PJM on Wednesday ordered its second load-shed event since implementing Capacity Performance in 2015, less than two months after ordering the first. (See PJM Experiences First Load Shed in the CP Era.)
Both events were in the American Electric Power zone.
The July 18 event occurred on the border between West Virginia and Virginia, PJM spokesperson Jeff Shields said. An AEP equipment issue led to other equipment being taken out of service, which resulted in “severe” low voltages in the area around Bluefield and Princeton in West Virginia.
PJM called on AEP at 11:14 a.m. to reduce load in the area by 32 MW to return the voltages to acceptable levels. Keeping the voltages low would have risked “potential further voltage problems and equipment damage that could cause wider problems,” Shields said, but assured that didn’t include any potential for cascading outages.
The order lasted for 83 minutes until PJM canceled it at 12:37 p.m. after the equipment was returned to service. Approximately 13,000 customers were affected.
While both events trigger the significant performance-related bonuses and penalties introduced with CP, no resources were impacted by either incident. The May 29 event was caused by transmission equipment unexpectedly tripping offline in the area of several planned transmission line outages, causing constraints that had potential to cause a cascading outage. (See “Load Shed Details,” PJM Operating Committee Briefs: July 10, 2018.) Prior to these events, PJM last ordered load shedding during the 2013 heat wave.
PJM plans to review the most recent event at its Members Committee meeting on July 23.
VALLEY FORGE, Pa. — PJM on Tuesday rolled out a proposal to procure reserves on a more granular level, a move the RTO hopes will shift more generator revenues back into the energy market.
“I do think that, philosophically, energy is the primary product in these markets,” PJM’s Stu Bresler said at a July 17 meeting of the Energy Price Formation Senior Task Force.
PJM is “not pricing reserves as well as we could,” Bresler said, adding that he expects the revenue distribution between energy and capacity markets to effectively work itself out if reserves prices are developed “as right as we can” make them.
The meeting began with PJM’s Cheryl Mae Velasco and Patricio Rocha-Garrido explaining that under current rules, a unit’s capacity can count as both synchronized reserves and more general primary reserves (which includes non-synchronized reserves), and that a unit would be compensated at a price that reflects providing each. For example, a unit can count as both $20/MW synch and $10/MW primary reserves and be paid a combined $30/MW. The amounts are calculated using “shadow prices” indicated by operating reserve demand curves (ORDCs) that are based on the probability of falling below the minimum reliability requirements for synch and primary reserves.
The shadow prices can vary extensively based on system circumstances, and even fall to $0/MWh, but the penalty factors are capped at $850/MWh. The payment, which is then also combined with a locational LMP, is designed to entice units to respond when called upon.
PJM’s Angelo Marcino discussed staff’s thoughts on how the ORDC can be adjusted to give grid operators more operational flexibility but still make sure that activity is captured in the market. They had been considering developing an “extreme day” ORDC but are now looking at revising on a case-by-case basis to adjust the reserve requirement rather than the slope of the curve, he said. The changes would be classified as either “market” adjustments that are determined through PJM’s clearing engine or “out of market” adjustments that grid operators assign based on issues observed that are not modeled in the RTO’s software.
PJM would ensure real-time notification of the adjustments and be responsible for keeping a historical record of them.
PJM’s Lisa Morelli also discussed staff’s concerns that current reserve zone modeling of the RTO zone with the Mid-Atlantic Dominion (MAD) sub-zone “doesn’t always accurately reflect the constraints dispatch is most concerned with overloading,” which can exacerbate constraints and result in reserve prices that don’t accurately reflect system conditions.
PJM is recommending including nodal reserve pricing and flexible sub-zone modeling in the task force’s discussion. The RTO would define several reserve sub-zones but only tackle one at a time. They could be defined by three categories of constraints: reactive transfer interfaces; 345-kV or larger actual overload constraints; or contingency overloads exceeding the load dump limit on a facility that is 345 kV or larger. PJM would notify participants about their use as early as possible, but provide at least one day’s advance notice.
Each subzone would have its own ORDCs for synch and primary reserves that would remain consistent with the RTO-wide methodology. Staff confirmed that units that hadn’t been assigned for reserves and are offline for some other reason wouldn’t be eligible to receive primary reserve payments.
‘Philosophical Issues’
The proposal sparked discussion from stakeholders about the potential implications.
Susan Bruce, representing the PJM Industrial Customers Coalition, said she was “comforted” to hear that the issues the proposal is meant to address don’t happen often but said she has “philosophical issues” with the market ramifications.
“PJM benefits as a reserve-sharing concept,” she said.
Bresler’s comments about energy as a primary market prompted Roy Shanker, a consultant for several generators, to warn that when the energy and ancillary services markets become “large enough, the behavior of the demand curve has to be examined.”
Bresler agreed that the capacity market’s variable resource requirement demand curve and the energy market’s ORDCs are connected.
Bruce asked that PJM and its Independent Market Monitor attempt to find “areas of consensus” on the topic.
“As much as can be done to narrow those gaps, especially from a customer perspective, that would be highly valued,” she said.
Bresler said staff are “working pretty hard” with the Monitor to come to agreement and that “the sooner that happens, the better off we and the stakeholder community will be.”
PJM also remained noncommittal on Bruce’s request for simulations to see how the proposal shifts revenues between the capacity and energy markets.
“Certainly industrial customers are concerned given their high volume usage,” she said.
PJM staff expressed concerned that stakeholders would judge the proposals on the simulated outcomes rather than the logic of the methodology.
“We do want to have principled reasons for the changes we’re making,” Bruce said, but she added that insight into the potential impact “would be a useful tool … so we can make the right choices before it’s too late.”
James Wilson of Wilson Energy Economics, who consults for several member states’ consumer advocates, said he was interested in “understand[ing] the consequences at a nitty-gritty level, not at an aggregate level.”
Bresler said that could be helpful with the caveat that nothing can be extrapolated to suggest larger consequences.
The meeting concluded with PJM’s Vince Stefanowicz explaining the next steps for developing the real-time 30-minute reserves product. The operational justification and methodology for defining the procurement target were endorsed at the July meeting of the Operating Committee and are moving on to be considered by the Markets and Reliability and Members committees. (See “Real-time 30-minute Reserves,” PJM Operating Committee Briefs: July 10, 2018.)
The price formation task force will focus on pricing the reserve target and optimizing with other ancillary services, determining what resources are eligible and coordinating real-time dispatch, he said.
GT Power Group’s Dave Pratzon asked that the discussion include an analysis to identify why the reserve deficiencies are occurring in the first place.
While the U.S. is keen to benefit from the declining costs of developing offshore wind energy, it appears less focused on learning how the industry matured in Europe, where it was pioneered in 1991.
That’s the assessment of two industry experts who, admittedly, have a stake in the issue.
“We see [regulators] focusing on the generation resource and assuming the transmission is going to be there, and not providing for the transmission necessary to get to scale,” said Stephen Conant, partner with Anbaric Development Partners, an independent transmission company.
The U.S. may be late to the game, but East Coast states are moving fast to join in.
The levelized costs for U.S. offshore wind has fallen steadily, making its development increasingly attractive in the relatively shallow waters off the Northeast coast. | DOI, DOE
In May, New Jersey set a goal of 3,500 MW of offshore wind by 2030, while Massachusetts awarded a contract for 800 MW and Rhode Island agreed to procure 400 MW. In June, Connecticut signed on for 200 MW, while New York regulators this month authorized state agencies to procure 800 MW by next year, the first phase of a plan to develop 2,400 MW by 2030. (See NYPSC: Offshore Wind ‘Ready for Prime Time’.)
Conant and his colleague Kevin T. Knobloch spoke to RTO Insider about Anbaric’s efforts to develop open access offshore transmission grids to facilitate offshore growth, particularly off the coasts of Massachusetts and New York.
Integrated Planning
In contrast to the U.S. approach, the European energy sector first builds out the transmission system and then has generators compete to an offshore interconnection point, Conant said.
“For example, in Germany, rather than have independent generators lead, they have 14 export cables with 34 different generators connecting to them,” Conant said. “That optimizes the export cables so you get the maximum amount of capacity and you optimize the terrestrial interconnection points.”
FERC in February granted Anbaric the right “to charge negotiated rates for transmission rights on a proposed integrated offshore transmission system that includes two HVDC transmission lines connecting Massachusetts offshore wind generation to the ISO-NE transmission system” (ER18-435).
The company’s Massachusetts Ocean Grid project would have two 1,000-MW HVDC transmission lines capable of delivering power from off the coast of Massachusetts to ISO-NE’s Southeast Massachusetts load zone.
Two 1,000-MW offshore platforms with AC switching stations would be linked by a subsea AC cable, and the electric energy would be converted to DC and transferred by two subsea HVDC cables to onshore convertor stations at two separate 345-kV substations.
Legislative Remedy
The Massachusetts offshore wind solicitation (83C) called for an expandable — and nondiscriminatory — transmission system, which means it would be open to all comers and not limited to one developer or generator.
However, nothing in the legislation authorizing the solicitation obligated it to be open to entities other than the generation developers that own the offshore leases.
“We’re in the process right now of some legislative activity to try to make changes in Massachusetts that would allow transmission to be separate from the generation and allow independent transmission companies to participate in that process,” Conant said.
As Massachusetts lawmakers consider a bill (H.4756) to increase the state’s renewable energy and reduce high-cost peak hours, Anbaric is lobbying to include an amendment that would allow independent transmission developers to participate in the next offshore wind solicitation.
“We thought things could be done better, and some of that comes from our looking at what’s been done in Europe, where they really develop the transmission separate from generation, which is really how they do the onshore grid here in the U.S.,” Conant said.
One of the upshots of the European approach: Generators are submitting zero-subsidy bids into the market.
“So you’ve got the generators essentially bidding in at market prices, and we think that’s where folks in Massachusetts and up and down the East Coast want to be,” Conant said. “You don’t need these long-term contracts and subsidies in order to do that.”
New York Groundwork
Anbaric has a history of bringing energy into New York under water. The company was part of the consortium that built the 660-MW Neptune HVDC cable linking PJM to Long Island, and also helped construct the 660-MW Hudson project connecting midtown Manhattan to the RTO.
Knobloch, president of Anbaric subsidiary New York OceanGrid, said the company is preparing a FERC filing for authority to sell transmission rights at negotiated rates both in New York and New Jersey.
Anbaric is focusing much of its efforts on areas off the coast of Massachusetts, which is seeking aggressively to develop offshore wind. | BOEM
Beyond having to navigate multiple regulators, there is also the matter of working through the NYISO interconnection queue, where Anbaric has an advanced position (363) for a 500-MW line connecting into Ruland Road on Long Island because of its work on the Poseidon transmission project, which was intended to bring in power from New Jersey.
“And we have follow-on interconnection requests for an additional 700-MW DC at Ruland Road, and then for a 800-MW AC line up into Ruland Road,” Knobloch said. “Because the queue 363 was part of the Poseidon project, our hope is to win the blessing of NYISO to repurpose that for our offshore wind project, because the on-land route is precisely the same … the material facts are identical.”
Anbaric has also filed an HVDC interconnection request with NYISO for 1,200 MW and additional 800 MW AC into the Farragut substation in Brooklyn for its hoped-for offshore wind grid.
“We wish that the [Public Service Commission] had decided to incorporate planned open access offshore transmission into Phase 1 [of the solicitation], but we note that they signaled that [the New York State Energy Research and Development Authority] should begin thinking about a planned transmission approach now and use the next year or two that way,” Knobloch said. “We appreciate that.”
Anbaric has also nearly completed the New York Department of Environmental Conservation’s environmental permitting process for both the on-land and state waters portions of its offshore grid.
The company several months ago submitted an application with the U.S. Bureau of Ocean Energy Management for rights of way and right of use, which Knobloch expects to be approved within a year, given the Trump administration’s willingness to speed up permitting processes. The process from conception to start of construction for any large transmission project takes roughly eight years, he said.
“Any offshore wind generator who wants to develop transmission, they’re going to have to go through these same processes,” Knobloch said. “To our knowledge, no one else has put in their interconnection requests to NYISO for offshore wind.”
Skewed Background
New York is making a competitive solicitation with only one company, Equinor, owning an offshore wind area lease close to the city. BOEM plans to lease two new areas off the Massachusetts coast later this year and is studying a proposal from New York for additional leases there.
| BOEM
“You’ve got some very large European developers who’ve been successful in Europe, and I think it’s fair to say there’s a degree to which they’re trying to corner the market a bit,” Conant said.
“They’re using a lot of influence and spending a lot of time in capitol buildings, and some of it is a little bit of disinformation,” he said.
For example, Conant contends, those developers don’t tell the full story of Germany’s experience. Although they emphasize the mistakes the industry made in the early years of the offshore wind industry, they neglect to relate all of what they learned.
“But the lesson learned is that you need to do the transmission first,” Conant said.
“Early on in Germany, the delays caused costly headaches. Developers cite that as a reason to have control over transmission, but it’s only part of the story, the beginning,” agreed Knobloch. “The Danes and the Germans quickly moved to planning transmission before soliciting offshore wind generation.”
FERC on Thursday signaled a change in its thinking about how RTOs should allocate costs for projects that improve grid stability, reopening proceedings regarding PJM’s controversial Bergen-Linden Corridor (BLC) and Artificial Island projects in New Jersey.
For reliability projects, PJM assigns 50% of the costs of regional facilities (500-kV lines or higher and double 345-kV lines) and “necessary” lower-voltage facilities required to support regional lines on a load-ratio share basis. The other 50% is allocated using the solution-based distribution factor (DFAX) method. All costs of lower-voltage facilities not supporting regional lines are allocated via DFAX.
Complaints against both projects argued that the DFAX method failed to align allocations with benefits.
In addressing requests for rehearing of complaints about cost allocations for the BLC project, FERC on Thursday ordered settlement judge procedures to urge the parties into settlement, saying the underlying facts in the complaint “have significantly changed” (EL15-67-003, et al.).
FERC also granted rehearing of its April 2016 order rejecting a complaint by Delaware and Maryland regulators, who argued that the DFAX method, as applied to Artificial Island, does not produce an allocation of Regional Transmission Expansion Plan project costs roughly commensurate with the benefits (EL15-95-003).
BLC
The commission urged a settlement of the BLC dispute rather than rule on a rehearing request over its April 2016 order denying a complaint from Linden VFT over the projects and two others totaling $1.3 billion. Linden, Consolidated Edison, the New York Power Authority and Hudson Transmission Partners — the operator of another merchant transmission line into New York City — requested rehearing of the decision.
Since then, one of the projects was canceled and the costs for another were reassigned entirely to Public Service Electric and Gas, so that only the allocations for BLC, totaling $1.2 billion, remain in contention.
Linden’s complaint was that the reliability issues upon which the projects were based are not related to power flows, so PJM’s solution-based DFAX method, which identifies beneficiaries based on flows, did not align costs with benefits. While the formula is split 50/50 between load-ratio share and DFAX, the allocation ends up weighted toward the DFAX. Of the $1.3 billion in allocations Linden initially complained about, approximately $400 million was allocated on a load-ratio share basis and $900 million based on DFAX.
Even though BLC is in PSE&G’s zone, the company was allocated only about $88.4 million of the costs. Con Ed was allocated approximately $720.4 million, Linden $9.6 million and Hudson $103.2 million.
FERC denied Linden’s complaint, ruling that the company failed to prove the DFAX method was unjust and unreasonable. In urging a settlement before ruling on rehearing, the commission said, “the circumstances regarding the cost responsibility assignments … have significantly changed.”
In May 2017, Con Ed canceled a wheeling agreement with PSE&G that had made the wheel part of cost responsibility assignments in the RTEP. With the wheel eliminated, PJM reassigned the costs that had been allocated to Con Ed.
In December, FERC granted Linden’s and Hudson’s request to convert their firm transmission withdrawal rights to non-firm rights, allowing the merchant facilities to escape RTEP cost allocations. PJM subsequently reassigned to PSE&G the costs Hudson and Linden had been allocated. (See PSE&G on the Hook for Bergen-Linden Costs.)
The chief judge has 15 days to assign a settlement judge, who will report back in 30 days after being appointed. The chief judge will then allow more time if a settlement remains unfinished or inform FERC that there’s an impasse that can’t be settled.
Artificial Island
As in the Linden complaint, the commission initially rejected the Delaware and Maryland regulators’ complaint over the use of the DFAX cost allocation for Artificial Island. The project would add new transmission between New Jersey and Delaware to address stability limits on generation at the Salem and Hope Creek nuclear plants and transmission constraints that sometimes prevent the generators from exporting power at full capacity.
The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | BHI Energy
About $242 million (87%) of the cost of the project was assigned under DFAX and the remaining $38 million assigned based on load-ratio share.
The state commissions requested rehearing in April 2016, along with the states’ public advocates, Old Dominion Electric Cooperative, Easton Utilities and the Delaware Municipal Electric Corp. LSP Transmission Holdings also requested rehearing separately.
In granting a paper hearing, FERC said it now believes the DFAX method is unjust and unreasonable for projects that address stability-related reliability issues. The commission cited a statement from PJM in the docket that “stability is analytically unique compared to voltage or thermal overloads” because it results from “an imbalance of generation and load caused by a sudden event on the transmission system where the rotational inertia of the generator could cause the generator to lose synchronism with the rest of the transmission system.”
Generators oscillate to re-establish balance, but the severity of the oscillation is dependent on the strength of the transmission system, FERC said. A weaker transmission system will cause the issues to last longer and be more severe, which could ultimately result in damage to the generator and cause additional outages of other system elements. Stability-related projects “provide additional outlets” for generators to address the issues.
FERC established a paper hearing to consider an appropriate alternative. Stakeholders have 60 days to provide their comment on proposals from PJM and Exelon. The PJM proposals were filed in the docket by the state commissions after the RTO unveiled them last year. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
The first alternative, which PJM called a “direct extension” of the DFAX, would reduce Delmarva Power & Light’s responsibility to about 7% while raising the bill for PSE&G to more than 42%. New Jersey’s other utilities — Jersey Central Power & Light and Atlantic City Electric — would pick up 13% and 7.3%, respectively. PECO Energy would shoulder about 20% of the costs.
PJM’s second “stability deviation method” would allocate 19% to PSE&G, 15% to PECO, 12.5% to PPL, 12.4% to JCP&L, 10.4% to Delmarva Power & Light, 7.2% to ACE and about 5% to Met-Ed.
Exelon presented its proposal as comments in the docket. Its “hybrid method” could assign some portion of cost responsibility for benefits identified by flows on transmission projects that address stability issues in proportion with the benefits identified by PJM’s approaches.
With two commissioners calling for additional action to protect consumers, FERC this week issued a final rule requiring natural gas pipelines to reflect the federal corporate income tax cut in their rates (RM18-11).
The July 18 order largely follows the commission’s Notice of Proposed Rulemaking in March, prompted by the Tax Cuts and Jobs Act, which reduced the federal corporate income rate to a flat 21%. (See FERC Orders Rate Revisions to Reflect New Tax Law.)
The NOPR would have required interstate pipelines to file a one-time report (FERC Form 501-G) to estimate the company’s return on equity before and after the tax cut took effect Jan. 1.
FERC staff present the final rule at Thursday’s commission meeting. | FERC
The final rule makes changes to the proposed form, including eliminating accumulated deferred income tax (ADIT) from the cost of service for pipelines that do not pay taxes — consistent with a separate order on rehearing of its revised policy statement on income taxes, also issued Wednesday (PL17-1-001).
The rule gives a pipeline several options for addressing changes to its revenue requirements, including making a filing under Section 4 of the Natural Gas Act to reduce its rates. Companies that do so will be granted a three-year moratorium on NGA Section 5 rate investigations if the pipeline’s Form 501-G shows an ROE of 12% or less.
Pipelines also can file either a prepackaged uncontested rate settlement or a general NGA Section 4 rate case. The commission said it will not initiate Section 5 rate investigations for pipelines that choose this option by Dec. 31.
The rule will take effect 45 days after publication in the Federal Register.
Call for Congressional Action
Democratic Commissioners Cheryl LaFleur and Richard Glick issued a joint concurrence calling on Congress to amend NGA Section 5 to provide the commission with refund authority like that for electric rates under the Federal Power Act.
“We believe that current law provides a perverse incentive for protracted litigation and creates an asymmetry of leverage between pipelines seeking a rate increase under Section 4 of the NGA and complainants or the commission under Section 5,” they wrote.
| National Fuel Gas
“We believe that our lack of refund authority affected the balance the commission was able to strike in today’s order. It is a clear tenet of cost-of-service ratemaking that tax savings should flow through to ratepayers, and the commission is rightly pursuing that goal in the final rule. However, because our Section 5 ‘stick’ under the NGA cannot effectively deliver timely relief to customers, the final rule proffers a series of ‘carrots’ in the hope that pipelines will exercise their Section 4 filing rights to quickly flow those tax benefits back to their customers. While we think the balance struck in the final rule is reasonable in light of our limited refund authority, we believe that the commission would be better equipped to protect customers if the law were amended.”
Dissents on Certificates
On Thursday, LaFleur and Glick also continued their campaign to force the commission to assess pipeline projects’ impact on greenhouse gas emissions. (See Dem Dissents Show FERC Divide on Carbon.)
Glick dissented on four gas pipeline certificate orders (Columbia Gas Transmission, CP17-80; Texas Eastern Transmission, CP18-10; Northwest Pipeline, CP17-441; and Millennium Pipeline, CP16-486-001).
LaFleur also cited the lack of GHG considerations in concurring opinions on three of the orders and indicated she would issue a partial dissent later on Millennium Pipeline.
GHG emissions are also certain to be a point of contention as the commission reconsiders its 1999 policy statement on pipeline certificates (PL18-1). Comments on the Notice of Inquiry are due Wednesday. (See FERC Outlines Gas Pipeline Rule Review.)
FERC on Thursday affirmed its denial to extend the 10-year pilot license for what could be the country’s first commercial project for producing tidal power (P-12611-011).
Verdant Power’s proposed 1,050-kW Roosevelt Island Tidal Energy Project on New York’s East River was previously issued a FERC pilot license for 2012-2021.
Site of Roosevelt Island Tidal Energy Project on the East River | Verdant Power
Last December, the company requested an extension until 2026 to “acquire operational monitoring data” on the hydrokinetic pilot project, contending the technology involved is not at “commercial readiness.” Commission staff denied the extension request in May, saying that “barring extraordinary circumstances, 10 years should be enough time to complete a testing program and to make a decision on whether to file an application for a build-out license.”
Verdant requested a rehearing on the grounds that there is no prescribed timespan for pilot licenses and no stakeholders made “credible” objections to the extension request. New York environmental nonprofit Riverkeeper expressed concerns about protecting the endangered Atlantic sturgeon and requested use of a fish-friendly turbine design.
But FERC stuck with staff, saying Verdant still has more than 16 months before the company must file a final license application “to continue testing its technology and [acquire] additional data.”
FERC said in a 2008 white paper that an ideal hydrokinetic pilot project would be “small, short-term and located in environmentally non-sensitive areas.” In its order, the commission pointed out that the Roosevelt Island project already has double the recommended five-year pilot license time suggested in that white paper.
“If we were to accept Verdant’s argument, there is no indication that even 15 years would be a sufficient amount of time to determine whether to file an application for relicensing,” FERC added.
WASHINGTON — FERC celebrated departing Commissioner Robert Powelson’s brief tenure Thursday, with colleagues extolling his candidness and defense of competitive energy markets.
After only a year on the commission, Powelson is leaving in mid-August to become CEO of the National Association of Water Companies. (See Powelson Leaving FERC to Head Water Lobby.)
McIntyre tweeted this photo praising Powelson as a “tireless defender of wholesale markets and competitive market principles.” | FERC
The former National Association of Regulatory Utility Commissioners chairman was his usual joking self as he thanked fellow commissioners and staff until he began talking about his wife and two sons, when he choked up.
“They have been very supportive of me, and they have persevered through commutes [and] travel,” Powelson said, fighting back tears.
Powelson has been unafraid to speak his mind while at FERC. He once tweeted a debate challenge to coal magnate Robert Murray and ribbed then EPA Administrator Scott Pruitt at a storage industry conference for his excessive travel expenses. He also elevated the sports trash talk at commission meetings as an outspoken Philadelphia fan, enjoying a rivalry with Commissioner Cheryl LaFleur, a Boston native.
“I also respect your fierce independence and your commitment to the independence of FERC,” LaFleur said. “And your unbridled wit — I think that’s a euphemism for ‘complete lack of filter’ — made commission meetings and Twitter more enjoyable while you were here.” As a parting gift, she gave him a mug that said, “I don’t care how they do it here. I’m from Pennsylvania.”
“It’s very rare in this town that you find someone who’s willing to speak unfiltered in a variety of different ways, but without the need to be in lockstep with one political party or another,” Commissioner Richard Glick said. “But Commissioner Powelson certainly has shown the freedom to be able to speak his mind. And everyone in this room knows that Commissioner Powelson has always told us what he thinks, every single time, no matter what the issue is.”
Commissioner Neil Chatterjee, former energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), said he had vetted Powelson for a seat on the commission in 2011. Powelson, however, had just become chair of the Pennsylvania Public Utility Commission and “felt he didn’t want to leave the commission too quickly, which, as I think about it and reflect on it today, is rather ironic.”
“That was a lifetime ago,” he continued amid laughter. “Cheryl used to vote for pipelines back then with no regard whatsoever for emissions.”
McIntyre Toughs it out
The hour-and-a-half meeting appeared taxing for Chairman McIntyre, who revealed in March that he had undergone surgery and treatment for a brain tumor. (See McIntyre Discloses Brain Tumor Surgery.)
On the commission’s podcast, “Open Access” Tuesday, McIntyre said he has been suffering severe back pain since before July 4, later determined to be the result of compression fractures in two of his vertebrae. He also stumbled and fell on July 4, injuring his left arm.
In a departure from normal procedure, the doors to the commission meeting room were locked until five minutes before Thursday’s meeting was scheduled to begin at 10 a.m. McIntyre was already seated when staff, visitors and reporters were allowed in.
He remained seated throughout, excusing himself for not standing during the Pledge of Allegiance. His arm in a sling, he read slowly and deliberately, stumbling over some words.
FERC spokeswoman Mary O’Driscoll declined to answer a reporter’s question as to why there was a delay in opening the doors.
Normally open to talk about subjects not discussed at open meetings, McIntyre took few questions from reporters after Thursday’s session and was not asked about his injuries.
After the press conference, McIntyre remained seated in the hearing room as reporters and staff left. O’Driscoll said the room needed to be cleared for another meeting.
In Tuesday’s podcast, McIntyre said he was hoping to take time off soon. “Some major R&R would be really great if I’m able to arrange that consistent with my FERC responsibilities.”
WASHINGTON — FERC is collaborating with the Transportation Department’s Pipeline and Hazardous Materials Safety Administration to process the 15 applications for LNG terminals before the commission, Chairman Kevin McIntyre announced Thursday.
“The new collaborative procedures, which will be implemented imminently, will significantly reduce the time required to review LNG project applications by taking full advantage of the expertise of our federal partners at PHMSA, the safety experts, to study potential impacts to public safety of each and every LNG terminal proposal,” McIntyre said at the commission’s monthly open meeting.
U.S. Transportation Department headquarters
FERC and PHMSA staff are still working out the details and will issue a formal memorandum of understanding “as soon as possible,” he said.
McIntyre alluded to the announcement Tuesday on the commission’s podcast, “Open Access.”
“In just the last few days, we have made truly significant strides in reforming the permitting process with our federal partners,” he told commission spokeswoman Mary O’Driscoll.
McIntyre also denied that FERC had sent letters to several export terminal developers notifying them that their applications could be delayed by 12 to 18 months as it struggles to deal with its backlog, as reported by Bloomberg last week. Bloomberg had corrected the story to remove references to the letters, but it still says FERC “is preparing to notify” developers of the delays, citing anonymous sources. (RTO Insider noted Bloomberg’s report in an article about a Senate Energy and Natural Resources Committee hearing at which the subject of delayed natural gas pipeline and LNG project approvals was discussed. See Senate Talks Gas Infrastructure amid Increasing Delays.)
The commission has in the past six months revised the notice schedules for three projects, McIntyre said, but it has not issued any new schedules in that time frame.
“FERC staff is very cognizant of the financial market impacts of its LNG project schedules,” he said. “Moreover, since we have been working diligently to streamline our permitting process and are still making significant strides in that direction, the release of any schedules to date would have been premature.”
FERC on Thursday ordered expanded reporting of cybersecurity incidents, saying attempts not currently reported could lead to bigger, more successful attacks.
The commission gave NERC six months to revise its critical infrastructure protection (CIP) reliability standards to mandate reporting of incidents that compromise, or attempt to compromise, a responsible entity’s electronic security perimeter (ESP) or associated electronic access control or monitoring systems (EACMS) (RM18-2).
FERC said the new rules will improve threat awareness by covering the installation of malware and other “incidents that might facilitate subsequent efforts to harm the reliable operation of the [bulk electric system].”
Under the current CIP-008-5 (Cyber Security – Incident Reporting and Response Planning), incidents must be reported only if they “compromised or disrupted one or more reliability tasks.”
The final rule adopts the Notice of Proposed Rulemaking the commission issued in December, which concluded that “the current reporting threshold may understate the true scope of cyber-related threats facing the bulk power system, particularly given the lack of any reportable incidents in 2015 and 2016.” (See FERC Orders Tightened Cyber Reporting Rules.)
Control room | Schneider Electric
The commission’s order also calls for standardizing cybersecurity incident reports to improve the quality of reporting and allow easier comparisons and analyses. The reports will require information on the impact, or intended impact, of the intrusion; the attack “vector” used; and the level of intrusion achieved or attempted.
In addition to continuing to send the reports to the Department of Energy’s Electricity Information Sharing and Analysis Center (E-ISAC), the reports would also be distributed to the Department of Homeland Security’s Industrial Control Systems Cyber Emergency Response Team (ICS-CERT). NERC will be required to file an annual report with the commission with anonymized summaries of the reports.
Seeking Balance
In its 2017 State of Reliability Report, NERC recommended redefining reportable incidents “to be more granular and include zero-consequence incidents that might be precursors to something more serious.” Although NERC received no reports of cybersecurity incidents during 2016, it noted that DOE’s Electric Disturbance Reporting Form OE-417 included two suspected cyberattacks and two actual attacks for the same period and that ICS-CERT responded to 59 cybersecurity incidents in the energy sector in 2016.
“Our directive is intended to result in a measured broadening of the existing reporting requirement in reliability standard CIP-008-5, consistent with NERC’s recommendation, rather than a wholesale change in cyber incident reporting that supplants or otherwise chills voluntary reporting, as some commenters maintain,” the commission wrote. “Indeed, as NERC contends, we believe that the new ‘baseline understanding, coupled with the additional context from voluntary reports received by the E-ISAC, [will] allow NERC and the E-ISAC to share that information broadly through the electric industry to better prepare entities to protect their critical infrastructure.’”
The ESP is defined by NERC as the “logical border surrounding a network to which BES cyber systems are connected using a routable protocol.” EACMS include firewalls, authentication servers, security event monitoring systems, intrusion detection systems and alerting systems.
“Since responsible entities are already required to monitor and log system activity under reliability standard CIP-007-6, the incremental burden of reporting of the compromise or attempted compromise of an EACMS that performs the identified functions should be limited, especially when compared to the benefit of the enhanced situational awareness that such reporting will provide,” the commission said.
Report Preferable to Data Request
The commission concluded a reporting requirement is preferable to a “perpetual” data request to collect the same information, saying it is “more aligned with the seriousness and magnitude of the current threat environment, and more likely to improve awareness of existing and future cybersecurity threats and potential vulnerabilities.”
It noted that “the commission will have the ability to review and ultimately approve the standard, as opposed to the opportunity for informal review that the commission would have of a data request.”
Timelines
The commission told NERC that it should consider the threat posed by attacks in developing its reporting thresholds and timelines.
“Higher risk incidents, such as detecting malware within the ESP and associated EACMS or an incident that disrupted one or more reliability tasks, could trigger the report to be submitted to the E-ISAC and ICS-CERT within a more urgent time frame, such as within one hour, similar to the current reporting deadline in reliability standard CIP-008-5. For lower risk incidents, such as the detection of attempts at unauthorized access to the responsible entity’s ESP or associated EACMS, an initial reporting time frame between eight and 24 hours would provide an early indication of potential cyberattacks. For situations where a responsible entity identifies other suspicious activity associated with an ESP or associated EACMS, a monthly report could, as NERC states, assist in the analysis of trends in activity over time.”
Top Challenge
Commissioner Neil Chatterjee said protecting the grid from cybersecurity threats is one of FERC’s top challenges. “Both the Department of Homeland Security and Federal Bureau of Investigation have issued multiple public reports describing intrusion campaigns by Russian government cyber actors against our critical infrastructure, including the electric grid,” he said in a statement. “While thankfully none of these intrusions have resulted in an actual power outage, they do represent an unsettling uptick in attempts to undermine America’s critical infrastructure systems.”
“Cyber threats to the bulk power system are ever changing, and they are a matter that commands constant vigilance,” added Chairman Kevin McIntyre.
Split Ruling on NERC Rules of Procedure
In a separate order, FERC also approved in part and denied in part NERC’s proposed revisions to its Rules of Procedure (RR17-6).
The commission approved NERC’s proposed revisions to Section 900 to clarify the scope and governance structure of its training and continuing education programs.
But it ordered NERC to restore sections of its personnel certification rules the safety organization had proposed for deletion from Section 300. The commission said it disagreed with NERC’s contention that the sections, pertaining to procedures for suspending an operator’s certification, dispute resolution and disciplinary action were “programmatic detail” that can be transferred to NERC manuals.
“If these provisions were removed from the NERC Rules of Procedure and remain only in a NERC manual, they would be subject to further change with minimal, if any, stakeholder input and without commission review,” FERC said. “This is not appropriate because changes in the provisions for suspension, dispute resolution or disciplinary actions could have a significant impact on a stakeholder’s or individual’s rights and obligations.”
ERCOT set new all-time systemwide peak demand records Wednesday afternoon, reaching 72.2 GW between 4 and 5 p.m.
That eclipsed the mark of 71.4 GW set between 3 and 4 p.m., which broke the prior record of 71.1 GW set in August 2016.
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Real-time hub average prices peaked at $2,172.70/MWh on Wednesday in the interval ending at 4:30 p.m. The West load zone saw prices reach $2,281.95/MWh during that same interval. According to Bloomberg data, it was the highest prices have been since August 2015, when they hit $2,233/MWh.
Texas has been bedeviled by a high-pressure system that has settled over it and is expected to result in triple-digit temperatures into next week. Wednesday’s highs in the Dallas/Fort Worth area reached 108 degrees Fahrenheit in places. The region is expecting temperatures to reach 106 through Saturday, while Houston is looking at 100-degree days into next week.
“Texans continue to deal with extreme heat across the state as ERCOT and electricity providers are working diligently to ensure they have the power they need to keep cool,” ERCOT said in a written statement.
The ISO system cracked 70 GW of demand Monday and Tuesday, bettering the previous monthly high of 69.7 GW set July 3. Demand reached 70.6 GW and 70.96 GW, respectively.
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“We fully expect to keep hitting new demand records as summer 2018 continues,” ERCOT said.
The grid operator has forecasted demand will top 74 GW on Thursday and Friday, 72 GW over the weekend and 75 GW on July 23.
ERCOT spokesperson Theresa Gage said the ISO has yet to issue a conservation appeal, despite the oppressive heat.
“As ERCOT predicted in the spring, we will likely break usage records as temperatures climb,” Gage said. “So far, the system is performing as expected.”
Staff in the spring projected a record peak of 72.97 GW in August, assuming normal weather conditions. The ISO says it has 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
The grid operator has now recorded four new monthly highs this year.
