The New England Power Generators Association (NEPGA) on Monday filed a request for rehearing of FERC’s Oct. 6 order accepting ISO-NE’s updated cost of new entry value for the RTO’s capacity auctions (ER17-795).
ISO-NE is required to recalculate the values every three years and will apply the revisions in next February’s Forward Capacity Auction 12 covering the 2021/22 capacity commitment period, as well as in FCAs 13 and 14. (See FERC Approves ISO-NE CONE, Offer Trigger Updates.)
The Brayton Point Power Station in Somerset, MA went offline in June 2017.
In its Nov. 6 filing, NEPGA specified several perceived errors in FERC’s order and asked the commission to reconsider its previous finding that a net CONE value based on simple cycle generator technology is just and reasonable. The group instead favors basing that value on the costs needed to support a combined cycle turbine. It is asking the commission to change the rules in time for FCA 12, which begins Feb. 7, 2018.
NEPGA contended that the order was “arbitrary and capricious and not the product of reasoned decision-making” because the commission did not balance the financial interests of capacity providers against the “substantial” benefits conferred to load. The group also argued that the commission failed to consider the record of evidence indicating that simple cycle generators are not likely to be built in New England.
The $8.04/kW-month net CONE value proposed by the grid operator will cause a $1.5 billion reduction in market-wide capacity revenues at equilibrium from FCA 11 to FCA 12, which for a 500-MW capacity resource means a $22.8 million cut in capacity revenues in a single year, and more than $67 million during the three years covered by the auction, NEPGA said.
The filing did not seek to change the commission’s approval of offer review trigger price (ORTP) values, which were also part of the order.
CAISO is facing pressure from some stakeholders to broaden the scope of its latest effort intended to increase the participation of energy storage and distributed energy resources in its market.
The ISO is in the beginning stages of its Energy Storage and Distributed Energy Resources (ESDER) Phase 3 initiative, kicked off in September with an issue paper that will be developed into a straw proposal. (See CAISO Load-Shifting Product to Target Energy Storage.) Participants in the effort include companies such as eMotorWerks, Stem, investor-owned utilities and the California Energy Storage Alliance.
Energy storage company STEM is participating in CAISO’s ESDER Phase 3 | STEM
ESDER Phase 2 unearthed several issues for Phase 3, most which are touched on in the issue paper. Based on stakeholder input, CAISO is proposing that the latest initiative cover rule changes that would relax limitations on how demand response can participate in the market, as well as the integration of distributed resources, microgrids and electric vehicle charging infrastructure. The effort could also explore “multiple-use applications” for energy storage, which recognize the ability of those resources to provide services and receive revenue from more than one entity at a time, such as at the wholesale, transmission and distribution levels.
Developing electric vehicle charging equipment load curtailment as a proxy demand resource is one aspect of ESDER Phase 3 | emotorwerks
In a Nov. 6 conference call, the ISO asked stakeholders to prioritize among a list of six topics listed in the issue paper regarding changes to demand response rules, which provide a point of market entry for distributed resources. Those topics include how to handle challenges such as setting start-up and minimum/maximum load costs, dealing with variability of weather-sensitive DR, refining DR aggregation rules and others.
CAISO representatives at various points in the call indicated they do not want to delve too deeply into one particular focus area of the initiative, which includes many complex challenges in implementing new technologies and market products.
But Robert Anderson — chief technology officer for Olivine, a DR and DER services company — urged the ISO not to require commenters to choose among the six topics for the DR portion of the initiative, but instead cover them all.
“When is ESDER Phase 4?” Anderson asked rhetorically. “The question is: ‘When do we get another chance at this?’ I am very optimistic that you guys can take on a lot more than you think.” Instead of a slower approach to the proposals, “maybe we can get through them very quickly, and get them done and get them behind us,” he said.
Margaret Miller of Customized Energy Solutions said the microgrid sector is not well-represented in the stakeholder process, and there are a lot of unanswered questions as to how microgrids will participate in wholesale markets.
“There are decisions made today that could unduly limit those microgrids from participating,” she said, calling for policy guidance in ESDER 3 or elsewhere. “Otherwise, we are continuing to address these on a one-off basis.”
CAISO External Affairs Officer Peter Colussy said microgrids are being studied in other processes. ESDER 3 is aimed at looking at different technologies and platforms to provide various services, not focusing too much on one technology, he said.
“We are not trying to focus on microgrids here,” Colussy said.
The CAISO Board of Governors in July approved ESDER Phase 2, which is still pending approval by FERC. (See New CAISO Rules Spell Increased DER Role.) That initiative developed a set of alternative energy usage baselines to assess the performance of proxy demand resources, which are DER aggregations of retail customers. It also developed new rules that distinguish between charging energy and station power for storage resources, and created a net benefits test for DR resources that participate in the Western Energy Imbalance Market (EIM).
FERC on Tuesday agreed to sharply reduce the penalty Barclays Bank must pay to settle claims that it manipulated Western electricity markets a decade ago.
The commission approved a settlement agreement requiring the U.K.-based company to pay $105 million in penalties after company traders engaged in a two-year scheme to influence physical power prices at certain trading hubs in the West in order to benefit from their positions in financial swaps covering those same markets (IN08-8). The illegal trades occurred from November 2006 to December 2008, and involved the Mid-Columbia, NP-15, SP-15 and Palo Verde delivery points.
FERC accused Barclays traders of influencing prices at the Mid-Columbia, NP-15, SP-15 and Palo Verde trading hubs in order to benefit the bank’s positions in financial swaps covering those markets. | EIA
The agreement represents a significant comedown for FERC, which in July 2013 levied a record $470 million fine against Barclays, which included a requirement that the bank disgorge nearly $35 million in profits from the scheme. Those proceeds were to be paid into the low-income home energy assistance programs (LIHEAPs) of Arizona, California, Oregon and Washington. Former FERC Chairman Norman Bay was director of the commission’s Office of Enforcement at the time.
Barclays challenged the penalty in federal court, and Tuesday’s settlement indicates the bank largely prevailed in its nearly five-year legal battle with FERC. Under the terms of the agreement, the bank will pay just $70 million in civil penalties, though it must still relinquish its profits from the scheme, just over half of which will be directed to the LIHEAPs. The company and its traders did not admit nor deny committing any violations against the commission’s anti-manipulation rules.
“The commission concludes that the agreement is a fair and equitable resolution of the matters concerned and is in the public interest, as it reflects the nature and seriousness of the conduct and recognizes the specific considerations stated [in the order] and in the agreement,” FERC wrote in its decision to approve the order.
One critic of the settlement strongly disagreed with FERC’s take.
“FERC’s action is an outrage and sends a clear signal to market manipulators: Crime will now pay,” Tyson Slocum, director of Public Citizen’s energy program, said in a statement.
Slocum said the “egregious” settlement did not occur in isolation but instead points to a broader development in which FERC “may be getting soft on rule-breakers.” As evidence, he cited the recent appointment of General Counsel James Danly, who previously served on the legal team defending Dynegy in market manipulation case brought by Public Citizen (EL15-70). One of Danly’s former law partners has written articles “attacking” Bay’s enforcement actions and appointment as chair, Slocum pointed out.
“Consumers have benefited from FERC’s aggressive enforcement of wrongdoers,” Slocum said. “The evisceration of the Barclays settlement, when combined with key staffing decisions at FERC, may signal that the days of tough enforcement on banks, hedge funds and other energy traders may be coming to an end.”
Slocum called for Congress to hold an oversight hearing on FERC operations to ensure that consumers are protected from energy market manipulation.
David Applebaum, an attorney who previously served as director of investigations in the Office of Enforcement, told Bloomberg that FERC’s move was “inevitable” after a federal judge in September ruled the agency had waited too long to bring its case against Ryan Smith, one of the Barclays traders involved in the scheme. Smith, along with fellow traders Karen Levine and Daniel Brin, initially faced penalties of $1 million each, while their manager, Scott Connelly, was ordered to pay $15 million.
“I think once the Smith decision came out, it was inevitable that FERC would have to reduce its damages and civil penalties significantly,” Applebaum said.
Levine, Brin and Connelly were covered under Tuesday’s settlement.
ERCOT on Monday approved Luminant’s proposal to dispose of nearly 2,300 MW of coal-fired generation capacity in Texas.
The ISO’s reliability assessments determined that none of the four units at the company’s Big Brown and Sandow plants was “required to support ERCOT transmission system reliability.”
ERCOT said the Texas grid is undergoing “significant change,” with new technologies “changing the role that some older generation resources play in grid and market operations.” The ISO said lower natural gas prices have been reducing revenues for all generators in recent years, and wind and solar resources continue to flood the market.
As of Oct. 30, ERCOT has nearly 48 GW of new generation projects under study, and more than 21 GW of new projects have interconnection agreements. That includes more than 10 GW of proposed gas-fired projects, 2 GW of utility-scale solar and more than 8.7 GW of wind projects.
ERCOT has said it will have almost 81 GW of total capacity available this winter, more than enough to meet a projected peak of more than 61 GW. It will update the expected reserve margins for 2018 and the next several years in the next Capacity, Demand, and Reserves Report, scheduled for Dec. 18.
The Public Utility Commission of Texas has also directed the ISO to study and consider the appropriate level of reserves needed to maintain reliability while minimizing costs in its energy-only market.
Big Brown’s two units date back to the early 1970s and are capable of 1,150 MW of output. Vistra has said it is exploring a sale of the site north of Houston, but the plant will be shut down if it hasn’t been sold by Feb. 12, 2018.
Sandow’s units date back to 1981 and 2009 and have 1,137 MW of capacity. They will be closed Jan. 11.
Combined with the earlier retirement of Monticello’s three coal units, Luminant will have shuttered 4,167 MW of coal capacity by early next year — more than half of its 8,000 MW of available capacity. The company has only two coal plants left: Martin Lake (2,250 MW) in East Texas and Oak Grove (1,600 MW) in the southern part of the state.
Exelon will relinquish four Texas natural gas plants to its lenders and pay $60 million to keep a fifth plant in the latest response to what the company called “historically low power prices” in the state.
The plans were detailed in a Chapter 11 bankruptcy filing Nov. 7 by ExGen Texas Power, Exelon’s merchant generation business in Texas, and in an 8-K filing by Exelon. It follows Vistra Energy’s announcements last month that it would retire 4,100 MW of coal-fired generation in the state.
The 738-MW Wolf Hollow facility in Granbury, Texas, is one of the four power plants in the state Exelon will sell as part of the bankruptcy of its ExGen Texas Power subsidiary. | GE Power
Exelon said it made the bankruptcy filing to offload most of a $675 million loan due in September 2021. “Pending a competitive bidding process,” the company said in a statement, it will pay $60 million to lenders to keep its 1,265-MW Handley Generating Plant in Fort Worth.
“Lenders have agreed to exchange the debt they currently hold in EGTP’s other four plants for equity in the plants, effectively taking ownership of these facilities,” Exelon said.
The company told the Securities and Exchange Commission that it expects a pre-tax gain of $125 million to $200 million in the fourth quarter off the sale. It had recorded pre-tax impairment charges of $418 million in the second quarter of 2017 and $40 million in the third quarter for the plants.
The other four plants are the 738-MW Wolf Hollow combined cycle facility in Granbury; the 510-MW Colorado Bend combined cycle in Wharton; the 808-MW Mountain Creek steam boiler in Dallas; and the 156-MW simple cycle facility in La Porte.
The company has been seeking to sell its Texas fleet since at least March, when Reuters reported that it had hired a debt restructuring adviser to help it evaluate its options. This followed a January decision by Moody’s Investors Services to downgrade EGTP’s debt from B2 to Caa1.
Exelon’s stock closed at $41.27/share Tuesday, up 1.45% from Monday’s close.
Independent Market Monitor Beth Garza told ERCOT’s Board of Directors last month that the Vistra retirements will result in higher prices and lower capacity margins, citing two years of “clearly unsustainably low prices with high reserve margins.” (See ERCOT IMM: ‘Fat and Happy’ Times Ending with Coal Closures.)
Nuclear and coal generators made their closing argument for price supports Tuesday, as opponents urged FERC to reject the proposal or let RTO stakeholders take up the resilience debate.
Tuesday was the deadline for reply comments in response to the Department of Energy’s Notice of Proposed Rulemaking, which called for cost-of-service pricing for coal and nuclear generators in competitive markets (RM18-1). The deadline for initial comments was Oct. 23. (See FERC Flooded with Comments on DOE NOPR.)
The Rule of Three
Three-step proposals were all the rage in the latest filings, with the Nuclear Energy Institute calling for a cost-of-service mechanism to prevent “premature” retirements, an order requiring RTOs to promptly improve their price formation rules, and a long-term program for ensuring that organized markets value resilience.
Exelon, which is the beneficiary of nuclear subsidies in Illinois and New York, had its own three-step proposal, starting with “immediate action” to correct “inaccurate price signals [for] fuel-secure resources,” including ordering PJM to make energy market reforms within 90 days. RTOs and ISOs also would be prevented from mitigating the capacity market bids of plants receiving zero-emission credits “or other support payments.”
FERC should follow those actions, the company argued, with an order requiring RTOs to report on their systems’ vulnerabilities to high-impact, low-frequency events. Lastly, it said the commission should use that data, “together with threat analysis from the national security and intelligence communities, to establish a design basis threat (DBT) that can inform cost-effective market reforms.” The DBT would provide a resilience benchmark and a basis for developing solutions, the company said.
The last two steps of Advanced Energy Management Alliance’s proposal were like those of Exelon’s, with the opening of a resilience proceeding and reporting by RTOs.
But the group, which represents distributed energy resource companies and storage providers, had its own idea for step one: “Eliminate barriers to storage and distributed energy resource participation” by finalizing FERC’s November 2016 NOPR (RM16-23). (See FERC Rule Would Boost Energy Storage, DER.)
The commission received hundreds of responses to the DOE NOPR. FERC staffer Patrick Clarey told the SPP Board of Directors meeting Oct. 24 that the commission had received more than 700 comments; AEMA said it had counted “roughly 750 sets of comments.”
Congress Weighs in
Among the most recent responses were dueling submissions from members of Congress, with Republicans generally supporting the proposal and Democrats mostly in opposition.
Illinois Republican Reps. Mike Bost, Rodney Davis and Darin LaHood said “the proposed DOE rule makes critical strides toward correcting faulty market designs and valuing the role of baseload generation.”
Rep. Joyce Beatty (D-Ohio) joined with David Joyce and 10 other Ohio Republicans to warn that premature plant closings “have resulted in an electrical grid with weakened resiliency and a diminished ability to respond to crisis.”
New Jersey Republican Reps. Frank LoBiondo and Leonard Lance expressed fear that the state could lose its nuclear generation — the source of almost half of its electricity.
Hope Creek Nuclear Generating Station in New Jersey
Rep. Jerry McNerney (D-Calif.) and 13 other Democrats from his state, Pennsylvania, Hawaii, New York, Massachusetts, North Carolina, Virginia and Vermont expressed “serious concerns with the proposal and its timeline.”
They cited DOE data showing outages resulting from extreme weather increased 10-fold from 1984 to 2012 and doubled between 2003 and 2014. “Given these facts and the compounding, regional and varied effects of climate change on extreme weather, a one-size-fits-all approach to resiliency, as outlined in the NOPR, is inappropriate and not adequate to the challenge,” they said.
House Energy Subcommittee Vice Chair Pete Olson (R-Texas) joined with ranking member Bobby Rush (D-Ill.) to say more time is needed to study the “remarkably complex issue.” They said it should be addressed “through existing proceedings at the federal and regional level rather than quickly moving to make a sweeping, top-down decision in the near term.”
“FERC — with bipartisan support from members of Congress and presidents — have worked for decades to improve these markets. Ultimately, this has given us markets that provide a reliable and resilient power system through open competition. This has also meant that risks are borne by investors in generating assets, not consumers or taxpayers. We continue to believe this is critically important,” they said.
Among those also registering support for the NOPR were the Interior Department, Southern Co. and AES (parent of Indianapolis Power & Light, Dayton Power and Light and AES Energy Storage).
Opponents Urge Time for Study
In contrast, the Electricity Consumers Resource Council and other industrial energy users said the NOPR would “overturn decades of precedent and suddenly determine the existing RTO/ISO tariffs are unjust and unreasonable.”
A broad coalition including the American Petroleum Institute, American Wind Energy Association, Conservation Law Foundation and Electric Power Supply Association reiterated its earlier comments, urging FERC to reject what they called an “abrupt and unjustified cost-based compensation mechanism.”
The National Association of State Utility Consumer Advocates, which had not filed initial comments, said acting on DOE’s demand for a final rule within 60 days would violate the Administrative Procedure Act by failing to provide the public with adequate notice or reasonable time to have meaningful input.
ISO-NE said the “very limited time” FERC allowed for reply comments did “not permit a comprehensive rebuttal to the efforts of the NOPR’s supporters to overcome the proposal’s unsound foundation.”
“However, in-depth analysis is not needed to understand why the proposal is both legally untenable and an unviable policy option,” the RTO said. “The breadth and depth of opposition to the NOPR among industry stakeholders and electricity consumers is striking in its own right.”
American Municipal Power also cited procedural concerns. “Several other commenters suggested that the commission adopt alternative proposals to modify the RTO energy market rules or take other actions that are beyond what was contemplated by the DOE proposal. The commission cannot lawfully accept such proposals as part of this rulemaking process.”
Former FERC Chairman Norman Bay made a similar point at the GTM U.S. Power and Renewables Summit in Austin, Texas, Tuesday.
“The timeline really amounts to a rocket docket. There’s no other way to describe it,” Bay said. “When you look at FERC Order 888, FERC spent a year on that particular order. In the normal course of events, it’s not uncommon to see a rulemaking take 12-15 months, or even longer than that,” Bay said.
AMP also agreed with many critics that the DOE proposal failed to prove existing RTO market rules are unjust and unreasonable. “The legal deficiencies coupled with the practical reality that the DOE proposal would not resolve the reliability concerns raised by the secretary but would impose significant new costs on customers should make this an easy call for the commission,” AMP said.
The Environmental Defense Fund urged FERC to “further enhance gas-electric coordination in a focused and targeted manner.”
“Electric generators were the smallest sector for natural gas demand in 1988, and they now are the largest,” EDF said. “But the natural gas regulatory framework has not kept pace with this new development.”
Next Steps
The commission has said it expects to take some action on the proposal within 60 days after its Oct. 10 publication in the Federal Register.
FERC will address the NOPR with a full complement of commissioners, thanks to the Senate’s Nov. 2 confirmation of Republican Kevin McIntyre and Democrat Richard Glick.
Tom Kleckner and Michael Kuser contributed to this article.
VALLEY FORGE, Pa. — PJM and its Independent Market Monitor provided updates to their capacity market redesign proposals at last week’s meeting of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF), but the discussion was dominated by the question of when the group should recommend any rule changes.
Proponents for load — including American Municipal Power, Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition (ICC) and the PJM Public Power Coalition (PPC), the Organization of PJM States and the Consumer Advocates of the PJM States (CAPS) — argued that the decision should be delayed until after FERC responds to the Department of Energy’s Notice of Proposed Rulemaking for coal and nuclear price supports. The commission has said it expects to take some action on the proposal within 60 days after its Oct. 10 publication in the Federal Register.
Generators urged staying on the task force’s current timeline of having a proposal selected to file with FERC by the end of the year. “By putting things off, we just slow down the process,” Calpine’s David “Scarp” Scarpignato said.
Monitor Joe Bowring called for stakeholders to take the lead on how FERC responds to the NOPR.
“What you say does affect the process,” he said. “I would urge you all not to think of yourselves as passive consumers of what FERC is doing. They’re looking for guidance as well.”
Load representatives, however, said they didn’t have enough information to make an informed choice.
“Boy, I don’t have anything among any of these proposals that I can say, ‘This is what’s going to be best for the market and my customers’ future,’” said Carl Johnson, who represents the PPC.
Joe DeLosa, of the Delaware Public Service Commission, said there has been some difficulty in evaluating proposals. “We feel the time is not appropriate to move forward with proposals,” he said.
Morris Schreim, of the Maryland Public Service Commission, asked about a commitment he said PJM made to perform an analysis of the most popular proposals. At a meeting in August, staff agreed to research possible solutions to several stakeholder concerns, including a request from ODEC’s Adrien Ford to substitute data from recent Base Residual Auctions into PJM’s model of the proposals. (See PJM Stakeholders Begin Defining Capacity Design Needs.)
PJM’s Adam Keech responded to Schreim that he remembers another meeting where staff “pretty clearly” said they would not be performing modeling.
RTO officials acknowledged the concerns of load but remained focused on the current timeline.
“I believe it’s important for this group to keep working forward,” PJM’s Suzanne Daugherty said.
PJM Revises Reference Price
PJM revised the reference price in its proposal for undefined subsidies. Previously, it was calculated using a formula for a competitive offer: the net cost of new entry multiplied by the expected average balancing ratio for the delivery year. The RTO has revised it to a “capacity repricing value” that is based on resource type and whether it’s new or existing. That value is used to resort the generation offers in the second, price-setting stage of PJM’s proposal.
The RTO presented its methodology for calculating the default values along with example values for delivery year 2021/22 measured in gross dollars. An existing combined cycle gas turbine’s value would be $84 per ICAP MW-day, while a new unit would be $501. Onshore wind would be $65 and $998, respectively.
“What we’re trying to do is determine what the market price should be for that year,” PJM’s Rich Brown explained.
Stakeholders asked Brown to provide a comparison of how reference prices change under PJM’s previous proposal and the new “capacity repricing values.”
Bowring didn’t need any comparisons.
“This is entirely inconsistent with the Capacity Performance paradigm,” he said.
The Monitor revised its proposal to expand one of the exemptions to its extended minimum offer price rule (MOPR) proposal. The renewable portfolio standard exemption would be extended to all competitive, non-discriminatory, state-mandated programs and not just competitive auctions. The IMM is also planning to adjust its public power exemption to allow supply to be “slightly” greater than 105% of demand for a year “to recognize that investment can be lumpy,” Bowring said.
Several load proponents, including Ford, AMP’s Steve Lieberman and Susan Bruce, representing the PJM ICC, thanked Bowring for his willingness to adjust his proposal.
“We don’t think repricing is the right answer,” Ford said, acknowledging that ODEC’s proposal, which has been retracted, included repricing. “We’re really appreciative, Joe, that you’re listening to some of the concerns expressed here in the CCPPSTF and finding ways to modify what we think is a fairly pure market proposal as opposed to an administrative, two-stage approach.”
“Certainly, we continue to believe that the time is not appropriate to move forward, especially with the NOPR out there, but we appreciate the efforts that have been made to try to frame the issue,” Bruce said. “I am not at all suggesting that the time is never. … We live in a time of more uncertainty than I’ve seen. … We’re going to see some guidance from FERC soon, and I think that is going to be an important touchstone.”
Greg Poulos, the executive director of CAPS, said some state advocates are questioning why stakeholders are “all of a sudden” focused on revising the capacity market after nuclear units in one PJM state — Illinois — received price support, particularly when they believe there will not be any new subsidies for generators. He said there is “growing support” among the advocates for the Monitor’s revisions.
“It’s definitely getting more favor from the advocate groups,” he said.
The remaining proposals — from NRG Energy, LS Power, Exelon, AMP, Northern Virginia Electric Cooperative and the Natural Resources Defense Council’s Sustainable FERC Project — had no new revisions.
Poulos expressed advocates’ concerns about “gaming” the repricing structures, and asked representatives from LS and NRG, who have also submitted repricing proposals, whether they have examined how their proposals prevent gaming and how their protections compare to other repricing proposals. The representatives said they have not noticed or been alerted to any concerns.
“We don’t see a meaningful distinction between all the repricing proposals,” Bowring said. “We think they’re all subject to the kinds of issues that were raised by [Poulos].”
FERC may consider additional changes to its hydropower licensing rules following a review prompted by President Trump’s March 2017 executive order to eliminate burdens on domestic power production.
Executive Order 13783, “Promoting Energy Independence and Economic Growth,” required executive branch officials to review their regulations, orders and policies and eliminate those that “unduly burden the development of domestic energy resources.”
On Nov. 1, FERC published in the Federal Register a 30-page report in response, saying it had found several potential changes involving its hydropower rules that the commission may consider. Commission staff emphasized that, as an independent agency, it was not required to respond to the order but was doing so voluntarily.
The report said “the vast majority of agency actions relating to the commission’s hydropower program do not present a material burden.”
But it said the commission “could consider” revising its regulations to:
Make optional the integrated licensing process (ILP), which is currently the default — requiring applicants to justify the use of the traditional licensing process or the alternative licensing process;
Make optional the requirement to submit a draft license application or preliminary licensing proposal before submitting a final license application as part of the prefiling process;
Reducing comment and filing deadlines to save three months in the three- to three-and-a-half-year process for obtaining an integrated license;
Increasing the threshold — currently 5 MW — for eligibility for the “simplified and expeditious licensing procedure for small hydroelectric power projects” under the Public Utility Regulatory Policies Act;
Removing the requirement that facilities eligible for license exemptions under PURPA Section 405 install or increase the capacity of their facilities;
“Explicitly” allow applicants for small hydropower exemptions to convert their exemption applications to a license application if the exemption is rejected; and
Allow hydro operators whose license applications are rejected to resubmit their applications once the deficiencies are corrected.
Next Steps up to Commission
FERC spokeswoman Mary O’Driscoll emphasized that the response is a FERC staff report. “The commission itself will determine what steps to take on any and all matters related to this,” she said in an email. “We cannot predict, nor can we surmise, what the commission will do in the future.”
The response to the executive order also says the commission “currently is considering comments” on its policies on the length of hydropower licenses, an apparent reference to the responses to its 2016 Notice of Proposed Rulemaking (RM17-4).
Kerr Dam in Montana
O’Driscoll explained that the staff response was due Sept. 27, before the commission’s Oct. 19 meeting, at which it approved a policy statement setting a 40-year default license term. The commission said the change will reduce administrative costs and encourage dam owners to upgrade capacity and make environmental or recreational investments (PL17-3). (See FERC Sets 40-Year Term for Hydro Licenses.)
Prefiling Requirement for LNG Terminals
Commission staff also reviewed but found no rules to recommend changing regarding LNG terminals; natural gas pipeline and storage facility siting; generator interconnection policies; and electric capacity markets in PJM, ISO-NE and NYISO.
For example, staff examined the prefiling process for LNG terminals and related facilities but ultimately decided “there is no need for the commission to consider any revision.”
Commission regulations require applicants to use its prefiling process for at least 180 days before filing an application. Staff said that although the Natural Gas Act only requires prefilings for terminals and not “related” facilities, gas pipelines and the terminals they serve need to be evaluated together to avoid segmentation under the National Environmental Policy Act.
“Further, the prefiling process allows stakeholders to become involved in the overall project at an early stage, and applicants can benefit from stakeholders’ early identification and resolution of issues that may overlap with the LNG terminal. Without using the prefiling process for related jurisdictional natural gas facilities, delays could occur during the application review, when issues are first identified and need resolution,” staff said. “Thus, although this regulation may result in delays or additional costs to the applicant early on in a project’s development, its overall result is a more timely application review.”
The CEOs for three of the largest companies that stand to gain from proposed price supports for nuclear and coal generators used their third-quarter earnings calls last week to praise FERC, the Department of Energy, PJM and states for their attention to the issue.
Exelon’s Chris Crane, Public Service Enterprise Group’s Ralph Izzo and Dominion Energy’s Thomas F. Farrell II all made a point to thank the RTO, states or federal agencies who have made — or are considering — changes to funnel additional money to the generators, which the companies argue are critical to the grid but undervalued in markets.
And they had good reason to. Crane said “each dollar [per] megawatt-hour of distortion caused by a flawed market design” costs the company $135 million per year. Izzo said each dollar change in per-megawatt-hour revenue from PJM is worth $55 million pre-tax to his company.
“We commend [Energy Secretary Rick Perry] for focusing attention on the need to reform the energy markets, and ensure that our customers continue to benefit from the resilient system,” Crane said. “Between these efforts and state initiatives, we’re optimistic about the path to preserve nuclear power plants. … We are confident that the FERC actions around resiliency will facilitate needed power price reforms in PJM that will fairly compensate our generating assets.”
The DOE’s Notice of Proposed Rulemaking “is aimed at protecting our customers from outages resulting from manmade and natural interruptions on the gas system by preserving resilient generation sources, including nuclear,” he said.
PSEG is “on track … to reduce the all-in cost per megawatt-hour of its nuclear operations by 10% from the average cost experienced during the prior three years,” Izzo said. “But energy prices influenced by the availability of natural gas have declined by a greater degree during this time frame.
“We believe that the DOE NOPR is necessary. … We recommend that measures adopted in response to the DOE NOPR should be viewed as an interim [solution] until effective mechanisms can be developed that recognize these attributes in the market,” he said. “State action also remains critical to prevent the loss of these units. We believe state action can be done [in a] way that both maintains the integrity of the wholesale market and serves as a bridge until a regional [or] federal solution is in place.”
State ZEC Programs
Farrell
Farrell didn’t want to speculate on the outcome of the NOPR, but said “Connecticut certainly hasn’t been willing to depend on it.” He said he expects Connecticut lawmakers to follow Illinois and New York in establishing a zero-emission credit program to support nuclear units.
Last week, Gov. Dannel Malloy signed a bill that could allow Dominion’s Millstone nuclear plant in Waterford, Conn., to compete in a state-sponsored solicitation for zero-carbon electricity if officials conclude it is in the best interest of ratepayers. Malloy, however, said he believes the plant is profitable and does not need a subsidy.
“Dominion Energy thanks the general assembly for giving Millstone this opportunity and is grateful to the Malloy administration for his work in negotiating the current form of the legislation,” Farrell said.
“We weren’t surprised” by approval of the legislation, he added. “We’ve been working on it for two years and been deeply involved in it for that period of time.”
Joe Dominguez, Exelon’s vice president of governmental and regulatory affairs and public policy, also praised the Connecticut legislation and said that his lobbying efforts aren’t done.
“We have been [in] very productive discussions both in Pennsylvania and New Jersey. We’ll continue to do that,” he said.
He said that the ZEC programs are designed to decrease if energy-market reforms happen, so “it will not be a double-dip here.”
Izzo said PSEG is lobbying as well.
“Depending on what happens at the federal level, there remains the opportunity for New Jersey to recognize certain attributes that perhaps are not explicitly identified at the federal level,” he said. “We are just in a series of conversations with people right now. We are just making sure they understand what our nuclear plants mean to New Jersey.”
FERC Action
Izzo and Crane agreed FERC should order PJM to revise its price formation methodology, a move Izzo called a “no brainer” and “long overdue.” Crane anticipated changes by as early as mid-2018.
Defining “resiliency” has been an ongoing debate, but Dominguez said PJM’s Capacity Performance design makes the discussion quantitative.
“We were able to value the cost of incremental reliability associated with dual fuel, so if the design basis ultimately ends up being we need 90 days of fuel, we have a mathematical way of calculating what’s the market solution to get dual-fuel resources to 90 days of fuel with it,” he said. “That would probably be $8 or $10/MWh in terms of doing that based on the cost we saw in CP.”
A rule from FERC that boosted power prices could also leave smaller retail competitors who have been “aggressive” in their pricing vulnerable to acquisitions by large, integrated energy companies like Exelon, Crane said.
“Any time we’ve seen a volatility event … we’ve had opportunities to acquire companies in that type of environment,” Crane said.
Izzo said he was wary of projections that rules on price formation will increase PJM energy prices by $2 to $4/MWh, saying it ignores other factors that can have an impact.
“What [is the impact] of pipelines that may change the basis differential of gas in Western PJM versus Eastern PJM? What [is the impact of] future carbon constraints that may or may not be part of a subsequent administration in Washington?” he said. “Some people on this call may want to go see their children in their Halloween parades; otherwise I would list a thousand other factors that should go into people’s thought process before making those kind of investment decisions.”
Earnings
Crane said the Illinois Power Authority’s decision last month to delay the finalization of the procurement of the ZEC contracts from December 2017 to January 2018 will shift 9 cents of earnings per share from 2017 to 2018.
Exelon earned $824 million ($0.85/share) in the third quarter, missing expectations by 1 cent but improving on the 53 cents/share earned in the same quarter a year ago. Revenue of $8.77 billion beat expectations by $90 million but was down from $9 billion a year ago. Operating earnings were 85 cents/share, compared to 91 cents/share for the third quarter of 2016.
While Exelon hasn’t escaped the industry’s cyclical nature, “we’ve gained greater flexibility with programs like the ZEC,” Crane said.
Dominion posted operating earnings of $672 million ($1.04/share) for the third quarter of 2017, which beat expectations by 2 cents but was down from $716 million ($1.14/share) for the same period in 2016. Revenue of $3.18 billion missed expectations by $110 million but was up from $3.13 billion in the third quarter of 2016.
PSEG reported third-quarter operating earnings of $417 million ($0.82/share), which missed estimates by 2 cents and was down from $444 million ($0.88/share) a year ago.
Seeking Alpha provided the earnings calls transcripts for this article.
PJM’s announcement on Thursday of plans to recommend more than $400 million in transmission upgrades — just weeks after the RTO’s Board of Managers authorized $1 billion in spending — sparked pushback from American Municipal Power, which said the RTO ignored questions about the effectiveness of several of the projects.
Staff plan to recommend adding the projects to PJM’s Regional Transmission Expansion Plan at the board’s Dec. 4 meeting.
AMP’s Ryan Dolan questioned PJM’s analysis of several of the reliability projects, arguing that the proposed solutions fail to address all issues at the nodes in question and will necessitate additional construction in the future. He was displeased that PJM plans to recommend the projects even though, he said, concerns were raised about their effectiveness from a “holistic planning” perspective at a sub-regional RTEP discussion the previous day.
“For some of these projects, basically … [PJM is] planning on making these recommendations no matter what comments were provided,” Dolan said. “I think it would be useful to give time between when we make recommendations to when the last review of a project is to ensure any of the comments … that were brought up … can actually be accounted for.”
PJM’s Mark Sims responded that all information underlying the RTO’s recommendation has been available throughout the planning process and that recommendations can change as additional information is added to the analysis.
“We’ve been transparent with all the steps along the way,” he said.
The $400 million in additional projects will be recommended as the result of a reliability analysis for the 2021/22 delivery year, Sims said. They include eight projects from the first RTEP proposal window for 2017, along with 13 projects that were previously identified.
The recommendations also include one market efficiency project proposed by American Electric Power to address a thermal constraint on the Tanners Creek-Dearborn 345-kV circuit. PJM’s Nick Dumitriu explained that AEP’s $600,000 solution would upgrade equipment at the Tanners Creek station, removing price separation in the Duke Energy Ohio/Kentucky (DEOK) locational deliverability area in the 2020/21 Base Residual Auction Capacity Emergency Transfer Limit (CETL) study.
PJM rejected two other proposals for the same constraint that estimated costs at $4.9 million and $12.7 million.
RTO staff confirmed the upgrades will be included in the model for the 2021/22 BRA.
AMP has become increasingly critical of transmission spending in PJM. In September, the company released a report showing that more than half of the $24.3 billion in transmission spending in the RTO since 2012 were supplemental projects by transmission owners and were not needed to comply with RTO or federal reliability requirements. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
