ISO-NE on Wednesday said it expects to have sufficient capacity on hand this winter to meet load, which it forecasts will peak at 20,357 MW in normal weather conditions or 21,057 MW in extreme cold.
The region contains 4,500 MW of natural gas-fired generating capacity at risk of not being able to get fuel when needed, the RTO estimates.
“Last winter demonstrated just how much the weather can impact power system operations, not just in terms of consumer demand for electricity, but in the ability of generators to access fuel,” Peter Brandien, ISO-NE vice president for system operations, said in a statement.
Satellite image of a blizzard rapidly deepening off the Northeastern U.S. at 8:45 a.m ET on Jan. 4, 2018. | National Oceanic and Atmospheric Administration
During a two-week cold snap that started the day after Christmas in 2017, the region burned 2 million barrels of oil, more than it would in an entire year of more temperate weather. Shortages of natural gas continue to be a major concern for the grid operator.
Extreme cold weather constrains natural gas pipelines’ ability to deliver fuel for gas-fired plants and can also impact oil and LNG deliveries and generation from renewable resources, ISO-NE said. (See Familiar Winter Story: ISO-NE Braces for Gas Shortages.)
New initiatives by the RTO include forecasting the region’s available energy supplies for the next 21 days and providing a market mechanism to ensure that limited fuel supplies are used when they are most valuable for system reliability and cost-effectiveness.
Earlier in November, Mark Karl, ISO-NE vice president for market development, said the RTO is looking to create a new “energy inventory reserve constraint” to optimize the use of limited energy over more extended periods compared with how markets are currently designed to optimize energy over the course of an operating day. (See New England Talks Energy Security, Public Policy.)
The grid operator on June 1 integrated price-responsive demand into its markets and its new Pay-for-Performance rules, which provide for enhanced incentives in the form of bonus payments and institute financial penalties, ensuring resources are ready to meet their obligations to provide energy and reserves or reduce demand if needed. (See ISO-NE Begins Real-time Dispatch of Demand Response.)
The 2018/2019 winter outlook forecasts availability of 32,300 MW of resources with capacity supply obligations from the Forward Capacity Market, and total resources of 34,415 MW. The winter 2017/2018 peak demand of 20,631 MW occurred on Jan. 5, 2018, during the 5 to 6 p.m. hour.
The all-time winter peak in New England of 22,818 MW occurred on Jan. 15, 2004, while the all-time peak demand of 28,130 MW occurred on Aug. 2, 2006.
VALLEY FORGE — PJM is nearing the finish line in determining how it handles the primary frequency response (PFR) requirements put in place by FERC Order 842.
Stakeholders and staff put the final touches on the three remaining proposals at Tuesday’s meeting of the Primary Frequency Response Senior Task Force. (See “Primary Frequency Response Moving Forward,” PJM Operating Committee Briefs: Nov. 6, 2018.)
The proposals differ on thresholds for inclusion in the requirement, and on whether and how units that provide the service should receive separate compensation. A fourth proposal, offered by American Electric Power, has been removed.
Still under contention within PJM’s proposal is whether units can claim exemptions from the PFR requirements if installing the necessary technology would be prohibitively expensive. The RTO had added language that exemptions could not be justified “solely” on economic grounds, but Howard Haas of Monitoring Analytics, the Independent Market Monitor, said that a technical exemption should only be allowed if there is a “physical restriction that cannot be rectified using available commercial alternatives.”
He said the market should determine whether a commercial solution is economically feasible, and the requirement would remain either way.
PJM’s Vince Stefanowicz agreed that the rule should be that economics cannot be used as an exemption criteria.
“It sounds like we muddied the water” with the revisions, he said. “I’m actually inclined to go back to the original wording.”
PJM staff joked that removing the revision would leave the proposal “sole-less,” and Haas agreed.
“It would be ‘sole-less,’ just as economics should be,” he said.
But Bob O’Connell of Panda Power Funds and FirstEnergy’s Jim Benchek criticized the removal, arguing that prohibitive cost should be a consideration in approving exemptions.
PJM’s Glen Boyle said that equipment manufacturers provided feedback to staff that the necessary solutions are commercially available and low-cost. O’Connell asked for that understanding to be documented in the revisions.
Additional Discussions
David “Scarp” Scarpignato asked PJM to analyze whether units at 100% maximum output can receive an exemption from evaluation of PFR performance during a frequency event in the same way that units aren’t evaluated when at minimum output during an event. Staff agreed to review wording.
Staff also agreed to work with the Monitor on agreeing to a single megawatt threshold for aggregated resources under which they would be exempt from providing PFR. Currently, the Monitor’s proposal has a 10-MW threshold while PJM’s is 20 MW.
They also said they would provide a PFR market solution “if one becomes viable.” Calpine’s proposal calls for allowing units that produce more PFR than required to sell it. PJM is concerned how that would work for system restoration.
“The short answer is I’m not sure how you’d do that,” Stefanowicz said.
While PJM and the Monitor are attempting to avoid FERC-approved cost recovery similar to how reactive service is paid, stakeholders complained that the proposed process — in which PJM and its Monitor agree on a fair rate — doesn’t allow for due process for the unit seeking the rate while commission approval does. They asked PJM and the Monitor to develop language to determine standards and how the process will occur.
Next Steps
Reconciliation of the revisions should happen soon, staff confirmed.
“I think it can be resolved pretty quickly,” Boyle said.
Staff plan to open a one-week poll on the proposals that will close on Dec. 3 and have the results ready to review for the task force’s next meeting on Dec. 5. Packages that receive at least 50% support will receive a first read at the Dec. 20 meeting of the Markets and Reliability Committee. The proposal with the most support will be the main motion, and any others that meet the threshold will be considered as alternates.
The proposals will then be offered for consideration at the Jan. 24 meeting of the MRC and Members Committee. Endorsement on that timeline would lead to a filing at FERC in early February, PJM’s Jim Burlew said, and the RTO likely would seek an effective date of 60 days after approval. That would trigger the beginning of PJM tracking units’ performance during PFR events. However, as part of PJM’s implementation timeline, repercussions of the scoring, including referral to FERC enforcement, wouldn’t take effect for two years following FERC approval.
The poll will also include a question about whether stakeholders prefer a change to the status quo. If no proposal receives at least 50% or if the vote shows a preference for the status quo, staff will provide the results as part of the task force’s update and ask the MRC for further direction. Boyle indicated that, in that case, the RTO might decide to file a proposal for FERC approval without stakeholder endorsement under Section 206 of the Federal Power Act.
“I don’t think PJM would consider status quo an acceptable outcome,” Boyle said.
HOUSTON — ERCOT CEO Bill Magness says utility-scale solar “is the next big thing coming at us from the supply side,” giving the ISO just one more challenge to consider.
Noting that solar and wind generation generally complement each other, Magness told a recent Gulf Coast Power Association luncheon that solar “tends to fill the gap during the [late-morning, low-wind hours as load ramps up] … before coastal wind picks up later in the afternoon.”
“[Solar] will continue to accentuate the challenge other types of resources find in having to run economically,” Magness said. “It’s an interesting challenge as we go forward.”
Solar was expected to provide nearly 2 GW of capacity to meet ERCOT demand this winter, but the ISO’s interconnection queue tells a different story for the future. There, 32.2 GW of solar projects are in various stages of the study process, nearly equal to the 40.2 GW of wind projects under study. Together, solar and wind account for 86.8% of the 83.4 GW of the proposed projects in the queue (wind is providing almost 22 GW of capacity this winter).
“It’s all gas, wind and solar. There are no other resources coming along,” Magness said. None of the 1.8 GW of battery storage resources in the queue have a signed interconnection agreement.
“Our solar is very different from [that of] California. California has a lot of solar, but it’s primarily rooftop,” he said. “We’ve seen the real growth in utility-scale. Rooftop is coming, but the big chunks are coming on the utility side.”
ERCOT projects it could have as much as 5 GW of solar energy on the system by 2021, as developers continue to take advantage of the expiring tax credits. Most of those projects have been sited in West Texas, where the irradiance is best.
“As wide an expanse as Texas is, east to west, it’s a different picture in how solar will react than in California,” Magness said. “We’re having to do a lot of work figuring these things out, just as we did with wind.”
He said staff will have to start forecasting solar energy, as they did with wind.
“It was something we didn’t really need to do,” Magness said. “There was never a need to forecast generation. You turned it on, you turned it off. We’re getting better and better with the use of those tools.”
Also of concern to ERCOT is the growth of distributed energy resources (DERs), which can include gas or diesel technologies and storage assets, all connected to the distribution system. The ISO has seen a growth rate of 62% in DERs over the last three years, although the current grand total is only about 1.3 GW of capacity.
“For ERCOT, it’s a question of visibility,” Magness said. “If we don’t know it’s out there, we can’t get it in the system model.”
Staff has spent considerable time recently working with transmission and distribution providers to map some of the 93 existing registered DERs and to map all registered DERs to the system load. The goal is to capture the DERs’ capabilities and capacity “to where they make sense in the models.”
“If you have generation that runs on the system and wants be in the market, you want it to run in the right time and at the right place,” Magness said. “We welcome megawatts of all kinds. We’re just being sure we’re able to see [DERs] and they send the right price signals to make the most effective market.”
Pattern of Load, Wind and Solar on Peak Days | ERCOT
He pointed to ERCOT’s performance in the face of slim reserve margins this summer, when it met record demand multiple times without having to take emergency measures or call on additional resources, as an example of the energy-only market’s effectiveness. (See ERCOT SHs Debate Need for Changes Following Summer.)
“Most of the capacity we saw was self-committed. We didn’t need to intervene that many days,” Magness said. “The incentives in the energy-only market are aligned when you keep running in the peak season. We saw the energy-only market work as designed.”
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.]
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.”
