NERC stakeholders have until 8 p.m. ET Friday to weigh in on proposed changes to reliability standard PRC-024-2 concerning inverter-based generation resources.
The proposal is intended to ensure that generator owners (GOs), operators, developers and equipment manufacturers understand how their plants are expected to respond to grid disturbances. It was based on disturbance analyses and the Inverter-Based Resource Performance Task Force’s PRC-024-2 Gaps Whitepaper. (See NERC to Try Again on Inverter Rules.)
One of the most significant changes is in section 4.1.2., in which NERC proposes expanding applicability to include transmission owners “that own a bulk electric system generator step-up (GSU) transformer or collector transformer.”
It also requires inverters not to trip or “enter momentary cessation” — an interruption in their injection of current into the grid — within the “no trip zone,” except for “documented and communicated regulatory or equipment limitations.”
Most solar PV generation is below the 75-MW threshold requiring registration with NERC. | NERC
The unofficial comment form references two issues that the standard drafting team (SDT) said must be addressed to ensure the reliability intent of the PRC-024 is achieved.
It notes that the existing standard refers only to “generator protective relaying,” which suggests the setting of voltage and frequency protection relays on the GSU transformers on synchronous generators are excluded.
“Because the GSU and the generator are connected to the same bus and have the same source (the generator), they see the same voltage (and frequency). Consequently, the voltage and frequency protection settings applied to the relays on the GSU must be included in the standard as the operation of those relays would result in tripping the generator, thus defeating the reliability intent of the standard,” it said.
Another issue identified by the SDT is that the standard applies only to GOs, excluding TOs that own GSUs or collector transformer and associated voltage and frequency protective relays.
However, none of those who had filed comments as of Monday said they knew of any GSU owners that were registered as a TO but not as a GO.
The Electric Reliability Organization’s proposed $207 million budget appears headed for approval, but NERC’s increased spending to develop its cybersecurity capability is facing some pushback from Canadian utilities.
NERC is boosting 2020 assessments by 4.5% overall, but Canada (+7.2% to $0.013/MWh) and Mexico (+6.0% to $0.016/MWh) face bigger increases than the U.S. (+4.3% to $0.016/MWh).
“Canadians have voiced concern regarding the overall value proposition of the E-ISAC, especially given substantial increases in the value of cyber-related services and cybersecurity investments by Canadian government partners,” the CEA said, adding that its member utilities have “limited ability … to flow through NERC costs to ratepayers.”
It said the E-ISAC should take advantage of “capabilities already available from other agencies or partners (such as the Canadian Cyber Centre) to avoid unnecessarily fully building out its own capabilities.”
IESO noted that concern over rising electricity costs has led the Ontario government to promise a 12% rate reduction. “A rise in regulatory fees beyond the rate of inflation forces the IESO to adjust our budget in areas that may negatively affect our ability to execute on our strategic priorities,” it said.
The CEA and IESO were among six entities that filed comments on NERC’s initial budget proposal. (See ERO Budgets up 3.8%; Assessments up 2.9%.) NERC’s second draft budget, released July 15, adds $500,000 for modifications to its Atlanta headquarters to provide more meeting space.
Other Commenters
Other commenters on the initial draft were generally supportive of the expansion of the E-ISAC, although the Bonneville Power Administration called for more “transparency” on its programs and benefits. BPA noted that the E-ISAC and the Cybersecurity Risk Information Sharing Program (CRISP) are more than 30% of the NERC budget, saying it “would like assurance that as resources are transferred from other programs such as event analysis to E-ISAC that those programs will still be viable to the industry.”
The Edison Electric Institute expressed no misgivings over the expansion, saying “the execution of the E-ISAC’s long-term strategic plan for building a world-class ISAC is critical for providing timely sharing of security threat information.”
The ISO/RTO Council (IRC) Standards Review Committee said NERC should “ensure the E-ISAC is able to provide the most relevant and timely actions in response to bulk power system threats and vulnerabilities.”
NERC responded to the comments by detailing the E-ISAC’s programs and touting its access to the intelligence community. It said industry participation with the office has increased, noting 25 Canadian asset owners and operators had established user accounts since late 2018.
Personnel Costs
EEI and the IRC did question NERC’s personnel costs.
The IRC suggested NERC should cut spending in reliability standards and compliance programs to reflect reduced compliance requirements as a result of its Standards Efficiency Review. In May, the Board of Trustees approved the elimination of 84 reliability requirements. (See “Standards Efficiency Review Retirements OK’d,” NERC Standards News Briefs: May 8-9, 2019.)
The council also said that while risk-based monitoring has introduced some efficiencies in the compliance program, “the enforcement program continues to follow a lengthy process.”
“The 2018 average processing age for the entire ERO Enterprise inventory was almost a year, with 37% between one and two years old and 7% over two years old. Developing a quicker path to resolve issues of noncompliance, particularly those that pose minimal risk to the reliability or security of the BPS could affect personnel and future budget dollars,” it said.
EEI sought information on NERC’s salary increases and urged the organization to seek ways to reduce medical expenses, which are budgeted to increase by 13%. NERC said its budget includes a 3% increase over base salaries for “merit adjustments” and “up to 0.5% for equity and market adjustments” that was requested by its board.
The institute said NERC should continue seeking ways to minimize operational costs “and focus resources on activities that are aligned with NERC’s performance objectives and [Reliability Issues Steering Committee] priorities. If new risks are identified, NERC should re-evaluate and prioritize activities, including deferring certain work to efficiently manage resources.”
NERC said its salaries are based on guidelines from the board’s Corporate Governance and Human Resources Committee and market compensation and benefit studies. “NERC is committed to building and maintaining top talent with the required specialized expertise necessary to fulfill the ERO Enterprise’s mission-critical roles,” it said.
The organization said it also benchmarks benefit costs and that increases to its medical insurance plan were “below market for several years.”
“The past two years have shown higher increases due to recent loss experience and fewer medical insurance provider options in the state of Georgia,” it said. “NERC continues to negotiate these premiums and will have final amounts for 2020 at the end of 2019.”
NERC presented its revised budget at the board’s Finance and Audit Committee (FAC) conference call Thursday. Interim CFO Andy Sharp said the additional spending, which was revealed in the second draft of the budget, will save money on catering and travel costs.
The additional spending boosts NERC’s 2020 budget to $83.4 million, a 4.5% increase over 2019, compared to 3.8% in the first draft. The office improvements will be funded through reserves, so the NERC assessment will not increase from the original draft.
In addition to the spending on the office, the second draft adds two employees converted from contractors, which it said will result in a slight savings.
The regional entities also presented their 2020 budgets at the meeting, none of which changed materially from the first drafts. All told, NERC and the REs are proposing about $207.3 million in spending in 2020, a 4.1% increase. Total assessments are projected to increase by 2.9%.
Approval Schedule
Written comments on the final budget draft, which are due by July 31, should be sent to Erika Chanzes, manager of business planning and regional relations (erika.chanzes@nerc.net).
The Member Representatives Committee will hold a call to receive input on Aug. 2. The FAC will meet Aug. 14 to recommend approval of final budgets, followed by board approval on Aug. 15 and a FERC filing Aug. 26, with subsequent filings to Canadian authorities.
DES MOINES, Iowa — SPP’s Strategic Planning Committee last week debated the merits of deterministic versus probabilistic planning approaches during a review of the RTO’s transmission investments.
Lanny Nickell, SPP’s vice president of engineering, told the SPC during its July 15 meeting that his staff use the industry’s standard deterministic approach, which requires that a single component’s outage does not cause system instability, thermal overloading, load curtailment or cascading outages. Critics say the approach does not adequately consider all the possibilities that arise during an event.
Probabilistic planning evaluates a range of possible outcomes but is more expensive than the deterministic approach. Nickell said a 2013 assessment of the approach estimated it would cost about $275,000 to develop probabilistic planning concepts, and another $2 million to develop and implement the software systems needed.
Nickell pointed out that SPP’s Integrated Transmission Planning (ITP) studies have performed “selective sensitivities” on the portfolios’ final assessments, including ranges for wind energy, gas prices and load growth. He also reminded the committee of the RTO’s 2016 transmission-value study, which indicated that for every $1 of transmission investment made in 2012-2014, members could expect at least a $3.50 benefit to ratepayers. (See SPP Begins Promotional Campaign to Tout Transmission Value.)
SPP’s transmission planning process has resulted in $7.7 billion in completed projects. Another $1.9 billion in projects have been approved.
If anything, Nickell said, SPP tends to be conservative when planning transmission buildouts.
“When building an ITP portfolio, our benefit-to-cost [studies] tend to be lower. We don’t do a lot of what-if scenario analyses,” he said, noting the 2019 scope’s reference case and emerging-technologies case are fairly similar. “I don’t think it’s too far out of the realm from what we’ve seen in the past. If the world dramatically changes, what will that mean? We don’t know until we study it.”
SPP-directed transmission investment | SPP
Golden Spread Electric Cooperative’s Mike Wise, the SPC’s vice chair, praised SPP’s work in creating an “uncongested, reliable system,” but he said current practices may need to change.
“Going further than what we’ve done requires a real stretch of the imagination,” he said. “I’m concerned we’re going to look back and say, ‘Did we make a quality decision to ensure we understand the probability of regret?’”
SPP CEO Nick Brown agreed with comments about future uncertainty, saying, “We’re woefully inaccurate in terms of how we look at the future.”
“We, as an industry, should be spending a lot more time than we do on transmission planning,” he said. “I think it’s time we move into a probabilistic approach to transmission planning.”
To increase planning confidence, Nickell said SPP could increase the minimum benefit-cost threshold for approval from 1.05 to 1.25, reduce the financial analysis time frame and perform more frequent assessments with real-time data, as it did with its transmission-value study.
SPP Chairman Larry Altenbaumer said the RTO has built a strong foundation with its planning processes, “but we can’t let that blind us moving forward.”
Altenbaumer said the Value and Affordability Task Force (VATF), which he chairs, is also looking at the issue. The discussion will continue there, he said.
Expansion the Top Strategic Priority
The SPC also reviewed feedback from its May planning retreat, during which members were asked to determine which strategic initiatives should be actively pursued.
Committee members identified the top three priorities as:
Expanding SPP’s 14-state footprint, both east and west.
Implementing the Holistic Integrated Tariff Team’s recommendations shared with the Markets and Operations Policy Committee.
Implementing the VATF’s recommendations. The task force was formed in January to review the cost recovery of transmission investments as well as the ongoing benefit from those investments and SPP’s operation. (See “Altenbaumer Continues to Exert his Influence,” SPP Strategic Planning Committee Briefs: Jan. 16, 2019.)
Staff said the SPC members’ consensus was that continuing to seek opportunities to provide services and develop markets “would add tremendous value and benefit to SPP’s current stakeholders.” The feedback indicated expansion “must be considered strategically and proactively while minimizing the cost to existing members,” staff said.
The SPC also identified other priorities as expanding services within SPP, a continued focus on cybersecurity, taking a lead role in applying battery storage, better integrating renewables and resolving issues that prevent the export of renewable or other low-cost generation.
The SPC will share its feedback with the Board of Directors and Members Committee during their July meeting.
ISO-NE Director of Transmission Planning Brent Oberlin presented a revised draft of the competitive transmission request for proposals template at a teleconference meeting of the Planning Advisory Committee on Thursday.
The materials provided — including general instructions and related workbooks — focus on a solicitation for a reliability transmission upgrade or a market efficiency transmission upgrade.
In evaluating competitive transmission proposals, ISO-NE says it will use a normalized base case analysis (illustrated) along with a risk analysis to consider market and project-level risks. | ISO-NE
To submit proposals, respondents will use RFP360, a web-based application the RTO uses to communicate with the respondents and to collect responses.
“‘Make sure there’s a controlled environment.’ That’s one of the lessons we’ve learned from other areas,” Oberlin said.
The RTO has drafted similar documentation for an RFP for a public policy transmission need, but it has not yet published it, he said.
Oberlin described the lifecycle cost workbook as “a monster,” saying “it takes a while to open, so don’t touch anything while it’s opening or you’ll regret it.”
The RTO has posted an unlocked version of the lifecycle cost workbook for review.
Comments on this latest draft of the RFP materials should be submitted to pacmatters@iso-ne.com by Aug. 5.
Refined Accuracy
Responding to a question from Eversource Energy, Oberlin said ISO-NE is “going to be pushing the bounds” on cost estimate accuracy and hopes that “everyone is in at least the plus 50%, minus 25% range.”
“Our desire would be to actually be a lot tighter than that; plus/minus 10% would really be the goal, because we don’t want to revisit this in the future,” Oberlin said.
Between phases 1 and 2 of the application process, the RTO asks for additional information to better understand the project and “really dig in on the nuts and bolts,” he said.
“It is not a time for the respondent to be changing the design of the project,” Oberlin said. “We shouldn’t see night-and-day changes in the estimate between those two stages, so we are looking for a fairly refined accuracy right up front.”
Respondents can also provide their own workbook with an explanation of why they do things differently, he said.
Lawrence Willick of New England Energy Connection asked about the period for lifecycle costs, and how the RTO would reconcile project components of varying lifetimes.
Oberlin said it is assuming 15 years for the base lifecycle and that it would be up to the RTO to understand the varying lifecycles of installed components.
FERC last week affirmed a previous ruling that a 2016 merger left three ITC Holdings subsidiaries no longer fully independent, disqualifying them from a full return on equity incentive intended for standalone transmission providers (EL18-140).
The commission last year halved the ROE adders previously granted to ITC subsidiaries for being independent providers, saying a merger with Canada-based Fortis and Singapore government-owned investment company GIC Private Limited compromised the parent company’s autonomy. (See FERC Reduces ITC Adders over Independence Issues.)
Under FERC rules, a fully independent transmission company is eligible to receive a 50-basis-point transco adder. The commission last October determined that a reduced incentive of 25 basis points was appropriate for International Transmission Co., ITC Midwest and Michigan Electric Transmission Co.
“We continue to find that to be the appropriate incentive in this case,” the commission said in its order Thursday, noting again that the merger reduced, but did not eliminate, the companies’ independence.
ITC Midwest builds a transmission line in Iowa in 2013. | ITC Midwest
In seeking rehearing on the issue, the ITC companies argued that their relatively new upstream owners have no impact on their investment planning or capital formation. They also repeated a contention that their affiliates aren’t MISO market participants and said the commission failed to justify its decision to reduce the adder.
“ITC Holdings’ governance is fully independent from market participant influence, as ITC Holdings is governed, managed, operated and financed on a standalone basis,” the companies argued.
But FERC said the company misunderstood the yardstick the commission uses to gauge independence.
The commission said that while it considered ITC’s structure and arrangement with subsidiaries, it also found that both Fortis and GIC own other market participants that exercise control over the companies. Fortis, the commission pointed out, evaluates capital expenses for its “entire corporate family.”
“On capital formation, the ITC companies necessarily rely on Fortis for financing, as they cannot issue their own common stock, and Fortis indicated that cash for subsidiary capital expenditure programs will also come from debt issuances from Fortis,” FERC explained.
The commission also noted that both Fortis and GIC representatives sit on ITC’s board of directors and that “all executives of Fortis’ regulated utility subsidies meet regularly to discuss business operations.”
ITC had argued that a “majority” of its board members are independent.
In a separate, partial dissent, Commissioner Richard Glick repeated his previous assertion that the companies are not independent enough to justify any ROE adder.
“I do not believe that a 25-basis-point adder is just and reasonable here, and [I] would instead eliminate the ITC companies’ ROE adder altogether,” Glick said.
ITC said it was “disappointed” in the ruling.
“ITC’s operating companies remain fully independent of affiliate market participants in all RTO/ISOs in which they operate, and therefore continue to fully meet the conditions under which FERC originally granted independence adders,” Nina Plaushin, vice president of regulatory and federal affairs, said in a statement. “To the extent the commission chooses to make changes to this specific incentive adder, any change should be consistently applied across the industry and warrants full discussion in the general proceeding currently before FERC.”
In March, FERC issued a Notice of Inquiry seeking feedback on whether it should change the “scope and implementation” of its incentives policy (PL19-3). Dozens of entities submitted comments last month. (See Tx Incentives NOI Brings Calls for Broader Reforms.)
MISO last week said it will still pursue major aspects of a cost allocation proposal that FERC rejected last month after it found that the RTO’s treatment of a new category of local economic transmission projects would have violated the principle of cost causation.
The extensive cost allocation plan would have lowered the voltage threshold for market efficiency projects (MEPs) from 345 kV to 230 kV, created two new project benefit metrics and eliminated a 20% footprint-wide postage-stamp cost allocation method for projects. It would have also provided limited exceptions to the competitive bidding process if a transmission project were needed immediately for the sake of reliability. (See MISO Allocation Plan Fails on Local Project Treatment.)
MISO says it will still seek most of those changes, staff revealed during a Wednesday conference call of the Regional Expansion Criteria and Benefits Working Group. Director of Economic and Policy Planning Jesse Moser said the RTO is still hopeful it can apply the cost allocation changes before the 2019 Transmission Expansion Plan is approved in late December.
Keep Local Economic Project?
But MISO’s proposal also sought to create a new project type — the local economic project — meant for smaller, economically driven transmission projects between 100 and 230 kV, where 100% of costs would be allocated to the local transmission pricing zone containing the line. The projects would not only have to meet a local benefit-to-cost ratio of 1.25 to 1 or greater within their pricing zones, they would also be required to show the same minimum regional 1.25-to-1 ratio required of MEPs.
FERC ultimately rejected MISO’s entire cost allocation proposal on the basis of the local economic project design. The commission said the requirement to show regional benefits only to charge project costs to local pricing zones would have violated its cost-causation principle.
MISO is currently undecided on whether to alter the local economic project criteria or abandon the proposal altogether.
The revised plan could include a “Local Economic Project 2.0,” Moser said, adding that MISO could remove the 1.25-to-1 regional benefit-to-cost ratio requirement and preserve the proposed project criteria.
“I have some reservations on even using the [local economic project] terminology because it was rejected,” Moser said.
But Clean Grid Alliance’s Natalie McIntire argued that MISO should commit to assigning costs commensurate with any regional beneficiaries, even for small transmission projects.
“We’re trying to get some direction. I don’t think we even have enough detail to call them options just yet,” Moser said. “We’re not proposing anything today.”
However, MISO is clear that it will not lower its proposed regional MEP voltage threshold from 230 kV to 100 kV, although some stakeholders on the call said the RTO should consider lowering the threshold across the board.
At any rate, staff said, FERC will address the 100-kV issue shortly in response to LS Power’s June complaint seeking to compel MISO to lower the threshold for competitively bid transmission projects to 100 kV. (See Complaint Seeks Bigger Role for Smaller MISO Projects.)
Interregional Aspect
While MISO will still seek to lower its internal MEP voltage threshold to 230 kV, it still must address a six-year-old FERC compliance directive to lower its interregional MEP voltage threshold to 100 kV.
FERC in 2013 ordered MISO and PJM to lower interregional project thresholds after Northern Indiana Public Service Co. complained about shortfalls in the RTOs’ interregional planning process.
Like the local economic project proposal, MISO had proposed that its share of interregional economic projects with voltages below 230 kV but 100 kV and above be fully allocated to the transmission pricing zones where the project is located. FERC similarly ruled out the proposal based on deviation from the cost-causation principle.
“MISO is not at a place where we have a preferred option or solution to address the interregional. We’re at the place where we have to do something for PJM lower-voltage projects, but maybe we leave SPP alone?” Moser said.
Moser said MISO could either file to lower the interregional project threshold to 100 kV on both seams or make a standalone filing to extend MEP cost allocation to lower-voltage interregional projects with PJM. He added those were merely options at this point. MISO is on a 90-day timeline to address the NIPSCO complaint order.
MISO asked stakeholders to weigh in over the next three weeks on which interregional filing path it should take.
DES MOINES, Iowa — SPP ended eight days of conservative operations last week, just in time to meet near-record demand in its 14-state footprint.
The RTO declared the alert, a level down from an energy emergency, on July 10, when it projected an above-normal number of primarily forced outages and a drop in wind production. Normal operations resumed on Wednesday.
SPP was already without 13 GW of non-variable resources when it declared the alert. Those outages peaked at slightly more than 14 GW on July 13, before finally falling to less than 10 GW on Thursday.
“At one point, 45% of our generation was unavailable to us through outages or derates,” Operations Vice President Bruce Rew told the Markets and Operations Policy Committee on July 16. He said outages were slightly less than 8 GW a year ago on July 13.
Rew said SPP was predicting a more normal wind production of 12 to 13 GW through the end of last week. Forecasters pretty much nailed their prediction.
“Less than 5 GW is a low wind day for us anymore,” he said.
Fortunately, the alert ended just as SPP was expecting to set new records for peak demand. Demand fell short Wednesday to Friday, though on Friday it came within 30 MW of the all-time mark of 50.6 GW, set in July 2016.
It was the sixth time the RTO has called for conservative operations this year, more than it did all last year. The first two alerts were called in February and March as a result of normal cold weather events. SPP has since issued alerts on May 29, June 4 and July 1 over what staff called “uncertainty factors.”
“What’s the weather forecast? Potential generation? Certainty of load?” Rew said. “We’re seeing outages extending a little longer than normal.”
A comparison of SPP’s July outages | SPP
Asked if SPP’s criteria for declaring conservative operations have changed, C.J. Brown, director of system operations, said no.
“We have gotten better at what we’re looking at from a certainty perspective,” he said.
Given the number of conservation alerts called this year, which have totaled 25 days, the MOPC asked SPP to further evaluate this year’s events and bring back a recommended policy and/or process improvement to October’s regular meeting. Members asked for more detailed information on the outages and the discrepancies between real-time operating capacity and assumed planned capacity, and to clarify the RTO’s current must-offer requirements.
CARMEL, Ind. — MISO’s grid can withstand major reliability risks even when renewables reach 40% of the generation mix, RTO staff said last week.
That finding represents a turnabout from a study last year that found the RTO would need to take significant steps to reinforce its grid to handle a jump from 30% to 40% renewable penetration. (See Study: MISO Grid Needs Work at 40% Renewables.) But it is now more confident about its ability to maintain reliability as renewable development intensifies.
“The challenge is a non-linear thing. There are certain points where it becomes more complex as you eat up some of the flexibility and capacity on the system. … There’s more megawatts of capacity needed on the system over time,” MISO Manager of Policy Studies Jordan Bakke said during a special workshop on the topic Wednesday.
MISO renewable growth projection | MISO
MISO foresees continued wind growth in the northern part of its footprint, with most renewable generation in the South coming from solar. As more solar comes online, the daily peak risk hour shifts to later in the day as the sun sets, Bakke said.
“The characterization of renewable generation deployment is wind in the north and solar basically everywhere,” he said.
In a scenario in which renewables account for 40% the resource mix, MISO found they could serve 42% of peak load, 67% of shoulder or light load, and up to 81% of load when weather conditions for renewables are optimal. When renewable conditions are ideal, wind and solar generation drastically cut into the share of load served by natural gas and coal generation.
“Renewables try to replace other generation because of the economics,” MISO Senior Transmission Expansion Planning Engineer Nihal Mohan said.
Although MISO found frequency response degrades as more renewables are added, the system would remain stable at 40%, even when a hypothetical large generator of about 4,500 MW trips offline. When that happens, the system stays above the 59.5-Hz underfrequency load shedding threshold.
Bakke said MISO staff now think declining frequency response is not as serious as first suspected.
While frequency response seems to remain acceptable up to 40% renewables, staff say they’re still concerned about scenarios with combinations of high renewable output, low load and large generator disturbances.
And MISO is still concerned that reliability will suffer in other ways.
Under a 40% renewables scenario, the RTO may need to remedy low short-circuit issues with transmission lines equipped with dynamic support capabilities. It said members may be better off building HVDC lines rather than installing several synchronous condensers, then mitigating the small signal stability issues that such equipment produces.
“You can add small lines, you can add condensers, but they would probably add more stability issues,” Mohan said. “It’s probably better to think about this in advance and come up with an [all-encompassing] solution.”
“We’re able to get to a renewable energy penetration and deliver energy in a stable way” if MISO members are willing to move to new technologies, Bakke said.
MISO also found that at a higher penetration of renewables, the system would in most cases have more time to clear line faults.
Keeping with previous discussions on the renewable integration assessment, stakeholders asked how MISO envisions that electric storage resources will mitigate reliability issues.
“At this phase of study, we’re not considering storage,” Mohan said. Storage devices will make an appearance in the third phase of the ongoing study, he said.
MISO will host another workshop Sept. 13 to discuss its study results on a 50% renewable future. The final phase of the study will examine how the grid operates when locally sited renewables serve load.
NYISO’s Business Issues Committee on Wednesday voted to approve updates that align the Transmission Expansion & Interconnection (TE&I) manual with Tariff changes made since the last comprehensive manual update, provide additional detail regarding interconnection study methodology, and clarify existing practices and procedures.
The Operations Committee reviewed and approved the revisions on Thursday.
The ISO’s senior manager for interconnection projects, Thinh Nguyen, detailed the TE&I Manual revisions and the Tariff revisions accepted by FERC over the past two years to alter the transmission expansion and interconnection procedures. Updates include:
Revisions made as part of the 2017 comprehensive queue revision, such as reducing the number of study agreements.
Creating deadlines for study reports.
Clarifying roles and responsibilities of parties in the interconnection process.
Making feasibility studies under Attachments X and Z options at the developer’s election, with two alternative levels of analyses.
Revising interconnection request data forms and requirements.
Providing parties the option to narrow the scope of studies required or uprate projects.
Allowing certain projects with multiple voltage levels to submit a single interconnection request.
The manual changes also reflect queue reforms aimed at improving the class year study process by revising start dates; creating the “bifurcated class year” process; affording additional opportunities for projects to withdraw from the class year study; and specifying how a project can finalize an interconnection agreement prior to completion of a class year study and/or request limited operations prior to execution of an interconnection agreement.
New York Power Authority transmission lines near the Adirondack Mountains | NYPA
Other changes to the interconnection process reflected in the manual updates include clarification of interconnection study base case inclusion rules; updated small generating facility deposits and application fee requirements; clarification of the clustering process for small generating facilities; clarification of the process for evaluating alternative points of interconnection for small generators; and the requirement that certain large generating facilities install phasor measurement units.
The manual changes, consistent with the 2017 revision, also explain the process for calculating capacity resource interconnection service values applicable to the winter capability period and require stakeholder review of changes in transmission owner planning criteria, while also increasing the frequency of required updates to proposed in-service, initial synchronization and commercial operation dates.
External Capacity Resource Eligibility
Director of Market Design and Product Management Robert Pike presented the monthly Broader Regional Markets report and highlighted item 26, regarding an effort to clarify the minimum deliverability requirements for external capacity into the NYISO Installed Capacity (ICAP) market.
The ISO reviewed eligibility and deliverability requirements for external capacity from ISO-NE with stakeholders at the June 27 ICAP/Market Issues Working Group meeting and will return to future working group meetings to continue the discussions, he said.
NYISO will continue to evaluate what, if any, additional performance requirements and obligations are needed for deliverability to the New York Control Area border for purposes of external resource eligibility to sell capacity into New York.
LBMPs down 25% YoY in June
NYISO locational-based marginal prices averaged $24.43/MWh in June, up slightly from $23.10/MWh in May, but down about 25% from the same month a year ago, Pike said in delivering the monthly operations report. Year-to-date monthly energy prices averaged $35.76/MWh, a 25% decrease from a year ago.
Day-ahead and real-time load-weighted LBMPs came in higher compared to May. Average daily sendout was 429 GWh/day in June, compared with 373 GWh/day in May and 445 GWh/day in the same month a year ago.
St. Lawrence-Franklin D. Roosevelt Power Project on the St. Lawrence River | NYPA
Transco Z6 hub natural gas prices averaged $2.10/MMBtu for the month, off slightly from May and down 14.1% from a year ago.
Distillate prices were down 13.2% year over year and lower from the previous month, with Jet Kerosene Gulf Coast averaging $13.50/MMBtu, down from $14.64/MMBtu in May, while Ultra-low Sulfur No. 2 Diesel NY Harbor dropped to $13.23/MMBtu from $14.54/MMBtu in May.
June uplift dropped to 7 cents/MWh from 13 cents/MWh in May, while total uplift costs, including the ISO’s cost of operations, came in higher than the previous month.
The ISO’s 19 cents/MWh local reliability share in June was down from 23 cents the previous month, while the statewide share dropped a penny from the previous month to -12 cents/MWh.
The Thunderstorm Alert cost for New York City was 77 cents/MWh, up from 19 cents in May.
Grid modernization and security were the focus of two U.S. House of Representatives committees last week as four bipartisan bills cleared the Energy and Commerce Committee and a second panel held hearings on two other legislative proposals.
The House SST Committee’s Energy Subcommittee held hearings on grid modernization and cybersecurity last week.
On Wednesday, the Energy and Commerce Committee passed the following bills by voice votes, moving them to consideration by the full House:
The Enhancing Grid Security through Public-Private Partnerships Act (H.R. 359), introduced by Reps. Jerry McNerney (D-Calif.) and Bob Latta (R-Ohio), would direct the Department of Energy to encourage public-private partnerships to mitigate electric utilities’ physical and cybersecurity risks. The effort, in consultation with state regulators, industry and the Electric Reliability Organization, would promote the use of maturity models, self-assessments and auditing methods for measuring security, provide training to address supply chain risks, and encourage sharing of best practices and data collection.
The Cyber Sense Act of 2019 (H.R. 360), also introduced by Latta and McNerney, would require the secretary of energy to establish a program to identify cybersecure products for use in the bulk power system.
The Pipeline and LNG Facility Cybersecurity Preparedness Act (H.R. 370), introduced by Rep. Fred Upton (R-Mich.) — ranking member of the E&C Committee’s Energy Subcommittee — and Rep. David Loebsack (D-Iowa), would establish a program at DOE to improve the physical security, cybersecurity and resilience of natural gas transmission and distribution pipelines and LNG facilities.
The panel also approved a bill (H.R. 362) that would codify the role of Karen S. Evans, who was appointed in September as assistant secretary for DOE’s Office of Cybersecurity, Energy Security and Emergency Response.
Science, Space and Technology Committee
Evans was among the witnesses who testified Wednesday before the House Science, Space and Technology Committee’s Energy Subcommittee.
Rep. Conor Lamb (D-Pa.)
Subcommittee Chair Conor Lamb (D-Pa.) opened the hearing by touting two other pieces of legislation, the Grid Modernization Research and Development Act of 2019 — which calls for research on grid resilience, emergency response, modeling and visualization — and the Grid Cybersecurity Research and Development Act of 2019 (H.R. 4120), which would authorize a research and development program by the Department of Homeland Security, the National Institute for Standards and Technology (NIST), and the National Science Foundation to harden the grid from cyberattacks. The R&D program would include technical assistance, education and workforce programs. The bills will be introduced after the August recess.
Artificial Intelligence’s Role
Evans told the committee that DOE is seeking to spur innovation in big data and artificial intelligence, saying AI has a “critical role” in improving grid resilience. “We’re talking about … software-defined networks, autonomous solutions, really analyzing the data … to remove some of what is happening at a human level now that could be done by AI, by machine learning. That is the area that we are really exploring so that we can look at higher analysis of security, and also being able to model the resilience in real time.”
Karen S. Evans, Department of Energy
McNerney asked whether adversaries could use AI to attack the grid.
“For every great new innovation that we do … we also have to evaluate what are the potential risks associated with that and then engineer preventative solutions,” she responded. “We don’t want to stifle innovation. We want to take advantage of those things.”
Juan Torres, associate laboratory director for energy systems integration at the National Renewable Energy Laboratory, agreed.
“Just about any tool … can be used for good or for bad. That’s why it’s imperative for us to maintain that leadership in the advancements of these technologies so we are the ones using these for the right purpose and can actually deter any negative use or any attacks on these systems,” said Torres, who is also co-chair of DOE’s Grid Modernization Lab Consortium.
Juan Torres, NREL
Torres said DOE is applying AI to four “foundational areas”: understanding complex systems theory; big data analytics; optimization to ensure distributed systems work together; and non-linear controls.
“What we’re seeing is with highly distributed systems, some of the linear control concepts that are used now on the grid may not apply in a highly decentralized type of system,” he said.
Wind, Solar Cybersecurity
Torres said DOE’s solar and wind technology offices are working with industry officials to identify the industry’s cybersecurity needs and those of distributed energy systems. DOE and the International Electrotechnical Commission on Wednesday hosted a cybersecurity workshop at the National Wind Technology Center at NREL’s Flatirons Campus in Boulder, Colo. “This event is bringing key government and industry players together for the first time to add the cybersecurity needs of the growing wind power industry,” he said.
AI would build on smart grid technologies that witness Katherine Hamilton, executive director of the Advanced Energy Management Alliance, said “have allowed the grid to operate more efficiently and with greater visibility.”
“The year of detective work necessary to determine that the Northeast blackout of 2003 was caused by a branch in Cleveland would no longer be the case thanks to these technologies,” she said.
Workforce Needs
The hearing also discussed the industry’s workforce needs. According to research funded by NIST, the U.S. has almost 716,000 people in the cybersecurity workforce and almost 314,000 job openings.
Katherine Hamilton, AEMA
Hamilton said the workforce challenges extend beyond cybersecurity, noting that about 30% of utility employees and 40% of the industry’s engineers are millennials. “Millennials tend to change jobs faster than we’re used to in the utility workforce. You would start in the utility and retire in the utility. But people change jobs a lot faster and there are more types of jobs, so we need to find out what [kinds of] training are needed. … What are some of the skills that transfer really easily?
“In California right now, there are wildfires that are potentially going to cause public safety outages of 30 days or more … and there are not enough trained tree trimmers to do the work needed on vegetation management. You can’t send a kid out with a bushwhacker. These are really trained labor. So, there are a lot of job needs and opportunities, and there are people who don’t have jobs, and we need to somehow match those. So, bringing the public sector and the private sector together on that seems to me to be a good way to think about that.”
Hamilton said encouraging interest in STEM education and cybersecurity needs to begin in elementary school.
Kelly Speakes-Backman, Energy Storage Association
Witness Kelly Speakes-Backman, CEO of the Energy Storage Association, said she was glad her twin 15-year-old daughters were in the audience hearing the discussion. “Their high school has a program that is partnered with the U.S. Naval Academy specifically on cybersecurity, and I really want them to take it,” she said.
Torres said that in addition to sparking early interest in the STEM fields, industry and government should encourage mentoring to ensure a pipeline of future teachers and professors.
Hamilton said DOE and its National Labs also should be involved in encouraging what she called the “democratization” of innovation.
“Innovations are not limited to our labs, our universities or our utilities. They are everywhere. They are kids in basements playing with their apps,” she said. “So, trying to make sure that our research programs are able to connect the dots so that we can bring entrepreneurs to test and make sure that we have proof of concept [is important]. Because no utility is going to purchase a piece of equipment that was designed in somebody’s basement. They need to know that the Department of Energy and the National Labs have given it the seal of approval … by testing it and making sure that this all works.
“While part of that is about bringing new people into the industry — because there are so many new excited young people coming in — we also need to make sure that we then connect them to the programs that are existing to enrich the programs too,” she said.
A House subcommittee meeting last week heard testimony from (from left) Karen S. Evans, DOE; Juan Torres, National Renewable Energy Laboratory; Kelly Speakes-Backman, Energy Storage Association; and Katherine Hamilton, Advanced Energy Management Alliance.
Measuring Cost-effectiveness
Speakes-Backman, a former member of the Maryland Public Service Commission, had a different ask of DOE, saying it should help states develop ways to measure the cost-effectiveness of resilience measures. “This is an issue that I personally had after the derecho in 2011. Utilities can invest in reliability and there are metrics for that, but they cannot invest in resilience because there aren’t metrics for that to prove cost-effectiveness.”
