Page 1107 – RTO Insider

November 6, 2018

Microgrids Seek Path out of Regulatory Limbo

By Michael Brooks

BALTIMORE — The drafters of the 1935 Federal Power Act could not have imagined modern distributed energy resources, let alone a small network of them that can operate independently of the grid.

“The phenomenon that I think FERC confronts and other agencies in Washington confront is that there’s been a lot more technological change than there’s been legislative change for a whole bunch of reasons that are above my pay grade to diagnose,” Commissioner Cheryl LaFleur told attendees of Microgrid 2.0 at the Hyatt Regency Baltimore Inner Harbor last week.

FERC Commissioner Cheryl LaFleur | *International District Energy Association*

“We’re trying to solve 21st century problems using … a 1930s law.”

How microgrids should be regulated was a central topic at the third annual conference held by the International District Energy Association (IDEA), which advocates for distributed generation, district heating and cooling, and combined heat and power.

Christopher Berendt, Drinker Biddle & Reath | *International District Energy Association*

“The reason we’re here talking about this today, probably more than anything else, is that consumer demand is driving us, and that we’re seeing more and more people say, ‘We want to see mixed-use, multi-customer microgrids because we want the variety of benefits that can come out of them,’” Christopher Berendt, counsel to IDEA’s Microgrid Resources Coalition, said during a panel on market design and policies.

Regulatory risk, he said, “acts kind of like repellant to private capital.”

“There is more capital waiting to flow into microgrid investment right now [that] you would not believe,” said Berendt, a partner with Drinker Biddle & Reath. “There is more capital chasing fewer good projects, and what is really needed to unlock those loads of capital and get more good steel in the ground is not the desire to deploy it, but the regulatory frameworks that support project financing.”

Without any direction from Congress, however, regulators must work with what they have. During her luncheon keynote speech, LaFleur pointed to the complications of DER aggregation, which the commission has been working on for nearly two years. (See FERC Rule Would Boost Energy Storage, DER.)

“It seems quite clear that distributed resources can be aggregated and bid into the market and contribute great value. But since they’re, in many cases, behind the meter, what do the states figure out? Who gets the first bite of the value?” LaFleur asked. “How are we going to figure out who pays what to whom in a sensible way? I think our staff has made a lot of progress in thinking about it. I think it can be worked through, but it’s a little more complicated than some of the … issues we usually deal with because of the number of different uses, and because although it acts wholesale when we see it in the markets, it’s actually at the distribution level.”

Commissioner Richard Glick told the Energy Bar Association last week he hopes the commission will act soon to encourage aggregation of DERs in wholesale markets. (See related story, Nearing 1-Year Mark, Glick Rejects ‘National Security’ Grid Risk.)

Dan Dobbs, Anbaric Development Partners | *International District Energy Association*

The industry also faces challenges at the state and local levels over siting rights of way and whether microgrids are defined as public utilities. “One thing all jurisdictions in this country have in common is that they’re not set up for microgrids,” Berendt said

Dan Dobbs, vice president of distributed energy for Anbaric Development Partners, pointed to New York’s Value of Distributed Energy Resources tariff as “a start.” (See NYPSC Takes Subway into Value Stack.)

“It’s not perfect, but it’s a good attempt at getting that value,” he said. But “you really need to be able to value power that comes in and goes out equally. That’s at the retail level, and you need to be able to do that similarly at the wholesale level when you are aggregating resources.”

November 6, 2018

FERC Sets GridLiance’s Zonal Placement for Hearing

By Tom Kleckner

FERC last week allowed GridLiance High Plains to begin rate recovery Nov. 1 for its facilities in the Oklahoma Panhandle but set the company’s proposed annual transmission revenue requirement subject to refund and settlement judge procedures (ER18-2358).

The Oct. 31 order rejected requests from SPP transmission owners to reject the filing or suspend rate recovery.

GridLiance’s assets, 410 miles of 69- and 115-kV lines and related substation infrastructure, were acquired in 2016 from Tri-County Elec. Co-op. (See GridLiance Closes Deal for Tri-County Co-Op’s Tx Assets.)

SPP placed the facilities in Southwestern Public Service’s transmission pricing zone, Zone 11. The RTO said in its August filing that GridLiance’s ATRR and facilities were not large enough to warrant their own pricing zone, and that they were also interconnected solely with Zone 11 facilities.

Tri-County service territory | *Tri-County Elec. Co-op*

It said the addition of the GridLiance assets will increase Zone 11’s ATRR of $112 million by 6.9%. Network integration transmission service charges will rise 2.8% if the ATRR of transmission facilities whose costs are recovered under Schedule 11 (Wholesale Distribution Service) is included, the RTO said.

More than a dozen SPP TOs and cooperatives and the Texas Public Utility Commission protested SPP’s filing, arguing that the RTO did not explain how upgrades GridLiance made to the Tri-County assets benefit existing Zone 11 customers and questioning how FERC could determine the additional costs were fair without analyzing the benefits.

Xcel Energy complained that GridLiance constructed more than $50 million of facilities outside the SPP regional transmission planning process even though the Tri-County load has decreased by at least 23 MW since 2016.

GridLiance said its planned and constructed upgrades address outages from ice and wind storms that resulted from a non-networked system.

Brett Hooton, president of GridLiance High Plains, said he was pleased FERC denied requests to reject the filing or suspend rate recovery.

“We look forward to demonstrating why wholesale loads are entitled to enjoy comparable reliability as the load served by the dominate transmission owners within SPP and how our reliability improvement upgrades meet that goal,” he told RTO Insider.

Commission OKs Revised ‘Financial Interest’ Definition

The commission also accepted revisions to SPP’s bylaws that clarify the concept of a financial interest. With the Nov. 1 order, SPP employees, directors and their spouses, minor children, and any person for whom they have power of attorney or guardianship rights will be allowed to invest in companies that have a de minimis relationship with the RTO and the electric sector (ER18-2376).

FERC agreed that SPP’s rules, developed before the expansion of its membership and market participation, created barriers in recruiting and retaining directors and employees. The commission said the bylaw revisions should continue “to safeguard SPP’s independence” by prohibiting directors and employees from investing in market participants active in the Integrated Marketplace.

FERC Order 2000 bars grid operators, staff and non-stakeholder directors from holding financial interests in any market participant and require them to maintain independence from “any entity whose economic or commercial interests could be significantly affected by the RTO’s actions or decisions.”

November 6, 2018

FERC OKs MISO External Capacity Zones, Dispute Deadlines

By Amanda Durish Cook

MISO can create external zones for its annual capacity auction and place time limits on members’ settlement disputes, FERC ruled in a pair of Oct. 31 orders.

The first order allows MISO to create external resource zones and modify capacity import and export limits to align with them. Excess auction revenues will be divided among load-serving entities with historic supply arrangements that may be affected by the new zones (ER18-2363).

FERC said distinguishing external capacity suppliers from internal ones would preserve the intent of the RTO’s local clearing requirement. “We find it just and reasonable … for MISO to no longer count all external resources, regardless of electrical distance and dispatch control, towards satisfying the local clearing requirements for MISO’s local zones. Continuing to do so would undermine the purpose of the local clearing requirement, which is to ensure that a sufficient amount of unforced capacity is located within each local zone so that each local zone can meet its [loss-of-load expectation] during its local zone peak demand when it is import-constrained,” the commission said.

FERC also brushed aside stakeholder protests that the RTO’s plan was hasty because its current treatment of external resources was not causing reliability issues. “A transmission operator need not wait until there is a reliability event before proposing tariff revisions to prevent one,” the commission said.

It also rebutted municipal agencies’ argument that WPPI Energy’s Nelson Energy Center in Illinois should be considered a border external resource because Exelon’s Quad Cities nuclear plant is considered one. The commission said that while Quad Cities is directly connected to the MISO system, the Nelson plant “requires intervening transmission to reach the MISO transmission system” and doesn’t follow a predictable path. FERC also declined to speculate on municipal agencies’ concerns over how the RTO might treat future external generation using the proposed Grain Belt Express HVDC line, saying such discussion was “premature.”

FERC had rejected MISO’s plan for external capacity zones in August, taking issue with a proposal allowing an external resource bordering more than one local resource zone to choose which zone to participate in during the auction. The commission also rejected a provision that would have allowed holders of evergreen supply contracts written prior to the RTO’s capacity construct to receive historical supply arrangement credits in perpetuity.

MISO responded with edits that made evergreen contract extensions eligible for excess auction revenues for the original term of the contract or two years, whichever is longer, and a new electrical connectivity analysis that ensures external resources bordering more than one local resource zone participate in only one zone. (See MISO Adds Study to 2nd External Zone Filing.)

FERC accepted both changes and said the two-year limit would ensure that resources won’t be able to “permanently avoid the locational price signal that MISO’s resource adequacy construct was designed to provide.” But the commission said that the RTO should notify owners of external resources bordering multiple zones which zone they’ll be assigned to in the upcoming auction. MISO agreed to provide the notice.

Limits on Settlement Dispute Resolution

FERC’s other order allows MISO to bar settlement disputes that are not initiated within approximately four months (ER18-1648-001).

Effective Nov. 1, members have a 120-day time limit for initiating transmission or market settlement disputes and another 90 days to request either an informal or formal alternative dispute resolution if the member doesn’t like MISO’s response. The RTO has two years from the operating day in question to make resettlement corrections. Resettlement outside the two-year cutoff would require MISO and the participant to seek a Tariff waiver with FERC. The commission’s order permits MISO to create a “Limitations on Claims and Adjustments” section of its Tariff.

The 120 days will be counted from the operating day of the market settlement in question or the date of the first transmission settlement invoice. The 90 days are counted from the day the settlement dispute was “resolved or determined” by MISO.

The RTO said the two years would also apply to settlement errors that it “unilaterally discovers without a related dispute submission by a market participant.”

Until now, MISO’s Tariff did not prohibit settlement disputes that are not submitted within specified time periods.

MISO’s first attempt at the dispute resolution filing was met with a FERC deficiency letter, questioning the two-year requirement. (See FERC Seeks Details on MISO Dispute Resolution Plan.) The RTO argued “that the need for market certainty and promptness of claims supports a two-year resettlement period.” It added the definition of “continuing error” to the two-year provision, which covers “continuing, system, software or other execution that is inconsistent with the Tariff.” The term replaces the undefined terms “system error” and “software error,” which MISO used in its first filing.

MISO said it only foresees two kinds of transmission and market settlement errors: those in system procedures or software that take longer to identify or “execution errors,” including human errors, that are more easily identifiable.

FERC said the RTO’s proposal strikes an “appropriate balance between requiring market participants to promptly initiate claims involving readily discoverable one-time MISO errors and the correction of more long-lasting MISO errors that may not be readily discoverable.”

November 4, 2018

MISO Pivots to Near-term Resource Availability Fixes

By Amanda Durish Cook

CARMEL, Ind. — MISO has mostly focused its multiyear resource availability and need initiative on big-picture solutions, but RTO staff now say they will zero in on three short-term fixes that can be rolled out early next year.

The shift comes after stakeholders expressed the need for near-term improvements in MISO’s effort to address the growing mismatch between its changing resource availability and demand. (See MISO Narrowing Options on Resource Availability Fix.)

MISO’s Nov. 1 Reliability Subcommittee gets underway. | © *RTO Insider*

“We agree and we’d like to take some near-term action to give us the space to work on holistic solutions,” MISO Executive Director of Market Development Jeff Bladen said during a Nov. 1 Reliability Subcommittee meeting. “We do need the operational breathing room to work on those long-term solutions.”

MISO will likely make a FERC filing for short-term solutions before the end of the year while spending “the bulk” of 2019 on longer-term improvements, Bladen said. MISO’s near-term objective is to make 5 to 10 GW of additional supply more available by the spring, focusing on stricter load-modifying resource (LMR) obligations, more advanced notice of planned outages to members and firmer planned outage requirements.

“Our goal now is not to get to perfect, but get to better,” Bladen said.

MISO next year expects to focus on how resources are accredited in the annual Planning Resource Auction. Beyond that, Bladen said the RTO will work on new market incentives to spur resource availability and a possible seasonal resource adequacy construct.

Outages

MISO wants to create a region-by-region forward rolling forecast of planned outages in its North, South and Central regions “many, many months in advance,” Bladen said.

The RTO is seeking stakeholder input on the definition of a planned outage and the lead time required. The Tariff does not currently spell out a notification period for planned outages, instead leaving stakeholders to interpret the NERC standard of “well in advance.”

Bladen said MISO received suggestions to deem any outages submitted less than a month in advance as “forced.” Stakeholders have also asked the RTO to consider transitioning to a “total” outage rating for generators that includes planned outages and derates, not simply a forced outage rate.

But Bladen said MISO’s recommendation is to consider all outages and derates as forced outages only during periods of low availability of capacity reserves unless the asset owner has provided ample notice of a planned outage. The RTO has not yet determined a possible notification lead time, nor has it defined what would constitute “low reserves,” though Bladen said it may require a 120-day notice period for an outage to be considered planned and anywhere from 5 to 7% in available reserves before MISO declares low availability.

WPPI Energy’s Valy Goepfrich said the RTO could also simply increase its expected forced outage rates for generators.

Bladen said MISO currently experiences a “double camel’s hump” of planned outages in April and October, when maintenance outages spike. He said increasing outages, combined with diminishing reserves, increase the potential of firm load shedding.

Xcel Energy’s Kari Hassler said the RTO could request that generation owners smooth out the two concentrations of outages during the year.

“This is direct correlation of our aging fleet. … It’s something we have to account for in operations,” Bladen said, adding that MISO’s improved transparency around planned outages will require a “heavy lift” from member utilities. He said the RTO’s planned outage data are only as good as what generation owners provide: “If we don’t know outages are coming, we can’t” inform stakeholders.

Minnesota Public Utilities Commission staff member Hwikwon Ham pointed out that multiple generators that were in poor condition have retired in the past few years.

Bladen said that while a transition to a newer generation fleet is a possibility, MISO should work proactively with what generation it has now to ensure reliability while fleet evolution continues.

“We have to account for these trends, even in the short term. We can’t assume a younger fleet, even if the queue tells us that’s on the horizon,” Bladen said. He also noted MISO is seeing more new resources categorized as LMRs, available only in emergencies.

LMRs

MISO is also recommending calling on long-lead-time LMRs ahead of an emergency declaration rather than after. Some stakeholders have asked that LMRs meet a defined response time, perhaps two hours. Bladen said that was something for future consideration but not yet a MISO recommendation. He also said the RTO recommends requiring LMRs to participate in annual testing of their load-tempering capabilities.

Occidental Petroleum’s Suzanne Mottin said MISO’s suggestions were “concerning.” She said Occidental’s LMR service comes with a contract with its utility and guarantees a notification time. “I don’t know how you roll this out with these contracts,” she said.

Coalition of Midwest Transmission Customers attorney Jim Dauphinais pointed out that LMRs are already subject to performance penalties not applicable to other classes of MISO generation.

Bladen said MISO is seeking that and other stakeholder feedback, noting the RTO is not aiming to make LMR participation so “onerous” that most entities are unlikely to sign up.

MISO will also undertake capital spending next year to make it easier for asset owners to communicate through the LMR availability reporting platform. Stakeholders have criticized the usability of the RTO’s current setup.

Bladen also asked for stakeholder feedback on MISO’s recommendation to issue earlier instructions to LMRs in anticipation of tight operations.

“What we’re talking about is the operators being more ready to call on LMRs. They’re pretty smart, and they can see those things in advance,” Bladen said.

MISO will schedule a stakeholder workshop in late November to go over more specific proposals on LMRs and outages, Bladen said.

November 4, 2018

FERC OKs CAISO Changes to EIM Bid Adders

By Hudson Sangree

FERC last week approved CAISO’s proposal to revise its bid adder for the Western Energy Imbalance Market, allowing the changes to take effect Nov. 1.

The revisions limit the megawatt quantity of the bid adder, which reflects the costs EIM resources pay to comply with California’s greenhouse gas regulations (ER18-2341).

EIM resources sending energy to California must comply with the state Air Resources Board’s GHG regulations and pay associated compliance costs. External resources receive a payment to offset those costs when they are dispatched to serve CAISO load. (See EIM Members Seek More Details on GHG Accounting Plan.)

The change addresses stakeholders’ concern that the market might designate a resource as supporting a transfer into CAISO even when the resource would have operated at the same level to serve load outside the ISO.

To deal with the problem, CAISO proposed limiting the hourly megawatt quantity of the bid adder to the resource’s dispatchable bid range between its base schedule and its upper economic bid for the operating hour.

“We find that CAISO’s proposal will more accurately attribute EIM transfers to the actual generation being incrementally dispatched to serve California load and will reduce the attribution to CAISO load of EIM resources that would have generated even without CAISO load, as reflected in EIM base schedules,” the commission said.

However, FERC also directed CAISO to file an informational report on the results of the changes by Jan. 1, 2020. The report is intended to provide greater market transparency and address concerns by CAISO’s Department of Market Monitoring (DMM) that the Tariff changes could undermine market efficiency. (See CAISO, ARB to Address Imbalance Market Carbon Leakage.)

“The report must describe the extent to which situations similar to the scenario described by DMM in its comments to CAISO’s stakeholder process materialize during the 12 months after the implementation of CAISO’s Tariff revisions,” the commission said.

November 4, 2018

Ratemaking Rules Pose Challenge for Tx Technology

By Rich Heidorn Jr.

Energy Bar Association — Peter Esposito, Crested Butte Catalysts, left, moderated an EBA general session discussion on regulators’ difficulty keeping up with new technologies. Also participating were, from left, former FERC Commissioner Nora Brownell; Hannah Polikov, Advanced Energy Economy; Gregg Rotenberg, Smart Wires; Susan Pope, FTI Consulting; Mark Jamison, University of Florida and Kelly Speakes-Backman, Energy Storage Association. | © *RTO Insider*

WASHINGTON — The role of regulators in adapting to new transmission technology was the topic for the opening general session of the Energy Bar Association’s Mid-Year Energy Forum last week, where Mark Jamison gave a history lesson.

Jamison, director of the Public Utility Research Center at the University of Florida, said the telecommunications revolution that followed the breakup of AT&T’s monopoly in 1984 illustrates what he called the “myths” of industry transformations.

“One of those myths is we can … create the future by rearranging the components of the past,” he said. “What happens is when you … start opening things up to competition … the real underlying economics of the system just comes roaring out and it creates a future that we did not anticipate.”

The breakup of AT&T assumed a difference between local telephone service and long-distance service, he said. “Once we opened the markets, we found out that that assumption was fundamentally flawed. The technologies, the customers said, are not distinct from each other.”

Jamison said the electric industry is likely to be upended by technologies such as blockchain and artificial intelligence.

“It could drive us to larger, more expansive utility services, or it could shrink them down further. It all depends upon how the economics actually play out,” he said. “Blockchain would tend to disassemble things; artificial intelligence could put things back together again, make them even bigger. We just don’t know.”

Former FERC Commissioner Nora Mead Brownell also cited blockchain and AI as technologies she is watching. She also is keen on transmission technology.

“We spend time talking about generation mix — candidly perhaps a little too much — and not enough time talking about all the [transmission and distribution] technologies that can add efficiency, add transparency, have applications that solve for multiple problems, like cyber, like customer interaction … and solve for reliability and resiliency,” said Brownell, who serves on the boards of several technology companies in addition to that of U.K.-based utility National Grid.

A Call for Short-term Thinking

Gregg Rotenberg, CEO of Smart Wires, called for less emphasis on long-term transmission planning and more focus on short-term needs. “We’re getting far worse [at predicting the needs of the future grid]. This changeover in generation … is incredibly difficult to predict. And just as much innovation is going on on the consumer side. So, if you can’t tell me where generation is going to be, if you can’t tell me what load is going to be at any one substation, how could a utility possibly predict what their grid needs going forward?” he asked.

“What we’ve really done is built a system that takes three to five years to make the simplest of decisions because we treat every decision as though it is a 30-year investment and that you have 30-year information on what your grid is going to look like, and that’s simply not the world we live in anymore,” Rotenberg said.

Kelly Speakes-Backman, Energy Storage Association | © *RTO Insider*

Kelly Speakes-Backman, CEO of the Energy Storage Association, said focusing exclusively on the short term is not realistic. “You have to think about long-term investments because these are really large investments.”

“I totally agree,” Rotenberg responded. “When you have to think long term, let the market compete for who’s going to make that long-term investment.”

Changing TOs’ Incentives

Rotenberg said utilities in Europe and Australia have been quicker to adopt advanced transmission technology by his company and others because they have ratemaking rules that allow their utilities to share in savings. In most of the U.S., by contrast, utilities’ rate-of-return structures incent them to spend more on expensive transmission upgrades. Rotenberg said seven of the top 11 utilities in the U.S. have nonetheless adopted his company’s power flow “valves” and should be regarded as “heroes” because the technology will reduce their earnings.

Susan Pope, FTI Consulting | © *RTO Insider*

Susan Pope, managing director of FTI Consulting, agreed with Rotenberg on the need for change. “If a battery is the cheapest way to ensure service to a customer at the long end of a transmission line, we shouldn’t be building wires,” she said.

Pope said she fears the pace of technological change may result in a new episode of stranded costs.

“I’m concerned that we get state-level initiatives that are going to be investing in technologies or in projects that are not justified on a market basis. And somebody’s got to pay for that. That’s going to end up being shareholders in terms of stranded costs, or I think it’s going to be small customers because … large customers find a way to avoid paying those large fixed costs. If they’re levied based on peak usage, for example, what you’re seeing in Ontario is customers are increasing their demand in peak hours so that they can meet the threshold so that they can bypass transmission charges.”

November 4, 2018

MISO Tariff Changes Target Cybersecurity Data Sharing

By Amanda Durish Cook

CARMEL, Ind. — MISO has drafted proposed Tariff changes that would allow it to share more information on significant cyberattacks with the federal government.

The revisions, targeted for FERC filing early next year, will permit emergency data sharing with the Department of Homeland Security should MISO experience a cyberattack.

“Right now, we’re very limited in the information we can share,” David Rosenthal, director of incident response and systems recovery, said during a Nov. 1 Reliability Subcommittee meeting. MISO’s Tariff currently permits data sharing with FERC and the Commodity Futures Trading Commission.

MISO is a Section 9 entity according to President Barack Obama’s 2013 Executive Order 13636, which means it’s on a shortlist of entities with critical infrastructure at greatest risk that the government is interested in protecting.

Last year, President Trump signed Executive Order 13800, which tasked DHS with measures that federal agencies could use to support cybersecurity efforts of Section 9 entities.

MISO is also waiting to see how complicated the new NERC standard CIP-008-6 will be; the rule requires reliability coordinators to report attempts to breach cybersecurity. A comment period for the standard closed on Oct. 22.

In anticipation of these activities, MISO has drawn up Tariff revisions for data sharing with “federal agencies with responsibilities for cybersecurity in response to cyber exigency.”

“Honestly, we truly only plan to use this in a significant event like a blackout or a nuclear event,” Rosenthal said. “MISO hopes to never need to use the additional data-sharing practices.”

Staff said the ambiguity around which federal agencies MISO can share data with is deliberate, providing the RTO the latitude to share information with other federal entities with cybersecurity responsibilities, such as the FBI, in the event that DHS is overloaded following a mass attack.

“We just don’t want to pause while we’re in the middle of an incident to see which federal agencies are listed in the Tariff,” Rosenthal said.

He stressed that the information sharing can only be authorized by MISO’s chief information officer or chief information security officer. The RTO will be authorized to terminate the agreement at any time.

The Tariff revisions will also include a confidentiality request that federal agencies not share MISO’s information with third parties. Rosenthal said this aligns with current information-sharing practices with FERC and CFTC, agencies that also do not guarantee confidentiality, though the RTO nevertheless includes confidentiality requests in those agreements as well. Staff promised to make use of whatever authority available to MISO to limit the spread of its information.

MISO requests feedback on the data-sharing proposal by Nov. 21. Rosenthal said MISO would try to file in January.

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.