Page 1017 – RTO Insider

July 21, 2019

US House Takes on Grid Security

By Rich Heidorn Jr.

Grid modernization and security were the focus of two U.S. House of Representatives committees last week as four bipartisan bills cleared the Energy and Commerce Committee and a second panel held hearings on two other legislative proposals.

Grid Security — The House SST Committee’s Energy Subcommittee held hearings on grid modernization and cybersecurity last week.

On Wednesday, the Energy and Commerce Committee passed the following bills by voice votes, moving them to consideration by the full House:

The Enhancing Grid Security through Public-Private Partnerships Act (H.R. 359), introduced by Reps. Jerry McNerney (D-Calif.) and Bob Latta (R-Ohio), would direct the Department of Energy to encourage public-private partnerships to mitigate electric utilities’ physical and cybersecurity risks. The effort, in consultation with state regulators, industry and the Electric Reliability Organization, would promote the use of maturity models, self-assessments and auditing methods for measuring security, provide training to address supply chain risks, and encourage sharing of best practices and data collection.
The Cyber Sense Act of 2019 (H.R. 360), also introduced by Latta and McNerney, would require the secretary of energy to establish a program to identify cybersecure products for use in the bulk power system.
The Pipeline and LNG Facility Cybersecurity Preparedness Act (H.R. 370), introduced by Rep. Fred Upton (R-Mich.) — ranking member of the E&C Committee’s Energy Subcommittee — and Rep. David Loebsack (D-Iowa), would establish a program at DOE to improve the physical security, cybersecurity and resilience of natural gas transmission and distribution pipelines and LNG facilities.

The panel also approved a bill (H.R. 362) that would codify the role of Karen S. Evans, who was appointed in September as assistant secretary for DOE’s Office of Cybersecurity, Energy Security and Emergency Response.

Science, Space and Technology Committee

Evans was among the witnesses who testified Wednesday before the House Science, Space and Technology Committee’s Energy Subcommittee.

Subcommittee Chair Conor Lamb (D-Pa.) opened the hearing by touting two other pieces of legislation, the Grid Modernization Research and Development Act of 2019 — which calls for research on grid resilience, emergency response, modeling and visualization — and the Grid Cybersecurity Research and Development Act of 2019 (H.R. 4120), which would authorize a research and development program by the Department of Homeland Security, the National Institute for Standards and Technology (NIST), and the National Science Foundation to harden the grid from cyberattacks. The R&D program would include technical assistance, education and workforce programs. The bills will be introduced after the August recess.

Artificial Intelligence’s Role

Evans told the committee that DOE is seeking to spur innovation in big data and artificial intelligence, saying AI has a “critical role” in improving grid resilience. “We’re talking about … software-defined networks, autonomous solutions, really analyzing the data … to remove some of what is happening at a human level now that could be done by AI, by machine learning. That is the area that we are really exploring so that we can look at higher analysis of security, and also being able to model the resilience in real time.”

McNerney asked whether adversaries could use AI to attack the grid.

“For every great new innovation that we do … we also have to evaluate what are the potential risks associated with that and then engineer preventative solutions,” she responded. “We don’t want to stifle innovation. We want to take advantage of those things.”

Juan Torres, associate laboratory director for energy systems integration at the National Renewable Energy Laboratory, agreed.

“Just about any tool … can be used for good or for bad. That’s why it’s imperative for us to maintain that leadership in the advancements of these technologies so we are the ones using these for the right purpose and can actually deter any negative use or any attacks on these systems,” said Torres, who is also co-chair of DOE’s Grid Modernization Lab Consortium.

Torres said DOE is applying AI to four “foundational areas”: understanding complex systems theory; big data analytics; optimization to ensure distributed systems work together; and non-linear controls.

“What we’re seeing is with highly distributed systems, some of the linear control concepts that are used now on the grid may not apply in a highly decentralized type of system,” he said.

Wind, Solar Cybersecurity

Torres said DOE’s solar and wind technology offices are working with industry officials to identify the industry’s cybersecurity needs and those of distributed energy systems. DOE and the International Electrotechnical Commission on Wednesday hosted a cybersecurity workshop at the National Wind Technology Center at NREL’s Flatirons Campus in Boulder, Colo. “This event is bringing key government and industry players together for the first time to add the cybersecurity needs of the growing wind power industry,” he said.

AI would build on smart grid technologies that witness Katherine Hamilton, executive director of the Advanced Energy Management Alliance, said “have allowed the grid to operate more efficiently and with greater visibility.”

“The year of detective work necessary to determine that the Northeast blackout of 2003 was caused by a branch in Cleveland would no longer be the case thanks to these technologies,” she said.

Workforce Needs

The hearing also discussed the industry’s workforce needs. According to research funded by NIST, the U.S. has almost 716,000 people in the cybersecurity workforce and almost 314,000 job openings.

Hamilton said the workforce challenges extend beyond cybersecurity, noting that about 30% of utility employees and 40% of the industry’s engineers are millennials. “Millennials tend to change jobs faster than we’re used to in the utility workforce. You would start in the utility and retire in the utility. But people change jobs a lot faster and there are more types of jobs, so we need to find out what [kinds of] training are needed. … What are some of the skills that transfer really easily?

“In California right now, there are wildfires that are potentially going to cause public safety outages of 30 days or more … and there are not enough trained tree trimmers to do the work needed on vegetation management. You can’t send a kid out with a bushwhacker. These are really trained labor. So, there are a lot of job needs and opportunities, and there are people who don’t have jobs, and we need to somehow match those. So, bringing the public sector and the private sector together on that seems to me to be a good way to think about that.”

Hamilton said encouraging interest in STEM education and cybersecurity needs to begin in elementary school.

Kelly Speakes-Backman, Energy Storage Association

Witness Kelly Speakes-Backman, CEO of the Energy Storage Association, said she was glad her twin 15-year-old daughters were in the audience hearing the discussion. “Their high school has a program that is partnered with the U.S. Naval Academy specifically on cybersecurity, and I really want them to take it,” she said.

Torres said that in addition to sparking early interest in the STEM fields, industry and government should encourage mentoring to ensure a pipeline of future teachers and professors.

Hamilton said DOE and its National Labs also should be involved in encouraging what she called the “democratization” of innovation.

“Innovations are not limited to our labs, our universities or our utilities. They are everywhere. They are kids in basements playing with their apps,” she said. “So, trying to make sure that our research programs are able to connect the dots so that we can bring entrepreneurs to test and make sure that we have proof of concept [is important]. Because no utility is going to purchase a piece of equipment that was designed in somebody’s basement. They need to know that the Department of Energy and the National Labs have given it the seal of approval … by testing it and making sure that this all works.

“While part of that is about bringing new people into the industry — because there are so many new excited young people coming in — we also need to make sure that we then connect them to the programs that are existing to enrich the programs too,” she said.

A House subcommittee meeting last week heard testimony from (from left) Karen S. Evans, DOE; Juan Torres, National Renewable Energy Laboratory; Kelly Speakes-Backman, Energy Storage Association; and Katherine Hamilton, Advanced Energy Management Alliance.

Measuring Cost-effectiveness

Speakes-Backman, a former member of the Maryland Public Service Commission, had a different ask of DOE, saying it should help states develop ways to measure the cost-effectiveness of resilience measures. “This is an issue that I personally had after the derecho in 2011. Utilities can invest in reliability and there are metrics for that, but they cannot invest in resilience because there aren’t metrics for that to prove cost-effectiveness.”

July 21, 2019

SPP Western Reliability Briefs: July 16-17, 2019

SPP’s Western Reliability Working Group last week approved several governing documents as it continues its preparation for its new reliability coordinator function in the Western Interconnection.

Approved during a two-day meeting July 16-17 were the:

Communication Protocol for the West, which governs emergency and nonemergency situations where operating instructions are issued or received by an SPP operator. SPP’s Margaret Quispe said it is “very similar to what we’ve used” in the Eastern Interconnection under reliability standard COM-002-4.
Modification Oversight Process for the Western Interconnection, which was recommended for approval by the Western Reliability Executive Committee (WREC). Senior Interregional Coordinator Clint Savoy said the document was changed somewhat since the group discussed it in May based on feedback from the Executive Committee. The WREC delayed action on the document on Wednesday, saying it supported the edits but wanted to see a clean version before approving.
RC Restoration Plan. Senior Operations Engineer Neil Robertson said the document included “minor modifications” made since the committee’s last meeting. “In the process of preparing for our certification visit [by the Western Electricity Coordinating Council], SPP’s compliance group suggested we explain … how this document is distributed to [comply] with the EOP-006 standard,” he explained.
Congestion Management Methodology, which will set the RC’s procedures for mitigating system operating limit and interconnection reliability operating limit exceedances in real-time operations for both pre- and post-contingency conditions. “[We are] of the opinion that a consistent … methodology that everybody agrees on would help us do our job as the RC in a much more streamlined way,” explained SPP’s Yasser Bahbaz, a senior engineer. “When we assign any relief allocation to any of you guys, you know what the expectations are. The approach and the methodology has been documented, and there’s hopefully not a lot of back and forth in real time on who should give what relief.” The methodology was recommended for approval by the Congestion Management and Seams Task Force last month, he added.
Data disturbance document, documenting the process by which SPP identifies bulk electric system elements for which dynamic disturbance reporting data is required under PRC-OO2-2.

Tennille Tims, an SPP project manager, provided an update on the RTO’s progress in onboarding its RC customers, saying Inter-Control Center Communications Protocol (ICCP) connectivity was complete for 12 of the 13 customers.

WECC Update

The working group also heard an update from Steve Ashbaker, WECC’s reliability initiatives director, who said the regional entity was continuing to prepare for Phase 2 of CAISO’s expanded RC West footprint.

CAISO completed Phase 1 on July 1, when it became RC for 16 balancing authorities and transmission operators in California and Mexico. Phase 2 will expand the ISO’s footprint to 23 other entities in the Western Interconnection.

WECC will be conducting site visits in CAISO’s Folsom and Lincoln, Calif., offices July 30 through Aug. 1.

“The RC West Phase 1 transition went very smooth. Things continue to seem to be working very well, at least what we’re hearing and what we’re seeing,” Ashbaker said. “They’ve been fortunate in their shadow operations and in their real-time operations. They’ve seen quite a bit go on with … the energy emergency alerts, some earthquake activity —fortunately that didn’t cause a whole lot of chaos on the power system.”

WECC has a site visit planned with SPP in August.

Ashbaker said the Western Area Power Administration has agreed to take possession of 18 months of historical synchrophasor data from Peak Reliability. Ashbaker said WECC had considered taking the data although it lacks the hardware or software to read them. “We just didn’t want that data to be lost. But WAPA has stepped up … and said they said they would be willing to take that on,” he said.

WREC Update

During a brief WREC meeting Wednesday, staff said SPP and CAISO have entered an RC-to-RC agreement, the first business arrangement between the two. SPP is still working with CAISO to gain necessary data for its Western operations.

“It’s taken longer than expected,” SPP Director of System Operations C.J. Brown said. The RTO has since decided its best approach is to go to Peak Reliability to secure the data, he said.

The RC-to-RC agreement was executed last week.

— Rich Heidorn Jr. and Tom Kleckner

July 19, 2019

FERC OKs Changes to MISO-SPP Joint Study Process

By Tom Kleckner

FERC on Tuesday approved changes to the MISO–SPP joint operating agreement intended to improve an interregional planning process that has yet to produce joint projects.

The commission found the proposed Tariff revisions, effective Wednesday, to be just and reasonable and in compliance with Order 1000, which reformed FERC’s transmission planning and cost allocation requirements for transmission service providers (ER19-1895, ER 1 9 -1896).

The RTOs filed the revisions after Coordinated System Plan (CSP) studies came up empty in 2014 and 2016. After gathering feedback and other input from stakeholders, they proposed three primary improvements to the CSP process:

Eliminating the use of a joint model in favor of individual RTO regional analyses;
Adding avoided costs and adjusted production cost benefits to project evaluation; and
Removing the $5 million cost threshold to be eligible as an interregional transmission project.

The RTOs said the improvements would allow them to continue performing joint and coordinated planning annually, but also “to more efficiently evaluate regional and interregional transmission projects concurrently, potentially test more projects than the existing process, and evaluate potential interregional transmission projects under ‘multiple regional futures’ which may allow for a better business case than projects studied under a joint model with a ‘single future.’”

Stakeholders, particularly those on SPP’s side of the seam, had complained about the study process’ “triple hurdle,” which required the $5 million threshold, a 345-kV project or larger, and RTO benefits representing 5% or greater of the total benefits in the combined region. (See MISO, SPP to Ease Interregional Project Criteria.)

“It takes a herculean effort in what amounts to a simple screen” before going to the regional review, MISO’s Eric Thoms, then manager of interregional planning and coordination, said during a 2018 meeting of the RTOs’ Interregional Planning Stakeholder Advisory Committee.

“The changes resulted from extensive stakeholder discussions about the barriers to reviewing interregional transmission projects,” SPP’s David Kelley, director of seams and market design, said in a statement. “We believe the changes will lead to a more efficient, collaborative planning process as we continue to evaluate opportunities for addressing transmission needs along the extensive SPP-MISO seam. We’re putting this new process into place immediately and will continue to evaluate its effectiveness over the next couple of planning cycles.”

MISO spokesperson Julie Munsell agreed with Kelley, saying the changes “will allow both RTOs to better identify and build cost-effective, mutually beneficial interregional projects.”

The RTOs are already well into a 2019 CSP study, although they have yet to identify a joint project. (See “Revised Seams Study with MISO yet to Bear Fruit,” SPP Seams Steering Committee Briefs: July 10, 2019.)

SPP MISO — David Kelley, SPP | © *RTO Insider*

The American Wind Energy Association, Clean Grid Alliance and Advanced Power Alliance protested the RTOs’ filing, asking FERC to reject the elimination of the joint model, the most contentious issue among stakeholders. They argued that “negative consequences will outweigh any positive benefits” and that without the joint model, there would be no mechanisms for the RTOs “to work together or agree to study assumptions.”

MISO and SPP would wind up with “a transmission planning mechanism that is not robust and a cost allocation in which stakeholders will lack confidence,” the parties said.

FERC found that a joint model is not required to ensure interregional transmission coordination. It said that the JOA and CSP processes “support coordination between the two RTOs, including the proposed joint review of each region’s models.”

“We find that the [CSP] process adequately ensures that MISO and SPP are coordinating and sharing the information necessary to make transmission planning decisions and identify potential beneficial transmission projects,” the commission said. “Since each RTO uses its respective regional model to calculate project benefits using the benefit metrics outlined in the JOA, stakeholders in each region should have the same level of confidence in the cost allocation method for an interregional transmission project as they would have for a regional transmission project.”

July 19, 2019

FERC Heaps Praise on Departing LaFleur

By Michael Brooks

WASHINGTON — Current and former colleagues gathered at FERC headquarters Thursday to praise departing Commissioner Cheryl LaFleur.

As the commission does not hold open meetings in August, Thursday marked LaFleur’s last as a sitting commissioner before her term ends Aug. 31. When it does, she will have served 3,336 days, according to Chairman Neil Chatterjee, making her the second-longest serving commissioner in the agency’s history (519 days short of William L. Massey, who served from 1993 to 2003).

“Rare are those who … through grace, logic and verve make a genuine difference,” said former Commissioner Marc Spitzer, one of 12 she served with during her tenure. “That’s Cheryl LaFleur.”

She was also the longest serving chairman, with 704 days at the helm, Chatterjee said, including two stints as acting chair. During the meeting, LaFleur stacked her three nameplates — chairman, acting chairman and commissioner — in front of her.

Chatterjee presents LaFleur with a farewell gift. | *Federal Energy Regulatory Commission*

LaFleur arrived first among her colleagues to the hearing room, where a packed audience with few open seats awaited her. The meeting began slightly late; it was only until Chatterjee walked in with Commissioners Richard Glick and Bernard McNamee right behind him that it became apparent why. Each wore a Boston sports jersey in imitation of LaFleur’s tradition of supporting her teams during playoff runs: Patriots for Chatterjee, Red Sox for Glick and Celtics for McNamee.

After the meeting’s official proceedings, Chatterjee brought forward Spitzer; former Montana Public Service Commission Chairman Travis Kavulla; Jamie Simler, former director of the commission’s Office of Energy Market Regulation; and LaFleur legal adviser Steven Wellner. Along with her current colleagues, they all praised LaFleur as wise, gracious and having a good sense of humor.

“She’s one of the funniest people I’ve ever met and always has a story or analogy for pretty much any occasion,” Wellner said.

Simler choked up as she spoke about how supportive LaFleur is of her staff, especially during the quorum-less period in the early days of the Trump administration, in which she was eventually the only commissioner at the agency. (See LaFleur Recounts Turbulent Tenure at FERC.) “No matter what your title was, we had the security of knowing that you cared … about the agency, the staff, the decisions and getting things right, or as close to right as possible.”

Chatterjee also praised her for leadership during the period. After serving as chair, “I now have a greater appreciation for how difficult a period that must have been, not just because of the stress of the backlog that was accruing, but just maintaining morale among our wonderful staff,” he said.

“You’re the embodiment of what it means to be not only a good regulator, but a good person,” McNamee said. “Washington will be something less because you’re not a part of it.”

LaFleur thanked all her current and former staff members, many of whom were in the audience, and called her time at FERC “the most rewarding professional experience of my life.”

Chatterjee handed her the gavel to close out the meeting one last time.

July 19, 2019

MISO Looks to Prune Competitive Tx Process

By Amanda Durish Cook

MISO is wagering that proposed rule changes will cut down on the time and expenses spent evaluating transmission proposals and position it to assess multiple competitive projects in a single Transmission Expansion Plan (MTEP) cycle.

The RTO said Thursday that it will soon file with FERC to outline increased data requirements, page limits and tighter deadlines in its competitive developer selection process.

Stakeholders have repeatedly asked MISO to make the improvements.

MISO Senior Manager of Competitive Transmission Administration Brian Pedersen said the length of proposals grew sharply between the solicitation for the Duff-Coleman project — the RTO’s first competitive project — and the currently embattled Hartburg-Sabine project. (See Uncertainty Deepens for Hartburg -Sabine Project.) Developers vying for Duff-Coleman in 2016 on average attached about 85 files to their proposals, but the file attachments had grown to about 150 per proposal by the 2018 Hartburg-Sabine solicitation.

“We have good developers and they submit full proposals,” MISO design engineer Alex Monn said during a July 18 workshop on the competitive transmission process.

But the proposals might have been a bit too fleshed-out for planners, prompting MISO to propose setting a 125- to 300-page limit, depending on the size and complexity of the transmission project being bid on.

The RTO also wants to “right size” its evaluation time based on size and complexity and is proposing to spend no more than 240, 375 or 480 days on one developer selection. It said the three proposal windows will “match the right level of proposal preparation and evaluation resources to each project.” Pedersen said the idea is to trim timelines and evaluation efforts on smaller, more straightforward projects.

MISO’s Tariff currently allows a maximum 480 days to execute the developer selection process from MTEP approval to an executed selected developer agreement. The Duff-Coleman selection took nearly all that time, while Hartburg-Sabine took less than a year.

The RTO also said it will change rules so it can accept a smaller project evaluation deposit for simpler projects that won’t require as much review. The current deposit requirement is $100,000 per proposal. Accordingly, MISO is proposing to scale down its proposal submission windows to either 60, 120 or 165 days, also depending on project intricacy.

Multiple stakeholders said a 60-day window would not be enough time to put together project proposals.

“Sixty days is just not enough time. … I feel like 90 days would be the minimum,” Entergy’s Yarrow Etheredge said.

Pedersen said he would re-examine the smallest proposal window with his staff to make sure it’s a sufficient amount of time.

“Matching our level of effort with your level of effort is a good thing,” Pedersen said. “Just like you’re on the clock, we’re on the clock when the proposals come in.”

MISO is also adding requirements to ensure the information received from developers is more valuable in aiding selection. It would specifically ask for recent project success stories, more project cost breakdowns and calculations to support design decisions along with three years of financial data and company credit ratings.

Pedersen said MISO will still move ahead with improving the competitive bidding process despite FERC’s rejection of its proposed cost allocation for competitive projects last month. (See MISO Allocation Plan Fails on Local Project Treatment.)

“There is a future out there and we still need to plan. It’s better to be ready when it happens,” he said.

MISO plans to file the competitive process changes with FERC in mid-September, with a goal to enact the rules by December. The RTO will not have a competitive project process in 2019.

July 19, 2019

Ohio Senate Clears Nuke Subsidy Bill

By Christen Smith

The Ohio Senate on Wednesday cleared a controversial plan to curb state renewable energy mandates and create subsidies for nuclear and coal plants, but the House of Representatives’ stamp of approval is still likely two weeks away.

Nineteen senators — 17 Republicans and two Democrats — approved House Bill 6 after months of hearings that debated the merits of saving FirstEnergy Solutions’ nuclear reactors at the Davis-Besse and Perry facilities near Lake Erie. The bankrupt company said it will begin shutting down the plants over the next few years without ratepayer subsidies to offset the flood of cheap natural gas that makes it difficult to compete in the wholesale energy market. (See FirstEnergy Extends the Clock on Ohio Nuke Plan.)

Two Ohio Valley Electric Corp. coal plants would also receive funding, which some critics have described as a sweetener to attract support from the state’s other electric distribution utilities (EDUs). (See Ohio Nuke Bill: A Worthwhile Trade-off?)

The latest iteration that moved out of the Senate Energy and Public Utilities Committee earlier this week would collect $150 million for the plants starting in 2021 via ratepayer fees that range from 85 cents for residential customers up to $2,400 for large industrial plants. The charge would sunset in 2027 and the Public Utilities Commission would audit the nuclear facilities each year between 2022 and 2026 to determine if the subsidies are still needed — an attempt to placate critics who insist the plants aren’t losing money at all.

Another $20 million would support six solar power projects being built throughout the state. The OVEC fees would range from $1.50 for residential customers to $1,500 for commercial and industrial customers, and would be subject to OVEC revocation.

The bill also preserves a scaled-back renewable portfolio standard, dropping from 12.5% by 2027 to 8.5% until 2025, with no continuation of the mandate thereafter.

The House didn’t vote on the plan but returns to session Aug. 1. Speaker Larry Householder (R) has reportedly worked behind the scenes to secure bipartisan support in his chamber by pushing the fees for OVEC and slashing RPS mandates long unpopular among state Republicans.

“This will give Ohio an energy plan that puts Ohioans first,” he said when the plan cleared the House Energy and Natural Resources Committee in May. “We’re keeping good-paying jobs here in Ohio and maintaining a diverse energy portfolio.”

Although the current version of HB 6 — Ohio’s Clean Air Act — walks back some of the House-approved components, critics insist the bill remains deeply flawed and misguided. The Sierra Club said it would wreck the state’s potential to become a leader in wind and solar development all for the sake of a “regressive” and burdensome surcharge that would disproportionately hurt small businesses.

The Ohio Consumers Council and the Ohio Manufacturers’ Association sent a joint resolution to Gov. Mike DeWine on Wednesday urging him to veto the bill, saying it will thwart the benefits customers receive from competitive energy markets. A spokesperson for the governor did not return request for comment, but DeWine has signaled support for the bill in the past few months.

FirstEnergy did not respond to requests for comment from RTO Insider on Thursday. The company extended the June 30 deadline for legislative action, remaining “optimistic” that lawmakers would approve the bill in the coming weeks.

July 19, 2019

FERC Orders Cold Weather Reliability Standard

By Rich Heidorn Jr.

FERC on Thursday called for reliability rules requiring generator owners and operators to winterize their units and provide their reliability coordinators (RCs) and balancing authorities (BAs) with information about their preparations.

The commission issued the directive as a result of a joint FERC-NERC investigation into the abnormal cold and higher-than-forecast demand that caused MISO and SPP to seek voluntary load reductions and nearly forced load shedding in MISO South on Jan. 17, 2018. (See FERC, NERC to Probe January Outages in MISO South.)

“Today’s report finds that, despite prior guidance from FERC and NERC, cold weather events continue to result in unplanned outages that imperil reliable system operations,” the regulators said in a press release. Although the system remained stable, “continued reliable operation would have required shedding firm load if MISO had experienced its largest single generation contingency in MISO South.”

They said the need for a new reliability standard to improve generator performance was demonstrated by the 2018 incident as well as the large-scale unplanned outages during the 2014 polar vortex and the 2011 Southwest cold weather event.

“Learning from near-miss events is extremely important,” Chairman Neil Chatterjee said in announcing the report at Thursday’s open meeting.

The report said the 2018 incident resulted from both gas supply shortages and a failure to properly winterize generation facilities. It made 13 recommendations, calling for improvements in generator performance, load forecasts, communication and planning.

9 States Affected

The event affected all or parts of nine states, including MISO South (Arkansas, eastern Texas, Louisiana and Mississippi); southeastern SPP (lower Kansas-Missouri border, the eastern half of Oklahoma, Arkansas, eastern Texas and Louisiana); the western portion of the Tennessee Valley Authority (western Tennessee, lower Missouri, northeastern Oklahoma, northern Mississippi and Alabama) and the western portion of the Southeastern Reliability Coordinator (SeRC)/Southern Co. footprint (southern Mississippi and Alabama).

MISO did not expect to have a problem meeting its South load on Jan. 17, based on anticipated generator availability and precautionary measures it took to increase projected reserves. But conditions worsened because of the “extraordinary” level of generation outages and derates.

The report found 183 generating units in the RC footprints of SPP, MISO, TVA and SeRC suffered an outage, derate or failure to start between Monday, Jan. 15, and Thursday, Jan. 19.

Reliability — Generation outages and derates by RC footprint beginning Jan. 17, 2018 | *FERC*

Including generation already derated or on planned or unplanned outages before Jan. 15, the four RCs had more than 30,000 MW of generation unavailable in the South-Central portions of their footprints by the Jan. 17 morning peak.

MISO South had as much as 17,000 MW of generation unavailable — all but 4,000 MW unplanned — including 57% of generation in Louisiana and 23.5% of that in Arkansas.

“Had MISO’s next single contingency generation outage in MISO South of 1,163 MW occurred, continued reliable [bulk electric system] operations would have depended on system operators shedding firm load promptly to prevent further degradation of BES conditions,” the report said.

Weather Impact

Generator owners and operators (GOs and GOPs) directly blamed 14% of the generator failures between Jan. 15 and 19 on the cold weather, citing frozen sensing lines, frozen equipment, frozen water lines, frozen valves, blade icing and low-temperature cutoff limits.

An additional 30% were indirectly linked to the weather, including fuel curtailments to gas-fired generators (16%) and mechanical causes related to cold weather (14%), such as freezing of gas purge valve and steam turbine intercept valves, drops in oil pressure, wet or frozen coal and the loss of feedwater.

The report recommended GOs and GOPs implement freeze protection measures, such as installing wind breaks on generating units and conducting regular maintenance, and inspection of other protections, such as heat tracing equipment and thermal insulation.

The investigators noted about 70% of the unplanned outages occurred in gas-fired units. They recommended requiring gas generators to inform their RCs and BAs whether they have firm gas supplies.

Ambient Temperature Ratings

The report also recommended better information sharing on the impact of ambient temperatures on generators and transmission lines.

It said GOs and GOPs should ensure the accuracy of generating units’ ambient temperature design specifications and share them with RCs and BAs.

All four of the RCs experienced transmission constraints, and MISO declared an energy emergency because it lacked enough reserves to balance generation and load in South. But the researchers said some system operating limits that became constraints were based on summer temperatures or static, year-round ratings, which understated the lines’ winter capabilities.

The report said SOLs and their associated equipment ratings should be based on “at a minimum, ambient temperature conditions that would be expected during high summer load and high winter load conditions, respectively.”

Power Transfers

The report also noted that increased electricity demand resulted in large power transfers, with MISO and SPP dispatching remote wind generation and SPP importing power over its HVDC ties with ERCOT. In addition, MISO’s regional directional transfer (RDT) from Midwest to South exceeded its contractual firm and non-firm limit of 3,000 MW, peaking at 4,331 MW about 6:30 a.m. CT.

“Although MISO exceeded the RDTL, and did not reduce the RDT below the 3,000-MW limit within 30 minutes as contemplated by the settlement agreement [with SPP and neighboring RCs], MISO operators communicated with adjacent RCs … that MISO would be exceeding the limit, and that if MISO’s RDT flows caused a system emergency for the adjacent RCs, MISO would take appropriate actions,” the report said.

The report also called for improvements to the joint Regional Transfer Operations Procedure that governs MISO’s use of the RDT. The recommendations included changes to clarify roles and timing and a requirement that affected entities declare an emergency before MISO sheds firm load to reduce the RDT.

The report also recommended that RCs consider the deliverability of reserves, noting that the constraints “caused reserves to be stranded from MISO South.”

It also said MISO should notify the other RCs when it is counting on the as-available, non-firm portion of the RDT to deliver reserves for MISO South.

Inaccurate Load Forecasts

The investigators gave good marks to the RCs’ system operators, saying their actions were “effective and timely.” But they said they were hampered by inaccurate load forecasts for MISO South. MISO’s five-day forecast for Jan. 17 underestimated load by about 6,000 MW (18.9%), and its three-day forecast was 1,900 MW low (6.1%). The report said MISO should work with its local BAs and adjacent RCs to improve its accuracy.

“While MISO and its neighbors worked together to maintain system reliability during the event, we recognize the opportunity to collaborate on changes that improve coordination during extreme events,” MISO spokeswoman Julie Munsell said Thursday. “We look forward to reviewing the findings and recommendations in the final report.”

Studies and Drills

Several of the recommendations concerned additional studies.

The report recommends studies that consider “stressed but realistic conditions,” noting that none of the RCs had anticipated the widespread transmission constraints on Jan. 17.

MISO and SPP should “jointly perform seasonal transfer studies and sensitivity analyses in which MISO and SPP model same-direction simultaneous transfers (e.g. north to south, south to north, west to east) to determine constrained facilities so that they can develop mitigation plans or other procedures for the operators,” it said.

It also said planning coordinators and transmission planners should jointly develop and study scenarios to prepare them for extreme weather. It said the studies should include removing generation units entirely to represent actual generation outages as opposed to scaling generating unit outputs.

The study team also recommended that MISO and other RCs perform:

Voltage stability analyses in future constrained conditions and benchmark planning and operations models against actual events that stressed the system;
Periodic impact studies to identify which elements in the adjacent RCs’ systems have the most impact on their own systems; and
Drills to “execute load-shedding for maintaining reserves while at the same time alleviating severe transmission conditions.”

July 19, 2019

NARUC Offers Tools for Measuring Cybersecurity

By Rich Heidorn Jr.

The National Association of Regulatory Utility Commissioners this week completed the release of a suite of tools it says will allow state regulators to gauge their utilities’ cybersecurity preparedness — without becoming technical experts.

NARUC said the two newest offerings, a template of questions and an evaluation tool, will help regulators make “well informed … decisions regarding the effectiveness of utilities’ cybersecurity preparedness efforts and the prudence of related expenditures.”

“The threat posed by cybersecurity incidents is very real, and it is essential that regulators have a clear understanding of the work being done by our utilities to safeguard vital systems and address current and future cyber threats,” said Pennsylvania Public Utility Commission Chair Gladys Brown Dutrieuille, who heads NARUC’s Critical Infrastructure Committee.

Understanding Cybersecurity Preparedness: Questions for Utilities supplements prior NARUC cybersecurity publications, providing a list of queries that regulators can use to evaluate a utility’s cybersecurity risk management program and practices.

The Cybersecurity Preparedness Evaluation Tool (CPET) provides a way to measure the maturity of individual utilities’ cybersecurity risk management programs over time. It is intended to be used with the questions on an iterative basis to help regulators identify utilities’ cybersecurity gaps and press them for continued improvement.

“As regulators, we must assess utilities’ decisions to invest in risk management tools and other protections for business and customer information, but we are not cybersecurity experts,” Washington Utilities and Transportation Commissioner Ann Rendahl said. “CPET will help us dive into risk management and cybersecurity topics without each commission reinventing the wheel.”

The two new publications supplement three previously released resources: the Cybersecurity Strategy Development Guide (2018), which provides a “roadmap” for regulators to structure “long-term engagement” with utilities on cybersecurity; the Cybersecurity Tabletop Exercise (TTX) Guide (2019), an aid for creating exercises to gauge utilities’ and other stakeholders’ ability to respond to and recover from a cybersecurity incident; and a Cybersecurity Glossary (2019), which defines cybersecurity terms used in the other publications.

The content builds on NARUC’s Cybersecurity Primer, which was released in 2012 and updated in 2017.

Questions Template

The new questions document is organized by the five cyber risk management functions defined in the National Institute of Standards and Technology’s industry-agnostic Cybersecurity Framework (CSF).

The questions are divided into two categories: policy and plans, and implementation and operations.

NARUC recommends regulators consider creating cross-functional teams, including personnel familiar with utility operations, IT specialists and legal staff, to conduct the evaluations. Some commissions may hire cybersecurity consultants to assist.

The questions align with NERC’s Critical Infrastructure Protection standards. Some samples: Does an asset inventory exist? Do you require specialized cybersecurity training for personnel with IT or OT [operational technology] responsibilities? Do you budget for cybersecurity tools and technology separately from IT? Have you identified minimal operational functionality for recovery of critical assets?

Evaluation Tool

NARUC said its cybersecurity evaluation tool is intended to be more accessible than other resources, such as the Department of Energy’s Cybersecurity Capability Maturity Model (C2M2).

“Feedback from NARUC working groups and interviews consistently reveal that many [commissions] do not have access to the resources and technical knowledge necessary to apply highly technical tools like the C2M2,” it said. “By focusing only on the aspects of cybersecurity most important to commissions, completing an assessment using the CPET is likely to be less resource intensive on both the commission and the utility than assessments using other maturity models.”

The CPET helps regulators determine whether utilities have sufficient cyber plans and policies ready and have protected their IT and OT systems and are prepared to respond and recover quickly to attacks. While C2M2 can be used to evaluate generation, transmission or distribution operations separately, the CPET is intended to provide an overall assessment.

“By regularly engaging with utilities (e.g., annually, semiannually) using the Questions for Utilities and analyzing the information received using the CPET, commissions can assess the year-over-year change in cybersecurity preparedness of individual utilities within a [commission’s] jurisdiction, promote continuous improvement, and increase the overall awareness and visibility of cybersecurity preparedness and resilience across the utility landscape within their states,” NARUC said.

The CPET allows regulators to assign one of six maturity levels for nine topic areas consistent with the NIST CSF and NERC CIP standards.

NARUC recommends state regulators perform the cybersecurity evaluations separately from regulatory proceedings, saying it is likely to produce more openness from the utilities.

The CPET is not intended to be used to compare utilities’ maturity levels “as the operating environment and resource availability for each utility is unique and does not lend to a one-to-one comparison,” NARUC said.

“Although the CPET is not intended to assess utilities against each other, commissions can use the data collected from its analysis to develop a comprehensive view of cybersecurity preparedness across its jurisdiction, including strengths, challenges, best practices and other valuable information that will help guide their long-term activities and future engagements with utilities.”

July 19, 2019

FERC Clears MISO 2015/16 Auction Results

By Amanda Durish Cook and Rich Heidorn Jr.

In a decision marked by minor controversy, FERC on Thursday capped a three-year-old investigation into MISO’s 2015/16 Planning Resource Auction by finding no market manipulation on Dynegy’s part.

The commission also found the $150/MW-day clearing price in Southern Illinois’ Zone 4 was just and reasonable, despite ordering MISO to change capacity auction rules following the auction. Thursday’s order also declined to set up an evidentiary hearing to possibly recalibrate the auction results (EL15-70).

The investigation centered on an auction in which Zone 4 cleared at $150/MW-day, a nine-fold price increase compared with just $16.75/MW-day a year earlier. MISO’s other nine local resource zones cleared below $3.50/MW-day that year.

Complaints followed swiftly, questioning the justness of Zone 4 prices, and included then-Illinois Attorney General Lisa Madigan, Southwestern Electric Cooperative, Illinois industrial energy consumers and the public interest group Public Citizen. All questioned Dynegy’s market behavior because the company controlled a significant portion of the capacity available in Zone 4. (See FERC Launches Probe into MISO Capacity Auction.)

Two years before the auction, Dynegy acquired from Ameren four coal-fired generators in Zone 4 with a total installed capacity of more than 3 GW. At the time of the transaction, Dynegy’s market share in MISO’s capacity market was analyzed on a systemwide basis — rather than at the zonal level — because the 2013/14 auction cleared at a single price of $1.05/MW-day. Dynegy has since been acquired by Vistra Energy.

In early 2016, FERC determined that MISO’s $155.79/MW-day maximum bid was too high, needing to be set closer to $25/MW-day, and that the RTO didn’t accurately gauge power exports. As a result, MISO revised capacity import limits, set the initial reference level for capacity at $0/MW-day and developed default technology-specific avoidable costs. (See FERC Orders MISO to Change Auction Rules.)

In the auction, Dynegy offered 1,709 MW of capacity at $0/MW-day, 270 MW at $108/MW-day, 651 MW at $150/MW-day and 2,775 MW at $167/MW-day.

In Thursday’s order, FERC said that although Dynegy had pivotal supplier status and that substantial price separation occurred, MISO had conducted the auction in accordance with its Tariff and market power mitigation rules.

The commission noted that all Dynegy’s offers were made below Zone 4’s $247.40/MW-day cost of new entry and said it agreed with MISO and Dynegy that a clearing price isn’t unjust simply because it’s higher than expected.

“We find no evidence in the record to support a finding that Dynegy’s offers violated MISO’s Tariff, and we conclude … that the resulting auction clearing price was just and reasonable,” FERC determined.

MISO Independent Market Monitor David Patton had argued the RTO’s previous auctions, not the 2015/16 auction, were the problem, saying that previous “near-zero” clearing prices “undervalued the reliability provided by that capacity.”

“The price increase in Zone 4 merely reflects that prices were unreasonably low in previous planning years,” the Monitor said.

‘Full and Thorough’

The commission also said that contrary to complainants’ arguments, its Office of Enforcement conducted “a full and thorough investigation” into the matter, spanning more than three years, with review of about 500,000 pages of documents and 17 days of testimony from 11 witnesses.

“We reject any implication that the investigation was not sufficiently complete to consider the conduct at issue,” FERC said, adding it would take no further action to investigate allegations of market manipulation in the auction.

Southwestern Electric Cooperative’s complaint went a step further, arguing that all sellers in Zone 4 stood to be enriched by the high clearing price. Madigan also argued that all Zone 4 sellers should refund excess charges to customers.

But FERC dismissed that complaint, saying Southwestern Electric failed to specify any alleged violations of statutory or regulatory standards on the part of Zone 4 sellers.

Glick Miffed at Chair’s Action

During Thursday’s open meeting, Commissioners Cheryl LaFleur and Richard Glick noted pointedly that — although the investigation had been authorized by the entire commission — they were not consulted before Chairman Neil Chatterjee unilaterally ended the probe.

While LaFleur said she concluded that there was no evidence of market manipulation, Glick said Chatterjee “cut short” the probe prematurely.

Glick, who dissented on the order, noted that Congress gave the commission expanded authority to police market manipulation as part of the Energy Policy Act of 2005.

“I really don’t believe that when Congress enacted the law, they intended for there to be one commissioner to be able to make the decision about whether to conclude an investigation or not,” Glick said. “I think that Congress intended for all commissioners to … take a vote on those decisions.”

He echoed LaFleur in saying “reasonable minds very much could disagree” on whether the investigation should have continued. But because the evidence is not public, he said, “we can’t really have a discussion on the record. There’s not really any transparency about it. So, one of the things we should do is release as much of the information as we can. People need to have a lot of confidence in what we do and confidence in the markets.”

Glick said the commission’s ruling in the MISO case, and a separate rulemaking that reduced the amount of data the commission will require in market power reviews, “don’t really instill the kind of confidence we need to have in our markets.”

In his dissent, Glick called Thursday’s order a “wholly unsatisfactory response to the allegations of market manipulation” and derided the commission’s explanation behind terminating the investigation as “a series of statements, none of which adequately support the commission’s finding that those results were just and reasonable.”

“Today’s order does not provide even the scantest reasoning to support its finding that the nearly 1,000% year-over-year increase in the MISO Zone 4 capacity price had nothing to do with market manipulation,” Glick wrote. “Instead, all we have is the commission’s unsubstantiated assurance that no one violated the commission’s regulations regarding market manipulation.”

Asked by reporters after the meeting why he decided to close the investigation without consulting his colleagues, Chatterjee said, “It has always been the chairman’s prerogative to close an investigation. I’m not getting into the particulars of exactly when and how the investigation was closed, because that’s nonpublic. But the results of the investigation were made available to my colleagues, and as you can see, a majority of us agreed that market manipulation did not occur.”

Michael Brooks contributed to this article reporting from Washington.

July 17, 2019

MISO Makes Second Attempt at More Rigorous Queue

By Amanda Durish Cook

CARMEL, Ind. — MISO will this month take a second shot at a FERC filing that would change its generator interconnection fee structure and require customers to secure locations for projects earlier in the queue.

The commission in March rejected a plan to impose more stringent site control requirements and increase milestone payments for interconnection customers, ruling that the RTO didn’t adequately demonstrate its proposals were reasonable and not unduly discriminatory. But it did agree that more stringent site control requirements and higher milestones could help reduce speculative and duplicative projects. (See MISO Promises Refile on Stricter Queue Requirements.)

This time around, MISO will not make changes to its first milestone payment, which would remain $4,000/MW instead of becoming a variable cost representing 10% of the average network upgrade cost from the last three definitive planning phase (DPP) cycles. FERC said the RTO’s percentage proposal would have resulted in inconsistent payment amounts.

However, the new plan will add a refund mechanism to the total milestone fees imposed on a customer. The “true down” feature will cap total milestones at 20% of a project’s network upgrade cost, with any excess payment refunded back to interconnection customers after a project clears the second decision point, roughly 250 days into the queue.

Like MISO’s first filing, 50% of milestone fees are considered at risk of not being refunded if they’re needed to help defray network upgrade costs should a project withdraw at the first decision point, about 180 days into the queue. At the second decision point, the percentage of at-risk fees drops to 25%. The RTO currently considers all milestone fees at risk of acquisition to help pay for promised system upgrades at both decision points.

MISO will request an Oct. 1 effective date in its new filing, Manager of Resource Interconnection Arash Ghodsian said during a meeting of the Interconnection Process Working Group on Tuesday.

“We understand that the process is working as is … but we’re looking to fine-tune. The goal is to provide the highest amount of certainty for projects coming through the queue,” Ghodsian said.

He said the new filing will occur within the month. “Exact date TBD. But we’re shooting for the near future. Soon.”

Multi-project Sites

MISO is also proposing to amend the Tariff to allow different fuel types and multiple generation projects to share the same site. The RTO said its new proposal will allow “multiple proposal submissions provided they are concurrently viable.”

FERC had said MISO’s earlier requirement that project owners demonstrate “exclusive use” site control conflicted with a Tariff section that allows interconnection customers to submit “multiple interconnection requests for a single site” and a policy that requires customers to submit separate requests for generating units that use multiple fuel sources.

MISO will propose to require all projects sharing a location to identify each other in their respective interconnection requests and provide a common diagram of land usage. It would then analyze whether all the projects can be developed on the same parcel of land.

Site Maps vs. Secured Acreage

Stakeholders argued that interconnection customers’ responsibility to demonstrate an acreage-per-megawatt minimum can be done without providing a site plan map. MISO would require customers provide a location map as part of site control 90 days prior to the start of planning studies.

Some stakeholders still contended that an acre-per-megawatt demonstration and a project site map are two different requirements. Coming up with a site map is an administrative burden, they said.

“I just don’t see how you demonstrate site control without providing a map,” responded Paul Muncy, of MISO’s transmission access planning division.

Mike Blackwell, with MISO’s legal staff, said he didn’t see how a site plan map amounted to an administrative burden because any prospective project applying to the queue should at least already have a location map or parcels for lease options.

Ghodsian said interconnection customers should be prepared to submit an approximate project layout, even if the location changes from the final site control demonstration due at the time of signing the generator interconnection agreement.

“Initially what we’re asking is, ‘Do you have enough land for your project?’ … I don’t think this is that burdensome. If your project is ready, you should be able to put land on a site map for us,” Ghodsian said.

Other stakeholders pointed out that the queue takes three years to complete, and providing a facility site map so early in the process all but guarantees location changes.

Ghodsian said early site maps will help MISO determine whether multiple projects are proposing to develop on the same property. Maps help weed out site overlap instances later in the queue, he said.

Stakeholders also questioned MISO’s proposal that interconnection customers provide a full demonstration of site control prior to entering the DPP, pointing out that two years ago, FERC deemed sufficient a 75% demonstration of site control at the time of interconnection application.

Ghodsian said the 100% site control requirement was not up for renegotiation in the refiling. He said the new proposal will stick to the same principles as the original but take FERC guidance into account.

MISO Resource Interconnection Planning Manager Neil Shah said the changes are as important as ever, given that the RTO received 45 GW of new project requests this spring, bringing the queue to more than 100 GW.

“Everybody involved in that process knows that not all are going to go through,” Shah told Planning Advisory Committee members in June. “In short, the urgency is about processing the projects in the queue as quickly as possible.”

MISO’s current generator interconnection queue includes 642 prospective projects totaling 100.6 GW.

Except for its western region, MISO will begin processing the slate of projects received in April in October or November. Because of the large number of interconnection requests in the west, the RTO will begin work on those projects in August.

MISO has negotiated more than 30 interconnection and construction agreements so far in 2019; the RTO projects it will negotiate upward of 130 agreements by year-end.

Other Time Savers

The RTO is also pursuing other avenues to reduce the amount of time projects spend in the interconnection process.

Queue engineer Will Buchanan said MISO will continue building DPP system models in-house after a successful trial run.

“MISO was able to save a considerable amount of time in the 2018 cycle versus past years,” Buchanan said.

Buchanan said the RTO’s handling of queue modeling will maintain a consistency it couldn’t achieve when it outsourced modeling work to third parties. The move also cut out the “months of delay” that it experienced with modeling vendors, Buchanan said.

MISO will also create an instant, online application for interconnection requests, replacing its previous print-and-return PDF form.

Finally, MISO is betting it can shave an additional 10 days off the queue by requiring the bulk of stakeholder model reviews take place prior to the kickoff of DPP cycles. It will allow 10 business days from model posting for stakeholder review and another five business days for any final review after the official start of the DPP.

Stakeholders said shortening the timeline on model review may increase the margin for error, especially in MISO’s western states, which currently account for 69 project requests alone in the DPP. But RTO staff countered that no review time would be lost, with the idea being that MISO releases models sooner so stakeholders can begin sizing them up earlier.

“If we can get the models out earlier, it gives people more time to review. … We’re trying to give you an extended period. It just doesn’t look the same as it does now,” Buchanan said.