About 97% of customers who lost power during Hurricane Irma have had their service restored, utilities and regulators reported Monday.
Parts of Alabama, North Carolina, South Carolina and every county in Florida and Georgia were impacted by Irma, which prompted what Tom Bossert, President Trump’s homeland security and counterterrorism adviser, called the “largest ever mobilization of line restoration workers” in U.S. history.
A crew from Joplin, Mo. receive their safety orientation at Tampa Electric’s staging area in Plant City. | Tampa Electric
More than 60,000 utility workers deployed from more than 30 states and Canada. Dozens of utilities — including Atlantic City Electric, AEP Ohio, Avista, Black Hills Energy, Consumers Energy, Consolidated Edison, Dayton Power & Light, Delmarva Power, Dominion Energy, Duquesne Light, Entergy, Eversource Energy, FirstEnergy, Green Mountain Power, Hydro-Quebec, Indiana Michigan Power, Jersey Central Power & Light, Kansas City Power & Light, Liberty Utilities, National Grid, Pepco, Northern Indiana Public Service Co., Pacific Gas and Electric, Texas-New Mexico Power, Toronto Hydro, and Wisconsin Public Service — reported sending crews.
As of Monday, they had eliminated significant outages everywhere except Florida.
| FPL
The Florida Public Service Commission said almost 312,000 customers, 3% of the state’s total, were still without power as of 6 p.m. Monday. Florida Power & Light had about 160,000 customers still out, down from 4.45 million. Duke Energy had almost 94,000 out, 5% of its total. Georgia Power reported 171 customers still dark as of Monday evening.
| FPL
At Irma’s peak on Sept. 11, more than 7.8 million customers were without power.
The Edison Electric Institute said work had been slowed by debris, fallen trees and downed power lines. But FPL spokesman Bryan Garner told the Palm Beach Post that the restoration was four times faster than it was following Hurricane Wilma in 2005, thanks to $3 billion in grid-hardening investments since then.
The effort included strengthening 600 transmission lines, placing more than 450 lines underground and clearing vegetation from more than 135,000 miles of wires. More than 1.2 million poles have been inspected and upgraded or replaced. Also speeding the recovery was the installation of millions of smart meters and grid devices that help detect problems. FPL deployed almost 50 drones to assess the damage.
But not all the investments worked out. About 40% of FPL’s system is underground, but uprooted trees damaged some underground lines in Homestead, south of Miami.
“One of the things you are seeing in particular with FPL’s investment in hardening their system is not that it prevented outages, but that it allowed for the restoration process to be a lot quicker and a lot safer,” EEI Executive Director Scott Aaronson told the Post.
| FPL
Even if customers paid $1,000/kWh, Aaronson said, “I still cannot guarantee that there are not going to be outages. There is no such thing as risk elimination. It is really about risk management.”
The Senate Energy and Natural Resources Committee this morning approved FERC nominees Kevin McIntyre and Richard Glick, sending them to a confirmation vote by the full Senate.
The committee voted unanimously in favor of McIntyre, a Republican tapped by President Trump to be FERC chairman, and Glick, a Democrat. The two testified before the committee Sept. 7. (See McIntyre to Senate: ‘FERC does not Pick Fuels’.)
Their confirmation would restore the commission to its full five members for the first time since October 2015, when Republican Phil Moeller left the commission. FERC was without a quorum between February, when former Chairman Norman Bay resigned, and August, when Republicans Neil Chatterjee and Robert Powelson joined Commissioner Cheryl LaFleur on the commission. (See FERC Quorum Restored as Powelson, Chatterjee Confirmed.)
On Wednesday, the commission is scheduled to have its first open meeting since January. (The meeting was moved from its normal Thursday schedule because of Rosh Hashanah.)
Also approved by the Senate committee today were Ryan Nelson, nominated for solicitor of the Interior Department; Joseph Balash, to be Interior assistant secretary for land and minerals management; and David Jonas, for general counsel of the Department of Energy. Sen. Al Franken (D-Minn.) opposed Balash. Jonas was approved 14-9 on a largely party line vote.
RENSSELAER, N.Y. — Members of NYISO’s Business Issues Committee last week discussed a recent Brattle Group report on pricing the social cost of carbon into the wholesale electricity market with the report’s principal author, Sam Newell.
Because most meeting participants had attended a public comment session on the topic during the previous week, Newell presented a summary of the report as well as a spreadsheet of modeling assumptions for a more detailed discussion. He explained that Brattle had used load-weighted average locational based marginal pricing (LBMP), proportional to state load patterns. (See NYISO Stakeholders Talk Details of Carbon Charge.)
Several people wondered whether the carbon charge would incentivize construction of fossil fuel generators — or whether the study assumed too much capacity being built in the form of gas-fired turbines.
“I don’t care what the demand reset curve says,” Newell said during the Sept. 12 meeting. “Look at what people are building: a lot of combined-cycle generators.”
Erin Hogan of the New York Department of State Utility Intervention Unit asked whether the study incorporated the effects of offshore wind on wholesale prices. Yes, was the answer, but not by 2025. One participant asked whether increased energy prices stemming from the charge might prompt large industrial users to leave the state. Although Newell was reluctant to speculate, he said an industrial user might see higher energy costs but a lower overall bill.
| The Brattle Group
“This is the crystal ball stuff,” Newell said. “We assume a third of New York State load is the biggest industrial users with sophisticated rate design capabilities and a greater ability to respond to price signals. … We can’t imagine all the ways the market might respond.”
Still, the study did not consider how increased wholesale prices might provoke industrial users to relocate.
“There’s a lot of freedom in how you allocate [carbon charge] revenues,” Newell said. “You could let the big users see the LBMP and just write them a check” to cover their increased costs from the charge. He added that the proposed $40/ton charge on carbon emissions was based on “nothing to do with electricity” but on the “worldwide harms from carbon.”
When asked why the modeled offset from renewable energy credits (RECs) was greater than that for zero-emission credits (ZECs), Newell said the ZECs can drop only by $5 and cannot go below zero, while RECs can go below zero and thus can be modeled to drop $15.
Newell thanked participants for their input and asked them also to look into the unintended consequences of a carbon charge.
LBMPs Down 29% from a Year Ago
NYISO Senior Vice President for Market Structures Rana Mukerji reported that the ISO’s August 2017 average year-to-date monthly energy cost of $35.80/MWh marked a 4% increase from a year earlier. LBMPs last month averaged $30.57/MWh, down 15% from July and 29% from August 2016.
The grid operator’s average daily sendout was 477 GWh/day in August, compared with 498 GWh/day in July and 548 GWh/day in August 2016.
August natural gas prices were lower while distillate prices were higher compared with those of the previous month. Gas prices on the Transco Z6 pipeline serving New York City averaged $2.16/MMBtu, down from $2.44/MMBtu in July but up 7.4% from a year earlier.
Distillate prices were up 17.6% year-on-year, with Jet Kerosene Gulf Coast averaging $11.53/MMBtu (up 10% from July) and Ultra Low Sulfur No. 2 Diesel NY Harbor averaging $11.65/MMBtu (up 7%).
The local reliability share was $0.12/MWh, slightly higher than $0.11/MWh in July, while the statewide share was $0.31/MWh, compared with $0.54/MWh in July. Total uplift costs, with Schedule 1 components including NYISO cost of operations, were higher than those in July.
Mukerji highlighted a section of his Broader Regional Market report, showing steps NYISO has taken to reduce the impact of potential ISO-NE policy changes on New York’s capacity market. The New England grid operator has proposed to revise the requirements for enabling “import capacity resources” to participate in ISO-NE’s Reconfiguration Auctions and bilateral transactions, a move that could increase New York capacity prices and create inefficient price signals.
NYISO last year filed proposed Tariff revisions with FERC to set the Locality Exchange Factor for capacity exports from Zone G-J generators into ISO-NE at 80% from June 2017 through May 2018, rather than use existing Tariff methodology and inputs. While FERC accepted the new methodology in January, it rejected a one-year transitional mechanism. NYISO followed up in June by filing an informational report concerning potential modifications to its rules-governing capacity exports from certain localities but does not now intend to pursue changes to the currently effective Locality Exchange Factor calculation methodology.
Updates to Tx Constraint Pricing Manuals
The BIC also approved revisions to the Transmission Constraint Pricing Manual, which will be presented to the Operations Committee for approval on Sept. 15.
| Potomac Economics
NYISO Associate Energy Market Design Specialist Jennifer Boyle proposed the changes to update the ancillary services, day-ahead scheduling and the transmission and dispatching operations manuals. Section 6.8.2 of the ancillary services manual would no longer refer to a “transmission demand curve.”
The updated day-ahead scheduling manual would include a new section (4.3.5) describing the ISO’s transmission constraint pricing logic, with sub-sections detailing the constraint reliability margin and its application to transmission facilities and the pricing logic. It also provides a table of the pricing values used.
The transmission and dispatching operations manual would see a section renamed to “ancillary service demandcurves,” with transmission demand curve references removed from the section description and table. A new Section 6.3.7 would include new sub-sections describing the same subjects being proposed for the day-ahead scheduling manual.
CARMEL, Ind. — MISO officials said last week they will consider stakeholders’ request that it seek a second extension on FERC’s deadline for introducing five-minute market settlements.
The RTO is about three months behind schedule on creating a market program to achieve five-minute settlement intervals under FERC Order 825, Chris Delk, MISO manager of market settlements, said during a Sept. 14 Market Subcommittee meeting.
Delk said implementation is delayed because needed software code cannot be written until MISO completes replacement of its settlements computer system in the fourth quarter. The RTO was slated to begin stakeholder testing of the program at the end of the year, but it is now unclear whether it will meet that deadline. MISO will release software components as soon as it can, he said.
Last month, several stakeholders asked the RTO to consider delaying five-minute settlements to give members more time to develop and test their own software changes. (See “Five-Minute Settlements Delayed?” MISO Market Subcommittee Briefs: Aug. 10, 2017.)
MISO officials responded then that FERC had already granted MISO a March 1, 2018, deadline — seven weeks later than the order’s required date — to allow time for deploying the new settlements system (ER17-778). MISO’s real-time settlements are currently based on an hourly average price, while real-time operating reserve settlements are conducted on a five-minute basis already.
On Thursday, MSC attendees voted 30-1 to urge MISO to request an additional extension from FERC. The stakeholder motion asks for the release of final business practice manuals at least four months ahead of parallel operations testing of the new settlements system. It also requests at least 12 weeks of testing before a go-live date.
“Our intent here is to gain that three-month delay back for our stakeholders,” said Northern Indiana Public Service Co.’s Bill SeDoris, who introduced the motion.
Because the RTO’s new settlement system is taking longer to go live than originally intended, SeDoris said, MISO members need time to review and adapt to the settlement rules, seek vendors to update related software and finish new coding.
Bladen said meeting those demands could delay the implementation date of five-minute settlements until next summer.
“It puts us at risk for FERC to deny a delay. The response we’ve [gotten] from FERC [thus far] is that a motion for delay is not off the table, but an unreasonably long motion of delay would be unwelcome,” Bladen said.
Bladen nonetheless agreed to take the stakeholder request to MISO management. FERC might be more amenable to MISO filing closer to the standing deadline with the explanation that it is still working on implementation, he said.
Hurricanes Harvey and Irma were very much on the minds of lawmakers and electric industry regulators last week during a House Energy and Commerce subcommittee hearing on the grid’s reliability and resilience.
The subcommittee’s Sept. 14 hearing, “Defining Reliability in a Transforming Electricity Industry,” was delayed two days following Irma’s landfall in Florida and then shortened to 45 minutes so members — who had recently approved a hurricane aid package — could take a series of roll-call votes.
FERC’s Neil Chatterjee
FERC acting Chairman Neil Chatterjee and his fellow witnesses, NERC CEO Gerry Cauley and Patricia Hoffman, the Department of Energy’s acting assistant secretary for the Office of Electricity, used their opening comments to detail the steps their organizations have taken in the restoration efforts in Texas, Florida and other southern states.
“It’s times like these that … remind us how important the reliability and resilience of the electric grid is in our lives,” said Chatterjee. “Rebuilding from these storms is going to take time. It’s important as we confront these storms and the impact they’ve had on the grid that we ensure … we can bounce back from these types of events.”
‘Modern, Dramatic Response’
Kathy Castor (D-Fla.)
While the subcommittee’s Republicans focused their questions on threats to reliability they said were posed by the changing generation mix, Florida Democrat Kathy Castor challenged her colleagues and the industry to respond to the threats posed by “the changing climate.”
Castor said a “modern, dramatic response” was needed in the face of increasingly large and violent weather events.
“These disasters are very expensive, and it is time to make a dramatic investment in a modern grid, something that is more resilient and preserves the needs of our citizens in a better way,” she said. “We have some of the brightest minds in America, and we need to put them to work, and we need to put the technology to work, whether that’s burying lines we haven’t invested in before or a greater distributed energy grid or building renewables over time.”
DOE’s Patricia Hoffman
Castor questioned DOE’s Hoffman regarding how the agency could invest in a modern grid under significant budget cuts. The department submitted a fiscal year 2018 request of $28 billion in funding, 5.4% below its FY16 levels — including a 42% cut to the Office of Electricity Delivery and Energy Reliability.
“We simply can’t cut our way and think we can address these costs and the challenges ahead,” Castor said. “I hear the [DOE] wants to be proactive on this, but I don’t know how we are going to do that when we see such tremendous cuts by the Trump administration in resilience, in research. We have to re-think that.”
“The administration has focused its FY18 budget on early research,” Hoffman responded. “We are concentrating on maximizing the effectiveness of work at the Department of Energy. We did provide a budget to Congress for FY18. We look forward to what Congress will provide back on what the department will implement as part of our FY18 appropriations.”
“You’re right. It’s back on Congress … and I hope [Congress is] listening and understanding the huge cost if we do not address this,” Castor shot back. “Look at what we’re facing already … emergency aid packages, flood insurance, rising property insurance, rising local taxes because local governments are having to raise taxes to harden [infrastructure], the loss of life. Let’s do more working together.”
NERC’s Gerry Cauley
Castor found a friendlier ear in Cauley, who said the 50 largest events to affect the grid over the last six years have all been weather related. That has led NERC to “focus on resiliency as a priority going forward,” he said.
Responding to a question from subcommittee ranking member Bobby Rush (D-Ill.), Cauley said climate change is “outside our organization” but agreed there appears to be “an increase in magnitude and severity of events, flooding and storms.”
“We have to think about that in designing our systems and how we prepare for more extremes than we have seen historically,” Cauley said. “Florida Power & Light invested $3 billion in hardening its infrastructure. The equipment that was hardened performed significantly better.”
Script Ripped Up
The hurricanes threatened to steal the script from those who had hoped the hearing on resilience — the fifth in the committee’s “Powering America” series — would provide support for struggling coal and nuclear generators.
Kevin Cramer (R-N.D.)
When it was their turn to ask questions, North Dakota Republican Kevin Cramer drilled into what he called the importance of coal generation as baseload power, while Texas Republican Joe Barton questioned whether reliability is threatened when generation is predominately renewable.
“I think the technology is there today [to ensure reliability], but it requires a lot of coordination,” Cauley answered Barton.
Chatterjee, who reminded the legislators that FERC is fuel-neutral, referred to Democratic FERC nominee Richard Glick’s confirmation hearing testimony, in which Glick said that FERC and DOE should closely monitor retirements of coal and nuclear baseload generation. (See McIntyre to Senate: ‘FERC does not Pick Fuels’.)
“I would echo those comments,” Chatterjee told Cramer. “We are going to closely watch and monitor whether or not, in fact, transitions in the grid do lead to threats to reliability and resilience, and where we would need to take steps to make sure it is met.”
Cramer asked Chatterjee how the commission will react to Illinois and New York, which are providing subsidies to preserve struggling nuclear generators, and whether the future will be “regulation by litigation.”
“I believe in states’ rights, and it is their prerogative to determine the sources of generation in their generation mix,” Chatterjee said. “When it does affect interstate commerce and potentially does have threats to reliability, FERC does have the authority to weigh in there.”
Morgan Griffith (R-Va.)
Virginia Republican Morgan Griffith, facing a ticking clock, reserved one question for Chatterjee. Griffith asked how high a priority the commission is placing on ensuring wholesale markets properly compensate the existing baseload fleet for its reliability services.
“We can walk and chew gum at the same time,” Chatterjee assured Griffith, alluding to the backlog of orders that accumulated during FERC’s six months without a quorum. “I’d say [it’s] a high priority.”
“We face a period of rapid change in the electric industry … this transition is altering our understanding of baseload power and how generating resources are dispatched,” Cauley said, citing cheap natural gas, technological advances, public policy and customer preferences as causes.
“With the appropriate policies, careful planning and strong actions, I’m confident the electricity sector will continue to accommodate these changes and enhance reliability and resilience,” he said. “Even with the changes that are already underway, the bulk power system remains highly reliable and resilient, and shows improved performance each year.”
Cauley called for ensuring reliable gas supplies as the industry becomes “increasingly dependent on natural gas” and said all generating resources should be able to support “essential reliability services.”
“Markets should incent and require all resources … and ensure those resources will respond in both normal and extreme conditions,” he said.
CARMEL, Ind. — MISO is seeking stakeholder feedback on its proposal to use a new calculation to crack down on generators that fail to follow dispatch instructions.
The proposed calculation, which comes after years of debate, will impose a “failure to follow dispatch” warning when a resource fails to move at least half its offered ramp rate over four consecutive dispatch intervals, MISO Market Quality Manager Jason Howard said during a Sept. 14 Market Subcommittee meeting. Generators are currently flagged after they deviate by more than 8% from dispatch instructions over four consecutive intervals.
MISO Executive Director of Market Design Jeff Bladen emphasized that the calculation is not yet final and asked for stakeholder suggestions.
After several months of delays, MISO said in May it was still developing software to support its effort to tighten tolerance bands on uninstructed deviations. The RTO’s Market Monitor has been recommending the project for more than five years. (See Monitor Again Criticizes MISO’s Uninstructed Deviation Rules.)
A MISO impact study using production data from May through July found that failure to follow dispatch increased from 2.4 to 6.1% under the new threshold. The study also found that the calculation reduced excessive and non-excessive energy charges by 4.4% across the MISO footprint for the three months, while Day-Ahead Margin Assistance Payment (DAMAP) disbursements decreased by 7.6% or $941,000.
MISO Market Monitor David Patton said the reduction in DAMAP payments is “huge” because it shows MISO will stop awarding make-whole payments to generators that fail to follow dispatch.
Howard said MISO now will seek feedback on the new calculation from the FERC Office of Enforcement and continue discussions with the Monitor’s staff. At an Advisory Committee meeting this spring, several stakeholders asked MISO to convene a workshop to discuss the RTO’s analysis and the possible shape of the proposal. (See “AC Prods Restart on Tighter Uninstructed Deviations,” MISO Advisory Committee Briefs.)
DTE Energy’s Nick Griffin asked if the new proposal might have “unintended consequences” by discouraging slow-ramping resources from offering in fear of being penalized.
“The goal here is to get people to offer the ramp rate that they are comfortable with and they actually can live with,” Bladen said. “We don’t want generators to offer a ramp rate that they can only meet half the time because the reality is we’re counting on the ramp. We’re counting on people to move.”
“It harms the system to provide a ramp rate that you can’t realistically meet,” Patton added. “Your offer parameters aren’t really accurate if you can’t perform to them.”
Some stakeholders expressed concern that the nearly $1 million in theoretically lost DAMAP would inordinately affect slower moving coal units.
“You’re talking about a million dollars [for] every generator [in] MISO. We’re not going to devastate anyone here,” Patton said. “There might be one or two units that are so inflexible that they might alter their offer, but that’s a good thing because we won’t be relying on flexibility that we really don’t have.”
The California legislature ended its 2017 session in the early hours of Saturday, drawing criticism for its last-minute pursuit of CAISO regionalization and for letting a 100% clean energy bill die in committee.
Assembly member Chris Holden (D) took the political heat on both the regionalization effort and SB 100, the clean energy proposal by Senate President pro Tempore Kevin de Leon that was hotly anticipated by renewable energy supporters. That latter bill died in the Assembly Committee on Utilities and Energy, which he chairs.
On Thursday, police officers guarded Holden’s office in Pasadena as a small band of protestors appeared, according to social media posts. As news spread that SB 100 had stalled, Holden was tagged on social media and actor Leonardo DiCaprio posted Holden’s phone number — and those of other lawmakers — to his more than 18 million Twitter followers.
Holden’s main vehicle to boost regionalization, AB 726, was kicked back to the Senate Rules Committee on Tuesday and would have required policy committee approval before returning to the Senate floor. Another bill containing regionalization language, AB 813, was amended by the Senate and referred back again to the Rules Committee the week before.
“It’s important to recognize that these bills did not authorize regionalization of the grid,” Holden said in a statement on Wednesday. “The bills established the next steps for the ISO to follow. But there is still more to discuss starting with the role of the legislature in review of any proposed governance structure of a new ISO. We will continue our work on the issues over the fall and likely revisit it in the second half of this two-year session.”
In an interview with RTO Insider last week, Holden said: “What we wanted to do on the regionalization piece is make sure there was legislative review of whatever came out of a committee evaluation. We wanted that committee to be unanimous. The strategy was then to move to the legislature where people who represent all parts of California had a chance to sign up and speak. It is big legislation, and we wanted to make sure everybody had a say in it.”
Both bills also contain a provision that would require California electricity sellers with more than 100,000 customers to procure “tax-advantaged” renewable generation above that required by the state’s renewable portfolio standard and recover costs from retail ratepayers. The measure is intended to encourage the development of new renewable resources within the state before the expiration of federal production tax credits in 2020.
Holden said his initial focus was on taking advantage of expiring tax credits on wind and solar and addressing concerns among geothermal producers.
“Regionalization was introduced into the conversation around the bill, which I had no problem with doing, as long as it was broken into two pieces — multiple pieces — so it’s not like ‘here’s what we’re going to do and we are cutting everybody out,’” he said.
Independent Energy Producers Association CEO Jan Smutny-Jones said that regionalization would make it easier to export excess solar energy from California and allow access to lower-cost renewables from around the West.
“Obviously, we have spent a lot of time on these issues this year. It’s unfortunate that we couldn’t quite get it out of the legislature this first year, but we look forward to working on it when we come back in January,” he said.
The ISO has allowed for more efficient use of transmission, and the same would be true with regionalization, Smutny-Jones said.
“From a market efficiency perspective, it will work a lot better,” he said. He noted that the Western Energy Imbalance Market (EIM) is working well on a regional basis, but it is only a five-minute market and does not allow day-ahead transactions like a full ISO.
In a blog post Wednesday, Natural Resources Defense Council Co-director Ralph Cavanagh said: “By not authorizing changes in how the grid is managed this session, lawmakers are delaying a prime opportunity to reduce utility bills, cut pollution and increase electric service reliability. And it wouldn’t have cost the taxpayers a dime.”
CAISO, which favors regionalization, said it had no comment.
SB 100 Fizzles, Drawing Ire
SB 100, the zero-carbon bill, widely anticipated by renewable energy advocates, faced strong headwinds, according to Holden. (See California Zero-Carbon Power Bill Advances.)
About SB 100, Holden said, “That is not going to move — there is overwhelming opposition to it. And there is not time to work that out.” He said he hopes to integrate several proposals so there is “a global fix to everything. But we are out of time.”
Labor unions, worried about the potential loss of jobs, also urged the legislature not to pass SB 100. The Coalition of California Utility Employees and the California State Association of Electrical Workers issued public statements opposing the bill, saying that the state is on the way to meeting its current renewable goals and that more information is needed on the proposal.
Legislature Passes Energy Storage Bill
The legislature did succeed in passing legislation meant to encourage the development of energy storage technology in California. AB 546, authored by Assembly member David Chiu (D), is intended to streamline the approval process for new storage installations. Chiu is chair of the Assembly Housing and Community Development Committee.
“Our future energy needs will require us to dramatically improve energy storage and increase the flexible management of electricity supply and demand,” Chiu said in a Sept. 7 statement. “California should encourage simplicity and standardization with local permits. When permitting conditions vary between cities, it can slow the industry down. Guidance that draws from best practices can help local governments standardize their processes so that the energy storage industry will grow quickly and safely.”
The bill requires the development of an energy storage-permitting guidebook by 2020 and requires cities and counties to accept electronic submissions of storage projects.
Aliso Canyon Bill Passes
The legislature also passed SB 801, introduced by Sen. Henry Stern (D), that would require publicly owned utilities in the Los Angeles Basin to support deployment of distributed energy resources (DERs) and energy storage and reduce the region’s reliance on gas-fired generation. (See Aliso Canyon Measure Clears Calif. Assembly Committee.) The bill was drawn up in response to the 2015 leak that resulted in the closure of the Aliso Canyon natural gas storage facility.
A spokesperson with Stern’s office said Gov. Jerry Brown is expected to sign the legislation.
The bill was amended to remove a requirement that investor-owned utilities make data available that would help DER providers identify solutions to increase reliability in the region. That provision that now applies only to the Los Angeles Department of Water and Power.
Also struck was language that would have required IOUs to maximize the use of demand response and other technologies in the areas affected by the well failure at Aliso Canyon.
The legislature reconvenes in January, when renewable energy interests, CAISO and other stakeholders will renew the debate over how aggressively California should pursue regionalization and further strengthen the most ambitious renewable energy requirements in the country.
SARATOGA SPRINGS, N.Y. — New York’s top regulator last week assured the state’s power producers that he would offer a steady hand in a time of dramatic change for the electricity sector.
“With me, you should expect a policy of continuity — continuity with the state’s energy policies,” New York Public Service Commission Chair John Rhodes said at the fall conference of the Independent Power Producers of New York.
IPPNY CEO Gavin Donohue introduced Rhodes by saying his group’s members are “very concerned” about New York’s natural gas infrastructure.
“The siting of natural gas pipelines is FERC’s jurisdiction, but the DEC [New York State Department of Environmental Conservation] has developed a pattern of denying water quality certificates for projects, most recently evidenced by the decision on the Millennium Pipeline,” Donohue said. (On Friday, FERC overruled the DEC, saying that by failing to act within the one-year time frame required by the Clean Water Act, it had waived its authority to issue or deny a water quality certification (CP16-17)).
Rhodes responded that his commission continues to support programs that lead to more gas customers.
“We support programs that encourage customer conversions from carbon-intensive petroleum products such as No. 6 heating oil,” he said, and when gas distribution projects “are economically and environmentally sensible, we clearly give the green light, and we have a track record of doing that.”
While about 38,000 New York customers are converting to natural gas each year, the commission doesn’t “have a lot to do with gas transmission,” Rhodes said. “That is a sister agency, principally the [DEC], but I’ll just note for the record, and it is in the record, that the state in all its agencies has been consistent in delivering … on all project proposals. Each project is based on specific circumstances and characteristics and is assessed on a series of clear, unambiguous, sometimes strict standards, appropriately strict standards having to do with environmental health and safety.”
Rational Actors
Rhodes cited the commission’s work on the Reforming the Energy Vision proceeding, the Clean Energy Standard and “the continuous matter of rate cases.”
“One could look at them as separate bundles of things … but also recognize that there is a commonality to them and to how we are dealing with them,” he said. “We’re seeking in all of these to achieve a cleaner, more cost-effective and reliable energy system.”
To achieve the state’s clean energy goals requires market actors “to commit one basic act … [to] make an investment decision,” Rhodes said. “It’s up to us — and this is the commonality, it’s up to us as the Public Service Commission … to set things up … so that those investments also serve our policy goals.”
Rhodes said that regulators can trust market actors “to act rationally … and our role is to keep the picture whole,” and that getting the transmission right is a way of harnessing the ability of the market to move toward the grid of the future.
The CES is “up and running” and the first request for proposals has been released, which, in combination with an RFP by the New York Power Authority, represents the largest procurement in New York and U.S. history, Rhodes said.
“These projects will generate 2.5 million MWh of electricity a yea r… and the response so far has been … robust,” he said.
The state has taken important first steps in pricing carbon into the wholesale energy market, Rhodes said.
“I’m told that it’s an elegant idea by certain editorial writers,” Rhodes said. “We kind of agree. The future carbon pricing policy can and must be a really effective instrument for achieving New York’s policy goals: a cleaner, more affordable energy system for the ratepayer. If we can harmonize the operations and rules of the wholesale energy markets with the state’s policy goals, we can decarbonize the state’s energy system in a better way.” (See NYISO Stakeholders Talk Details of Carbon Charge.)
PSEG Power’s Howard Fromer asked about the connection between carbon pricing and reform to the capacity market, a subject touched on slightly in the preface to the Brattle Report signed by Rhodes and NYISO CEO Brad Jones. (See NYISO Study Sees Little Cost Impact from Carbon Charge.)
The reference in the preface was intended to acknowledge that a carbon charge has consequences that “may go beyond another layer in the price tag,” Rhodes said. “We’ve got a system that works. If you perturb it, it’s going to be a different system. Make sure it works in the future, too. That’s just ordinary good housekeeping.”
John Reese of Eastern Generation asked about the many levels of REV, from the “umbrella level” to the core of the program.
“As a non-utility company without limitless resources, tracking the 46 REV-specific activities, the paper that comes through, and moving from the weeds back up a level to, ‘What does it mean in synthesis?’ … How can you help synthesize the information? … I mean, my REV reading list is waist-high,” Reese said.
“What did you do with the rest of it?” Rhodes joked, referring to the reading list. “REV’s outcome is simple. We want a system that’s more cost-effective, smarter investments, cleaner. We know it’s going to be more distributive because that’s what technology is telling us.”
REV’s regulatory proceedings “are many and complex, so there’s a complicated machine, but it’s aimed at some fairly direct, simple outcomes,” Rhodes said.
He said a “regulatorily naïve observer,” thinking about investment decisions and wanting to know where to focus attention, will eventually see a clearer picture emerge.
“I think we’re going to start getting the operational outcomes increasingly over time. … It’s on a conveyor belt that’s about to start coming out,” he said.
Indian Point and Transmission
Donohue asked Rhodes how the PSC will integrate NYISO’s study on the retirement of Entergy’s Indian Point nuclear plant into the work of the New York State Energy and Research Development Agency’s task force on the issue.
“That’s a complicated question and I’m going to give an over-simplistic answer,” Rhodes said. “The task force obviously has a broad remit, but the issues that it’s going to focus on … are relevant to the communities around the plant, so they have to do with taxes and economic development. They have to do with the site.”
NYISO’s Brad Jones addressed the issue of Indian Point’s closing from the ISO’s perspective.
“We have not yet received a completed notice of deactivation for the plant, yet we decided on Aug. 1 to go ahead and begin our reliability assessment,” said Jones. “And we do that somewhat outside our normal process for doing a reliability assessment … but we believe that, because of the significance of this unit, it’s important to study that now.”
NYISO hopes to complete the assessment by the end of this year, Jones said.
“There are a number of factors that continue to move, and we have to make assumptions, and we will have to do several sensitivity analyses around the report to get something that each of you will be comfortable with what you see,” he said.
Jones also said NYISO is wrapping up its role in developing the western New York public policy transmission line. If the grid operator’s board in October approves selection of NextEra Energy’s Empire State Line, the project will move into the state’s Article VII siting approval process. (See Public Policy Tx Project Wins Key NYISO Endorsement.)
Jones said the ISO’s work on the proposal for the AC transmission project proposed to run from upstate to load centers in New York City and Long Island will likely run into next year.
“We’re steadily in [the] process of moving the AC forward, and that’s also a significant project for the health of New York and the ability to move renewable generation around the state,” he said.
CAISO last week finalized its proposal for preventing the retirement of unprofitable power plants that may be needed for future system reliability, addressing concerns of some stakeholders about the initiative.
The ISO will discuss the draft final proposal for its Capacity Procurement Mechanism Risk-of-Retirement Enhancements (CPM ROR) initiative during a Sept. 20 call.
Pacific Gas & Electric’s Moss Landing Gas-Fired Power Plant
The grid operator altered the proposal to allow resources that currently have a resource adequacy (RA), CPM or ROR contract to apply for a CPM ROR designation — although they cannot have multiple designations at the same time. The revised plan also adjusts the deadlines for applying for CPM ROR designation and makes other changes for three different types of CPM ROR designations.
Generation owners Calpine, Pacific Gas and Electric and Southern California Edison raised questions about the plan after CAISO introduced the CPM Tariff provisions in May. The larger issue, many say, is that CAISO’s market increasingly produces negative prices from excess solar that leave generators unable to earn adequate revenue unless they have RA contacts. (See CAISO Stakeholders Question Risk-of-Retirement Initiative.)
Generation Owners Such as Calpine Express Concern Over CAISO Markets
Power sellers commenting on the straw proposal had urged changes to the program, which proposed to open two application windows each year — in April and November — for three types of risk-of-retirement designations. (See Power Sellers, LSEs Question CAISO ROR Designation.)
The latest draft provides additional detail about the reliability studies the ISO will perform to determine the need to designate generators as CPM ROR resources.
CAISO also altered the cost threshold requirement for obtaining a “Type 2” designation during the April window, rolling back a previous stipulation that a resource may not submit an ROR request for April unless its costs exceed the CPM soft offer cap. Type 2 refers to a request by an RA or a non-RA resource for designation in the calendar year following the current RA compliance year.
The updated proposal requires that a resource attest that it “reasonably believes” its annual fixed costs meet or exceed certain price thresholds.
“This requirement will help ensure that only resources that are less likely to receive an RA contract will be eligible for a Type 2 designation,” CAISO said. “This change provides an option for resources to use the April window and not have to wait until the November window to seek a designation.”
The ISO reasons that higher costs indicate that a generator likely will not be chosen as an RA resource. It said that it wants the CPM ROR payment to be based on cost of service and that the resource should be the only one that could meet an identified reliability need.
NRG Energy commented that the requirement would have meant that a resource with costs below the soft offer cap must wait until the November window. Forcing a generator to wait until November to seek a CPM ROR designation effectively negates one of the primary reasons why resource owners sought a change in the ROR process, the company contended.
The ISO also said it continues to support cost-of-service pricing to determine compensation. Most stakeholders also support that approach, although some changes were suggested.
Notable in the latest proposal is a provision that a CPM ROR designation no longer be voluntary but mandatory. Some stakeholders had wondered why CAISO would allow a resource not to accept a designation after being found necessary for reliability.
“The CAISO believes that [mandatory designation] is appropriate in circumstances where the resource has requested a CPM ROR designation, the CAISO has committed time and resources to conduct a reliability study, and the CAISO is determined that the resource is needed for reliability,” the ISO said. The grid operator said that approach is better than what some suggested — requiring a unit to shut down if it decides not to accept the designation.
The CAISO Board of Governors is due to review the CPM ROR proposal at its Nov. 1 meeting.
ARLINGTON, Va. — Even before its release last month, the Department of Energy’s grid study generated dozens of headlines because of expectations that its focus on “resilience” might provide a policy foundation for subsidizing financially struggling coal and nuclear generators.
But a month earlier, the National Academies of Sciences, Engineering and Medicine’s DOE-funded report, “Enhancing the Resilience of the Nation’s Electricity System,” went virtually unnoticed. Last week, one of the leaders of the study briefed the department’s newly reconstituted Electricity Advisory Committee (EAC) on the report, which recommended ways to prepare for “large-area, long-duration” outages.
“A lot of folks have as a primary responsibility worrying about reliability. Almost nobody really has primary responsibility for resilience,” Carnegie Mellon University engineering professor Granger Morgan, chair of the committee that prepared the report, told the EAC on the first day of a two-day meeting at the headquarters of the National Rural Electric Cooperative Association (NRECA).
The study says resilience is broader than reliability. “Resilience is not just about lessening the likelihood that these outages will occur,” it said. “It is also about limiting the scope and impact of outages when they do occur, restoring power rapidly afterwards, and learning from these experiences to better deal with events in the future.”
The DOE grid study, ordered by Energy Secretary Rick Perry, also made the distinction, saying that while “markets recognize and compensate reliability … more work is needed to address resilience.” (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Large outages are more common than one might think | The National Academies of Science, Engineering and Medicine
Morgan said one of the findings of the Academies’ report was that large-scale outages, such as those resulting from this summer’s Hurricanes Harvey and Irma and Superstorm Sandy in 2012, are more common than widely believed. Yet winning support for spending on resilience is hampered because some of the worst events imagined “haven’t happened yet,” Morgan said.
Valuing Resilience
“The loss of load probability is not equal to a willingness to pay” for resilience, commented consultant Clark Gellings, an EAC member who served on the New York Governor’s Infrastructure Commission following Superstorm Sandy.
“The willingness to pay changes dramatically once they’ve experienced something like Sandy … or the events that have happened in the U.S. in the last week or two,” he said. “The enthusiasm in the Northeast for [the integration] of central and distributed resources is much different than it is in other parts of the country right now.”
The report noted that while there have been studies of the value of electric power during outages of a day or less, “we know very little about what society is willing to pay [for] full or partial back-up service during large outages of long duration.” It called for studies assessing the value to customers of providing partial service through reduced amperage or rotating service during long-duration blackouts.
Visioning
The study encourages planners to conduct “visioning” exercises to imagine the challenges of a prolonged outage, such as what could occur following earthquakes on the West Coast or mass solar ejections in the Northeast. In Pittsburgh, where Carnegie Mellon is located, the exercise produced the realization that the city needs electricity to pump sewage over its hilly terrain, Morgan said.
“We’re not naïve. We don’t expect this will result in a sudden transformation of how we think about these issues,” he told the EAC. “But if we can’t raise the visibility of the level of vulnerability our society faces to large-scale, long-duration blackouts, then because there doesn’t seem to be anybody in charge worrying about resiliency, I think progress will be much slower,” Morgan said.
Training
The report said operators of the electric system should conduct more regional emergency preparedness exercises simulating large-scale outages.
It acknowledged that more than 100 organizations participated in NERC’s November 2015 GridEx III, the latest of its biennial “distributed-play” exercises simulating cyber and physical attacks. But it also suggested current disaster drills are insufficient, saying “the level of sophistication of attacks may continue to grow along with the number of vulnerable cyber and physical targets.” (See GridEx III Shows Vulnerability of Power Grid to Cyberattack.)
Physical Assets
Researchers called for more investment in the physical components needed to recover from a large-scale blackout. “For example, DOE, [the Department of Homeland Security] and other agencies should oversee the development of more reliable inventories of backup power needs and capabilities, like the U.S. Army Corps of Engineers’ mobile generator fleet. Investments should also go toward expanding efforts to improve the ability to maintain and restore critical services like power for hospitals, first responders, water supplies and communications systems.”
It also recommended using non-traditional sources, such as locomotive engines and hybrid and fuel-cell vehicles, for backup power and universal credentialing of repair crews loaned to storm areas by other utilities.
Smart Grid
Morgan said that the promise of a self-healing “smart grid” is far from reality because many utilities are unable to island sections of their transmission networks. Researchers also noted that despite increasing deployment of distributed generation and microgrids, “most U.S. customers will continue to depend on obtaining their power from the large-scale, interconnected electrical grid at least for the next two decades.”
Cyber Resilience
The report refers not to cyber “security” but to cyber “resilience.”
“Cybersecurity implies trying to keep the bad guys out,” Morgan explained. “But the evidence is increasingly compelling that the bad guys, in many cases, are already in and are just sitting there waiting to turn something on.” Cyber resilience focuses on responding quickly to mitigate damage and return to normal operations.
Research and Development
The study also called for more rapid implementation of resilience-enhancing technologies and operational strategies and the expansion of DOE’s research and development efforts on grid modernization, systems integration and cyber monitoring and controls, a topic that also came up at a Congressional hearing on Thursday. (See related story, Hurricanes Steal ‘Baseload’ Thunder at Grid Resilience Hearing.)
Who Should be in Charge?
EAC member and Great Plains Institute CEO Rolf Nordstrom asked Morgan whether the Department of Homeland Security or DOE should be responsible for resilience. Morgan acknowledged the report did not make a recommendation on that issue, calling only for the two agencies to “work closely” with utility operators and others. It also recommended a joint program by the National Association of Regulatory Utility Commissioners and the National Association of State Energy Officials to provide state regulators guidance on how to respond to identified vulnerabilities.
Role of EAC
It is unclear how the study, and the Electricity Advisory Committee’s (EAC’s) review of it, will inform federal policy. The committee’s mission is advising DOE on “modernizing the nation’s electricity delivery infrastructure” and implementing the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007.
EAC’s 24 members, who meet three times per year, are drawn from academia (Washington State University, Georgia Institute of Technology, Texas A&M and Ohio State), utilities (Southern Company, American Electric Power and Florida Power & Light), state and local government (Washington House of Representatives, California Public Utilities Commission and Electric Power Board of Chattanooga) and other stakeholders (ERCOT, SPP, NERC and NRECA).
It has issued more than three dozen reports since 2008, including three in 2017. DOE issues a memo each year detailing its responses to the committee’s recommendations. DOE’s six-page February 2017 memo provided responses to eight recommendations from 2016.
Wednesday’s EAC meeting also featured a presentation on the North American SynchroPhasor Initiative by project manager Alison Silverstein, a former FERC official who was also one of the authors of DOE’s grid study.
Silverstein said phasor management units (PMUs) — which provide 30 to 120 samples per second, 100 times faster than supervisory control and data acquisition (SCADA) systems — are providing real-time situational awareness and early warning of grid disturbances and failing equipment.
In addition to saving money, identifying problems before equipment fails can protect utility workers, Silverstein said. A capacitor voltage transformer can explode when it fails, sending shrapnel flying in a switching yard.
“Had we had voltage stability monitoring in 2003, we wouldn’t have had the U.S.-Canada blackout,” Silverstein said. “Had we had phase angle monitoring, we wouldn’t have had the blackout.”
| North American SynchroPhasor Initiative (NASPI)
Most of the 2,500 PMUs installed nationwide were funded by the federal government under the American Recovery and Reinvestment Act following the 2008 financial crisis.
“In the last year or two, companies are seeing so much value that they no longer have to be bribed with federal grants,” Silverstein said. “SPP is rushing to get their blanks filled in.”
But Silverstein said the value of the sensors has been undermined by the reluctance of PMU owners to share their data. “There’s a lot more we could get done if we could get good, solid data sharing,” she said.
