FERC last week said that it will not delay its decision to shut down a Michigan hydropower dam over safety violations.
The commission ruled there was no reason to grant a stay of its order to revoke the license of the 4.8-MW Edenville Dam in northern Michigan, saying it only allows such a delay in cases of “irreparable injury” to the petitioner (P-10808-062). In this case, the commission said it found no harm other than economic loss.
FERC ordered the dam shut down in February, citing concern over a failure of owner Boyce Hydro to increase the dam’s spillway capacity. (See Michigan Dam Ordered Shut over Safety Breaches.)
Edenville Dam spillway
Boyce filed for a stay last month, along with the Sanford Lake Preservation Association, the Wixom Lake Association and the Gladwin County Board of District Commissioners, who wanted to take over dam operations. The D.C. Circuit Court of Appeals on Sept. 25 denied Boyce’s motion to stay the revocation order.
In its ruling Thursday, FERC reiterated the dam’s 14-year history of noncompliance and safety violations.
“In multiple orders, the commission has set forth a history, going back to 2004, of Boyce Hydro’s failure to comply with its license, the commission’s regulations and commission orders,” FERC wrote. “The commission’s primary concern has been Boyce Hydro’s ‘longstanding failure to address the project’s inadequate spillway capacity.’ Nevertheless, 14 years after acquiring the license for the project, the licensee has still not increased the project’s spillway capacity. The licensee has shown a pattern of delay and indifference to the potential consequences of this failure, which the commission has found must be remedied in order to protect life, limb and property.”
FERC also said it was not swayed by the argument by the lake associations and county commissioners that it would be costly and difficult to acquire a new license for the dam.
“Whether Boyce Hydro and the lake associations will reach agreement regarding the sale of the project works is speculative; these entities have not suggested that such a transaction has gone beyond the exploratory stages,” FERC said.
The shutdown is ultimately in the public interest, FERC said, observing that even the temporary state of the dam during spillway renovations would place the public at further risk: “Boyce Hydro … notes that to repair the spillways will require the installation of a cofferdam for four to six months, which will reduce the spillway capacity by approximately 50%, increasing the potential for overtopping of the dam.”
FERC last week reduced the return on equity adders previously granted to ITC Holdings subsidiaries for being independent, standalone transmission providers, saying a 2016 merger affected the parent company’s autonomy.
The commission’s Thursday order said International Transmission Co., ITC Midwest and Michigan Electric Transmission Co. were no longer fully independent because ITC Holdings merged with Canadian and Singaporean companies in 2016. FERC reduced their “transco” adders to 25 basis points each effective April 20, 2018 (EL18-140).
| ITC
FERC had granted ITC and METC 100-basis-point adders in 2003 and 2005, respectively, and ITC Midwest a 50-point adder in 2015.
But in 2016, Canada-based Fortis purchased 80.1% of ITC Holdings, while Singapore government-owned investment company GIC Private Limited acquired 19.9%. As a result, FERC now says the ITC subsidiaries are indirectly owned by two entities “with affiliates that participate in Eastern Interconnection energy and capacity markets.”
Tangled Associations
Several utilities had joined the complaint against ITC’s transco adders, including Consumers Energy, Interstate Power and Light, Midwest Municipal Transmission Group, Missouri River Energy Services, Southern Minnesota Municipal Power Agency and WPPI Energy. The complainants said the change in ownership meant ITC’s companies no longer have the full independence necessary to collect the approximately $24 million in annual revenues from the adders.
The utilities pointed out that Fortis subsidiary FortisOntario uses parts of the grid affected by the loop flow around Lake Erie that is managed by phase angle regulators owned and operated by the ITC companies. Another Fortis subsidiary, Central Hudson Gas and Electric, “generates, purchases and sells electricity over the Eastern Interconnection grid, in portions of New York state that can also be affected by the operation and planning of the ITC companies’ MISO-area facilities,” they noted.
They also said GIC subsidiary Epsom Investment indirectly owns 44.4% of Duquesne Light Co. and Duquesne Power, which sells retail electricity and markets power within PJM. Another GIC subsidiary, Camborne Investment, owns a “substantial minority stake” of four generators owned by Eastern Generation. The companies also said a Wisconsin Public Service Commission proceeding shows that “senior executives of the ITC subsidiaries, FortisOntario, Central Hudson, and other Fortis operating subsidiaries meet regularly, outside the Open Access Same-time Information System transparency contemplated by Order No. 889, to ‘collaborate on initiatives that are of interest and benefit to the regulated utility subsidiaries.’”
Finally, the complainants argued that “equity infusions from Fortis to ITC Holdings or dividends from ITC Holdings to Fortis may cause generation and transmission investments to compete for capital” and that ITC’s proposed 2,000-MW Big Chino Valley pumped storage hydroelectric facility in Arizona is evidence that the company is interested in pursuing investments outside of transmission.
ITC Holdings had argued there was “no credible argument” that Fortis, GIC or their affiliates are market participants in MISO and therefore could not affect its independence. The company also contended that FERC analyzes market participation for transco adders on an RTO basis, not an interconnection-wide basis, and pointed to NextEra Energy owning more than 38 GW of generation in the Eastern Interconnection. It also said it continues to be governed by an independent board of directors and is party to a shareholders’ agreement with Fortis that restricts ITC equity securities holders from MISO market participation.
The company said “nothing has changed in ITC Holdings’ planning of, investment in or operation of its transmission systems under the ownership of Fortis and GIC.”
But FERC said ITC’s merger “has reduced, but not eliminated, the ITC companies’ independence from market participants.” The commission relied on criteria in its Order 679 to scrutinize ITC’s independence and examined investment planning, capital formation, investment processes and business structure. In several areas, FERC found ITC still demonstrated “some level” of independence.
“We acknowledge certain minor potential conflicts of interest associated with other assets owned by Fortis and GIC may exist. However, such concerns are largely attenuated by the location of such assets and the fact that they are largely subject to small ownership shares by Fortis and GIC. Moreover, ITC’s and MISO’s actions have indirect and limited effects on their other affiliates or subsidiaries,” FERC said.
The commission said a 25-basis-point adder “appropriately encourages the transco business model in these circumstances and promotes corresponding consumer benefits.”
Commissioner Richard Glick dissented, saying the ITC companies are no longer sufficiently independent to justify any ROE adder.
“Fortis, which owns 80% of the ITC companies, assesses capital expenditures on a consolidated basis, meaning that in evaluating how to allocate capital among its subsidiaries, it is directly comparing investments in transmission with investments in other aspects of its business,” Glick wrote. “Even though the ITC companies are permitted to develop their own capital and business plans, Fortis and GIC retain ultimate authority with respect to those plans.”
ITC Reaction
An ITC spokesperson said the company was disappointed in FERC’s “failure to fully recognize our independence” and is reviewing its options, including rehearing and appeal.
“While the order acknowledges value in our business model, the commission found ITC to be less independent post Fortis ownership,” the spokesperson said in an email to RTO Insider.
ITC also recognized the issue could spark a review of transmission incentives.
The “order was characterized as a compromise solution, and several of the commissioners spoke to the need for a broad review of all transmission incentives. Such a review will provide an opportunity for a more expansive review of this and other transmission incentives offered under FERC’s policy statement,” the spokesperson said. “ITC will advocate that any change to current policy should take into consideration previously approved incentives, which were relied upon by developers to construct facilities that provide ongoing benefits to customers.”
FERC on Wednesday approved National Grid’s request to add liquefaction facilities at its 600,000-barrel Fields Point LNG storage facility in Providence, R.I.
Customers currently truck LNG to the Fields Point facility for storage, with National Grid redelivering gas via truck or through use of Narragansett Electric’s distribution pipelines and Algonquin Gas Transmission’s interstate pipeline. “The proposed project would effectively reverse this flow by enabling Algonquin to transport gas that Narragansett Electric would deliver to Fields Point to be liquefied and stored,” the commission said (CP16-121).
Fields Point LNG | National Grid
National Grid said it proposed the liquefaction facilities at the request of Narragansett and a second customer, Boston Gas, which were seeking to diversify their supply sources. It will have a capacity of 20 MMcfd.
Narragansett will provide a dedicated 13-MW, 34.5-kV electric service to power the facility.
Opponents of the project disputed the need for it, saying gas trucked to Fields Point have met peak day demands. But the commission said it was persuaded by storage customers’ complaints that they have had trouble obtaining enough LNG supplies.
Commissioners Cheryl LaFleur and Richard Glick joined in the approval but wrote a concurring statement to reiterate their position that the environmental review of such projects should include greenhouse gas emissions.
“We agree with today’s finding that the liquefaction facility will not have a significant effect on the environment, particularly given the limited GHG emissions associated with the project,” they wrote. “However, we disagree with the language in the environmental assessment that dismisses the social cost of carbon as a useful tool to inform the environmental review, stating the social cost of carbon method ‘cannot meaningfully inform the commission’s decision whether and how to authorize a proposed project under the [Natural Gas Act].’ We believe the social cost of carbon provides a meaningful and informative approach for an agency to consider how its actions contribute to the harm caused by climate change.”
The ERCOT Technical Advisory Committee canceled its Oct. 24 meeting, citing a lack of items to be considered this month. It’s the fourth TAC meeting to be canceled this year, and the third in five months.
ERCOT has distributed its membership applications and agreements for 2019, recommending that entities interested in joining the grid operator do so well in advance of Nov. 9 to avoid potential processing delays.
Applicants may join as a corporate, associate or adjunct members. Corporate membership includes the right to vote on general membership matters, such as election of certain board members, election of TAC representatives and members of TAC subcommittees, and amendments to the Certificate of Formation and bylaws.
Market participants are not required to be members.
Membership terms are for no more than a year and do not renew automatically. Dues are required at the time of application; applicants can request waivers for good cause.
Confirmation of board members and TAC representatives for 2019 will take place at the annual membership meeting Dec. 11.
More Information and copies of ERCOT’s bylaws and Articles of Incorporation can be found on the grid operator’s website.
SACRAMENTO, Calif. — Solar and wind will replace fossil fuels. Big batteries will store renewable energy. And every new vehicle sold will be electric.
The 1,000 or so attendees at CAISO’s Stakeholder Symposium got a glimpse of what the future could hold from visionaries, venture capitalists and carmakers during the event’s 10th anniversary at the Sacramento Convention Center.
“If we come back here in 2030 or 2040, we won’t even recognize the grid,” said Ron Dembo, a former Yale University professor and high-tech entrepreneur who kicked off the event as its keynote speaker.
Dembo’s message was to prepare for the unpredictable. He gave the example of a forest fire so fierce that it could jump a major freeway and burn down an urban neighborhood. That happened last year in Santa Rosa, Calif., but many experts would have called it highly unlikely before it occurred, he said.
“We’re moving into a more volatile world, and that requires a different way of looking at things,” he said.
Dembo and Mark Rothleder, CAISO’s vice president of market quality and renewable integration, said factors such as global temperatures, renewable energy and regional collaboration would guide the future grid. (See Can Calif. Go All Green Without a Western RTO?)
Other speakers warned about the dangers of climate change but laid out options that could limit global warming in the decades ahead.
Brian Davis, vice president of energy solutions at Shell’s New Energies business, explained the company’s Sky Scenario, a roadmap for meeting the goals of the international Paris Agreement and keeping global warming to under 2 degrees Celsius, primarily through the “deep electrification” of energy systems.
The company’s plan envisions moving to all-electric light transportation, a vast reduction in energy derived from oil and an equivalent increase in solar and wind production, and an end to deforestation and reforesting an area the size of Brazil.
Though extremely challenging, “it’s technically, economically and industrially possible to do it,” Davis, the conference’s final speaker, told the audience.
Between Dembo’s and Davis’ big-picture perspectives, panelists got down to the nuts and bolts of shaping tomorrow’s grid today.
Dan Richard, chairman of California’s High-Speed Rail Authority, said the controversial multibillion-dollar project, should be a way that the state’s 40 million residents, regardless of income, can travel up and down the state at 200 mph.
“So all Californians can benefit from this,” Richard said as part of a three-person panel on the electrification of the transportation sector and the future of mobility. “We don’t want this to be the Lexus train.”
The high-speed rail project has begun construction near Fresno, one of the state’s more affordable urban areas, and could put residents of that Central California city within commuting distance of jobs in Los Angeles, Richard and others said.
The rail line is one of outgoing Gov. Jerry Brown’s big infrastructure projects and has been criticized as an expensive boondoggle by many residents and elected officials. Richard said it’s a problem of imagination.
“People can’t imagine having high-speed rail” and what it will mean for them, he said.
One critic from Fresno acknowledged to Richard that it could mean that she and her husband could go to San Francisco for dinner and a show and be home by bedtime, he said.
China has built 8,000 miles of high-speed rail lines in only 15 years, and anyone who’s seen it quickly comprehends the benefits, he said.
Janea Scott, one of the five members of the California Energy Commission, moderated the transportation panel. She pointed out the problem of making electric transportation available to lower-income residents, for whom electric cars remain unaffordable and impractical.
Adam Langton, an electric vehicle expert with BMW of North America, said installing charging stations in lower-income neighborhoods would help, but that electric busses and trains should also be part of the solution.
“Think about electric miles,” he said.
Creating Utility-scale Storage
A separate panel, moderated by CAISO Director of Regional Integration Phil Pettingill, talked about EVs in the context of stored energy.
In 2018, demand for lithium-ion batteries for vehicles exceeded the demand for batteries for consumer electronics, said Yayoi Sekine, who leads the Americas coverage for Bloomberg’s energy storage practice. The demand for EV batteries has shot up rapidly and will increase to 1,500 GW of storage by 2030, she said.
A major problem now is how to store enough renewable energy to charge those car batteries and supply other energy needs after the sun sets. Solar generation is becoming less expensive and more abundant, especially in California, but it ramps up when it’s often least needed in the daytime and must be stored to meet peak evening and early-morning demand.
“Once you have enough batteries, you’re soaking up the solar,” Sekine said.
Sekine and her fellow panelist Yet-Ming Chiang, a professor at the Massachusetts Institute of Technology, said they believed bigger and less costly lithium-ion batteries were the best bet for large-scale storage going forward.
“The technology that works today and is dropping in cost is lithium-ion,” Chiang said.
However, he said scientists should look to cheaper and far more plentiful chemical components such as sulfur and saline for batteries. Future energy storage could end up looking more like chemical factories, with building-size vats connected by pipes and wire, than blocky batteries, he said.
“I think we’re on the cusp of significant growth in grid-scale storage.”
Investing for the Future
Carbon reduction is bound to be another growth area, said Nancy Pfund, founder and managing partner of DBL Partners, a venture capital firm that invests in social, economic and environmental change.
Pfund’s advice to investors was to “follow the carbon.” The past century was optimized for carbon, she said. “The next century will be optimized for carbon reduction and avoidance,” she said.
Fighting climate change will mean monetizing carbon reduction for private industry rather than relying on environmental groups and governments. In addition to transportation, agriculture is a major sector that produces atmospheric carbon and is ripe for technologies to reduce its greenhouse gas emissions, she said.
Pfund was joined on the symposium’s investment panel by Jill Anderson, vice president of customer programs and services with Southern California Edison, and Jackie Biskupski, mayor of Salt Lake City. The panel was moderated by Dede Hapner, formerly Pacific Gas and Electric’s vice president of FERC and ISO relations.
CAISO Chairman David Olsen said California’s ambitious goal of getting all of its energy from renewable and other zero-carbon sources by 2045 would require “electrifying just about everything.” And Valerie Fong, chair of the ISO’s Western Energy Imbalance Market, said, “Our industry is changing at an unprecedented rate.”
Wrapping up the conference, Shell’s Davis said it’s a remarkably dynamic time to be part of the electricity sector, as evidenced by the symposium’s discussion topics.
“Who would have thought 20 or 30 years ago the energy industry was an exciting place to work?” Davis said.
Sempra Energy’s transmission footprint in Texas is set to expand with the announcement Thursday that its Oncor utility subsidiary is acquiring transmission owner InfraREIT, while Sempra will buy a 50% stake in Sharyland Utilities.
Sempra CEO Jeffrey Martin said the combined $1.37 billion deals are “rotating capital away from noncore assets to core assets” in the company’s ongoing shift away from generation resources and commodities into the guaranteed rates of return of regulated infrastructure.
InfraREIT and Sharyland are both owned by Hunt Consolidated, which made a play for Oncor in 2016 but scrapped the deal after the Texas Public Utility Commission attached conditions considered unacceptable by the creditors of Oncor parent Energy Future Holdings. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.) Sempra acquired EFH’s 80% interest in Oncor earlier this year in an all-cash buyout valued at $9.45 billion. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)
Martin called Oncor the “logical” owner of InfraREIT’s assets because of their “significant overlap” with the utility’s existing service territory. Sempra CFO Trevor Mihalik noted that approximately 260 miles of InfraREIT’s lines were previously owned by Oncor, but they were exchanged for Sharyland’s distribution system as part of a 2017 rate case settlement. (See Texas PUC OKs Settlement in Oncor-Sharyland Asset Swap.)
The companies plan to submit the transactions as a single integrated filing over the next few weeks for approval by the Texas PUC, company officials said during an analyst call Thursday. It will also require review and approval by FERC and other federal agencies, they said.
The deals are expected to receive final approvals and close in mid-2019.
Hunt will be the noneconomic general partner of Sharyland and continue to manage daily operations and appoint executive management.
Sempra said no equity will be issued to cover the price tag of the transactions. Sempra will fund its $1.12 billion share — which includes the $98 million to become a limited partner in Sharyland — with the proceeds from its recently announced $1.54 billion agreement to sell the majority of its renewable portfolio to Consolidated Edison.
The remainder of Oncor’s payment for InfraREIT will be funded through a capital contribution from Texas Transmission Investment, which owns the remaining 19.75% of Oncor. The deal includes InfraREIT’s outstanding debt of approximately $945 million and allows the company to solicit superior bids.
The deal also includes an “asset exchange” between InfraREIT and Sharyland that will result in all of InfraREIT’s assets being located in North, Central and West Texas and all of Sharyland’s being located in the southern part of the state. InfraREIT will receive two South Plains and Lubbock Power and Light interconnections, along with a Golden Spread Electric Cooperative transmission line that connects with its existing Competitive Renewable Energy Zone assets. Sharyland will receive a DC tie and assets in the city of McAllen that connect with its existing Cross Valley transmission line.
The swap will be a “like-kind exchange with no impact on taxes,” Mihalik said.
Infrastructure over Commodities
The deal continues Sempra’s bid to move away from the volatility of commodities in favor of the infrastructure that transports them, along with the stable returns those assets provide.
Oncor CEO Alan Nye explained the company’s focus in Texas by highlighting the state’s position as the second-largest economy among U.S. states and expectations that ERCOT’s load will increase 16% within 10 years. “Significant” transmission expansion will be necessary to interconnect the roughly 40 GW of wind capacity and 30 GW of solar currently in ERCOT’s interconnection queue, he said, along with oil and gas development in the Permian region of West Texas.
“The purchase of InfraREIT gives us access to high-quality transmission assets that are adjacent to our service territory and are a great fit for our portfolio,” Nye said. “InfraREIT’s existing presence in the panhandle and Permian places it in a unique position to benefit from these trends. … The larger the footprint we have in Texas, the more exposure we have to potential transmission investment opportunities.”
Sempra last month announced it was selling its interest in 980 MW of resources — 11 solar assets across the Southwest, and solar and battery storage development projects and one wind facility in Nebraska — to Consolidated Edison. The company’s remaining seven wind facilities of roughly 720 MW, additional wind development projects and approximately 40 Bcf of natural gas storage in the Gulf Coast region remain up for sale.
CEO Brad Jones abruptly left NYISO this week and will be replaced, at least temporarily, by General Counsel Robert Fernandez.
The ISO’s Board of Directors announced Fernandez’s appointment as interim CEO in a press release Wednesday.
Kevin Lanahan, vice president of external affairs, declined to elaborate beyond the press release, except to say Jones’ departure was “a personal decision by Brad.”
Former NYISO CEO Brad Jones and acting CEO Robert Fernandez | NYISO
Stakeholders told RTO Insider that senior ISO officials have told them the news was a surprise to them. “It’s a really big mystery … it came out of nowhere,” said a stakeholder, who, like others interviewed for this story, asked not to be identified. “Usually there’s a transition announced. We’re shocked. … We’re all sort of in the dark on this.”
A second stakeholder said the ISO’s vice presidents were not informed of Jones’ departure until Wednesday morning — shortly before the press release was issued — so they could brief their subordinates. “Secrets like this don’t keep very well. So, the limited subset of people who did know didn’t know for long,” he said.
Asked whether Jones had fallen out with stakeholders, he said “there’s always dissatisfaction” with ISO actions. “I guess they wouldn’t be doing their jobs right if they didn’t piss most of the people off” occasionally. But he said Jones had a reputation for being “even-handed and open to input. I don’t think I’ve heard anyone say a bad thing about the guy — which is pretty unusual.”
Jones, who joined NYISO from ERCOT, was commuting regularly from the ISO’s offices to his home in West Texas, according to sources. He had said he would not move permanently to New York while he had school-age daughters in Texas. He did not respond to a request for comment Thursday.
The Board of Directors tapped Fernandez as interim CEO at a meeting Tuesday. Stakeholders said Jones attended a Liaison Committee meeting with the board Tuesday and that there was no hint that it would be his last.
Lanahan declined to say whether the board intended to keep Fernandez as CEO or would launch a search for a successor.
NYISO Board Chair Ave Bie, former chair of the Wisconsin Public Service Commission, praised Gonzales in the ISO’s release, calling him “extremely talented” and saying he “will ably guide the company as we move forward during this transition period.” She did not respond to a request for comment.
Fernandez was named the ISO’s general counsel and chief compliance officer in 2000 after stints at Long Island Lighting Co. and independent power producer Sithe Energies. He has been involved in “all aspects of corporate governance, including market participant committee decision-making, appeals to the Board of Directors, as well as enterprise risk management,” the release said.
He earned his J.D. from Brooklyn Law School, a Master of Laws in taxation from New York University School of Law and a bachelor’s degree from Stony Brook University.
Jones, a registered engineer with a master’s degree in finance, joined NYISO in October 2015 from ERCOT, where he had been senior vice president and chief operating officer. Though born in Florida, Jones has spent most of his time in Texas, where he and his wife raised their six children. (See New NYISO Head Brings Broad Experience.)
Tom Kleckner and Michael Brooks contributed to this article.
MISO will shut down its regional planning office in Metairie, La., by the end of next year, RTO officials confirmed Wednesday.
The move will leave MISO with three physical locations: Carmel, Ind., Little Rock, Ark., and Eagan, Minn. MISO said it will not renew the lease at the Two Lakeway Center office building in the New Orleans metro area when it expires at the end of 2019. By then, the RTO hopes to complete relocation of employees and equipment.
MISO Metairie office location | Google
MISO spokesman Mark Adrian Brown said every employee at the Metairie office has the option to relocate to one of the other three offices. He said RTO leadership first disclosed the closure to employees in spring to ensure they had enough time to make relocation plans.
MISO is assisting affected employees with the transition. “We are working with each individual to ensure they have the information and support they need during this process,” Brown said.
The RTO has maintained the Metairie location since 2012, the year before it officially integrated Entergy’s territories into its footprint.
The closure will save MISO money, but it’s not clear how much, as the RTO doesn’t disclose how much it spends on property. Brown said shuttering the space will help support the RTO’s “overall organizational health.”
“MISO carefully studied a number of factors in the decision-making process. MISO is a steward of our members’ resources, and we must always consider the most efficient solutions and opportunities that enhance the value we deliver,” Brown in an email to RTO Insider. He added that the move would bring employees together and allow them to collaborate in its remaining and more modern regional offices.
In a 2019 budget report to the Audit and Finance Committee of the Board of Directors, Finance Subcommittee Chair Mitchell Myhre of Alliant Energy said the closure will “provide financial benefits in 2019 and beyond.” In recommendations this year, the seven-member committee also said MISO should be open to decreasing its scope of operations to cut costs.
MISO’s 2019 budget has not yet gone before the larger stakeholder community. The Finance Subcommittee will present the 2019 budget to the Advisory Committee on Oct. 24. The RTO is recommending a $312.6 million total operating budget and $27.2 million capital expense budget. MISO’s base operating budget, at $269.6 million, represents a 2% increase from 2018. (See “MISO Spending Closely Tracks 2018 Limit; RTO Ups 2019 Budget,” MISO Board of Directors Briefs: Sept. 20, 2018.)
FERC on Thursday approved reliability standards for mitigating supply chain risks in industrial control system hardware, software and computing and networking services. The commission also ordered NERC to develop rules expanding the supply chain protections to include electronic access control and monitoring systems (EACMS).
The commission’s final rule, intended to build on existing critical infrastructure protection (CIP) standards, approved NERC reliability standards CIP-013-1 (Cyber Security – Supply Chain Risk Management), CIP-005-6 (Cyber Security – Electronic Security Perimeter(s)) and CIP-010-3 (Cyber Security – Configuration Change Management and Vulnerability Assessments). The final rule hews closely to the commission’s January 2018 Notice of Proposed Rulemaking (RM17-13). (See FERC Backs NERC Supply Chain Standards.)
| Pixabay
The new rules, effective 60 days after publication in the Federal Register, will be implemented over 18 months, as requested by NERC. The commission said the transition was needed because compliance will likely require technical upgrades, with implications for capital budgets and planning cycles that have longer time horizons.
Counterfeits, Malicious Software
The rules are intended to protect the bulk electric system from counterfeits or malicious software and tampering. They require affected entities to implement security controls addressing: software integrity and authenticity; vendors’ remote access; information system planning; and vendor risk management. FERC said the rules will cover 288 reliability coordinators, generator operators, generator owners, interchange coordinators or authorities, transmission operators, balancing authorities and transmission owners.
FERC acknowledged the rules did not cover the supply chain risks of EACMS such as firewalls, authentication servers, security event monitoring systems, and intrusion detection and alerting systems. The commission said NERC must propose rules to address the gap within 24 months. “Once an EACMS is compromised, an attacker could more easily enter the [electronic security perimeters] and effectively control the BES cyber system or protected cyber asset,” FERC said.
The commission also noted the standards generally don’t address physical access control systems (PACS) or protected cyber assets (PCAs). “We remain concerned that the exclusion of these components may leave a gap in the supply chain risk management reliability standards. Nevertheless, in contrast to EACMS, we believe that more study is necessary to determine the impact of PACS and PCAs,” the commission said. “Compromise of PACS and PCAs are less likely. For example, a compromise of a PACS, which would potentially grant an attacker physical access to a BES cyber system or PCA, is less likely since physical access is also required.”
Budgets OK’d
The commission also approved NERC’s 2019 business plan along with almost $166 million in spending allocated for the U.S. share of funding NERC, its regional entities and the Western Interconnection Regional Advisory Body (WIRAB) (RR18-9).
The 2019 budgets include $62.5 million for NERC; $102.8 million for its seven regional entities’ funding and almost $630,000 for WIRAB.
Including funding from other sources, NERC’s 2019 budget is $79.1 million, an 8.4% increase over 2018. Most of the increase is attributed to expanding staffing and functions at its electricity information sharing and analysis center (E-ISAC). (See New NERC Chief Not ‘Smartest Guy in the Room’.)
NERC’s budget includes 205 full-time equivalents, an increase of six from 2018.
WASHINGTON — FERC on Thursday approved SPP’s proposal to allow generators to include major maintenance costs associated with the number of starts or run hours in their mitigated start-up and no-load offers in the RTO’s energy market (ER18-1632).
Under the changes, effective Jan. 15, 2019, generation owners will be required to submit each of their resources’ maintenance costs to SPP’s Market Monitoring Unit. If they’re validated, the MMU will then assign the costs by maintenance activity to either the resource’s start-up offer or the no-load offer.
Maintenance workers inspect a turbine. | Turbine Generator Maintenance
SPP said the proposal would not only result in more accurate compensation for generators’ costs, but also better help the RTO determine whether to dispatch resources and incent generators to run when dispatched.
Stakeholders had debated over what qualifies as major maintenance, and SPP decided to allow only activities agreed to in advance by the MMU and the resource owner to be eligible for cost recovery. Generation owners have 30 days to submit these to the MMU, which estimates that more than half of the 700 resources in SPP will apply to include major maintenance costs in their offers.
“We find SPP’s proposal to include a major maintenance cost component in mitigated start-up offers and mitigated no-load offer to be a just and reasonable means of addressing concerns over the recovery of costs resulting from the gradual deterioration of resources’ operating equipment in the SPP Integrated Marketplace,” the commission said.
The changes received support from the MMU, which had opposed earlier versions of the proposal, as well as City Utilities of Springfield and Golden Spread Electric Cooperative. No one submitted protests.
Chairman Kevin McIntyre did not attend Thursday’s open meeting and did not vote on the order.
