Public Service of New Mexico Sets Reactive Power Rate to Zero to Avoid Paying Reactive Power Compensation to Unaffiliated Resources
On September 30, 2021, Public Service of New Mexico (PNM) filed at FERC in Docket No ER21-2988 to add a pass-through mechanism to its Schedule 2 (reactive power) for recovery from customers of reactive power compensation paid to unaffiliated resources with a FERC approved rate. They also filed to set their Schedule 2 rate to zero, by which they would cease paying their own or affiliated generators for reactive power and thereby not have to pay for reactive power from unaffiliated resources. PNM, however, provided for continued payment to New Mexico Wind, which had an effective Schedule 2 rate when PNM made this filing. FERC denied the pass-through mechanism (PNM did not adequately show it was just and reasonable) and accepted the zero rate for Schedule 2. FERC found that PNM’s proposed revisions to eliminate compensation for reactive service under Schedule 2 are just and reasonable. Consistent with Commission precedent, a transmission provider may decide to eliminate compensation for having the capability of providing reactive service within the standard power factor range. As the Commission has stated, “[t]he decision to compensate affiliates and non-affiliates [for reactive service capability] rests with the transmission provider.” FERC found that PNM’s proposed Schedule 2 revisions to eliminate compensation for its own generation and the associated charges to transmission customers is permitted under, and consistent with, Commission policy.
However, regarding PNM’s proposed pass-through proposal, FERC found that, upon Commission acceptance of PNM’s revisions to eliminate compensation for reactive power provided by its own generation, it would be unduly discriminatory or preferential for PNM to continue compensating an existing wind facility for reactive service capability within the standard power factor range while compensating no other generators for reactive service capability within the standard power factor range. Commission policy requires that the transmission provider compensate affiliated and unaffiliated generators on a comparable basis, and the Commission has stated that “an unaffiliated generator should not receive compensation for reactive power inside the [standard power factor range] unless the transmission provider so compensates its own or affiliated generators.”
With respect to the effect of FERC’s decision on New Mexico Wind’s and Aragonne Wind’s rate schedules for reactive service compensation, FERC noted that as of the October 1, 2021 effective date of PNM’s revisions to eliminate Schedule 2 compensation, third-party generators, including New Mexico Wind and Aragonne Wind, will not be entitled to receive compensation for Schedule 2 service. Section 9.6.3 of the New Mexico Wind and Aragonne Wind LGIAs reflects the Commission’s comparability policy for reactive service compensation and precludes New Mexico Wind and Aragonne Wind from Schedule 2 compensation as of October 1, 2021. However, FERC clarified that New Mexico Wind is entitled to receive compensation for its reactive power revenue requirement at its filed rate, subject to the outcome of the hearing and settlement procedures in Docket No. ER21-1555-000, from the effective date of its filed rate schedule until September 30, 2021 (Aragonne Wind did not yet have an effective Schedule 2 rate on October 1, 2021). After September 30, 2021, neither PNM nor third-party generators will receive compensation for Schedule 2 reactive service. FERC stated in conclusion that resources like New Mexico Wind and Aragonne Wind, by designing their generating facilities to have the capability to provide reactive support, are only meeting the conditions of interconnection required of all generators and they not entitled to compensation unless the transmission provider pays its own or affiliated generators for reactive power within the established range.
 Bonneville Power Admin. v. Puget Sound Energy, Inc., 120 FERC ¶ 61,211, at P 20 (2007) (“Commission policy clearly allows [Bonneville Power Administration] to discontinue paying all its merchants for inside the [standard power factor range] reactive power service.”), order on reh’g, 125 FERC ¶ 61,273 (2008) (Bonneville Rehearing Order); E.ON U.S. LLC, 119 FERC ¶ 61,340, at P 15 (2007) (E.ON) (accepting proposal to compensate no generators for reactive power within the standard power factor range); Entergy, 113 FERC ¶ 61,040 at P 38 (accepting tariff revisions setting charge for reactive power to zero).
 Bonneville Rehearing Order, 125 FERC ¶ 61,273 at P 25 (noting further that the transmission provider “is under no obligation” to choose to compensate for reactive power within the standard power factor range).
 See Order No. 2003-B, 109 FERC ¶ 61,287 at P 119.
 Bonneville Rehearing Order, 125 FERC ¶ 61,273 at P 24.
On January 28, 2022, FERC issued Opinion 577 involving Pacific Gas and Electric (PG&E) and the City of San Francisco (City). The City requested additional service at a King Street Substation, the interconnection point with PG&E. PG&E performed a system impact study and determined the facility additions needed to provide the service the City requested. PG&E treated the facilities as direct assignment facilities and the City objected, saying they were upgrades.
The Initial Decision addressed four disputed issues: (1) whether the facilities at issue are properly categorized as direct assignment facilities under the WDT (Issue One); (2) if the facilities are not direct assignment facilities, then whether the facilities are “upgrades” under the WDT Interconnection Agreement (Issue Two); (3) whether PG&E is permitted, under the WDT and Commission policy, to directly assign San Francisco the full cost of facilities at issue where PG&E also requires San Francisco to pay the WDT distribution service charge (Issue Three); and (4) whether PG&E should be required to provide more detailed support for cost estimates in the WDT application process (Issue Four).
On Issue One, FERC found that the facilities were properly classified as direct assignment facilities, as they are for the sole use and benefit of the City. FERC also found that that since the facilities are properly classified as direct assignment facilities, it was not necessary to address the issues concerning whether the facilities are “upgrades” under the WDT Interconnection Agreement. Regarding Issue Three, FERC found that PG&E is permitted by Commission policy and the WDT to directly assign the costs of the King Street Substation facilities to San Francisco and require San Francisco to pay the WDT distribution service charge. As to Issue Four, FERC found that PG&E needs to provide a more detailed cost estimate to the City in connection with the King Street Project.
Further Information on Two Items
As to charging the City for the direct assignment facilities and for its charge under the tariff, FERC found this to be consistent with its Transmission Pricing Policy. FERC found that because direct assignment facility costs are netted out and excluded from PG&E’s revenue requirement that is used to calculate the distribution service charge, direct assignment facility costs are not included in the distribution service charge and the City is not paying twice for the same service. That is, because there is no cost overlap between the direct assignment facilities that the City pays for and the costs included in the distribution service charge, PG&E is not violating the “and” pricing policy.
FERC disagreed with the Presiding Judge’s finding that it is unjust and unreasonable “that the design of a distribution system to provide a customer electric service is within the sole discretion of the Distribution Provider.” Rather, distribution providers maintain discretion over their own systems. Each distribution utility, including the City, retains sole discretion over the provision of electric service to its own retail customers, and when two distribution utilities with a utility-to-utility relationship like here interconnect their systems at a point of interconnection, such as the City ’s WDT points of delivery, each distribution provider retains sole discretion over the management of the distribution system on its own side of the interconnection. Just as the City retains sole discretion over the provision of power to the SFMTA as its retail customer on its side of the interconnection at the King Street Project, PG&E retains discretion over the distribution facilities on its side of the interconnection.
In Docket No. ER21-2282, the PJM TOs requested that they have the option to fund Network Upgrades (transmission facilities necessary to interconnect new generation to the PJM system). The PJM TOs state that this option is necessary to ensure that the PJM TOs are properly compensated for owning and operating Network Upgrades, and this optionality is modeled after the provisions in the MISO Tariff that the Commission recently found to be just and reasonable. The PJM TOs explained that there is a sharp increase in the number of renewable generation resources interconnecting to the PJM transmission system in recent years and the growing amount of Network Upgrades necessary to accommodate those interconnection requests was the driver of the PJM TOs decision to file the Proposed Revisions to its tariff. The trend in generator interconnections is expected to continue, if not accelerate, in the coming years, and there are approximately $4.9 billion of Network Upgrades associated with generation projects that have been studied by PJM and are currently in the interconnection queue. In addition, there are more than 1,200 generation projects waiting to be studied by PJM.
The PJM TOs state in their brief filed on January 13 they are not currently compensated for the risk of owning and operating Network Upgrades, though they are compelled to own and operate Network Upgrades (the generator reimburses the TO for the cost), which produces risk without the attendant compensation. Moreover, because they receive no profit for Network Upgrades, as the amount of Network Upgrades on their system increases, the overall return for their other transmission facilities in rate base is effectively reduced. The PJM TOs state that in Ameren, the Court of Appeals for the District of Columbia expressed concern that the MISO transmission owners were required to own and operate Network Upgrades with no profit or compensation. On remand, the Commission agreed, finding that Network Upgrades present risks and the MISO Transmission Owners should be compensated for those risks. The same reasoning should apply in PJM.
The PJM TOs also state that Network Upgrades are transmission facilities and the PJM TOs face the same risks in owning and operating Network Upgrades as they do in owning and operating other transmission facilities. Accordingly, it is just and reasonable for the PJM Transmission Owners to be compensated for owning and operating Network Upgrades in the same manner that they are compensated for owning and operating other transmission facilities, including the use of the same base Return on Equity (“ROE”).
The PJM TOs state the FERC’s rationale adopted in the recent order denying funding of Network Upgrades of the NY TOs, that a utility’s risk profile of the enterprise as a whole accounts for the risks of Network Upgrades is flawed both legally as well as from an implementation perspective as the Commission’s ROE methodology is simply not designed to or capable of the precision necessary to account for the risks of individual transmission facilities in developing a risk profile used to establish a transmission owner’s ROE.
Lastly, the PJM TOs state that FERC should have no concerns regarding undue discrimination as
there are ample measures to protect against affiliate abuse concerns. Importantly, PJM
will maintain its key role in the interconnection process. In addition, the information that
the PJM TOs propose to post on the PJM website (combined with the detailed information that already exists on the PJM website) will provide significant, detailed information to allow interested parties to evaluate whether disparate treatment or undue discrimination has occurred, and to support a complaint pursuant to Section 206 of the FPA, if warranted. And the entirety of the Commission’s regulatory framework, including numerous rulemaking orders adopted over the past three decades, are in place to prevent affiliate abuse and undue discrimination.
For the PJM TO filing, go to https://elibrary.ferc.gov/eLibrary/filelist?accession_number=20220113-5168&optimized=false.
On December 21, 2021, in Docket No. ER21-2882, FERC denied Pacific Gas and Electric’s (“PG&E”) request to recover 50% of the abandoned plant costs associated with three projects which CAISO had not canceled but had changed the scope. PG&E had requested authorization to recover 50% of abandoned plant costs associated with three transmission projects that the CAISO approved and then subsequently modified: (1) the Spring/Morgan Hill Area Reinforcement Project (Spring/Morgan Hill Project), (2) Oro Loma 70 kV Reinforcement Project (Oro Loma Project), and (3) Lockeford–Lodi 230 kV Area Development Project (Lockeford–Lodi Project) (collectively, Projects). PG&E explains that it identified the project costs it seeks to recover by forming a Project Cost Review Team (Review Team) that was responsible for assessing the costs of the Projects. The Review Team evaluated PG&E’s work for the Projects as originally designed and compared them with the scope of each revised Project to identify those costs that would no longer be useful for the rescoped Projects. PG&E sought recovery of 50% of the approximately $11.8 million ($5.89 million) the Review Team determined were no longer useful to the rescoped Projects, with PG&E writing off the remaining $5.89 million.
PG&E did not assert that CAISO had recommended abandonment of any of the Projects, but rather that the “rescoping” of the Projects through CAISO’s regional transmission planning process had resulted in a reduction in size and cost of the Projects to such an extent that the originally conceived Projects have been “essentially cancelled” and, therefore, should be eligible for abandoned plant cost recovery treatment under Opinion No. 295. However, PG&E cited no authority to support its theory that the Commission should permit such cost recovery where projects have been “rescoped,” and FERC saw no reason here to deviate from the Commission’s well-established policy. The Projects are designated as active and ongoing within CAISO’s 2020-2021 Transmission Plan, and CAISO has assigned 2025 and 2026 expected in-service dates for them. Therefore, FERC found that the Projects have not been abandoned and do not qualify for abandoned plant cost recovery treatment pursuant to Opinion No. 295. Further, unlike in situations where projects have been abandoned, the Commission’s accounting procedures provide for the capitalization of construction costs once the Projects go into service; therefore, PG&E will have the opportunity to seek recovery of the relevant costs at that time.
On December 16, 2021, in Docket RM20-16, FERC issued a final rule on Managing Transmission Line Ratings (Order 881). Through this rule, FERC is requiring:
FERC defines a transmission line rating as the maximum transfer capability, computed in accordance with a written methodology and good utility practices, considering the technical limitations on conductors and other equipment (thermal flow limits), as well as technical limitations of the transmission system (voltage and stability limitations). The transfer capability of a transmission line can change with ambient weather conditions. Increases in temperature lower the transfer capability while decreases in temperature increase transfer capability. The continued use of seasonal or static transmission line ratings based upon conservative, worst-case assumptions, results in suboptimization of the transmission line.
FERC requires the following:
Though not ordered in this proceeding, FERC initiated a subsequent proceeding, Docket No. AD22-5, to consider dynamic line ratings (“DLR”), which presents opportunities for transmission line ratings that are more accurate than those established with AARs. Unlike AARs, DLRs are based not only on forecasted ambient air temperatures and the presence or absence of solar heating, but also on other weather conditions such as (but not limited to) wind, cloud cover, solar heating intensity (instead of mere daytime/nighttime distinctions used in AARs), and precipitation, and/or on transmission line conditions such as tension or sag. FERC adopted the definition of DLR as a transmission line rating that: (1) applies to a period of not greater than one hour; and (2) reflects up-to-date forecasts of inputs such as (but not limited to) ambient air temperature, wind, solar heating intensity, transmission line tension, or transmission line sag.
In this rule, FERC also requires transmission providers to use uniquely determined emergency ratings for contingency analysis in the operations horizon and in post-contingency simulations of constraints. Such uniquely determined emergency ratings must also incorporate an adjustment for ambient air temperature and daytime/nighttime solar heating, consistent with our AAR requirements for normal ratings. Most transmission equipment can withstand high currents for short periods of time without sustaining damage. Emergency ratings reflect this technical capability, defining the specific additional current that a transmission line can withstand and for what duration the transmission line can withstand that additional current without sustaining damage. Because emergency ratings reflect this capability, uniquely determined emergency ratings will ensure more accurate transmission line ratings.
FERC requires each transmission provider to submit a compliance filing within 120 days of the effective date of this final rule, revising their OATT to incorporate pro forma OATT Attachment M. FERC further require that all requirements adopted in the rule be fully implemented no later than three years from the compliance filing due date.
FERC issued Opinion 870 on November 18, 2021 in Docket Nos. ER17-998, EL17-61 and EL18-91 involving the DATC Path 15 transmission project in California. The central issue before FERC in these dockets is whether the transmission revenue requirement (TRR – stated rate, not a formula rate) reduction proposed by DATC Path 15, LLC (DATC) in its February 17, 2017 filing (2017 Filing), revising Appendix I to its Transmission Owner Tariff (Path 15 Tariff), is just and reasonable and not unduly discriminatory or preferential. FERC reversed the Presiding Judge’s determination in the Initial Decision on the just and reasonable return on common equity (ROE) for use in DATC’s TRR, including the composition of the starting proxy group and the use of Expected Earnings in the ROE methodology, and it found that the appropriate ROE for DATC is 10.86% (the Initial Decision found that the current ROE to be just and reasonable). FERC affirmed the Presiding Judge’s findings of fact and conclusions of law regarding test period adjustments and the appropriate effective date for the corporate income tax adjustment required by the Tax Cuts and Jobs Act. FERC ordered DATC to file a refund report detailing what portion of the refund is attributable to the ROE reduction and what portion is attributable to the reductions from the Tac Cut and Jobs Act.
The Path 15 Upgrade is an 84-mile, 500 kilovolt (kV) transmission line built along the existing Path 15 corridor in California to relieve a constrained congestion point. In 2001, FERC specifically recognized the Path 15 corridor as a significant problem area requiring incentives for investment to alleviate costly congestion. The upgraded Path 15 transmission line went into operation in December 2004, adding roughly 1,500 megawatts (MW) to the existing 5,400 MW of transmission capacity from southern to northern California, and increasing transmission capacity from north to south by about 1,100 MW. On June 12, 2002, the Commission accepted a letter agreement among the Path 15 participants that constituted the first step in a process that led to the addition of transmission capacity along California’s Path 15. The letter agreement set forth rate principles to provide some certainty to the financial community and to enable the Path 15 Participants to obtain necessary financing. The letter agreement provided for, among other things, the use of a 13.5% ROE in the calculation of a to-be-filed TRR so as to promote the timely construction of the transmission facilities.
In February 2017, DATC filed its fourth triennial rate case proposing to revise Appendix I to its Path 15 Tariff to reduce its TRR from $25.9 M to $25.6 M. DATC also stated that for the first time in its rate filings, the upper end of the zone of reasonableness had fallen below 13.5%. DATC calculated the zone of reasonableness using the Commission’s standard two-step discounted cash flow (DCF) methodology at a range of 6.10% to 11.19%. However, DATC stated it was entitled to an upward adjustment to this zone, resulting in a proposed range of 7.44% to 12.53%. DATC stated this adjustment was consistent with Commission precedent and necessary to account for anomalous capital market conditions surrounding the Path 15 Upgrade. DATC stated that if the Commission accepted the 2017 Filing without setting the matter for hearing, its ROE would be capped and set at 12.53%. If the Commission instead set the matter for hearing, DATC stated that it would update its cost-of-service numbers prior to hearing and seek a 13.5% ROE, bounded by the upper end of the zone of reasonableness.
In April 2017, pursuant to delegated authority, the Director of Electric Power Regulation – OEMR West – accepted the DATC filing, subject to refund, and set it for settlement and hearing procedures. In October 2017, FERC denied the request for an upward adjustment to the ROE. FERC recognized the significant rate and service reliability benefits, including a substantial decrease in actual and potential congestion, along with a substantial increase in system reliability. Consistent with the approach taken in the 2011 and 2014 Rate Cases and in recognition of the unique nature of the Path 15 Upgrade, FERC directed the Presiding Administrative Law Judge (Presiding Judge) to determine the appropriate range of reasonable returns, and to set the ROE at the upper end of the range, not to exceed the filed 13.5%. FERC held the hearing in abeyance to provide parties with an opportunity to settle, but settlement discussions were later terminated, and an evidentiary hearing ensued.
In arriving at its DATC decision, FERC applied the revised ROE methodology from Opinion 569, as modified in 569-A and 569-B, and found that certain modifications were required to apply the Opinion No. 569 methodology to the facts and circumstances of DATC because (1) DATC’s ROE is an all-in incentive ROE and not a base ROE; and (2) the Commission had already determined that DATC’s ROE should be set at the upper end of the range of reasonable returns, not to exceed the filed 13.5%. Applying this modified ROE methodology, FERC found that the composite zone of reasonableness was from 7.55% to 10.86%, and that DATC’s existing 13.5% ROE was entirely outside of this range, making the existing rate unlawful under the first prong of FPA section 206. Since FERC had previously determined that the DATC ROE would be set at the high end of the zone of reasonableness, FERC determined under the second prong that the just and reasonable ROE should be 10.86%, as that is the highest combination of base ROE and ROE adders that FERC would grant using its new ROE methodology.
FERC found that it was appropriate to apply the DCF analysis from the revised ROE methodology established in Opinion No. 569. Specifically, FERC held that: (1) only the IBES short-term growth projection should be used for calculating the (1+.5g) adjustment to the dividend yield instead of a composite growth rate; (2) a revised low-end outlier test applied under which FERC excluded from the proxy group companies with ROEs that do not exceed the Baa bond yield by at least 20% of the Risk Premium from the CAPM analysis; (3) a revised high-end outlier test applied, under which FERC treated any proxy company as high-end outlier if its cost of equity estimated under the model in question is more than 200% of the median result of all of the potential proxy group members in that model before any high or low-end outlier test is applied, subject to a “natural break” analysis; and (4) the long-term growth rate should be given 20% weighting and the short-term growth rate 80% weighting in the two-step DCF model. FERC also found that it was appropriate to apply the CAPM analysis (not the empirical CAPM) from the revised ROE methodology established in Opinion No. 569. FERC found that it was appropriate to apply the Risk Premium analysis from the revised ROE methodology established in Opinion No. 569. FERC disagreed with the Initial Decision directly including the Expected Earnings in determining the just and reasonable ROE it found here as it did in Opinion 569, 569-A, and 569-B that the Expected Earnings model is not market-based and did not satisfy the requirements in the Supreme Court Case Hope. As to adjustments made to the proxy group, FERC excluded Avangrid from the proxy group since it is a controlled company (DATC had included Avangrid).
FERC determined that substantial evidence supports a finding that the appropriate effective date of the adjustment to account for the Tax Cuts and Jobs Act was January 1, 2018. DATC has one locked-in rate period from April 21, 2017 through January 1, 2018, the effective date of the Tax Cuts and Jobs Act, and a second rate period from January 1, 2018 thereafter.
On November 18, 2021, in Docket No. ER18-1639, FERC issued an order on rehearing, lowering the ROE for Mystic from that determined its order (9.33%) to 9.19%. Mystic Generating Station in New England is operating under a cost-of-service contract as ISO-NE has determined that the facility is needed for reliability while the owner of the facility requested permission to cease operations. FERC made this change for the following reasons:
On November 18, 2021, FERC issued a notice of inquiry in Docket RM22-2 regarding reactive power compensation. Comments are due mid-January 2022 and reply comments are due mid-February 2022.
FERC set its approach to cost-of-service reactive power compensation back in 2002 when it determined that all resources that have actual cost data and support documentation should use the reactive power compensation approach from Opinion 440 involving American Electric Power Company. Since that time, many generators no longer use the FERC Uniform System of Accounts nor provide FERC Form 1, as they are exempted under their market-based rate authority. In addition, Opinion 440 was based upon synchronous generating resources (coal, natural gas, hydro), while many filings to FERC in recent times involve wind and solar facilities (nonsynchronous resources). These and other reasons prompted FERC to issue this NOI to consider changes to how generating resources receive compensation for reactive power. Here are the areas FERC is exploring and for which FERC seeks answers to questions:
In Docket No. ER21-864, on January 12, 2021, Meyersdale Storage requested reactive power compensation pursuant to Schedule 2 of the PJM OATT for its 18 MW lithium-ion battery (Facility) which is co-located with GlidePath’s 30 MW Meyersdale Wind Energy Center. The Facility interconnects with Mid-Atlantic Interstate Transmission LLC’s (MAIT) 115 kV Meyersdale North substation in the Pennsylvania Electric Company (Penelec) transmission zone. Meyersdale provides energy and frequency regulation services on a merchant basis to the PJM energy and ancillary services markets and is contractually obligated to provide Reactive Power Service to PJM. It began operation in 2015.
Meyersdale requested reactive power compensation in the amount of $837,000 annually, which it derived using a methodology consistent with AEP. Given that a battery storage facility’s inverter does not function the same as a traditional synchronous generator, Meyersdale did not use the stated “nameplate” power factor as it is not applicable and does not reflect the Facility’s capabilities. Rather, Meyersdale set forth an alternative power factor of 0.70 that differs from the generator nameplate which is traditionally used in an AEP analysis. In response to a protest from the IMM, Meyersdale asserted that, because its data is from testing performed in accordance with PJM Manual 14D requirements, it can operate at significantly lower (i.e. more difficult) power factors than a traditional resource. Meyersdale also asserted that the objective technical descriptions and testing data included with its filing demonstrates Meyersdale’s superior reactive power capabilities, as compared to a conventional resource on a per-MW basis. Meyersdale argued that the IMM’s assertion that “Meyersdale cannot sustain its rated output for a significant period of time” is true for real power for which batteries have output duration limits, but that is irrelevant in the instant filing as it can, in fact, inject or absorb its full reactive power capability at any time, regardless of battery charging conditions (similar to some solar facilities).
In setting the matters for hearing and settlement, FERC stated that under Order No. 841, RTOs and ISOs are required to allow electric storage resources to provide all capacity, energy, and ancillary services that they are technically capable of providing so long as they satisfy the RTOs’/ISOs’ technical requirements. However, FERC was unable to determine, based on the record, whether Meyersdale’s battery storage facility can provide reactive capability consistent with Schedule 2 of the PJM Tariff, and therefore FERC set this threshold question for hearing, along with Rate Schedule in its entirety. The case is in settlement procedures.
Dr. Paul Dumais
CEO of Dumais Consulting with expertise in FERC regulatory matters, including transmission formula rates, reactive power and more.