The American Wind Energy Association’s (AWEA) annual market report on the wind industry, released Tuesday, marks off one record achievement after another.
U.S. wind capacity grew another 8% last year, helping the industry support a record 114,000 jobs, more than 500 domestic factories and more than $1 billion a year in revenue for states and communities hosting wind farms.
Credit that to the 2020 wind-down of the production tax credit, said AWEA CEO Tom Kiernan.
But how does the end of tax credits help the wind industry if that means it becomes one of the few energy sources without some sort of tax support?
Kiernan said the 2015 extension of the PTC, which included a phased end of tax credits, provided the certainty the wind industry needed after years of on-again, off-again legislation in Washington, D.C. He said the “longer-term policy” was just what AWEA had been looking for, as it created an incentive for further investment in the industry and its technologies.
Kiernan said major turbine designers have all announced new designs, adding longer blades, newer technologies, digitization and “other factors that will continue to increase our productivity.” Noting developers have added roughly 8 GW of wind energy each year since 2015, he said he expects the growth to continue, if not increase, over the next few years.
“Because of that long-term policy, [wind] companies have been able to make investments and keep driving down costs,” Kiernan said. “After the PTCs phase off, there will probably be a softening, but because of that five-year horizon, we’ll be two to three years into our next product cycle. We still think we’ll be able to compete with solar, storage and gas.”
AWEA projects a “record amount” of wind generation to come online in the near future. It says more than 35 GW of capacity is either under construction or in advanced development across 31 states.
‘Americans Want It’
Wind energy now stands at 96.4 GW of cumulative installed capacity, more than double what it was in 2010. AWEA says the United States now has enough installed wind energy to power more than 30 million homes. According to the report, wind energy now “reliably delivers” more than 20% of the electricity produced in six states: Iowa, Kansas, Maine, North Dakota, Oklahoma and South Dakota.
Kiernan attributed the growth to corporate and industrial purchases of wind energy — 11.3 GW of clean wind energy because “Americans want it” — and utility purchase agreements.
“Fifty percent of Americans are more likely to buy products from a company that purchased wind energy,” Kiernan said, citing a Yale University poll. “Wind energy is the cheapest source of new electricity on an unsubsidized basis. Utilities are buying it because it’s clean but also affordable.”
Wind jobs by state | AWEA
To ensure the momentum continues, Kiernan said AWEA is encouraging the continued advancement of tax-abatement policies and other legislation at the state level, while asking for a focus on transmission infrastructure at the federal level.
“Our transmission grid is outdated and not built out to provide clean energy sources for the future,” he said, drawing comparisons to the interstate highway system. “We’re asking Congress to do a better job of permitting transmission, and we’re calling on FERC to do the interregional planning.”
Kiernan said transmission should be a key element in any infrastructure package Congress is working on, and it should include an element “requiring FERC to call on RTOs to do joint planning.”
“[Planning] should be done the same way and at the same time in addressing joint projects,” he said. “Connecting these different grids will allow more efficiency in connecting wind projects to the grid.”
Success in Texas
AWEA officials chose to announce its annual market report in Texas partly because Houston will be the site of its May 20-23 WINDPOWER Conference and Exhibition, billed as “the Western Hemisphere’s largest gathering of the people and technology driving wind power trends.”
But Texas is also a “living, breathing example of what’s happening nationally,” Kiernan said.
Annual lease payments by state | AWEA
AWEA says if Texas were a country, it would rank fifth globally in wind energy capacity, with nearly 25 GW of installed capacity. Texas is home to about a quarter of the nation’s wind capacity, and the 7 GW of additional projects under construction or in advanced development is more wind than all but two other states have installed.
The state’s Competitive Renewable Energy Zones transmission buildout, which connected West Texas wind farms with urban population centers, serves as a model of the type of legislation the organization would like to see nationwide.
“The Texas success story is very much an American success story,” Kiernan said.
AWEA’s 2018 market report is just the latest annual or quarterly report it provides. The report includes market rankings of major players, state-by-state details, economic and environmental impacts and assessments of power offtake, wind capacity ownership and project finance.
RENSSELAER, N.Y. — NYISO on Monday proposed using an estimated fuel cost to help determine the carbon component of locational-based marginal prices (LBMPc), while the state’s largest waste energy producer called for carbon offsets to be included in the ISO’s final carbon pricing plan.
The ISO’s fuel cost proposal is intended to improve stakeholders’ ability to estimate the LBMPc, carbon charges and credits and the carbon residual allocation. It would use the real-time LBMP divided by an estimated marginal fuel cost to provide an approximate heat rate in MMBtus, which would be applied against a “conversion factor” for calculating tons of emissions per megawatt-hour.
“We propose using the lowest-cost fuel on the system, on an MMBtu basis, given the varying costs of natural gas and oil,” Ethan D. Avallone, NYISO technical specialist, told the Installed Capacity/Market Issues Working Group.
The largest operator of New York waste-to-energy plants contends the facilities should get more generous treatment under a carbon pricing scheme because they provide a net reduction in GHGs. | Covanta
The ISO will determine the conversion factor from MMBtus to tons of carbon emissions and will post the factor and the fuel indices used, he said.
The ISO initially proposed calculating the LBMPc using a system of equations to determine binding transmission constraints and the characteristics of marginal resources, but staff found in many cases they could not solve the system of equations or could not determine a system of equations for a given market interval, Avallone said. (See NYISO Looks at Carbon Charge Tariff Impacts, Residuals.)
The new method will calculate the LBMPc in dollars per megawatt-hour by multiplying the tons of carbon emissions per megawatt-hour by the social cost of carbon.
Bias and Accuracy
“How do you determine a statewide lowest-cost fuel given the varying access to pipelines?” asked Howard Fromer, director of market policy for PSEG Power New York. “There’s quite a variation among major pipelines for natural gas prices under peak conditions.”
Avallone said one benefit of the new approach is that it captures price variations among different load zones.
Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, asked about levels of accuracy and whether the ISO is “comparing the former equations-based approach and this heat rate approach.”
“Any approach we use is going to be an estimate, so we will be looking at accuracy factors,” Avallone said.
David Clarke, director of wholesale market policy for Power Supply Long Island, was concerned about the potential for the new fuel-cost method to overstate the carbon component.
“You might end up dividing a high cost by a lower carbon component,” Clarke said.
Mark Reeder, representing the Alliance for Clean Energy New York, agreed with Clarke.
“If you’re using the lowest-cost fuel, and if it turns out the plant on the margin is really using a higher-cost fuel, then you would be overstating the carbon component,” Reeder said. “This method seems a bit biased toward the high side. I recommend the NYISO, when judging the quality of any approach, give significant weight to the goal of a lack of bias and not just to the goal of accuracy. There is often a tradeoff between these two goals.”
Sample LBMPc calculation. | NYISO
In the NYISO market, certain carbon-free resources able to store energy structure their bids to achieve schedules during the most profitable periods of the day. When energy prices are low, the bids from such resources include an estimated opportunity cost of profit relative to intervals with higher prices.
“The proposed LBMPc methodology we just walked through will incorporate carbon adders that are the result of bidding opportunity costs,” Avallone said, noting carbon-free opportunity cost resource bids are also likely to increase as a result of carbon pricing in some hours.
He also said internal generators would be charged for carbon based on their actual emissions — not the LBMPc — and the LBMP used to calculate LBMPc will include the impact of resources’ bidding opportunity costs when such resources are marginal, making any additional adjustments unnecessary.
Referring to an instance when a California gas-fired generator installed batteries as part of its facility, Couch White attorney Kevin Lang, representing the City of New York, asked how NYISO’s carbon pricing would impact carbon resources able to store energy.
“I think you’d have the same treatment … the LBMP would still incorporate the costs of that generator,” Avallone said.
Reeder said he found the ISO approach “an elegant way to determine opportunity costs.”
Waste to Energy
Michael E. Van Brunt, director of sustainability for Covanta Energy, which owns or operates most of the state’s waste-to-energy (WTE) plants, addressed a different challenge his industry faces regarding the carbon pricing scheme.
New York’s 10 WTE plants employ nearly 1,400 people and convert 3.2 million tons of solid waste per year into electricity, with a combined installed capacity of 285.1 MW. Van Brunt said while New York state policy values WTE over dumping in landfills, the facilities do not qualify for renewable energy credits under the Clean Energy Standard (CES) appendices, while landfill methane conversion does.
Landfills are required by state law to capture methane beyond a certain volume and use it to run generators. The latest figures from the state’s Department of Environmental Conservation show landfill methane generated 782,500 MWh of electricity in 2015.
In the voluntary emissions market, the WTE industry generates and sells offset credits from new capacity but “faces a significant penalty under the current NYISO proposal that will directly impact communities using WTE,” Van Brunt said, displaying a slide that shows the industry in New York having a net greenhouse gas factor of -0.8 ton CO2/MWh.
“I think a rational carbon pricing policy has to account for carbon offsets,” said Clarke.
Nicole Bouchez, the ISO’s principal economist, said state policy is “conflicted to some extent” and the CES does not cover WTE, requiring NYISO to have state approval to exempt WTE facilities from carbon pricing.
“The ISO plays an important role as arbiter on policy, and, in this case, where there are policy distortions,” its voice could count, Van Brunt said.
“Are you looking to be held harmless, as if the [carbon] program didn’t exist … or do you want to keep all the incremental revenue from carbon pricing?” asked Fromer.
“We look for equal treatment with landfills from the state,” Van Brunt said. “If landfills are going to be exempted, so should WTE.”
Bouchez said the ISO will soon announce a date for a second presentation by Analysis Group, which last month revealed the outline of a new study to provide additional insight into pricing carbon in NYISO’s wholesale electricity markets. (See Analysis Group Presents NYISO Carbon Pricing Study Plan.)
NYISO’s Board of Directors on Monday selected two 345-kV transmission projects intended to address persistent transmission congestion in New York and foster delivery of renewable energy to the state’s population centers.
The projects — part of the broader AC Public Policy Transmission Project — address transmission capacity at the Central East (Segment A) electrical interface and Upstate New York/Southeast New York (UPNY/SENY or Segment B) interface.
“The projects will add the largest amount of free-flowing transmission capacity to the state’s grid in more than 30 years,” the board said in a statement.
The board in December issued a mixed decision on project selections made by NYISO’s Management Committee. The MC — along with ISO staff — had backed two joint proposals by North America Transmission (NAT) and the New York Power Authority. (See NYISO MC Supports AC Transmission Projects.) Cost estimates for both projects ranged from $900 million to $1.1 billion.
New York’s AC Public Policy Transmission projects are intended to relieve congestion in key corridors. | NYISO
But while the board accepted the committee’s recommendation for Segment A, it switched Segment B to a competing proposal by National Grid and New York Transco. (See NYISO Board Partially Reverses AC Tx Project Selection.)
The NAT/NYPA Central East project involves construction of a new 345-kV line from Edic to New Scotland on an existing right-of-way; construction of two new 345-kV lines from Princetown to Rotterdam; decommissioning of two 230-kV lines from Edic to Rotterdam; and related switching or substation work at Edic, Princetown, Rotterdam and New Scotland.
The National Grid/Transco UPNY/SENY project involves several different areas of focus, including construction of a new double-circuit 345/115-kV lines from Knickerbocker to Churchtown and on to Pleasant Valley; construction of a new tap of the New Scotland-Alps 345-kV line and new Knickerbocker switching station; and related switching or substation work at the Greenbush, Knickerbocker, Churchtown and Pleasant Valley substations.
The project also entails decommissioning a double-circuit 115-kV line from Knickerbocker to Churchtown and two double-circuit 115-kV lines from Knickerbocker to Pleasant Valley.
National Grid and Transco will also oversee new line traps, relays, potential transformer upgrades, switch upgrades, system control upgrades and the installation of data acquisition measuring equipment and control wire needed to handle the higher line currents resulting from the buildout. The companies also will build a new double-circuit 138-kV line from Shoemaker to Sugarloaf; decommission a double-circuit 69-kV line from Shoemaker to Sugarloaf; and perform related switching or substation work.
“The additional transmission projects selected will improve the flow of power from upstate renewable resources to meet downstate demand and enhance the reliability and resilience of the grid … will alleviate congestion, help deliver power where it is needed most and aid the state in meeting its ambitious renewable energy goals,” interim NYISO CEO Robert Fernandez said in a press release.
The projects are the second and third transmission projects to emerge from the ISO’s Public Policy Transmission Planning Process, a planning activity required by FERC Order 1000 and the state’s Public Service Commission. The PSC identified the public policy transmission needs to increase transfer capability from central to eastern New York by at least 350 MW and from the Albany region through the Hudson Valley region by at least 900 MW.
HARRISBURG, Pa. — Critics of a bill to subsidize Pennsylvania’s failing nuclear fleet on Monday advised state lawmakers to put the brakes on the proposal, saying it would distort the deregulated energy markets it worked long to build.
Glen Thomas
Glen Thomas, president of GT Power Group, testified before the House Consumer Affairs Committee that House Bill 11 upends two decades of regulatory and legislative work and wastes $12 billion in stranded costs spent transitioning to a competitive wholesale power marketplace.
“It’s an absolute competition killer,” he said. “It’s a big deal. It’s a very complicated piece of legislation … that undoes a lot of the hard work it took to get us here.”
HB 11 would create a third tier of resources in the state’s Alternative Energy Portfolio Standard (AEPS) program from which retail providers must purchase at least 50% of their electricity by 2021: nuclear, solar, geothermal and low-impact hydropower. The first two tiers of the legislation include 16 resource types with targets of 8% and 10%.
Prime sponsor Rep. Thomas Mehaffie (R) said the plan would provide consumer protections through capped pricing and the prevention of “double dipping” across programs. He estimated the bill would cost $500 million — one-eighth of the $4.6 billion in annual costs he claims would result should all five nuclear plants in the state shut down: $788 million in higher electric prices; $2 billion in lost GDP; and $1.86 billion in costs associated with carbon emissions and harmful criteria air pollutants, including SO2, NOX and particulate matter. (See Pa. Lawmakers Unveil $500M Nuke Subsidy Bill.)
Exelon will begin the four-month process of shutting down Three Mile Island near Harrisburg in June if lawmakers fail to act. FirstEnergy will retire Beaver Valley in 2021 in what the company described as a growing trend during its testimony before the committee on Monday.
Dave Griffing
“On one hand, emitting plants get to pollute for free, not bearing any of the cost of the pollution they put into the air or water,” said Dave Griffing, vice president of government affairs for FirstEnergy Solutions. “And on the other hand, 16 other forms of technology get a payment, some as high as $55[/MWh], from the federal and state government through tax credits and AEPS credits. The result is not shocking. Pennsylvania nuclear facilities and others across the country have their hands tied behind their backs and are facing early retirement.”
Critics of the plan argue there’s better, cheaper ways to reduce carbon emissions and insist that subsidizing nearly 70% of the market props up aging nuclear reactors at the expense of competition.
“This is a major shift in Pennsylvania’s energy policy from a policy that puts consumers in the driver’s seat to one that puts policymakers in the driver’s seats by dictating where their energy comes from,” Thomas said, noting he’s spent the majority of the last 15 years convincing other states to deregulate their energy markets like Pennsylvania has. “HB 11 puts the thumb on the scale for 68% of the delivered megawatts in this state if approved.”
Tom Ridge
Tom Ridge, former secretary of Homeland Security, and Pennsylvania governor from 1995 to 2001, said preserving the state’s five nuclear facilities maintains reliability. He signed the 1996 bill deregulating the state’s energy markets and allowing it to join PJM.
“I’ve always believed in a diversified portfolio,” he told lawmakers Monday. “We want competitive markets and competitive markets need multiple sources of generation. Other states are doing it because they can’t wait on the feds to do it. In five or six years, we may not have these facilities left.”
Todd Snitchler
Todd Snitchler, vice president of market development for the American Petroleum Institute, said PJM’s generation portfolio will remain balanced, even as trends shift away from nuclear energy. Last month, the Independent Market Monitor said gas-fired energy output exceeded coal in PJM last year for the first time, though sources remain relatively balanced among gas (30.9%), coal (28.6%) and nuclear (34.2%), with renewables accounting for a small but growing share of less than 3%.
“A concern about a dash to gas needs to be tempered by realities on the ground,” he said.
The committee will host a second public hearing on HB 11 in Harrisburg on April 15.
The Senate version of the bill, SB 510, was introduced last week by Sen. Ryan Aument (R). That bill differs from the House version in that it directs the state’s Public Utility Commission to set credit prices and guarantee that between 17 and 23% of Tier III sources purchased include non-nuclear suppliers, like wind and solar. (See related story, Pa. Lawmakers Introduce 2nd Nuke Subsidy Bill.)
ERCOT staff and stakeholders began the long process of implementing real-time co-optimization (RTC) last week with the first meeting of the Real-Time Co-Optimization Task Force.
The group spent its Thursday meeting reviewing ERCOT’s current market design and the changes that RTC will necessitate. ERCOT Compliance Director Matt Mereness, the task force’s chair, said it’s important to understand the elements in RTC’s high-level design principles in order to better understand what is being implemented.
“We have a mandate to implement real-time co-optimization, and we will be working to see what market functions have to be changed to enable that,” Mereness said.
RTC is supposed to efficiently coordinate the provision of energy and ancillary services (AS) in the real-time market and price AS shortages according to their defined demand curves. Its elements include: real-time market and AS deployment; reliability unit commitment; day-ahead market operations; internal and external reporting; and performance monitoring.
Implementation of the process will mean the loss of ERCOT’s supplemental AS market.
The Texas Public Utility Commission directed ERCOT to implement RTC earlier this year (Project 48540). The grid operator has said it will take four or five years and about $40 million to add RTC to the energy-only market.
Bryan Sams, director of regulatory affairs for Lone Star Transmission, is serving as the RTCTF’s vice chair. The group is composed of stakeholders and staff from ERCOT, the PUC, the Independent Market Monitor and the Office of Public Utility Counsel. The task force will report directly to the Technical Advisory Committee.
ERCOT to Ask Board for NPRR916 Changes
ERCOT will ask its Board of Directors during its bimonthly meeting Tuesday to accelerate the implementation date for a previously approved Nodal Protocol revision request (NPRR) and to change its mitigated floor offer as a result of negative gas prices.
The TAC endorsed NPRR916 on March 27. The change sets the mitigated offer floor to $0/MWh for “combined cycle” (CCGTs) and “gas/oil steam and combustion turbine” (CTs) resource categories, replacing the fuel index price-based (FIP) calculation. The change also eliminates the grey-boxed language from NPRR664.
During a Thursday webinar, staff explained that negative fuel prices at the Waha Hub coupled with mitigated floor offers are creating “irrational restrictions” for CTs and CCGTs. When gas prices are negative, a floor of zero is excessive relative to the resource’s optimal offer, staff said.
ERCOT wants to change the offer floor to -$20/MWh, aligning CTs and CCGTs with coal and lignite units’ offer floor.
Texas Natural Gas Prices | ERCOT
The grid operator also wants to move up implementation of NPRR916 from May 1 to April 10. Staff said West Texas fuel prices support the need to “make this system adjustment as soon as practicable.” The proposed change to -$20 requires modifications to ERCOT systems that would become effective upon system implementation.
The current floor for CCGTs is set at 1 MMBtu/MWh x FIP, and 6 MMBtu/MWh x FIP/FOP (fuel oil price) for CTs and gas and oil steam turbines. NPRR916 changes those numbers to a straight value of $0/MWh.
The NPRR916 changes are expected to cost less than $10,000 and will be absorbed by ERCOT’s operations and maintenance budgets, staff said.
CHARLOTTE, N.C. — There was no stated theme to this year’s Transmission Resiliency Summit, held at Electric Power Research Institute laboratories last week, but some common motifs ran through the event.
The North American Transmission Forum (NATF), headquartered less than 6 miles west of the EPRI labs, gathered representatives from utilities, RTOs, NERC regional entities and government agencies to discuss improving the resilience of the bulk electric system.
That group held its first meeting in April 2013 in the aftermath of Superstorm Sandy, focusing on severe weather events, according to NATF CEO Tom Galloway. Less than two weeks later, gunmen carried out a highly sophisticated attack on Pacific Gas and Electric’s Metcalf substation, costing the utility more than $15 million in direct costs and $100 million in security upgrades.
Galloway’s recollection of those events set the stage for two days of discussing not just the myriad threats the grid faces — and the best ways to secure the grid, both physically and digitally, against them — but also how to respond to and recover from a catastrophic event.
Last week’s summit, hosted jointly with NERC this year, was the largest NATF and EPRI have held and the first one open to non-NATF members, including the press. Andrew Phillips, EPRI vice president of transmission and distribution infrastructure, said 230 people had registered, representing more than 100 different entities from the U.S. and Canada.
The maximum capacity for the conference room: 230. And there were only a few open seats throughout the event.
“Who’s who in the zoo [are] all here,” said Brian Harrell, assistant director for infrastructure security at the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA). “No. 1, I think that’s a testament to this particular conference, and two, it’s showcasing the fact that you all are taking resilience very, very seriously.”
Speakers Stress Collaboration, Info Sharing
A constant refrain among the multiple speeches, presentations and panels was an emphasis on working together and sharing information, both between the public and private sectors, and among utilities.
“I think we really need to advocate for a collective defense: Whether you are a critical infrastructure company, whether you are a citizen of the United States or you are the U.S. government, we are all in this together,” said Harrell, a former director of the Electricity Information Sharing and Analysis Center (E-ISAC). “Your problem quickly becomes my problem. My problem quickly becomes your problem. Duke’s problem quickly becomes SCANA’s problem, which becomes Dominion’s problem, etc.”
The current director of E-ISAC, Bill Lawrence, urged attendees to join the NERC-operated program, noting the effort to improve its web-based tools in the past few years. “Basically, back in 2015, many of your organizations took a hard look at us and said, ‘Hey, ISAC, if [you want us] to use you, you gotta suck less.’”
E-ISAC benefits from the required reporting under NERC’s Critical Infrastructure Protection standards, “but we also need to get that voluntary information sharing,” Lawrence said in a presentation on measuring the program’s effectiveness. “We’re definitely not sitting on … a pile of gold in voluntary shares, but it’s growing, because our vision is to be a world-class, trusted source of quality analysis and rapid sharing of electric infrastructure security information.”
Galloway asked Lawrence if there was anything besides “‘better information sharing’ … that this audience can do to better support you in moving the E-ISAC forward.”
“Other than my catch-all — ‘share more’ — challenge us,” Lawrence answered. He encouraged members to inform the center if they found its resources were not useful to them.
Most of the first day of the event was spent discussing the incident command system (ICS). The concept was originally developed by fire chiefs in several states in the 1970s to provide a common hierarchy and standardized terms among their departments to coordinate their response to wildfires. Now it is used across multiple sectors, companies and institutions to coordinate their responses to emergencies.
“Firefighting is a team sport,” said Wike Graham, battalion chief for the Charlotte Fire Department. He recalled that Carolina Panthers Head Coach Ron Rivera, after observing firefighters put out a fire in his house, compared the incident commander to a coach. “‘They send the plays in, and you watch these guys, they all know what they’re doing and they’re working as a team.’ That’s what ICS is all about.”
An ICS determines who is in charge (the incident commander) among teams from different entities that respond to an emergency — for example, local police, FBI and the military.
“Training military guys to not be in charge is difficult,” said Taylor Cox, senior consultant for business continuity at Xcel Energy. “‘Yes, sir, I understand you were in charge in Iraq. You are not in charge here,’” recalled Cox, a former member of the Army National Guard.
Staff members from several utilities shared their experiences implementing ICS. Manny Cancel, Consolidated Edison’s chief information officer, described how his company used the system to restore power to Wall Street after the terrorist attacks of Sept. 11, 2001. Kathy Bosse, crisis manager for Exelon, said her company used the system during the civil unrest in Baltimore following the death of Freddie Gray in 2015. Others shared their experiences using the system to respond to simulated cybersecurity attacks.
Emergency Communications
The Metcalf attackers, whose motives and identities remain a mystery, cut fiber optic cables less than a mile from the substation, briefly knocking out internet, phone and 911 service in the area. “One of the things that was most troubling is that it was a very deliberate effort to impact communications,” Galloway said.
One panel at the conference focused exclusively on communications during an event in which all other methods are unavailable.
Ross Merlin of DHS gave a presentation on the department’s SHAred RESources (SHARES) high-frequency radio (HFR) program. He began by explaining how HFR works.
“It works by something called ‘PFM.’ It stands for ‘pure freaking magic.’”
Actually, it’s quite simple but, based on the audience’s reaction to the technology, no less impressive. HFR works by bouncing signals off Earth’s ionosphere, the part of the atmosphere that has been ionized by solar radiation, about 80 km above the surface.
Normally, HFR is used for communicating over very long distances. But it can also be used in cases where all short-distance comms are down.
“By using the right antenna, you can make your signal go almost straight up, which sounds useless unless you’re trying to talk to the International Space Station,” Merlin said. But once it bounces off the ionosphere, the signal comes “not just straight down, but kind of like an upside-down ice cream cone,” allowing for communication within a certain radius. Users can send not only voice, but email and images as well.
SHARES has more than 2,600 participants using about 2,300 radio stations, according to Merlin. The program used to be restricted to the federal government only, but “a few years ago we found giant loophole, I mean, we found a way to reinterpret the rules so as to allow state and local government and critical infrastructure and key resources folks to take advantage of this. … The folks you depend on, whatever you have a dependency on to keep going, we can probably get them in here.”
Several attendees representing Canadian utilities said after Merlin’s presentation that they intended to inquire about applying for the program.
Drones
The second day of the conference featured presentations on the threats posed by unmanned aerial vehicles, more commonly known as drones, both those used by utilities for maintenance and those used by the public — or hostile foreign actors.
CISA’s Harrell repeated his warnings against using foreign-manufactured drones from last month’s NERC Reliability Leadership Summit. (See Feds Late to Act on Drone Threat, DHS Official Says.) E-ISAC’s Lawrence advised the audience to “look beyond” the manufacturers from which the federal government is banned from purchasing under the National Defense Authorization Act for Fiscal Year 2019.
There have also been incidences overseas of environmentalists using drones to try to disable electric infrastructure, including one last year in which Greenpeace flew a device shaped like Superman into a nuclear plant in France.
But according to Xcel’s Cox, “nuisance drones,” piloted by careless or curious hobbyists, are the most common threat to utilities.
“A lot of them are like the kid who throws the Frisbee on your roof and just wants his Frisbee back.”
The Federal Aviation Administration has exclusive jurisdiction over what can fly where, meaning utilities that spot drones over their substations or other facilities can’t do much about them except report them. But that doesn’t mean utilities shouldn’t monitor them.
“There are a lot of physical security managers not paying attention because they say, ‘Well we can’t shoot them down anyway, so why should we care?’” Cox said in response to an audience question about what is allowed. “Well a lot of your security folks don’t have arrest authority, and yet we’re still taking pictures of people stealing copper.”
He advised utilities to leave downed drones alone: Blades can easily cut off fingers, and any sim cards could be compromised with malware.
Travis Moran of Welund North America urged audience members to submit comments on FAA’s Advance Notice of Proposed Rulemaking regarding drones, due April 15. Proposed earlier this month under Section 2209 of the FAA Extension, Safety and Security Act of 2016, the rules would allow utilities to apply for airspace restrictions over their facilities.
“2209 is your best interest right now, and you’ve got to get your lobby people off their butts on this,” said Moran, also a strategic partner with SRC/Gryphon Sensors and a member of the Energy Drone Coalition’s advisory board. “I’ve always said you guys get it because you’re already used to the CIP standards and CIP process, so electricity should be the one to lead this. … Get your people on there … or else you know how the government is going to do it. They’re doing it without your comment, and you’re not going to like what you get.”
CHARLOTTE, N.C. — There was no stated theme to this year’s Transmission Resiliency Summit, held at Electric Power Research Institute laboratories last week, but some common motifs ran through the event.
The North American Transmission Forum (NATF), headquartered less than 6 miles west of the EPRI labs, gathered representatives from utilities, RTOs, NERC regional entities and government agencies to discuss improving the resilience of the bulk electric system.
That group held its first meeting in April 2013 in the aftermath of Superstorm Sandy, focusing on severe weather events, according to NATF CEO Tom Galloway. Less than two weeks later, gunmen carried out a highly sophisticated attack on Pacific Gas and Electric’s Metcalf substation, costing the utility more than $15 million in direct costs and $100 million in security upgrades.
Galloway’s recollection of those events set the stage for two days of discussing not just the myriad threats the grid faces — and the best ways to secure the grid, both physically and digitally, against them — but also how to respond to and recover from a catastrophic event.
Last week’s summit, hosted jointly with NERC this year, was the largest NATF and EPRI have held and the first one open to non-NATF members, including the press. Andrew Phillips, EPRI vice president of transmission and distribution infrastructure, said 230 people had registered, representing more than 100 different entities from the U.S. and Canada.
The maximum capacity for the conference room: 230. And there were only a few open seats throughout the event.
“Who’s who in the zoo [are] all here,” said Brian Harrell, assistant director for infrastructure security at the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA). “No. 1, I think that’s a testament to this particular conference, and two, it’s showcasing the fact that you all are taking resilience very, very seriously.”
Speakers Stress Collaboration, Info Sharing
A constant refrain among the multiple speeches, presentations and panels was an emphasis on working together and sharing information, both between the public and private sectors, and among utilities.
“I think we really need to advocate for a collective defense: Whether you are a critical infrastructure company, whether you are a citizen of the United States or you are the U.S. government, we are all in this together,” said Harrell, a former director of the Electricity Information Sharing and Analysis Center (E-ISAC). “Your problem quickly becomes my problem. My problem quickly becomes your problem. Duke’s problem quickly becomes SCANA’s problem, which becomes Dominion’s problem, etc.”
The current director of E-ISAC, Bill Lawrence, urged attendees to join the NERC-operated program, noting the effort to improve its web-based tools in the past few years. “Basically, back in 2015, many of your organizations took a hard look at us and said, ‘Hey, ISAC, if [you want us] to use you, you gotta suck less.’”
E-ISAC benefits from the required reporting under NERC’s Critical Infrastructure Protection standards, “but we also need to get that voluntary information sharing,” Lawrence said in a presentation on measuring the program’s effectiveness. “We’re definitely not sitting on … a pile of gold in voluntary shares, but it’s growing, because our vision is to be a world-class, trusted source of quality analysis and rapid sharing of electric infrastructure security information.”
Galloway asked Lawrence if there was anything besides “‘better information sharing’ … that this audience can do to better support you in moving the E-ISAC forward.”
“Other than my catch-all — ‘share more’ — challenge us,” Lawrence answered. He encouraged members to inform the center if they found its resources were not useful to them.
Most of the first day of the event was spent discussing the incident command system (ICS). The concept was originally developed by fire chiefs in several states in the 1970s to provide a common hierarchy and standardized terms among their departments to coordinate their response to wildfires. Now it is used across multiple sectors, companies and institutions to coordinate their responses to emergencies.
“Firefighting is a team sport,” said Wike Graham, battalion chief for the Charlotte Fire Department. He recalled that Carolina Panthers Head Coach Ron Rivera, after observing firefighters put out a fire in his house, compared the incident commander to a coach. “‘They send the plays in, and you watch these guys, they all know what they’re doing and they’re working as a team.’ That’s what ICS is all about.”
An ICS determines who is in charge (the incident commander) among teams from different entities that respond to an emergency — for example, local police, FBI and the military.
“Training military guys to not be in charge is difficult,” said Taylor Cox, senior consultant for business continuity at Xcel Energy. “‘Yes, sir, I understand you were in charge in Iraq. You are not in charge here,’” recalled Cox, a former member of the Army National Guard.
Staff members from several utilities shared their experiences implementing ICS. Manny Cancel, Consolidated Edison’s chief information officer, described how his company used the system to restore power to Wall Street after the terrorist attacks of Sept. 11, 2001. Kathy Bosse, crisis manager for Exelon, said her company used the system during the civil unrest in Baltimore following the death of Freddie Gray in 2015. Others shared their experiences using the system to respond to simulated cybersecurity attacks.
Emergency Communications
The Metcalf attackers, whose motives and identities remain a mystery, cut fiber optic cables less than a mile from the substation, briefly knocking out internet, phone and 911 service in the area. “One of the things that was most troubling is that it was a very deliberate effort to impact communications,” Galloway said.
One panel at the conference focused exclusively on communications during an event in which all other methods are unavailable.
Ross Merlin of DHS gave a presentation on the department’s SHAred RESources (SHARES) high-frequency radio (HFR) program. He began by explaining how HFR works.
“It works by something called ‘PFM.’ It stands for ‘pure freaking magic.’”
Actually, it’s quite simple but, based on the audience’s reaction to the technology, no less impressive. HFR works by bouncing signals off Earth’s ionosphere, the part of the atmosphere that has been ionized by solar radiation, about 80 km above the surface.
Normally, HFR is used for communicating over very long distances. But it can also be used in cases where all short-distance comms are down.
“By using the right antenna, you can make your signal go almost straight up, which sounds useless unless you’re trying to talk to the International Space Station,” Merlin said. But once it bounces off the ionosphere, the signal comes “not just straight down, but kind of like an upside-down ice cream cone,” allowing for communication within a certain radius. Users can send not only voice, but email and images as well.
SHARES has more than 2,600 participants using about 2,300 radio stations, according to Merlin. The program used to be restricted to the federal government only, but “a few years ago we found giant loophole, I mean, we found a way to reinterpret the rules so as to allow state and local government and critical infrastructure and key resources folks to take advantage of this. … The folks you depend on, whatever you have a dependency on to keep going, we can probably get them in here.”
Several attendees representing Canadian utilities said after Merlin’s presentation that they intended to inquire about applying for the program.
Drones
The second day of the conference featured presentations on the threats posed by unmanned aerial vehicles, more commonly known as drones, both those used by utilities for maintenance and those used by the public — or hostile foreign actors.
CISA’s Harrell repeated his warnings against using foreign-manufactured drones from last month’s NERC Reliability Leadership Summit. (See Feds Late to Act on Drone Threat, DHS Official Says.) E-ISAC’s Lawrence advised the audience to “look beyond” the manufacturers from which the federal government is banned from purchasing under the National Defense Authorization Act for Fiscal Year 2019.
There have also been incidences overseas of environmentalists using drones to try to disable electric infrastructure, including one last year in which Greenpeace flew a device shaped like Superman into a nuclear plant in France.
But according to Xcel’s Cox, “nuisance drones,” piloted by careless or curious hobbyists, are the most common threat to utilities.
“A lot of them are like the kid who throws the Frisbee on your roof and just wants his Frisbee back.”
The Federal Aviation Administration has exclusive jurisdiction over what can fly where, meaning utilities that spot drones over their substations or other facilities can’t do much about them except report them. But that doesn’t mean utilities shouldn’t monitor them.
“There are a lot of physical security managers not paying attention because they say, ‘Well we can’t shoot them down anyway, so why should we care?’” Cox said in response to an audience question about what is allowed. “Well a lot of your security folks don’t have arrest authority, and yet we’re still taking pictures of people stealing copper.”
He advised utilities to leave downed drones alone: Blades can easily cut off fingers, and any sim cards could be compromised with malware.
Travis Moran of Welund North America urged audience members to submit comments on FAA’s Advance Notice of Proposed Rulemaking regarding drones, due April 15. Proposed earlier this month under Section 2209 of the FAA Extension, Safety and Security Act of 2016, the rules would allow utilities to apply for airspace restrictions over their facilities.
“2209 is your best interest right now, and you’ve got to get your lobby people off their butts on this,” said Moran, also a strategic partner with SRC/Gryphon Sensors and a member of the Energy Drone Coalition’s advisory board. “I’ve always said you guys get it because you’re already used to the CIP standards and CIP process, so electricity should be the one to lead this. … Get your people on there … or else you know how the government is going to do it. They’re doing it without your comment, and you’re not going to like what you get.”
The SPP–MISO Joint Planning Committee has voted to begin a new coordinated system plan (CSP) this year, SPP staff told the RTO’s Seams Steering Committee last week.
The JPC, composed of planning staff from both RTOs, conducted the vote in March. The CSP is the first step in determining whether to build transmission projects that address interregional needs.
SPP Interregional Coordinator Adam Bell told the SSC during its Wednesday meeting that the RTOs’ planning staffs are exchanging solutions submitted through their regional processes for the CSP “joint” needs. Staff are also finalizing a draft CSP study scope, he said.
The RTOs have not yet scheduled a meeting to share initial results with stakeholders, but they have identified six potential economic projects along the seam. (See MISO, SPP Seek Coordinated Plan in 2019.)
“We’ve identified modeling inconsistencies, but our models are always going to be different,” Bell said. “Once we posted the needs, that’s when both sides began looking into the models.”
The study could result in a first-ever interregional transmission project for the RTOs, which conducted CSP and regional reviews in 2014 and 2016. They were unable to reach an agreement on interregional projects both times.
Switchable Generation Plan with ERCOT Almost Complete
The grid operators have been working since 2016 on a new agreement to cover the four resources capable of switching between SPP and ERCOT. The plan applies only to the operations of the reliability coordinators and does not address financial obligations of the SWGRs directed to switch in emergency conditions, RTO staff said.
SPP’s Market Working Group will be responsible for developing new commitment statuses and a mechanism to uplift financial obligations of SWGRs instructed to switch to SPP from ERCOT.
Two of the resources belong to Golden Spread Electric Cooperative and have historically operated in SPP. The other two resources belong to Tenaska and operate in ERCOT.
M2M Payments Soar to $3.33M in February
SPP recorded $3.33 million in market-to-market (M2M) payments from MISO in February, the highest amount since last March and the ninth-highest since the two RTOs began the process in March 2015.
February also marked the 23rd month in the last 29 in which M2M distributions have flowed in SPP’s direction. SPP has now amassed $58.6 million in net payments from MISO.
| SPP
Permanent flowgates along the SPP-MISO seam were binding for 244 hours, and temporary flowgates were binding for 245 hours. That resulted in $1.98 million and $1.35 million in payments, respectively.
Casey Cathey, the RTO’s manager of reliability planning and seams, told the SSC that staff hope to discuss with MISO potential changes to the M2M process. “My personal view is to optimize the system for congestion, rather than this clunky process,” he said.
Having met its current carbon reduction goal ahead of schedule, Entergy now says it plans to further slash emissions over the next decade to well below levels seen 20 years ago.
In a report issued Wednesday, Entergy said it is “intensifying” its efforts, pledging to reduce its CO2 emission rate to 50% below 2000 levels by 2030. If achieved, the company would produce about 24.6 million short tons of annual emissions, compared with 36 million short tons in 2017.
The announcement was rolled into Entergy’s 2018 Integrated Report, which combines the company’s annual shareholder report with its sustainability report. The company has already surpassed its previous commitment to reduce emissions to 20% below 2000 levels by 2020.
“The broad consensus of current scientific data on climate change indicates that, as an industry, we must do more to reduce our footprint and that of our customers and communities. Entergy sees this not as a choice but as a responsibility and an opportunity,” Entergy CEO Leo Denault wrote in a letter to stakeholders. “Speaking plainly, this means that for every unit of electricity we generate in 2030, we will emit half the carbon dioxide we did in 2000.”
| Entergy
In 2018, Entergy’s utility-only CO2 emission rate was 763 pounds/MWh, lower than the national average of 1,009 pounds/MWh. The 2018 emissions rate represented a 28% reduction from 2000.
Since announcing its portfolio transformation strategy in 2002, Entergy says it’s replaced almost 30% of its older generating assets. Natural gas-fired generation now represents 60% of the company’s more than 25 GW in generating assets.
While Entergy is not releasing a supply plan, it did say the new goal could mean a supply mix that’s 60% natural gas, 32% nuclear, 7% renewable and slightly more than 1% coal.
Entergy estimates it currently has about 1 GW of renewable projects in “various stages of development.”
Denault added that Entergy’s 8.8-GW nuclear portfolio is a “critical source of safe, large-scale and virtually emission-free baseload power” that could make or break the company’s sustainability goals. Preserving the plants is crucial, he said.
Those statements come at a time when Entergy is seeking to offload two nuclear units outside its service territory to a subsidiary of Holtec International. Entergy expects to complete the sales of the Pilgrim plant in Massachusetts by the end of 2019 and Palisades plant in Michigan by the end of 2022. The sales are part of the company’s strategy to exit the merchant power business and re-establish itself as a pure-play regulated utility.
Entergy also released a separate analysis and risk assessment on climate change. The company concluded it should focus on coastal wetland restoration, renewable generation, grid modernization, emergency response, energy efficiency and electric vehicles. It also said it’s designing facilities that can withstand flooding and extreme weather events.
| Entergy
The company is simultaneously planning for load reduction, as customers invest in distributed resources, and load growth, from increased demand for cooling and refrigeration. It expects climate change impacts to be “especially pronounced” in coastal Louisiana and Texas, where risks from sea level rise, damaging storms and coastal erosion are highest. The company also predicted “potentially disproportionate” impacts for its low-income customers.
None of the four states in Entergy’s utility service territory has passed carbon emissions regulations, though Texas has a renewable portfolio standard and New Orleans has published a climate action plan aimed at halving emissions by 2030. However, Entergy predicts that a federal carbon tax will soon become a reality.
Entergy said it would hold off on making plans around any technologies it might adopt until they prove cost-effective.
“Some of the technologies viewed as necessary to reduce greenhouse gas emissions consistent with a 2-degree [Celsius] scenario do not exist today. Others currently are not commercially viable and would require significant resource investments to adopt at a scale that is cost-competitive with conventional generation resources,” Entergy said.
The company also said simply halving its total emissions by 2030 isn’t feasible. To meet a 50% net reduction in emissions by that time, the company said it would have to increase its zero-carbon generation from the current 37% of the fleet mix to nearly 55% by 2030. One analysis showed Entergy would have to add 9.8 GW of solar capacity and 5.3 GW of battery storage in order to achieve the reduction, a scenario the company deemed unrealistic.
New York officials, utilities and solar energy advocates are trading comments through the state’s Public Service Commission on what constitutes appropriate compensation for the capacity value of distributed energy resources (VDER) (Case 15-E-0751; 15-E-0082).
The comments come after the PSC in December issued a staff whitepaper regarding capacity value compensation and in January ruled that John F. Kennedy International Airport could have a solar project up to 5 MW compensated under the VDER program while having other solar projects dedicated to serving on-site load (Case 18-E-0766). (See NYPSC Clarifies Value Stack Capacity Limits.)
In the value stack white paper, Department of Public Service staff recommend replacing the market transition credit (MTC) model, a value based on installed capacity estimates, with a new “community credit” model to compensate participants of community distributed generation (CDG) projects.
The commission’s original VDER order in March 2017 directed that the state’s compensation scheme for eligible DER transition from net energy metering (NEM) to the value stack, which bases compensation on provided benefits. The PSC’s Jan. 17 declaratory ruling said, “The rated capacity of projects used solely for serving on-site load and not seeking compensation under the value stack or net metering should not be counted towards the rated capacity limit.”
Rate Design
The DPS’ Utility Intervention Unit (UIU) filed comments that addressed rate designs for post-NEM mass market customers — those with eligible on-site generation.
“The proposed rate relies in part on advanced metering infrastructure (AMI) capability, which New York utilities have not yet fully implemented,” the UIU said. “Thus, to the extent that AMI is required to participate in this rate, the proposal appears premature.”
The Clean Energy Parties (CEP) — an ad hoc group including the Solar Energy Industries Association, Coalition for Community Solar Access, Pace Energy and Climate Center, Natural Resources Defense Council, New York Solar Energy Industries Association and Vote Solar — filed comments supporting DPS staff’s recognition “that some aspects of the tariff, such as DRV [demand reduction value], were achieving a false sense of accuracy and recommends changes that will better align the financial signals sent to customers with the benefits they can provide to the distribution system.”
A 2-MW solar project at Mohawk Valley Community College was supported by a grant from the New York State Energy Research and Development Authority. | NYSERDA
The group said that for more than a year they have “made the case that the current tariff does not accurately reflect the value of distributed energy resources or provide stable enough compensation.” The state’s utilities show “a surprising misunderstanding of the development process for medium-sized to larger-sized solar energy facilities,” it said.
Utilities — including Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, Niagara Mohawk Power, Orange and Rockland Utilities, and Rochester Gas and Electric — dismissed New York City’s advocacy of a higher MTC for Con Ed as unnecessary.
In addition to the 18 MW of projects identified in Tranche 0/1 as of March 1, 2019, Con Ed’s interconnection queue contains an additional 84.7 MW of eligible projects, including 42.5 MW of fuel cell projects, the utilities said. Because fuel cells are expected to operate at capacity factors in excess of 90% and achieve a high coincidence with the DRV, they will have the same cost impact as roughly 255 MW of solar installations, they said.
Resource Eligibility
The PSC last September expanded the eligibility of DER to be compensated under the state’s value stack tariffs, particularly standalone storage systems with 5 MW or less of capacity, including crediting to any clean generation technology that qualifies as a Tier 1 resource under the Clean Energy Standard (CES).
The new rules also make resources eligible for compensation that would qualify for Tier 1 but for their start date before Jan. 1, 2015, and also authorize interzonal crediting, allowing DERs receiving value stack compensation to apply credits to the bills of customers in the same utility territory but different NYISO load zones. (See NYPSC Takes Subway into Value Stack.)
In responding to the white paper, the utilities suggested that, rather than exposing customers to long-term commitments that provide limited customer benefits, DRV compensation should be tied to DER production during each utility’s service territory-specific peak hours.
“To the extent that the current 10-peak-hour window creates more volatility than is deemed necessary to support development of eligible resources, a modest expansion to 50 hours may be appropriate,” the utilities said. “Similarly, the [state’s] Office of General Services argues that behind-the-meter generation should also be eligible for value stack compensation. This proposal should be rejected as customers using generation to offset their usage are already avoiding distribution and energy charges.”
The utilities opposed creating a community credit, but if one is established, they also oppose the recommendation by large commercial and industrial end-users that its costs be allocated only to residential customers, favoring instead the same methodology as the MTC, which allocates costs to those customer classes that receive the benefit.
They also recommended that the PSC reject the CEP’s suggestion to establish a Distribution Planning Advisory Committee, saying that “such a committee is unnecessary and would duplicate the existing Distributed System Implementation Plan Advisory Committee” and also create an additional burden on stakeholder resources.
