LIVERPOOL, N.Y. — While offshore wind has dominated the energy agenda in the Northeast this year, New York officials are taking care to nurture the economic potential of onshore wind as well.
“In New York, new turbine technologies and cost reduction mean that land-based wind opportunities for the state are growing,” Alicia Barton, head of the New York State Energy Research and Development Authority, said Tuesday at a summit hosted by the New York State Laborers’ Organizing Fund (NYSLOF).
Barton cited a recent NYSERDA clean energy report showing “the sector growing at a rapid rate, last year at 4%, about double the overall employment growth rate in the state,” with wind farms accounting for an average of 32 workers per project.
“We see the success of land-based wind projects really paving the way for future wind development,” Barton said. “This is exciting not only for our ability to attract that type of investment, but it is making a significant contribution to our ability to deliver a cleaner future for New York communities.”
One summit participant asked how NYSERDA enforced local content and labor provisions in the state’s renewable energy contracts, such as requiring developers to pay the prevailing wage to workers.
Barton said that NYSERDA is not involved in some projects built by out-of-state developers, but compliance on state contracts so far has been very good.
“There are probably 20 proposed windmill projects in our area,” said New York Upstate Laborers’ District Council leader Sam Capitano. “Some of the developers here we have relationships with, some we do not … these jobs are important to our area, and … our labor market is challenged right now.”
Harrison Watkins of NYSLOF noted the importance for labor to participate in the planning process for renewable energy projects.
Barton said her agency also is “very excited about the new frontier in wind, which is offshore wind energy.”
NYSERDA will soon issue the state’s first offshore wind solicitation in consultation with the New York Power Authority and the Long Island Power Authority. The agency will announce the award in the second quarter of 2019 and, if needed, issue a second solicitation next year to meet the 800-MW goal.
“Ideally it would take two years from project proposal to final permitting,” Anne Reynolds, executive director of the Alliance for Clean Energy New York, said regarding onshore projects. “Remember, only one project so far has passed all the way through the Article 10 process, and that’s the Cassadaga wind project, so it’s hard to say what the average time is.” (See Overheard at ACE NY 2018 Fall Conference.)
The New York Public Service Commission on Nov. 15 granted a certificate of public convenience and necessity for the 126-MW Cassadaga wind project in Chautauqua County, southwest of Buffalo on the shores of Lake Erie (Case 18-E-0399).
New York in 2011 revised Public Service Law Article 10 to unify siting reviews of new or modified electric generating facilities under one state agency, the Board on Electric Generation Siting and the Environment.
“It’s going to come down to if, and under what circumstances, the siting board will override local law,” Reynolds said. “Remember, this is the third generation of this law, and when it was originally passed there was no wind or solar on the horizon; it was about fossil fuel power plants.”
The intent of the law was to enable the state to prevent communities from blocking a needed power plant, she said.
“The world has changed, and now a law that was primarily designed for fossil fuel is being applied to renewable energy plants,” Reynolds said. “It’s a legal and philosophical question as to whether the state should, could and under what circumstance override local law … the original intent of the law was, in the public good, the state should be able to override local laws so that we all could have safe, and now clean, electricity.”
“Permitting is a process that involves basically anyone who wants to be involved, which is a good thing, but a challenge for the state,” said Sarah Osgood, director of policy implementation at the Department of Public Service.
“Having a one-stop shop for siting these large projects is a fantastic concept for a process but makes delivering on it challenging,” Osgood said.
“By having the state agencies review these projects, review multiple projects, there is so much potential for having some predictability and standardization built in as we go forward and get some precedent-setting information,” said Valessa Souter-Kline, project developer on Invenergy’s proposed 380-MW Alle-Catt wind project in western New York. The other positive attribute of state-controlled siting is the ability to work across jurisdictions, she said.
“At Invenergy, we’re seeing the opportunity to have larger projects, which mean more jobs and more community benefits than we were able to do under individual seekers,” Souter-Kline said.
Good, successful wind projects are engaged in the local communities, so a state-level process under Article 10 does not mean that developers stop working with municipalities, she said.
“Built into that is a little bit of confusion around who’s making decisions,” Souter-Kline said. “A lot of town supervisors or town leaders who are getting pressure from opposition will sometimes toy with this idea of ‘Do we actually need to update our local laws, or is the state going to override it?’ There’s an interesting tension there as to who’s taking responsibility for this project.”
Barton said that NYSERDA for years has been developing toolkits for municipalities “and have upped our staffing, so we’re not just putting them on our website, but going to those communities.”
“There are a lot of myths about wind power,” Reynolds said. “If a project was proposed in your town, where would you go to get the facts? The American Wind Energy Association to me is a reputable source, but other people would say, ‘Oh, that’s just the industry,’ so the struggle is to give the information from a source people trust.”
Osgood said the state is trying to put reliable information out there, but that some people question the state’s motives because of its ambitious renewable energy goals.
Reynolds said that opposition to renewable energy projects is probably inevitable and possibly based on very simple reasons: “I personally think the arguments against wind energy are because people don’t want to see the turbines.”
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.]
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.’”
