WASHINGTON — In their closing remarks at Thursday’s annual technical conference on reliability, acting FERC Chair Cheryl LaFleur and Commissioner Colette Honorable talked as if the event would be Honorable’s last public appearance as a commissioner.
It was indeed.
“Parting is such sweet sorrow! My last day as a FERC commissioner will be this Friday. It has been an honor. Thank you!” Honorable tweeted late Monday night.
“When we sat in this [commission meeting] room last month, I said, ‘I hope this won’t be the last time we’re in this room together,’” LaFleur began.
“And I equally hope that today, but I’m less sanguine that there’ll be a lot of other times,” LaFleur continued. “I think you’ve brought so much … to the commission, particularly with your focus on customers and your constant reminders about the need to work with our state colleagues. … I will really miss having you here.”
Honorable thanked FERC staff at length and told LaFleur that “It’s been an honor to work with you.
“This has been the highest honor of my professional career,” she concluded. “And it’s so much so because of the men and women I’ve done it with. So thank you so much.”
BRANSON, Mo. — MISO staff and the Independent Market Monitor agreed that the RTO’s markets performed as they should have this spring, but both found a surge in MISO South outages troubling.
MISO reported an average 69.2 GW of load March through May, up 1.3% from 68.3 GW in spring 2016. Executive Director of Strategy Shawn McFarlane said hotter-than-normal spring temperatures contributed to the load increase. The RTO hit a 92.2-GW spring peak on May 16.
The average spring real-time energy price was $29.96/MWh (the Monitor reported an average $29.90/MWh), a 39% increase from spring 2016, driven by a sharp increase in gas prices, MISO said. Market Monitor David Patton said natural gas prices rose 57 to 65% year-over-year, with the highest price spikes in Texas and Louisiana.
McFarlane said the higher load, combined with forced outages, caused high real-time congestion on multiple days, particularly in the South and Central regions.
MISO racked up $467 million in congestion during the quarter, Patton said during his quarterly report delivered on the first day of summer to the Markets Committee of the Board of Directors. He cited higher gas prices as a contributor to the rise in congestion, saying “gas-fired units are often marginal when generation is redispatched to manage network flows.”
“MISO experienced the most congestion of any other RTO in the country … almost half a billion dollars,” Patton said. He repeated his proposal for relieving congestion: that MISO and its neighbors transfer the control of border constraints when one RTO has more relief on a flowgate than the other.
“A good reminder that there is always work to be done at the seams to improve things for our constituents,” Director Paul Bonavia said.
The congestion was also because of high planned outages in MISO South, Patton said, adding that the RTO should seek additional authority to approve and coordinate outages. Expanding the authority of the RTO, which is currently limited to a “reliability review,” will be one of the recommendations in his annual State of the Market Report this month.
Under its Business Practices Manual, MISO can only “recommend [an outage] schedule that maintains system security and minimizes adverse impacts.” Owners and operators submit planned maintenance outage schedules for generators 10 MW and above to MISO for a minimum rolling 24-month period. The RTO studies the impact of all transmission and generator outages and works with owners to reschedule when an “outage analysis indicates unacceptable system conditions” or when a zonal maintenance margin is reached. “We have to not schedule ourselves into emergency situations. The ability to schedule them to minimize their effects will be a significant savings,” Patton said.
There is no need for all resources to schedule their maintenance outages in the spring and fall shoulder months, Patton continued, noting that capacity often exceeds winter load in the South by so much that it becomes “stranded” because of the limit on South-to-North transfers. “Economic opportunities likely exist to shift outages from shoulder to winter months,” he said.
Outages in MISO South removed as much as a 34% share of capacity during the spring, and outages in MISO Midwest took about 25% of capacity. Last year, spring outages took out 15% in the South and 14% in the Midwest. As a consequence, real-time congestion cost increased more than 50% over last winter and the prior spring quarter, according to the Monitor.
Patton also noted that the transmission and generation outages and extreme weather in the South led to 22 days of conservative operations in load pockets and three days with maximum generation alerts in April. An emergency maximum generation event on April 4 was spurred by the loss of a large nuclear unit, apparently Entergy’s Grand Gulf 1 in Mississippi, which the Nuclear Regulatory Commission reported going out of service because of a condensate leak.
Director Baljit Dail asked if there was a reason behind the spate of outages. “It just struck me as a massive increase. … It was two-and-a-half times what we normally have,” he said.
Staff agreed the outages were higher than the usual crop of shoulder-season outages.
“We do agree with Dr. Patton’s suggestion that a higher degree of coordination would be useful,” Chief Operating Officer Richard Doying said.
Bonavia said he once commiserated with control room operators over the challenges of handling summer heat but was told it was the shoulder months that caused the most anxiety. “They’re ready on those hot summer days when demand is screaming. … It’s those shoulder periods when the weather is volatile and the storms kick up that worry them,” Bonavia recounted.
Patton also praised the rollout of MISO’s extended locational marginal pricing (ELMP), which he said was responsible for about a 10% decrease in real-time revenue sufficiency guarantees paid out to market participants in the spring. However, Patton said he is still recommending that the RTO expand ELMP further to allow all generators with two-hour minimum run times to set prices, instead of MISO’s change, which added online resources with one-hour start-up times. MISO contends that the Monitor’s price-setting expansion would not be worth the expensive software change. (See “MISO Officially Expands ELMP,” MISO Market Subcommittee Briefs.)
WESTBOROUGH, Mass. — ISO-NE Director of Regional Planning Mike Henderson on Wednesday presented the schedule for stakeholder comments on the grid operator’s 2017 Regional System Plan, which are due July 24. The plan will be discussed at the August Planning Advisory Committee ahead of a Sept. 14 public meeting in Boston. The draft plan will be posted online by July 7.
“Our view is that the report should be viewed as a [critical energy infrastructure information] document,” Henderson told the PAC during a June 21 teleconference. “In past years, we have noted some, frankly, mistakes that the ISO made in the report where we may have inadvertently included some CEII materials, and as a draft document, that would present a major issue. … We’d hate to see something that does not reflect your [PAC members] input … put out in the public domain.”
Transmission planner Jon Breard presented an update on transmission projects and asset condition as part of the RSP drafting process. One participant asked if, based on the presentation, the growth in transmission spending was coming to an end in 2019.
“I’d be careful about ‘coming to an end,’” said Brent Oberlin, director of transmission planning. “It’s just what we have planned so far [is] really slowing down, and that’s our expectation going forward.” He added that the RTO must still complete reassessments for Maine, New Hampshire and central Massachusetts.
RTO will not Conduct Public Policy Tx Study for 2017
Oberlin presented ISO-NE’s conclusion that no federal or state public policy requirements are currently driving transmission needs, precluding the need for a special study on the subject this year. The RTO’s position aligns with a similar assessment submitted by the New England States Committee on Electricity (NESCOE) last month. (See ISO-NE: Won’t Override States on Public Policy Tx Needs.)
A May 16 letter from the Conservation Law Foundation asked the RTO to conduct the analysis despite NESCOE’s conclusion. NESCOE responded that ISO-NE should evaluate potential projects only after states have indicated transmission needs resulting from their policies.
Paul Dumas of Avangrid asked when the Tariff stipulates that the RTO must start another public policy process.
“At least every three years,” Oberlin said. “So the farthest that we would go out would be initiating the process in 2020. I think we’re going to keep an eye on where the states are with [requests for proposals] and things like that and make our determination if we would go earlier.”
Eversource to Replace ‘Vintage 1950’ Equipment
Eversource Energy’s George Wegh presented CEII material on the utility’s work to modernize several outdated substation control houses in its Eastern Massachusetts service territory. Wegh apologized for informing the PAC after the work had already started. He said Eversource would fix whatever internal communications problem created the lapse in planning protocol.
Two of the control houses being refurbished are “vintage 1950” and still use some of the original equipment, including analog meters and electromechanical relays.
Woodpecker Woes on 345-kV Lines in Eastern Mass.
Woodpecker damage, pole rot and splitting | Eversource
Eversource’s Chris Soderman presented evidence of woodpecker damage and decaying support structures along a 345-kV line in Eastern Massachusetts and similar problems on the Southern Connecticut Loop, where the company will not only replace structures but install optical ground wire to enhance communications and reliability.
The company will replace with steel approximately a fifth of the 262 wooden structures along the 29-mile Northfield-to-Ludlow line in Massachusetts. The estimated $8 million cost includes installing new hardware and insulators.
Southern Connecticut Loop | Eversource
Along the Connecticut line, which runs about 38 miles, Eversource will spend an estimated $68 million to replace 258 structures, many of which have decaying, laminated wood cross arms. Soderman emphasized that the light-duty weathering steel poles being installed on both projects were not custom ordered but off-the-shelf equipment.
National Grid Implements Reliability Scheme on Tx Circuits
Jack Martin of National Grid presented the utility’s plans to install dual high-speed protection systems on 45 major transmission circuits over the next decade to meet standards set by the Northeast Power Coordinating Council.
NPCC Directory 1 mandates that all New England transmission owners meet the performance reliability requirements on Bulk Electric System elements by Sept. 10, 2025.
National Grid will pursue a five-stage rollout and estimates the cost for Phase 1 at $1.8 million. The company expects substantially higher costs for the ensuing phases, which include significant installation of optical ground wire and a number of control house rebuilds. The utility has started conceptual engineering for the other four phases and will update the PAC once it has estimated the costs.
CAISO last week proposed to eliminate from its Tariff an annual state transmission concept plan that it says is obsolete because of changes at the federal level.
The move has support from Southern California Edison and the California Office of Ratepayer Advocates (ORA).
CAISO has developed the Statewide Conceptual Plan each year since 2010 as part of its lead role in the California Transmission Planning Group (CTPG), the transmission owner and operator group once responsible for coordinating local and regional planning across the state under FERC Order 890.
But since the implementation of FERC Order 1000 — the federal process that supersedes the previous planning process — the CTPG is no longer operating, and utilities have generally stopped responding to CAISO’s conceptual plan.
“There is little if any value in the ISO alone developing the conceptual statewide plan, and it detracts limited ISO resources from focusing efforts on the extensive and important planning activities they must otherwise undertake,” CAISO said in its draft proposal.
CAISO Says the Annual Conceptual Transmission Plan is Obsolete | Berkshire Hathaway Energy
The planning process under Order 1000 now covers regional and interregional planning, and the CTPG has not held a meeting in four years, has none scheduled and has no chairperson. The ISO Tariff still requires the grid operator to develop the plan to determine transmission requirements to meet reliability, economic and public policy needs.
SCE, the state’s second largest investor-owned utility, said it “concurs with the proposal’s conclusions and the recommendation to remove the Conceptual Statewide Plan from the California ISO Tariff.”
ORA agreed that the conceptual plan “no longer serves its intended purpose” but said the impact of eliminating the plan should be evaluated after the completion of the next interregional transmission planning process. It should be determined whether the revised process adequately incorporates California’s specific transmission needs into interregional plans, the agency said.
Order 1000 identified CAISO as a planning region with Pacific Gas and Electric, SCE and San Diego Gas & Electric as members. Other participants in the conceptual plan are now associated with WestConnect as a planning region.
“Absent the active participation of all statewide planning entities in developing a conceptual statewide plan, development of the plan amounts to little more than a unilateral ISO exercise,” CAISO said.
The ISO is asking that stakeholders submit comments on the final draft proposal by June 29.
WASHINGTON — A decade of mandatory standards has improved the grid’s reliability, but it’s time for regulators to prune unnecessary rules, speakers told FERC on Thursday.
At its annual technical conference on reliability, the commission delved into the weeds on compliance enforcement, gas-electric coordination and cybersecurity (AD17-8).
NERC received accolades from many who spoke at the conference for its continual improvement of the grid’s reliability; its transparency and coordination with other stakeholders; and its Reliability Assurance Initiative, a risk-based approach to compliance enforcement approved in 2015 that allows facilities to self-log minor violations — and NERC to focus on the most serious issues. The initiative also included the creation of Inherent Risk Assessment (IRA) profiles for facilities, which help NERC decide what standards to focus on.
FERC’s conference came days after the 10th anniversary of the first mandatory reliability standards under FERC Order 693 and a week after NERC released its State of Reliability report, from which CEO Gerry Cauley recounted some key statistics in his opening remarks. (See NERC: Despite Solid 2016, Grid Threats Remain.)
Cauley
“Bulk Power System reliability remains very high and continues to show year-over-year improvement,” Cauley said. “Industry has been very responsive to our risk-based approach and has been shifting resources to fix the most critical challenges to reliability. … These standards have had a major impact on reducing risk. Over time, we’ve seen a dramatic decline in the number and severity of compliance violations.”
But Cauley and many other panelists said it was time for another “Paragraph 81” process, referring to a provision in the commission’s March 2012 approval of NERC’s Find, Fix, Track and Report process that directed the organization to identify requirements that do little to protect reliability and could be removed. FERC ended up approving the retirement of 34 such requirements (RC11-6, et al.).
“It may be time to focus again on streamlining the requirements to ensure the investment in compliance is commensurate with the reliability gains,” Cauley said.
Risk-Based Approach
Speaking on behalf of the Large Public Power Council, Steven Wright, general manager of the Chelan Public Utility District in Washington state, wanted to go a step further. The risk-based approach hasn’t reduced Chelan’s documentation requirements: Of the 1,236 requirements and sub-requirements applicable to the utility, only four qualify for self-logging, Wright said.
He suggested that entities be granted waivers from certain standards if the IRA indicates their implementation of them doesn’t affect the grid.
Cauley disagreed with that idea, calling it an “optional menu.” NERC’s Regional Entities “legally have the discretion today to monitor and enforce whichever standards we feel suit an individual entity. And that’s really the purpose of the Inherent Risk Assessment. … I think the regions could do a better job of explaining that and explaining what could be looked at.
“But I don’t think it makes sense to take a North American set of standards and create sort of a little checklist matrix for each entity. The standards are the standards.”
Wright also suggested that there be more incentives for entities’ standard compliance, which Commissioner Colette Honorable pushed back on.
“I have a 16-year-old daughter, and she gets good grades. But I think she could get better grades,” she said. “So do I reward her for … getting the grades she should be getting anyway?”
Wright did not directly respond to the question of carrot vs. stick, but he made clear he felt LPPC’s members haven’t gotten enough “bang for our buck.”
“We are spending a lot of money” on IRAs and Internal Controls Evaluation, another RAI component, he said. “And I think it’s a good thing because we’re improving reliability, but if we can find efficiencies we should get them.”
‘Special Assessment’ on Gas Dependence
Acting FERC Chair Cheryl LaFleur asked what the commission or NERC should be doing to account for the increasing reliance on natural gas pipelines for baseload power. She pointed out that FERC has no jurisdiction over the reliability of natural gas pipelines (which belongs to the Transportation Department’s Pipeline and Hazardous Materials Safety Administration), but it does have jurisdiction over those who burn the gas.
LaFleur
“Should we be changing our planning standards in some way to take that potential loss of the pipeline into account or the gas storage” site? she asked. “Aliso Canyon brings that into the front of the discussion.”
Cauley responded that NERC is working on a special assessment report on the issue. The organization has been analyzing key pipelines and storage facilities and the potential impact of losing them on the grid.
“It will be clear from this report, I believe, that you should be planning for the loss of a most critical, most impactful facility, including if it’s on a gas system,” he said. “I am concerned that you have certain reliability standards and expectations on an electric system and what I consider a foundational piece — the fuel deliverability piece — doesn’t have an equivalent.”
Hoffman
Patricia Hoffman, acting assistant secretary of the Energy Department’s Office of Electric Delivery and Energy Reliability, suggested that grid operators do assessments to determine how dependent regions are on one fuel source.
Cybersecurity
The threat of cyberattacks took up a sizeable portion of the daylong conference.
NERC Chief Security Officer Marcus Sachs revealed that the organization had only learned about the most serious threat to date — malware known as CrashOverride — days before it was made public by two cybersecurity firms earlier this month. The program, which can control circuit breakers via supervisory control and data acquisition (SCADA) systems, was used last December to briefly cut power to about one-fifth of Kiev, Ukraine. (See Experts ID New Cyber Threat to SCADA Systems.)
Sachs recounted that NERC learned of CrashOverride on the afternoon of Friday, June 9. ESET, a Slovakian antivirus software provider, had contacted Maryland-based Dragos, asking it to review its findings before it publicized them on Monday. Dragos then contacted NERC, which worked over the weekend reviewing ESET’s work and producing a report. Dragos also produced its own report over the weekend.
Sachs
“If we didn’t have those public-private partnerships already existing, we would have failed that weekend, and you would have had a huge media splash on Monday morning that none of us would have been ready for,” Sachs said.
Many experts believe hackers based in Russia are behind the attacks on Ukraine, which Sachs said has been under “relentless assault” for the past couple years: Banking, railroads and Internet service providers have all experienced disruptions.
But while everything points to Russia, it is also possible individuals posing as Russians are behind the attacks, Sachs said.
Speaking to RTO Insider, Sachs pointed to the Solar Sunrise incident in 1998, in which two teenagers from California attacked Defense Department systems and led the military to believe they were from Iraq. “Just because it looks like a duck, smells like a duck, quacks like a duck — it may be a moose,” he said.
There was considerable discussion about understaffing at the entities responsible for protecting against cyber threats. Many agreed that the supply of qualified cybersecurity workers is too small to meet the very high demand.
Scott
“At the state level, we’re generally not staffed for this type of thing,” New Hampshire Public Utilities Commissioner Robert Scott said. “We don’t have the expertise.”
“The electric utility, 30 years ago, was the place to go to out of college,” said Greg Ford, CEO of Georgia System Operations, a cooperative that provides power to half the households in the state. “Today it’s harder and harder to lure those college students.”
“It’s easier to find individuals who are familiar with cybersecurity when it comes to traditional [information technology] and Windows-based infrastructure,” said David Ball, director of AEP Transmission Dispatching. “The more difficult skill set to find today is … a power-based background” and familiarity with SCADA.
“People with these type of skills are very marketable and they’re very mobile,” Scott agreed. “At the state level, we can’t hope to attract those type of people.”
Honorable
Sachs pointed out, however, that middle and high schools are increasingly sponsoring competitive cybersecurity exercises and students are competing in “hack-a-thons.”
“This is good news,” he said. “And it’s something we need to leverage. … Getting into cybersecurity is absolutely what we want these young kids to do.”
“All I can say to that is ‘Amen,’” Honorable replied.
BRANSON, Mo. — The MISO Nominating Committee has waived Board of Directors term limits and unanimously voted to allow current Director Baljit Dail to stand for an additional term, board Chairman Michael Curran said last week.
Dail, who this year reached the board’s limit of three three-year terms, will be included on a slate of qualified candidates being prepared by consulting firm Russell Reynolds.
With five first-time directors added since 2015, the veteran agreed to seek re-election for an additional three-year term, but that required the waiver. (See “Committee Could Lengthen Board Member’s Tenure,” MISO Board of Directors Briefs.)
Curran said the committee approved the waiver with an understanding that it should be used sparingly.
“Only in very unique situations should we hand out a waiver. It’s not something that we should use all the time,” Curran said at a June 22 board meeting. The committee cited Dail’s much-needed information technology experience as the reason for the waiver.
The board is unlikely to confront another waiver situation within the next six years based on the terms of current directors, Curran said.
The terms of Thomas Rainwater and Paul Bonavia also expire at the end of this year, but neither have reached the term limit and both will seek re-election.
At the June 21 Advisory Committee meeting, Wisconsin Public Service’s Chris Plante said retaining Dail for an additional term can help educate MISO’s newer board members and keep valuable institutional knowledge in the board.
“This should not be seen as a routine thing,” cautioned Arkansas Public Service Commissioner Ted Thomas.
MISO expects to finish the year 1.2% over budget, Chief Financial Officer Melissa Brown said during a quarterly finance report to the board.
Year-to-date, MISO is $1.5 million under budget, mostly because of late start times on projects and delayed employee travel, according to Brown. The RTO will also save about $1.1 million during the year, in part because of the cancellation of a forward capacity market in retail-choice areas. Still, that savings will be erased by a lower-than-expected employee vacancy rate, resulting in an unexpected $1.5 million spend.
| MISO
Brown expects the unusually low vacancy rate will persist for the remainder of the year. That, coupled with unforeseen expenses related to upgrading IT systems and miscellaneous overages, could push spending to $241.4 million, against the 2017 budget of $239.1 million. However, expenses could range anywhere from $238.8 million to $241.9 million.
Curran said the RTO should be able cover the forecasted overages with reductions in other spending. “We’re hopeful that we can dial that in with six more months to go,” Curran said, adding that savings shouldn’t come at the expense of project progress.
With labor costs comprising about 60% of MISO’s annual budget, it will be difficult to find cuts that don’t impact labor, Brown said.
Director Todd Raba also requested that the RTO make up the overage with other cutbacks.
Additionally, MISO has so far spent about $15.1 million of its $29.9 million capital budget, which should leave spending on target by year-end, according to Brown.
ALBANY, N.Y. — New York lawmakers last week unanimously passed a measure requiring the state’s Public Service Commission to set targets to increase the adoption of energy storage in the state through 2030.
The new law requires the commission to work with the New York State Energy and Research Development Agency (NYSERDA) and the Long Island Power Authority to set targets and develop a storage deployment program.
“This newly passed bill gives New York’s PSC clear direction: set a storage target and design a deployment program by the end of 2017,” said Anne Reynolds, director of the Alliance for Clean Energy New York. “This is a great signal to the storage industry that New York will be a promising place to invest. But first we need Gov. [Andrew] Cuomo to sign it into law.”
The Energy Storage Deployment Program bill combined Assembly and Senate measures sponsored by Assemblywoman Amy Paulin and Sen. Joseph Griffo.
Both sponsors of the legislation pointed to enhanced reliability of the electric grid as a top benefit of increased use of energy storage, as well as the jobs expected to be created.
A NYSERDA study earlier this year found that about 4,000 workers were employed in the state’s energy storage industry by the end of 2015, up 30% since 2012. The study projected the state’s industry could grow from about $1 billion in revenue to up to $8.7 billion in 2030, with the number of jobs possibly exceeding 25,000.
EOS Energy Storage Project | EOS Energy Storage
“Storage also increases the resiliency of the electric grid by supplying power in the event of an electrical outage. The creation of an energy storage deployment program will increase the installation of energy storage systems throughout the state and accelerate these benefits,” Paulin said in a statement after the bill’s passage.
Setting Targets
Because energy storage is applicable to so many electricity grid functions, a narrow focus on one area fails to capture the complete value of the technology, according to Dr. William Acker, director of the New York Battery and Energy Storage Technology Consortium.
“By analyzing the system as a whole and setting targets, you’re able to create a situation where the energy storage can be adapted into a variety of different applications,” Acker said. “That will open up the markets and lead to penetrations that are far greater than the targets that will have been set. The energy storage industry has made rapid technological advancement over the past few year, but equally important, the costs have dropped dramatically in terms of both the technology and the scale of production.” (See Storage Technology Still Outracing RTO Metrics, Rules.)
Reynolds said her group looks forward to working with the PSC to create a workable program and targets.
Eos Aurora® 1000-4000 Energy Storage | EOS Energy Storage
“Since it is up to the PSC to determine the specific target by the end of December, industry members do not yet know what impact this could have,” Reynolds said. “New York’s ambitious renewable energy mandate is 50% by 2030. Technically speaking, we do not absolutely need storage to get there, but it can be an excellent complement to increasing renewables deployment and boosting overall system efficiency.”
The state’s Clean Energy Standard, part of Cuomo’s Reforming the Energy Vision initiative, mandates that 50% of electricity generation come from renewable resources by 2030.
New Commissioners on PSC
The Senate on June 21 approved NYSERDA CEO John Rhodes to serve on the PSC, along with former state Sen. James Alesi and Philip Wilcox, an official with the International Brotherhood of Electrical Workers, a union that represents power plant workers. Cuomo has named Rhodes as chair of the commission.
The Senate also reconfirmed Diane Burman for a second six-year term as commissioner after her current term ends next February. The term of Gregg Sayre, who has been serving as interim chair of the commission, also ends next year.
BRANSON, Mo. — A proposal to detach the appointment of MISO’s Steering Committee leaders from the election of the RTO’s Advisory Committee has been put on hold until late July.
The RTO’s Stakeholder Governance Guide currently calls for the vice chair of the Advisory Committee to serve as chair of the Steering Committee and vice versa. (See “MISO May End Automatic Steering Committee Leadership Posts,” Organization of MISO States Board of Directors Briefs.)
“Today, the Advisory Committee elects the Advisory Committee chair and vice chair, and then by way of peculiarity, they do a flip-flop” to lead the Steering Committee, Entergy’s Matt Brown said during a June 21 Advisory Committee meeting.
Representing MISO’s Transmission Owners sector, Brown proposed a sector email ballot to change the practice. The motion asks that “nominations be solicited annually for the Steering Committee chair and vice chair positions” and that the posts be open to any interested stakeholders. Elections would be decided by the Advisory Committee via sector vote.
Still, a majority of stakeholders in attendance voted to table the motion until the committee’s next conference call on July 26.
Brown said the current Advisory Committee chair and vice chair ― Manitoba Hydro’s Audrey Penner and NRG Energy’s Tia Elliott ― should be able to fulfill their current Steering Committee terms until the end of the year to avoid a leadership shake-up. The motion asks for elections to begin in 2018.
“It’s not the most important issue facing MISO now,” Brown admitted. “However, it’s important to the MISO Transmission Owners.”
Brown said sectors should vote to end the “unusual” practice of automatic leadership and move to “a more conscious choice.”
“This has absolutely nothing to do with the people that currently hold these roles,” Brown said. He recommended the vote to help the Steering Committee attain a level of independence from the Advisory Committee that is “impossible to achieve today.”
Elliott asked if the proposal was aimed at “fixing” something specific that the Steering Committee failed to address.
“This is not anything specific,” Brown replied. “This is not about any actions or decisions of the Steering Committee or any actions or decisions of its current leadership.”
Northern Indiana Public Service Co.’s Paul Kelley said the move was simply a response to a request by MISO Director Thomas Rainwater at the last Advisory Committee meeting to identify attainable stakeholder process improvements.
MISO Stakeholder Relations staffer Alison Lane said the Steering Committee’s dependent leadership posts were created about eight years ago with the Steering Committee itself. At the time, it was viewed as a “cohesive way” to coordinate with the Advisory Committee.
“That’s based on an eight-year-old memory,” Lane said after a beat.
WASHINGTON — A key natural gas trade group released a study Thursday that contends it is not fuel diversity but the presence of “reliability attributes” that policymakers should seek for the good of the grid.
And how does natural gas-fired generation fare on that report card? Very well, thank you.
The study, done by The Brattle Group for the American Petroleum Institute, concludes that gas-fired generation is “relatively advantaged” in all but one of the 12 attributes it identified, which included the ability to provide ancillary services, fuel security and proximity to load. Gas excelled on every measure except for storage capability.
| API/Brattle Group study
The next best alternative source was pumped hydro with 10. Nuclear and coal, the potential beneficiaries of policies favoring traditional “baseload” generation, fared far worse at five and four respectively, as did wind (one) and solar (two).
Ancillary Services’ Growing Importance
The report calls for RTOs and ISOs to further develop markets for ancillary services, which it said are becoming increasingly important because of the rising share of intermittent renewable generation.
“Policy and market design had not focused on ancillary services until relatively recently. After the provision of energy, generation resources historically had the capability to provide more ancillary services than systems required,” the report says. “Renewables increase the uncertainty and variability in net load and make ramps larger, thereby increasing the ancillary service requirements. In addition, higher renewable penetration depresses energy market prices. This reduces margins earned by resources in the energy market and increases the need to compensate resources for the ancillary services they provide.”
In a press briefing, API Chief Economist Erica Bowman said her organization wants “to push back against” state policies that seek to maintain coal and nuclear plants “at any cost.” API absorbed the smaller America’s Natural Gas Alliance (ANGA) in 2015.
API and its affiliates have been “100% against” policies providing state-backed funding streams for nuclear plants, spokesman Mike Tadeo said.
API said the report was not ordered to counter Energy Secretary Rick Perry’s grid reliability study, which critics have said is designed to benefit coal and nuclear generation. Bowman added, however, that she hoped the Energy Department researchers “use [the findings] as a resource.”
Perry told a House Appropriations subcommittee Tuesday that the report would be released by the end of June, but a department spokesperson said later it would not be ready until July.
Beyond the Reserve Margin
Bowman said grid operators’ traditional reliance on reserve margins — the difference between installed capacity and peak load projections — is no longer sufficient.
“In reality — and NERC has also talked about this — that needs to transition to looking at these other attributes as well,” she said.
Most of the grading on the 12 attributes is likely to be uncontroversial. Also included in the list were generation capability; dispatchability; start times; ramp rates; inertia; frequency response; reactive power; minimum load level; black-start capability; and proximity to load.
But Brattle’s description of gas as “relatively advantaged” regarding the security of its fuel supply supply — along with coal, nuclear and pondage hydro — may come as a surprise to officials in PJM and ISO-NE, which have been encouraging gas generators to add dual-fuel capability. Gas generators can lose their access to fuel during winter peaks, when heating load with firm contracts takes precedence.
The study concedes that — unlike coal and nuclear fuel — “natural gas is rarely stored in large quantities on site,” adding “some natural gas-fired plants have the capacity to burn distillate oil stored in tanks on-site in the event of a natural gas supply interruption.”
It also acknowledges that gas supplies “can be interrupted due to a lack of capacity when demand is very high” — singling out New England’s pipeline capacity constraints — but says “firm supplies have very low probability of interruption.”
| PJM
Unmentioned in the study is that many gas-fired plants have interruptible contracts because operators say firm pipeline contracts are too expensive.
In its 10-K report for 2016, Calpine — North America’s largest operator of natural gas-fired power plants — warned investors that pipeline constraints “could interrupt the fuel supply” to its plants in PJM, although “some” have dual-fuel capability.
Brattle defended the omission, saying the paper was about compensating units for their reliability attributes, not about the cost of interruptible contracts. “The authors note that cost and environmental attributes may also affect market design. This paper focuses solely on reliability attributes and on the appropriate principles for compensating resources that provide those reliability attributes.”
‘A Lot of Affordable Gas’
Bowman rejected the idea of maintaining coal and nuclear plants as a price hedge in case gas prices rise from their current lows, insisting that the addition of natural gas and renewables has resulted in the most diverse generation fuel mix in history.
She cited a 2016 study by IHS that said the U.S. has 1,400 Tcf of natural gas recoverable at $4/MMBtu — a two-thirds increase over 2010 estimates. The U.S. consumed 27.5 Tcf in 2016.
“There is a lot of affordable gas out there,” she said. “So I guess the real question is how much are you willing to pay for that hedge? I would argue that that would be a lot higher than looking at where natural gas resource affordability is today.”
Wind, Nuclear, Coal Groups Respond
Two competing trade groups weighed in with responses to the API/Brattle study.
“Decades of engineering experience demonstrates that a reliable electricity system needs a diverse portfolio of generation technologies, including nuclear and natural gas,” said Maria Korsnick, CEO of the Nuclear Energy Institute, in a statement. “A close reading of the Brattle study reinforces the conclusion that grid reliability would be hopelessly compromised without nuclear energy, and we’re at a loss to explain why API is advocating such a risky scheme.”
Michael Goggin, senior director of research for the American Wind Energy Association, the API-Brattle Group report findings are “largely consistent” with those of the Analysis Group in a report recently commissioned by AWEA. “Both reports conclude that the increasingly diverse grid, with the addition of renewable and natural gas generators and the services they provide, is operating reliably and, importantly, that markets are the preferred way to ensure the grid continues to secure the services it needs to remain reliable at the lowest cost to consumers. Notably, neither report finds that ‘baseload’ itself is a grid service necessary for reliability.”
Goggin disputed Brattle’s designation of wind as “relatively disadvantaged” in frequency response, saying wind turbines “can provide frequency response that is an order of magnitude faster than conventional power plants, and today are meeting a large share of ERCOT’s need for frequency response when system frequency is high.” He also said wind and solar plants “have excellent ability” to regulate reactive power — a characteristic Brattle rated as “neutral” — and said the report failed to grade the ability to ride through voltage and frequency disturbances. “Had API examined this, it would have found that wind plants, … thanks to their power electronics, far exceed the capability of conventional power plants to remain online following a grid disturbance,” he said.
“Though the API-Brattle report’s generation assessment downplays the significant reliability capabilities and contributions of modern wind turbines, we believe the commonalities between the reports are more notable,” Goggin said.
Paul Bailey, CEO of the American Coalition for Clean Coal Electricity said “backing up more renewables with new natural gas-fired generation will not solve” the challenges facing the grid. “First, natural gas would have to be available at all times to back up more renewables. However, a significant fraction of natural gas supplies for electricity generation is based on non-firm contracts, which means there is no guarantee that gas will be available all the time. For example, approximately 40% of the gas is supplied under non-firm contracts in PJM and MISO.”
Bailey said increased natural gas could make the grid less resilient. “On the other hand, coal plants are fuel secure because there is a large supply of coal (an average of 90 days) at each plant,” he said. “This is why FERC should adopt regulatory changes that properly value attributes, such as on-site fuel storage, that enhance grid resilience.”
Power producers could temporarily suspend the operations of unprofitable generators not needed for system reliability under a CAISO plan released this week.
The Temporary Suspension of Resource Operations straw proposal, released Wednesday, would allow a plant owner to temporarily take a money-losing generator out of the market short of the “mothball” and retirement procedures already spelled out in the ISO’s Business Practice Manuals. (See CAISO Initiative Could Toss Lifeline to Struggling Generators.)
The proposal stipulates that a resource owner must manage a suspended resource in such a way that it can retain the same megawatt rating and ramping capability as before the shutdown. Any plants denied a request could become eligible for payment under CAISO’s capacity procurement mechanism (CPM), which currently compensates units for specific reliability needs.
While that move would fall far short of establishing a capacity market, it could provide needed financial support to gas-fired generators the ISO identifies as vital for future system needs, particularly in integrating increased amounts of renewable resources. CPM payments would be limited to four-month terms.
The proposal calls for owners to be permitted to shut down a resource for two to four months at a time, with the option to request a subsequent four-month suspension.
A unit approved for shutdown would not be required to respond to “exceptional” — or out-of-market — dispatches issued by the ISO, but it could be recalled for system emergencies, making it eligible for a CPM payment. A suspended unit would be ineligible to be counted in the ISO’s resource adequacy showing during its suspension.
The proposal would allow resources to apply for temporary shutdowns throughout the year, but they must provide notice 60 days in advance of the effective date of the suspension. CAISO, in turn, would be required to notify the resource of an approval or denial of the request eight days before the effective date.
“The ISO will assess requests on the first-come, first-served basis, and there will not be a window that resource owners would need to work around,” CAISO said.
A resource would be required to maintain all environmental operating permits while on shutdown, and it must be fully available for service on its return date, the proposal stipulates. To accommodate “unforeseen circumstances” — such as an expected loss of resources, transmission outages or extreme weather — suspended units must be prepared to return to service within 10 days of being notified by the ISO.
CAISO developed the temporary suspension proposal in response to stakeholder comments filed in a 2016 FERC proceeding over the ISO’s refusal to approve outage requests for three of four units at the 965-MW La Paloma combined cycle plant 140 miles north of Los Angeles (EL16-88).
CAISO’s initiative stems from stakeholder concerns raised during a 2016 FERC proceeding related to the La Paloma generating plant, which filed for bankruptcy late last year after being refused permission to suspend its operations in the ISO market. | Kern County, California Public Health Services Department
FERC last October agreed with the ISO’s decision to reject the plant owners’ requests because they were made for economic — and not physical — reasons.
Because the request was economic, it “did not represent an appropriate use of the outage management system as allowed by the CAISO Tariff,” the ISO said.
CAISO also denied an additional request to compensate the units by designating them as reliability-must-run resources, contending that they were not needed for reliability purposes. At the time, 42 MW of La Paloma Unit 2 were under an RMR agreement.
La Paloma filed for bankruptcy late last year, citing $524 million in debt and an “inhospitable regulatory environment.”
Although stakeholders largely agreed with CAISO’s La Paloma response, some asked that FERC direct the grid operator to amend its Tariff to allow for outages based on economic considerations — a request that the commission rejected. The ISO nevertheless committed to establishing a stakeholder process to take up the issue this year.
“Through that process, the CAISO and stakeholders will have sufficient time to consider all pertinent issues, the conditions under which economic outages should be permitted, if at all, and how economic outages would interact with other requirements of the CAISO tariff and with CAISO grid and market operations,” the ISO said.
The ISO has scheduled a June 28 call to discuss the proposal and has asked stakeholders to submit comments by July 13.
