As 2019 gets underway, the American Public Power Association is keeping a close eye on several key regulatory issues that could affect our member utilities, including possible action by the Federal Energy Regulatory Commission on transmission rates. We will also be monitoring developments in the area of environmental regulations this year.
Transmission rates of return on equity and incentives: The Association is closely following recent FERC pronouncements regarding the Commission’s policies on allowed equity returns and transmission incentives.
In a late 2018 order, FERC proposed a new approach for calculating the allowed return on equity (ROE) to be included in the rates of transmission owners in ISO New England. Application of this new approach could result in higher allowed ROEs and could increase the level of incentive ROE that transmission owners are permitted to collect. In November, FERC directed that this new approach be considered in other pending proceedings.
FERC Chairman Neil Chatterjee has said that the Commission intends to consider whether it should make additional changes to both its calculation of base ROEs and its policies on transmission incentives.
As FERC undertakes this review, the Association is urging the Commission to adhere to its statutory obligation under Federal Power Act sections 205 and 206 to ensure that transmission rates are just and reasonable and not unduly discriminatory and preferential.
For an incentive rate to meet this standard, the costs of the incentive must not outweigh the expected benefits. Incentives must be carefully designed to encourage the desired behavior, and not be greater than what’s needed to achieve the desired result. FERC must abide by the long-standing principle that the level of return follows the level of risk.
Capacity markets: The Association will also continue to monitor proceedings at FERC that involve possible changes to RTO/ISO capacity markets. This includes FERC’s ongoing investigation of PJM’s capacity market. FERC could issue an order in this proceeding as early as this month.
In late December, the Association was joined by several other groups in telling FERC that competitive wholesale electricity markets do not exist to guarantee a return on merchant investments or to protect merchant plant investors from market risks.
The letter from the Association, the Electricity Consumers Resource Council, the Large Public Power Council, the National Rural Electric Cooperative Association and the Natural Resources Defense Council’s Sustainable FERC Project was sent as part of the PJM capacity market proceeding and responded to a letter to the Commission from a group of merchant generation owners.
Along with NRECA, LPPC and the Natural Resources Defense Council’s Sustainable FERC Project, we pointed out that for true market competition to occur, wholesale customers and suppliers should be able to come together and transact as they choose through bilateral contracts.
The Association has voiced concerns about mandatory capacity markets in recent years. While regional transmission organization markets for capacity are described as “competitive,” they are highly mechanized, centrally administered constructs governed by thousands of pages of complex rules. Transactions in these markets are opaque, with little meaningful data available to the public.
Mandatory capacity markets have proven ill-suited to promoting a diverse resource mix that supports reliability and accommodates state and public power resource policies. Worse yet, there is little empirical evidence that mandatory capacity constructs provide resource adequacy benefits that are commensurate with the costs they impose on consumers.
Order No. 841 and DER Rulemaking: At the end of 2018, RTOs and independent system operators submitted filings at FERC outlining how they will ensure that electric storage resources (ESRs) are able to participate in their markets.
The filings were submitted in compliance with FERC Order No. 841, which was issued last year and was aimed at removing barriers to electric storage resources participating in the capacity, energy and ancillary services markets operated by RTOs and ISOs. Implementation of proposed tariff changes, if approved by FERC, will be required by December 3, 2019.
In comments filed in early 2017, the Association said it generally supports FERC's efforts to allow storage and distributed energy resources to participate in wholesale markets but urged the commission to keep its main focus on the end result to electricity consumers and offered a number of recommendations.
While generally supportive of removing barriers to storage resource participation in RTO/ISO markets, the Association has raised concerns that the new rules improperly impinge on local regulation of the distribution system and retail service.
The Association, along with American Municipal Power, Inc. (AMP) and the National Rural Electric Cooperative Association (NRECA) filed a request for rehearing of Order No. 841 in March 2018 arguing that FERC overstepped the limits on its jurisdiction in suggesting that it has authority to allow ESRs located on a distribution system or behind a retail meter to participate directly in wholesale markets even where state or local laws may restrict such participation. The filing also objected to FERC’s refusal to implement an “opt-in/opt-out” framework for ESRs similar to the approach FERC adopted for demand response in Order Nos. 719 and 719-A, under which a relevant electric retail regulatory authority (RERRA) can veto aggregated retail customer participation in wholesale demand response programs. FERC has not yet acted on our rehearing request.
The Association is also awaiting FERC action on new rules to accommodate the participation of aggregated distributed energy resources (DERs) in RTO/ISO markets. Originally proposed in the ESR rulemaking that resulted in Order No. 841, FERC deferred action on proposed DER reforms to gather additional information. As with ESRs, the Association has expressed general support for accommodating the participation of DERs in RTO/ISO markets, but has asked FERC to find that DERs located behind the meter or on the distribution system should only be permitted to participate in RTO/ISO DER aggregation programs with the RERRA’s consent.
PURPA reform: FERC held a technical conference in 2016 to investigate certain of its Public Utility Regulatory Policies Act of 1978 implementation policies. Nothing came of the conference at the time, but in early 2018, then-FERC Chairman Kevin McIntyre directed Commission staff to reenergize FERC’s PURPA review initiative. (McIntyre relinquished his role as FERC chairman in October 2018 to focus on health-related issues and passed away in early January).
Association members have expressed concerns with PURPA’s mandatory purchase obligation, which requires electric utilities (including public power utilities) to buy qualifying facility (QF) power which they may not need, at rates that may be higher than what can be obtained from the market.
FERC has significant flexibility in implementing PURPA’s requirements, including determining who qualifies as a QF, establishing general rules for setting “avoided cost” rates that must be paid to QFs, and defining certain circumstances in which utilities can terminate their PURPA mandatory purchase obligations. FERC’s policies on these and other issues are likely to be evaluated as part of the agency’s PURPA review initiative.
FERC Chairman Chatterjee last year said that “this is an issue that has been top of mind for me since coming to the Commission.” He said that the current energy landscape “is profoundly different than that of the late ‘70s when PURPA was enacted and because of this many have rightly voiced their desire for a fresh look at existing policy to better align PURPA with the realities we face today.”
Resilience: The Association is also monitoring what actions, if any, FERC may take in connection with its 2018 investigation into grid reliability and resilience. After rejecting a rule proposed by the Secretary of Energy that would have provided cost support to coal and nuclear plants on “fuel security” grounds, FERC initiated its own investigation into grid resilience issues in January 2018 by issuing a number of questions to RTOs and ISOs. In May 2018, the Association filed comments in the proceeding arguing that, while vigilance on reliability and resilience issues was important, the RTO and ISO filings did not demonstrate the need for any specific FERC actions on resilience at this time, on either a generic or region-specific basis. The comments emphasized that any actions to promote resilience in the RTOs and ISOs should be undertaken on a regional basis, with input from regional stakeholders.
Environmental Protection Agency
Meanwhile, there are several environmental issues teed up for action this year that the Association is tracking including:
The Mercury and Air Toxics Standards rule: The U.S. Environmental Protection Agency in late December issued a proposed revised supplemental cost finding for the Mercury and Air Toxics Standards, or MATS, rule as well as the Clean Air Act required risk and technology review (RTR).
EPA is proposing to revise its response to the U.S. Supreme Court 2015 decision in Michigan v. EPA, which held that the EPA erred by not considering cost in its determination that regulation under section 112 of the Clean Air Act of hazardous air pollutant (HAP) emissions from coal- and oil-fired electric utility steam generating units (EGUs) is appropriate and necessary.
The agency proposes to determine that it is not “appropriate and necessary” to regulate HAP emissions from power plants under Section 112 of the Clean Air Act, thereby reversing the agency’s prior conclusion under Clean Air Act section 112(n)(1)(A) and correcting flaws in the EPA’s prior response to Michigan v. EPA.
In addition, EPA noted that it has completed the required RTR for MATS. The proposed RTR shows that no additional regulations are required.
In a recent joint letter sent to William Wehrum, the Environmental Protection Agency’s Assistant Administrator for the Office of Air and Radiation, the Association urged EPA to complete its RTR for power plants under section 112 of the Clean Air Act and to leave the underlying MATS rule in place and effective.
GHG emission standards: The EPA in December proposed revisions to the greenhouse gas (GHG) emission standards for new, modified, and reconstructed coal-fired power plants. The revised rule if finalized would replace the current standard based on carbon capture and storage with a more achievable standard based on high-efficiency generating technologies in combination with best operating practices. EPA also is taking comment on a number of issues related to the endangerment finding underpinning the section 111(b) regulation, including whether the agency must make a new finding with respect to each pollutant regulated from the source category. EPA’s current plan is to finalize the rule by June of 2019. In the meantime, the D.C. Circuit court continues to hold the CO2 NSPS litigation in abeyance while EPA proceeds with a rulemaking to revise the current CO2 NSPS rule. If finalized, the proposed revised standards would apply to new, modified, and reconstructed sources after the date the proposed rule is published in the Federal Register.
EPA plans to host at least one public hearing on the proposed rule and there will be a 60-day public comment period.
Amendments to EPA’s 2015 coal combustion residuals rule: Last summer, EPA issued a final rule that revises certain requirements of the coal combustion residuals (CCR) rule that EPA adopted in 2015. These revisions are the first set of many reforms to the 2015 rule planned for 2019 and beyond. The most important change is an extension of the mandatory closure deadline for CCR surface impoundments until October 31, 2020. The extension allows these surface impoundments to continue to operate while EPA completes additional rulemakings to fix other parts of the 2015 rule. EPA has committed to adopt these additional CCR reforms over the next 18 months. The most recent reforms are being challenged in the D.C. Circuit by environmental groups. In the meantime, the D.C. Circuit issued a decision in August that addressed all remaining issues in the litigation on the 2015 CCR rule. This court decision could make it much more difficult for EPA to reform the 2015 rule. Under a worst-case scenario, the court’s decision could require the closure of all unlined and clay-lined surface impoundments, which could trigger more coal retirements.
Revisions to the effluent limitation guidelines for fossil fuel-fired plants: In 2018, EPA granted petitions for reconsideration of the Effluent Limitations Guideline (ELG) rule. Subsequently, EPA issued a final rule postponing the start of the ELG compliance period by until November 2020, for bottom ash transport water and scrubber wastewater waste streams. EPA plans to issue a proposal to revise the ELG rule by March 2019 and a final rule in December 2019. The revised ELG rule will be based, in part, on new information and data that EPA has recently collected on technical feasibility and cost of control technologies for treating these two waste streams.
Other environmental proceedings we’ll be monitoring in 2019 include possible finalization of the Affordable Clean Energy rule and a revised definition of the “Waters of the United States,” or WOTUS.
The EPA last summer proposed to replace the CPP with a new rule (the Affordable Clean Energy Rule) that would let states decide how to make existing coal-fired power plants more efficient to lower their greenhouse gas emissions. EPA is expected to finalize the CPP repeal and ACE rule in March 2019.
Meanwhile, in December, The EPA and the Army Corps of Engineers unveiled a proposed new WOTUS definition that clarifies federal authority under the Clean Water Act.
The agencies will take comment on the proposal for 60 days after publication in the Federal Register.