CARMEL, Ind. — MISO said Tuesday it has selected NextEra Energy Transmission Midwest to construct the Hartburg-Sabine junction 500-kV project in East Texas, wrapping up months of evaluation.
The announcement for MISO’s second-ever competitively bid transmission project comes more than a month ahead of a year-end deadline for a decision. The RTO’s studies concluded the project will alleviate longstanding congestion issues and import limitations near the Texas-Louisiana border.
NextEra proposes to spend $115 million to build a new 23-mile 500-kV transmission line, four short 230-kV lines and the new Stonewood 500-kV substation, which will connect the longer line with the existing Hartburg substation to the southwest. The company estimates the project will have a 2.20:1 benefit-cost ratio and be in service by June 1, 2023. NextEra Transmission Midwest is a subsidiary of Juno Beach, Fla.-based NextEra Energy.
MISO issued the request for proposals in early February with a July 20 deadline for developers’ proposals. The RTO in September said it was evaluating 12 complete proposals. (See MISO Evaluating 12 Proposals for 2nd Competitive Project.)
“NextEra’s proposal offers an outstanding combination of low cost and high value, with best-in-class cost and design, best-in-class project implementation plans and top-tier plans for operations and maintenance,” MISO said in its selection report. The RTO’s Tariff requires it to evaluate proposals based on cost and design (35% consideration), project implementation (30%), operations and maintenance (30%) and transmission planning participation (5%).
MISO scoring of proposals | MISO
NextEra’s proposal scored 97 out of a possible 100 points, with other developers scoring between 95 and 40 points, the lowest still within the “acceptable” range. The RTO’s competitive development rules prohibit it from revealing how rejected proposals were ranked.
MISO said while all developers had the “necessary capabilities to design, finance, construct, operate and maintain the project,” there were “meaningful distinctions among the proposals with respect to specificity, certainty, risk mitigation, cost, quality of design and overall value.”
Project proposals ranged in benefit-cost from 1.37:1 to 2.34:1 and cost anywhere from $95.4 million to $133.9 million for 19.9 miles to 24.5 miles of 500-kV transmission line. MISO’s most recent estimate put the project cost at $122.4 million. Annual transmission revenue requirements in the proposals ranged from $88.2 million to $166.3 million. NextEra submitted an estimated annual transmission revenue requirement of $95 million.
“MISO was impressed by the quality and depth of all proposals for this project — and we congratulate NextEra on their merit-based selection as the developer,” Aubrey Johnson, the RTO’s executive director of system planning and competitive transmission, said in a statement. “NextEra’s proposal reflects the best overall balance of cost and value in the development and completion of this important project for the region.”
“With developer selection complete, MISO will work closely with NextEra, state regulators and other stakeholders to support successful, on-time completion of the project,” Johnson said.
Hartburg Sabine map | MISO
MISO’s Board of Directors approved the Hartburg-Sabine project belatedly in February, still part of MISO’s 2017 Transmission Expansion Plan (MTEP 17). Approval was delayed because of stakeholder concerns over the cost estimate and a late Tariff change to separate Texas and Louisiana into their own zones for cost allocation. (See MISO Board Approves Texas Competitive Tx Project.)
The Hartburg-Sabine project comes two years after MISO’s first competitively bid effort, MTEP 15’s $49.8-million Duff-Coleman 345-kV project in southern Indiana and western Kentucky. LS Power won selection with a $49.8 million proposal. That project will be under construction throughout 2019 and 2020 and in service no later than January 1, 2021. (See LS Power Unit Wins MISO’s First Competitive Project.)
RENSSELAER, N.Y. — NYISO said Monday it would revise its carbon pricing proposal to enhance the bidding treatment for carbon-free resources and help prevent carbon leakage within its market.
Stakeholders requested the change, which will allow carbon-free resources bidding opportunity cost to use an estimated carbon bid adjustment to better reflect the impact of carbon pricing when those resources set the locational-based marginal price (LBMPc).
Ethan D. Avallone, NYISO senior energy market design specialist, told the Integrating Public Policy Task Force (IPPTF) the ISO previously proposed using a carbon bid adjustment of zero dollars for opportunity cost resources when calculating the LBMPc. As a result of stakeholder feedback, however, the grid operator will now use a non-zero bid adjustment when carbon-free opportunity cost resources represent the marginal resource setting the price during an interval.
Opportunity cost resources represent those carbon-free resources able to store energy and structure their bids to achieve delivery schedules during the most economic periods of the day, Avallone said. In periods of the day with lower prices, the bids of such resources therefore reflect the estimated opportunity cost of profit from periods of the day with higher prices.
Illustration of Potential LBMPC Volatility | NYISO
NYISO determined that setting the LBMPc at zero dollars when a carbon-free resource bidding opportunity cost was on the margin would cause leakage of emissions because external resources not bidding that cost could be selected instead for dispatch based on price, regardless of their emissions profile, Avallone said. This could lead to increased imports during periods when interal opportunity cost resources are on the margin.
The LBMP is expected to increase slightly under carbon pricing to reflect the emissions of the marginal unit, and carbon-free opportunity cost resource bids are likely to increase as a result of carbon pricing in some hours.
Avallone noted the ISO would still use the net social cost of carbon (SCC) to determine the carbon reference level for a CO2-emitting generator that functions as the marginal resource. (See NY Task Force Talks LBMPc, Residuals, Hedge Effects.)
“This is essentially one update, dealing with carbon pricing and the calculation of LBMPc with opportunity cost resources … and will lead to export/import transaction flows that more appropriately reflect what flows would have been absent carbon pricing,” Avallone said.
Calculation Issues
Michael DeSocio, the ISO’s senior manager for market design, said there is an unrelated effort at the ISO related to energy storage resources that deals with opportunity cost reference levels, which will require a few steps before implementation.
“The ISO is still developing how it’s going to deal with opportunity cost in the storage effort,” DeSocio said. “That has yet to be designed. There are going to be implications from that design on how we best incorporate this feature into that design.”
More specific details on how the ISO will model opportunity cost depend on completing the market design, he said.
“We may be getting too deep when talking about RGGI or carbon content,” said Warren Myers, director of market and regulatory economics at New York’s Department of Public Service. “The constrained optimization we want to do is to do what we can with respect to import-export pricing to maintain the current marginal comparison about flows.”
The opportunity cost resource’s bid is already based on its opportunity cost projection and will change with carbon pricing because that will change its opportunity cost, he said.
“So their bid was not known with precision before; they weren’t going to bid zero; they were going to bid their opportunity cost,” Myers said. “Now they’re going to bid something other than their prior opportunity cost, so we would like to have an estimate of how much their opportunity cost is going to change so we can try to maintain current import-to-export cost comparisons as if there weren’t carbon pricing.”
Importer Concerns
External resources would receive the full increase in the ISO’s LBMP due to carbon pricing during hours when a carbon-free resource bidding opportunity cost is on the margin, and those increased revenues would occur regardless of the resource type backing the transaction, whether carbon-emitting or not.
Howard Fromer, director of market policy for PSEG Power New York, suggested it might be more fair to external resources for the ISO to provide them with an estimate of the LBMP rather than making them guess.
DeSocio explained why the ISO thought it makes more sense for those trading on the border to assume the associated risks.
“Certainly the ISO can estimate what it thinks this LBMPc is, and you the trader can decide whether you like that number or not and then adjust the rest of your offer to accommodate it,” DeSocio said.
The original assumption of what a trader thought the implied heat rate was going to be inside New York now has to be set against whether they trust the ISO’s prediction, plus the ISO has to assume the LBMP values because it doesn’t know the exact value until the dispatch is over, he said.
“It seemed to us that if we could narrow three assumptions to two, all of which are under your control, you have better capability of representing your risk in the market than we do,” DeSocio said. “From a market design efficiency standpoint, it seemed far better for the ratepayers of New York and the market as a whole for that risk to be borne by the trader.”
IPPTF Chair Nicole Bouchez, the ISO’s principal economist, said, “Internal resources know their heat rates, but importers have to estimate what the heat rates are and whether it makes sense to import … the carbon emissions rates are highly correlated with heat rates, so if you’re already estimating heat rates, you have the technology and the background to estimate the carbon emission rates.”
WASHINGTON — The Senate Energy and Natural Resources Committee advanced FERC nominee Bernard McNamee to the full Senate on Tuesday in a 13-10 vote, with most Democrats opposing him over his pugnacious advocacy of fossil fuels.
Chair Lisa Murkowski (R-Alaska) said she hoped for a Senate floor vote before the end of the year for McNamee, the executive director of the Energy Department’s Office of Policy.
Ranking member Maria Cantwell (D-Wash.) said she could not support McNamee because of his role in crafting DOE’s controversial Grid Resiliency Pricing Rule proposal. At his Nov. 15 confirmation hearing, Democrats had pressed McNamee to recuse himself from FERC’s proceeding on resilience, which the commission initiated in January after rejecting the DOE proposal. (See Democrats Urge McNamee’s Recusal from Resilience Docket.)
RTO Insider
Democrats had also raised concerns about McNamee’s work earlier this year for the Texas Public Policy Foundation’s Center for Tenth Amendment Action and its Life: Powered initiative, described as a project to “reframe the national discussion” about fossil fuels.
These concerns were heightened after a video of a speech McNamee made in February at the TPPF’s 2018 Policy Orientation — apparently taken down after he was nominated — was leaked and posted to YouTube by the Energy and Policy Institute, a liberal advocacy group, last week.
In the speech, McNamee touted fossil fuels as “the key not only to our prosperity [and] quality of life, but also to a clean environment. What do you think powers the sanitation system, the clean water systems, that runs things that clean our air? It’s energy, it is 24-hour energy and it is energy that is produced from a very concentrated source in coal, oil and natural gas.”
He also attacked “an organized propaganda campaign against fossil fuels.”
“We see that the green movement is always talking about more government control because it’s the constant battle between liberty and tyranny. It’s about people who want to say, ‘I know what’s better for you.’ It’s the thing where groups are saying, ‘I want to be the one in charge, I know what’s good for you, and I’m going to ration it.’”
Cantwell said before Tuesday’s vote, “I would have liked to take Mr. McNamee at his word” that he would not be a partisan on generation fuels.
“But after the video has surfaced … I find it hard to believe that he is going to be the impartial reviewer of these issues,” she said. “His words revealed a very strong bias in favor of fossil fuel and against renewable energy.”
She noted that FERC nominee Ron Binz withdrew from contention in 2013 because some Senators accused him of being too supportive of renewables and critical of coal.
Speaking to reporters after the hearing, Murkowski said, “I don’t know if there was ever a ‘Binz Test.’ … We didn’t have him before us as a committee vote, if you’ll recall.”
Murkowski said McNamee’s comments on the video were “unfortunate.”
“I believe that we continue to need [fossil fuels], but we also recognize their role in the changes we’re seeing in our climate,” she said.
In an apparent reference to McNamee’s complaint on the video that renewables “screw up the whole physics of the grid,” she added, “It’s more appropriate to think of renewables as … a technical challenge for the grid, one that we can, and one that we will, overcome.”
Nevertheless, Murkowski said she would support McNamee based on his commitment to uphold FERC’s independence. “I will expect that he be fuel-neutral and not a champion for one resource over another,” she said.
After the vote, Sen. Martin Heinrich (D-N.M.) expressed disappointment that McNamee is “the best we can do” at FERC.
“I think he is indicative of the dividedness in this country right now — our inability to have a realistic conversation about climate. And I find both the video and his background to suggest that he is going to have a very difficult time being fair, objective or anything close to impartial.”
Sen. Joe Manchin (D-W.Va.) was the only Democrat to vote for McNamee.
RTO Insider
Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative, tweeted Monday that McNamee’s comments could be problematic if he joins FERC.
“His participation in any docket that includes comments from the ‘green movement’ — and especially any docket started with a complaint filed by an enviro group — creates a legal vulnerability,” Peskoe said. “There’s a chance a court would invalidate FERC’s order solely due to his participation.
“Case law does not establish a hard line with regard to bias. Challenging McNamee’s decision not to recuse himself from a docket based on filings from enviro groups is certainly not a slam dunk. But he’s a procedural liability for FERC. All risk, no gain.”
Murkowski said she did not know whether his nomination would be part of a vote on a package of other nominees. She also said she had “no idea” how long the Senate would be in session beyond Dec. 7, when its continuing resolution runs out. “Beyond that we’re operating in the great unknown.”
But she also said that as far as she knew, McNamee is not being considered along with another nominee to replace Commissioner Cheryl LaFleur, who term ends June 30, 2019, as some outlets have speculated. “All I can tell you about that is that I know as much about that as you do. … I have been given no indication that there’s going to be any early nomination, or how we will vote” on McNamee’s nomination. “It’s arduous enough to go through the vetting process and the length of time it takes” to go through the nomination process. “It’s important to [the nominees] that we try to get these wrapped up.”
[Editor’s Note: A previous version of this story incorrectly stated McNamee advanced on a “party-line” vote.]
A draft Department of Energy memo leaked in May that sought to justify coal and nuclear plant subsidies cited a 2008 Defense Science Board report that noting off-site generation supplies virtually all the electricity for the nation’s more than 500 military installations.
“Backup power at military installations is based on assumptions of a more resilient grid than exists and much shorter outages than may occur and is not sized to accommodate new homeland defense missions,” the report said.
But DOE’s 40-page memo failed to note the considerable efforts the military has made to improve the resilience of the installations’ power supplies in the 10 years since then — or that most Defense Department outages are the result of distribution lines or other facilities on its bases. And it makes no mention of climate change, which the military has identified as a concern since at least 1977. (See related stories, Military Sees Climate Change as Growing Threat and US Climate Report Spells out Coming Challenges to Industry.)
In fact, the military has been among the leaders in the federal government in seeking to make its facilities more resilient and in adding renewable power, energy storage and microgrids to its facilities. DOD is the largest single energy consumer in the U.S., spending $3.48 billion on installation energy in fiscal year 2017.
At the time of the 2008 Science Board report, the bases’ backup power was almost entirely diesel generators. Since then, the department has begun investing in microgrids and solar generation to allow their critical operations to continue operating during grid outages.
For example:
The Naval Construction Battalion Center in Gulfport, Miss., is leasing part of its land to developer for a 4.3-MW solar PV system. The developer is building a microgrid that connects the PV with diesel generators and energy storage to keep the base operating during blackouts. The project is part of an 11-project, 310-MW PV portfolio in a DOD partnership with Southern Co.
Otis Air National Guard Base on Cape Cod, Mass., is adding a microgrid that can keep it running for 120 hours using wind power, batteries and diesel generation. Reportedly the first wind-powered microgrid for DOD, it is expected to be fully operational in early 2019.
The Otis Air National Guard base, in Cape Cod, Mass., is deploying the Defense Department’s first wind-powered microgrid. | EPA
Marine Corps Air Station Miramar near San Diego has a microgrid powered by landfill gas, solar energy, storage, diesel generation and natural gas that can power the installation for three weeks.
The military also has been increasingly turning to renewable generation. Nellis Air Force Base, Nev., for example, is the site of a 14-MW solar PV plant covering 140 acres that meets 25% of the base’s electricity needs.
Nellis Air Force Base is the site of a 14-MW solar PV site covering 140 acres that meets 25% of the base’s electricity needs. | U.S. Air Force
In the National Defense Authorization Act of 2010, Congress ordered DOD to produce 25% of facility energy from renewables by FY 2025. As of FY 2017, DOD was producing or procuring 8.74% of its total facility energy from renewables, below its intermediate goal of 10%.
The military has made more progress in its energy efficiency efforts, reducing its energy intensity (British thermal units per gross square foot of facility space) by almost 50% since FY 1975.
Defense Production Act
The DOE memo proposed payments to “fuel-secure” generators under the Defense Production Act, a Korean War-era law that allows the president to intervene in the economy to protect strategically important resources. In October, however, numerous news outlets reported that the White House had declined to act on DOE’s response following opposition from the National Security Council and National Economic Council. (See Chatterjee Dodges as DOE Spins on Coal Bailout.)
Then-Navy Secretary Ray Mabus with President Barack Obama in 2010 | The White House
In a commentary in August, former Navy Secretary Ray Mabus (2009-2017) said President Trump’s proposal “would do nothing to improve grid resilience.”
Mabus cited a Brattle Group study that estimated the cost of Trump’s plan at $34 billion over two years. “That money would either come from America’s ratepayers — showing up on the monthly bills of millions of households and businesses — or from a Pentagon budget that the military needs for the real business of national security. Invoking DPA authority to spend tens of billions of dollars [to] prop up failing companies without a valid strategic reason would set a dangerous precedent, potentially undermining support for the future use of that authority in a real emergency.”
Instead, Mabus called for investments “in new technologies like distributed generation, battery storage and microgrids. Those will help keep the lights on and the mission up and running at our bases, even if the grid goes down.”
Those technologies have been central to the military’s success in increasing its resilience over the past decade.
Four Sources of Risk
The 2008 Science Board report identified four sources of risk of grid outages: overloads, weather (natural disaster), sabotage/terrorism and cyberattacks, and fuel-supply interruptions.
It cited coal as an example of the last risk, noting that transportation routes that move coal from mines to generating plants “are sometimes remote and lacking in alternatives. Critical rail lines or bridges could be taken out by determined saboteurs. For example, in May 2005, 43 rail cars came off the tracks. The disruption to coal deliveries caused prices to spike and raised electricity prices by 6% nationally, according to the Bureau of Labor Statistics. The 100-mile length of rail line through Wyoming that carries the output of the Western coal belt to power plants is the most heavily traveled in the nation.”
Frank Rusco, GAO | GAO
Frank Rusco, who oversees the Government Accountability Office’s work on a variety of federal government energy programs, says a disruption of coal rail lines is “probably about as likely as you having a long-term disruption in a natural gas pipeline.”
“I’m not sure that there’s a problem that this is the answer to,” he said of the DOE proposal. “It’s not clear there is a fuel diversity problem currently, and DOE hasn’t produced a study that shows that conclusively. … It’s more of an assertion.”
The biggest challenge to the resilience of the military’s electric supplies is not fuel logistics but its own infrastructure.
Most Outages On-base
The military has been reporting outage data for their facilities since FY 2012, but until recently, the data were inconsistent and incomplete. DOD changed its reporting after a 2015 GAO report that the data were unreliable and ignored that most outages occur on department-owned facilities (GAO-15-749).
Between FY 2012 and 2014, the facilities reported 150 disruptions lasting eight hours or longer — 87% of which were outages of DOD-owned facilities.
“Our research indicates that DOD-owned infrastructure, which DOD controls, may play a larger role in disruptions than indicated by the energy reports, which only address external, commercial disruptions involving equipment over which DOD has little control,” GAO said.
For FY 2017, DOD reported about 1,205 utility outages that lasted eight hours or longer, 72% of which were electrical disruptions. Equipment failures were responsible for 43% of the outages, 35% were planned maintenance and 15% were caused by storms or other acts of nature.
Because DOD’s energy reports do not discuss specific examples of utility disruptions and their impacts on installation operations, GAO’s auditors collected additional information on disruptions from 18 installations inside and outside the continental U.S.
Brian Lepore, GAO’s director of defense capabilities and management, said DOD officials are making progress.
They “have taken the concerns seriously that were the grids to go down, or were they to lose access to assured power, there are going to be mission capability problems,” he said in an interview. “While our reports have identified things we think they should do to help enhance their progress … it’s also fair to say they that have genuinely been willing to implement the recommendations.”
Reporting on outages to DOD infrastructure is important “because it gives the department a better sense of where they need to invest their resources,” he added. “It is more than just sort of an accounting exercise.”
Alternatives to Diesel Generators
Solar panels at Marine Corps Air Ground Combat Center, Twentynine Palms, Calif. | U.S.Navy
In October 2016, the Massachusetts Institute of Technology’s Lincoln Laboratory published a study providing a methodology for comparing the cost-effectiveness of competing resilience options and concluded that the military could often obtain better resilience at a lower cost by using alternatives to the traditional reliance on backup diesel generators.
The study’s authors visited four installations where backup power sources were primarily small, building-scale diesel generators — the number ranging from 50 to more than 350 at a single installation.
“The reliability of these generators is typically below industry standards; the maintenance and failure rates of generators during start-up and operation is not always recorded,” said the study, which found that bases’ departments of public works were “often understaffed, leading to uneven testing and maintenance of the equipment despite their best efforts.”
The study found that other options could reduce life-cycle costs and increase resilience for critical mission operations. Among the ideas: larger distributed and centralized generation in combination with PV and uninterruptible power supplies for critical energy loads that cannot tolerate any unserved energy.
“The study found that often, critical energy loads were clustered at a limited number of electrical distribution feeders, providing an opportunity to increase resilience and lower costs by centralizing generation. Consolidating generation into a smaller number of 1-MW or larger diesel, natural gas or other cost-effective fuel source generators at the substation eliminates a large number of smaller generators at the building level. Centralizing generation also allows for revenue-generating opportunities with the local utility or participation in demand response, where these opportunities are available.”
Solar wall at Fort Drum, N.Y. | U.S. Army
The study found that while an on-base centralized energy solution can provide more resilience, bases should first consider improving the reliability of their existing electrical distribution system.
“Currently, a primary cause of outages on some military installations is the lack of reliability of the existing base electrical distribution system. … Critical missions will continue to experience outages if the reliability associated with the base’s electrical distribution system is not addressed. In some cases, a base receives a high level of reliability from the commercial electric system, only to see it degrade as the power makes its way onto the base and to the critical energy load.”
Batteries Still Costly
The analysis concluded that, at existing prices, large batteries (>1 MWh) sized for peak critical energy loads are not cost-effective for the military.
“The challenge with a renewable energy source plus energy storage system is that the energy storage system needs to be sized for the longest expected outage duration at the worst time of the year for solar production (and one that provides continuous power through nighttime operations). This could mean sizing batteries for multiple days, weeks, or months. This leads to a system design severely oversized for the critical energy load to ensure the remediation of outage risks. As battery prices continue to become competitive, however, the DOD could use the modeling and simulation tool to reassess energy storage as a cost-effective energy resilience option.”
Ariel Castillo
Among the authors of the Lincoln Lab study was Ariel Castillo, a Ph.D. engineer now on a Brookings LEGIS Congressional Fellowship who has been among the leaders of DOD’s resilience efforts since 2012.
“It’s a very valuable engineering tool,” said Castillo, who emphasized that he was not representing Congress or DOD in his comments.
Castillo said DOD officials are now working to integrate mission requirements with the tool. “It just so happened for those four bases that we reviewed that solution worked well but … you could go on to a base and your redundancy actually looks pretty good, but your distribution system may not be great.”
Funding Challenges
DOD generally uses congressional appropriations to fund small-scale distributed generation projects and partners with non-governmental third parties to develop large-scale projects, including renewables.
GAO reported in 2012 that DOD was not always getting the best terms in obtaining financing for energy security investments (GAO-12-401). Auditors also found inconsistent reporting on the results of investments, with only eight of 35 projects sampled having documented cost savings or reduced energy use (GAO-16-162).
In a 2016 study, GAO reported on complaints that energy security projects do not compete well against energy conservation efforts based on returns on investment (GAO-16-164).
A later study said better guidance was needed for analyzing costs and benefits (GAO-16-487). Some of the 17 projects GAO reviewed advanced DOD’s renewable energy and energy security goals by, for example, providing power during an outage on the commercial grid. “But project documentation was not always clear about how projects did so,” the report said. “The primary reason … is that DOD has not issued guidance on how to document projects’ contributions to its energy security objective.”
DOD concurred with GAO’s recommendations.
The military is increasingly privatizing its utilities as a solution to underinvestment. Since FY 2012, DOD has signed more than $2.9 billion in energy performance contracts. As of January 2017, it had privatized almost one-quarter of its 2,574 utility systems, according to a GAO report released in September (GAO-18-558).
GAO recommended DOD develop metrics to track the performance of privatization contracts, noting that while the military branches estimated cost savings when awarding contracts, they failed to determine whether the savings were being realized. DOD concurred.
Systems Engineering
Castillo said he sees resilience as “a product of systems engineering” and that solutions must be subject to rigorous analyses such as the Lincoln Lab tool that consider both life cycle costs and mission requirements.
“I don’t think we can predict the threats the way we used to. If they are asymmetric … threats, I think resiliency is a good way to approach the problem. Because you don’t want your adversary to know how you will adapt and recover. But if they believe that you have vulnerabilities and all of the sudden you are adapting instantaneously, you’re outcompeting your adversary,” he said.
“I care about national security. I care about doing it the right way. I care about doing it in a way that protects the taxpayer at the same time.”
Hurricane Michael tore the roof off a chapel at Tyndall Air Force Base in Florida in October. U.S. Air Force
When Hurricane Michael’s 130-mph winds flattened a swath of the Florida Panhandle in October, Tyndall Air Force Base saw its marina destroyed, power lines downed and all of its hangars and 17 of the base’s $339 million F-22 Raptors damaged.
With the base facing potentially several years of repairs, the 95th Fighter Squadron’s F-22s and 36 airmen were moved to bases in Virginia, Alaska and Hawaii, at least temporarily.
The hurricane was the latest example of the severe weather that scientists say will occur increasingly in the future because of climate change. Although Commander in Chief Donald Trump has dismissed climate change as a threat, the Defense Department has been planning for it since at least 1977, when the Army Corps of Engineers’ Institute for Water Resources conducted its first study. The first National Conference on Climate Change and Water Resources Management, which the corps took part in, was held in 1991. (See related stories, Military not Waiting for Trump’s Resilience ‘Solution’ and US Climate Report Spells out Coming Challenges to Industry.)
Crews repair power lines at Tyndall Air Force Base after Hurricane Michael hit the Florida Panhandle in October. U.S. Air Force
Frank Rusco, who oversees the Government Accountability Office’s work on a variety of federal government energy programs, credited the department’s “mission-readiness focus.”
“In terms of resilience and responding to climate change, they’re definitely a leader. They have been thinking about these things deeply and for a long time because they want to [protect] their supply lines, their fire capacity, their infrastructure,” he said in an interview. “Other agencies, if that’s their business, like [the Federal Emergency Management Agency], of course, they’re thinking about it. … And [for] a lot of other agencies probably that’s pretty far from their radar screen.”
October’s hurricane wasn’t the first severe storm to damage DOD facilities. In 2012, storm surge from Hurricane Sandy destroyed almost 8 miles of water and sewer piping at Naval Weapons Station Earle, N.J., resulting in a one-month disruption of service and causing an estimated $24 million in damage.
In 2013, Fort Irwin, Calif.. experienced three power outages within 45 days as a result of flash floods from extreme rain events. U.S. Army
In 2013, Fort Irwin, Calif., experienced three power outages within 45 days as a result of flash floods from extreme rain events.
In at least two instances — Homestead Air Force Base, Fla., after Hurricane Andrew (1992) and Langley Air Force Base, Va., after Hurricane Isabel (2003) — storm damage has been severe enough to cripple operational missions for a time.
In addition, thawing permafrost, melting sea ice and rising sea levels have increased erosion at several Air Force radar early warning and communication installations on the Alaskan coast, damaging infrastructure, including utilities. As one example of the potential costs, the Air Force spent $46.8 million to repair erosion to the Cape Lisburne Long Range Radar Station’s 5,450-linear-foot rock seawall, which protects the base’s airstrip from waves.
The Air Force spent $46.8 million to repair erosion to the rock seawall at the Cape Lisburne Long Rand Radar Station, Alaska, which protects its airstrip from waves. U.S. Air Force
Melting Arctic sea ice also has created a new venue for potential international conflicts, opening the region to shipping, oil and gas drilling and mining. Russia has increased its military presence in the region.
More ominously, DOD strategists say climate change could exacerbate regional tensions, with conflicts over scarce water resources and climate-driven mass migrations leading to increased terrorism and other conflicts.
“Climate change is impacting stability in areas of the world where our troops are operating today,” Defense Secretary James Mattis told the Senate Armed Services Committee in written testimony early this year. “It is appropriate for the combatant commands to incorporate drivers of instability that impact the security environment in their areas into their planning.”
Retired U.S. Marine Brig. Gen. Stephen Cheney said a four-year drought that caused crop failures was one of the contributors to the Syrian Civil War.
“Syria’s civil war is a poster child for climate change as a national security threat,” Cheney, CEO of the national security think tank the American Security Project, toldCongressional Quarterly.
Defense locations facing multiple risks from climate change | Department of Defense
Congress Balks
Members of Congress have resisted Trump administration efforts to downplay the threats. In July, 34 Democratic and 10 Republican members of Congress signed a letter to Mattis expressing concern over a Washington Post report that the administration was attempting to scrub references to “climate change” from DOD’s annual, congressionally mandated report on the subject. The Post reported that all but one of 23 references to “climate change” contained in a December 2016 draft were deleted or changed to “extreme weather” or “climate” in the final report submitted to Congress in January.
In its 2018 defense bill, Congress required each service to report their 10 bases most vulnerable to climate change.
For the climate change report released in January, DOD surveyed more than 3,500 defense installations worldwide on whether they had experienced effects from climate risks. More than half said they had, with many citing multiple risks. Drought was the most cited impact (782) followed by wind (763) and non-storm surge related flooding (706). Others cited extreme temperatures (351), flooding from storm surge (225) and wildfires (210).
One of the biggest concerns for military planners is the world’s largest naval base in Norfolk, Va., where most of the land surrounding the installation is less than 10 feet above sea level. The U.S. expects sea level in the region to rise to between 2.5 and 11.5 feet by 2100. The Navy is concerned about a loss of military readiness when sailors and other employees living off-base are unable to reach work because of flooding. Norfolk city officials estimate improving storm water pipes, flood walls, tide gates and pumping stations will cost hundreds of millions; some residents may have to abandon their homes.
GAO Findings
A 2014 GAO report said that while DOD had begun developing sea-level-rise scenarios for 704 coastal locations, it had not set milestones for completing the tasks (GAO-14-446). It also reported that department planners lacked guidance beyond current building codes for how they should incorporate climate change into construction and renovation programs. It said base officials rarely propose climate change adaptation projects because the services’ funding processes did not include climate change in the criteria used to rank potential projects.
In November 2017, GAO reported that DOD had implemented one recommendation and had taken steps toward implementing the remaining two recommendations from its 2014 findings (GAO-18-206).
The new report added six more recommendations, “including that DOD require overseas installations to systematically track costs associated with climate impacts; re-administer its vulnerability assessment survey to include all relevant sites; integrate climate change adaptation into relevant standards; and include climate change adaptation in host-nation agreements.” The department agreed with all but two of the recommendations.
FERC last week granted ISO-NE’s request to terminate the capacity supply obligation (CSO) for Invenergy’s delayed 485-MW Clear River Energy Center Unit 1, while also denying the developer’s request for a Tariff waiver over the matter (ER18-2457).
The RTO said it wanted to terminate the CSO because the combined cycle plant in Burrillville, R.I., will not be operating in time for the beginning of the capacity commitment year starting June 1, 2019. The unit obtained the CSO in Forward Capacity Auction 10, held in February 2016, but is now scheduled to begin commercial operation after June 1, 2021. Invenergy has covered the plant’s CSO for the capacity commitment periods beginning in 2019 and 2020. (See ISO-NE Asks FERC to End Clear River CSO.)
The commission denied Invenergy’s request for waiver because it “would result in undesirable consequences.”
“We find that, on balance, if Clear River is allowed to retain its CSO, or retain its existing capacity resource status, after failing to achieve commercial operation within 63 months after the FCA in which it initially obtained a CSO, it will have undesirable consequences for both system planning and Forward Capacity Market pricing,” the commission said.
Clear River Energy Center concept art | Invenergy
FERC agreed with ISO-NE that continuing to include Clear River in its planning processes would have negative consequences for multiple aspects of system planning and found that doing so would risk misrepresenting capacity availability for the associated delivery years.
“In turn, the FCA may send incorrect market signals for the value of capacity and therefore procure an economically inefficient quantity of capacity overall and/or in certain capacity zones,” the commission said. “Similarly, continuing to account for Clear River as an existing capacity resource may also skew the results of interconnection studies and transmission planning studies.”
The commission found that “allowing a resource that is so significantly late in achieving commercial operation to be treated as an existing capacity resource will have undesirable consequences for Forward Capacity Market pricing.”
Finally, the commission noted that its order addresses only the CSO termination filing submitted by ISO-NE and the companion waiver request submitted by Invenergy, “and does not address whether the Clear River project is in fact ‘needed.’”
FERC last week conditionally accepted CAISO’s Tariff revisions covering how it calculates opportunity cost adders for use-limited resources, such as small hydroelectric projects.
The commission had ordered CAISO to make the changes in June after finding the way the ISO calculated opportunity costs would produce varying results, instructing it “to address this ambiguity.”
“We find that CAISO’s proposed revisions … largely comply with the commission’s directives,” the commission wrote in its Nov. 19 order (ER18-1169).
The 3-MW New Hogan Dam in Calaveras County, Calif. Small hydro facilities such as Hogan are automatically classified by CAISO as use-limited resources. | U.S. Army Corps of Engineers
However, the commission agreed with NRG Energy’s protest that the RTO needed to specify the gas-price indices it would use to calculate the adders and instructed the ISO to submit another compliance filing within 30 days.
The changes FERC accepted last week were the latest in a series of revisions related to CAISO’s Commitment Costs Enhancements initiative. As part of that initiative, the ISO has tried to revamp the way it compensates resources that have limits on the number of start-ups and runtime hours, or on energy output, over a certain period.
CAISO has contended the changes are needed because of the increase in variable energy resources on its system, making supply more unpredictable and use-limited resources necessary at any given time.
Because the ISO’s market optimization software makes unit commitment decisions only one day ahead, it cannot consider that dispatching a use-limited resource may hinder its ability to run later. As a result, the resources’ opportunity costs are not reflected in their offers. CAISO sought to change that.
However, FERC agreed with NRG’s protest at that time that argued against CAISO’s method for calculating opportunity costs. It ordered the ISO to submit a compliance filing that provided more specificity on calculation methods.
The commission’s Nov. 19 order conditionally approved that compliance filing, with the exception of NRG’s most recent protest.
The Trump administration on Friday quietly released a major report detailing the impact of climate change on the U.S., posing a stark contrast to the president’s rhetoric on the phenomenon and his inaction to address the problem.
The 1,656-page report is the second volume of the latest National Climate Assessment, the fourth released since Congress passed the Global Change Research Act of 1990. It was prepared by the U.S. Global Change Research Program, composed of representatives from 13 federal agencies, including EPA, the Department of Energy and the Department of the Interior. More than 300 experts, from both the public and private sectors, contributed to the report.
Climate change is leading to increasingly severe weather and disasters, including wildfires and flooding. The 2017 Tubbs Fire (left) caused an estimated $1.2 billion in damages and destroyed more than 5,000 structures, including 5% of the housing stock in Santa Rosa, Calif. Hurricane Harvey in 2017 caused widespread flooding and knocked out power to 300,000 customers in the area of Port Arthur, Texas (right). | U.S. Air National Guard
The first volume, released in October last year, focused on how human activity is causing changes to the planet and detailed the scientific evidence for the phenomenon. The second volume focuses on the effects of those changes.
“The impacts of climate change are already being felt in communities across the country,” the report begins. “More frequent and intense extreme weather and climate-related events, as well as changes in average climate conditions, are expected to continue to damage infrastructure, ecosystems and social systems that provide essential benefits to communities.”
Work on the fourth assessment began in the final days of Barack Obama’s presidency. Its release alone is significant in that it directly contradicts President Trump’s stance on climate change. But it also doesn’t appear to have been altered or edited in any way to downplay its findings, as some scientists had feared.
“This report makes it clear that climate change is not some problem in the distant future,” said Brenda Ekwurzel, the director of climate science for the Union of Concerned Scientists and one of the report’s authors. “It’s happening right now in every part of the country. When people say the wildfires, hurricanes and heat waves they’re experiencing are unlike anything they’ve seen before, there’s a reason for that, and it’s called climate change.”
Trump has repeatedly called climate change a hoax. Just two days before the report was released, he tweeted, “Brutal and extended cold blast could shatter ALL RECORDS. Whatever happened to global warming?”
“I’ve seen [the report], I’ve read some of it and it’s fine,” Trump told reporters outside the White House on Monday. “Yeah, I don’t believe it.”
“The report is largely based on the most extreme scenario, which contradicts long-established trends by assuming that, despite strong economic growth that would increase greenhouse gas emissions, there would be limited technology and innovation, and a rapidly expanding population,” White House Deputy Press Secretary Lindsay Walters said in a statement.
The 1990 law required the administration to prepare an assessment every four years. But the first assessment was not released until 2000, and the George W. Bush administration was sued for missing the deadline for the second, which was eventually released in 2009.
Impacts on the Energy Sector
The report consists of 29 chapters and five appendices. Twenty-five chapters focus on climate change’s impacts to a particular sector or region of the U.S.
Chapter 4 is entitled “Energy Supply, Delivery and Demand.”
Extreme weather and climate change can potentially impact all components of the nation’s energy system, from fuel (petroleum, coal and natural gas) production and distribution to electricity generation, transmission and demand. | Fourth National Climate Assessment Vol. 2
The energy sector “is projected to be increasingly threatened by more frequent and longer-lasting power outages affecting critical energy infrastructure and creating fuel availability and demand imbalances,” according to the report.
As with other sectors’ infrastructure, energy facilities across the U.S. are threatened, though in different ways depending on the region. Structures along the country’s coasts are threatened because of rising sea levels. Increased precipitation will lead to flooding in the Northeast and Midwest, while drought in the West will lead to lower snowpack levels and, thus, reduced hydroelectric capacity.
Perhaps the most unique challenge posed by climate change to the electricity industry, however, is a reduction in generation capacity for thermoelectric power plants, which rely on surface water for cooling.
“Most U.S. power plants, regardless of fuel source (for example, coal, natural gas, nuclear, concentrated solar and geothermal), rely on a steady supply of water for cooling, and operations are projected to be threatened when water availability decreases or water temperatures increase,” the report says. Some plants would potentially need to shut down until their water cools enough to comply with federal discharge temperature regulations.
Rising average temperatures and heat waves will also drastically increase electricity demand for cooling, leading to congestion on transmission and distribution lines and reducing their efficiency.
The reports notes that two major trends in the industry — increased reliance on natural gas and increasing penetration of renewables — provide diversity and flexibility. But reduced water availability will also affect fracking capability, as “during droughts, hydraulic fracturing and fuel refining operations will likely need alternative water supplies (such as brackish groundwater) or to shut down temporarily.”
It also notes that while most service interruptions are caused by transmission and distribution line outages, increased fuel supply disruptions could also affect reliability. “Coal facilities typically store enough fuel on-site to last for 30 days or more, but extreme cold can lead to frozen fuel stockpiles and disruptions in train deliveries,” the report says. “Capacity challenges on existing pipelines, combined with the difficulty in some areas of siting and constructing new natural gas pipelines, along with competing uses for natural gas such as for home heating, have created supply constraints in the past.”
County-level median projected increases in energy expenditures for average 2080-2099 impacts relative to no additional change in climate. | Fourth National Climate Assessment Vol. 2
Solutions
The last two chapters of the report are devoted to reducing risks through adaptation and emissions mitigation. Many of the measures spelled out are similar to those recommended by the U.N.’s Intergovernmental Panel on Climate Change in a report released last month, most notably by quickly reducing the use of coal for generation and drastically increasing renewables’ share of the generation mix. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)
For the electricity industry, the report says infrastructure will need to be hardened against extreme weather by:
“adding natural or physical barriers to elevate, encapsulate, waterproof or protect equipment vulnerable to flooding;
reinforcing assets vulnerable to wind damage;
adding or improving cooling or ventilation equipment to improve system performance during drought or extreme heat conditions;
adding redundancy to increase a system’s resilience to disruptions; and
deploying distributed generation equipment (such as solar, fuel cells or small combined-heat-and-power generators), energy storage and microgrids with islanding capabilities (the ability to isolate a local, self-sufficient power grid during outages) to protect critical services from widespread outages.”
It also lauds energy efficiency as a means for controlling costs to consumers, which it says will inevitably rise from all the changes.
“The interdependence of critical infrastructure systems increases the importance of electricity resilience, as disruptions to energy services are projected to affect other sectors,” the report says. | Fourth National Climate Assessment Vol. 2
Like the IPCC, the report urges expediency.
“The current pace, scale and scope of efforts to improve energy system resilience are likely to be insufficient to fully meet the challenges presented by a changing climate and energy sector,” it says. “Without substantial and sustained mitigation efforts to reduce global greenhouse gas emissions, the need for adaptation and resilience investments to address the impacts of climate change on the energy sector is expected to increase if the most severe consequences are to be avoided in the long term.”
A new report released by the Wind Solar Alliance last week says full market participation for renewables will require revisions to electricity markets, particularly in MISO and PJM, that were not designed with widespread renewable deployment in mind.
Fenton wind farm near Chandler, Minn.
“We think it’s helpful to have a vision of where we see the market heading, even if we’re not going to get all these market changes right away,” said Rob Gramlich, founder and president of Grid Strategies, the consulting firm that authored the report. “It was gratifying to see the level of consensus between the wind and solar companies. We’ve never really had to opportunity to step back like this with the [number] of companies involved.”
The report says several market reforms aimed at incorporating renewable generation are needed to keep electricity reliable and affordable. Among the more than 30 market changes it recommends are:
Creating multiday forecasts for units;
Compensating reactive power;
Creating primary frequency response markets;
Pricing “inflexibility costs” of conventional generation;
Incentivizing better forecasting from renewable generators;
Allowing flexible resources to bid without market power mitigation; and
Furnishing contingency reserves to cover “abrupt” drops in renewable output.
The paper also calls for grid operators to relax a year-round capacity performance requirement and create seasonal capacity procurements while abandoning fuel security requirements unless they have been demonstrated to improve reliability or efficiency. The study says grid operators should also make sure “conventional generators are not awarded excess credit relative to renewable resources.”
“Many of the current market rules were originally designed and adopted in the 1990s and early 2000s, based on the grid operations protocols from earlier decades when the grid was dominated by large, slow-moving fossil-fired, nuclear and hydroelectric resources. There were few wind and solar generators, independent power producers and non-utility electricity purchasers,” the report said.
Modern grid response needs to be faster and cover more megawatts, and today’s technology is advanced enough to manage it, the report says, concluding that electricity grids need to be flexible, fair, geographically widespread and free of barriers for entry or exit. It also contends that markets should not inhibit the ability of states or other authorities to achieve energy-related policy goals.
Gramlich told RTO Insider there isn’t a specific timeline for implementing the changes, but some are timely because they are part of ongoing discussions about other market revisions. He noted statements of support released by other organizations as examples of “broad agreement” that might signal “some things can move forward relatively quickly.”
While the report did not directly address the current national focus on grid resilience, fuel security and unrecognized benefits of large, “baseload” coal and nuclear plants, Gramlich said that has “sidetracked” the discussion from addressing what needs to be done for the grid to handle the current influx of intermittent, seasonal resources and the additional growth that is coming in the future.
He noted that in MISO, the “renewable community” plans to analyze self-scheduling.
In PJM, recommendations to allow resources to avoid the minimum offer price rule (MOPR) through bilateral contracts and to abandon efforts to add a fuel-security component in the capacity market “are important and very timely,” he said, although he acknowledged they’re “also very controversial right now.”
“If you get the right prices during times of stress, maybe that’s all the compensation you need in order to get the resources the revenue they want,” he said.
Overall, he said RTOs should be “as broad as possible and as seamless as possible” to ensure that renewable generation — which is often sited in remote regions — can be delivered to load where it’s needed, though he noted that PJM and MISO are at the top of the list for geographic scope.
“They do pretty well on the geographic breadth score, but there are some seams issues they could work on,” Gramlich said, specifically noting the seam between MISO and SPP.
MISO: Working on it
MISO said several of the recommendations in the report are already under evaluation by staff and stakeholders.
“MISO is still reviewing the report — so we can’t speak to its conclusions at a detailed level. However, we generally see this report as an affirmation of the major themes we’ve been working on and talking about with stakeholders for over the last decade,” spokesperson Mark Brown said in an email to RTO Insider.
The RTO said it has already rolled out new market designs, including extended LMP, ramping products and a new emergency pricing structure.
“MISO continues to assess new products and designs to get ahead of the evolving needs of the system,” Brown said.
It pointed out that it has already successfully integrated more than 18 GW of wind capacity and more than 300 MW of solar capacity.
“Wind and solar resources make up about 11% of MISO’s total market capacity. Based on the ongoing discussions, MISO plans to publish a long-term market strategy report next year with key recommendations for accommodating these long-term trends,” Brown continued.
MISO is currently in discussions with stakeholders about what market reforms are needed to address the growing mismatch between its changing resource availability and demand. The RTO has decided to separate solutions into the near and long terms, hoping to free up an additional 5 to 10 GW of supply through stricter outage and load-modifying resource rules, giving itself time to come up with bigger solutions. (See MISO Pivots to Near-term Resource Availability Fixes.) The long-term solutions discussion has already included the prospects for a seasonal capacity market and multiday forecasts.
MISO’s ongoing renewable integration impact assessment recently found the system will need significant upgrades at a 40% renewables penetration. (See Study: MISO Grid Needs Work at 40% Renewables.)
Conclusions ‘Consistent’ with PJM goals
In an emailed statement, PJM called the report “thoughtful” and said its conclusions “are consistent with PJM’s priorities.” The RTO pointed to its Extended Resource Carve-out proposal for revising its capacity market as an example of respecting state policy choices “while affording a level playing field where renewables and other competitive resources can thrive.” (See PJM Stakeholders Hold Their Lines in Capacity Battle.)
“PJM shares the alliance’s goals of reducing barriers to entry, properly pricing resources for their reliability and other valued attributes, and allowing the wholesale electricity markets to facilitate competition on a fuel-neutral, technology-agnostic basis,” the RTO said. “We continue to seek refinements of our energy market and ancillary services market rules to properly compensate generation sources for the services they provide.
“PJM looks forward to engaging with the Wind Solar Alliance and other stakeholders, including state regulators, renewable resource owners and consumer advocates, on proposals that will help us to maintain and improve PJM’s wholesale electricity market,” the RTO said. “We believe that the markets can provide far-reaching, regional solutions by pricing attributes and incenting the competition and innovation that have already helped achieve a cleaner, more reliable, less expensive system.”
Some of the recommendations tied in with existing stakeholder processes in PJM. For example, the Primary Frequency Response Senior Task Force has been working on revising primary frequency response requirements and measurement standards, as well as considering whether units should be compensated for the service. (See “Primary Frequency Response Moving Forward,” PJM Operating Committee Briefs: Nov. 6, 2018.)
Gramlich acknowledged that MISO and PJM have made progress toward the recommendations “in some cases,” but said “there are some other areas … where we have some concerns.”
MISO’s reliability is unlikely to be hampered by gas supply issues, as there is only a very small chance a large natural gas pipeline serving the grid could be affected by fuel delivery issues, according to a recent study from the RTO.
MISO said that at any given time it faces up to a 2% probability of a fuel disruption event in any given 1-mile section of an interstate pipeline. Of 35 MISO-area pipelines that have experienced events, about 80% have a 0.2% or less chance of an event occurring in any 1-mile section.
Vector Pipeline | DTE Energy
Gas generation outages stemming from fuel delivery issues would be 915 MW at most in any operating hour, the RTO said. It also found fuel delivery disruptions reported by gas generators are not usually related to unplanned pipeline outages.
The RTO will not publicly release detailed study findings because they identify specific pipelines.
MISO performed the in-depth assessment to determine whether its previous examinations of pipeline infrastructure failed to foresee additional risks because of physical disruption, but it said the study didn’t produce any new concerns.
“Over the past four years, MISO has not found any significant reliability impacts in its assessment of gas-related contingencies. … MISO has found little historical evidence, nor additional contingency risks that are greater than what is currently being evaluated,” the RTO said.
Earlier this year, MISO pushed back on a NERC report that said two areas in the RTO would “experience transmission challenges during an extreme event” involving a disruption of natural gas delivery. The RTO said the study failed to account for gas-fired generators’ access to alternative fuel sources. (See MISO Rebuts NERC Findings on Gas Risks.)
