CARMEL, Ind. — A new report from MISO concludes that stakeholders will need to quickly adjust the RTO’s capacity construct and offer new market products to accommodate a resource mix in which renewables represent a majority.
The second annual Forward Report was framed from the perspective of MISO’s rapidly evolving utilities and what they will need from a grid operator in the near future. The report includes five hypothetical utility profiles based on integrated resource plans, interviews with stakeholders and investor presentations. MISO used the profiles to conclude it needs to change its capacity auction and resource accreditation, while developing new market products to incentivize a flexible supply.
“Utilities need MISO to act now to develop transitional and transformational solutions,” CEO John Bear wrote in the report’s introduction. “As customers continue to push for decarbonization goals, utilities are adopting significantly more diverse business models. Supply and demand of availability, flexibility and visibility will vary by utility. MISO’s ecosystem for exchange must accommodate this significantly increased degree of diversity and facilitate members to leverage that value.”
Bear said MISO utilities must “redefine what is needed” to manage risk on the grid.
MISO’s actual 2018 resource mix, and a projected 2030 mix based solely on utilities’ announced plans | MISO
“We have an imperative to act quickly,” MISO Executive Vice President of Market and Grid Strategy Richard Doying told the Resource Adequacy Subcommittee on Wednesday. He added that the Organization of MISO States and state regulators have said their utilities are weighing millions of dollars in investments and are wondering if the MISO market can accommodate their new resource portfolios.
Doying pointed to MISO’s 77-GW interconnection queue, now dominated by nearly 46 GW in solar generation projects.
“Not a lot of traditional resources; they’re new resources with operational characteristics that we aren’t used to,” Doying said of the queue makeup.
MISO predicts that by 2030 its generation mix will contain 32% renewables, 28% natural gas, 27% coal and 9% nuclear. In 2018, MISO’s generation mix was fueled by 47% coal, 27% natural gas, 15% nuclear and 8% renewables. Doying said the 2030 mix isn’t a MISO forecast but based on utilities’ announced plans.
“This is what all of your companies have said they’re doing. … This is not based on a bunch of assumptions,” he told stakeholders.
Sunset on the Planning Horizon
MISO said its footprint will soon contain “very diverse utilities that will rely on each other as neighbors in a shared resource pool in new ways.”
Customized Energy Solutions’ Ted Kuhn asked what role MISO sees itself playing: planner, or facilitator to the rapid change.
Doying said MISO will concentrate more on making sure it gathers more detailed and accurate information to share with its members making investment decisions.
The new report reiterated MISO’s now familiar prediction that its annual loss of load expectation process for estimating reliability needs will eventually be broken down by season to assess risks in all hours of the planning year.
“We count megawatts based on one thing: peak load. … If we only count megawatts based on the requirement we established, does that account for all reliability risks?” Doying asked rhetorically, referring to MISO’s current process of establishing accreditation and reserve margin requirements to serve load on the hottest summer day.
“I think a simple, summer-based loss-of-load expectation study doesn’t account for all risks. … It does a very good job, but it’s incomplete,” Doying said. “Is annual the right time frame to conduct that assessment, or should it be done seasonally?”
Doying said MISO is advancing on developing some sort of “sub-annual component” for its Planning Resource Auction. The RTO last year said a seasonal capacity auction would be beneficial though some stakeholders have pushed back on the idea. (See MISO Gives Tentative Nod to Seasonal Capacity Design.)
Kuhn said he was worried MISO was focusing too much on seasonal or monthly divisions of the planning horizon when an influx of solar generation will require an hourly analysis of risk.
“You can break the horizon down as much as you like; the sun doesn’t shine at night,” Kuhn said.
Doying also said MISO may create new market products that reward flexibility.
“We don’t have a proposal, but we do know that’s been done in other regions,” Doying said. “There are a lot of ramping needs when you get a lot of wind and solar on the system.”
He said MISO will re-evaluate its scarcity and emergency pricing in the coming months. Both items appear on the RTO’s Integrated Roadmap list of market improvements to undertake in 2020. MISO staff have said emergency pricing has generally been inefficiently low.
ERCOT’s first assessment of the summer season foresees a repeat of 2019 — record electric usage and tight reserves — but with additional capacity to help meet demand.
The Texas grid operator’s seasonal assessment of resource adequacy (SARA) projects a peak demand of 76.7 GW, almost 2 GW over the current record of 74.8 GW set last August. However, ERCOT expects to have 82.4 GW of total resource capacity on hand, a 3.5-GW increase over last summer’s available capacity.
“We continue to expect the region to have adequate reserves to cover a range of system conditions,” Warren Lasher, ERCOT’s senior director of system planning, said during a media call Thursday.
ERCOT said that, as in 2019, conditions could warrant the need to declare an energy emergency, but it noted that it and its market participants are taking steps to ensure system reliability can be maintained during tight conditions.
ERCOT has added 513 MW of capacity for the summer. | ERCOT
It has added 513 MW of additional capacity since December alone, including 348 MW of wind capacity. Solar energy accounts for 77 MW of capacity, and an 88-MW gas plant provides the only new addition of fossil generation.
Pointing to the vast amount of renewable energy in ERCOT’s generator interconnection queue (104.6 GW), John Hall, director of regulatory and legislative affairs for the Environmental Defense Fund, said renewable energy plays a critical role in “ensuring Texans have the power they need during the hot summer months ahead.”
“Texas’ competitive electricity market continues to lead the nation in providing clean, affordable and reliable power,” he said in a statement.
ERCOT also on Tuesday released its final SARA report for the spring season (March-May). The grid operator expects sufficient generation to meet a spring peak of 64.2 GW.
It will release the final summer SARA report and a revised Capacity, Demand and Reserves report in early May.
An SPP committee charged with coordinating the RTO’s policy development and recommendations to integrate electric storage resources (ESRs) took its first steps Tuesday with a conference call.
During the call, Chair Holly Carias, of NextEra Energy Resources, reminded the Electric Storage Resource Steering Committee’s (ESRSC) members that they are not to decide policies, but to “ensure the appropriate working groups are assigned the right recommendations.” She said the committee would be responsible for providing guidance, resolving conflicts and monitoring the working groups’ progress.
The committee discussed 17 of the 32 issues in front of it — divided into technical, cost allocation and “other” — before running out of time. The ESRSC will regroup March 13 to finish the task.
It is composed of the chairs of the Markets and Operations Policy Committee (Carias) and several working groups, including Economic Studies (ITC Holdings’ Alan Myers), Market (American Electric Power’s Richard Ross), Operating Reliability (Evergy’s Allen Klassen), Regional Tariff (Nebraska Public Power District’s Robert Pick), Supply Adequacy (Golden Spread Electric Cooperative’s Natasha Henderson) and Transmission (Midwest Energy’s Nathan McNeil).
The Nebraska Power Review Board’s John Krajewski, chair of the Cost Allocation Working Group, will serve on the ESRSC as a liaison member for the Regional State Committee.
The ESRSC reports to the MOPC but will also report progress to the SPC. The committee has set a tentative timeline of January 2021.
Wanted: Industry Experts to Review Order 1000 Projects
SPP is accepting applications through March 15 for the latest pool of industry experts that might be chosen to serve on an independent panel reviewing the RTO’s competitive transmission construction proposals in 2020.
The Oversight Committee will recommend the pool members, with the Board of Directors voting on their approval later this year.
SPP creates this pool of individuals each year in response to FERC Order 1000. The panel of industry experts will review, rank and score proposals for competitive transmission projects approved for construction.
SPP’s recently approved Transmission Expansion Plan includes two 345-kV projects that will be competitively bid: a $77 million, 60-mile line near Tulsa, Okla.; and a $152 million, 105-mile line and terminal equipment in Kansas and Missouri.
BOSTON — Approaches to transmission for offshore wind energy, including in Europe and Asia, seem to come in as many variations as do recipes for clam chowder in the U.S.
The different flavors came to light Tuesday when the Massachusetts Department of Energy Resources (DOER) hosted a technical conference to explore whether it should solicit proposals for a coordinated independent transmission network in the state for offshore wind generation.
The approaches can be divided into two main camps, as distinctive from each other as creamy New England clam chowder (served at the café near the venue) and the Manhattan variety based on tomatoes.
One side favors generators developing the transmission — the generator lead line, or radial system. The other favors independent transmission ownership, or a network system.
People have strong opinions on the transmission issue, just as they always have had about food. In 1939, for example, Maine Rep. Cleveland Sleeper proposed a bill to outlaw tomatoes in clam chowder.
State Gatekeeper
DOER’s offshore wind study, released last May, looked at the impact of the state doubling its offshore wind goal to 3,200 MW. It recommended the department “conduct a technical conference … and if necessary, issue a separate contingent solicitation for independent transmission in 2020 prior to additional solicitations for offshore wind.”
“As we pursue offshore wind as a key element of our climate change strategy, it’s essential that we have the opportunity to continue to fine-tune our approach so it’s cost-effective [and] regionally coordinated, and so we can make the best, most environmentally appropriate decisions around our shared ocean resource,” Massachusetts Energy Secretary Kathleen Theoharides said. “The critical issue of transmission is often overshadowed by the focus on offshore development, but not so today.”
Cash Factors
Massachusetts Clean Energy Center Director for Offshore Wind Bruce Carlisle said there are 26 GW of proposed projects up and down the East Coast, with more than 9 GW in contracts awarded so far.
“It’s easy to lose sight of the role that transmission plays in connecting these generators to the grid,” Carlisle said, pointing out that significance in the estimate that transmission makes up 25% or more of capital expenditures for any offshore wind project.
The distance from the shore will always have a significant impact on transmission costs, but more important is the increasing size of projects, which seems to lean toward using HVDC over AC, said Alastair Mills, a specialist on renewable energy integration with Siemens.
“In the U.K., we’ve moved from 100 MW per cable circuit and are now set at 400 MW per cable circuit in less than 10 years,” Mills said. “We are therefore looking at the real boundary between AC and DC technology.”
Projects in the U.S. now average from 800 to 900 MW, while a new one in the U.K. is set at 1.2 GW, which will be connected with DC for the first time, he said.
“The trend is clear: The generators are getting bigger; the projects are getting bigger; and we need to be ready for that in the future,” Mills said. “The biggest trend at the moment is the levelized cost of energy and the reduction in that cost. We’re seeing targets where we wanted to have below 100 cents/kWh, which have been reached well ahead of schedule.”
ISO-NE is “really busy now with offshore wind,” and wind makes up more than two-thirds of the 20,927 MW in the interconnection queue as of January 2020, said Al McBride, the RTO’s director of transmission strategy and services. The offshore figures from his presentation showed 4,160 MW for Connecticut, 8,460 MW for Massachusetts and 880 MW for Rhode Island.
The RTO last month presented its latest study results on integrating up to 8,000 MW of offshore wind into the regional grid, analysis requested by the New England States Committee on Electricity (NESCOE). That and a separate offshore study requested by Anbaric should be completed by the third quarter, McBride said. (See ISO-NE Planning Advisory Committee Briefs: Feb. 20, 2020.)
“There are or have been historically large generating stations located along the coast, some of which are retiring or have retired, and that is an advantageous system for us in our ability to interconnect generation that could come in from offshore,” McBride said. “Compared to other regions that don’t have quite this coastline and historical infrastructure, we’re fairly well situated.”
Developers have proposed interconnecting up to 1,200 MW at various points along the coast, from Barnstable and Brayton Point in Massachusetts, to Kingston, R.I., and Montville, Conn.
The U.S. Bureau of Ocean Energy Management has exclusive leasing authority on the outer continental shelf, “and a lease is not only to develop generation projects, but it comes with a pertinent right to have one or more transmission easements to get basically the long extension cord from the generation facility to the shore,” said attorney Mark Kalpin, of Holland & Knight.
“It’s an integrated process that BOEM has set up already in terms of how to build a project,” Kalpin said. “So when you do your site assessment plan or your construction and operation plan, you’re really saying this is the entirety of the project that I want; not only the offshore component, but everything necessary to get it to shore.”
An independent transmission developer also can apply to BOEM for a right-of-way grant or right-of-use easement, but that application process would not cover the activities of the generation developer, he said.
“So right off the bat, there’s a little bit of potential disconnect,” Kalpin said.
Laura Manz of Navigant previously helped CAISO develop $8 billion worth of transmission in California for renewable generation development.
“Renewable resources are remote from load centers, that’s a fact, so it’s just how we want to have the electrons move,” Manz said.
It’s important to achieve an optimal solution when looking at congestion in a cost-benefit analysis, she said.
“It might be better to just not pay for that upgrade that will completely eliminate congestion, but for one that can sustain congestion once in a while,” Manz said. “I think most of the RTOs, especially in this area, are pretty good at looking at that.
“And then we have the public policy upgrades, which is where this gets into a bit of a mess when you’re in a multistate RTO and it’s not really clear whose public policy gets the price tag.”
Connecticut regulators in January convened a public hearing to examine whether ISO-NE’s wholesale electricity markets are really geared to serve the state’s clean energy objectives after determining that out-of-market actions resulted in increased costs to Connecticut ratepayers. (See Connecticut Weighs Pros, Cons of ISO-NE Markets.)
Limited interconnection points are not a phenomenon limited to offshore wind, she said.
“What we see on the West Coast is because we’ve had the once-through-cooling retirement mandate, there have been some locations where previous coal-fired power plants, fossil fuel-fired power plants and now our nuclear plants are retiring in those shore locations, so there are some places to drop your offshore wind,” Manz said.
She encourages developers to start with an injection study to see where it can be done without an upgrade, followed by an integration study to look at the chances of curtailment.
European Lessons
Ksenia Kaladiouk of McKinsey & Co. delivered lessons learned in Europe, highlighting different operational models in Denmark, Germany, the Netherlands and the U.K. — with the U.K. most similar to Massachusetts, so far, in letting developers lead site and radial transmission development.
Denmark and the Netherlands both have the state build and own the radial transmission, while Germany has a network transmission system for developers to tie into offshore.
“If we look at where Massachusetts and the East Coast are today, you could say that we are headed in 2030 [24 GW] to a place where Europe is right now [29 GW] … but the situations are not identical,” Kaladiouk said.
“We’ve learned a lot, not just in regard to costs coming down and opportunities for technical innovation, but also in terms of what works from a market standpoint and what works from a regulatory standpoint,” she said.
“If we do go for a model where the developer is not responsible for transmission, what does it mean to actually align incentives properly?” Kaladiouk said. “Are they built in a way that actually minimizes outages? Are they front-loaded with certain costs or redundancies, or are you going to do that on the back end?”
Though the continental European system has seen lower borrowing costs and a stronger mechanism for compensating generators when needed, “we’re not co-optimizing development, so if you do have a developer building out both pieces of the system, do you actually see more coordination? Do you see stronger incentives to build on time?” Kaladiouk said.
Regional Effort
DOER Commissioner Patrick Woodcock kicked off the afternoon session by noting that “we do have some other states here — New Hampshire, Connecticut, Rhode Island and New York I believe is participating online.”
New York Gov. Andrew Cuomo is now pushing a bill that would allow the state to procure “submarine transmission facilities needed to interconnect offshore renewable generation resources to the state’s transmission system.” (See NY Renewable Supporters Push for New Siting Agency.)
“We really have found that [planning for offshore wind] requires participation from the entire region, and that was reflected in the New England States Committee on Electricity request for the economic study,” Woodcock said. “We look forward to continuing that partnership with the other states.”
Woodcock thanked stakeholders who submitted comments for the conference and said the department would be making a second request for comments after the conference.
“I assure you that our policy response will likely disappoint a lot of you,” Woodcock said. “It seems that there are a lot of strong opinions on this topic, and we do look forward to giving clarity to the marketplace on how we’ll be designing future” requests for proposals.
Getting to Shore
Joanna Troy, DOER director of policy and planning, outlined the legal background and statutory authority for the agency regarding offshore wind energy and related transmission procurement.
She emphasized that DOER “has not made a decision yet on whether to authorize a separate and independent offshore wind transmission solicitation.”
Perhaps not surprisingly, the offshore generation contractors were openminded about independent transmission developers but tended to favor the status quo for now, at least to get the industry rolling.
“There’s no doubt that if this region fulfills its offshore wind potential … at some point in time we have to look at integrated grid solutions,” Vineyard Wind CEO Lars Pedersen said. “The biggest issue we face is actually the onshore grid … which is not built to take off all the potential offshore wind energy we can deliver, and at one point in time we need a regional approach … that accommodates the multi-gigawatt scale of offshore wind.”
“What we’re talking about here … is a solution looking for a problem,” Pedersen said. “If you define success as clean, affordable energy at a rapid scale, while you continue to have the buildout of an industry — this will not deliver it.”
Pedersen said that any independent transmission developer coming into Vineyard Wind’s projects now would face a “very, very complex process,” which would make it extremely unlikely that the independent company could win on cost or project risk.
Theodore Paradise, Anbaric senior vice president for transmission strategy, said, “If your goals in Massachusetts are a few thousand megawatts, then maybe this works. But there’s a fallacy in the thinking around, do you do radials or do you do meshed networks?
“The U.K. is moving toward meshed networks for fewer ecological impacts and increased savings to consumers … because their goal is more than just a radial world.”
The region only has to look at onshore wind bottled up in Maine, he said: “Onshore wind in Maine is dead because it was expedient [to build before upgrading nearby transmission], and for that moment, it looked like the cost-effective choice,” he said.
“An example of this would be if I’m doing one project into the cape, I might do a 115-kV network for 1,600 MW. I spend $500 million doing that, and I think about my next project,” Paradise said. “I have to tear that down [and] I need to build a 345-kV. I should have built a 345-kV to begin with.”
Stranded cost is not the issue, but lack of planning, he said, citing how Texas built out a transmission network for wind and the developers came with their own proposals, unsubsidized.
“If you want to make a choice here for the 1,600 MW, you need to be thinking about where we are,” Paradise said.
He cited a Brattle Group study from last September that said in order for New England to achieve an 80% reduction in greenhouse gas emissions by 2050, the region will need to procure 3,000 MW of wind per year through 2050 if it’s going to electrify the transportation sector and home heating.
“And if you’re going to do that, you’re not going to do that with radials,” Paradise said. “By the way, we’ve already decided that in this country, and that is we have separate generation and transmission. We separated the two. The ocean isn’t different from on land; it’s still the grid.”
WASHINGTON — U.S. Sen. Chris Van Hollen (D-Md.) said Wednesday that he and other Senate Democrats will seek to amend a bipartisan energy bill this week to undo FERC rulings on PJM’s minimum offer price rule (MOPR) and NYISO buyer-side market power mitigation (BSM).
Van Hollen told the American Council on Renewable Energy’s Policy Forum that the American Energy Innovation Act introduced by Sens. Lisa Murkowski (R-Alaska) and Joe Manchin (D-W.Va.), the top members of the Senate Energy and Natural Resources Committee, was an opportunity to reverse FERC’s Dec. 19 order expanding PJM’s MOPR. (See Murkowski, Manchin Offer Bipartisan Energy Bill.)
Speaking with reporters after his speech, Van Hollen said he, Senate Minority Leader Chuck Schumer (D-N.Y.) and Sen. Cory Booker (D-N.J.) will offer an amendment to reverse both the PJM order extending the MOPR to new state-subsidized resources and FERC’s Feb. 20 order narrowing the resources exempt from NYISO’s BSM rules in southeastern New York. The latter order requires the ISO to subject storage and demand response to a minimum offer floor in its capacity market. (See FERC Narrows NYISO Mitigation Exemptions.)
“We should get 51 votes,” said Van Hollen, who last month joined with colleagues in asking PJM CEO Manu Asthana to delay the next Base Residual Auction to give states time to react to FERC’s “rash decision.” (See PJM’s MOPR Quandary: Should States Stay or Should they Go?)
Murkowski said last week her 550-page bill, which incorporates some 50 bills previously approved by the Senate committee, “is our best chance to modernize our nation’s energy policies” since the 2007 Energy Independence and Security Act.
In addition to reauthorizing the Advanced Research Projects Agency – Energy (ARPA-E) through fiscal year 2025, the bill could provide new markets for coal and natural gas and add initiatives for carbon capture, ocean energy, next generation nuclear power and advanced vehicles. The legislation is being substituted for a geothermal bill previously introduced by Murkowski and Manchin (S.2657) with a Senate floor vote coming as soon as this week.
House Democrats also hope to put their imprint on the bill, Rep. Paul Tonko (D-N.Y.), a member of the Energy and Commerce Committee, told the ACORE forum.
Tonko said the bill is a step in the right direction but that the House of Representatives will seek to make “it even more robust” by seeking to amend it with an extension of the investment tax credit for wind and a standalone storage ITC.
The Senate voted 90-4 Wednesday to begin debate on the bill. Murkowski opened debate with comments on Title II, which includes cyber, grid and mineral security. She cited World Bank estimates that meeting the goals of the Paris Agreement would increase demand for battery storage minerals — lithium, cobalt and nickel — by 1,000%.
She said the bill “will help America become a leader in growing industries like battery and renewable manufacturing, along with the jobs and the economic growth that they represent. I think it also helps put the United States in the driver’s seat to prevent supply disruptions that could quickly derail our efforts to deploy renewables, energy storage, EVs and other technologies.”
More than 10 years after the failure of the Waxman-Markey cap-and-trade bill, carbon pricing’s time may be nearing — seemingly good news to those concerned about climate change.
But carbon pricing won’t solve the climate crisis by itself or persuade states to abandon their own clean energy policies, speakers said Tuesday at a forum in D.C. sponsored by New York University School of Law Institute for Policy Integrity and Duke University’s Nicholas Institute for Environmental Policy Solutions.
Former FERC Commissioner Suedeen Kelly
“We’ve seen political interest increase for doing something to reduce greenhouse gas emissions,” said former FERC Commissioner Suedeen Kelly, now a partner with Jenner & Block. “We’re seeing it in Congress. We aren’t seeing it in legislation likely to be passed by both houses yet. But people on the inside say it’s quite likely that we could do something in the next Congress around carbon or climate change.”
Kelly noted that the Obama administration deferred action on the Waxman-Markey bill, choosing to spend its political capital first on winning approval of financial market legislation and the Affordable Care Act.
She recalled that former Sen. Jeff Bingaman (D-N.M.), whom she served as a legislative aide, talked about the ability of carbon pricing to “create new wealth” by creating a commodity that didn’t exist before — a way to create funding for programs such as carbon sequestration that can win support from coal generators and other unlikely allies.
“If we had put it first, it would have sailed through,” she said. “That consensus, for political reasons, has fallen apart, but underneath it I think there are still the underpinnings that could give rise to a consensus again.”
Indeed, there is evidence that climate denialism may have reached its nadir.
On Feb. 26, the Electric Power Supply Association (EPSA), many of whose members own fossil fuel generation, announced its support for a carbon price.
That came two weeks after Minority Leader Kevin McCarthy (R-Calif.) announced Republican plans for addressing climate change through carbon sequestration and removal, prompting Jason Grumet, president of the Bipartisan Policy Center, to declare: “The climate science debate is formally over.”
But FERC Commissioner Richard Glick said carbon pricing won’t solve climate change by itself. Nor will it necessarily eliminate the tension over state and federal jurisdiction, illustrated most recently by FERC’s December order that PJM expand its minimum offer price rule (MOPR) to new state-subsidized resources, he said.
One issue, Glick said, is the price level.
Danny Cullenward, Stanford University
“If it’s too high, you’ll have some states reacting negatively to it. If it’s too low, a number of states are going to say, ‘Why should I [eschew] clean energy policies if FERC is going to impose a carbon price that we don’t think is going to have a significant impact?’”
Danny Cullenward, a Stanford University law lecturer, also is concerned about pricing levels, saying carbon pricing should “integrate” state policies rather than seeking to replace them. “The more this is done from the bottom up, the less of a risk that FERC will come in and say, ‘Here’s a $3 carbon price that applies to everybody and that’s the end of climate policy.’ Which I think is an awful outcome and — frankly in the hands of the wrong people — could be done.”
Won’t End State Policies
Jeff Dennis, general counsel for Advanced Energy Economy, said carbon pricing will be less effective in decarbonizing the economy outside of electric generation.
“There are reasonable [carbon] price levels that will get you significant benefits in the power sector today and that’s why we should do carbon pricing. When you’re thinking about economy-wide though, you need other policies, because you need some astronomically high carbon prices, from what I’ve seen, to get a lot of those hard-to-abate sectors to achieve carbon reductions,” he said.
“Are states going to have to rethink their own policies in response to markets and carbon prices? Sure. But I don’t think that’s going to obviate the need for states to continue to have policies — or frankly the desire of other states to continue to have policies.”
(From left) Burcin Unel, Institute for Policy Integrity; Jeff Dennis, Advanced Energy Economy; Travis Kavulla, NRG Energy; Casey Roberts, Sierra Club; and Abe Silverman, NJ BPU
Casey Roberts, senior attorney for the Sierra Club, said state energy policies have objectives including green energy jobs and priming the pump for technologies such as storage and offshore wind “that might otherwise not get off the ground but that are really needed to [reach the] 100% renewable energy future.”
“Because of that, I think the notion that carbon pricing is going to solve the MOPR [and] federal-state tensions is a bit misguided,” she said. “If the carbon price is intended to displace those other state policies, then that’s really a nonstarter for organizations like the Sierra Club, and I think many other stakeholders.”
Roberts said carbon pricing also poses an “opportunity cost” because of the limited resources of RTO stakeholder processes and FERC.
“We feel like there are bigger obstacles to clean energy deployment in the country and a major one of those … is the mandatory capacity market,” she said. “I’m worried that carbon pricing becomes a distraction from resolving those other problems.”
Gary Helm, lead market strategist for PJM, insisted capacity markets can enable emissions reductions, citing PJM’s generation shift following the Mercury and Air Toxics Standards (MATS), which resulted in the closing of many coal generators.
Pricing in Capacity or Energy Market?
NYISO Principal Economist Nicole Bouchez said the ISO determined its carbon price should be incorporated in the energy rather than capacity market because of transmission constraints that prevent upstate New York, which has 87% zero-emission generation, from delivering it to downstate, where only 27% of the mix is renewable.
“The problem with having it in the capacity market is in many ways [you have] some of the same problems as in renewable portfolio standards and different types of subsidies and payments from states to resources, which [are]: How do you make sure that what you’re getting is offsetting carbon production and not being replaced by something else; and how do you make sure you’re getting the most bang for your buck in that? Because location matters. … We all have constrained systems. There are times when you can’t get energy from point A to point B, and the impact on the dispatch matters at those times.”
FERC Commissioner Richard Glick
Glick also cited the importance of transmission in meeting clean energy goals.
“We need to spend a lot more time at the commission … on the issue of transmission. How are we going to help the states achieve these dramatic, aggressive clean energy goals? We’re not going to do it unless we build out the grid.”
Abe Silverman, general counsel for the New Jersey Board of Public Utilities, had a different perspective, saying that carbon prices as an LMP adder to the energy markets is “a very small part of the solution.”
“We need to start shifting that carbon price into the future; into the planning horizon and incorporating those carbon externalities into things like capacity markets, into our long-term planning,” he said.
“This is one of the fundamental questions,” he added. “Are we trying to incent investment in the lowest carbon grid tomorrow, or are we really trying to build the low-carbon grid of the future? Those are two very different policy outcomes. And they may require a different style of carbon pricing.”
Expensive RECs
Travis Kavulla, vice president of regulatory affairs for NRG Energy, said carbon prices may not matter “if states are just going to commandeer this market” with long-term resource procurements at higher prices.
He cited the cost of D.C.’s solar renewable energy credits (SRECs), which he said “exceed the social cost of carbon by an order of magnitude.”
“The rooftop solar developers of [wealthy] Georgetown thank the people of [low-income] Anacostia for their generous contributions to climate policy,” he joked.
FERC last week accepted settlements with Bonneville Power Administration and FirstLight Power, along with an unnamed entity in the Eastern Interconnection, for violations of NERC reliability standards. The commission said in a notice on Friday (NP20-7) it would not review the settlements, leaving NERC’s penalties intact.
NERC submitted the settlements to the commission in a spreadsheet notice of penalty (NOP) on Jan. 30.
$50,000 Penalty for Unnamed Entity
The unnamed entity accepted a $50,000 settlement with ReliabilityFirst over violations of reliability standard CIP-010-2 R2, relating to the management of configuration changes in its IT systems.
On Nov. 30, 2016, the entity’s IT team discovered that some of its device types — not specified in the NOP — were not being properly monitored for baseline configuration changes as required by CIP-010-2 R2. The standard requires the baseline for a group of devices to reflect every individual device within the group. However, staff at the entity had assumed that one device within a device type or group could be used to represent all devices within that type or group.
This approach is allowed under CIP-010-2 R1, but ReliabilityFirst found that the entity’s management had not clearly communicated the R2 requirements in procedures. As a result of the oversight, discrepancies developed in a number of device groups between individual device baselines and group baselines, leading to further errors, such as 11 devices missing port setting documentation, a violation of CIP-007-6 R1, and 10 potential missed change authorization instances, a violation of CIP-010-2 R1.
The IT team outlined the discrepancies in a self-report submitted to ReliabilityFirst on Feb. 16, 2017. The RE observed that “[not] monitoring baselines has the potential to affect the reliability of the Bulk Power System … by reducing the entity’s ability to identify unauthorized activity, changes, or vulnerabilities and by introducing system instability when making changes to assets.” It warned that the entity could have tried to make important decisions based on outdated information or missed unauthorized changes to ports needed for emergency operations (though this did not create an opportunity for unauthorized access).
However, the regional entity also credited the IT team for finding the discrepancy relatively quickly. The relevant requirement had gone into effect in July 2016, meaning the entity had been in violation for less than five months. In addition, ReliabilityFirst noted that the issue was discovered during a regular review of entity change management processes and device baselines. This, along with stringent defense-in-depth measures covering the affected devices, indicated that the entity had a robust safety culture.
Mitigating measures taken by the entity in response to the violation included:
Updating management training procedures regarding change management tools and compliance change management requirements;
Creating job aids for updates and monitoring and training employees in their use;
Investigating and documenting port ranges in baseline documentation;
Performing new baseline monitoring steps for IT and creating a baseline monitoring report and evidence for a cycle.
In determining the penalty level, ReliabilityFirst weighed these factors against the “severe” nature of the violation and “medium” risk factor. The RE also considered aggravating the penalty based on a previous incident of noncompliance with CIP-010-2 R2 but decided against this because the prior incident was attributed to a different root cause.
FirstLight Reports Ratings Error
None of the other violations in the NOP — one attributed to FirstLight Power and four to BPA — carried a monetary penalty.
The FirstLight Power settlement stemmed from a self-report filed to the Northeast Power Coordinating Council (NPCC) in 2019. The generator owner (GO) was seeking to register a violation of reliability standard FAC-008-3 R1, relating to the establishment of facility ratings. In a regular internal compliance review at the Cabot generating station on the Connecticut River in Massachusetts, the company had discovered incorrect ampacity ratings on several components. Correcting the relevant ratings limited the station’s overall rated capacity.
FirstLight determined that Cabot was the only station affected and that all of the components in question had been installed between 2001 and 2006 when the station was owned by the local transmission owner. When the GO discovered the discrepancy, it reduced the station’s maximum output to prevent unloading the limiting equipment.
Because of the age of the affected components, NPCC concluded that the violation spanned two versions of the relevant standard. FirstLight was in violation of FAC-008-1 R1 from Aug. 2007, when the entity registered as GO for the Cabot station, until the standard was retired on Dec. 31, 2012. The violation of FAC-008-3 R1 lasted from the standard’s introduction in January 2013 until the station’s output was reduced in July 2019.
Due to the duration of the violation, NPCC decided against compliance exception processing. However, in light of FirstLight’s quick mitigation activities — along with the low level of risk and lack of history of noncompliance, the RE ultimately declined to assess a penalty. Mitigation measures included the reduction of the facility’s output; revisions to its facility rating sheet; and updates to its procedures regarding tracking, documenting and approving changes to ratings.
BPA Files Transmission, Protection System Violations
Three of BPA’s violations concerned the MOD-029-2a, the NERC standard governing transfer capability calculations — but because two of the incidents occurred in 2016, they were found to involve the earlier version of the standard, MOD-029-1a.
For the first violation, BPA submitted a self-report to WECC in July 2016 that it had incorrectly allocated the total transmission capability (TTC) for one available transmission capability (ATC) path while responding to an outage in the Western Interconnection. Because of an agreement with another transmission operator, the entity was required to reduce the TTC pro-rata along with the other TOP during an outage. Instead, it took the entire reduction but corrected the allocation the same day.
The second case occurred on June 4, 2018, when it correctly posted the TTC on one ATC path but did not correctly allocate between affected transmission owners while assessing a seasonal limit as required by its allocation agreement. Instead, BPA allocated an additional 16 MW to one entity while reducing another’s allocation by the same amount. It corrected the issue the same day and submitted a self-report regarding the violation on June 15, 2018.
In response to both incidents, BPA allocated the correct TTC and clarified its desk-level procedures regarding the relevant issues. For the earlier incident the entity also tested its systems to ensure that operators can update ownership shares correctly.
The entity’s third violation, related to MOD-029, took place between March 27, 2016, and Sept. 6, 2016, and involved a 450-MW transmission reliability margin (TRM) for one ATC transmission path that was implemented on Feb. 3, 2016. The TRM was intended to ensure reliable system operation when the system operating limit across the ATC transmission path exceeded 2,000 MW. However, BPA set its TTC too low on March 27, April 2 and April 8, resulting in an incorrect TRM methodology.
The entity corrected its TRM calculation on Sept. 6, ending the violation. It then completed a series of mitigating steps, including the creation of a system to automate TRM submissions, updating its production environment to incorporate the new system and training staff on the new functionality. Mitigation was completed on Oct. 30, 2018.
BPA’s final violation concerned reliability standard PRC-005-2(i) R3, relating to “the maintenance of protection systems affecting the reliability” of the BES. On Dec. 23, 2016, the entity reported that four days earlier it had found that a control battery at one substation had not been inspected for unintentional grounds as required in the standard. BPA had incorrectly thought that maintenance was not required because the battery did not have automated ground detection equipment and that the battery was not subject to the standard because the substation did not support BES elements.
“However, in December 2016, BPA corrected its assumption because the VLA control battery at the substation supported distributed Under Frequency Load Shedding (UFLS), which qualified the VLA control battery as a BES element and subject to the requirements of PRC-005,” the NOP said. “As a result, BPA found one VLA control battery that did not have the required maintenance activities as far back as October 1, 2015, for its required four-month calendar intervals.”
WECC identified the root cause of the violation as BPA’s incorrect assumptions regarding the requirements for BES elements and about the significance of the lack of automated detection equipment. Mitigation actions undertaken by the entity included completing inspection and maintenance on the control battery and confirming the application of relevant inspection forms for all batteries subject to the standard. In addition, BPA added the missing control battery to the work management system and added its voltage readings to other monthly readings.
The entity is not subject to monetary penalties due to a D.C. Circuit Court of Appeals ruling that FERC and NERC cannot impose such penalties against federal entities.
The Senate Energy and Natural Resources Committee on Tuesday once again voted 12-8 to advance FERC General Counsel James Danly’s nomination to the commission for consideration by the full Senate.
Just as he did last November, ranking member Joe Manchin (D-W.Va.) joined Republicans in voting for Danly, who would serve a term ending in 2023. (See Danly, Brouillette Advance to Senate Floor.) And, as he did last year, Manchin voiced displeasure that President Trump had not nominated Democrats’ choice — Allison Clements, clean energy markets program director for the Energy Foundation — to fill a seat left open by the departure of Cheryl LaFleur in August.
This time, however, several senators — Ron Wyden (D-Ore.), Martin Heinrich (D-N.M.), Angus King (I-Maine) and Maria Cantwell (D-Wash.) — also expressed their frustration with the White House and what they called the politicization of FERC, referencing its recent orders on PJM’s minimum offer price rule and NYISO buyer-side mitigation as evidence.
King was particularly critical of the vote and interrupted Chair Lisa Murkowski (R-Alaska) before she could move on to an Energy Department budget hearing with Secretary Dan Brouillette.
“Madame Chair, I don’t quite understand … the way to get to the other nominee is to say ‘no’ to this one until we get the other nominee,” King said. “Why didn’t we hold and say, ‘We as a committee want both nominees together, and we’re not going to hold hearings and not going to move them until then?’” By advancing Danly alone, “there’s no incentive on the White House for putting anyone forward.”
Murkowski and King went back and forth, with Cantwell interjecting, until Manchin jumped in.
“‘No’ was the right vote for the purpose that you stated, Sen. King,” the ranking member said. He explained that he had personally assured Danly he would support his nomination with the expectation that the White House would move forward with Clements and that he did not want to go back on his word. He then committed himself to opposing any Republican nomination unless it is paired with that of Clements. Commissioner Bernard McNamee’s term ends June 30, but he has committed to staying until there is a replacement for his seat.
“I don’t care who they give me the next time, no matter how qualified that person is, I’ll make [it] known, if there isn’t a pairing, we’re not voting,” Manchin said.
As the discussion was going on, the committee’s Republican majority tweeted, “The process for filling FERC seats was designed to avoid the need to pair. That is why the terms are staggered by a year. #GetTheFacts”
ClearView Energy Partners noted that Senate Minority Leader Chuck Schumer (D-N.Y.) last year threatened to filibuster any energy legislation without a pair of FERC nominees. “That struck us as a bit of an idle threat, as no bill seemed destined for imminent floor consideration back in September,” ClearView said.
“We are not quite convinced that the minority leader is prepared to bring the Senate to a near stop over FERC nominations, but the option appears available to him, assuming he could hold his caucus together to maintain a filibuster,” ClearView said.
(Updated March 4 to include latest developments at CAISO.)
The nation’s grid operators are taking their first steps to respond to the spreading COVID-19 coronavirus, issuing travel restrictions, limiting access to their facilities and conducting stakeholder meetings through webinars and conference calls.
ERCOT, ISO-NE and NYISO have all emailed their stakeholders to say they are closely monitoring the outbreak and following guidance from federal, state and local health agencies to mitigate COVID-19’s further spread. CAISO followed suit Wednesday when it announced its own measures to prevent spread of the virus.
ERCOT notified stakeholders on Tuesday that, “out of an abundance of caution,” it has scrapped all in-person meetings through March 15 and replaced them with webinars or conference calls, effective Wednesday. The ISO has also instituted restrictions for visitors to all of its facilities and is canceling non-essential business travel by staff and contractors for the same period.
The Texas grid operator is also monitoring staff and their family’s international travel, instructing staff with illness or symptoms to stay home, and deep cleaning its facilities.
The COVID-19 coronavirus has infected more than 90,000 and killed more than 3,000 globally.| Shutterstock
The ISO said it will review its restrictions on a weekly basis and alert stakeholders to any changes.
“ERCOT provides a critical service to Texans, and we are taking an abundance of caution to ensure the health and safety of our staff during this time,” spokesperson Leslie Sopko said in an email.
NYISO was first to email its stakeholders, doing so on Feb. 28. ISO-NE, like ERCOT, messaged its members on Tuesday.
NYISO “strongly encouraged” members’ personnel that travel to the ISO’s facilities to minimize the spread by following The Centers for Disease Control and Prevention’s guidelines. It also asked that it be notified if members’ staff attended recent in-person meetings or met with NYISO staff and later reported symptoms or tested positive for the coronavirus.
NYISO said its requirements are effective immediately for its personnel and will remain in place until further notice.
ISO-NE suggested members’ employees not meet with its staff or visit its facilities if they feel ill or show symptoms. The ISO referenced CDC’s expectation that the number of coronavirus cases will continue to grow and recommended stakeholders consider following the its guidelines.
“It is important to stress that, at this time, the risk to [ISO-NE] business operations remains low,” the grid operator said in its email.
COVID-19 has infected more than 90,300 people worldwide, killing more than 3,000.
PJM told its members earlier that its Incident Response Team is monitoring the outbreak and the guidance from the CDC, World Health Organization, the U.S. State Department and local health officials.
The RTO said it has suspended all international business travel and canceled all international visits to the PJM campus. It is requiring staffers to obtain a physician’s clearance to return to work after travel to affected geographic areas. It also is conducting “an enhanced cleaning process” with hospital-grade disinfectant and said staffers are equipped to work remotely if necessary.
CAISO alerted stakeholders Wednesday that “to protect the health of the company’s staff, and prevent possible disruption to critical business operations ” it has issued temporary restrictions on all in-person meetings through April 1 — or until further notice. In-person meetings hosted by CAISO and its Western Energy Imbalance Market will be conducted as teleconferences or webinars when possible, the ISO said.
The policy applies to a series of key meetings scheduled for this month, including those for CAISO’s Board of Governors; the Western EIM Governing Body and Governance Review; the Market Surveillance Committee; the Market Performance and Planning Forum; and the 2021 Local Capacity Requirements process. The decision will also impact CAISO’s March 11 Resource Interconnection Fair.
The ISO has also restricted visitor access to its facilities and suspended non-essential business travel for employees.
“We understand that the new protocol may be an inconvenience, and we apologize for any changes in travel plans, but continued reliable operation of the electrical system is our company’s first priority,” CAISO CEO Steve Berberich said.
SPP told RTO Insider it is continuing to work with health officials to monitor COVID-19 and influenza threats and respond appropriately. The RTO said it would use its communication channels and social media to alert its stakeholders of any steps being taken.
“We have a robust emergency management and business continuity plan that exists to maintain uninterrupted provision of our critical services,” SPP’s Derek Wingfield said. “Our goal is to ensure both the health and safety of our employees and the continued reliability of the grid.”
SAN FRANCISCO — The former president of the California Public Utilities Commission told a gathering of energy lawyers Friday that common assumptions about the future of renewable energy and electrification need to be re-examined.
Michael Picker, who left the commission in summer 2019, was replaced by Marybel Batjer. Since then, Picker said he’s been working for Gov. Gavin Newsom, putting together an energy roadmap for the state as it tries to reach its ambitious renewable energy and greenhouse gas reduction goals by midcentury. (See Retiring CPUC President Still Has Lots to Say.)
His research has led him to new thinking about reliability and resilience, he told the Western Chapter of the Energy Bar Association at its annual meeting. Picker was the keynote speaker, and his thought-provoking presentation was discussed throughout the day’s proceedings.
For instance, Picker said the idea that the state’s biggest utilities are opposed to clean energy, while community choice aggregators are more progressive, doesn’t pan out in the math.
The state’s investor-owned utilities — the “much maligned” Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — had achieved renewable portfolio compliance of 40%, 36% and 41%, respectively, by the end of 2018, he said.
“So that’s not bad progress since the goal was 30% by 2020,” Picker said. “And if you look at the forward compliance, each of them expects to be at 52% or above by 2024.”
Under Senate Bill 100, passed in 2018, the IOUs are expected to achieve primary reliance on clean energy sources by 2045.
Community choice aggregators (CCAs), most of which promise clean energy to retail customers and will become the majority of load-serving entities in coming decades, are falling behind, he said. They’ve proven more reliant on short-term contracts with out-of-state generators, with transmission constraints between source and sink, he said.
The IOUs, with more capital available, have been more successful in signing long-term contracts with in-state generators, whereas the “smaller entities [such as CCAs] with thinner capitalization have had a harder time being able to make those investments in long-term contracts,” he said. (See Calif. Lawmakers Reveal Growing Divisions over CCAs.)
Another issue, Pickers said, is that time-of-day demand from residential and commercial customers is merging.
California’s aerospace and automobile manufacturing economy died away, he said. Those industries used electricity around the clock, working three shifts every 24 hours. Now the state has a lot of “computational-based industries” that mirror household demand, with peaks about 200 hours out of the year, mainly after 5 p.m. on weekdays, he said.
“Who wants to build a power plant that’s only going to be selling electricity for 200 hours per year?” Picker said. “And how do you do that with solar if some of that demand is in the evenings after the effective capacity of solar starts to decline as the sun’s going down to the horizon?”
Rethinking EVs
Picker also noted that there’s a common misconception that generators are responsible for the bulk of greenhouse gas emissions. Electricity generation is responsible for 15% of carbon emissions, whereas transportation is responsible for 40%, he said.
State law requires a reduction in greenhouse gases by 40% below 1990 levels by 2030.
“As the electricity supply gets cleaner, it’s harder to reach that 2030 goal simply on the backs of the electric industry,” Picker said. “We have to address transportation.”
Statutes set a goal of having 2.5 million electric vehicles on California’s roads by 2025, he said. But planners tend to focus on individual ownership of EVs.
“There’s an implicit assumption amongst many of the planners that transportation is going to look the same 20 years from now as 20 years before,” he said. “Most of the policy … is focused on single ownership cars.”
In some urban areas, including Sacramento, more EVs are being charged and parked under car-sharing programs. The cars are taken to central locations where they’re charged at night, when demand is lowest, and distributed throughout the cities during the day.
Why, then, are government planners focused on owners charging cars in their garages? Picker asked.
“Why wouldn’t [car sharing] be the public policy priority rather than people installing [charging stations] in their homes?” he said.
Another point: As more Western states adopt renewable energy goals, the hydroelectric power generated in the Pacific Northwest will become a more coveted commodity, Picker said. And limited transmission will result in greater congestion, he said.
Electricity is becoming devalued as a commodity, while poles and power lines are generating greater revenues, he said.
The focus of policies has been on reducing greenhouse gases, but climate change will require greater resilience, which Picker said is another term for adaptation to changing circumstances.
“What I’m arguing,” Picker said, “is that we’re going to see more and more focus on adaptation.”
