RENSSELAER, N.Y. — NYISO’s Management Committee voted unanimously to recommend board approval of the grid operator’s 2016 Comprehensive Reliability Plan despite concerns about locational planning requirements and the shutdown of the Indian Point nuclear plant.
The CRP is prepared every two years. Laura Popa, manager of reliability planning, told the committee that under the conditions studied in the 2016 Reliability Needs Assessment, the grid’s bulk power transmission facilities meet all applicable reliability criteria from now through 2026.
Last October, officials identified two reliability needs: the Oakdale 345/115-kV substation in the NYSEG zone and the East Garden City-Valley Stream 138-kV line in PSEG-LIPA. In November, however, the transmission operators presented local transmission plans and operational procedures that eliminated the two needs.
Kevin Lang of law firm Couch White, representing New York City, said the grid operator should have considered in its CRP the closure of the Indian Point nuclear plant, whose two units are set to be shut down successively in 2020 and 2021. “I don’t think it’s appropriate to wait for a Notice to Retire, and it’s certainly important to New York City,” Lang said. He urged NYISO to go ahead with that analysis.
The grid operator contends, however, that it is pointless under the prevailing fast-changing market conditions to do a full reliability study before they receive a formal notice to retire the plant. (See NYISO, PSC: No Worries on Replacing Indian Point Capacity.)
David Patton, head of NYISO’s Market Monitoring Unit, said the MMU had concerns about locational planning requirements under the current rules. Some wind farms, for example, might be located in places that aggravate transmission constraints. “In particular, we find that market incentives for investment in resources in certain areas of the 115-kV system in upstate New York are inadequate partly because these lower voltage constraints are not reflected in the NYISO’s energy and ancillary services markets,” he said. “This has contributed to the need for cost-of-service contracts to keep older capacity in service.”
| NYISO
Patton recommended the ISO consider managing upstate 115-kV constraints in the day-ahead and real-time markets that currently require supplemental commitments, out-of-merit dispatch and other expensive operator actions.
Howard Fromer, director of market policy at PSEG Power New York, said that the CRP failed to mention any adjustments “to accommodate vast new changes in our intermittent energy supply. We don’t yet have a good answer to the question of ‘Will we have a reliable system?’”
Lang questioned the validity of the Monitor’s approach. “Some of these resources are coal plants that are 50 years old or older, or nuclear plants,” he said. “These resources are also being pushed out for policy reasons, not just market reasons. Low natural gas prices are competitive forces. … I don’t see any real analysis in your comments. Where’s your cost-benefit analysis?”
WASHINGTON — President Trump signed an executive order Tuesday directing EPA to begin the lengthy process of undoing its Clean Power Plan, a centerpiece of American efforts to battle climate change.
Years of Litigation to Come?
The long-promised order, which directs EPA Administrator Scott Pruitt to immediately review and begin steps to rescind the CPP, is but the first step in a process that could take years. And it’s unclear if the effort will ultimately succeed.
The Supreme Court stayed the CPP in February 2016 pending a legal challenge by more than two dozen states that contended the rule overstepped EPA’s regulatory authority. The D.C. Circuit Court of Appeals heard arguments in the case in September. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
Shortly after Trump signed the order, the Justice Department filed a motion with the D.C. Circuit to hold the state challenge in abeyance while EPA reconsiders the plan. “The Clean Power Plan is under close scrutiny by the EPA, and the prior positions taken by the agency with respect to the rule do not necessarily reflect its ultimate conclusions,” the department said.
President Trump speaks before signing an executive order seeking to undo the Clean Power Plan as Vice President Mike Pence, EPA Administrator Scott Pruitt, Interior Secretary Ryan Zinke and coal miners watch. | WhiteHouse.gov
On Thursday, Pruitt sent a letter to state governors, telling them, “It is the policy of the Environmental Protection Agency that states have no obligation to spend resources to comply with a rule that has been stayed by the Supreme Court of the United States. To the extent any deadlines become relevant in the future, case law and past practice of the EPA supports the application of day-to-day tolling.”
Legal experts differ on whether the D.C. Circuit will dismiss the states’ challenge based on the Trump administration’s withdrawal of support. Environmental groups immediately promised to fight the reversal of the plan.
The challenge for the Trump administration is to kill the CPP without providing some alternative for controlling greenhouse gases. Under the 1946 Administrative Procedure Act, the federal rulemaking process cannot be “arbitrary and capricious.”
Thus, Trump’s order will put EPA officials in the odd position of having to contradict the findings the agency cited when it issued the final rule in August 2015, which incorporated feedback from 4.3 million comments and months of meetings with state regulators, utilities and RTO officials. (See Revised Clean Power Plan Allows More Time, Sets Higher Targets.)
The administration also will have to overcome the Supreme Court’s 2007 ruling in Massachusetts v. EPA that carbon dioxide is a pollutant that EPA must regulate under the Clean Air Act and the agency’s 2009 finding that greenhouse gases endanger public health.
According to a report in Politico, Pruitt successfully argued against attempting to reverse the agency’s endangerment finding, citing concerns it would be difficult to defend in a court challenge.
Myron Ebell of the Competitive Enterprise Institute and the former head of Trump’s EPA transition team, told Politico that leaving the endangerment finding in place would require EPA to come up with an alternative to the CPP for regulating power plant emissions. “Before you know it, you end up having to do a Trump Clean Power Plan,” he said.
Paris Agreement Threatened
Although the order does not indicate whether the U.S. will withdraw from the 2015 Paris Agreement on climate change, eliminating the CPP would make it far more difficult for the nation to meet its obligations to cut its carbon emissions to 26% below 2005 levels by 2025. The CPP requires a 32% reduction in power plant CO2 emissions from 2005 levels by 2030.
| Rhodium Group Analysis
Economic consultancy company Rhodium Group estimates the U.S. would reduce carbon emissions by 21% below 2005 levels in 2025 under the CPP but that the reduction would flatten at 14% under Trump’s rollback.
The Paris Agreement is intended to prevent the planet’s temperature from increasing by more than 3.6 degrees Fahrenheit, which many experts say would lead to an irreversible future of rising oceans and extreme weather, leading to drought, flooding, and food and water shortages.
Social Cost of Carbon
Trump’s order requires federal agencies to use “the best available science and economics” in their cost-benefit analyses of regulations. But it also disbands the Interagency Working Group on Social Cost of Greenhouse Gases, created by the Council of Economic Advisers and the Office of Management and Budget in 2009, and dismisses the group’s work products as “no longer representative of governmental policy.”
Instead, it orders that “when monetizing the value of changes in greenhouse gas emissions resulting from regulations,” agencies rely on a 2003 Bush-era finding by OMB.
“In sum, to make a calculation based on ‘the best available science,’ they’re reverting to 2003 data,” wrote astrophysicist turned science writer Ramin Skibba in Slate.
The working group’s current SCC price of $36/ton has been widely criticized as too low, with some scientists contending it should be as high as $220/ton.
The OMB circular that Trump’s executive order cites suggests using a 7% discount rate for valuing future impacts of carbon emissions, more than twice the Obama administration’s rate of 3%. The higher discount rate is likely to reduce the SCC further.
Trump’s “plan would return the calculation to its 2003 level — a time when regulators could get away with ignoring climate costs and the benefits to avoiding them because of how uncertain they were,” Skibba said. “The main effect will be on proposed policies; for example, the next time [Department of Transportation] or EPA officials evaluate the fuel economy standards of cars and trucks, they wouldn’t have to set such strict limits. Eventually there will be more heavily polluting vehicles on the road, less efficient appliances in the marketplace, etc.”
CAISO is seeking to create a new transmission access charge (TAC) area for a California load-serving entity that does not intend to become a participating transmission owner in the ISO.
The “one-off” proposal with the Metropolitan Water District of Southern California (MWD) would create an unorthodox relationship between the CAISO and an important transmission provider that seeks to retain rights over its own network, while also protecting the ISO’s access to key delivery points along the California-Nevada border.
CAISO’s proposed new TAC area would cover the transmission system the Metropolitan Water District uses to feed pump stations used to move water from the Colorado River Aqueduct into Southern California. | CAISO
MWD delivers water to 26 member agencies serving 19 million consumers in six Southern California counties. It owns about 300 miles of 230-kV transmission lines that feed five pumping plants moving water from the Colorado River Aqueduct and State Water Project into Southern California. At full power, the pumps consume 300 MW of load, which is served by the agency’s share of output from the Hoover and Parker dams.
Edison Agreement Ending
Southern California Edison has been operating MWD’s transmission under a decades-long agreement that predates the existence of the ISO. SoCalEd has declined to renew the agreement when it expires Sept. 30 because of the utility’s reduced allocations from the Hoover Dam.
As a result, MWD is seeking a similar arrangement with CAISO allowing it to preserve its transmission operating rights (TORs) while continuing to offload responsibility for operating its grid. The ISO late last year agreed to act as the water agency’s transmission planning coordinator in matters related to meeting NERC reliability requirements.
While MWD’s generating assets sit outside CAISO’s balancing authority area, its agreement with SoCalEd has firmly integrated the agency’s transmission network into the ISO’s operations. It has allowed the utility to take advantage of MWD’s regulation, ramping capability and capacity reserves. The utility has, in turn, used its own baseload resources to serve MWD’s 24/7 pump loads at a flat rate.
The agreement also requires MWD to turn over its excess transmission capacity to SoCalEd — and now CAISO — for market use. That last point is especially important, because MWD’s transmission broadens the ISO’s access to the key Mead wheeling point out of Nevada and provides the ISO market its only access to the Parker delivery point.
“The ISO has been working with MWD on an operations agreement, which is what we typically do with entities inside the ISO [balancing authority area] that are nonparticipating TOs, but still have a substantial system within the ISO,” Deb Le Vine, CAISO director of infrastructure contracts and management, said during a March 28 call to discuss the issue.
Self Sufficient
As Le Vine explained, MWD is positioned to interact with the ISO as a nonparticipating TO because of its self-sufficiency: The agency can completely serve its load with its own generation and transmission.
“MWD does not lean on the CAISO system at all,” Le Vine said. “They have sufficient generation to meet the [California Energy Commission’s] resource adequacy requirements.”
And the ISO will derive a key benefit from continued integration with MWD. “They are going to still let us use their excess transmission,” Le Vine said.
MWD does have an alternative to being required to join CAISO as a full member. It could instead turn control of its assets over to the Western Area Power Administration’s Lower Colorado balancing area, which would narrow the reach of the ISO’s market.
“We’d stay at Mead, but only with Southern California Edison’s transmission,” Le Vine said. “We would no longer have access to Parker. We’d no longer have MWD’s parallel transmission line [out of Nevada] and the ability to use their transmission.”
Resource Adequacy Requirements
The need to create a new TAC area for MWD is based on an “unfortunate” technicality rooted in the link between California’s resource adequacy (RA) requirements and the ISO’s TAC areas, according to Le Vine. In adopting the state’s RA framework, the ISO chose to use TAC areas as the basis for allocating requirements among LSEs.
“We just need to create this TAC area to account for [MWD’s] load-serving entity obligations separately from how they’ve been accounted for in the past, which was all part of the Edison arrangement under the existing contract,” said John Anders, CAISO assistant general counsel.
Creation of the area will allow MWD to cover the resource adequacy requirements for powering its pumps along the Colorado River Aqueduct system.
“Are they going to pay the same TAC that load everywhere else pays?” asked Susan Schneider of Phoenix Consulting.
“No, MWD has TORs,” replied Le Vine. “They own their own transmission system, so they have never paid the TAC since 1998,” when the ISO began operations.
Eric Little, manager of wholesale market and greenhouse gas market design with SoCalEd, asked if the ISO expected MWD to serve a “significant portion” of its RA requirement with its own pumping load, which can provide system RA in a demand response capacity. Little noted that CAISO’s Tariff exempts participating load from ISO penalties meant to guarantee the availability of resources. Entities that enter a participating load agreement with the ISO are entitled to self-supply to meet their requirements.
“Which means that if they were to use a significant portion of their pumping load to serve as their RA, they would meet RA without having a similar obligation as others because they wouldn’t be penalized if they didn’t meet the obligation,” Little said.
“Well, that’s a decision for MWD to make, and they’d need to be consistent with what’s in the ISO Tariff,” Le Vine said.
“I don’t think there is any other load-serving entity out there that is in that same boat,” Little said. “I think everybody else, if they’ve got participating load, [pumping load] is a very small proportion of their load.”
Le Vine disagreed.
“There’s a very large entity that has a significant amount of participating load that is pumping load that uses that as RA,” she countered, referring to the California Department of Water Resources.
“It’s concerning, but I guess that ship has already sailed,” Little responded.
CAISO wants stakeholders to submit comments on the proposal to create the MWD TAC area by April 11, and expects to seek Board of Governors approval on the measure in May.
The Public Utility Commission of Texas unanimously agreed Thursday that NextEra Energy’s proposed $18.7 billion acquisition of Texas utility Oncor is not “at this point” in the public interest.
Chairman Donna Nelson and Commissioner Ken Anderson both read prepared statements into the record during a PUC open meeting. They cited the need for strong ring-fencing provisions that would include an independent board of directors for Oncor — a requirement NextEra has called a “deal-killer.”
“The tangible benefits to this transaction are few,” Nelson said. “In order to find this in the public interest, I would need to keep those ring-fencing provisions in place.”
“Bottom line, I do not find the tangible and quantifiable benefits are an improvement over the status quo to justify approval” of the deal, Anderson said, reading from a memo he later filed (Docket 46238). “To be honest, it has to do with their deal-killers.”
Commissioner Brandy Marty Marquez agreed with Anderson, saying she took NextEra “at its word” and complimented the company on its candor in the proceeding.
“I don’t believe they were posturing,” she said. “They were telling us quite clearly what they could and could not live with. I’m not happy to say that those were, unfortunately, the things I feel like we should not bend on.”
PUC staff will now draft a preliminary order that the commissioners can adopt during their April 13 open meeting.
Next Step Unclear
Whether this ends NextEra’s bid to acquire Oncor — which the Florida-based company has eyed for several years — remains to be seen. NextEra and Oncor representatives were not given an opportunity to appear before the PUC on Thursday, and both companies declined to comment on the commissioners’ remarks or next steps.
A previous attempt to acquire Oncor, by Dallas-based Hunt Consolidated, ended last May when Hunt withdrew its yearlong application over PUC requirements it found too onerous. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)
Hunt officials would not say Thursday whether they hope to make another bid.
“We have a long-standing policy of not commenting on other parties’ regulatory proceedings,” said Hunt spokesperson Jeanne Phillips in a written statement. “We are watching these events with interest and will wait for the commission’s final vote.”
Oncor has long been considered the crown jewel of Energy Future Holdings’ assets. EFH — previously TXU Corp. before being acquired by private-equity firms in a leveraged buyout — declared Chapter 11 bankruptcy in 2014 and has since spun off its generation and retail electric service providers as part of Vistra Energy.
Board Independence Issue
The utility has been ring-fenced since the 2007 buyout. That helped insulate Oncor from much of the $45 billion in debt EFH had incurred when it declared bankruptcy.
“The lack of a truly independent disinterested board and the lack of independent board control over the dividends are what worry me the most,” Nelson said. “And unfortunately, those are the issues on which it seems NextEra Energy is not willing to budge.”
During a public hearing in February, NextEra told the PUC it needs to maintain control over Oncor’s board to ensure its ability to appoint or remove the utility’s directors. The company said that is a fair trade-off for lending its A- credit rating and $59.2 billion market capitalization to help Oncor eliminate debt left by EFH. (See Hearings Over, PUCT, NextEra Ponder Oncor ‘Deal-Killers’.)
In its most recent filing, NextEra said its proposed ring fence retains virtually all of the 2007 conditions, while adding additional protections “that would not impede consolidation of NextEra Energy’s and Oncor’s credit profiles.”
The company noted it is proposing “a comprehensive suite of 73 regulatory commitments,” some in response to staff and intervenor concerns.
“These regulatory commitments offer substantial protections and benefits for Oncor and its customers and are more than sufficient to protect Oncor and its customers from any perceived risks associated with NextEra Energy’s ownership of Oncor,” NextEra said.
Nelson also referenced a July 2016 ratings report from Moody’s Investor Service. She quoted the report as saying “the acquisition-related debt without a material amount of deleveraging would exhaust NextEra Energy’s debt capacity at its current rating” and “makes the company more vulnerable to unforeseen events or margin shortfalls.”
NextEra told the PUC in February it has $12.2 billion reserved for funding the transaction — $9.8 billion for an 80% interest in Oncor and $2.4 billion for a 20% interest in various holding companies. It would assume the remaining $6.5 billion in debt, in line with its 60/40 debt-to-equity ratio.
“I worry about removing the ring-fence protections in this situation, where the debt above Oncor isn’t being extinguished, but is instead being refinanced with new debt at NextEra Capital Holdings,” Nelson said. “The parent company will remain substantially leveraged in order to make the purchase happen.”
“I see as much downside as upside to linking Oncor’s credit rating to NextEra Energy,” Anderson said. “I would require staff’s version of the condition de-linking the respective credit ratings … but given that they are all also NextEra Energy deal-killers, it seems to me that we would be wasting time and resources to proceed further down the road of appearing to approve the transactions with such conditions.”
VALLEY FORGE, Pa. — PJM should explain its daily operating decisions in more detail so market participants can better understand how markets are formed, stakeholders told staff at Tuesday’s special session of the Market Implementation Committee.
Bruce Bleiweis of DC Energy went so far as to request that PJM produce “an actual document” that enunciates all of its processes.
“If there are things that PJM doesn’t publicly want to post, doing it under the [Critical Energy Infrastructure Information] protocol should be sufficient,” he said.
Chantal Hendrzak, who chairs the MIC, said that her staff at PJM will “take that back and see what we can come up with.”
Part of the concern for stakeholders is that PJM gives its system operators discretion to analyze data and make decisions on the fly. While this keeps the system flexible, stakeholders said it also makes understanding the RTO’s thought processes more opaque.
“I think the first order of priority ought to be [finding out] what information [PJM can share] to understand what’s going on on the system,” one stakeholder said. He clarified that part of his interest was looking back to determine what caused uplift on the system.
PJM’s Keyur Patel, who gave a presentation on the RTO’s day-ahead market clearing process, pointed out that PJM will dispatch between 1,200 and 1,500 generation units on a typical day, and only 10 to 15 units will change throughout the day.
“There are times where we do want to make some commitment changes, but we run out of time and at those times, it’s better to post results on time than to change one unit,” he said.
Additionally, some decisions are made by the mathematic calculations of PJM’s security constrained economic dispatch (SCED) system without human intervention, said PJM’s Joe Ciabattoni, who gave a presentation on the RTO’s dispatch process.
There are times when “the engine cannot solve the problem in the time parameters it’s given. [It will] sacrifice one constraint to get power balance and retain control for the rest of the system,” he said. “We need a solution every three to five minutes to maintain system control.”
In that case, the system relaxes its constraints to allow the system to solve.
Ciabattoni explained it as his “but-for logic,” in that certain units wouldn’t have been committed but for a specific constraint.
“To unravel every one of those little variables … would need a team to determine them all,” he said. “But we could use: ‘but for that constraint, we wouldn’t have committed these [theoretical] 500 MW.’”
PJM’s perfect dispatch analysis evaluates all commitments, but only after the fact when the RTO knows what flow actually transpired, he said.
Ciabattoni said PJM doesn’t have any ramping issues for wind or solar “like other RTOs do,” except on extremely cold mornings.
An issue to consider, he said, is that once a unit is brought on, the constraint may go away because that unit overwhelms the constraint, but it may return if the unit is turned off.
“When SCED is looking at a solution … it may be getting fractional megawatts from a bunch of units,” Ciabattoni said, or a unit’s economic minimum output may be so close to its economic maximum output that it can’t cycle up or down efficiently. If such a unit is left running, there will be hours where it sets price and hours where it does not. When It doesn’t, it will create uplift, he said.
Joel Luna of Monitoring Analytics, the firm that serves as PJM’s Independent Market Monitor, said uplift comes down to three factors: megawatt-hours, LMP and the unit’s offer price.
By the end of the meeting, the special session’s facilitator, PJM’s Rami Dirani, determined that stakeholders needed more education before a useful list of interests for the group could be determined. He decided to cancel the group’s next meeting on April 5 and proceed with more education at its following meeting on April 25.
PJM can maintain adequate reliability with a generation fleet almost entirely composed of natural gas units, but a capacity mix of more than 20% of solar would unacceptably increase the risk of loss-of-load events, according to a study the RTO released Thursday.
The study, titled “PJM’s Evolving Resource Mix and System Reliability,” identified essential reliability and adequacy criteria and used them to compare a wide range of potential future fuel diversity scenarios. PJM focused on generator “reliability attributes” of frequency response, voltage control, ramping ability, fuel assurance and flexibility.
PJM created a “composite reliability index” to assess the operational reliability of various resources under four conditions: normal peak conditions, light load, extremely hot weather and extremely cold weather. Resources were grouped into 11 categories: coal, natural gas steam, natural gas combustion turbine, oil steam, oil combustion turbine, nuclear, solar, wind, hydro, battery/storage and demand response.
The RTO said the report is in response to stakeholder concerns that the system is losing too many traditional baseload resources as coal plants retire and nuclear assets struggle to remain profitable.
In 2016, PJM’s installed capacity was 33% coal, 33% natural gas, 18% nuclear and 6% renewables, which include hydro. By comparison, coal and nuclear resources accounted for 91% of its generation fleet in 2005.
| PJM
“This analysis underscores our responsibility to continue to operate the system reliably, and explore the role of resilience, the ability to tolerate unforeseen shocks and continue to deliver electricity,” PJM CEO Andy Ott said in a statement. “Different resources provide different reliability attributes, though new technology or regulations have the ability to improve those capabilities.”
No Upper Bound on Gas
Of particular interest, given the rise in gas-fired units interconnecting to PJM’s system, was the revelation that the there was no upper bound for the percentage of gas-fired units in the fleet before reliability is harmed.
The scenarios showed natural gas’ share of the fuel mix could rise to as high as 86% without reliability problems. Mike Bryson, PJM’s vice president of system operations, who spoke during a press briefing on the report, said staff stopped at 86% to account for demand response, hydropower and biomass currently on the system. “We figured it was a safe assumption to say they won’t go away.”
The report acknowledged, however, that it didn’t assess the gas-deliverability issues that pinched supply during January 2014 or the continued sluggishness of gas pipeline development. PJM’s previous natural gas studies generally concluded that the existing and planned pipeline infrastructure would be adequate for current and future anticipated electric system needs.
“We did not look at ability for infrastructure to support that, but we think it’s probably worthy of following up with the natural gas industry,” Bryson said. “There’s a lot of work left to do.”
The report also didn’t address the economics of resource types, factors that might impact a fuel’s deliverability or public policy issues such as environmental impacts or the use of subsidies. Bryson suggested coordination with the gas industry to begin addressing “more complicated issues” that cross over from the electricity sector, including data coordination.
That said, the report found that PJM’s current and near-term fuel mixes were near the top of the study’s reliability analyses. Less coal and nuclear generation would decrease frequency response, reactive capability and fuel assurance, but increase flexibility and ramping capabilities.
Renewables Limits
Portfolios with solar representing 20% or more of unforced capacity (UCAP) failed because they resulted in loss-of-load-expectation (LOLE) violations at night. UCAP is calculated by multiplying nameplate capacity by the resource’s capacity factor (38% for solar).
| PJM
Bryson said increases in batteries and other storage would likely change the conclusions.
He added that certain fuel types were given credit for their abilities, if not their current usages. “We gave wind kind of high marks on flexibility, even though that’s not how they operate today,” he said. “The capability’s clearly there, but they don’t operate in that way.”
Fuel Diversity ≠ Reliability
The study also found that a more diverse fuel portfolio isn’t necessarily more reliable. Certain resource blends that fall between the least and most diverse offer the greatest number of key generator reliability attributes.
| PJM
“Having a certain amount of diversity — not too much, not too little — gives you optimal reliability,” said PJM’s Chantal Hendrzak, who also spoke at the briefing.
However, high reliance on one type, such as gas, would create concerns that the paper didn’t attempt to analyze. PJM said it would continue to investigate ways to minimize its exposure to “low-probability, high-impact” events that could pose serious threats to the system.
“Our markets are designed to provide the incentives that the [13] states [within PJM’s footprint] need to implement their policies. We think there is an opportunity for PJM to work with the states” to determine how to harmonize well-functioning markets and public-policy initiatives, Bryson said.
The topic of reliability will be the focus of PJM’s upcoming Grid 20/20 conference scheduled for April 19.
Kentucky has dropped its decades-long nuclear moratorium, but experts on both sides of the nuclear debate say the move probably won’t result in new reactors for now.
The law, signed by Kentucky Gov. Matt Bevin on March 27, eliminates the requirement that nuclear power facilities have “means of permanent disposal” of nuclear waste, allowing a less onerous Nuclear Regulatory Commission-approved waste plan.
Carroll
Sen. Danny Carroll (R), the bill’s sponsor, said it was important that Kentucky start looking to diversify its energy portfolio, pointing out that nearby states take advantage of nuclear energy. Carroll said the law will “keep Kentucky competitive with the energy portfolios of surrounding states.”
“When you run a business, you look for varied funding streams. You don’t put all your eggs in one basket. … That’s what we’re doing in our state. Out of fear of nuclear energy, out of efforts to protect the coal industry, whatever the case may be, we are putting all our eggs in one basket,” Carroll said last year, when an earlier version of the bill languished after Senate approval. Kentucky does not house any nuclear generation.
The law eliminates the requirements that cost of waste disposal be known and that the facility have “adequate capacity to contain waste.” It also grants the Kentucky Public Service Commission the authority to hire consultants “to perform duties relating to nuclear facility certification” and allows it to prohibit construction of low-level nuclear waste disposal sites in Kentucky. The PSC can also direct the Energy and Environment Cabinet to review the nuclear permitting process. Kentucky PSC Director of Communications Andrew Melnykovych declined to comment on the law.
14 States
According to the National Conference of State Legislatures, 14 states currently have restrictions on the construction of new nuclear power plants: California, Connecticut, Hawaii, Illinois, Maine, Massachusetts, Minnesota, Montana, New Jersey, New York, Oregon, Rhode Island, Vermont and West Virginia. Most of the state moratoriums were made because of an absence of a permanent repository for spent fuel in the U.S. Wisconsin’s legislature ended its moratorium last spring.
President Obama ordered NRC in 2009 to stop work on a permit for licensing the nuclear waste depository at Yucca Mountain in Nevada. Obama acted at the behest of then-Sen. Harry Reid (D-Nev.) As a result, waste is being stored in spent-fuel pools and dry cask storage at operating and retired nuclear plants. (See Panelists Weigh Nuclear Waste Solution Post-Obama.)
The Trump administration’s 2018 budget requests $120 million to relicense Yucca Mountain.
Christine Csizmadia, the Nuclear Energy Institute’s director of state governmental affairs and advocacy, said she shared Carroll’s idea that long-term energy planning should not exclude certain generation types.
“You want to have an open option on the table, and that’s something that they couldn’t even consider before,” Csizmadia said. “It’s going to open the door to healthier conversations because now lawmakers aren’t confined and they can have long-term, open conversations.”
Csizmadia said that although she does not envision new nuclear building permits in Kentucky in the near term, she hopes Wisconsin’s and Kentucky’s actions will spark a trend. “That’s exactly what we’re hoping for, and why not? The thing about states is that they can be very competitive with each other; there’s a snowball effect. I don’t see why there wouldn’t be similar repeals. A lot of these moratoriums were made 20 years ago, and attitudes have changed.”
Nuclear Power a Distraction
Not everyone’s attitude toward nuclear energy has changed, however.
“Lifting the nuclear moratorium is not going to produce plants. Nuclear is such a politically charged question that it sucks all of the air out the room when planning,” said Arjun Makhijani, president of the Institute for Energy and Environmental Research, who has testified against overturning Minnesota’s nuclear moratorium. Minnesota’s legislature came close in the 2015/16 legislative session.
Far from opening up planning to new resource types, Makhijani said the moratorium reversal could shut down other, more important energy planning conversations.
“The main result is it’s going to divert the attention of Kentuckians away from the kind of energy policy that will be useful to create jobs in the state,” Makhijani said. “In a state that is hurting from coal industry job losses [the idea that] there are plans to replace those jobs with the nuclear industry — the most polite thing that I can say is that it’s very far-fetched. The idea is that we should have all options [but] the options have to make sense in economic terms and in planning terms. We’re entering the era of distributed energy and smart grids.”
Makhijani argues that the country’s aging nuclear fleet is often in need of repairs, requiring new valves and pumps and expensive shutdowns. He noted that nuclear plants cannot economically ramp up and down, making them too inflexible to be paired with increased wind penetration.
“I think the suffering communities in Kentucky, the coal miners, should be economically protected. But I don’t think they can be protected by promising a return of coal jobs or replacing it with nuclear industry. Nuclear is more expensive and less economic than coal. Nuclear is sort of in hospice care right now,” he said.
Summer, Vogtle Plants
Csizmadia and NEI spokesman John Keely said they did not know of any sites in Kentucky that have been eyed for nuclear development. But Keely said nuclear power can help fill the need for clean energy as coal plants retire.
Nuclear power is being revived, he said, with two new reactors being built by South Carolina Electric & Gas at its Virgil C. Summer nuclear plant near Jenkinsville, S.C., and two by Georgia Power at its Vogtle site near Augusta.
Virgil C. Summer Nuclear Plant Construction | SG&E
However, Makhijani said these new reactors are being subsidized by ratepayers and plagued by cost overruns and delays. “It’s even unclear whether those reactors will be finished,” he said, alluding to U.S. nuclear giant Westinghouse Electric’s bankruptcy filing Wednesday. Westinghouse is the lead contractor at both construction sites.
Makhijani also cautions against seeing small modular reactors as an option, saying they won’t be cost effective unless large numbers of them are purchased, and even then, several of them will need to be installed to generate a significant amount of power.
Still, a permanent repository is needed no matter how many more states light up a welcome sign for nuclear energy, Makhijani said. But he maintains that Yucca Mountain is not the ideal site.
“It’s much better than leaving it around in five dozen or odd sites in storage. There are terrorism risks, there are environmental risks, there are safety risks,” he said. Each 1,000-MW nuclear reactor results in 30 Nagasaki-sized bombs worth of plutonium per year in spent fuel, Makhijani said. “Today there is more civilian-made nuclear waste around than all the plutonium of all of the nuclear weapons worldwide,” he added.
Keely maintains that nuclear moratoriums “were a manifestation of the 60s’ anti-nuclear attitude … and can’t be defended anymore. It’s that basic and that pragmatic.”
He also said today nuclear has bipartisan support. “This used to be somewhat of a left-right issue and that’s no longer the case.”
A coalition of environmental, renewable energy and business groups called on California officials Tuesday to reignite CAISO’s effort to expand its operations into other areas of the West.
The groups — which include the Natural Resources Defense Council, Environmental Entrepreneurs, Union of Concerned Scientists and the Solar Energy Industries Association — issued a letter urging Gov. Jerry Brown and top state lawmakers to support legislation facilitating the ISO’s transition into a Western RTO.
“An integrated Western Grid is essential to a goal that we know all of you share: meeting our ambitious clean energy targets while driving down energy costs and creating new good-paying jobs,” the letter said. “We urge you to continue the process toward legislative authorization of a transition to a fully independent board for an independent grid operator that all Western utilities and generators will have the opportunity to join.”
The coalition kicked off its Secure California’s Energy Future campaign in response to the Trump administration’s move to roll back the Clean Power Plan, EPA’s chief initiative to combat climate change by reducing carbon emissions from the nation’s power plants. (See Trump Begins Attempt to Undo Clean Power Plan.)
“California has an opportunity — and a responsibility — to continue its leadership in responding to our climate crisis by working to integrate the Western grid,” Ralph Cavanagh, codirector of NRDC’s energy program, said in a statement. “While the White House and some in Congress are trying to roll back the climate progress we’ve made, Sacramento can take action and secure California’s energy future.”
Reduced Costs, Increased Reliability
The campaign’s supporters contend that integration of the Western grid would reduce costs and increase reliability for the region’s electricity customers, reduce the need to curtail output from renewable resources and “safeguard against price gouging by unscrupulous power marketers,” while at the same time allowing state governments to retain control over their energy policies. They also tout the benefits to California’s economy, including expansion of the state’s clean technology sector.
“Every day, California is basking in clean, affordable, reliable solar electricity,” SEIA CEO Abigail Ross Hopper said. “By enabling the state to fully utilize this solar resource, including sharing it across state lines, Californians will reap the benefits of increased jobs and investment and billions of dollars in electricity savings.”
A 2015 California law requires the grid operator and state energy agencies to explore ISO expansion to help the state meet its 50% renewable energy mandate. California lawmakers must sign off on any such expansion, which would necessitate that the state yield its direct oversight authority over CAISO once the grid operator becomes a multistate organization.
Brown Presses Pause Button
With skepticism mounting against regionalization efforts, Brown last August postponed CAISO’s expansion effort, saying he wanted state agencies to take more time to develop a governance proposal for the new RTO. (See Governor Delays CAISO Regionalization Effort.) Before that announcement, Brown had expressed hopes of delivering a proposal to state lawmakers before they concluded their 2016 session in September.
Progress on regionalization has since slowed. While the ISO last October released the third draft of a proposal outlining the principles for governing a Western RTO, nothing formal has been submitted to the legislature for consideration. (See Latest CAISO Proposal Fills out Western RTO Governance Plan.)
“We continue to be involved in discussions with stakeholders, and we get requests for briefings from lawmakers about the studies” related to the economic and environmental impacts of regionalization, CAISO spokesperson Anne Gonzales told RTO Insider. “The ISO is a technical resource for policymakers to understand the studies and the governance changes.”
Gonzales said the ISO has no stakeholder meetings scheduled to further discuss regionalization.
Agreement on a governance plan represents the biggest hurdle for expanding CAISO. Skeptics outside California have expressed concerns about the populous state’s potentially outsized influence over a Western RTO, while those within California are worried about losing the ISO as a key instrument for achieving the state’s environmental goals. (See Governance Plan Critics Urge Slowdown of Western RTO Development.)
The new campaign appears to be an attempt to jump-start the effort to overcome barriers to grid integration.
Other campaign supporters include the Independent Energy Producers Association, Bay Area Council, Health Care Without Harm, Sierra Business Council, Silicon Valley Leadership Group and SunPower.
DENVER — SPP and the Mountain West Transmission Group pitched the benefits of RTO membership Tuesday in an open forum before Colorado’s Public Utilities Commission as the two entities pursue a possible collaboration.
Taking advantage of the opportunity to get the last words in, SPP COO Carl Monroe grabbed a podium microphone just before the meeting adjourned to let his audience know the RTO would be holding its regular quarterly governance meetings in Denver in July, and that it would be a chance to see first-hand how SPP works with its members.
Coincidence?
Maybe not. SPP scheduled the meetings in the middle of last year, about the same time Mountain West was considering joining CAISO, MISO, PJM or SPP. Mountain West announced in January it was entering into discussions with SPP to further explore the relationship. (See Mountain West to Explore Joining SPP.)
The PUC scheduled the forum so regulators, consumer advocates and other stakeholders could gather information and discuss with Mountain West participants the potential benefits, costs and risks of the options under consideration. More than 70 attendees registered to participate, a number Commissioner Frances Koncilja noted was larger than normal.
Mountain West is an informal collaboration of 10 electricity service providers serving 6.4 million customers in the Rocky Mountains. Its members’ coincident peaks total just more than 12 GW, and it generated almost 70 million MWh of energy in 2015. Were it to join SPP, it would create a sprawling organization spread over 17 states.
Monroe told the commission that Mountain West would increase SPP’s size (575,000 square miles of service territory encompassing about 18 million people) by about a third. The new RTO’s Tariff would include seven of the eight DC ties between the Eastern and Western Interconnections, except for one in Canada. SPP also has two DC ties with the Texas Interconnection.
“We own the gateway facilities that go into” the ties, Monroe said. “We’ve spent a lot of time coordinating and understand those ties.”
“This is a very complicated transaction,” Koncilja told RTO Insider. “It will be up to the utilities to persuade us it’s a good thing for the ratepayers. This is just the first of many meetings.”
Mountain West members said they were pursing RTO membership to improve efficiency by eliminating pancake transmission rates and taking advantage of modern market designs to maximize transmission capacity. A 2016 Brattle Group study found Mountain West could save $53 million to $71 million annually through 2024 by participating in a day-ahead market and replacing its nine tariffs with a single one.
“It’s not that we have decided to go forward,” said Steve Beuning, Xcel Energy’s director of market operations. “We are in the process of evaluating what it means to go forward and [determining] the terms and conditions … that Mountain West considers essential before moving forward.”
Familiarity
Beuning said he was impressed by the knowledge in the group’s proposed RTO membership.
“This familiarity with the issues of our proposal, and an understanding of the particular needs of utility service providers in the western U.S., really helped lead to a deep and meaningful discussion,” he said.
Former FERC Commissioner Suedeen Kelly, an attorney with Akin Gump provided an overview of RTOs and ISOs, their functions and their regulatory relationship with FERC, while touting the virtues of regionalization and economic dispatch.
“The SPP transmission system is managed and operated for the same purpose as an individual system — to maintain reliability across the footprint and to dispatch generation,” she said. “There are no pancaked rates. Energy that flows from the northern end to the southern end pays one rate, no matter how many systems it touches.”
Jennifer Gardner, a staff attorney for Western Resource Advocates, praised SPP’s security constrained economic dispatch and its ability to create more renewable energy.
“By automatically dispatching resources where they’re needed, that allows us to deal with the variability of resources,” she said. “We see the immense potential for getting new renewable energy to the market” with SPP membership.
But Kelly also shared reasons for not joining an RTO.
“Why don’t we have one in the West?” she asked. “A lot of reasons, but to me, the most important, after being in California in 2000 when the California market imploded, is because the market imploded. We said, ‘Wait a minute, whatever they did, we don’t want to do.’”
Colorado PUC
Abby Briggerman, of counsel with Holland & Hart who generally speaks for large industrial ratepayers in the Rocky Mountains, and speaking on behalf of the ratepayer interests, said she was concerned about the risks of joining an RTO.
“We’ve come a long way since 2001, but we need to look no further than California. We remember the rolling blackouts,” she said. “The ratepayer must have a seat at the table in the decision-making process over whether to join an RTO.”
Briggerman also warned that SPP could be a “Hotel California,” referring to the Eagles’ song in which “you can check out any time you like, but you can never leave.”
“We need to make sure there are no barriers to exit,” she said.
Consumers’ Voice
Other attendees also questioned whether consumer interests would be lost in SPP.
SPP representatives, members and stakeholders countered by praising the RTO’s stakeholder engagement, and Monroe emphasized the diversity of is 94-entity strong membership. “We provide a lot of transparency into SPP,” he said. “Our meetings are open, even up to board level. We had 150 people at our last board meeting. Anybody that has ideas that will help SPP make good business decisions will be listened to.”
SPP General Counsel Paul Suskie brought up Steve Gaw, a former Missouri commissioner and legislator who represents The Wind Coalition at meetings although the coalition is not a member.
“He’s not a member, but he gets just as much input as members,” Suskie said.
SPP and Mountain West have developed a steering committee and working groups focused on governance, rate design and cost allocation, transmission planning, reliability coordination and SPP’s Regional State Committee. Composed of regulators from 10 different states, the RSC will be a key player in the membership negotiations.
Mountain West members said they expect to decide on whether to proceed with SPP membership in the second or third quarter of 2017. Rate cases would be filed shortly thereafter, with a final recommendation presented to SPP’s board in January 2018.
“I would be bold to call [the timeline] aggressive, but it keeps us on track. It keeps us focused on what we’re trying to accomplish,” said Mary Ann Zehr, senior manager of transmission contracts, rates and policy for the Tri-State Generation and Transmission Association.
Zehr said she anticipates numerous meetings over the next few months devoted to writing a tariff, governance and membership agreements and bylaw changes.
“We’re attempting to answer those questions at the front end,” she said.
CAISO has signed an agreement with the Bonneville Power Administration designed to facilitate Energy Imbalance Market (EIM) transfers in the Pacific Northwest while ensuring that the agency can continue to reliably serve its own transmission customers.
The Coordinated Transmission Agreement (CTA) could provide a model for future joint efforts between the two agencies that operate most of the transmission network along the West Coast, according to Todd Miller, a senior project manager with BPA.
“This agreement kind of seems like a no-brainer,” Miller said during a March 27 call hosted by the EIM Body of State Regulators (BOSR), an informal network of Western utility commissioners that convenes regularly to discuss market issues. “We need to have an operating agreement … so everybody understands the rules of the road.”
The agreement also represents a “milestone” in cooperation between BPA and CAISO, Miller said. “I think it’s really a first step in being able to coordinate seams issues.”
The CTA largely formalizes procedures already put in place before the EIM was launched in November 2014. At the time, BPA worked with PacifiCorp — the EIM’s first member — and the ISO to define practices around exchanging transfer data and setting limits on the use of dynamic transfers on the BPA system.
Since its rollout, the market has expanded farther into the Northwest to include Puget Sound Energy, with Portland General Electric slated to join later this year, followed by Idaho Power in early 2018. All three utilities rely to some extent on BPA, which controls about 70% of the transmission in the region.
“Some of [the original practices were] captured in operating procedures, but until the CTA, there was no contractual obligations regarding these requirements,” BPA said.
The agreement spells out an obligation for both parties to share transmission system data: CAISO must share total market dispatch for EIM resources during a market interval and load forecasts for EIM balancing authority areas, while BPA must convey real-time managed limits and actual flows on its facilities. The agreement clarifies the processes by which that data will be made available, including frequency and granularity.
The agreement between CAISO and Bonneville Power Administration is intended to facilitate Energy Imbalance Market transfers on Bonneville’s system, which accounts for about 70% of transmission capacity in the Northwest. | BPA
“It also includes a confidentiality provision,” Miller said. “Everybody is doing what they’re supposed to be doing, but now there’s something in the contract that makes the lawyers feel better about things.”
The agreement also codifies BPA’s right to place limits on the upward and downward rate of change in usage that EIM dynamic transfers would impose on its transmission network — making explicit an already existing practice.
“Bonneville will set the upper rate of change limit and lower rate of change limit at its discretion and notify the CAISO of such limits for each Bonneville-managed facility before each market interval,” the agreement states.
The agreement gives BPA the ability to manage system operating limits on its paths at its own discretion, but requires it to alert the ISO to any changes ahead of an interval.
It also provides for the development of “flow-relief tools” related to the EIM. Among those tools: a procedure that, in a curtailment situation, will allow BPA to transmit to CAISO the EIM’s prorated share of curtailed flows on an affected transmission flowgate between the two balancing areas.
New Groups
The CTA additionally calls for CAISO and BPA to convene a Coordinating Committee every quarter to address operational issues related to the agreement, resolve disputes and offer up potential revisions.
The agreement also establishes a working group — consisting of Pacific Northwest EIM members, a select group of BPA transmission customers and the Coordinating Committee — charged with discussing implementation, data exchange and transmission operations under the agreement.
“As far as the selected Bonneville customers, we haven’t decided how we’re going to do that yet, but we want to select customers that are representative of our various classes of transmission customers,” Miller said.
Ann Rendahl, a Washington Utilities and Transportation commissioner and chair of the BOSR, noted that the “whereas” clause at the beginning of the CTA specifies that the Coordinating Committee will discuss seams issues.
“I assume that the working group is also to discuss seams issues, but to get at them from a more granular level,” Rendahl said.
Miller agreed and said the group could also be the body that initiates other “major” types of coordination and constraint relief along the interties.
CAISO and BPA plan to file the agreement with FERC in April. “Hopefully we’ll have another FERC commissioner at some point so it can actually be approved,” Miller said.
Chairman Donna Nelson and Commissioner Ken Anderson both read prepared statements into the record during a PUC open meeting. They cited the need for strong ring-fencing provisions that would include an independent board of directors for Oncor — a requirement NextEra has called a “deal-killer.”
