OGE Energy reported third-quarter earnings on Thursday, beating analysts’ expectations with a net income of about $251 million ($1.25/share). That compared favorably with the year prior, when the company reported earnings of $205 million ($1.02/share).
Thomson Reuters had projected earnings of $1.11/share.
The Oklahoma City company said it benefited from more favorable weather, rate recovery and 9,000 new customers. OGE executives said they see “upward momentum” in the company’s historical load growth of 1%.
OG&E service trucks | OGE Energy
“There’s a lot of modeling that goes into forecasting load growth,” CEO Sean Trauschke told financial analysts. “To the extent we continue to see growth and we’re able to continue to attract customers and new businesses and have sales growth, that gives you the opportunity to spread costs over a larger base and minimize customer impact.”
Trauschke said OGE’s partnership in Enable Midstream Partners is in “good shape.” The midstream gas business contributed $37 million during the quarter to OGE, marking $1 billion in total distributions since the partnership with CenterPoint Energy was formed in 2013. Trauschke said the revenues are used to support dividend growth and invest in its Oklahoma Gas & Electric utility. (See related story, Hot Summer Yields Positive Earnings for CenterPoint.)
Natural gas midstream operations (Enable) | OGE Energy
The company revised its year-end earnings guidance to $2.24 to $2.30/share, up from $2.05 to $2.20/share.
CenterPoint Energy’s third-quarter earnings surged more than 57% thanks to record electricity usage this summer, the company reported Thursday. Profits were $241 million ($0.47/share) for the quarter, compared with $153 million ($0.35/share) a year earlier.
CenterPoint’s performance exceeded Zacks Investment Research’s projection of 43 cents/share.
The company’s Houston transmission and distribution utility reported operating income of $269 million for the quarter, up from $227 million in 2018’s third quarter.
“Our utilities delivered another strong performance this quarter, driven by solid customer growth, disciplined cost management and favorable weather,” CEO Scott Prochazka said.
CenterPoint Energy headquarters in Houston
The company also reported a $77 million distribution from Enable Midstream Partners, its gas gathering and processing partnership with OGE Energy. Enable is forecasting a distribution of $385 million to $445 million in 2020, bringing CenterPoint’s cash distribution since 2013 to $1.8 billion. (See related story, OGE Earnings Surge, Beat Expectations.)
Tempering the company’s positive news was a recent Texas administrative law judge’s proposed decision that a requested Houston electric rate increase of $154.6 million be reduced to $2.6 million, or 0.11% of its present rate base. The docket is on the Texas Public Utility Commission’s agenda for its meeting this Thursday (49421).
Prochazka told financial analysts during the earnings call that the decision was “clearly not a good outcome.”
“We’ve assumed we would at least be recovering the additional investment, the billion dollars plus that we have already put in service that are not yet in rates. If we recover just that piece, it would be an increase in rates,” he said. “The process isn’t over, and the commissioners haven’t yet opined on this. We hope the commissioners will have a different view of it.”
ATLANTA — NERC’s Board of Trustees last week accepted the EMP Task Force’s Strategic Recommendations report but pointedly did not endorse the panel’s suggestions, saying it will consider them after reviewing stakeholders’ comments.
The issue of electromagnetic pulses is a polarizing one, and at least some of the task force’s recommendations — notably calling for guaranteed cost recovery for investments to protect the grid — are hot potatoes for NERC. The draft Strategic Recommendations report, which was released for comment Aug. 30, also urged more access to classified information.
The report made 15 recommendations in four areas — research needs; vulnerability assessments; mitigation guidelines; and response and recovery — and suggested lead and support organizations for each, including NERC, the Department of Homeland Security and the Federal Emergency Management Agency. (See EMP Task Force Calls for Federal Funding.)
The trustees praised the task force for its research but gasped at the potential implications of its recommendations.
“Reading through that document — it puts things into context that are extraordinarily complex in a way such that you can begin to see how we might actually tackle this initiative,” Trustee Rob Manning said. “But the complexity is what scares me. The breadth of recommendations, the scope of those recommendations — it’s truly scary. So many people have to be involved. So much action has to be taken by so many different parties.”
Trustee Jan Schori said it was “very helpful” that the report suggests potential lead and support agencies for the recommendations — all 15 of which list NERC as lead or co-lead.
“I would be interested in input from those that comment on what role NERC should play going forward,” Schori said, noting “some of [the roles] are … not areas where we … have taken the lead.”
Schori also said she “can understand why the industry participants would be very concerned about … the question of cost recovery for work that is done” in response to any standard or guideline adopted by NERC.
“Traditionally, NERC is the technical resource. We don’t usually get into opining on cost recovery matters. And so … I’m very cautious about those parts of the report.”
A number of the industry comments pushed this theme, arguing that the task force’s recommendations gave NERC too prominent a role and often relegated more qualified bodies to a supporting function. For example, Ruida Shu, manager of reliability standards at the Northeast Power Coordinating Council, suggested that the Department of Energy should take the lead on providing educational materials relating to EMP preparedness, as “NERC is not equipped to engage in mass public educational endeavors.” In the same vein, representatives from Exelon and the Edison Electric Institute recommended that DHS replace NERC as the lead on coordination across utility sectors.
Taking questions about the task force’s perspective a step further, Robin Yee, adviser on U.S. affairs and grid security at the Canadian Electricity Association, objected to the U.S.-centric framing of the report and its lack of attention to the legal and regulatory requirements of other jurisdictions. Yee requested that “NERC develop a framework for ongoing consultation and dialogue between governments,” so that policies affecting the North American grid would take note of all relevant perspectives.
Kim Thomas of Duke Energy said the task force had failed to make use of “the full body of work already performed in the industry for this topic” and recommended NERC “acknowledge and utilize work-in-progress or completed for this topic [in order] to avoid duplication of work and to provide additional depth and understanding.”
No Confusion
“We don’t want any confusion on accepting the report as [representing] final approval of the recommendations,” said board Chair Roy Thilly, who promised the board would issue its recommendations on EMPs in February.
Thilly said the board will solicit additional comment from NERC management and others on the recommendations and what it should prioritize. “I suspect there are budget impacts and other resource impacts. So, we need to understand we can’t just approve the recommendations without knowing those factors. We do have work to do to get to February.”
The task force’s work was informed by a report released by the Electric Power Research Institute in April that concluded a high-altitude EMP caused by a nuclear explosion could cause a multistate electric outage but not the nationwide, monthslong blackout some observers fear. The report prompted a harsh critique by the Electromagnetic Defense Task Force. The group, which has ties to Maxwell Air Force Base, contends EPRI underestimated the risks and that relying on it would not address “remaining vulnerabilities impacting large power transformers, generating equipment, communication systems, data systems and microgrids designed for emergency backup power.” (See Critics: EPRI EMP Report Understates Risks.)
Next Steps
NERC Manager of Standards Development Soo Jin Kim, who presented the recommendations to the board, said the task force would like to begin Phase 2 of its work — more detailed analysis that would be forwarded to the newly created the Reliability and Security Technical Committee (RSTC). The RTSC would “develop detailed mitigation guidance and policy and procedures for how to update certain response and recovery plans,” Kim said.
“Only after the detailed work is done at the RSTC level — if it identified that there are enhancements or gaps in the standards, there [would] be an initiative for the EMP Task Force to kick off a standards development effort,” she said. “But that would only be if necessary, after the technical committee has first done its homework.”
In response to a question from Manning about proposed next steps, Kim said the task force identified as a “threshold question … that there needs to be progress in determining what’s an acceptable level of [bulk power system] performance during an EMP attack.”
She also noted that EPRI and several utilities are planning field trials of potential mitigation measures.
“Hopefully those field trials will be able to shed some light on certain mitigations and how available that technology will be to industry generally,” Kim said. “There’s also several research efforts going on right now with the National Labs. We have been reaching out to DOE and DHS also to try to share more information and to get more accurate information so industry can make those vulnerability assessments and accurately look at their systems.”
NERC’s EMP Task Force proposed 15 recommendations on research needs; vulnerability assessments; mitigation guidelines; and response and recovery. | NERC EMP Task Force
While some of the recommendations are outside the ERO’s authority, some are actionable by NERC and “will largely flow right into the RSTC next year as part of Phase 2,” she said. “We hope these recommendations will flow into the development of next steps for the industry to move forward in addressing EMP events.”
Not all industry participants were as positive about the momentum of the task force’s work: while Mark Gray, senior manager of transmission operations at EEI, described the report as a “good first step,” he said more research was needed to develop an effective response. Gray also recommended the removal from the report of language related to local distribution providers and other systems outside of NERC’s statutorily designated role.
Andy Dodge, director of FERC’s Office of Electric Reliability, asked whether the other agencies suggested as having roles have “bought into” the recommendations.
Kim said the task force followed President Trump’s March executive order in “highlighting some of the agencies that could be on point” and noted that the task force — formed in April — had a “very aggressive schedule” with the directive to provide recommendations to the board by November.
“Several of the entities that we did reach out to, and some of our contacts, stated that we probably would not be able to get some type of endorsement,” she said. “There has not been an official stance from any of the government agencies. Quite frankly, in that amount of time, I don’t think we could have received an official statement … that they would be willing to take on some of those recommendations.”
“Is NERC leadership going to follow up with these entities?” Dodge asked.
ATLANTA — The NERC Board of Trustees last week approved the merging of the Planning, Operating and Critical Infrastructure Protection committees and named Greg Ford as chairman of the panel that will replace them.
Ford, CEO of Georgia System Operations, is completing a term as chair of the Member Representatives Committee (MRC). MISO’s David Zwergel will be vice chair of the new panel, which is named — for now — the Reliability and Security Technical Committee (RSTC). Both will serve two-year terms.
Board Chair Roy Thilly said the new committee was welcome to change the name, noting concerns that the RSTC could be confused with the RISC — the Reliability Issues Steering Committee. “We do live in acronym hell,” Thilly joked.
“We talked about that on the board, and rather than having an extensive debate at this moment, we decided … to kick the can down the pike and … empower the new committee to propose a new name if they so choose,” he said.
Thilly called the approval of the merger and the RSTC Charter “a major step, with a lot of work in front of it.”
He said he appreciated “all the comments that came in, because it really made it better.” As a result of stakeholder feedback, the number of sector representatives was doubled and the sectors, rather than the board, will select them. (See Revised NERC Committee Merger Plan Released.)
While the three retiring committees totaled almost 120 members, the RSTC will have 34 voting members: two each from sectors 1-10 and 12, 10 at-large members, a chair and a vice chair. Terms for the new committee members will expire in June of alternating years. The initial membership will be split between two- and three-year terms, after which terms will run for two years.
Any unfilled sector seats will be filled by an at-large member until the term expires.
There will be five nonvoting members: the NERC secretary, two for the U.S. federal government, and one each for the Canadian federal and provincial governments.
The merger plan was developed by the Stakeholder Engagement Team (SET), led by Co-Chairs Jennifer Sterling, of Exelon, and Mark Lauby, of NERC.
“The SET is planning to live by example and wind down now that we have our deliverable,” said Sterling, who is succeeding Ford as MRC chair next year. “Any [additional changes to the transition] will be handled in the detailed implementation plan that the new committee will develop.”
One of the RSTC’s first work products will be reviewing the subcommittees, working groups and task forces under the three retiring committees and “eliminate or combine any of those that don’t really have recurring responsibilities or a defined deliverable,” Sterling said.
Three-week Sector Nominating Period
The transition will begin with the nomination of sector nominees, which will open this Tuesday and end Dec. 6. Sterling and sector leaders agreed to delay the opening of nominations by a week — they were originally scheduled to begin Wednesday — at the request of Bill Gallagher, a representative of the Transmission-Dependent Utility sector.
Gallagher said the delay would give sectors time to seek consensus on their two representatives. “We think it’s important to be able to do that because it gives us an opportunity to work behind the scenes to be sure that we get the right people to be running for these elections,” he said. “We think it would be a little bit smoother.”
“Is your concern that during that first week that somebody will nominate themselves without being vetted by your sector?” Sterling asked.
“Yes,” Gallagher replied. “If you look at the TDU sector, today we have six people that are serving on these three committees that are now going to be reduced to two people. We’d like to have an opportunity to influence the right people to make those transitions.”
None of the other sectors voiced opposition to reducing the nominating period when asked by Sterling.
“The voting would take care of [Gallagher’s concern], but it’s probably better not to get into that situation,” said Sylvain Clermont, a representative of the Federal/Provincial Utility sector.
The new Reliability and Security Technical Committee (RSTC) will replace the Operating, Planning and Critical Infrastructure Protection committees. | NERC
Transition Schedule
The transition to the RTSC will take about eight months:
Dec. 6: Sector nomination period ends. NERC staff to conduct sector elections, if necessary, by Dec. 20.
Dec. 9 to Jan. 3, 2020: Open at-large nomination period. NERC staff/SET analyze sector representatives’ expertise and regional mix for gaps to be filled by at-large members. The goal is to have at least one representative from each interconnection and regional entity footprint, and a mix of subject matter expertise (planning, operating and security), organization type (cooperatives, investor-owned utilities, public power, power marketing agencies, etc.) and geography (Canada, Mexico and U.S.).
Jan. 6-15: Nominating Subcommittee to develop slate of at-large nominees for presentation to the board.
Feb. 6: Board appoints RSTC members (sector and at-large).
Feb. 7 to May 29: RSTC develops transition plan and work plans for itself and subcommittees.
March 3-4: OC, PC and CIPC meet as scheduled.
March 4: RSTC holds its inaugural meeting.
June 2020: OC, PC and CIPC meet for final work plan approvals and to complete any other approvals. RSTC holds initial regular meeting with subcommittee reports and other agenda items.
MISO is proposing standalone fixes to its loss-of-load expectation (LOLE) study and capacity accreditation while it still conducts analysis to determine whether it should implement a seasonal capacity construct.
The analysis and proposals are the latest efforts in the RTO’s ongoing resource availability and need (RAN) initiative.
MISO planning adviser Davey Lopez called his presentation at the Resource Adequacy Subcommittee’s meeting Wednesday a “progress report” on the RAN effort, given that MISO suspended presentations on the project in September to allow time for analysis that could drive future draft rules. (See “RAN Respite,” MISO Resource Adequacy Subcomm. Briefs: Sept. 12, 2019.)
Lopez said MISO will finish a detailed analysis on a seasonal construct and have results for stakeholders by January, and that it is still targeting a March filing to change capacity resource accreditation. He said a seasonal construct might provide a more accurate representation of the footprint’s capacity supply.
“We know some resources perform differently throughout the year, and some might not be available all year long,” Lopez said. “We know some resources aren’t participating in our auction because they don’t want to be subject to must-offer all year long.” He said seasonal divisions of capacity supplies could provide the “granularity” that those resources require.
MISO executives this year began publicly questioning the effectiveness of continuing to measure system reliability according to the ability to meet demand during the summer peak hour.
CEO John Bear said the RTO must be mindful of reliability across all hours of the year, with resources being accredited based on availability and market prices incenting availability. He also said an efficient transmission system is needed to accommodate the shifting generation portfolio.
“We’re seeing significant change in our resource portfolio and how it performs. We’re going to need our stakeholders,” Bear said during an Oct. 22 Informational Forum, noting that solutions will become more complex.
MISO’s LOLE modeling assumptions have historically been tailored to covering a summer peak.
“But given that we’ve seen [maximum generation] events in recent history, primarily outside of the summer months … we’re asking ourselves if a summer focus still makes sense,” Lopez said.
Day-ahead offers have decreased since 2014 in relation to generation cleared in the Planning Resource Auction, he said. “Much of our requirement is being made up by emergency-only resources.”
LOLE Modeling and Accreditation Changes
Lopez said a “disconnect” exists between LOLE modeling and resource accreditation. He said MISO needs to better define risks and include seasonal effective outage rates, limitations in load-modifying resource availability and intermittent resource capabilities in its modeling. The LOLE study improvements can be made regardless of whether the RTO moves forward with accreditation changes or a seasonal construct, he said.
MISO could also tie a resource’s accreditation to its day-ahead offers during critical times, possibly using a resource’s day-ahead offers for the bottom 5% tightest margin hours over the last three years to calculate accreditation. The RTO must conduct more analyses to determine the impacts of factoring day-ahead offers into accreditation, Lopez said.
Lopez noted that MISO realizes it could not apply the day-ahead approach to intermittent resources, so it would instead continue to use its effective load carrying capability (ELCC) analysis to determine capacity credits for wind resources. MISO will devise an ELCC for solar generation as penetration increases.
In response to a question from Customized Energy Solutions’ Ted Kuhn, Lopez said using separate ELCC analyses across all resources might be too big a lift for RTO staff, although he would look into the possibility.
At the October RASC meeting, WPPI Energy Assistant Vice President of Planning Todd Komplin questioned what supporting research MISO had performed to verify the need for a seasonal auction or accreditation.
“It seemed that MISO jumped right into a seasonal resource adequacy construct without analysis behind it. We’re not necessarily opposed to a seasonal construct, but the data needs to show a need,” he said. “We haven’t really seen [data], and it’s been quite confusing.”
Komplin argued that more market participants than ever are using MISO’s Maintenance Margin supply look-ahead page and scheduling generation outages more judiciously, minimizing supply shortages.
He also said stakeholders have yet to see a “meaningful” LOLE analysis that reflects loss-of-load risks outside of summer. Customized Energy Solutions’ David Sapper added that MISO hasn’t considered its future resource mix in LOLE studies.
Kuhn also reminded MISO staff that they could consider just adding the now-hot September weather to the RTO’s definition of summer months and forgo capacity seasonality altogether.
MISO has called its short-term RAN fixes a success, reporting that stricter generation outage rules, better LMR availability reporting and annual real power testing for demand response have resulted in 5 to 10 GW of additional availability during times of need.
Dustin Grethen, MISO market design adviser, said this past summer broke a three-year pattern of declining margins and increasing emergency near misses.
“We had our tightest margins day after day after day in the summer of 2016,” Grethen said at the Market Subcommittee meeting in October, adding that 2017 was relatively manageable because of low load, but 2018 was again a study in volatility.
MISO has said its near-term RAN filings were meant to buy time to spell out bigger ideas to rectify supply imbalances brought on by increasing renewable generation.
MISO is proposing new Tariff changes that would require a market participant to put up additional collateral — or face a suspension from trading — when it exhibits undue risk to the RTO’s wholesale market.
The proposal is separate from actions MISO has already taken to safeguard its financial transmission rights market. The RTO last month filed with FERC to apply stiffer rules to FTR traders, including a 5-cent/MWh minimum collateral requirement and a mark-to-auction valuation (ER20-73).
“These changes will cover the entire market,” MISO credit analyst Brian Brown explained at Thursday’s meeting of the Market Subcommittee.
Brown said the Tariff language will focus on evidence of default, manipulation and unreasonable risk to the market and would allow MISO to request additional collateral when it perceives “unreasonable credit risk” from a market participant. He said the RTO prefers to step up collateral requirements “rather than ban a risky or bad actor.”
The proposed changes would also allow MISO to reject applications from new and former market participants and those that have an uncured financial default in the RTO’s market and attempt to rejoin under a different name.
The changes would additionally require current and prospective market participants to provide more specifics in their annual certification forms, including information about any past defaults, bankruptcies, dissolutions, mergers or acquisitions, and any investigations.
“In reading our Tariff, we found MISO currently does not have explicit authority to act in order to protect the market. We have implicit authority, but we want to have explicit authority in these issues,” Brown said. “We just want to be able to protect the market when it’s threatened.”
MISO’s legal team has said it is targeting a filing in December.
Gabel Associates’ Travis Stewart last month said the first draft of the proposed Tariff language was vague and affords MISO with a “substantial amount of judgment.” He asked for a more descriptive proposal.
But Brown said MISO needs the latitude to be able to address a variety of risks to the market. However, he said the RTO has opened the proposal to stakeholder feedback through Nov. 21.
ERCOT said Thursday it will have sufficient installed capacity available to meet projected peak demand this winter and spring.
According to its final seasonal assessment of resource adequacy (SARA) for the winter months (December to February), ERCOT will have more than 82 GW of capacity available — more than enough to meet an expected winter peak of 62.3 GW.
The capacity includes 136 MW of winter-rated gas-fired and wind capacity that have become commercially operable since the release of the preliminary winter SARA. As much as 768 MW of planned winter-rated capacity could be available from new gas generation, wind and utility-scale solar projects.
| ERCOT
The forecast projects more than 7 GW of resource outages this winter, based on historical data compiled since 2016.
“We studied a range of potential risks and believe there will be sufficient operating reserves to meet the forecasted peak demand,” Pete Warnken, ERCOT’s manager of resource adequacy, said in a statement.
ERCOT’s all-time winter peak is 65.9 GW, set in January 2018.
The Texas grid operator’s preliminary spring SARA for March to May foresees an additional 2.9 GW of gas, wind and solar units coming online to meet an expected peak demand of 64.2 GW. The final spring SARA report will be released in early March.
ATLANTA — Electric utilities have been largely proactive in their application of cyber risk protection programs across supply chains, according to NERC’s supply chain data request. However, much work remains to be done to ensure consistent adherence to supply chain standards, NERC said.
The organization presented the survey results at the meeting of the Member Representatives Committee on Tuesday. The goal of the survey was to fill in some holes in the understanding of low-impact bulk electric system cyber systems and how they differ from medium- and high-impact assets. Information on low-impact systems has previously been lacking because utilities are not required to inventory such assets.
“A lot of the low-impact cyber asset locations are with entities that have mediums and highs, so they’ve already got a [critical infrastructure protection] cyber compliance program in place,” said Howard Gugel, NERC’s vice president for engineering and standards. “They’re also subject to CIP-013 [procurement standards, and] they said they were going to voluntarily apply that, because they’re not going to have separate procurement systems for the lows, mediums and highs.”
Among the survey’s findings was that two-thirds of low-impact assets allowed external connectivity by third parties. Gugel described the consistency of this statistic as surprising given the diversity of operators participating in the survey.
“The amazing thing about this was, any way we split the numbers — if we looked at folks that only had low-impact BES cyber assets, if we looked at just the mediums and highs, or if we looked at entities that had the mediums and highs, and also lows — that same percentage was there for all of them,” he said.
But the findings became more varied as the team dug further into the details, breaking the overall cyber assets down by location: transmission stations and substations, generation resources, system restoration, etc. For operators with portfolios that included high-, medium- and low-impact assets — a category that included about 93% of the low-impact assets surveyed — the latter tend to be weighted toward the transmission side. For those that only own low-impact systems, most of their assets tend to be in generation.
Both types of operators are more likely to allow third-party electronic access to generation resources than transmission, but the divide is far starker with low-only asset owners. More than half of their generating resources in both the low and medium load (defined as less than 500 MW and 501 to 1,000 MW respectively) allowed external connectivity; by contrast, the split was more even for owners of low-, medium- and high-impact assets.
“It might cause us to have some more conversations with some of those entities; say, ‘What kind of controls do you have over this, and how are you looking at that access?” Gugel said.
Currently operators that have only low-impact cyber assets are not required to adhere to the portions of the NERC CIP reliability standards that apply to medium- and high-impact systems, partly because of the perception that such assets do not pose enough of a threat to include them. Gugel suggested that this attitude could need to be revisited: Although these assets may not be dangerous on an individual basis, collectively they have the potential to cause considerable headaches.
“I’m a transmission planner at heart and tend to look at blows to the system and impacts to transmission lines and such,” Gugel said. “From a cyber perspective, it’s a completely different beast — the ability to impact a bunch of blows from a remote threat actor is more than what I would consider for an N-1 from a transmission planning perspective, and it may rise to a risk that we should start considering.”
ATLANTA — Andy Dodge, director of the FERC Office of Electric Reliability, said the commission and NERC are reviewing the more than 70 comments filed in response to their proposal on disclosure of critical infrastructure protection (CIP) violations and will determine their next steps “probably in the next couple months.”
A white paper released in August proposed that NERC CIP Notices of Penalty (NOPs) include a public cover letter disclosing the name of the violator, the standards violated (but not the requirements) and the penalty amount. NERC would submit the remainder of the NOP, containing details on the violation, mitigation activity and potential vulnerabilities to cyber systems, as a nonpublic attachment, for which it would request critical energy/electric infrastructure information (CEII) designation. (See FERC, NERC Propose New CIP Disclosure Rules.)
From 2010 until December 2018, the public version of NERC’s CIP NOPs contained similar information as the confidential submission to FERC but excluded material NERC considered CEII, such as the name of the registered entity. In 2019, NERC began submitting public line-by-line redactions of information claimed as CEII.
The commission initially treats information claimed by NERC as CEII as nonpublic but has reviewed those determinations — and sometimes released additional information — in response to Freedom of Information Act (FOIA) requests. The staffs said they reconsidered their approach in response to an increase in FOIA requests.
“Some commenters liked the joint FERC-NERC approach. Some were totally opposed to it,” including some who thought all information should be shared, Dodge said.
Among respondents unsatisfied with the initiative was the Foundation for Resilient Societies, which criticized the proposal for requiring that any violations be fully mitigated before an NOP is submitted. It also disagreed with allowing utilities to request indefinite delays in public disclosure. As a result, “the public may become aware of adverse compliance trends only after a series of catastrophes occur,” the foundation said.
Public Citizen said the proposed disclosure requirements were a step in the right direction. However, the consumer advocacy group said further reforms were needed, including formal protection for whistleblowers and the creation of regional advisory bodies to provide feedback to FERC and NERC at the state level. It also criticized NERC for what it described as an overrepresentation of utility company executives in its leadership, which it said hindered the independence of the corporation.
At the other end of the spectrum, the MISO Transmission Owners said the level of detail envisioned for the NOPs could be dangerous for the security of the grid, warning that “this type of information could provide roadmaps to bad actors” targeting critical infrastructure assets. If greater transparency is required, the TOs said, the commission could consider indicating the degree of risk posed by the violation rather than the specific standard involved, and disclosing a range of penalties rather than the exact amount assessed.
Echoing this view, a joint filing — by the Edison Electric Institute, American Public Power Association, National Rural Electric Cooperative Association, Large Public Power Council, Transmission Access Policy Study Group, the Electric Power Supply Association, WIRES, and the Electricity Consumers Resource Council — argued that electric utilities already “have every incentive to protect the reliability of the BPS [bulk power system].”
They noted that most NOPs reported by NERC are the result of utilities voluntarily sharing information with the corporation. “Given that the public would require specialized training and expertise to derive any value from the name of the standard violated … it is not clear what benefit there is in automatic disclosure of this information,” said the group.
Transmission Line Ratings
Dodge also shared staff observations from the commission’s technical conference on transmission line ratings in September (AD19-15). (See FERC Considering Tx Line Rating Rules.)
Staff identified potential benefits of dynamic line ratings (DLRs) and ambient-adjusted ratings (AARs), including:
increased capacity for integrating renewables;
reducing congestion and curtailments;
improved transmission flexibility and situational awareness; and
increased transparency of line ratings.
Potential challenges to DLRs/AARs include:
possible reduction in available capacity during summer (when ambient temperatures exceed 104 degrees Fahrenheit) and winter seasons (when ambient temperatures exceed 32 F);
the fact that ambient condition forecasting is vital to DLR systems and transmission line AARs; and
AARs may not apply to all transmission lines.
Post-technical conference comments were due Nov. 1. Reply comments are due Nov. 16.
change the Board Executive Committee into a full hybrid board, including stakeholder and independent directors;
add at least three independent directors to the Board of Directors;
formalize SERC’s membership body to include a representative from each member company by transitioning the existing full board into a members group that will meet at least annually to advise the board on the business plan and budget, elect independent directors and approve bylaw changes, as needed;
change the Board Compliance Committee into the Board Risk Committee; and
add a Human Resources and Compensation Committee, a Nominating and Governance Committee, and a Finance and Audit Committee.
It “changes almost everything,” SERC General Counsel Holly Hawkins said of the revised bylaws, which were approved unanimously by the regional entity’s board last month.
SERC CEO Jason Blake called the new rules “transformational.”
NERC Chair Roy Thilly called it a “very positive development,” noting that all REs will now have hybrid boards.
“This moves SERC to the front of the pack in terms of good governance,” Trustee Fred Gorbet said.
ReliabilityFirst Bylaw Changes Approved
The board approved changes to ReliabilityFirst’s governance and oversight guidelines to:
modify the CEO and independent director compensation approval process;
appoint a lead independent director to serve with an appointed stakeholder chair and vice chair;
implement term limits for directors, consisting of four consecutive three-year terms;
appoint the CEO as a non-voting, ex officio member of the Board of Directors; and
require board approval for directors serving on more than five outside boards.
The board approved the following committee members:
Personnel Certification Governance Committee: Cory Danson, Western Area Power Administration, as chair for a term of two years. Current Chair Michael Anderson, American Electric Power, did not seek reappointment because his position changed at AEP. Margaret Quispe, SPP, will continue as vice chair.
Standards Committee: Amy Casuscelli, Xcel Energy, as chair, and Todd Bennett, Associated Electric Cooperative Inc., as vice chair for two-year terms.
Critical Infrastructure Protection Committee: Marc Child, Great River Energy, chair; and David Grubbs, city of Garland, Texas, and David Revill, Georgia Systems Operations, co-vice chairs, for terms beginning Jan. 1. The remaining positions on the Executive Committee will be filled at the December meeting.
Compliance and Certification Committee: three-year terms for Justin MacDonald, Midwest Energy, Cooperative Utility sector; Ashley Stringer, Oklahoma Municipal Power Authority, Transmission-Dependent Utility sector.
Approvals
The board approved:
The 2020-2022 Reliability Standards Development Plan and authorized NERC staff to file it with applicable regulatory authorities. The three-year plan for reliability standards development addresses FERC directives, emerging risks and the Standards Efficiency Review.
Reliability standard BAL-003-2 (Frequency Response and Frequency Bias Setting) and authorized its filing with FERC and other regulatory authorities. Howard Gugel, vice president of engineering and standards, said the revisions address inconsistencies identified in the Frequency Response Annual Analysis.
PRC-006-NPCC2 (Automatic Underfrequency Load Shedding), which removes redundancies with PRC-006-1, PRC-006-2, PRC-024-1 and PRC-024-2.
The board approved the ERO Reliability Risk Priorities Report, prepared by the Reliability Issues Steering Committee (RISC), which reflects the committee’s efforts to define and prioritize risks and recommend what NERC and industry representatives should do to manage them. The report adds a 10th risk — critical infrastructure interdependencies — to the nine previously identified. (See ‘Interdependencies’ Joins RISC’s List.)
RISC Chair Nelson Peeler said the report also was modified to make it “simpler [and] cleaner.” It also incorporates survey results, which “will allow us to better track and trend as we go year to year.”
“I think we have had much better alignment than in prior years,” he added.
2020-2022 Reliability Standards Development Plan Approved
The board approved the 2020-2022 Reliability Standards Development Plan (RSDP) and authorized NERC staff to file it with applicable regulatory authorities. The plan seeks to address FERC directives, emerging risks and the Standards Efficiency Review.
OGE Energy reported third-quarter earnings on Thursday, beating analysts’ expectations with a net income of about $251 million ($1.25/share). That compared favorably with the year prior, when the company reported earnings of $205 million ($1.02/share).
