The Society for the Protection of New Hampshire Forests has appealed the dismissal of its complaint against the Northern Pass transmission project to the New Hampshire Supreme Court.
The Coos County Superior Court last month dismissed the group’s suit, which sought to prevent the burial of lines in a highway right of way. The society said its property rights allowed it to deny access, even though it had granted rights of way for above-ground construction. (See Court Dismisses Complaint vs. Northern Pass.)
Revised path for Northern Pass shows buried sections in yellow.
“We believe strongly that the Superior Court erred by not getting to the root of the private property rights issue in its decision,” Forest Society attorney Tom Masland said.
He said the Superior Court ruling that dismissed the suit sidestepped legal questions about the property rights of the Forest Society by deferring to transportation officials.
“The N.H. Department of Transportation does not have the authority to determine the property rights of landowners affected by a project like Northern Pass,” Masland said. “By failing to address that issue now — nor allowing the issue to be litigated — landowners like the Forest Society would be left with no remedy. This is a complex case, and important issues remain unresolved, including the complexities and ramifications of declaring DOT the sole authority to resolve all matters involving the use of roads.”
Project developer Eversource Energy said it was confident it will prevail in the appeal.
“The New Hampshire Superior Court spoke clearly and decisively on May 25 when it dismissed the Forest Society’s lawsuit that claimed that the Northern Pass project does not have the right to bury the project under public roads in the North Country,” the company said in a statement. “The court’s summary judgment decision was based on over a century of New Hampshire law. We are confident that the state Supreme Court will uphold the Superior Court’s ruling.”
Eversource and its partner Hydro-Quebec have proposed to bury 60 miles of the 192-mile route. The project is being reviewed by the New Hampshire Site Evaluation Committee. (See Northern Pass Decision Delayed Nine Months.)
WILLIAMSBURG, Va. — As of last year, 17 states had smart meter penetration of 50% or more. Yet only seven states — Maryland, Delaware, Arizona, Oklahoma, Ohio, Arkansas and Louisiana — have more than 5% of their residential customers enrolled in time-varying rate plans, according to the Energy Information Administration.
The reason for states’ halting progress was the subject of a session moderated by Maryland Public Service Commissioner Anne Hoskins at the Mid-Atlantic Conference of Regulatory Utilities Commissioners Education Conference last week.
Leah Gibbons, director of regulatory affairs for NRG Retail Northeast, said consumers’ wariness of time-of-use rates and the speed of technological changes are arguments for retail competition.
“The real reason for relying on retail markets … is because consumer needs and desires are a very quickly evolving thing. People change their minds on what they want and what they need all the time. And the best way to meet those needs is through the innovation of competitive markets. … The regulated model simply is not equipped to deal with that pace and keep up.
“We still don’t know what are customers really going to want. What are they going to go for?” she asked, citing the experience in Texas and some experiments in the Northeast. “Customers really do not like big price spreads that you get in a time-of-use rate. … They’re kind of afraid of it. But you really need to have a decent price spread between on- and off-peak to get customers to change their behavior and actually shift their load. So … we’re going to have to figure out: How do you get customers to choose those kinds of products? Or does it make sense to think more about demand response products?”
Gladys Brown, chair of the Pennsylvania Public Utility Commission, said many of the state’s industrial customers are already on TOU rates and that the commission is now focused on expanding the option to residential ratepayers to take advantage of its 2008 law mandating smart meters. The PUC says about 40% of its 5.7 million residential customers now have advanced meters.
A PPL Energy pilot program that began in 2011 was suspended after less than a year after an unexpected increase in spot market prices resulted in both on-peak and off-peak prices being below the fixed-price default service, resulting in undercollections (P-2013-2389572). When prices rose above the default rate, customers fled the program.
“It started out slowly,” Brown said. But she said regulators hope that with “full deployment of smart meters that we’ll have a lot of different programs.”
Rich Sedano, director of U.S. programs for the Regulatory Assistance Project, said that in addition to reducing peak demand, TOU rates can influence customers’ willingness to add solar panels or a high-efficiency water heater. “The marginal costs of the system are something that customers are typically not aware of if they are in a flat-rate situation, but with time-varying rates they can be made aware of that. And their investments can actually be replacing utility investments,” he said.
William Fields, senior assistant for the Maryland Office of People’s Counsel, questioned whether TOU rates are compelling enough to motivate consumers, citing Pepco’s current TOU rates: 9.6 cents/kWh on-peak; 7.7 cents/kWh off-peak; and 8.2 cents/kWh intermediate.
“In this low-gas-cost, relatively high-capacity-cost … environment, is there really a big difference there?” he asked. “We just want to express some caution that we take a very close look at whether there’s value there to make it worth it.”
The first step is to obtain better data, he said. “One of the frustrations I’ve had … is the limited amount of really good customer data — usage for residential customers, different size houses, apartments,” he said. “I think the [advanced metering infrastructure] that we have should be looked at as an opportunity to collect some better data on things like how does overall usage correlate to [peak] demand? … Do smaller-usage customers have small demand and large-usage customers have large demand?”
WILLIAMSBURG, Va. — More than 300 regulators, PJM officials and industry stakeholders attended the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ 21st Annual Education Conference last week. Here are some highlights.
Haque Reflects on Year as MACRUC President
Public Utilities Commission of Ohio Chairman Asim Haque reflected on his year as president of MACRUC as he prepared to hand the gavel to incoming president and New Jersey Board of Public Utilities Commissioner Mary-Anna Holden.
Haque acknowledged obstacles in executing his theme for the year: “lead together, lead now.”
His tenure coincided with a bruising battle in Ohio over FirstEnergy’s and American Electric Power’s requests for financial support for their merchant generation. At the same time, Exelon’s acquisition of Pepco Holdings Inc. split commission members in D.C. and Maryland.
“What I’ve come to find this past year is that each of our states’ challenges, while possibly common, are layered in so much subtext,” Haque said. “Most often that subtext can be unique to that particular state. The subtext can be existing law, the makeup and strength of various stakeholders in the state, the political tenor, varying financial interests…
“Finding the answers that are universally acceptable to each of our states is incredibly challenging,” he continued. “If you can’t find universally acceptable answers, then most certainly you won’t be able to lead now.”
‘CEO Panel’ Compares Notes
In the “CEO Panel,” executives from AEP, Pepco and NiSource discussed their challenges in response to questions from moderators Judith Jagdmann, of the Virginia State Corporation Commission, and Richard Mroz, president of the New Jersey BPU.
Robert Powers, COO of AEP, and David Velazquez, CEO of Pepco, shared their experiences operating in multiple jurisdictions. AEP has distribution utilities in seven states in SPP, ERCOT and PJM. In March, Pepco became part of Exelon, which now has distribution operations in five states and D.C. within PJM.
Powers said AEP’s geographical diversity gives the company “opportunities to experiment” on initiatives in one location before proposing them elsewhere. AEP’s philosophy is to “put strong people locally who don’t always have to come to [AEP headquarters in] Columbus for every decision,” he said.
Velazquez said dealing with multiple commissions prevents the company from rolling out initiatives such as smart meters and smart grids in all of its territories at once because of the need to “sell” them to state regulators individually.
On the other hand, he said, “As we get feedback, it helps us … refine and make better the product we’re offering. … So there’s pluses and minuses.”
Carl Levander, executive vice president for regulatory policy and corporate affairs for NiSource, said his company faces a challenge in maintaining institutional knowledge because 23% of its workforce is eligible for retirement and another 29% has at least 20 years’ experience — while a quarter of the employees have less than three years’ tenure.
Levander said that his company, the parent of Northern Indiana Public Service Co. and Columbia Gas, is not interested in expanding into services, such as home security, that other utilities have tried. “We’ve made a decision to be a very boring company — and we have the right people running it,” he said, prompting laughter.
CAISO last week stepped up efforts to convert skeptics of a Western RTO, convening a forum in Denver to discuss a proposed set of governing principles and dispel concerns that California interests would dominate a West-wide entity.
“What we’re doing actually matters, and it has enormous upsides,” CAISO board member Ashutosh Bhagwat said of the effort.
CAISO is leading the push for an RTO in the West, in part driven by a 2015 California law requiring the grid operator and state energy agencies to explore ISO expansion to improve the state’s ability to meet its 50% renewable energy mandate.
The ISO also seeks to accommodate the timelines of PacifiCorp, which hopes to join the ISO in 2019 but must gain regulatory approval from five Western states before doing so.
Bhagwat said the diversity of resources in an expanded ISO would improve renewable integration and reduce costs for customers in California and the broader region.
EIM Experience
“Experience with the [Energy Imbalance Market] has proven this,” Bhagwat said. “We’re doing this because there is a lot to be gained.”
Contending that the West is “behind the rest of the country” in creating an RTO, Bhagwat also acknowledged “legitimate concerns” among Western industry stakeholders about how the organization would be governed.
“We’ve tried to address them,” he told the forum, referring to the ISO’s proposed principles for governance, which would seek to preserve state regulatory authority, provide all participating states the means to influence RTO policy and reshape the ISO into an entity no longer overly subject to the prerogatives of California.
Still, RTO skeptics — and some supporters — contended that an expanded ISO would be overly subject to California’s influence even with the principles in place.
They cited one major sticking point: the transition to an independent and regionally representative board of directors.
CAISO’s proposal calls for the RTO’s initial board to include the five members of the ISO’s current board and four new members selected by other RTO states through a process approved by those states. Initial board members would have terms staggered in such a way that California-appointed members would always hold a majority through a transition period.
That transition would conclude with the initial board selecting a final, independent board through a nominating process developed by a transitional committee of stakeholders. The nominating process — along with other governance elements proposed by the committee — would be subject to approval by the initial board.
A second sticking point: The transitional committee itself would be appointed by the ISO’s current board.
‘The Mother of all California-Centric Concerns’
“The proposal for the initial board is the mother of all California-centric concerns,” said Bryce Freeman, administrator of the Wyoming Office of Consumer Advocate.
Freeman pointed out that the proposal did not provide an explicit deadline for the transition period, meaning the current ISO board would constitute a majority for an unspecified amount of time. Any policies “hammered out under that arrangement would be accountable to the California political process,” he said.
Freeman also noted that the five PacifiCorp states would be forced to jockey for just four seats on the initial board.
Governing principles for a Western RTO will initially need buy-in from the five states containing PacifiCorp’s service territories.
“Whose ox gets gored in that process?” he asked.
“When we get to the final stage of things, California still gets what I’ve been calling a veto over everything anyway,” added Abby Briggerman, an attorney representing inland industrial energy consumers in the West.
Continued reliance on the ISO’s current board is also the American Wind Energy Association’s biggest concern, said Caitlin Liotiris, a consultant representing the organization, which is a strong supporter of the expansion.
Montana Public Service Commissioner Travis Kavulla echoed Freeman’s concerns about the open-ended nature of the initial board. He said it would have more influence on governance than the final board, as governance design would actually be developed and approved during the transition period.
Market-Oriented Board
Kavulla instead suggested the establishment of a market-oriented board populated by members with expertise in electricity market operations, while the “big questions” regarding tariff design and governance would be left to another body.
“That leaves the more complex matters of market design to the people actually running the ISO,” said Kavulla, the current president of the National Association of Regulatory Utility Commissioners.
While Kavulla didn’t specify what body should have authority over the tariff and governance issues, CAISO’s proposal calls for the formation of a body of state regulators “to provide policy direction and input on matters of collective state interest.”
That body would be funded by the RTO but incorporated as a separate entity, with one regulator from each state serving as a voting member. Publicly owned utilities (POUs) within the RTO footprint would appoint one nonvoting representative to act in an advisory capacity.
CAISO intends for the body of state regulators to have “primary authority” over RTO initiatives related to matters like transmission cost allocation and “aspects” of resource adequacy — meaning the RTO would be required to seek the body’s approval for any Section 205 filing with FERC.
“It has been noted that this body has a lot of reserve authority and power,” Kavulla said, adding that it should be staffed with experts to advise its members and support that authority.
Public Power Role
Mark Gendron, Bonneville Power Administration (BPA) senior vice president of power services, suggested a full voting role for the public power representatives.
“That might be a good home for BPA as a [federal power marketing agency],” said Gendron, whose organization operates 78% of the transmission in the Northwest and markets the output from 31 hydroelectric projects.
Gendron’s suggestion received support from Marshall Empey, COO of Utah Associated Municipal Power Systems, which represents community-owned utilities throughout the West.
“The reason we want this as public power is that regulators don’t represent us,” Empey said.
Steve Beuning, director of market operations at Xcel Energy, voiced a different perspective.
“I’m concerned to think of any stakeholder that might have more of a stake than me — such as public power getting a defined role,” Beuning said.
Kavulla noted that the interests of POUs are represented on the state committees of other RTOs. None of those committees set aside a seat for POUs.
“That level of trust might not exist in the West,” he added, referring to the fact that the region’s public utility districts are not subject to state oversight and maintain an arms-length relationship with utility commissions.
Briggerman spotlighted what she considered to be yet another flaw in the design of the state body: a provision that policy changes would require not just a majority vote, but approval by members representing a majority of load in the RTO footprint. California would hold a clear majority in an RTO that includes just PacifiCorp.
“This just sort of echoes my general theme that California has too much authority in this proposal,” Briggerman said.
“At the end of the day, [a Western RTO] is going to take mutual trust between California and non-California,” Kavulla said.
Hunt Consolidated’s bid for Texas utility Oncor may not be over after all.
The Hunt group filed a lawsuit Thursday in state court against the Public Utility Commission of Texas, seeking a review of its March order that accepted the proposed acquisition but imposed restrictions that led to the deal’s unraveling.
The lawsuit says the PUC made a number of errors in its ruling on plans to split Oncor into two companies and incorporate a real estate investment trust (REIT) structure (Docket No. 45188).
The order approved the creation of Oncor AssetCo, which would own the transmission and distribution facilities, while Oncor Electric Delivery Co. (OEDC) would rent the facilities to provide electric delivery services. As a REIT, AssetCo would avoid paying federal income taxes if it derived at least 90% of its profits from property rents.
But the PUC’s order included conditions that made it less attractive to investors, including requiring federal tax savings be set aside for possible refunds to customers. The REIT structure would have allowed Hunt to funnel as much as $250 million a year in tax savings to shareholders.
According to the lawsuit, the PUC “prejudiced” the group’s rights by finding the leases between the Oncor companies would be tariffs subject to commission approval; by not treating AssetCo and OEDC on a consolidated basis for ratemaking purposes; by failing to give the restructured Oncor the standard income tax allowance; and by failing to vacate the final order and dismiss the docket.
The lawsuit says the PUC made “administrative findings, inferences, conclusions and decisions” in violation of the state Public Utility Regulatory Act and that were not “reasonably supported by substantial evidence in the record.”
“Because the merger agreement terminated, there was no longer a transaction for the PUCT to approve,” the lawsuit says. “At that time, the PUCT still had jurisdiction over the final order. … Therefore, the PUCT should have vacated the final order and dismissed the proceeding without prejudice. This would have avoided the errors.”
“It sounds like they want to reopen the case, which is confusing at best,” said PUC spokesman Terry Hadley when notified of the lawsuit Thursday evening. “This is unusual.”
“Businesses often file appeals within the court system to preserve their legal rights going forward,” Hunt spokesperson Jeanne Phillips said in a statement. “That is the intent here.”
The Hunt bid appeared to be dead in May, when the PUC rejected all motions for rehearing in the case and let its March order stand. The Hunt group and creditors of Oncor’s bankrupt parent, Energy Future Holdings, had asked the commission to vacate the order and dismiss the proceeding, thus leaving open the possibility of a new application. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)
A litigation analyst for Bloomberg Intelligence, Julia Winters, told Bloomberg News that if the Dallas-based Hunt group’s lawsuit is successful, “there’s a chance they would get back to the negotiating table with the debtors and move forward on a deal to buy Oncor.”
“It would be a lot easier to move forward with the plan that was already on the table and approved by the bankruptcy court,” Winters said.
The Hunt group has been pursuing an acquisition of Oncor, the largest transmission and distribution utility in Texas, for several years. Oncor is widely seen as the key to EFH’s bid to restructure almost $50 billion in debt and emerge from two years of bankruptcy. (See EFH Files New Chapter 11 Plan.)
NextEra Energy is also thought to be a potential suitor.
The original plan EFH filed with a Delaware bankruptcy court included a Hunt-led purchase of Oncor for more than $17 billion.
Hadley said the PUC would have no additional response to the lawsuit. It will be represented in the proceeding by the Texas attorney general’s office.
Pacific Gas and Electric said Tuesday it will shut down California’s last nuclear power plant in 2025 under an agreement reached with a coalition of environmental, labor and anti-nuclear groups.
The utility said it will develop a portfolio of renewable resources, energy efficiency and energy storage to replace output from its 2,240-MW Diablo Canyon facility, located on the state’s central coast near Avila Beach.
That condition was a victory for environmental groups that had opposed the plant on safety grounds but wanted to avoid an outcome in which gas-fired generation would replace the plant’s greenhouse gas-free output.
“It will be the first nuclear power plant retirement to be conditioned on full replacement with lower-cost, zero-carbon resources,” said the Natural Resources Defense Council, one of the parties that negotiated the agreement.
PG&E’s Diablo Canyon nuclear plant is the utility’s single largest source of energy production. Source: PG&E
Other parties included Friends of the Earth, Environment California, International Brotherhood of Electrical Workers Local 1245, the Coalition of California Utility Employees and the Alliance for Nuclear Responsibility.
Under the proposal, the company would also commit to serving 55% of its customer load with renewables by 2031.
The state’s revised renewable portfolio standard, enacted last year, calls for 50% renewables by 2030. PG&E cited the RPS, the recent doubling of state energy efficiency goals, growth of distributed energy resources and the potential loss of retail customers to alternative suppliers known as community choice aggregators as key factors in the decision to retire the facility.
Quake Risk
Environmentalists have long been concerned with the plant’s location near several earthquake fault lines, including one 3 miles from the plant that was discovered three years after construction began in 1968. Calls for its closure were renewed after the 2011 quake and tsunami that led to a meltdown at the Fukushima Daiichi nuclear plant in Japan.
Another major consideration: the inability of a baseload plant like Diablo Canyon — which cannot be quickly cycled up and down — to respond to the “overgeneration and intermittency conditions” stemming from increased penetration of solar and wind resources.
In response to the 50% RPS, CAISO will put a premium on the capability to respond to renewables’ variability. The ISO is currently developing a “flexible ramping” product to encourage the development of resources to fulfill that need.
Diablo Canyon accounts for about 20% of annual electricity production in PG&E’s service territory and 9% of production in the state. While the utility points out the plant is currently needed to help maintain system reliability, it said that its absence will reduce the need for solar curtailments during peak solar production and improve the integration of RPS resources.
“California’s energy landscape is changing dramatically with energy efficiency, renewables and storage being central to the state’s energy policy,” PG&E CEO Tony Earley said. “As we make this transition, Diablo Canyon’s full output will no longer be required.”
2025 Retirement Assumed
The California Public Utilities Commission has not yet asked CAISO to perform any special studies related to the retirement, ISO spokesman Steven Greenlee told RTO Insider.
CAISO’s 2016-17 transmission planning process — which looks 10 years into the future — already assumes Diablo Canyon will be retired by 2025 because of state restrictions on “once-through cooling,” the process of drawing coastal or river water to cool turbines. That water is then expelled back into the environment at higher temperatures, affecting marine life. State regulators required the plant to end the practice by 2024.
Any reliability issues stemming from retirement will be identified in the current transmission planning analysis, according to the ISO.
“We will not present a recommendation [on retirement], but PG&E’s decision allows the ISO to begin planning for a grid without Diablo Canyon and a grid that better integrates renewable resources in support of the state’s goals,” Greenlee said. In 2009, PG&E filed with the Nuclear Regulatory Commission to extend the licenses for Diablo Canyon’s two reactors for an additional 20 years. This week’s proposal stipulates that the company will ask to suspend that proceeding. In return, the other parties to the agreement promised not to seek the facility’s closure before the last license expires in August 2025.
They also agreed not to oppose PG&E’s efforts to fully recover costs for the shutdown from California ratepayers. That stipulation requires the parties “to not oppose amortization and cost recovery of Diablo Canyon’s costs in PG&E’s 2017 general rate case” submitted to the PUC.
The agreement is subject to approval by the PUC. PG&E has asked regulators to render a decision by Dec. 31, 2017.
Groups opposing FirstEnergy’s plan to win subsidies from Ohio regulators asked FERC last week to again intervene in the dispute (EL16-34, et al.).
The Electric Power Supply Association, Dynegy, NRG Energy and others filed a joint protest, asking FERC to block the company’s revised bid to win revenues from Ohio ratepayers for its merchant generation. The Sierra Club, the Environmental Defense Fund and the Ohio Consumers’ Counsel also filed protests.
FirstEnergy asked the Public Utilities Commission of Ohio in May to withdraw an eight-year power purchase agreement — in which the company’s regulated utilities would purchase output from the company’s merchant generators — after FERC ruled April 27 that the PPA, and one for American Electric Power, would be subject to its affiliate abuse review.
FirstEnergy’s Davis Besse Nuclear Power Plant Source: Wikipedia
The modified plan “would allow for the same transfer of captive customer money to market-regulated affiliates and shareholders, but without the affiliate PPA that initially triggered FERC jurisdiction,” the EPSA petitioners wrote last week. “In short, [First Energy Services] and the FirstEnergy [electric distribution utilities] are attempting to achieve the same result as their initial proposal, while evading the commission review mandated by the April 27 order.”
While they did not mention the Ohio situation specifically, the companies said PJM’s markets manage resource adequacy just fine on their own.
“What PJM’s markets have not done — and should not do — is provide protection for certain suppliers who want to be shielded from market risk,” the companies told the board. “Generators that are unable to compete because their facilities are inefficient or their operating costs are too high must make rational business decisions about their future operations, but PJM should not feel compelled to change its market rules to protect them.”
They further urged the RTO to educate policymakers about the negative effects their proposals can have when they interfere with the markets.
The Sierra Club urged FERC to “not allow this brazen end-run” around the commission’s review.
“With their latest gambit, FES and the FirstEnergy EDUs apparently think that they can achieve the same results as their initial plan while evading FERC review by simply eliminating the affiliate PPA,” the Sierra Club wrote. “The modified plan poses the same threat to the commission’s affiliate transaction rules as does the affiliate PPA.”
The Environmental Defense Fund filed similar arguments and spread the word through a blog post.
“It’s not usually a good idea to dis federal regulators,” wrote Dick Munson, EDF’s director of Midwest Clean Energy. “FirstEnergy doesn’t seem to care.
“The utility does deserve credit for persistence and creativity, yet its new proposal doesn’t even pass the laugh test,” Munson continued. “To avoid FERC jurisdiction, for instance, FirstEnergy now claims its subsidy will no longer guarantee the operation of its uneconomic power plants. Yet the utility’s new surcharge is contingent on the continued operation of virtually the same number of megawatts of its nuclear and fossil generation.”
Ohio Consumers’ Counsel Bruce Weston also weighed in, asking FERC to order FirstEnergy to “show cause why it should not be found to be in violation of the Federal Power Act, FERC’s [April 27] order and/or FERC’s affiliate restrictions regulations.”
FirstEnergy’s modified request “strictly involves adjustments to retail electric rates, which is designed to be solely under the jurisdiction of the PUCO,” company spokesman Doug Colafella said. “The objective of our plan — safeguarding our customers against long-term price increases and volatility — can still be achieved without a purchased power agreement.”
The Delaware House of Representatives last week unanimously passed a resolution aimed at blocking a proposed stability fix for New Jersey’s Artificial Island nuclear complex that could raise bills for the state’s ratepayers.
House Concurrent Resolution 89, sponsored by Energy Committee Chair Trey Paradee, directs the state Department of Natural Resources and Environmental Control to deny any easement request related to the project as long as the current cost allocation is in place.
That formula assigns $354 million of the $410.5 million project to customers in Delaware and on the Delmarva Peninsula, according to the resolution.
Under the proposal, an average residential customer could expect to see an extra $1 to $3 on their monthly electric bill. The charge would be much higher for commercial customers.
“This could cost businesses thousands of dollars a month and burden local residents for something that will not benefit them,” Paradee said. “That’s the definition of a bad deal. We might not have been successful in appealing to FERC, but we have the final say when it comes to environmental permitting.”
The project calls for the construction of a transmission line that will be buried beneath the Delaware River connecting Artificial Island to Delaware with the goal of improving reliability on the grid.
“Under current project plans, an easement will be sought from the Department of Natural Resources and Environmental Control to connect the line on the Augustine Wildlife Area … and the Augustine Wildlife Area is a renowned deer and waterfowl habitat in Delaware,” the resolution states.
When asked if the resolution could kill the project, Sharon Segner of LS Power, which is constructing the marine crossing, responded, “Absolutely not. It is a nonbinding resolution that must be passed by both the House and Senate in Delaware. A Delaware resolution does not have the force of law. In addition, a resolution expires at the end of the legislative session, which is in two weeks in Delaware.
“We continue to support the Delaware Public Service Commission’s efforts in addressing the cost allocation for the Artificial Island project, as this is the real challenge for Delaware. We hope FERC grants both the rehearing request of the Delaware PSC and LS Power.” (See Stakeholders Ask FERC to Rehear Cost Allocation Order.)
PJM issued a statement urging policymakers not to delay the project. “We are sympathetic to the concerns about cost allocation, which must be resolved by the federal commission,” it said. “It would be unfortunate to delay this necessary project and its reliability benefits.”
Following complaints about the cost allocation for this project as well as the proposed Bergen-Linden Corridor upgrade, FERC held a technical conference in January. It asked: Is there a definable category of projects for which the DFAX method might not be appropriate, and could a fair approach be developed for those occasions? The commission on April 22 upheld the cost allocation for both projects. (See FERC Upholds Cost Allocation for Artificial Island, Bergen-Linden Projects.)
The Artificial Island project faces other hurdles. After Public Service Electric and Gas submitted estimates nearly doubling the cost of its scope of work to $272 million, PJM planners decided to consider alternate configurations. One is to terminate the new transmission line at Hope Creek instead of Salem. However, if the scope of the work is changed substantially, it could require PJM to solicit new bids under FERC Order 1000. (See Artificial Island Cost Increase Could Lead to Rebid.)
Three competitive transmission developers asked FERC last week to order NYISO to issue a new request for proposals for transmission upgrades to alleviate congestion and bring renewable energy downstate (EL16-84).
The RFP was issued in February in response to a New York Public Service Commission order that declared a public policy need for two projects in the Mohawk and Hudson valleys to deliver energy to load centers in and around New York City. (See NYPSC Directs NYISO to Seek Tx Bids.)
The developers — Boundless Energy NE, CityGreen Transmission and Miller Bros. — say NYISO violated its Tariff and FERC directives under Order 1000 when it solicited projects without conducting its own review and instead deferred to state regulators.
“We are filing a petition with FERC because the NYISO violated its FERC tariff by inappropriately deferring to the New York Public Service Commission rather than follow its FERC-approved transmission planning function,” Boundless President Rod Lenfest said in a statement.
“Based on FERC’s own guidelines, the NYPSC has a limited role in the energy transmission planning process. While that planning process allows the NYPSC to identify to the NYISO the transmission needs for the state, here the NYPSC went even further and pushed for a particular project solution to meet those needs. Rather than consider these projects along with other alternatives that could reduce costs for consumers, the NYISO decided to consider only proposals for the particular projects identified by the NYPSC.”
The developers asked FERC “to confirm that the NYISO, not the NYPSC, is the entity that is required to study and identify the specific project solutions.”
The plaintiffs said the ISO should follow its normal study process — including its base assumptions and generator dispatch modeling — to consider competing solutions without excluding specific technologies or relying on the PSC’s assumptions and modeling.
Developers’ proposals, which were submitted in late April, are currently being evaluated by NYISO staff.
Boundless CEO E. John Tompkins said in an affidavit that the company is seeking a stay of the solicitation process in the appellate division of the state Supreme Court.
The company participated in an evaluation of potential projects last year by NYPSC staff in its AC Transmission initiative. But staff recommended that the developer be disqualified because its proposals were deemed to be not cost-effective. (See NYPSC Staff Recommends $1.2B in Transmission Projects.) Boundless also sought a rehearing of the NYPSC order that declared the public policy need, but that petition was denied in February.
Earlier this month, NYISO named 10 project finalists in a concurrent public policy proceeding designed to alleviate congestion in the Buffalo area. (See NYISO Identifies 10 Public Policy Tx Projects.)
WASHINGTON — New wind generators will be required to provide reactive power following a FERC order last week eliminating their exemption from having to provide the service (RM16-1).
Inverters, necessary for wind turbines to provide reactive power, have become much less expensive since FERC exempted the resource from having to provide the service.
Reactive power, essential for controlling the voltage of the grid, can be measured at three points: the generator itself, the generator substation or the point of interconnection. Synchronous generators’ reactive power is measured at the interconnection point.
The commission’s order revises the commission’s pro forma generator interconnection agreements — both small and large — to require nonsynchronous generators’ reactor power to be measured at the high side of generator substations. In its Notice of Proposed Rulemaking in November, FERC had proposed the interconnection point, but it was persuaded by commenters who said doing so would require additional investment in equipment.
FERC issued the wind exemption in Order 661 in 2005 because it was concerned that the cost of the technology needed to provide reactive power would inhibit the development of the resource. Improvements in that technology since then have made it far less expensive, and FERC said that continuing the exemption could result in insufficient reactive power as wind power grows and traditional synchronous generation retires.
Order 661 did not exempt other types of nonsynchronous generation, such solar, but FERC has been treating them similarly to wind on a case-by-case basis. The commission has sometimes required that balancing authorities demonstrate that the lack of reactive power from a non-wind, nonsynchronous generator would threaten reliability before requiring it to provide the service.
The new requirements apply to all new nonsynchronous generators, regardless of type, that have not executed a facilities study agreement as of 90 days after publication in the Federal Register. They would not apply to existing generators, including those making upgrades that require new interconnection requests. FERC said these provisions would allow generators to complete the interconnection process without delay or extra costs.
FERC approved the new requirements at Thursday’s meeting, which was open to the public again after the commission closed it last month. (See Pipeline Protesters Force FERC to Close Monthly Meeting.) Staff’s presentation of the order was interrupted by two protesters, who urged the commission to halt approval of natural gas pipelines.
“There’s a certain irony here because the protesters interrupted a presentation by staff on commission work that can enable a higher degree of penetration by wind resources while maintaining reliability,” Chairman Norman Bay said in response. “This final rule will ensure comparable and nondiscriminatory treatment of both traditional resources and new resources, such as wind and solar, in the provision of reactive power, while recognizing that some technological differences remain.”
“Today’s rule recognizes that wind and other nonsynchronous generators, which are an increasingly important part of the fleet, now have the technical ability to provide reactive power at reasonable cost, and so they’ll now be required to do so,” Commissioner Cheryl LaFleur said. “I think today’s rule highlights that wind and solar are no longer just niche technologies.”
