Calling 2016 “very successful” and predicting 2017 will be “another transformational year,” American Electric Power CEO Nick Akins paid tribute to the late television icon Mary Tyler Moore during a Thursday conference call with financial analysts.
“In respect to the passing of Mary Tyler Moore, I will just say, we are going to make it after all,” Akins said during the company’s fourth-quarter and year-end report. “This has been a year of repositioning and de-risking the company. … We have come through with flying colors, but as a premium energy regulated company, our work is far from done.”
Akins’ optimism is fueled by the pending sale of four competitive power plants for $2.2 billion, the company’s hopes for restructuring Ohio’s electric market and possible corporate tax reform under the Trump administration.
The company reported fourth-quarter operating earnings of 67 cents/share, up almost 40% from a year earlier, which beat the Zacks consensus estimate of 55 cents/share. For the year, operating earnings were $3.94/share, up from $3.69/share a year ago. Its transmission segment contributed 54 cents to earnings for the year, an increase of more than 38%. AEP reaffirmed its 2017 operating earnings guidance range of $3.55 to $3.75/share.
Investors reacted to the news by driving AEP’s share price up 40 cents to $62.97 at Friday’s close.
Under Generally Accepted Accounting Principles (GAAP), the company reported 2016 earnings of almost $611 million, a $1.4 billion drop from 2015 that reflected its $2.3 billion write-down on its Ohio competitive generation assets in the third-quarter, as well as a federal tax audit settlement over the sale of its commercial barge operations and mark-to-market impact of hedging activities.
Akins said AEP expects to close its sale of three natural gas plants, with 2,533 MW of capacity, and the mammoth 2,665-MW Gen. James M. Gavin coal plant to Lightstone, a joint venture between The Blackstone Group and ArcLight Capital Partners, “sometime in 2017.”
AEP’s Gavin Power Plant. | AEP
Three of the gas plants are in Ohio, and the fourth, the 1,186-MW Lawrenceburg Generating Station, is just across the state line in Indiana. Akins said the company was continuing a “strategic review process” for the remaining merchant generation units.
“This was a year of reducing risk and volatility of earnings for the company in the future and reinforcing our balance sheet to provide a strong platform for future growth,” Akins said.
The CEO said the company is discussing with other utilities and stakeholders its proposed legislation to restructure Ohio’s competitive market and expects a bill to be introduced as early as the second quarter.
“AEP will not invest in new generation in Ohio unless we have a clear path to recovery of our investment, so enabling legislation is critical,” he said. “There’s already drafts of legislation that are circulating around, and we just need to make sure all the parties are comfortable with that.”
Though AEP saw signs of an improving economy in its service territory in the fourth quarter, Akins called the growth “minimal.” He said the company will continue to watch the economy closely under the new administration’s “pro-growth agenda.”
“President Trump’s focus of enhancing the ability for manufacturing industries to thrive and produce jobs … well that’s AEP’s service territory,” he said. “AEP should prosper, and we are very much looking forward to working with the Trump administration to bring prosperity and jobs back to this country.”
ALBANY, N.Y. — Audrey Zibelman was brought from Pennsylvania to New York in 2013 to lead Gov. Andrew Cuomo’s Reforming the Energy Vision initiative. But as she prepares to leave, Zibelman insists the ambitious program will survive her departure.
Zibelman surprised the state’s energy industry when her new employer, the Australian Energy Market Operator, announced her hiring a week ago. (See NYPSC Chair to Head Australia Grid Operator.)
At a news conference after the New York Public Service Commission’s Tuesday meeting, she said the offer was made barely a week before the meeting. She will preside over two more commission sessions, with her more than three-year tenure ending after the March 16 meeting.
Zibelman said she had no intention of leaving the PSC but was instead recruited by the Australian grid operator.
“This job, as chair, is a fantastic job for someone like me, who loves these industries and is always looking for ways to make things better,” she said.
She is most closely associated with the state’s ambitious REV initiative. She praised Cuomo for making tough policy decisions that will lead to a new organizational structure in the industry.
“I feel very strongly that REV is on the right track. Almost all of the key policy decisions that were needed to really start moving the industry in the direction that REV contemplates have been made,” she said, citing orders issued last week as examples. “We have really moved away from the policy conception to the implementation.” (See related stories, Con Ed Rate Order Moves REV Forward with Shared Savings and NY PSC OKs New Rules to Break Solar Interconnection Logjam.)
What Zibelman will leave behind is at least a dozen open dockets that deal with aspects of REV. These include the Clean Energy Standard and the zero-emission credits for nuclear plants, the Distribution System Implementation Platform, distributed generation compensation and several others.
On top of that, there are company- or issue-specific dockets that either predate REV and now include it, or have added REV components as they have progressed.
The PSC’s years-long grappling with how to combat alleged abuses by energy service companies is an example of the former. Its just-approved rate case with Consolidated Edison with several provisions for distributed generation, demand management and utility investment incentives were features of the latter.
But Zibelman said incumbent commissioners Gregg Sayre and Diane Burman and a strong staff would ensure no loss of momentum.
Her departure, the pending retirement of Commissioner Patricia Acampora and a two-year-long vacancy means the PSC will have three openings for new members in short order.
“At this point, the momentum is in the [energy] market. They’re leading and we’re following as they tell us where they need to go,” she said.
The decision to leave was made harder by having her husband on the other side of the world, Zibelman said. She is married to former PJM CEO Phil Harris, who for several years has led the Tres Amigas “superstation” project in New Mexico that would link the Eastern and Western Interconnections.
“It’s a personal decision we’re making, but he will continue at Tres Amigas, and we’re going to work it out,” Zibelman said.
ALBANY, N.Y. — The New York Public Service Commission last week updated interconnection rules for solar projects larger than 50 kW in an effort to break a logjam in utilities’ queues (16-E-0560).
The order sets deadlines and payment schedules for system upgrades to cull inactive projects from the queues and free up space for those projects further along in their development cycles.
The projects covered by the new rules are from above 50 kW to 2 MW. The PSC said more than 2,000 projects in that category were filed with the state’s utilities from April through December 2016. Many of those projects are community shared solar developments, intended to expand the benefits to customer pools who are unable to install solar generation on their own properties.
“These new requirements will help determine whether a proposed solar project is viable and should move forward to construction,” commission Chair Audrey Zibelman said in a statement. “Every proposal requires a lengthy, in-depth analysis to determine whether it is feasible and, too often, unrealistic projects have been getting in the way of workable proposals.”
Although it did not cite statistics, the PSC said that multiple developers have filed interconnection requests for the same projects, exacerbating the logjam.
The utilities filed a joint proposal in September that was endorsed in whole or in part by 20 stakeholders.
The new rules include fixed decision deadlines and cost-sharing requirements for the required system upgrades. Developers must prove they have exclusive permission or a land-use agreement from a property owner for a specific project.
To remain in the queue, projects with a completed coordinated electric system interconnection review must pay 25% of the system upgrade costs to the utility and execute a standard interconnection agreement.
The rules would apply to those projects currently undergoing the interconnection review along with newer projects that have had only a preliminary review. Projects that fail to comply would be removed from the queue.
Projects that have been delayed by municipal moratoria can hold their positions by either paying the 25% system cost upgrade or executing an interconnection agreement.
The order also includes an interim cost-sharing mechanism in which the first developer in an affected area pays 100% of the system upgrade costs and is reimbursed by later projects that enjoy the same benefit.
PSC staff will work on a more permanent solution, the commission said.
The plan updates the standard interconnection requirements first adopted in 1999. The requirements have been updated several times since, including last March (15-E-0557), but the queue continued to pile up.
“The interconnection queue backlog presents a serious challenge to the commission’s goals for increased solar installations, renewable power, and creating efficient markets for distributed energy resources, as contemplated in the [Reforming the Energy Vision] proceeding,” the PSC wrote.
The six investor-owned utilities — Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, National Grid, Orange & Rockland Utilities and Rochester Gas and Electric — must file tariff amendments and updated interconnection requirements that would become effective on March 1.
FERC last week denied requests for rehearing on a formula rate it approved in April for Northeast Transmission Development’s construction of a transmission line across the Delaware River (ER16-453).
A graphical depiction from PJM of the proposed line across the Delaware River
Both NTD and the Delaware Municipal Electric Corp. had requested rehearing of the order, though for opposing reasons. NTD argued the commission erred in denying it a 50-basis-point risks and challenges return on equity adder in its initial order, while DEMEC argued the commission erred in granting NTD a 50-basis-point adder for joining PJM and turning over operational control of the line to the RTO upon completion.
DEMEC had also argued that FERC erred in allowing any of NTD’s affiliates or subsidiaries to use the rate. The commission also denied this, clarifying that it applies to any affiliates or subsidiaries that may be formed in the future as well.
The efforts might all be for nothing though, as NTD’s line is part of the Artificial Island project, which has been mired in years of delay. The project — PJM’s first competitive solicitation under FERC’s Order 1000 — is undergoing reanalysis and scope changes that won’t be known until at least April. (See PJM Analysis on Artificial Island Project Delayed Again.)
FERC on Wednesday accepted transmission calculations submitted by Southwestern transmission-owning utilities in support of their requests for market-based rates in their balancing areas.
But the commission’s approval of the simultaneous import limit (SIL) values provided by the Arizona and New Mexico utilities was accompanied by pointed advice about how FERC expects SIL studies to be performed and reported in the future (ER10-2302, et al.).
| APS
The commission’s Jan. 24 decision directly affects Arizona Public Service, El Paso Electric, Public Service Company of New Mexico (PNM), Tucson Electric Power, UNS Electric and UniSource Energy Development in Arizona and New Mexico. Also included in the order, which included 10 dockets, were Public Service Company of Colorado, Northern States Power and Southwestern Public Service Co., which submitted their SIL analyses at about the same time as the Southwestern companies in an effort to help FERC expedite its approval process for such studies.
PNM’s application for market-based rate authority within its own territory was rejected by FERC in October 2015 in part because of an inadequate SIL analysis. The PNM order was issued at the same time the commission issued a rule to clarify and streamline its MBR program, the first major update to the policy since codifying it in Order 697 in 2007 (RM14-14). (See FERC Refines Market-Based Rate Rules.)
The commission said it will use the accepted SIL values when reviewing updated market analyses submitted by the Southwestern transmission owners, as well as those filed by non-transmission-owning entities in the region.
Order 697 requires a utility to perform SIL studies in order to determine the amount of available transmission capacity that can serve the utility’s home market “under the most limiting normal and single-contingency operating contingencies.” The analysis is designed to determine how transmission constraints will limit energy imports to compete with the utility controlling the area.
The study, which examines transmission links with “first-tier” — or neighboring — balancing authority areas (BAAs), is expected to provide “a reasonable simulation of historical conditions” rather than a theoretical maximum transfer capability between areas.
FERC’s order commended the Southwestern utilities, which in many cases function as first-tier BAAs for each other, for coordinating the preparation of their SIL studies and sharing SIL values with each other.
“Such a coordinated approach leads to more accurate and consistent SIL study results,” the commission said, noting that the submitted studies were “generally” done correctly. “However, our review of the SIL studies and acceptance of the SIL values was hindered and delayed because of various modeling issues and incomplete or ambiguous reporting of results.”
In light of those shortcomings, the commission outlined guidance for submitting SIL studies. FERC said future filers:
Should study system contingences in both the home and first-tier areas that are historically used and identified in the energy seller’s available transfer capability and OASIS practices documentation.
Should furnish documentation showing that the contingency lists provided align with the BAA’s OASIS practices. A “valid” contingency would consider the realistic conditions and operating procedures for the home and first-tier areas.
Must consider that, if a contingency does not solve in a powerflow simulation, it could be difficult proving that the contingency would not cause an overload somewhere within the system. That could affect SIL values, the commission said.
Should ensure the accuracy of transmission line ratings in the home and first-tier areas.
May use historical capacity factors for certain energy-limited resources, such as hydroelectric and wind capacity.
Should explain the reason for changes in SIL values from previous studies and identify significant changes in the system, such as major generation additions or retirements and construction of new high-voltage lines.
ALBANY, N.Y. — Standard utility rate cases in New York can now be expected to include innovative rate designs and programs to encourage energy efficiency and clean energy technologies following Tuesday’s action by the Public Service Commission.
In its approval of the three-year Consolidated Edison rate plan (16-E-0060, et al.), the PSC also passed a companion order that advanced the state’s Reforming the Energy Vision initiative (15-E-0229).
Heat Map of Behind-the-Meter Solar in 2015 and 2030 | NYISO
Con Ed’s March 2016 filing was in compliance with the PSC’s December 2015 Targeted Demand Management Program order, which allow utilities to propose non-wire alternative (NWA) projects that replace or defer the need for transmission and distribution infrastructure through customer-side distributed energy resources or load reductions.
The commission’s latest orders specify the utilities’ incentives for such investments, with most the financial benefits returned to ratepayers.
“This is a big step on the way to implementing REV,” Commissioner Gregg Sayre said at the meeting. “The REV orders only give us a framework and policy guidance on this process, and it’s in cases like this where the rubber meets the road and real progress is made.”
A benefit-cost analysis would be performed for any NWA, with various checkpoints set up through the approval and implementation processes to verify its viability, the order states.
The order adopts Con Ed’s proposed incentive mechanism, but the commission reduced the utility’s proposal of a 50-50 split of the benefits between shareholders and ratepayers. The order provides 30% of the net benefits to shareholders and 70% to ratepayers.
“As the commission articulated in the REV Track Two Order, incentive opportunities should be financially meaningful and structured such that they encourage enterprise-wide attention at the utility and spur strategic, portfolio-level approaches beyond narrow programs,” the order states. “Further, incentive opportunities should be commensurate with the level of financial risk borne by utility shareholders.
| Edison
“The 30% sharing adopted here represents a financially meaningful incentive opportunity that should encourage Con Edison to pursue the innovative portfolio-level approach to implementing NWA projects, while producing significant net benefits to customers and reflecting the financial risk required of Con Edison shareholders,” the order continues.
Commissioner Diane Burman abstained on the Con Ed order, “consistent with my past voting record.”
Burman says she prefers a “holistic approach” rather than deal with these items individually. “I think there’s a lot here that is affecting other items that are still policy decisions that have not had finality, and we will work through that,” she said.
Con Ed is already using demand management in a pilot program, the Brooklyn-Queens Demand Management program. It deferred a $1.2 billion substation with a combination of energy efficiency, DERs and demand response. (See Overheard at the NYISO Distributed Energy Resource Workshop.)
A new, “expedited” CAISO initiative seeks to establish a process for selecting and procuring black start resources, needed to restore segments of California’s transmission system in the event of regional outages.
The effort will follow an ambitious timeline: The ISO hopes to present a plan to its Board of Governors for approval in May.
The initiative represents the second phase of a 2013 undertaking to address NERC reliability standard EOP-005-2, which required transmission operators to draw up plans for system restoration in the event of widespread blackouts.
The ISO decided to explore the procurement issue after identifying a need for additional black start resources in the transmission-constrained San Francisco Bay Area.
CAISO’s black start procurement initiative was prompted by the need to better prepare the transmission-constrained San Francisco area for system restoration. | SF Travel
“This need is the impetus for this stakeholder initiative,” Scott Vaughan, CAISO lead grid assets engineer, said during a Jan. 24 call to kick off the effort.
CAISO staff have determined that, unlike in Southern California, where black start resources are more evenly distributed near major load centers and can provide more rapid restoration, resources serving the Bay Area are relatively far from population centers.
Under current practice, ISO and transmission owner restoration plans rely on black start resources either owned by a utility or acquired through a long-term contract. For a TO plan, a utility is able to recover the costs for resources through retail rates. Generation providing black start capability under the ISO’s plans are subject to a three-party agreement among the ISO, the applicable TO and the generator for a zero-price term.
Still, CAISO’s Tariff allows it to enter into black start service contracts for payment. If specific costs are not outlined in a contract, then the resource will be paid as exceptional — or out-of-market — dispatch and is entitled to bid cost recovery. The Tariff also outlines that scheduling coordinators can be required to pay for the service.
The new initiative would likely modify the current approach to procuring black start capability by ensuring that costs are spread beyond just the transmission-owning utility.
“Any such procurement would benefit all transmission customers in the area, yet may not result in the allocation of costs to all transmission customers if procured by the investor-owned utility,” said an ISO issue paper, released Jan. 17, in reference to the Bay Area’s specific need. “For instance, non-bundled customers taking service from a community choice aggregator, electric service provider or municipal utility in the area that rely on the black start capability may not face any cost allocation.”
CAISO has floated two ideas for cost allocation. The first would have the ISO enter black start contracts and charge all scheduling coordinators, rather than specific TO areas, for incremental black start capability. The other idea would entail it shifting cost allocation to local transmission access charge areas and recovering the costs from TOs as reliability service costs.
The Bay Area, however, poses unique challenges for black start procurement. One is the lack of eligible resources there.
“The ISO has said that there is a relatively small set of units from which this service could be procured,” said Brian Theaker, director of market affairs at NRG Energy. “Will the ISO disclose what that subset of units is?”
CAISO staff were reluctant to wade into that aspect of the issue before laying out a framework for procurement.
“At this point, we were not planning on getting into any more of the details around the specific requirement in the area or how we would go about procuring,” said Neil Millar, CAISO executive director of infrastructure development. “The goal right now is to land on the cost allocation process and the procurement process itself that would set out how we would go about doing this.”
Robert Jenkins of Flynn Resource Consultants picked up on Theaker’s theme.
“I was looking for what kind of characteristics is the ISO valuing in identifying this small number of units,” Jenkins said. “Is it geography? Is it size? Is it connectivity” to the ISO’s system? He added that he would be interested in learning more about the scope of the market when that information became available.
Millar responded by offering some qualifications, pointing out that CAISO wanted stakeholders to consider the procurement issue within the context of the relatively small number of resources eligible to participate in the market.
“It’s not a case of any generator located anywhere in the system,” Millar said. “Location does matter very much and there’s a relatively small subset, so that could affect people’s input on how we should go about planning this procurement process to pick a couple of units out of a relatively small subset.”
Bonnie Blair, a consultant representing the “Six Cities” utilities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside, pressed the ISO on the importance of the location of the resources.
Millar explained the “piecemeal” approach of restoring a part of the system after a blackout. The ISO starts by first bringing up a black start resource, then energizing individual transmission lines and “picking up other generators, a bit of load, more generators, then more load” to reach into the affected areas.
“So as you keep considering sources further and further away, you quickly get to where the time it would take to do all those steps wipes out the benefit of getting the resource in the first place,” Millar said.
Paul Nelson, electricity market design manager at Southern California Edison, wanted more specifics on the timeframe for acquiring the resources.
“Is this something that needs to be done in 2017, 2018?” Nelson asked. “Because that impacts the approaches for procuring it.”
“We’d like to have some sort of contractual arrangement by the beginning of 2018 or end of 2017,” Vaughan replied, adding that the small set of potential resources are not identified as black start capable and would likely require upgrades.
Theaker questioned whether the ISO schedule for completing the initiative was realistic, given the need to deal with issues of “compensation, context, structure and cost allocation,” as well as to draw up a straw proposal.
“It’s highly aggressive, but I think it is realistic,” Vaughan responded.
“Then I’d encourage you to identify some near-term milestones in terms of what has to be in place [and] when, in order to get this ready — not only for the board meeting in May, but also lay out the milestones for getting [resources procured by January 2018], as we’ve just discussed,” Theaker said.
Comments on the issue paper must be submitted to CAISO by Jan. 31. The ISO will publish a straw proposal Feb. 14.
WASHINGTON — President Trump on Thursday appointed Commissioner Cheryl LaFleur as acting FERC chair, replacing Norman Bay.
Hours after the announcement, Bay said he would resign his post Feb. 3, 16 months before the end of his term.
Bay’s departure, announced in a six-page letter reciting the agency’s recent accomplishments, will leave the commission with only LaFleur and fellow Democrat Colette Honorable — one member short of the three-person quorum required to issue other than routine orders. (See related story, Backlog, Delays Feared as FERC Loses Quorum.)
That will add urgency to the need to fill the three vacant Republican seats on the five-member panel. It could allow the reappointment of Honorable, whose term expires June 30 and was otherwise expected to be replaced by a Republican.
Calling his service on the commission “the greatest honor and privilege of my professional life,” Bay praised his fellow commissioners and the “dedicated and talented career staff” with whom he had worked.
“The last few years have brought dramatic change to the energy space. The shale revolution and an abundance of low-priced natural gas, technological innovation, the expanded use of renewable energy, increased energy efficiency and flat load growth, state and federal public policy, and consumer choice have been drivers for change,” Bay said. “As chairman, I have sought to help consumers realize the benefits from this change, while assisting the wholesale markets and industry in adapting to the change and maintaining just and reasonable rates and reliability.”
LaFleur’s Focus
LaFleur said she will remain focused on the same priorities as before: system reliability, grid security, transmission, energy supply diversity “and trying to adapt competitive markets to some of the state initiatives that we’ve seen.”
“While I recognize that FERC is in a state of transition as we await nominations to fill vacant seats at the agency, it is important that FERC’s work on the nation’s energy markets and infrastructure move forward,” she said in a statement. “I would particularly like to thank Chairman Norman Bay for his leadership of the commission over the past two years, and I look forward to working with him, Commissioner Colette Honorable, the terrific staff throughout the agency and future colleagues at FERC to continue to address the important energy issues facing our nation.”
Honorable issued a statement Monday praising Bay for his “grace and humility.”
“His leadership was critical for our continued work on gas and electric coordination, competitive transmission development, price formation and energy storage,” she said. “The utility sector is in the midst of profound change, and former Chairman Bay made certain that the commission kept pace and did not leave consumers behind.”
Republican Distrust
LaFleur’s appointment as acting chair suggests Bay never overcame the distrust of Republican congressional leaders, who had sought to keep LaFleur in the top spot she had ascended to after Jon Wellinghoff’s departure in November 2013.
President Barack Obama nominated Bay as chairman in a move engineered by then-Senate Majority Leader Harry Reid (D-Nev.), who publicly said he did not want LaFleur as chairman.
Bay was confirmed on a 52-45 party-line vote in July 2014, following a deal with the White House that delayed his move to the chairmanship for nine months. LaFleur was confirmed to a second term at the same time by a 90-7 vote.
Cheryl LaFleur and Norman Bay being sworn in at their Senate confirmation hearing in May 2014.
The deal was a concession to those who questioned why Bay — who had served as director of FERC’s Office of Enforcement since 2009 but had never served as a state utility regulator — would be appointed directly to the chairmanship over LaFleur, a former utility executive who has served on the commission since 2010. The last five chairmen before then had served a median of 30 months before becoming chair.
Bay also came under fire for what some energy lawyers and legislators called his heavy-handed running of the commission’s enforcement division.
Bay’s appointment to the chairmanship was strongly opposed by Sen. Lisa Murkowski (R-Alaska), ranking member at the time, now chairman of the Senate Energy and Natural Resources Committee. Sen. Mitch McConnell (R-Ky.), now Senate majority leader, said he feared Bay would be a “rubber stamp for the [Obama] administration’s anti-coal agenda.” (See At FERC, Uncertainty Remains Despite Norman Bay’s Nod.)
Republican Majority Coming
LaFleur acknowledged that her return to the center seat at the commissioners’ table is likely temporary. In a podcast posted Monday, she said that her appointment and Bay’s resignation made for “a pretty strange week.”
“I’d already decided to serve out my term,” she said. “I’ve been part of the Democratic majority ever since I’ve been here, and I knew that going forward I would be part of a Democratic minority, and if I was going to be here, and asked to lead, I thought I should.”
Although the commission has not traditionally been marked by partisan divisions, the president gets to appoint members of his party to three of the five seats and to pick the chairman. Since Republicans Philip Moeller and Tony Clark left, the five-member panel has been all Democrats.
Carolyn Elefant, a former FERC attorney advisor and partner at a D.C. law firm specializing in energy regulatory issues, wondered why the Trump administration didn’t have a Republican ready to fill the slot immediately. “I cannot recall a time in my 27 years of FERC practice that the commission has been down to two members,” she said.
“I know that Sen. Murkowski has posted a statement on the Senate Energy Committee website about the importance of filling the seats promptly, but I don’t know how much pull she has with the administration,” Elefant said.
“The fact that Commissioner LaFleur — a Democratic appointee — was elevated to the chairmanship suggests to me that the administration hasn’t given much thought to FERC appointments; if it had, I would have expected a Republican nominee for chairman right out of the gate.”
Differences over Enforcement
LaFleur and Bay have always been cordial publicly, regardless of which one of them held the gavel. But they have had differences on policy.
When Bay was enforcement chief, FERC won more than $670 million in fines and disgorged profits from Morgan Stanley, Constellation Energy, Deutsche Bank and JPMorgan Chase.
Although LaFleur supported all of the settlements Bay brought to the commission, the two have not always seen eye-to-eye. In response to questions from the Senate, LaFleur detailed seven cases in which she issued separate concurrences or dissented from the majority on matters such as the way the commission applied its penalty guidelines or when it would share deposition transcripts with investigation targets.
Subjects in four of the cases LaFleur cited were represented by former FERC General Counsel William Scherman, who coauthored an Energy Law Journal article in May 2014 accusing Bay’s unit of ignoring subjects’ due process rights. Scherman and some other members of the energy bar had been criticizing Bay’s enforcement tactics privately and in industry forums for months.
The criticism became louder when the principals of Powhatan Energy Fund, which had been under investigation by Bay’s unit for three years without being charged, released documents they say prove they had been unfairly hounded.
On Bay’s last day as enforcement chief in August 2014 — before his swearing in to the commission — FERC issued a “notice of alleged violations” against Powhatan and its principals accusing them of market manipulation for making riskless back-to-back up-to-congestion trades to profit on line-loss rebates. In May 2015, the commission ordered Powhatan and its leaders to pay $34.5 million in penalties and disgorged profits in the case (IN15-3). The company is fighting the case in U.S. District Court for the Eastern District of Virginia.
Policy Changes?
Elefant said that once the Trump administration installs its three new members, FERC is likely to act swiftly to undo many of Bay’s enforcement initiatives. “I think that many of his aggressive enforcement policies will be dismantled — if not immediately, then once other commissioners are appointed,” she said.
But attorney Ken Irvin, co-leader of Sidley Austin’s global energy practice, said he doesn’t see anti-manipulation enforcement being significantly curtailed. “They’ve made a robust effort and collected a lot of monetary penalties,” he said in a statement. “I don’t expect to see any let-up.”
The Long Island Power Authority on Wednesday approved a contract for a 90-MW offshore wind farm, by far the largest such facility contemplated in the U.S.
The site, 30 miles off the island’s Southern Fork, is the first part of a wind development in federally leased waters that could support up to 1,000 MW of offshore wind.
Gov. Andrew Cuomo two weeks ago proposed the state develop 2,400 MW of offshore wind in various sites off Long Island to support the goal of 50% renewable energy by 2030. He also prompted the LIPA Board of Trustees to act on contract negotiations that had stalled since the summer. (See Cuomo Proposes 2,400 MW of Offshore Wind by 2030.)
The wind farm could provide enough electricity to power 50,000 homes. If the Cuomo proposal is realized, as many as 1.25 million homes could be powered.
The wind farm developer, Deepwater Wind, built the nation’s first offshore wind farm off Block Island in Rhode Island, which was commissioned last month.
The LIPA board approved a contract submitted by Deepwater Wind for the South Fork Wind Farm after a yearlong process. Offshore wind was the lowest-cost option in the request for proposals from LIPA, beating out natural gas generation.
Neither LIPA nor Deepwater released contract terms on Wednesday.
The 20-year power purchase agreement includes a pay-for-performance clause, which allows LIPA to only pay for delivered energy, eliminating operating and construction risk, the authority said. LIPA said technology improvements reduced the project’s “all-in” energy costs to be competitive with other renewable energy sources.
“Depending on the schedule for permitting, construction could start as early as 2019, and the wind farm could be operational as early as 2022,” Deepwater spokeswoman Meaghan Wims told RTO Insider.
LIPA CEO Tom Falcone said in a statement, “We are confident this is the first step to developing the tremendous potential of offshore wind off Long Island’s coast and meeting Gov. Cuomo’s Clean Energy Standard. This project is the right size, at the right location and demonstrates how smart energy decisions can reduce cost while providing renewable energy and clean air for all of Long Island.”
Elizabeth Gordon, director of the New York Offshore Wind Alliance, said, “LIPA’s 90-MW South Fork project moves New York to the forefront of offshore wind development in America. Major progress on what will be the nation’s largest offshore wind project, combined with Gov. Cuomo’s 2,400-MW commitment, makes it clear that New York is entering a new energy era — one where offshore wind power is poised to play a key role in meeting downstate’s electricity needs.”
FERC last week approved NYISO’s revised demand curves but said the ISO must eliminate the assumption that new peaking plants in the New York Control Area (NYCA) will require emissions controls (ER17-386).
The Jan. 17 order approved NYISO’s Nov. 18 proposal on all but one of nine contested issues. The new demand curves will take effect with the ISO’s capacity auction for the 2017/18 capability year beginning May 1 and will be the basis for auctions through the 2020/21 delivery year. (See IPPNY: Demand Curve Reset ‘Top Priority’.)
The ISO will continue to use the F class frame peaking turbine as the proxy unit for setting the cost of new entry. It also continued the requirement that peaking plants include dual-fuel capability and selective catalytic reduction (SCR) emissions controls for the New York City, Long Island and G-J Locality demand curves.
But the commission rejected the ISO’s proposal to extend the SCR requirement to the NYCA, where gas-only designs were permitted.
The curves, calculated for NYISO by consulting firm Analysis Group, suggest increased prices in most zones, with Zones G-J starting at about $22/kW-year, up from less than $20 for 2014/15. Long Island’s curve starts at almost $25, versus about $21 in the previous curve. The New York City curve is virtually unchanged with a $26 starting point.
The NYCA curve would have jumped from a starting point of about $14 to almost $20.
In its last demand curve reset, the ISO proposed that the NYCA peaking plant operate under an annual operating hours limit in lieu of installing SCR emissions controls. FERC said that assumption still holds, despite the ISO’s contention that peakers without the controls risk not obtaining necessary air permits.
“It is undisputed that SCR emissions controls are not required for peaking plants located in load zones C and F in NYCA,” the commission said. “In addition, NYISO admits that the F class frame turbine can meet the New Source Performance Standard requirement to limit nitrogen oxides emissions while operating on natural gas without SCR emissions controls.”
The ISO acknowledged that F class turbines can meet New Source Performance Standards for carbon dioxide emissions without SCR controls by limiting their operations to 3,300 hours annually, a capacity factor limit of 38%.
The Independent Power Producers of New York joined the ISO in calling for the SCR inclusion, contending that increasing concern in New York over fossil fuels will pressure the state’s Siting Board to require tougher controls.
FERC said their position was “speculative,” quoting from its order in the last reset that “while there is always a risk that regulations will change in the future, we cannot base the finding of viability on speculation that the EPA or New York state regulators will act at some point in the future.”
It noted that the demand curve reset process takes place every four years “so that changed circumstances, such as new regulations, can be taken into account.”
“We find more compelling the statements from [the New York State Department of Environmental Conservation] and evidence that New York state has issued air permits and Article 10 certificates for electric generators without SCR emissions controls in recent years. Specifically, NYSDEC stated in its comments to the NYISO Board of Directors that its permit reviews are fact specific, so SCR emissions controls to limit nitrogen oxides emissions “may not be required or appropriate in every case, such as where other control measures are available or where a facility accepts federally enforceable permit conditions to limit emissions below the applicable thresholds.
“We are more persuaded by NYSDEC’s comments and N.Y. Siting Board precedent than speculation about future public involvement in [plant] certification proceedings,” the commission said.
The commission ordered the ISO to file a revised Tariff within 30 days removing the SCR requirement for NYCA.
FERC otherwise approved the ISO’s filing as is, siding with it on the choice of the F class turbine, peaking plant costs, property tax treatment, natural gas forecasts, and incorporation of shortage pricing into the net energy and ancillary services revenues assumptions.
The auction for the 2017 summer capability period (May 1- Oct. 31) will be conducted March 30-31, with results posted April 4.
