Page 1307 – RTO Insider

June 13, 2017

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — It took another hour of debate, but stakeholders at last week’s Market Implementation Committee meeting found just enough consensus to approve a problem statement and issue charge developed by PJM to analyze potential changes in how energy efficiency resources can participate in wholesale markets.

The vote was precipitated by a Kentucky Public Service Commission order saying state retail electric customers have no authority “to participate directly or indirectly in any wholesale electric market.”

The Advanced Energy Economy has also petitioned FERC to issue a declaratory order on the topic.

“There was a state commission that was being asked to clarify its requirements” for letting in-state energy efficiency aggregators bid into the RTO’s energy efficiency market, PJM’s Denise Foster said. “We looked at the rules in PJM and realized there was no way for us to respect any determination that came out of that process. … There was a lot of discussion about jurisdiction … but there was also a lot of discussion about how proscriptive the problem statement and issue charge was — so we cleaned up the problem statement.”

Foster was careful to clarify that PJM doesn’t want to get involved in the regulatory process but seeks to move the analysis forward to be ready to take action as soon as FERC has made a decision. (See “Energy Efficiency Proposal Sparks Debate over State Jurisdiction, Stakeholder Identification,” PJM Market Implementation Committee Briefs.)

Representatives of utilities involved in the issue — including Dana Horton of American Electric Power, Chuck Dugan of the East Kentucky Power Cooperative, Jim Benchek of FirstEnergy and Brian Garnett of Duke Energy — all voiced support for the problem statement. Benchek pointed out that rule changes should be careful to avoid unintended effects on electric distribution companies.

Rick Drom, an attorney representing AEE along with an unnamed energy efficiency aggregator in Kentucky, reiterated his position that the activity is premature.

“I was glad to hear [the utilities] say that once the FERC jurisdictional issues are resolved, then we can move forward with the problem statement, because I think it’s very clear that until FERC jurisdictional issues are resolved, it would be difficult to modify the Tariff,” he said. “To me, this is a simple educational issue.”

Energy efficiency resource providers contract with manufacturers and wholesale retailers, not with retail customers, Drom said, suggesting that the Kentucky PSC might not be aware of that nuance. He warned that by moving forward with the problem statement, “PJM stakeholders will be spending resources on a problem that simply does not exist.”

Dugan said retail customers’ rates will be adversely impacted by energy efficiency providers.

“I don’t think any education is going to change their mind,” he said of the Kentucky PSC. “I truly believe they knew what they were talking about.”

Other stakeholders raised points on both sides of the issue, including EnerNOC’s Katie Guerry, who said PJM’s demand response processes still have “kinks” to be worked out. “I do see value in working out the kinks in advance,” she said.

CPower’s Bruce Campbell motioned to defer a vote on the problem statement until after FERC has ruled, a measure seconded by Tom Rutigliano, who represents energy efficiency providers. That measure failed.

Stakeholders discussed whether the problem statement’s language should be further neutralized. Foster said PJM was very deliberate in its word choices because it didn’t want to be in a position of determining whether participants need to be in compliance.

The measure eventually passed with 85 votes in favor, 81 opposed and 14 abstentions.

All DR Registration Changes Fail

After months of discussion in the Demand Response Subcommittee, all three proposals for increasing flexibility to add and subtract resources from aggregators’ portfolios failed to garner necessary stakeholder support. The three options differed on registration deadlines and testing requirements. (See “DR Open Registration Under Consideration,” PJM Market Implementation Committee Briefs.)

Guerry and NRG Energy’s Brian Kauffman were quick to register their opposition.

“At the outset of this discussion, we had reservations because we knew it was going to be very complicated” and create administrative problems along with additional costs that must be passed on to customers, Guerry said. “From our perspective, it just sort of spiraled out of control.”

Independent Market Monitor Joe Bowring challenged Guerry’s opposition, asking whether she opposed the idea of requiring removal of resources that can no longer reduce load.

“Do I have a specific opposition to that? No, I do not … but these are the additional layers of complexity that we believe are unnecessary just to allow the registration window to be open beyond the window that it’s open to right now,” she said.

“One person’s complexity is another’s solution to a problem, but I understand what you’re saying,” Bowring said.

Campbell, who proposed the problem statement, acknowledged that he hadn’t foreseen some of the issue’s complexity but was simply attempting to make DR comparable to generators, which can enter PJM’s markets at any time.

FTR Revisions Continue Forward

Three new proposals for revising financial transmission rights rules moved forward, although one didn’t advance as easily as the rest.

The wave of FTR actions began when stakeholders endorsed by acclamation revisions to Manual 28 regarding allocation of balancing congestion.

A problem statement and issue charge presented by Direct Energy’s Jeff Whitehead to review the allocation of surplus funds for day-ahead congestion and FTR auction revenues received a little more discussion. GT Power Group’s Dave Pratzon asked if the adjective “alternative” could be substituted for “appropriate” in describing the disposition of the surpluses. The issue, which had received substantial debate previously, was subsequently approved. (See New FTR Task Force on the Way for PJM?)

The final measure, resolving delayed results for periods of the year when there are several overlapping FTR products available, didn’t fare as easily. Bruce Bleiweis of DC Energy suggested the issue might be technological.

“We think that PJM may not be using the most efficient clearing engine,” he said.

PJM Market Implementation Committee — Scarpignato | © *RTO Insider*

Other stakeholders offered differing perspectives. Eventually, Calpine’s David “Scarp” Scarpignato threw up his hands to register his confusion.

“I can’t vote to approve this problem statement because too many people are interpreting it in too many ways,” he said. “I hate telling people to come back with another rock, but this doesn’t do it for me.”

As the meeting broke for lunch, stakeholders debated the issue and eventually agreed upon a two-phased problem statement and issue charge. The first phase would explore reducing the overlapping periods while maintaining liquidity through other market enhancements, and the second would explore other ways to solve the issues, such as through algorithm or technological changes. The revised document subsequently received endorsement.

PJM’s Asanga Perera noted that a special session of the MIC will be held on June 23 to begin exploring the issues.

Started from the Bottom, Now We’re at the MTSL

PJM and the Monitor remain at odds over how much compensation black start units should be allowed to receive for storing fuel.

The RTO is willing to cover storage costs for the oil units require to meet its black start requirement — usually 16 hours of operation — plus the minimum tank suction level (MTSL), which is the lowest amount of fuel needed to provide adequate supply to the generation unit, PJM’s Tom Hauske said.

Bowring argued that the incremental cost of keeping the level of fuel needed for black start capabilities is zero. The tanks are often used for multiple units and are so large that the black start needs are but a small fraction of the tank’s overall MTSL.

Bowring later added that his office agrees with PJM that black start units should be paid carrying charges on the fuel required to meet the 16-hour obligation and for the MTSL when there are tanks dedicated to them.

“But the PJM approach can require customers to pay for more than 10 times the MTSL required for the black start unit, depending on the size of the tank,” he said. “The PJM approach assigns to the black start unit the MTSL for a very large tank that was designed to serve another unit and continues to serve that other unit. The actual MTSL does not change by even a gallon when a black start unit is added for such a unit. The result is unfair to all the customers who pay for black start service.”

Balancing Differences

A PJM analysis of FTR data became a battleground when Roy Shanker, an industry consultant, took exception to the numbers suggesting that auction revenue rights holders benefited from a recent FERC order that allocated the costs for balancing congestion to load.

Perera presented the analysis, which suggested that the value of FTRs for the 2017/18 delivery year would have increased by $91 million compared to the previous year, during which balancing congestion was allocated to the ARR holders.

While other stakeholders defended the analysis as an important backward-looking review, Shanker complained that it seemed to be sending a message.

“I do mind when [the numbers are] represented as a metric of the benefit to the ARR holders,” he said.

“I agree it’s a material difference in perspective: I’m paying for balancing congestion and you’re not,” Direct Energy’s Whitehead countered.

“And you always should have been!” Shanker immediately shot back.

Bowring said the numbers should be neutral, but analysis should still be done. “I would be shocked if there’s a net benefit, but if there is, there is,” he said.

– Rory D. Sweeney

June 13, 2017

PJM Planning Tx Expansion Advisory Committees Briefs

VALLEY FORGE, Pa. — While some components remain to be finished, the major elements of PJM’s proposed structure for its competitive planning processes moved past the Planning Committee at last week’s meeting.

PJM’s Michael Herman presented the final version of the new Manual 14F, which outlines rules for competitive bidding on transmission projects as established in FERC Order 1000. The committee finally endorsed the manual, which has struggled to gather momentum and was sent back to staff for revisions several times in recent months.

Members have criticized the manual for its silence on how project bidders might include cost-containment provisions in their proposals and any preferential treatment such assurances might provide, but PJM has pushed to make the manual active prior to opening a competitive-bidding window later this summer. Staff have organized a series of special sessions of the committee to develop cost-containment rules, which will later be added to the manual. (See PJM Kicks off Transmission Cost Cap Initiative.)

John Farber, who represents the Delaware Public Service Commission, asked if construction contractors must meet any standards. PJM’s Sue Glatz assured him the manual includes prequalification standards for bidders.

Members also endorsed a series of design standards to be included in designated entity agreements, which successful bidders must sign with PJM. The endorsement covers standards for overhead lines, substation construction and system protection. The Designated Entity Design Standards Task Force is still developing standards for underground and HVDC lines, Herman said.

PJM is planning to transition the task force into a subcommittee that would continue to review and update standards based on biennial reviews instead of being disbanded following the completion of its charter, Herman said.

PJM Planning Committee forecasted summer peaks — Tatum | © *RTO Insider*

Steve Lieberman and Ed Tatum, who represent American Municipal Power, reiterated previous concerns that the design standards will not require additional endorsement from the Markets and Reliability Committee, which is the standard procedure for most rule implementation at PJM.

“I think that’s really inappropriate,” Tatum said.

Glatz explained that the standards are referenced in revisions to Manual 14C, which will require MRC endorsement. Those revisions, which require that all designated entities follow the design standards, subsequently received planning committee endorsement. (See “DEDS Task Force Ends at PC,” PJM Planning Committee/TEAC Briefs.)

McGlynn Becomes PC’s New Chair

Paul McGlynn, PJM’s senior director of system planning who has long overseen the Transmission Expansion Advisory Committee, has assumed duties as the chairman of the Planning Committee. He succeeds Steve Herling, PJM’s vice president of planning.

McGlynn acknowledged Herling “will certainly be a tough act to follow” but was confident stakeholders won’t notice much of a change in leadership styles.

He brings a decade at PJM and three decades of industry experience to the position, having started in 2007 as a manager of transmission planning and being promoted to his current position two years later. Prior to that, he worked at PECO Energy for 20 years in various engineering and operations positions.

He expects the committee to focus on evolving the planning process as needs change to integrate new technologies, such as distributed energy resources, storage and system resilience. He also plans to work with stakeholders on refining PJM’s Order 1000-compliant competitive bidding processes “to improve efficiency and transparency.”

PJM Reconsidering Planning Assumptions

PJM staff announced plans to revisit several of its planning assumptions in light of new data. The revisions come as the RTO analyzes how it plans to address resilience in system planning. PJM’s Mark Sims said the goal will be to consider potential events and create simulations to study system performance in the face of infrastructure failures such as voltage collapse or thermal issues.

“We want to think about what could happen and run the simulations,” he said. “From a planning point of view, [the focus will be to] absorb and adapt.”

“Resilience is a really broad topic,” McGlynn said. “What we want to focus on, obviously, is what resilience means from a planning discussion.”

First on the list is PJM’s light-load reliability analysis criteria, which were established in 2011. A lot has changed since then, Sims explained, including EPA’s publication of its Mercury and Air Toxics Standards and the emergence of the shale gas boom.

“At the time, the data was telling us that natural gas was barely operating during the [light-load] period,” he said.

Demand has also dipped significantly in the interim. Several of PJM’s 27 zones experience light-load conditions of less than 35% of the forecasted summer peak load for a “significant number” of hours, he said. That difference can create voltage spikes that cause problems for grid operators.

PJM plans to begin updating its light-load criteria with several changes, Sims said. First, the load-modeling assumption will be reduced from the current 50% of forecasted summer peak to a more appropriate percentage. Next, natural gas’ capacity factor for base generation dispatch will be increased from the current 0% to a percentage more in line with current usage. Additionally, PJM plans to establish a ramping limit for natural gas based on statistical data.

Finally, the deliverability ramping limit for wind would be increased from 80 to 100% of nameplate capacity.

Sims acknowledged there are other tweaks to be made, but they would be “sharpening the pencil” beyond addressing the concerns at hand.

“We have some definite issues, for example, with the lower loads and natural gas that are here today,” he said.

PJM also plans to revise its capacity emergency transfer limit (CETL) calculation methodology. Currently, PJM models firm existing transfers and assumes non-firm flows will materialize up to the transmission system’s capacity limits. But data confirms that those external zones will likely be experiencing the same capacity emergencies and unable to provide support. NYISO’s eastern region and PJM have peaked on the same day, and sometimes the same hour in four of the past six years, Sims said.

“A lot of questions came out of the [Regional Transmission Expansion Plan] planning parameters,” he said. “We’re assuming our neighboring systems can support us, but maybe that doesn’t make sense.”

Sims also noted that, unlike HVDC lines that can adjust power flows quickly, phase-angle regulators must be manually adjusted and “take time.” Several of the ties between NYISO and PJM are controlled by PARs.

Many of the insights Sims noted were pointed out by Public Service Electric and Gas in a letter the utility sent to PJM’s Board of Managers in May. (See “Following PSE&G Complaint, PJM to Discuss Updated CETL Requirements,” PJM Planning Committee/TEAC Briefs.)

Analysis Strategy Announced for Market Efficiency Projects

The plan for analyzing market efficiency project proposals in the 2016-17 window begins with interregional projects, PJM’s Nick Dumitriu said at last week’s meeting of the Transmission Expansion Advisory Committee. The window is part of PJM’s RTEP.

Interregional projects will be considered first, he said, because they require the most lead time when factoring in interregional coordination. Both energy and potential capacity benefits will be examined, he said.

Proposals for the PPL region will be analyzed next, followed by those in the Baltimore Gas and Electric region. “Slam dunk” projects — considered low-cost upgrades with high benefit-to-cost ratios and minimum competition — will be analyzed in parallel. All other regional projects will be analyzed last.

Responding to an inquiry from LS Power’s Sharon Segner, Dumitriu confirmed that PJM will re-evaluate previously submitted projects in parallel and present them after the base case is completed, likely at the July or August TEAC meetings. PJM hopes to have the interregional, PPL and “slam dunks” ready for presentation to the board at its meeting in October, with BGE and all other projects ready for the board’s December meeting.

Accelerated AEP Project Won’t Increase Costs

PJM staff noted that an American Electric Power proposal to speed up the timeline of a planned reconductoring project won’t incur any incremental costs.

The previously approved baseline projects 1-11B and 1-11C to reconductor the Dequine-Eugene-Meadow Lake 345-kV line in western Indiana will provide Reliability Pricing Model benefits by improving CETL values, along with energy benefits for reducing congestion. The projects are scheduled to be in service by 2021, but AEP has offered to complete them by 2019, saving two years of congestion costs.

“Anything divided by zero turns into a pretty big number pretty quick, so I think we’d continue to recommend that the project get done by 2019,” McGlynn said.

Detail of Proposal Descriptions Still a Concern

Stakeholders reiterated concerns about what they felt was a lack of information about project details. While PJM staff were attempting to clarify the complicated history of proposals to alleviate constraints on the Olive-Bosserman 138-kV line in northern Indiana, Tatum took the opportunity to log the frequent complaint.

“You are aware, though, that we don’t share your opinion that the information provided and the methodologies shared so far are adequate?” he asked Sims in reference to the information AEP provides about its proposals.

“I thought we were getting pretty close,” Sims said, noting that AEP has held several regional meetings — attended by Tatum — at which company representatives have explained their internal methods. Tatum acknowledged that the meetings were informative, but he asked for a greater level of detail in the TEAC slides.

Mark Ringhausen of Old Dominion Electric Cooperative asked when PJM plans to implement meetings for localized planning and stressed the importance of seeking input throughout the process from the stakeholders such as ODEC and AMP, who pay for the upgrades.

Sims acknowledged the importance of getting their buy-in. “We want to know upfront what are the expectations so we can work toward that instead of getting to the end and having to change things,” he said.

Segner noted that because some states don’t have certificates of public convenience and necessity, local planning is even more important there.

Project Delay Creates Controversial Cost Increase

Recent analysis by PJM shows that a once-approved Virginia project is still needed to alleviate reliability violations but will now cost nearly twice as much.

The PJM Board of Managers in 2014 approved rebuilding Station C in the Dominion zone along the Potomac River and installing a new 230-kV line from there to the Glebe station at a cost of $165.4 million.

The project was never constructed. Since then, the estimated cost has nearly doubled.

Several alternatives were considered, Sims said, but ultimately the cheapest option turned out to be connecting the two stations via a line under the river. However, local regulations require expensive “micro tunneling” for the line, and Station C must be rebuilt as a gas-insulated substation. Add in construction of a PAR, and the new estimated cost is nearly $300 million.

Given the substantial cost increase, Ringhausen asked PJM to revisit the alternative solutions and see if any of them are comparatively cheaper now.

“I think we owe it to the folks paying the bill to look at it again,” he said.

“I’m not sure it’s going to be fair to put them all side by side,” Sims said, as it would compare the current estimate for the proposed solution with 2014 estimates for the alternatives. But Ringhausen suggested updating the estimates should be a quick process.

Stakeholders also inquired whether the project could be reopened to a competitive bidding window, but PJM staff were concerned it might throw off project timing.

– Rory D. Sweeney

June 13, 2017

ISO-NE: Won’t Override States on Public Policy Tx Needs

By Michael Kuser

ISO-NE on Friday rejected a request that it conduct an independent analysis on whether state renewable energy and carbon reduction policies are creating a need for additional transmission.

The RTO acted in response to the Conservation Law Foundation’s May 16 letter asking it to conduct the analysis despite a May 1 submission by the New England States Committee on Electricity, which said there are no current transmission needs, although some could arise in the future.

Conservation Law Foundation FERC Order 1000 ISO-NE — Rollins Wind Farm in Maine | *Reed & Reed, Inc.*

“The ISO disagrees with the conclusion reached in the May 16 CLF letter,” Theodore J. Paradise, ISO-NE assistant general counsel for operations and planning, said in a June 9 letter to CLF Senior Attorney David Ismay. “The Tariff is clear that while there is a process for stakeholders to request an ISO review of the NESCOE letter regarding federal public policies, there is not a similar review provision for state public policy determinations made by the New England states and communicated through NESCOE.

“What NESCOE did provide satisfies, and exceeds, what is required by the FERC-approved Tariff language,” Paradise added. “Not only was a written communication regarding the existence of public policies that may drive transmission provided [by NESCOE], but each New England state submitted, as part of that communication, a thorough and reasoned explanation of why each of the identified statutes and regulations are not driving the need for new transmission in the regional planning process.”

Ismay had said NESCOE’s report was “legally insufficient for purposes of the regional system planning determinations that [FERC] Order 1000 requires.”

NESCOE responded to the CLF letter on June 1, saying that ISO-NE should only evaluate potential projects after states have indicated transmission needs resulting from their policies. (See NESCOE Defends Role in Identifying Public Policy Tx Needs.)

Ismay told RTO Insider on Monday that CLF is considering filing a complaint with FERC in response to the RTO’s determination. It “is obvious to all in the region … that state public policies, particularly those of Connecticut, Rhode Island and Massachusetts, are driving the procurement of large volumes of renewable and other low-carbon generation that are directly impacting regional transmission,” he said.

June 13, 2017

UPDATE: Trump Fights Congress, History with Tx Sale Bid

By Jason Fordney and Robert Mullin

Donald Trump is the fourth president since Ronald Reagan to propose selling off assets of the federal power marketing administrations (PMAs). Based on congressional response, he is unlikely to be the first to make it happen.

About three dozen members of Congress have joined publicly owned power utilities in opposing Trump’s plan, part of his proposed fiscal 2018 budget released May 23. It would sell the transmission assets of the Bonneville Power Administration, Southeastern Power Administration, Southwestern Power Administration and Western Area Power Administration to private investors for an estimated $5.5 billion over a decade.

CAISO trump congress — President Donald Trump | © *RTO Insider*

The four agencies own a combined 34,000 miles of transmission, nearly all of it belonging to BPA and WAPA. About 1,200 public power utilities and rural electric cooperatives in 34 states purchase electricity from federal hydropower plants via the PMAs.

The elected officials and public utilities disagreed with Trump’s rationale that increasing the role of the private sector would encourage more efficient allocation of resources and lower taxpayer risk.

Twenty-one senators, including Democrats Maria Cantwell of Washington and Dianne Feinstein of California, as well as Republican James Risch of Idaho, last week wrote Energy Secretary Rick Perry to oppose the plan. “There are improvements that can and should be made to the operations of some PMAs, but the dismantling of them is simply not sound governmental policy,” says the June 7 letter.

Power marketing is one of the few federal programs that pays for itself, and it actually benefits the government’s balance sheet, they said. The PMAs also support flood control, navigation, irrigation and other critical services at federal dams.

Cantwell in a tweet called the proposal “a short-sighted plan that will take money out of the pockets of consumers and businesses in our states.”

Sen. Ron Wyden (D-Ore.) last week voted to oppose the nomination of Dan Brouillette as deputy secretary of energy because Brouillette would not commit to keeping BPA in public hands in response to a written question from the senator.

“I cannot support a nominee who won’t even say whether he opposes a proposal that would hike energy prices for Northwest customers who have invested in a system that runs successfully on its own,” Wyden said in a statement.

Wyden called the proposal to sell off BPA assets a “non-starter.”

Fifteen members of the House of Representatives from Northwestern states also wrote Perry to oppose the plan, saying it would “harm individuals and businesses, divert capital needed for further infrastructure investment in the Northwest and undermine regional utility coordination.” They include Rep. Peter DeFazio (D-Ore.), ranking member on the House Transportation and Infrastructure Committee.

Scott Corwin, executive director of the Portland-based Public Power Council, which represents publicly owned utilities in seven Western states that benefit from low-cost power sold by BPA, said there has been “excellent engagement from Congress” in opposing the proposal.

“On a bipartisan basis, every senator from the Northwest, and every member of the House from Oregon and Washington signed letters of opposition,” Corwin told RTO Insider. “I have not yet heard of anyone pushing [the sale of the PMA transmission] on the Hill.”

Publicly owned utilities also oppose the proposal, saying it is more likely that private owners would increase transmission rates for the same service they now receive.

“These arguments are merely a pretext for actions that would raise electricity costs for millions of people and businesses,” says a June 6 letter to Perry from the American Public Power Association and the National Rural Electric Cooperative Association.

Customers have paid “all power program expenses, plus the interest on any capital projects, and have ensured continued investment in the federal infrastructure,” they said.

The administrations of Presidents Reagan, Bill Clinton and George W. Bush also proposed selling off the PMA assets, but the efforts did not gain traction in the face of heavy Congressional opposition.

Even so, Corwin was cautious about dismissing the prospects for this latest move.

“There are a couple of things that are different this time that makes the proposal worth watching closely,” he said. “First, the fact that it was limited to the transmission systems lends a different dynamic. And, second, the level of uncertainty in Washington, D.C., in general means that it is wise to take nothing for granted.”

Portland-based energy economist Robert McCullough estimates that the budget’s proposed $4.9 billion in revenues from the sale of Bonneville’s transmission network represents just 80% of the value of those assets, based on the power agency’s own published estimates.

“This raises the question of why these valuable assets would be sold at a discount — and who would get the benefit of the discounted price,” McCullough Research said in a June 13 report.

McCullough’s firm also calculated that the sale would increase transmission rates by either 44% under a “most likely scenario” in which the transmission is valued at its actual worth or 26% based on a “less likely scenario” in which FERC reduces the regulatory value — or rate base — of the assets to the proposed sale price.

“Most importantly, privatization of BPA would increase costs for consumers,” the report said. “BPA currently sells and delivers its power at cost; under a private regime, an investor-owned utility would likely charge a higher rate of return.”

Wyden called BPA a “key part” of his state’s economic future and that selling off its assets would “strangle the power supply for businesses” and “stretch” the budgets of residents.

“Pacific Northwesterners have fought this battle before and we’re going to fight these malicious efforts again,” Wyden said.

June 13, 2017

CAISO Boosts Reserves After August Event Report

By Jason Fordney

CAISO will temporarily increase its daily procurement of operating reserves in response to findings that the erroneous tripping of solar generation caused the loss of 1,200 MW of output as the Blue Cut fire burned in Southern California last August.

operating reserves caiso solar — SolarStar Utility Scale Solar Project | *BHE Renewables*

Beginning June 14, the ISO will procure more operating reserves in response to last week’s NERC report showing that solar inverters — which convert photovoltaic DC output to utility frequency AC — are susceptible to erroneous tripping during transients caused by faults on the power system. The ISO did not say how long it will keep the measure in place.

A NERC/Western Electricity Coordinating Council task force said the loss of inverter power injection was caused by a perceived low-frequency condition and low-voltage blocking of inverters. The inverter manufacturer recommended changes to inverter settings to prevent the erroneous tripping, and CAISO and Southern California Edison are working to develop a corrective plan.

The inverters tripped on Aug. 16 as the Blue Cut fire raged in the Cajon Pass and quickly moved toward an electric transmission corridor containing lines owned by SCE and the Los Angeles Department of Water and Power. There were 13 faults on 500-kV lines and two 287-kV faults that took down 1,200 MW of solar. The facilities did not de-energize, but they ceased output because of the system faults, with the most significant losses occurring around 11:45 am. Four of the faults (see chart) caused losses of PV generation.

Utility-scale solar PV output in SCE footprint on Aug. 16, 2016. Four of 15 faults that day caused losses of PV generation. | *NERC*

CAISO said it will increase its reserves “to minimize the potential impact due to loss of inverter power injection during a single transmission contingency event.” More reserves will be procured during solar operating hours, and the total target reserve amount will be up to 25% of forecast solar production.

The task force recommended a minimum delay for frequency tripping to ensure an accurate system frequency measurement and that inverters be equipped to quickly return to operation if they cease supplying power during voltage excursions.

It also said generation owners and operators should receive an alert to ensure they are aware of recommended changes to inverter settings.

“With the proliferation of solar development in all interconnections across North America, the results of this disturbance analysis need to be widely communicated to the industry highlighting the present potential for widespread solar resource loss during transmission faults on the [bulk power system],” NERC said.

The growing use of inverter-based technologies that operate in microseconds is rapidly changing the characteristics of the power grid and presents some new challenges, NERC Vice President of Reliability Risk Management James Merlo said in a statement. The loss of generation was a “previously unknown risk to reliability,” and NERC is taking steps to mitigate the risk, he said.

June 13, 2017

Experts ID New Cyber Threat to SCADA Systems

By Rich Heidorn Jr.

Two cybersecurity firms on Monday disclosed what may be the most dangerous cyber threat yet to U.S. power systems: malware that can take control of circuit breakers without any manual involvement.

Maryland-based Dragos and ESET, a Slovakian anti-virus software provider, said the malware — which the former is calling CrashOverride and the latter Industroyer — was likely the cause of a disruption last December that cut about one-fifth of Kiev’s power consumption for about an hour.

Unlike the December 2015 hack of the Ukraine system — caused by the BlackEnergy program that took advantage of vulnerabilities in Microsoft Office and required manual intervention to control circuit breakers — the new threat takes advantage of the simplicity of supervisory control and data acquisition (SCADA).

Dragos said CrashOverride is the first malware framework designed specifically to attack electric grids and the fourth ever piece of malware tailored for industrial control systems. It follows BlackEnergy 2, Havex and Stuxnet, the last of which was believed deployed by the U.S. to hack centrifuges used in Iran’s nuclear weapons program.

Dragos founder Robert M. Lee told Reuters that the malware could be used to attack power systems across Europe as is and in the U.S. “with small modifications.” It could cause outages of up to a few days in portions of a nation’s grid, he said.

The program can be detected if utilities monitor their networks for abnormal traffic, such as indications that it is searching for the location of substations or sending messages to breakers, according to Dragos.

The program’s “dangerousness lies in the fact that it uses protocols in the way they were designed to be used,” wrote Anton Cherepanov, senior malware researcher for ESET. “The problem is that these protocols were designed decades ago, and back then industrial systems were meant to be isolated from the outside world. Thus, their communication protocols were not designed with security in mind. That means that the attackers didn’t need to be looking for protocol vulnerabilities; all they needed was to teach the malware ‘to speak’ those protocols.”

Cherepanov said the program can remain undetected and eliminate traces of itself after its work is complete.

“For example, the communication with the [command and control] servers hidden in Tor can be limited to non-working hours. Also, it employs an additional backdoor — masquerading as the Notepad application — designed to regain access to the targeted network in case the main backdoor is detected and/or disabled,” Cherepanov wrote.

Part of the “dark web,” the Tor network allows users to access the Internet through “virtual tunnels” rather than making a direct connection, allowing them protect the privacy of their communications. It has been used to circumvent government censorship and by journalists to communicate with whistleblowers and dissidents. The U.S. Department of Homeland Security said TOR IP addresses were used by the Russian hackers who stole data from the Democratic National Committee before last year’s presidential election.

“What makes this thing a holy-crap moment is the understanding of grid operations encoded within it,” Lee told the Daily Beast. The program can run continuously, requiring manual overrides to interrupt it. “It’s like a popup on a website, where you close it and it just keeps opening again. That’s what they’re doing to circuit breakers.”

In a statement Monday from Marcus Sachs, chief security officer for the Electricity Information Sharing and Analysis Center (E-ISAC), NERC said it is aware of the threat but that “there are no reported instances of the malware in North America.”

NERC said it will update its Ukraine Defense Use Case report, issued in March, to reflect the new information.

“There is no question that cyber threats like the one in Ukraine are real and that constant vigilance is needed to protect the reliability of the North American grid,” Sachs said.

It is not certain who authored the malware.

Dragos tied it to a group called Electrum, the same group behind the 2015 Ukraine attack that left 225,000 customers in the dark. The group is believed to be tied to the Russian government. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)

But a spokesman for Ukraine’s state cyber police told Reuters it had not been able to confirm Dragos’ claim because the security firms hadn’t provided authorities with samples of the code they analyzed.

Lee told The Washington Post the outages caused by CrashOverride would probably not last more than a few days in the U.S. because the electric industry is prepared to respond to disruptions from violent weather. “They’re used to having to restore power with manual operations,” he said. While it is “a significant leap forward in tradecraft, it’s also not a doomsday scenario.”

June 13, 2017

Experts ID New Cyber Threat to SCADA Systems

By Rich Heidorn Jr.

Two cybersecurity firms on Monday disclosed what may be the most dangerous cyber threat yet to U.S. power systems: malware that can take over control of circuit breakers without any manual involvement.

Maryland-based Dragos and ESET, a Slovakian anti-virus software provider, said the malware — which the former is calling CrashOverride and the latter named Industroyer — was likely the cause of a disruption last December that cut about one-fifth of Kiev’s power consumption for about an hour.

Dragos founder Robert M. Lee told Reuters that the malware could be used to attack power systems across Europe as is — and in the U.S. “with small modifications.” It could cause outages of up to a few days in portions of a nation’s grid, he said.

Cherepanov said the program can remain undetected and eliminate traces of itself after its work is complete.

NERC said it will update its Ukraine Defense Use Case report, issued in March, to reflect the new information.

“There is no question that cyber threats like the one in Ukraine are real and that constant vigilance is needed to protect the reliability of the North American grid,” Sachs said.

It is not certain who authored the malware.

June 12, 2017

SPP Members Send Z2 Alternatives to MOPC

By Tom Kleckner

SPP members are advancing at least two alternative solutions to address the RTO’s complicated crediting system for transmission upgrades.

The Z2 Task Force agreed last week in Kansas City to present two proposals to simplify the process spelled out in Attachment Z2 of SPP’s Tariff for assigning financial credits and obligations for sponsored upgrades to the Markets and Operations Policy Committee next month for members’ feedback. The proposed alternatives are among the same three the group has spent several months hashing over. (See SPP Members Again Struggle with Solutions to Z2 Credits.)

SPP z2 credits MOPC — Xcel Energy upgrade project *Burns & McDonnell*

“We’re doing an awful lot of talking, but we’re not getting anywhere,” Oklahoma Gas & Electric’s Greg McAuley said during the task force’s meeting.

The problem, McAuley told RTO Insider, is that there’s still not enough detail in the proposals to make informed decisions. But obtaining the necessary data would be “a significant undertaking in itself,” he said.

“Without some kind of analytical comparison, it’s difficult for anyone to make decisions,” he said. “There can be unintended consequences with any of these options that can be significant.”

That became apparent as members peppered Westar Energy’s Grant Wilkerson with questions as he ran through several scenarios related to his solution, which will be among those presented to the MOPC.

Under the Westar proposal, transmission rates would be calculated based on an average cost per megawatt. Wilkerson said his approach would not be affected by the order in which upgrade sponsors are compensated; rates would be trued up annually and credits would be based on directly assigned costs and usage factors (as determined by impacts identified in aggregate studies).

The task force also agreed to share staff’s proposal at the MOPC meeting. It agreed with staff’s recommendation to eliminate credits for new upgrades that don’t add transfer capacity and to eliminate credits for all short-term service, approving a pair of motions in roll-call votes. Staff agreed to provide additional data for the task force’s next meeting, when members will resume their analysis of the proposals.

A third proposal, incremental long-term congestion rights (ILTCRs), while no longer being considered a substitute for Z2 credits, also remains an option.

“I’m comfortable if people want to fund this stuff [with ILTCRs],” said Kansas City Power & Light’s Denise Buffington, the task force chair. “There isn’t any transparency to it, and I struggle to identify [the costs] to regulators. Maybe we do want to socialize the costs, but I don’t know if ILTCRs are any more transparent.”

The task force will meet again June 27 in Dallas. The MOPC meets July 11-12 in Denver.

June 12, 2017

MISO Embraces Monitor’s New Constrained Area Category

By Amanda Durish Cook

CARMEL, Ind. — MISO last week committed to adopting its Independent Market Monitor’s recommendation to implement market mitigation for a new category of narrowly constrained areas (NCAs) identified by momentary congestion and associated market power.

MISO narrowly constrained areas — Chatterjee | © *RTO Insider*

‎Within a month, the RTO will file Tariff revisions on a proposal to create dynamic NCAs after staff spoke extensively with the Monitor on the issue, according to MISO Director of Market Evaluation and Design Dhiman Chatterjee.

“Conceptually, we are in alignment that the broadly constrained areas leave open some needs,” Chatterjee said at a June 8 Market Subcommittee meeting.

But while MISO is adopting the Monitor’s proposal without changes, there are still some minor details to be worked out, and the RTO is accepting stakeholder feedback, Chatterjee said. The RTO and Monitor will both need to make software changes before the definition is introduced into the market in late fall after FERC approval, he said, adding that stakeholders have generally supported the idea.

“We don’t believe at this point there are any broad, outstanding questions that are in the way,” Chatterjee said.

Monitor David Patton recommended in April that the RTO expand mitigation measures on NCAs by creating a new definition aimed at short-lived congestion and applying mitigation if the constraint has bound in 15% or more hours over at least five consecutive days. The new category would set a conduct threshold at $25/MWh. The definition would differ from FERC-defined NCAs, which must bind for more than 500 hours annually. (See MISO IMM Recommends Tighter Rules for Constrained Areas.)

Patton said FERC’s definition of NCAs is inadequate because it only measures binding constraints annually and does not tackle intense but temporary congestion. Only about 10 to 15% of MISO’s footprint is subject to traditional NCA mitigation, in Patton’s estimation.

Patton said dynamic NCAs would only be declared in situational congestion where normal market participants have more market power than usual. Mitigation measures would be lifted once the binding congestion dissipates.

“It won’t be defined on a more permanent basis like the NCAs are,” Patton said.

June 12, 2017

MISO Examines Potential Mississippi Trading Hub

By Amanda Durish Cook

CARMEL, Ind. — MISO is considering establishing a possible commercial trading hub in Mississippi and will conduct stress tests and sensitivity analyses into the fall to help support its decision.

MISO South Trading Hub — Robinson | © *RTO Insider*

The RTO will use 12 to 15 months of hourly price and varying load data to create hub parameters and analyze the 618 existing pricing nodes in Mississippi and nearby areas in order to test the viability of the new hub, according to Michael Robinson, principal adviser of market design.

MISO will draft a white paper for stakeholders if the study concludes the Mississippi trading hub is worthwhile, Robinson said. The RTO hopes to finalize the hub in early November and have it go live in early December.

“It looks like there’s enough here to consider,” MISO South Vice President Todd Hillman said of the upcoming study at a June 8 Market Subcommittee meeting.

The RTO has deliberated over the issue since Mississippi became its 10th local resource zone in 2015, Hillman explained. “As the South region has gotten more knowledge, what we found is that when companies look for new locations, part of the reason they might do that is the gas infrastructure, but they also do it to join RTO pricing,” he said.

Hillman also said the state is especially looking for commercial growth. “Mississippi, as you know, is the poorest state in the country, so they’re looking to use their infrastructure.”

MISO has experience in creating and managing new trading hubs. Robinson said the RTO established the FE hub in 2005, redefined the Cinergy hub in 2010 and handled the addition of the Texas, Arkansas and Louisiana hubs during the MISO South integration in 2013.

“We’ve been through this process before, and it’s been a good process,” NRG Energy’s Tia Elliott said. She cautioned that, not being familiar with MISO’s process for creating a new hub, MISO South stakeholders could appreciate periodic updates. Robinson agreed and said he would work with Hillman to keep stakeholders informed about the situation.