Page 1310 – RTO Insider

June 20, 2017

Huntoon: Microgrid Defense Misses the Point

By Steve Huntoon

Noblis continues to miss the basic point, which is readily apparent from two figures from its January 2017 report “Power Begins at Home: Assured Energy for U.S. Military Bases” (see graphic). The left figure is the status quo of individual building backup generators. The right figure is a microgrid.

microgrid military cybersecurity — Huntoon

As you can see, the microgrid adds exposure to military base distribution system problems because it is dependent on the distribution system. And distribution system problems cause the vast bulk of outages (87%).

This is not, as Noblis claims, a matter of “correcting” poorly maintained military base distribution systems, which Noblis would do by having the local utility assume responsibility for them.

Problems on local utilities’ own distribution systems cause about the same percentage of their customers’ outages (90%), as documented in footnote 5 of my column. Noblis does not address this.

The point is that most outages have nothing to do with poor maintenance, by military bases or by local utilities. Most outages are caused by severe weather, lightning, human error, unpredictable equipment failure, vehicle collisions, even metallic balloons and squirrels.

If local utilities had magic wands, they would wave them.

Noblis suggests undergrounding distribution systems to mitigate the added risk of microgrids, but it didn’t add the enormous cost of undergrounding to its microgrid costs.^[1] And it doesn’t consider that service restoration of an underground line outage typically takes much longer.

Speaking of cost, Noblis says its hypothetical microgrid cost under its natural gas “Case B” is close to the real-world cost of the microgrid at Marine Corps Air Station Miramar. I can’t reconcile this claim with the capital cost data Noblis presents in its Appendix C.2, which appear to be much lower. By the way, even if the Noblis data were right, its Case B is still uneconomic in the Northeast and Southeast regions that it modeled, and only economic in California.

And a few words about cybersecurity. My column did not suggest that no cyber protection exists for microgrids, simply that microgrids add cyber risk (and electromagnetic pulse risk) that does not exist with individual building backup generators.

The Department of Defense cyber protection that Noblis refers to is based on “limiting communication bandwidth within the network [microgrid].”^[2] The dilemma is that operating a microgrid of substantial size in parallel, in order to get the peak shaving, energy savings and demand response benefits that Noblis is counting on, cannot be done without communications links with the regional grid operator and the local utility. In other words, you can have (1) high cyber protection through isolation, or (2) benefits of parallel operation, but not both. Noblis eats the cake and has it too.

Finally, Noblis criticizes my reporting that the University of California, San Diego (UCSD) microgrid flunked its acid test in the Southwest Blackout of 2011. Noblis says my reference to that microgrid as “flagship” was “strange at best.” I didn’t make that up — just Google “UCSD microgrid flagship” (without quotation marks).

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel LLP.

(See STAKEHOLDER SOAPBOX – Noblis: Huntoon Microgrid Critique ‘Seriously Flawed’.)

The Edison Electric Institute estimates that undergrounding a distribution line costs up to $5 million per mile. http://www.eei.org/issuesandpolicy/electricreliability/undergrounding/documents/undergroundreport.pdf (page 31, Table 6.4). ↑
https://energy.gov/sites/prod/files/2016/03/f30/spiders_final_report.pdf (page 3-15). Microgrid Cyber Security Reference Architecture, which the DOD cyber protection follows (page 3-14), does not consider operational modes in which the microgrid is operating in parallel with the rest of the grid. http://prod.sandia.gov/techlib/access-control.cgi/2013/135472.pdf (page 23). ↑

June 20, 2017

PJM Making Moves to Preserve Market Integrity

By Rory D. Sweeney

For some time, PJM has found itself in a no-win situation, pitting stakeholders valuing market consistency against those seeking flexibility to integrate changing ideas and technologies.

From technological advancements that have reduced demand, to the shale gas boom that has upended the supply stack, to governmental actions that have artificially buoyed preferred technologies, what’s an RTO to do?

“Increasingly, public policies seek to recognize value associated with generation plants beyond their cost effectiveness and reliability attributes,” PJM said in an explanatory document released last week. “The most recent iteration of state policies has involved explicit, legislatively driven subsidies for specific generating units. These types of subsidies can suppress wholesale electricity market prices and threaten these markets’ basic design mission.”

But through that document and three supporting papers, PJM believes it has found a way forward. The RTO published the document along with the last two of three working papers that each focus on addressing different aspects of the issue.

The first, published the same day as a May FERC technical conference analyzing the viability of energy markets, offered guidelines for how states could work with PJM to develop carbon pricing rules that integrate with existing market structures. (See PJM Stakeholders Offer Different Takes on Markets’ Viability.)

The second, published last week as an update of a proposal PJM floated last year, outlines a two-phase capacity auction that would allow subsidized resources to be counted as available reserves without influencing the clearing price. (See PJM’s Grid 20/20 Ponders Mixing Public Policy, Competitive Markets.)

Also published last week was a third paper containing ideas initially advanced in PJM’s response to its Independent Market Monitor’s 2016 State of the Market report. In it, the RTO proposes tweaks to its energy market design to address complaints that market factors — both naturally developing and artificially introduced — have improperly depressed clearing prices so that true real-time costs aren’t being accurately reflected. The grid operator argues that its price-setting logic should be revised to allow inflexible units to set LMPs. (See PJM Differs with Monitor in State of the Market Response.)

“Since the inception of competitive wholesale electricity markets, the industry has evolved significantly and in ways that could not have been fully anticipated,” the document said. “Technological disruptions … have altered the economics of electricity supply, creating new opportunities and challenges. … These shifts in economic trends and market dynamics could lead to an unintended bias in the energy markets favoring lower capital cost resources … [putting] financial stress on all units, but particularly large units with high capital costs.”

The proposals face an uphill battle for acceptance. Stakeholders have criticized PJM for filing some of the ideas with FERC as additional testimony during the technical conference. The Monitor opposes the proposed changes to the LMP-setting logic.

Market participants have also expressed concerns with the RTO’s two-phase capacity-auction proposal. And carbon pricing was a tough sell long before President Trump set out to eliminate his predecessor’s signature Clean Power Plan. (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)

PJM acknowledges the work ahead. The capacity proposal, it said, “likely will be evaluated with other potential solutions” by the Capacity Constructs/Public Policy Senior Task Force, which has been meeting regularly since January and remains mired in foundational discussions on the basic goals of a capacity construct. (See PJM Capacity Task Force Debates the Value of Price Transparency.)

The other proposals haven’t found a home for discussion yet, but the RTO is confident something must be done.

“I certainly think a do-nothing approach going forward puts the goals of the markets in general at risk,” Stu Bresler, PJM’s senior vice president of operations and markets, said at PJM’s Grid 20/20 conference on the issue last August. “The risk of a do-nothing approach is a detrimental effect on the long-term price signal.”

June 20, 2017

SOAPBOX – Huntoon Microgrid Critique ‘Seriously Flawed’

By Jeffrey Marqusee

Steve Huntoon’s March 13 column “Microgrid Kool-Aid and National Security” reviews the Noblis report “Power Begins at Home: Assured Energy for U.S. Military Bases” and raised a number of issues that he claims invalidate the study’s conclusions. Huntoon’s claims and conclusions are seriously flawed.

Huntoon cites a recent Government Accountability Office report that found outages can be attributed to on-base problems as opposed to the utility. He states that outages attributed to on-base issues cannot be solved: “if they were easily avoided, they would be.” From this statement he concludes, incorrectly, microgrids cannot be the solution.

Our report specifically acknowledges that problems with on-base distribution systems must be corrected prior to using a microgrid and in most cases this can easily be accomplished. Currently, some outages on military bases are completely due to the utilities that serve the base (Fort Irwin), while others are due to on-base infrastructure issues (Camp Lejeune). Fixing these on-base problems is well understood and routinely done. Simple activities such as tree trimming, routine maintenance and, when needed, undergrounding of distribution systems can and do reduce the issue to near zero. Fort Belvoir has demonstrated this through these actions over the last several years.

The main reason it has not been done at all bases is well recognized at the Defense Department and is the driver for utility privatization. Maintenance of on-base utility systems has been underfunded for decades. Fort Belvoir is a perfect example. Upon privatizing the on-base utilities, the frequency of outages attributed to on-base issues began to rapidly decline to near zero.

Huntoon argues that microgrids place military installations at risk to cyber threats. He implies that this risk should not be taken.

As the report explicitly states, cyber risks are real and must be addressed, but this was not the focus of our study. If you believe that cyber risks should be always avoided, then you cannot have advanced meters, smart buildings or network anything (including weapon systems). You network things because it buys performance advantages, as in the case of microgrids, and if you own the network you can manage that risk. Huntoon seems unaware that cyber protection for microgrids exists. Cybersecurity solutions for microgrids have been demonstrated on bases by the government’s Environmental Security Technology Certification Program and its Smart Power Infrastructure Demonstration for Energy Reliability and Security (SPIDERS) program.

Huntoon says, “please note one other glaring oversight in the study. This one involves the estimated cost of microgrids.” He claims the study’s estimated costs are grossly wrong by comparing numbers he incorrectly quotes from the report with recent costs for a project at Marine Corps Air Station Miramar.

His comparison of our estimates and a real-world example at Miramar are grossly in error. He quotes our number for the capital costs of an all diesel generator system rather than the costs for one that is half natural gas and half diesel like Miramar. The numbers he should have quoted from the report, which are relevant to Miramar, are twice the numbers he does quote. In addition, he ignored the costs of two microgrid control stations as well as other upgrades. In fact, our cost estimates, constructed prior to the award of the Miramar contract, when compared apples to apples is within 10% of the actual costs.

In the conclusion, Huntoon states, “And speaking of fact, the nation’s ‘flagship’ microgrid at the University of California, San Diego flunked its acid test in the Southwest Blackout of 2011. The campus shut down with the rest of San Diego.” He implies that microgrids don’t work.

microgrids military bases noblis — UC San Diego Microgrid | *UC San Diego*

No one in the microgrid technical community believes that the U.C. San Diego microgrid is the “flagship” example. Using a decade-old, university-based microgrid as an example is strange at best. Dozens of microgrids have been demonstrated in recent years. They all operate as designed during outages and provide assured power. For example, the White Oak microgrid, which is described in the report, has maintained power during dozens of outages, never experienced a failure and is saving money each year.

Jeffrey Marqusee, Ph.D., is chief scientist for Noblis, a nonprofit science, technology and strategy organization whose clients include many federal government agencies.

(See Huntoon: Microgrid Defense Misses the Point.)

June 20, 2017

UPDATE: California Heat Wave Prompts CAISO Flex Alert

CAISO on Monday called on consumers to voluntarily conserve energy this week as scorching heat drove up electricity usage and caused outages in Pacific Gas and Electric’s service territory.

The ISO issued a “flex alert” effective 2 to 9 p.m. on Tuesday and Wednesday, with peak load expected to break 47,000 MW both days in the face of triple-digit temperatures. The alerts are issued when the grid is “under stress” from generation or transmission outages, or persistently high temperatures, the ISO said.

This week’s expected peaks would be more than 90% of CAISO’s all-time peak demand of 50,270 MW, set on July 24, 2006.

By late Monday, the ISO forecast that the day’s peak demand would hit about 44,600 MW, well short of an earlier forecast of 46,500 MW.

Temperatures soared up to 110 degrees in California’s interior, the most intense heat wave to hit the state since the summer of 2013. Multiple days of extreme heat are stressing equipment and causing some outages. PG&E still had 4,200 customers without power as of Monday morning, with about 189,000 customers initially affected.

“This is a heat wave, and we have got all our generation that we can make available made available to us,” CAISO spokesman Steven Greenlee said during a media call held jointly with PG&E.

An extended period of very hot weather is expected across the interior portions of southwest California through the middle of the week, and temperatures could reach 112 degrees in parts of the state, the National Weather Service said as it issued a heat advisory.

– Jason Fordney

June 20, 2017

Offshore Wind Developers Ponder Tx Options

By Michael Kuser

BOSTON — Massachusetts faces a big question in its plan to add 1,600 MW of offshore wind by 2027: What’s the best way to get the power to shore?

The state, which is expected to issue a request for proposals by the end of the month for at least 400 MW, will ask the three winners of offshore wind leases to propose both underwater transmission cables for each of their projects and a single trunk line that would serve all three. Developers also will have to choose between high-voltage AC or DC lines.

Panel left to right: Stephens, Conant, Calviou and Hindbo | © *RTO Insider*

The stakes, as a panel told Raab Associates’ 154th New England Electricity Restructuring Roundtable on Friday, are high.

A multibillion-dollar offshore wind farm can be stranded for six months because of a single cable fault. However, developers can reduce their risk through contracts that provide compensation for transmission failures, said Søren Hindbo, senior director of electrical systems for DONG Energy. In addition, interlink cables among substations can allow electricity to be sent ashore even when an export cable fails, he said.

Denmark-based DONG — which has 26 years of offshore wind experience, with 21 European wind farms in operation and seven under construction — was one of three companies to win leases off of Massachusetts from the U.S. Bureau of Ocean Energy Management. Deepwater Wind and Vineyard Wind (formerly OffshoreMW) also won.

iso-ne transmission offshore wind — | *National Grid*

Hindbo described the contracts used in Germany, France, the Netherlands and Denmark, which provide wind developers compensation if there is a transmission problem. “You measure the wind speed on the wind farm and get compensated according to that, if for instance the connection is delayed or faulty. And that’s very important, because who wants to invest in something and have your billions put up there and no chance of getting anything back because you haven’t got an export connection?”

DONG expects two to three export cable faults per 100 km per 20 years, so having interlinks to provide alternative routes for delivering power is important, he said. “One benefit is you don’t need diesels [for] a black start; also if you are delayed, which often happens … you are still in the game,” Hindbo said.

In Europe, developers have found HVDC lines more cost effective for the most distant wind farms and AC better for those closer to shore, with a break-even point between 100 and 200 km (about 62 to 124 miles).

The export cable represents up to 60% of the total cost in an HVAC system. The total percentage is somewhat lower with a HVDC system, Hindbo said, though the total capital expenditure is higher. “The export cable,” he said. “It’s the weakest and the most expensive part.”

Backbone or Alternatives?

Mike Calviou, senior vice president at National Grid USA, said the most cost-effective approach is a “coordinated and expandable” plan that accommodates future offshore resources, citing research showing it can reduce costs by 8 to 16%. National Grid connected the first offshore wind farm in the U.S. to the grid, the 30-MW Block Island project off Rhode Island.

“We believe coordination does provide a range of benefits: fewer cables; you get the economies of scale; the permitting complexity can actually be significant. There are certainly, we believe, some environmental and safety benefits,” he said. “And particularly the expandability: When you know you are going to be doing more offshore wind … you can actually design for future expansion.”

Anbaric’s Stephen Conant said the RFP unwisely excludes transmission developers such as his company from participating in the design of a solution: They aren’t permitted to respond to the RFP except in partnership with one of the three wind developers/lease holders.

“We think competition is good for the industry,” Conant said. “Putting generators in the transmission business seemed a little odd in the RFP. We have a system here that we separate transmission and generation by having a common transmission system [onshore]. That then allows … those generators to bid competitively into the market.”

The RFP could give market power to the three leaseholders, he said.

“The way the construct is now, essentially if they pick one [bidder], then the first one in … their tendency is going to be to sort of lean towards the expansion of their [initial] 400 or 800 [MW]. So you’ve essentially gotten a little market power that exists as a result of not letting others into the field.”

Anbaric, which was among a group of entities that built the 660-MW Neptune HVDC cable linking PJM to Long Island Power Authority and the 660-MW Hudson project connecting PJM to New York City, is also developing the Vermont Green Line, a 400-MW project to deliver power from upstate New York into the New England grid.

Equal Treatment

Erich Stephens, CEO of Vineyard Wind, highlighted the risk of separating the transmission and generation projects. “If you separate as a matter of policy who builds the generation from who builds the cable, you basically have two projects going forward at the same time,” he said. “Inevitably those projects are not going to be finished at the same time … and that means you’re going to have a very expensive asset sitting offshore that’s not earning the revenue that it should.”

Vineyard Wind was already working with Copenhagen Infrastructure Partners on its offshore wind projects before earlier this year selling a 50% stake to Avangrid Renewables to bid in the Massachusetts RFP.

June 19, 2017

NERC: Despite Solid 2016, Grid Threats Remain

By Rory D. Sweeney

The North American grid was very reliable in 2016, but threats are increasing and restoration from a total system collapse could prove time-consuming, two recent nationwide studies found.

NERC last week released its annual analysis of the grid’s performance, which found that while 2016 ranked as the second-most reliable year on record, threats to the system — particularly on the cybersecurity front — are on the rise.

The revelation adds weight to a recent joint FERC/NERC report that found that recovery of the bulk power system (BPS) from a blackout could be a lengthy and resource-consuming process if supervisory control and data acquisition (SCADA) and energy management system (EMS) functionality are also lost. The report was based on responses from eight industry participants who provided information for the study.

The system’s cumulative severity risk index (SRI) for 2016 is second only to 2011 since the metric began being tracked in 2008. Breaking it down by each BPS component, unplanned generation unavailability accounted for the vast majority of cumulative SRI, which the report said is typical. Transmission loss made up about a fifth of the total, and load loss was relatively minimal.

“No single component shows a significant step change for any given day,” the NERC report says. “The performance within each segment proves to be very stable.”

James Merlo, NERC’s senior director of reliability risk management, said that 2016 was the second consecutive year in which no daily SRI broke the top 10 most severe days on record, despite days with severe weather. This indicated that the BPS is becoming increasingly resilient to severe conditions, he said.

Merlo reported that overall transmission outage severity was reduced year over year. For the second consecutive year, there were no Category 4 or 5 events — the most severe — and only two Category 3 events.

Still, outages caused by human error last year increased to 2014 levels after falling in 2015.

“While no increase in outage severity was discovered, human error remains a major contributor to transmission outage severity and will remain an area of focus,” the report said.

However, the misoperation rate continued a four-year trend of decline across North America. Misoperation events have the highest correlation with the most severe outages.

Frequency response, what Merlo called the “heartbeat of the grid,” is “looking good,” he said. It remains flat or improving across the continent. He said frequency response becomes “different” but not necessarily harder with the influx of intermittent resources on the system.

He also reported that no load was lost to physical or cybersecurity attacks but noted that such attacks are increasing.

“It’s a positive finding, but I think we all know that we’re going to have to give our attention in this area based on the risk increasing every day,” he said.

The report highlights National Institute of Standards and Technology data that indicate high-severity cybersecurity vulnerabilities are consistently increasing. However, vulnerabilities increased 23%, while incidents increased 38%.

“Vulnerabilities are increasingly being successfully exploited, [which] reinforces the need for organizations to continue to enhance their cybersecurity capabilities,” the report says.

The threat was further accentuated in the joint report from FERC and NERC, which found that all participants would remain capable of executing their restoration plans without SCADA/EMS availability by leveraging redundancies. However, the process would be more complicated, take more time, require more resources and rely much more on “interpersonal” communications.

“Participants indicated that system restoration steps [that] involve additional communications and coordination with multiple personnel, such as load pick-up, will be more labor-intensive in the absence of SCADA or EMS,” the report said.

The report recommends utilities ensure the effectiveness of backup communications systems and incorporate that into emergency training, including determining the manpower and tools necessary to collect information and maintain operational awareness without SCADA.

“Participants expected that dependency on interpersonal communications would significantly increase in performing system restoration in the absence of SCADA, and that any unavailability of interpersonal communications would further hamper system restoration,” the report said.

It also recommended considering the shelf life of onsite fuel for backup generators and backup area control error applications.

Participants reported that their emergency procedures were flexible and robust enough to handle a wide range of changing circumstances. All plans involve development of multiple restoration paths and islands.

“If a SCADA system(s) is still unavailable as system restoration progresses, the participants may adjust their restoration strategy accordingly, e.g., restore areas within the reliability coordinator footprint but remain operating as separate islands within the reliability area, holding off synchronizing to form a larger island and/or interconnecting with the rest of the interconnection, thereby reducing the risk of an outage to a larger restored area,” the report said.

In the event of a cyber event that disables SCADA or EMS, participants indicated it would be more reliable to remain islanded “until associated risks are alleviated” in order to avoid repeated widespread blackout.

The increased reliance on interpersonal communications did raise concerns about satellite and cellular phone functionality during emergencies, as usage by other organizations would undoubtedly increase, limiting available bandwidth and exacerbating voice delays.

Most participants stressed the importance of owning and maintaining their own backup wireless systems for emergency field communication — a practice followed by all the participants.

June 19, 2017

WECC Generation, Transmission Loss Events Spike

By Jason Fordney

Electric system disturbances resulting from the loss of generation or transmission in the U.S portion of the Western Interconnection increased by 50% between 2015 and 2016, according to a new report from the Western Electricity Coordinating Council.

There were 24 “loss of generation or transmission” events in 2016 compared with 16 in 2015, WECC said in its State of the Interconnection report. The category refers to the loss of three or more Bulk Electric System facilities from a common cause, or the loss of 2,000 MW or more of generation.

WECC did not provide detail on the reason for the increase and did not immediately respond to a request for more information.

Loss-of-load events in the interconnection also increased between 2015 and 2016, from one event to five. These events are defined as loss of firm load for 15 minutes or more exceeding 300 MW for entities with demand of 3,000 MW or greater in the previous year, or exceeding 200 MW for all other entities. There were three loss-of-load events in 2014.

The largest loss of load occurred Aug. 7, with the loss of 665 MW, about 0.5% of the day’s peak system demand of about 127,000 MW.

Not all bulk power system disturbances qualify as loss-of-load events, and “relatively few meet the criteria,” WECC said.

Noting the increase, WECC said that “more years of data will be necessary to determine whether this signifies an increasing trend and potential concern, a statistical anomaly or normal variation between years.”

“Loss of monitoring or control” events — those lasting 30 minutes or more that affect an entity’s ability to make operational decisions — also increased in the Western Interconnection last year. There were 20 such events in 2015 and 22 in 2016.

Islanding events — unintentional system separation resulting in an electrical island of 100 MW or more — dropped from eight in 2015 to just one in 2016.

Incidents in which a remedial action scheme failed or was enacted unnecessarily dropped from four in 2014 to three in 2015 and 2016.

The Western Interconnection housed a combined nameplate generation capacity of 267,000 MW in 2016, up 1% from the previous year. Natural gas-fired generation represented the largest share (40%), followed by hydroelectric (27%), coal (14%) and wind (8%), with the balance coming from solar, geothermal, nuclear and “other” utility-scale generation.

In 2016, “retirement of coal and steam turbine gas units led to slight decreases in capacity from these fuel types, while the installed capacity of utility-scale solar increased by over 6,000 MW,” WECC said. There is about 14,350 MW of solar in the interconnection, or about 5% of capacity.

Hydro dominates in the Northwest, while California and the Southwest are heavy with natural gas. Solar capacity is growing in California, and wind capacity is increasing in the Rocky Mountains and along the Columbia River.

WECC is the regional entity responsible for compliance monitoring and enforcement in the Western Interconnection, which spreads west from the Rocky Mountains to California, north into western Canada and south to Mexico’s Baja California Peninsula. It consists of 37 balancing authorities and is one of four major interconnections across North America. The WECC report covers the bulk power system, which does not include local electric distribution systems.

The WECC Board of Directors is due to receive an update regarding the State of the Interconnection report at its June 21 meeting in Salt Lake City.

June 19, 2017

MISO PAC Briefs: June 14, 2017

MISO has aligned its Business Practices Manuals with interconnection queue improvements approved by FERC at the beginning of the year (ER17-156). (See FERC Accepts MISO’s 2nd Try on Queue Reform.)

MISO planning advisory committee briefs attachment Y — Muncy | © *RTO Insider*

Paul Muncy, of MISO’s transmission access planning division, told the Planning Advisory Committee last week that BPM 015 mirrors the RTO’s queue filing and is nearly complete, with final review expected over the next few weeks. Language was crafted by the Interconnection Process Task Force (IPTF), which was due to sunset in July but will now continue through December after a unanimous sector vote to extend the group’s existence by six months.

Muncy also said MISO will create a separate process for a few HVDC projects currently in the queue’s system planning and analysis phase. The RTO has already filed to immediately move those projects out of the queue and put them in a holding pattern (ER17-1793). Muncy said a filing on the new process will be ready by the end of this year.

The Merchant HVDC Task Team will work on the separate HVDC filing, stakeholder sectors decided in a vote at the meeting. Muncy said the team began work on Tariff language, but the RTO prefers to transfer that job to the IPTF, which makes recommendations involving interconnection queue revisions. During a sector vote at the PAC meeting, the Coordinating, Transmission Owners and Environmental sectors voted to keep the assignment in the task team, with only the Transmission-Dependent Utilities sector voting in favor of an IPTF handoff. The State Regulatory, Power Marketers and End Users sectors abstained from voting.

MISO Moves Toward Singular Attachment Y Status

MISO plans by the end of the year to introduce Tariff changes eliminating resource suspensions in favor of a single retirement process that would allow a potentially retiring resource to retain the ability to participate in an upcoming capacity auction.

The RTO proposes to reduce its Attachment Y process to a catch-all “economic shutdown” status that no longer recognizes temporary suspensions or require resource owners to provide return dates. Owners could reverse a retirement decision over a full planning year and participate in an upcoming Planning Resource Auction. The same yearlong rescission period will apply to system support resources whose status has been lifted by MISO. (See “Removal of Temporary Suspensions will Provide Generators Flexibility, RTO says,” MISO Planning Advisory Committee Briefs.)

“We don’t need to have a separate process for handling suspensions,” MISO adviser Joe Reddoch said.

MISO will add a provision allowing it to terminate interconnection service for units that have been on extended outage for more than 36 months, he said. “This allows us to dispose of models in our planning studies that are inoperable but show up as available. This way we get rid of the hoarding of interconnection service.”

An additional provision would permit an asset owner to waive its right to rescind a retirement decision and progress directly to retirement. Reddoch said some resource owners might be ready to make a binding decision by the time they file an Attachment Y request.

Reddoch said the proposal’s largest point of contention is the removal of confidentiality for results of Attachment Y reliability studies. By the time confidentiality is lifted, generator owners would on average be three months away from retirement and would have likely made a public announcement, he said.

MISO said it is not “seeking to assume the responsibility or to pre-empt the owner’s announcement of a generator retirement, but Attachment Y is late enough in the process for the owner to have made preparations for the decommissioning process.”

“We feel that it’s so late in the game, we don’t see it as detrimental to the asset owner,” Reddoch said.

PAC OKs Competitive Transmission Task Team Extension

PAC sectors approved a six-month extension of MISO’s Competitive Transmission Task Team.

Brian Pedersen, manager of competitive transmission, sought the extension to enable the group to continue identifying improvements to the RTO’s competitive project selection process in preparation for a future Tariff filing. The team was created after MISO selected LS Power to develop the Duff-Coleman 345-kV transmission project in December. (See Texas Law Could Affect MISO Competitive Transmission.)

“We want to make sure proposals take less time and money to evaluate,” Pedersen said.

The PAC allowed the extension by consent. Chair Cynthia Crane will report the extension at a July 26 meeting of the Steering Committee, which could ask why the group has not completed its original mission in the usual six-month time frame allotted to task teams.

MISO Extends Scoping for Long-Term Overlay Study

MISO will spend more time scoping its long-term overlay study, extending analyses into the first quarter of 2018 in order to better assess system needs.

MISO’s Lynn Hecker said the RTO needs more time to analyze system drivers of resilience and reliability 20 years into the future and discuss how the study will differ from annual Transmission Expansion Plan studies. In April, MISO released a preliminary overlay map of transmission needs that might be considered. (See MISO Planners Looking at 3 La. Projects, Overlay ‘Skeleton’.)

MISO canceled its next Economic Planning Users Group on July 27, where a discussion of the study was planned. Hecker said the RTO will plan a November special workshop to discuss scoping with stakeholders.

The extra quarter dedicated to analysis is not expected to alter the overall study timeline at this point, Hecker said. Projects resulting from the long-term overlay are not expected until the third quarter of 2018, with business cases discussed throughout 2019 before a targeted end-of-year approval on projects that make the cut.

Expedited Project Requests Move to MTEP 17

MISO is recommending that three expedited projects valued at $16.3 million advance to the 2017 Transmission Expansion Plan. Three other project requests are still under consideration.

Two southern Louisiana projects were recommended for MTEP 17 inclusion after reliability studies. Thompson Adu, senior manager of transmission expansion planning, said Entergy’s new $1.3 million Roux Substation and transformer upgrade will proceed, along with the company’s new $11.3 million Lyle Substation and associated rebuild of a 10-mile, 69-kV circuit.

MISO is also recommending ITC Holdings’ proposed $3.7 million, 120-kV Zephyr Substation and circuit in southeastern Michigan after determining the project will have no adverse reliability impacts.

The RTO is still assessing two substation projects in Iowa, Adu said. If approved, ITC would construct the $3.2 million Van Allen 69/12.5-kV and $2.2 million 69/25-kV West Okoboji Lakes substations.

“MISO is collaborating with transmission owners to perform a reliability no-harm test,” Adu said, adding that it should have recommendations on the projects by July.

Finally, Wolverine Power Supply’s $3.7 million Iron Works station and 120-kV loop project to support induction furnace load in southeastern Michigan has not turned up any reliability issues so far, but MISO is still studying the project, Adu said.

— Amanda Durish Cook

June 19, 2017

MISO Rethinks Weighting of MTEP 18 Futures

By Amanda Durish Cook

CARMEL, Ind. — Recent market developments are compelling MISO to reconsider how it weighs the relative importance of its 15-year future scenarios designed to inform its 2018 Transmission Expansion Plan, staff said last week.

miso mtep 18 futures — Ellis | © *RTO Insider*

“The final MTEP futures reflect the various opinions of this group,” Matt Ellis, a MISO policy studies engineer, told the Planning Advisory Committee at its June 14 meeting. He noted that the RTO sifted through 128 pages of stakeholder input to create the four recently completed futures.

MISO is proposing to eliminate futures weighting — which assigns a probability-based likelihood to each MTEP planning scenario — in favor of placing equal importance on each of the four futures. The proposal comes after stakeholders criticized the RTO’s weighting process for not being transparent enough. Some MISO South members called for less stringent carbon-reduction estimates. (See MISO Changes MTEP Futures Weighting for South.)

“It comes down to no one knows what the future will bring,” Ellis said. “The whole point with this that we’re truly trying to acknowledge is no one knows what is going to happen 15 years out, so let’s give them equal consideration.”

Uncertain Outlook for Carbon, Nukes

President Trump’s decision to withdraw the U.S. from the Paris Agreement on climate change prompted some stakeholders to ask if MISO should further reduce the 20% target carbon reduction in the accelerated alternative technologies future. (See Trump Pulling US Out of Paris Climate Accord.) Other stakeholders contend that some states’ renewed commitment to the agreement in the wake of Trump’s move indicated a possible need to increase the carbon-reduction constraint.

Ellis said MISO plans to keep the 20% carbon reduction measure. “It’s something we’ll keep an eye on,” he added.

Nuclear retirements easily earned the most stakeholder comment, according to Ellis. They were included last month as part of MISO’s fourth and newest future — a distributed and emerging technologies scenario. (See “MISO Tweaks 4th and Newest MTEP Future,” MISO Planning Advisory Committee Briefs.)

MISO will assume that 5 GW of nuclear will retire by 2032 based on the license expiration dates of five units in the RTO’s footprint, which include Callaway Unit 1 in Missouri, Clinton Unit 1 in Illinois, Palisades in Michigan, Point Beach Unit 1 in Wisconsin and River Bend Unit 1 in Louisiana.

Some stakeholders asked MISO to consider nuclear economic data in forecasting retirements, but Ellis reminded them that the RTO uses only public information to inform MTEP futures, precluding the inclusion of forecasted retirements based on the future financial viability of nuclear units, which is considered confidential.

Richard Seide of Apex Clean Energy said he was troubled that MISO would only use license expiration dates to forecast nuclear retirements. Ellis asked for stakeholders to submit their reasoning for including or removing other nuclear retirements from a future scenario.

Equal Weighting Spurs Doubts

Some stakeholders expressed surprise at MISO’s proposal to weigh all scenarios equally, saying they agreed on the futures under the assumption they would have input on weighting them.

“My concern boils down to: We’re pretty comfortable with the futures process now because we know we can weight them later. I think there will be a lot more focus on the development of futures,” WPPI Energy’s Steve Leovy said. He asked for MISO to delay finalizing the futures to ensure that stakeholders agree to those that could be applied equally across MTEP projects.

Stakeholders have until July 14 to comment on MISO’s proposal.

Ellis also said the RTO will attempt a series of workshops to improve project siting for the MTEP 19 cycle, especially for renewables. He said he would bring a proposal for workshops to the July Planning Advisory Committee meeting.

June 19, 2017

ETT Updates ERCOT on Extended Outages

By Tom Kleckner

Electric Transmission Texas told ERCOT market participants last week that it is working closely with the ISO to minimize the economic effects of an 18-month project to repair cracks on metal transmission structures that will result in extended transmission outages through November 2018.

ETT, a joint venture between subsidiaries of American Electric Power and Berkshire Hathaway Energy, is currently inspecting transmission facilities on seven different 345-kV lines in Northwest Texas. The lines were all built as part of the Competitive Renewable Energy Zones (CREZ) project, which resulted in 3,600 miles of transmission to carry West Texas and Panhandle wind energy east to urban load centers. The project was completed in 2013 at a cost of $6.9 billion.

The transmission company notified market participants in May that it would be taking the CREZ lines out of service to inspect and, if necessary, replace structural components as part of a warranty claim. ETT said the work would involve visual and ultrasonic inspection of 2,743 structures, 21,944 arms, and 2,192 flanges and baseplates.

“Our contractors and suppliers are committed to completing things and not just doing the work to go home,” ETT President Kip Fox told market participants during a June 15 web conference. “We’re very confident we’re pursuing a solution that limits our costs to ratepayers, supports long-term reliability, improves safety and reduces the risk of unplanned outages.”

Fox and ERCOT staff both answered questions from market participants, many of them wind farm owners and developers.

In response to a written question about whether wind farms would be taken offline by the maintenance work, staff said its “current understanding” of the outage does not indicate that any generation resources will be “islanded” from ERCOT’s grid. The ISO expects some market participants will encounter congestion caused by the work, but it has not performed any specific resource analysis.

The Texas grid operator said it will schedule a second web conference to discuss an alternative ordering of the outages and address concerns about their effects on production costs.

Fox said ETT decided to address the structural issues now, “rather than the next 70-some-odd years.”

The company said it first discovered cracking on a structure arm in late 2012 and began a full inspection and arm replacement of more than 2,000 tangent poles in July 2016. The transmission structures are all steel, single-pole, 345-kV, double-circuit towers. Cracked arms and arm brackets will be replaced, and cracked baseplates and flanges will be repaired.

ERCOT ETT Outages — | *Electric Transmission Texas*

Inspection, repair and replacement crews are working in tandem, and line clearances will be taken continuously to help speed the work along. Outages will be scheduled one at a time and coordinated with ERCOT to minimize effects on the system.

A detailed work schedule and specifics on the outages’ timing and duration can be found in ERCOT’s outage scheduler.