarios that we run. We’re going to have more dialogue. Our point is, engaging this conversation — getting ahead of the game — is in my opinion the prudent way to go.”

Mike Bryson, PJM vice president of operations, explains the study as CEO Andy Ott listens. | © *RTO Insider*

The ‘Tipping Point’

RTO officials said the study, which simulated a two-week cold spell in winter 2023/24, found that PJM would remain reliable during typical winter loads (a 50/50 peak of 134,976 MW) under both the 12,652 MW of retirements announced as of Oct. 1, 2018, and under “escalated” retirements cases.

Both escalated retirement scenarios envisioned an installed reserve margin (IRM) of 15.8%: one assumed an additional 32,216 MW of retirements by 2023, with 16,788 MW of capacity added to meet the IRM; the second assumed that no replacement capacity is added but there were an additional 15,618 MW of retirements, which reduced the IRM to 15.8%.

The RTO also remained reliable in the announced retirements case under all extreme winter load scenarios, a one-in-20 year (95/5) peak load of 147,721 MW. (PJM’s all-time winter peak load of 143,338 MW was set in 2015.)

But combining the extreme load, escalated retirements and pipeline outages resulted in numerous scenarios with voltage reductions, reserve shortages and load sheds of as much as 83 hours — about 3.5 days. The location of the outages would depend on that of the pipeline outages, PJM said.

PJM said a combination of extreme load, escalated retirements and pipeline outages resulted in numerous scenarios with voltage reductions, reserve shortages and load sheds. | *PJM*

What are the Odds?

RTO officials said they had not looked at the probabilities of the most severe events coinciding over a 14-day span. They are “extreme but plausible scenarios,” Ott said. “‘Extreme’ means relatively rare.”

The RTO modeled disruptions to both single, or radial, gas pipelines (up to 5,051 MW of capacity lost) and parallel or “looped” lines (up to 13,715 MW lost).

The extreme weather, medium-impact disruption assumed the loss of 50 to 100% of the pipeline capacity for five days. The extreme, high-impact break would knock out the line for five days with a 20% derating for the remaining nine days.

Oil refueling was modeled at 10 to 40 truck deliveries per day for sites larger than 100 MW and zero to 10 trucks daily for sites less than 100 MW.

Reaction

The study is certain to be debated by partisans on all sides of the “fuel wars” debate that has raged since the Trump administration proposed price supports for at-risk coal and nuclear plants.

“PJM is doing the kind of analysis that other grid operators should do too,” said Michelle Bloodworth, CEO of coal lobby American Coalition for Clean Coal Energy. “PJM’s analysis shows that accelerated coal retirements could lead to periods when demand for electricity exceeds supply. This should worry electricity consumers in other parts of the country, not just in PJM.”

Renewable advocates said the study was overly narrow.

The American Council on Renewable Energy (ACORE) faulted PJM for its focus “on resource attributes rather than actual performance when it comes to providing needed reliability services.”

“A more comprehensive study would have recognized how renewable energy technologies provide a range of resiliency and reliability attributes to the grid, including flexibility, dispatchability and other essential reliability services,” said Todd Foley, ACORE’s senior vice president for policy and government affairs.

PJM “should not presuppose a fuel supply solution when other options such as transmission enhancement exist,” said Amy Farrell, senior vice president for government and public affairs for the American Wind Energy Association.

Rob Gramlich, a consultant to clean energy groups, said he was pleased to hear Ott indicate a preference for providing compensation through the energy markets. “Really what these power markets need is flexibility, and capacity markets are so crudely defined that they don’t distinguish between flexible and inflexible resources,” he said.

But he said he opposed defining the product as “fuel security.”

“What they’re saying to me is they want winter-peak energy during extreme cold scenarios. That’s a technology-neutral product. ‘Fuel-secure resource’ is not a technology-neutral product. And the difference is, things like wind, which is usually screaming hard during these situations, is providing winter-peak energy.”

Attorney Susan Bruce, who represents the PJM Industrial Customer Coalition, echoed Sotkiewicz’s concern that the study did not account for how industrial customers might reduce demand under the high LMPs that would result under the most stressed scenarios. She said PJM also should consider stakeholders’ “broader conversations about energy price formation.”

Sotkiewicz, who now heads E-cubed Policy Associates, complained that PJM had “stacked” the analysis by using economics to predict generation retirements while ignoring the economics of how the market would replace them.

He cited the wave of coal retirements PJM experienced several years ago after EPA’s Mercury and Air Toxics Standards rule went into effect.

“That turned into an absolute non-event for PJM because of all the new entry that came in through various quarters, whether it was demand response or energy efficiency or new combined cycle gas,” he said. “I’m afraid you’re going to have people with certain agendas taking these results for their own purposes and saying the sky is falling.”

PJM’s Daugherty acknowledged that risk. “We’re trying to make sure as hard as we can [that] the facts of what we did are out there,” she said. “We do recognize … that different pieces of the information could be taken out of context by folks if they choose to do so.”

Next Steps

PJM will continue discussion of the study at a special MRC conference call Nov. 26, and a special MRC in-person meeting Dec. 20.

The RTO also will develop a “frequently asked questions” document. Questions should be sent to natalie.tacka@pjm.com.

November 2, 2018

Edison Takes Partial Blame for Wildfire in Earnings Call

By Hudson Sangree

Edison International’s president said in an earnings call Tuesday that equipment owned by its Southern California Edison subsidiary was at least one cause of a December 2017 wildfire that burned nearly 282,000 acres and resulted in multiple deaths.

The Thomas Fire in Santa Barbara and Ventura counties was the state’s largest wildfire in modern history until a combined series of Northern California blazes, the Mendocino Complex, greatly exceeded it this year. The Thomas Fire was directly blamed for the death of a firefighter and a civilian. Mud and debris flows in its aftermath killed 21 others when heavy rain drenched scarred mountain slopes.

“Based on the progress of our ongoing work in these areas with the information currently available to us, we believe that the Thomas Fire … had at least two separate ignition points,” Pedro J. Pizarro, Edison’s president and CEO, said during the earnings call. “With respect to one of these ignition points, Koenigstein Road, SCE believes that its equipment was associated with this ignition.”

The company hasn’t determined if a second ignition point in the Anlauf Canyon area also involved its equipment, Pizarro said. The California Department of Forestry and Fire Protection is also investigating the fire.

As with other California utilities’ wildfire liabilities, Edison’s could prove costly. California employs a unique system of holding electric providers strictly liable for property damage if their equipment sparks wildfires, even if they followed all rules and regulations. Pacific Gas and Electric is facing billions of dollars in liability for Northern California fires last year, which has undermined its stock price.

Edison may face similar problems. The company reported third-quarter earnings of $513 million ($1.57/share) on Tuesday, compared with $470 million ($1.43/share) in the third quarter of 2017 — the increase largely attributed to deferral of operations and maintenance costs and tax benefits at SCE. But it also discussed its potential financial exposure from the Thomas Fire and highlighted its wildfire prevention efforts with investors.

“Mitigation and prevention are the best defenses against future wildfires,” Pizarro said.

The company’s California plans call for spending $407 million on grid hardening, enhanced operations and “situational awareness” of wildfire risks, he said.

Much of the money will be used to replace 600 circuit miles of bare wire with insulated wire over the next two years in areas at high risk from wildfires, the CEO said. SCE has identified another 3,400 circuit miles of bare overhead conductors in fire-prone regions, he said.

The company’s plans are in line with the goals of SB 901, a bill the California legislature passed this year that requires utilities to file wildfire mitigation plans with the state, he noted. (See California Wildfire Bill Goes to Governor.)

Pizarro said Edison is also seeking to comply with another landmark bill, SB 100, which requires the state to rely entirely on renewable and other zero-carbon energy sources by 2045. The measure sets goals along the way, including achieving 60% renewable energy reliance by 2030. (See California Gov. Signs Clean Energy Act Before Climate Summit.)

“We found the most feasible pathway to reach the state’s 2030 goals to be an electric grid supplied by 80% carbon-free energy made reliable by up to 10 GW of energy storage,” Pizarro said on the call.

“This will support at least 7 million electric vehicles on California roads and nearly one-third of space and water heaters powered by electricity,” he added.

Call transcript courtesy of Seeking Alpha.

October 31, 2018

Western EIM Reports Record Benefits

By Hudson Sangree

CAISO said Monday its Western Energy Imbalance Market has produced more than a half-billion dollars in benefits for participants since its founding five years ago, including more than $100 million in benefits in the third quarter of 2018.

Those third-quarter benefits, driven by high demand and fuel costs in July and August, were the most for any quarter since CAISO started the EIM in November 2014, the ISO said. In Q3, the EIM produced $100.58 million in savings, with its total benefits reaching $502.31 million, it said.

“This clearly illustrates the value of markets to the customers in California and the region,” Steve Berberich, CAISO’s president and CEO, said in a statement.

This table shows the Western EIM’s Q3 2018 gross benefits by participant. | *CAISO*

CAISO and Arizona Public Service (APS) claimed the largest share of third-quarter benefits ($21.02 million and $20.78 million, respectively), followed by PacifiCorp ($17.82 million), Idaho Power ($13.31 million), NV Energy ($11.09 million), Portland General Electric ($9.47 million), Puget Sound Energy ($4.44 million) and Powerex ($2.65 million).

CAISO was by far the biggest net importer of energy during the quarter at nearly 1.336 million MWh, with NV Energy a distant second at 285,971 MWh. By comparison, CAISO’s net imports were just 355,549 MWh during the second quarter, while net exports surged above 1.9 million MWh in the face of solar surpluses.

APS facilitated the largest volume of wheel-through transfers last quarter (364,046 MWh), followed by PacifiCorp’s West balancing area (350,170 MWh) and NV Energy (312,593 MWh). EIM members derive no financial benefit from wheel-throughs, and CAISO said it will continue to examine whether “there is a potential future need to pursue a market solution to address the equitable sharing of wheeling benefits.”

The EIM real-time wholesale market allows CAISO and non-ISO participants to trade energy across the West, often reducing costs and curtailment of renewable resources including solar, wind and hydroelectric power.

Many industry leaders have praised its benefits, including those who oppose the idea of a Western RTO led by CAISO. (See Overheard at Transmission Summit West.) Unlike an RTO, the EIM’s transmission-owning entities retain operational control over their assets, while member generators participate in the real-time market on a voluntary basis.

A CAISO proposal to extend the EIM to include a day-ahead market has been the subject of discussion at industry conferences throughout the West this year. (See CAISO Day-ahead Could be Tailored for West.)

Meanwhile the EIM has been expanding, increasing its reported benefits.

Notably, Idaho Power and Powerex began transacting in the market in April, bringing to eight the number of members participating in the EIM. (See .) That expansion equipped the EIM to serve imbalances for about 55% of load in the Western Interconnection, according to the ISO.

The Western EIM is expanding with new and planned participants. | *CAISO*

Market participants serve more than 42 million customers in an area that stretches from Canada to the Mexican border, including large swaths of Arizona, California, Idaho, Nevada, Oregon, Utah, Washington and Wyoming.

NV Energy, APS, PacifiCorp, Puget Sound Energy and Portland General Electric are already participants.

Five more entities are slated to join the EIM in the next two years. The Balancing Authority of Northern California and the Sacramento Municipal Utility District plan to begin participating in April 2019. The Los Angeles Department of Water and Power, Arizona’s Salt River Project and Seattle City Light are scheduled to begin participating in April 2020.

Public Service Company of New Mexico, the state’s largest utility, is seeking permission from its regulators to join the EIM by 2021, officials announced in August. (See .)

The Bonneville Power Administration has been discussing joining the EIM, most recently in a stakeholder call on Oct. 11. BPA would likely bring its “big-ten” resources to the EIM, officials said on that call, including the Grand Coulee, Chief Joseph and The Dalles hydroelectric projects on the Columbia River. The Columbia basin covers an area roughly the size of France, they noted.

Officials on the call said the BPA could sign an agreement with the EIM as early as the end of 2019.