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Statements from FERC in ISO New England Inc. to Comply with the Fair Rates Act of 2018, Part Two: Commissioner Richard Glick’s Statement

The Chairman and Commissioners of the Federal Energy Regulatory Commission (FERC) released statements regarding ISO New England Inc. filing revisions to the “ISO-NE Transmission, Markets and Services Tariff (Tariff) to implement an inventoried energy program in the Capacity Commitment Periods associated with the 14th and 15th Forward Capacity
Auctions (FCA 14 and FCA 15, respectively) to compensate resources for maintaining inventoried energy during the winter months of 2023-2024 and 2024-2025 (Inventoried Energy Program or program).” In May, FERC issued a letter to ISO-NE to inform them that the filing was deficient, and they needed additional information; they received a response in June.
Since FERC did not take action by August 5, the amended proposal from ISO-NE “became effective by operation of law.”

FERC did not act on the filing due to “a lack of quorum at this time.” As per section 205(g)(1)(B) of the FPA, the FERC Chairman and Commissioners provided written statements explaining their views of the filing.

This is Commissioner Richard Glick’s statement.

Glick said that he found the program to be unjust and unreasonable because “The program will cost New England consumers as much as $300 million without any evidence to suggest that it will actually improve the region’s fuel security or that any improvement is likely to be worth the cost. Indeed, the program goes so far as to hand out substantial payments to nuclear, coal, and hydropower generators with no indication that these payments will change their behavior in the slightest.” He said he found this to be a windfall instead of a reasonable rate.

Glick agreed that there is an issue with fuel security in New England, and that during “especially cold winter days, the region’s natural gas transportation capacity can become constrained, creating a risk that there may not be enough natural gas available to supply the natural gas-fired
power plants that would otherwise help power the grid. On these days, the region tends to substitute oil and natural gas delivered via liquefied natural gas (LNG) terminals for gas that would otherwise be shipped through the constrained pipelines.” However, since oil and LNG are not relied upon much during normal weather conditions, “there is a concern that resources may not always have enough of these fuels on hand to sustain the grid over a long period of time. Although the number of these cold winter days has historically been low—and the region has never actually run out of oil and natural gas—the consequences of not being able to generate enough electricity could be catastrophic, making the region’s fuel security an issue we must take seriously.”

Glick stressed that he believes FERC should be “taking fuel security seriously means that ISO New England, stakeholders, and the Commission itself must ensure that efforts to address this issue actually help the region procure the services needed to operate the grid reliably. It also means that we must not waste consumers’ money on poorly designed solutions that do little, if anything, to improve the region’s fuel security.” He believes that “wasting consumers’ money is exactly what the Inventoried Energy program does.”

He explained that the program “proposes to pay certain types of resources for maintaining ‘inventoried energy’—which is, essentially, onsite fuel that the resource can convert into electricity —during two winters: 2023-2024 and 2024-2025. A resource is eligible to participate in one of two ways: either by entering a forward contract, which requires the resource to have a certain amount of ‘inventoried energy’ onsite whenever the ISO declares a cold weather event, or through the spot market, which allows the resource to be paid for whatever ‘inventoried energy’ it happens to have onsite during a cold weather event.”

He explained the “fatal flaws” that he saw in the proposal. “Most importantly, ISO New England does not point to any evidence that there is a near-term operational problem that cannot be adequately addressed by its existing rules or any evidence that the Inventoried Energy program would address any such problem by making the region more fuel secure. Without such analysis, there is no foundation to evaluate whether the program will achieve its intended purpose or do so in a manner that is just and reasonable.”

“At least a third of the capacity eligible to receive payments through the Inventoried Energy program is from resources that will not change their behavior in response to these payments because they already maintain considerably more than three days’-worth of fuel onsite.” He explained that “at least $40 million dollars a year is likely to be spent on resources, such as coal and nuclear generators, that will not change their behavior in response to those payments. That is an utter waste of ratepayers’ money. Based on the record here, one cannot help but wonder whether burning that money might contribute as much to fuel security as wasting it on entities that we know will not do anything differently.”

Glick said “the record suggests that the Inventoried Energy program’s poor design will dissuade other types of resources from participating. For example, ISO New England explains that its proposed forward rate is based on the fair market value of a fuel contract between a natural gas-only generator and an LNG storage terminal. This suggests that the program is intended to incentivize resources to enter into backup LNG contracts.” However, ISO New England has described the “forward rate as representing the ‘break even’ payment associated with a backup LNG contract, meaning that, at that price, resources will be economically indifferent about whether to enter such a contract.” It is because of this that Glick thinks “there is little reason to think that the program will do anything to change the behavior of natural gas-only units, which, as noted, are the primary concern when it comes to fuel security in New England.”

ISO New England suggested that the program was “just and reasonable because it might forestall the retirement of otherwise uneconomic resources, which might then benefit the region’s fuel security… creating a program to funnel money to uneconomic resources in order to prevent their retirement would seem to undermine a key element of the balancing act that the Commission relied upon when it found the Capacity Auctions with Sponsored Policy Resources (CASPR) program just and reasonable.”

But even if we assume, for the sake of argument, that the Inventoried Energy program will make an incremental contribution to fuel security, ISO New England has not shown that this contribution is likely to be worth the program’s considerable price tag. As noted, the ISO estimates that the Inventoried Energy program will cost New England ratepayers between $200 and $300 million over just two years. But the record is insufficient to determine whether that is just and reasonable. For one thing, there is no evidence of how much incremental ‘inventoried energy’ the ISO might get in response to those payments.” He said that since they “did not perform any analysis of how much ‘inventoried energy’ it needs, we have no way of knowing whether the program will satisfy any need for ‘inventoried energy’ that New England may or may not have. And without that information, we simply cannot assess what benefit, if any, New England customers will receive from the program, and therefore whether it is just and reasonable.”

“The Inventoried Energy program does not possess even the basic principles of an effective market-based solution, which the Commission has repeatedly instructed ISO New England to make the foundation of its approach to fuel security.” Glick said that it it those principles that
“help to ensure that the approach is effective, both in delivering the product in question and in ensuring that customers get what they pay for.”

ISO New England “evaluate[d] neither the specific need for inventoried fuel nor the quantity demanded. As a result, there is no market competition for this product because every resource with the necessary attributes receives the same price. But without competition, the price-setting mechanism is untethered from market fundamentals and may produce an extremely inefficient outcome.” He said this is what will happen now; “SO New England established a fixed price, $82.49 per megawatt-hour, without making any attempt to evaluate how much ‘inventoried energy’ it should buy at the price or how much resources might supply at that price.”

“ISO New England’s decision to pursue such an ill-conceived approach is all-the-more disappointing because the ISO has better options than the Inventoried Energy program to address any short-term need that might exist.” He said there were other options that would allow the region’s need to be addressed at a better rate. ” In general, by taking away the downside
risk of having excess fuel at the end of the winter, the Winter Reliability Program provided a proven method for incentivizing resources to procure fuel while targeting payments at resources that might actually respond to those payments. A modified version of the Winter Reliability Program might have helped to address any short-term need while providing at least some evidentiary basis, in the form of real-world experience, for the Commission to evaluate whether the proposal might be effective and worth the cost—in other words, whether it is just and reasonable.”

FERC Makes Early Action Determination for Public Utility District No. 1 of Chelan County, Washington

In June Public Utility District No. 1 of Chelan County in Washington filed a request for determination that “project investments over the term of the existing license” met the criteria in subsection 36(b)(2) of the Federal Power Act, to ensure “that the investments will be considered when the Commission sets the term for the next license for the project.” This is for the Rock Island Project on the Columbia River, near Wenatchee.

Chelan PUD predicts that by 2029 there will be a “total investment during the current license term of over $710 million. Specifically, Chelan PUD requests that the Commission determine whether the following project investments meet the criteria under FPA section 36(b)(2): (a) rehabilitation of Powerhouses 1 and 2; (b) design and construction of new office, warehouse, and storage facilities; (c) replacement of two spillway gate hoists; and (d) implementation of an Anadromous Fish Agreement and Habitat Conservation Plan (HCP).”

They noted that the Federal Energy Regulatory Commission (FERC) “has not issued any order extending the existing license term,” which was issued in 1989. “Therefore, Chelan PUD maintains that the Commission must consider, at the time it determines the next license term, any investment meeting FPA section 36(b)(2)(A) criteria that was not a requirement of the 1989 license order.”

Chelan PUD has requested that FERC “consider the ‘significant’ investments it has made and is proposing to make to rehabilitate the two Rock Island Project powerhouses. Powerhouse 1 contains 10 turbine-generator units (B1 through B10); Powerhouse 2 contains eight
turbine-generator units (U1 through U8). In 2003 and 2017, Chelan PUD notified the Commission of its intent to rehabilitate 9 of the 10 generating units at Powerhouse 1.” Chelan PUD says that those units ““were reaching the end of their remaining useful lives,” and that
“rehabilitation was necessary to keep the project ‘in an adequate condition of repair.'”

Only three Powerhouse 1 units have been rehabilitated: “Unit B10 completed in 2008, Unit B9 completed in 2012, and Unit B6 completed in 2018.” They plan to have the remaining units rehabilitated by 2022. “By 2029, Chelan PUD plans to rehabilitate eight bulb turbine-generator units at Powerhouse 2. Chelan PUD anticipates that the rehabilitation of Powerhouse 2 will provide an additional 40 years of reliable and efficient power generation capability for the units. Chelan PUD estimates that it will cost approximately $270 million to rehabilitate Powerhouse 1, and approximately $352 million to rehabilitate Powerhouse 2.”

“Chelan PUD’s turbine and generator improvements will enhance the efficiency and reliability of the Rock Island Project. These improvements were not considered by the Commission as contributing to the existing 40-year license term. Therefore, we find that the Powerhouse 1 and Powerhouse 2 rehabilitation projects qualify as ‘rehabilitation or replacement of major equipment,’ meeting the criteria under FPA section 36(b)(2).”

“Chelan PUD intends to implement a long-term Rock Island facilities master plan that will include constructing or updating multiple office, warehouse, and storage facilities at the Rock Island Project, estimated at $40 million.” FERC noted that Chelan PUD’s request for determination had “limited information on this investment, such that it is unclear whether it would qualify as a ‘project-related’ investment under the criteria of section 36(b)(2)(A).” FERC is also uncertain if “Congress intended for us to consider ancillary facilities, such as office buildings, that do not have a demonstrated direct hydropower purpose, may not be necessary for project operation, and may have other uses. Therefore, based on the information before us, we cannot determine whether these investments meet the criteria under section 36(b)(2).” They noted that Chelan PUD was welcome to ” file further information on these matters during the relicensing process.”

Chelan PUD also said it ” plans to replace two spillway bay gate hoists to improve the safety and reliability of the spillway operation. In March 2020, Chelan PUD plans to replace the existing manually-operated hoists with automatic hoists, increasing the spillway gate capacity. Chelan PUD anticipates that these improvements will cost an estimated $4 million.”
“Chelan PUD’s planned replacement of manual spillway gate hoists with auto hoists will allow remote gate operation and increase gate capacity, improving the safety and reliability of the spillway. These improvements were not considered by the Commission as contributing to the existing 40-year license term. Therefore, we find that this planned investment meets the section 36(b)(2) criteria.”

In June 2004, FERC approved “a project-specific HCP for the Rock Island Project,” for which they amended “the license to incorporate the provisions of the plan as special articles. The Rock Island Project HCP is a comprehensive and long-term management plan for salmonid species affected by the project.” In order “To achieve the objective of the HCP – achieving and maintaining a ‘no net impact’ for each plan species – Chelan PUD explains that it has spent more than $44 million on fish passage survival studies, hatchery construction, operation and maintenance, annual funding for tributary protection and restoration projects, fish predator control programs, and ongoing passage facilities operations and maintenance.”

FERC found those measures applicable to FPA section 36(b)(2) criteria, but recommended that “during the licensing process, Chelan PUD may wish to provide additional information to clarify the nature of these measures, such as explanations of the extent to which the measures arise from HCP obligations, as opposed to the requirements of the 1987 settlement agreement regarding the project.”

FERC’s final determinations were:
“(A) that Chelan PUD’s investments made to rehabilitate the two Rock Island powerhouses, improve the project spillway, and implement its HCP appear to meet the criteria set forth in section 36(b)(2) of the Federal Power Act.

“(B) that it is unable to find whether Chelan PUD’s construction investments in new office, warehouse, and storage facilities meet the criteria set forth in section 36(b)(2) of the Federal Power Act.”

FERC is Creating a New LNG Division in Texas

The Federal Energy Regulatory Commission (FERC) announced that they will be “creating a new division in its Office of Energy Projects to accommodate the growing number and complexity of applications to site, build and operate liquefied natural gas export terminals.” The new division will be the Division of LNG Facility Review & Inspection (DLNG), and it will have “20 existing LNG staff members in Washington, D.C., and eight additional full-time staffers recruited in the Houston area and based in a new Houston Regional Office.”

FERC Chairman Neil Chatterjee said in the announcement that, “As the demand for U.S. LNG and the number and complexity of project applications has grown, the Commission has experienced a similar growth in the need for FERC to expand its oversight in this program area. Much of the work related to these LNG projects, and the expertise it requires, is based in and around Houston, the so-called ‘Energy Capital of the World.’ For that reason, after careful research and evaluation, the Commission has determined we should direct our newest efforts to recruiting staff in the area to build upon the good work already being done on these issues at our D.C. headquarters.’”

FERC has had 13 staff members “dedicated to working on LNG engineering and review issues,” since April 2018. Since then, that number has grown to 20 staff members, “whose efforts are critical to completing engineering reviews, coordinating safety reviews with the Pipeline and Hazardous Materials Safety Administration at the Department of Transportation, and preparing engineering analyses for inclusion in environmental documents.” The DLNG and the Houston expansion are intended to help FERC prepare for additional work when “LNG project applicants make final investment decisions and move toward construction.”

The Office of the Executive Director and the Office of Energy Projects have started coordinating with General Services Administration about the office configuration and space requirements in the Houston office. There will soon be job postings for the additional staff, starting with the Division Director.

FERC Streamlines Processes for Market-Based Sellers

The Federal Energy Regulatory Commission (FERC) has finalized a set of rules to help “ease the regulatory burden for electric power sellers with market-based rate authority,” while making sure that FERC keeps preventing the “potential exercise of market power.”

The first rule “concerns the horizontal market power analysis required for market-based rate sellers.” They have eliminated the “obligation to submit indicative screens in order to obtain or retain market-based rate authority in certain organized wholesale power markets.” The sellers will not have to “submit the pivotal supplier screen and the wholesale market share screen in any organized wholesale power market that administers energy, ancillary services, and capacity markets subject to Commission-approved monitoring and mitigation.”

In the organized markets that “do not administer capacity markets” with the FERC approved monitoring and mitigation, “that is the Southwest Power Pool and California Independent System Operator, market-based rate sellers will be required to submit analyses if they wish to sell capacity there. All market-based rate sellers still would be required to file a vertical market power analysis as well as an asset appendix, which provides comprehensive information relevant to determine a seller’s market power and ensure just and reasonable rates.”

The second rule FERC finalized will help improve their “monitoring of wholesale power markets by streamlining the way it collects certain data for market-based rate purposes, specifically collecting this information in a database. The approved changes will eliminate duplication, minimize compliance burdens, modernize data collections, and make information collected through its programs more usable and accessible for the Commission, its staff, and the public.” One of the main things this rule does is adopt changes to help “reduce and clarify the scope of ownership information that sellers must provide as part of their market-based rate filings, revises the information required in a seller’s asset appendix as well as the format through which such information must be submitted, and eliminates the requirement that sellers submit corporate organizational charts.”

FERC issued a Notice of Proposed Rulemaking about this in July 2016, proposing to “collect connected entity data from market-based rate sellers and entities that trade virtual products or hold financial transmission rights;” the final rule did not adopt that proposal.

The first rule will go into effect 60 days after it is published in the Federal Register.

The second rule will go into effect on October 1, 2020.

FERC Commissioner Richard Glick issued a statement dissenting the second rule and explaining his choice to do so.

Glick said that while he does support some aspects of the rule “that streamline collection of the data needed to regulate market-based rates by creating a relational database and revising certain information requirements.” He noted that he dissented because FERC “is declining to finalize a critical aspect of the underlying notice of proposed rulemaking that would have required Sellers and entities that trade virtual products or that hold financial transmission rights (Virtual/FTR Participants) to report information regarding their legal and financial connections to various other entities.” He said that this “information is critical to combatting market manipulation and the Commission’s retreat from the NOPR proposal will hinder our efforts to detect and deter such manipulation.”

Glick explained that the context is important in policing market manipulation, and “a transaction that seems benign when viewed in isolation may raise serious concerns when viewed with an understanding of the relationships between the transacting parties and/or other market participants. Unfortunately, information regarding the legal and contractual relationships between market participants is not widely available and may, in some cases, be impossible to ascertain without the cooperation of the participants themselves. That lack of information can leave the Commission in the dark and unable to fully monitor wholesale market trading activity for potentially manipulative acts.”

The problem is more acute, Glick explained, “when it comes to market participants that transact only in virtual or FTR products. Virtual/FTR Participants are very active in RTO/ISO markets and surveilling their activity for potentially manipulative acts consumes a significant share of the Office of Enforcement’s time and resources.” He said it may be somewhat surprising that FERC collects “limited information about Virtual/FTR Participants and often cannot paint a complete picture of their relationships with other market participants.” FERC also has “no mechanism for tracking recidivist fraudsters who deal in these products and perpetuate their fraud by moving to different companies or participating in more than one RTO or ISO. And, perhaps most egregiously, the Commission’s current regulations do not impose a duty of candor on Virtual/FTR Participants, meaning that bad actors can lie with impunity, at least insofar as the Commission is concerned. The abandoned aspects of the NOPR would have addressed all three deficiencies, among others.”

There can be consequences to having those deficiencies, Glick said, citing a recent example of a FERC order of “how an individual involved in one manipulative scheme was able to move, rather seamlessly, to allegedly perpetuate a similar scheme at another entity.” FERC “issued an Order to Show Cause with an accompanying report and recommendation from the Office of Enforcement that detailed how Federico Corteggiano allegedly engaged in a cross-product market manipulation scheme in the California Independent System Operator’s (CAISO). As described in that order, this alleged scheme used techniques that were similar to another manipulative scheme involving Corteggiano while he was employed at Deutsche Bank. Without the Connected Entity reporting requirements contemplated in the NOPR, the Commission lacks any effective means of tracking individuals who perpetrate a manipulative scheme at one entity and then move locations and engage in similar conduct elsewhere, as Corteggiano is alleged to have done. That makes no sense. We should not be leaving the Office of Enforcement to play ‘whack-a-mole,’ addressing recidivist fraudsters only when evidence of their latest fraud comes to light.”

Glick also used the example of “GreenHat Energy, LLC’s (GreenHat) default on its FTRs in PJM Interconnection, L.L.C. (PJM), at least as it is described in an independent report prepared for PJM’s Board.” In the report, there are allegations that “GreenHat told PJM it had bilateral contracts that would provide a future revenue stream, alleviating the need for additional collateral. 10 The report further contends that PJM mistakenly relied on GreenHat’s representations and the contracts in question did not provide the promised revenue stream, significantly exacerbating GreenHat’s collateral shortfall.” He said that under the current regulations, “no duty of candor attached to GreenHat’s allegedly misleading statements. It is, of course, impossible to know how a duty of candor for Virtual/FTR Participants would affect potential misstatements. But, if there were a duty of candor for Virtual/FTR Participants, it would give the Commission a basis for investigating potentially misleading statements and, if appropriate, sanctioning that conduct.”

Glick said that while FERC “does not dispute the benefits that the Connected Entities Information would provide, it ‘declines to adopt’ this aspect of the NOPR without any real analysis or explanation and based only on its ‘appreciat[ion]’ of the ‘difficulties of and burdens imposed by this aspect of the NOPR.'” There is nothing to suggest in the record that the associated burdens this reporting obligation may cause would outweigh the benefits. The Notice initially “paired back the scope of Connected Entity Information compared to the previous NOPR addressing this issue.” He believes that FERC “could have further explored ways to limit the impact of this rule if it were truly concerned about that burden by, for example, eliminating the inclusion of contracts for defining connected entities, which received strong pushback from industry. Alternatively, the Commission could have established a phased-in implementation schedule to provide industry time to adjust to the new reporting requirements.”

Instead, FERC made a “conclusory statement based on an unspecified burden to industry. It makes no effort to explain why that burden outweighs the benefits that Connected Entities Information would provide to the Commission’s ability to carry out its enforcement responsibilities. Without such information, the predictable result of today’s order is that market participants are more likely to find themselves subject to a manipulative scheme than if we had proceeded to a final rule on these aspects of the NOPR.”

Glick said that one of FERC’s chief priorities should be “identifying, eliminating, and punishing market manipulation,” which it has been since 2005 when “Congress vested the Commission with that responsibility” when amendments were made to the “FPA in the wake of the Western Energy Crisis. In addition to the financial losses directly attributable to a particular instance of fraud, market manipulation erodes participants’ confidence in wholesale electricity markets—a dynamic that has serious deleterious consequences for the long-term health and viability of those markets.” He said he can “appreciate the importance of avoiding unnecessary regulatory burdens, the record in this proceeding indicates that the Connected Entity Information is necessary and would, in the long-term, benefit all market participants, including those subject to the regulations, by helping to ensure confidence in the integrity of wholesale electricity markets.”