This report is a collaborative effort to cover the significant developments within the electric industry over the last year and that are currently being addressed in the various regions of the United States.
Major rulemakings headlined the Federal Energy Regulatory Commission’s (“FERC”) agenda this year in the context of the transition away from fossil fuels/decarbonization and recent extreme weather events. FERC proposed major reforms to the regional transmission planning, cost allocation, and generator interconnection process. Additionally, FERC initiated rulemakings taking preliminary steps toward reliability reforms of the bulk powers system against extreme weather events. FERC also issued Order No. 881, which enacts reliability-related modifications to the Open Access Transmission Tariff (“OATT”) by improving line ratings.
The California Independent System Operator (“CAISO”) authored its first 20-year transmission plan forecast, identifying $30.5 billion in long-term infrastructure upgrades necessary to achieve California’s objective of 100% carbon‑free electric retail sales in the state by 2045. The New York Independent System Operator, Inc. (“NYISO”), ISO New England Inc. (“ISO-NE”), and PJM Interconnection Inc. (“PJM”) all sought FERC authorization to reform their respective market rules to facilitate state policies supporting decarbonization of the electric grid in those regions. Southwest Power Pool (“SPP”) and the Midcontinent Independent System Operator, Inc. (“MISO”) jointly identified seven possible transmission projects along a portion of their border to open up 53 GW of generation capacity for interconnection with the grid.
Several Northeast states have pursued decarbonization of the electric grid by codifying such goals.
Extreme weather events and tighter than normal anticipated reserve margins are issues that MISO addressed this year. State regulatory activity in the Midwest is oriented toward decarbonization goals. This activity is highlighted this year by the passage of the Climate and Equitable jobs Act into Illinois law. The omnibus statute addresses themes common to other states in the region and across the country—decarbonization targets for electricity generation, increased renewable generation targets, and transportation electrification initiatives. Another common theme in the Midwest is the adoption of regulations allowing for the securitization of costs associated with the early retirement of fossil fuel-powered generation. Also notable, Indiana and Iowa are addressing issues related to the regulatory treatment of small modular nuclear reactors.
Hurricane Ida struck Louisiana in August 2021, marking the second consecutive year a major hurricane made landfall in the state. Ida caused six direct deaths and 28 indirect deaths in addition to over $2.7 billion in utility-forecast storm restoration costs. Florida escaped Ida, but major Floridian utilities nevertheless sought, and received regulatory approval for, increases to their revenue requirements based on updated Storm Recovery Factors as the region faces more frequent extreme weather events.
Electric Reliability Council of Texas (“ERCOT”) market developments in connection with the February 2021 Winter Storm Uri continued to dominate the agenda of market regulators in Texas over the past year. Other topics reviewed include corporate mergers/acquisitions, resource planning and construction, hydrogen, transportation electrification, distributed energy resources, and storm cost securitizations.
States in the Western region continue to focus on realizing their decarbonization goals by promoting zero-emission vehicles through increased funding for incentives and development of transportation electrification infrastructure. Western states have also experienced a greater regulatory and industry focus on distributed energy resources in the context of the energy transition.
On April 21, 2022, FERC issued a notice of proposed rulemaking (“NOPR”) outlining reforms to the pro forma Open Access Transmission Tariff (“OATT”) and the pro forma Large Generator Interconnection Agreement to correct deficiencies in the FERC’s existing regional transmission planning and cost allocation requirements. If enacted, the NOPR headlined the requirements for interstate transmission providers to: (1) identify forward-looking transmission needs based on changes to the resource mix and demand by developing long-term scenarios, including accounting for high-impact low-frequency like extreme weather events; (2) more fully consider dynamic line ratings and advanced power flow control devices in regional transmission planning; (3) seek the agreement of state entities within the transmission planning region regarding cost allocation methods that will apply to transmission facilities selected in the regional transmission plan for long-term transmission planning; (4) identify opportunities to “right-size” replacement transmission facilities by adopting transparency requirements for local planning processes and coordinating between regional and local planning entities; and (5) revise their interregional transmission coordination procedures to reflect the long-term 20-year regional transmission planning reforms proposed in the NOPR. The NOPR proposes a requirement that transmission providers avoid construction work in progress (commonly known as “CWIP”) accounting for transmission facilities selected in a regional transmission plan.
The NOPR’s proposal for transmission providers to seek the agreement of relevant state entities on the cost allocation method (or methods) applied to facilities included in the regional plan will be an important factor moving forward. The need for clarity over how costs are allocated—and a method seen as fair—was highlighted by past FERC orders and this NOPR reiterates that need. The NOPR thus preliminarily finds that a formal opportunity for relevant state entities to develop a cost-allocation method would increase the stakeholder and state engagement to an extent that would increase the likelihood that transmission facility projects are sited with fewer delays. To that end, FERC proposes allowing transmission providers the option to revise their OATTs to include either or both of a Long-Term Regional Transmission Cost Allocation Method and a State Agreement Process to allocate the costs of long-term facilities. The chosen method must comply with the Order No. 1000 cost allocation for regional transmission planning principles. The NOPR proposes a flexible approach. There is no requirement for relevant state entities to determine an agreed method with transmission providers. An “agreement” may be new or an application of an existing provision between transmission providers and the relevant state entity. The NOPR proposes to require transmission providers establish a process and time period in their OATTs for states or transmission planning regions to negotiate a cost allocation method that is different than any ex ante method. The flexibility provided by this aspect of the proposed rule, and engagement of state-level entities, may be central to transmission planning timely responding to the energy transition.
Generation interconnection reform was a prominent issue in the advanced NOPR issued by FERC back in July, 2021, but was not addressed by the NOPR. Chairman Glick announced that FERC would instead take up generator interconnector reform in a separate rulemaking “in the months ahead,” along with rulemakings for interregional transmission development, transmission incentives, and transmission development oversight.
On December 16, 2021, FERC issued Order No. 881, which revised both the pro forma OATT and FERC’s rules on accuracy and transparency of electric transmission line ratings. Transmission line ratings are used in reliability and market models by various reliability and transmission planners to ensure that flows on transmission lines do not increase risk to reliability or damage to facilities. Line ratings establish the extent to which equipment associated with a power line is rated to withstand the thermal limit of transmission lines. Such lines generate heat due to the electrical resistance of the line or external factors such as solar irradiance.
FERC now requires: (1) ambient-adjusted line ratings (“AARs”) on transmission lines operated by public utility transmission providers; (2) Regional Transmission Organizations (“RTOs”) and Independent System Operators (“ISOs”) to create and oversee procedures for hourly reporting of line ratings on public utility transmission lines; (3) emergency ratings unique to each provider; (4) line rating methodology sharing between providers, RTOs, and ISOs and publication of such data on a password-protected website.
The AAR mandate is the central reform of Order No. 881. Use of AAR is forecast to produce significant reliability, operational, and economic benefits. The market monitor for MISO, for example, stated that reduced congestion charges from AAR implementation in the Midcontinent Independent System Operator (“MISO”) region would have produced savings in the region of $67 million and $49 million in 2019 and 2020 respectively. The NOPR defines an AAR as a transmission line-rating that reflects an up-to-date forecast of ambient air temperatures across the time period to which the rating applies which reflects the absence of solar irradiance over a time period of no more than an hour. AARs must be recalculated at least every hour. Transmission providers and RTOs/ISOs receiving transmission service requests that will end within ten days of the request must use AARs as the basis for the evaluation of transmission service. The pro forma OATT now also defines seasonal line ratings. Where longer-term service is requested, Order No. 881 requires the use of seasonal line ratings as the basis for evaluation of the requests and curtailments or interruptions.
Order No. 881 stopped short of requiring dynamic line ratings, which refers to line ratings with additional inputs beyond AAR such as wind and solar factors and the tension and sag of the transmission line. However, FERC has opened a rulemaking to explore a future dynamic line ratings requirement.
On June 16, 2022, FERC initiated two rulemakings seeking to improve the reliability of the bulk power system against extreme weather events. These rulemakings are the upshot of a process that began in June 2021 when FERC held a technical conference to discuss the threat to the electrical grid posed by climate change.
The first rulemaking proposed to direct the North American Electric Reliability Corporation (“NERC”) to submit modifications to develop Reliability Standard TPL-001-5.1 (on Transmission System Planning Performance Requirements) to address extreme weather. Specifically, NERC must: (1) develop benchmark planning cases based on past events and future weather projections; (2) oblige transmission providers to conduct studies on the effect of extreme weather on the providers resource mix on a current and prospective basis; and (3) instruct transmission providers to develop corrective action plans where performance requirements are not met during extreme weather events.
On benchmark planning, FERC directed NERC to proposed modifications in six discrete areas, but stated that NERC has ultimate control over what method is used to reach those benchmarks. FERC sees the benchmarks as an adequate basis for creating a sensitivity analysis against which the performance of various generation dispatch, system transfers, and load can be measured in the context of extreme heat and cold. FERC noted that performance requirements are already part of Reliability Standard “TPL-001-5.1.” and that the performance requirements are corollary to the benchmarks. Without a measure of system performance, such as stability, voltage, or thermal limits, the benchmarks do not inform to what extent a stakeholder is meeting the performance requirements.
The second rulemaking directs RTOs and transmission providers to submit one-time reports outlining how they assess their preparedness for extreme weather and to what extent they have identified mitigation strategies. The rulemaking requires the report to detail how transmission providers establish a scope for their extreme weather vulnerability assessments, develop inputs, identify vulnerabilities and determine exposure to extreme weather hazards, estimate the costs of impacts, and develop mitigation measures to address extreme weather risks.
On January 31, 2022, CAISO issued its first 20-year forecast for transmission expansion needs in the state, titled “20-Year Transmission Outlook” (“20-Year Plan”). Customarily, CAISO conducts a FERC-required annual 10-year transmission outlook. The 20-Year Plan identified $30.5 billion in long-term infrastructure upgrades necessary to achieve the state’s objective of 100% carbon‑free electric retail sales by 2045. CAISO explained that the longer term outlook was conducted with the goal of meeting California’s greenhouse gas reduction and renewable energy objectives reliably and cost-effectively. CAISO’s study worked backwards from a projected peak load in 2040, at 28.5% higher than 2020 peak load, and then adjusted for behind the meter additions. Another adjustment was accounting for a reduction of 15 GW of natural gas-fired generation. The result was an estimated need for 37 GW of battery energy storage, 4 GW of long-duration storage, over 53 GW of utility-scale solar, over 2 GW of geothermal, and over 24 GW of wind generation—totaling 120.8 GW. Then the 20-Year Plan detailed the necessary high-voltage bulk transmission upgrades, and arrived at the $30.5 billion figure. Approximately one-third each of that figure was allocated to existing upgrades to the CAISO footprint (consisting of 230 kV and 500 kV AC lines, HVDC lines, and substation upgrades), offshore wind integration lines, and out-of-state wind integration lines. The 20-Year Plan was developed as a baseline, recognizing that resource planning and procurement decisions will differ over the years ahead from the assumptions used to establish this baseline.
On March 17, 2022, CAISO approved its 2021-2022 10-Year Transmission Plan. The 2021-2022 Plan emphasized the need for long-term planning (conducted by the 20-Year plan discussed above) in light of the accelerating addition of new resources. CAISO explained that the 2020-2021 Plan was based on a requirement to add approximately 1,000 MW of new resources per year over the 10-year planning horizon, the 2021-2022 Plan projected 2,700 MW of new resources per year, and next year’s plan is expected to be based on over 4,000 MW of new resources. CAISO stated the following reasons for the acceleration: (1) the escalating need to decarbonize the electricity grid because of emerging climate change impacts, (2) the expected electrification of transportation and other carbon-emitting industries, which is driving higher electricity forecasts, (3) concerns regarding reduced access to opportunity imports as neighboring systems also decarbonize, (4) greater than anticipated impacts of peak loads shifting to later-in-the-day hours when solar resources are unavailable, and (5) the need to maintain system reliability while retiring the Diablo Canyon Power Plant and gas-fired generation relying on coastal waters for once-through cooling. The 2021-2022 Plan was approved by CAISO on March 17, 2022. At the time of writing, however, California Senate Bill 846 had been signed into law by Governor Newsom, extending Diablo Canyon Power Plant’s operation through 2030.
On January 5, 2022, NYISO submitted market rule changes intended to stimulate the investment needed to meet the state’s decarbonization and renewable investment mandates for consideration by FERC, which FERC accepted subject to condition in an order issued on May 10, 2022. Specifically, NYISO proposed revisions to its Market Administration and Control Area Services Tariff to: (1) exclude resources that further the goals of the Climate Leadership And Community Protection Act (“CLCPA”) from application of NYISO’s buyer-side market power mitigation rules (“BSM Rules”); (2) accredit all resources’ capacity value based on their marginal contribution to resource adequacy; and (3) compute NYISO’s capacity market demand curves using the derating factor for the reference peaking plant.
NYISO’s proposed changes to the BSM Rules are key to achieving the stated purpose of advancing the CLCPA goals. NYISO explained that its proposal would automatically exclude wind, solar, storage, hydroelectric, geothermal, fuel cells that do not use fossil fuel, and demand response resources from application of its BSM Rules. Other additional types of new capacity can qualify for the same exclusion subject to self-certification. NYISO submitted a study that concluded the following estimated changes to NYISO’s resource fleet between 2022-2026 that would result from reform of the BSM Rules: (1) a decrease in fossil-fueled resources of 2,384 MW; (2) an increase in onshore wind resources of 244 MW; (3) an increase in offshore wind resources of 1,200 MW; (4) an increase in grid-connected solar photovoltaic resources of 5,000 MW; and (5) an increase in battery storage resources of 1,571 MW.
NYISO asserted that its proposal would prevent potential suppressive price effects and argued that FERC has held that price suppression is not per se unlawful, but rather that buyer-side market power mitigation measures must balance investor and consumer interests. NYISO relied on this balancing analysis to argue that its requested changes to its BSM Rules were just and reasonable due to the proposal striking a balance between avoiding artificial price suppression and over-mitigation. NYISO also argued that the proposal accommodates New York State’s jurisdiction over “facilities used for the generation of electric energy” under Federal Power Act (“FPA”) Section 201 and that the proposal represents a legally durable solution to the tension between protecting FERC-jurisdictional markets and accommodating state policies.
FERC determined that it was appropriate to modify the current BSM Rules. But for NYISO’s proposal, the current BSM Rules threatened to increase costs, over-procure capacity, and distort ICAP price signals, along with interfering with the CLCPA’s requirements. FERC thus concluded that it was time to “change course” in light of the CLCPA and also prevent harms associated with over-mitigation. FERC also held that approval of NYISO’s proposal would focus buyer-side market power mitigation on those resources most likely to behave uncompetitively through the exercise of buyer-side market power.
FERC focused on three potential harms of the current BSM Rules in explaining its determination—over-procurement of capacity, inflated capacity market prices, and inefficient price signals from the capacity market. FERC noted NYISO’s Brattle Group analysis that modification of the BSM Rules would avoid additional costs to consumers of $400-$900 million per year by 2030. FERC also agreed with NYISO’s assessment that the proposal struck an adequate balance between protecting FERC-jurisdictional markets and accommodating state policies, stating that it is not necessary to “hermetically seal NYISO’s markets from the indirect effects of state policies” to ensure just and reasonable non-discriminatory rates.
The new BSM Rules went into effect May 11, 2022. This is timely, given that NYISO identified in its 2022 Power Trends Report that reliability margins in the region are declining concurrent with the state’s push for a greener grid. NYISO stated in the report that the “pace of deactivation of current fossil-fueled resources must not exceed the pace of development and deployment of new, non-emitting electricity supply resources that can provide the reliability services that New Yorkers expect.” Thus the extent to which the new BSM Rules stimulate investment in such non-emitting resources will be an important factor in how quickly decarbonization of the state’s electricity supply can be achieved.
ISO-NE also sought to reform its buyer-side market rules this year in the context of the state-sponsored efforts to promote non-emitting generation resources. On March 31, 2022, ISO-NE and the New England Power Pool Participants Committee (“NEPOOL”) submitted proposed revisions to ISO-NE’s Transmission, Markets and Services Tariff to modify the current minimum offer price rule (“MOPR”) in its Forward Capacity Market (“FCM”) through a two-year extension of the MOPR via the “Transition Mechanism.” Unlike NYISO’s BSM Rule reform, NE-ISO and NEPOOL’s MOPR tariff revision did not accredit all resources’ capacity value based on their marginal contribution to resource adequacy.
The joint submission stated that the MOPR is at the center of a “confounding challenge” to protect investors in generation resources and consumers who pay for capacity from two competing inefficiencies. On the one hand, allowing the below-cost capacity of state-sponsored resources to enter the FCM without application of the MOPR would reduce the clearing price in the FCM auction, harming investors’ ability to recover their costs. The investors thus would either raise their offer prices or withdraw from the market, thus harming consumers through increased capacity costs. On the other hand, employment of the MOPR to exclude state-sponsored resources from the FCM may have the effect of consumers paying “twice” for such capacity. State decarbonization policies fund the construction of the state-sponsored resources, which means they will be built anyway, at expense to consumers. Consumers thus pay for additional capacity as the region continues to meet its resource adequacy objectives solely with FCM resources, ignoring the reliability contribution of the state-sponsored resources that are excluded from market participation. Consumers thus pay twice—once to meet the resource adequacy objectives of the FCM and a second time to meet the clean energy and decarbonization objectives of the states. No party argued that the proposed MOPR reforms were unjust and unreasonable. Instead, argument was focused on the merits of the Transition Mechanism. ISO-NE and NEPOOL asserted that the Transmission Mechanism was needed to mitigate (1) concerns about adverse impacts to reliability from inefficient retirements and from likely delays in the development of state-sponsored resources, and (2) the need to provide the region time to undertake market reforms to facilitate the reliable transition to the new resource mix. On the latter point ISO-NE and NEPOOL offered the example of a year’s delay in energization of offshore wind projects resulting in an approximate 104 MW capacity margin in the region. Intervenors responded that such reliability concerns could be addressed by capacity accreditation rather than the Transition Mechanism and that there is no basis for asserting that offshore wind, the primary resource disadvantaged by the delay in MOPR Reforms, is over-accredited. Another point of distinction made by Intervenors was on the threat of delays to reliability. Intervenors states that delays are possible for every project, and that the projects with state support are less likely to suffer delay due to that support. Intervenors also noted that demand response resources have a capacity to come online quickly. In light of these arguments, Intervenors called ISO-NE and NEPOOL’s 104 MW deficit a worst-case scenario.
FERC determined that the Transition Mechanism was “a just and reasonable proposal” because the package of reforms presented by NE-ISO and NEPOOL had met the burden associated with that standard. In coming to this determination, FERC noted that the MOPR is not in itself a reliability tool but its operation contributes to reliability by altering the clearing price of the FCM auction. FERC determined that removal of the MOPR could affect reliability because the price shock could lead to early retirement of resources potentially needed during the extended cold conditions. In light of this, FERC agreed that the graduated reform to the MOPR through the Transition Mechanism was reasonable.
Even though NE-ISO and NEPOOL’s tariff revisions passed muster under the FPA and the FERC’s rules, the Chairman and Commissioners outlined their reservations in three concurrences. Chairman Glick stated that the best outcome would have been immediate reform of the MOPR without a Transition Mechanism, but that the package filed by NE-ISO and NEPOOL was just and reasonable. Chairman Glick urged ISO-NE to move forward expeditiously in developing and filing a capacity accreditation proposal to ensure that the FCM is accurately valuing the capacity contribution of all resources so that FERC-jurisdictional market can complement rather than contradict state resource decision-making. Commissioners Clements and Phillips stated that tariff revision presented a “path forward” to elimination of the MOPR—which they described as “a likely unjust and unreasonable tariff mechanism that, if left uncorrected, could force customers in New England to pay millions or even billions to prop up capacity that they do not want or need.” Commissioner Christie based his concurrence on his belief that RTO capacity markets should “accommodate the public policies of the states as long as the impacts, both in costs and reliability, of one or more states' public policies are not being forced onto other states not sharing those public policies.” Here no state in ISO-NE opposed the revised tariff. Commissioner Christie stated that the revised tariff may negatively affect reliability and cause higher prices for consumers, but that the consumers’ recourse for those impacts is the ballot box.
Commissioner Danly dissented, stating that the effect of the tariff revision was that the states pay new renewables out of market, and these resources would then bid zero in the capacity market, ensuring the resource gets a commitment, the result of which will have an “inevitable, albeit indirect, effect on FCA prices.” The result, Commissioner Danly stated, is the elimination of competition and consequently a rate that is in fact not a market rate, which cannot be just and reasonable as a market rate. Commissioner Danly concluded that the approved tariff revision will compromise reliability and that “[his] colleagues will have presided over a predictable, avoidable, and catastrophic failure.”
On July 30, 2021,PJM filed for revision to its minimum offer price rule (MOPR) by filing a “Focused MOPR” that revised the embattled “Expanded MOPR” approved by the Commission in 2019. However, the Commission was, and remains, divided over the revised tariff and so no Commission order was issued approving or denying the revisions. Per FPA Section 205, the Focused MOPR as filed went into effect on September 29, 2021.
The focused MOPR does not discriminate between generation resource types and allows capacity market sellers’ offers to include the extent to which a state supported their resource. The Focused MOPR, according to PJM, is just and reasonable attempt to (1) accommodate longstanding business models of public power and vertically integrated utilities; (2) accommodates state policies on resource mix, so long as they do not attempt to set the price of capacity; (3) protects against the exercise of buyer-side market power and improper state actions that would have a direct effect on capacity market clearing prices (i.e., Conditioned State Support); (4) for Conditioned State Support, applies only to generation resources receiving a state benefit if FERC accepts that the state program or policy would improperly condition such benefit on the resource clearing the market or offering at a specific price; and (5) for Exercises of Buyer-Side Market Power, applies only if, upon inquiry into a potential exercise of such power, PJM makes a determination based on evidence that the Capacity Market Seller has the ability and incentive to suppress the capacity auction clearing price, and that such potential price suppression would provide an overall net benefit to an affiliated Load Interest.
As required by FPA Section 205, the Chairman and Commissioners filed statements explaining their views with respect to the Focused MOPR. Chairman Glick and Clements stated that they would have voted to approve the Focused MOPR because it satisfied the just and reasonable standard and that it “abandons [FERC’s] deeply misguided campaign to ‘nullify’ the effects of legitimate state policies.” Commissioner Christie expressed his view that this proceeding was needlessly rushed, highlighted the PJM IMM’s comment that the PJM market would be better off with no MOPR rather than a reformed one, and that the focused MOPR fails to accommodate state policies while ensuring a credible capacity market to benefit consumers. Commissioner Danly stated that he would have voted against the Focused MOPR because it is almost certain that the MOPR would never actually be applied to any generation resource, which precludes FERC’s statutory duty to ensure PJM’s capacity market produces just and reasonable rates.
The lawfulness of the Focused MOPR, as enacted under Section 205(g)’s provision for default orders arising from a 2-2 vote deadlock at FERC, is currently the subject of a petition before the Court of Appeals for the Third Circuit.
On March 8, 2022 the SPP and MISO published the Joint Targeted Interconnection Queue (“JTIQ”) Study Report identifying seven possible transmission projects along a portion of their border that could open up 53 GW of generation capacity for interconnection with the grid. The ISOs stated that customer preference and changing policies have increased demand for renewables and that the resulting development of electrically remote resources to demand locations is not consistent with the existing grid—particularly along the seam between the two power pools. A major component of equitably interconnecting the seven projects is the cost allocation mechanism, which is undergoing discussion and development through a stakeholder process. The joint report stated that “it is expected that a novel approach of sharing the costs of the JTIQ Portfolio between both interconnection and transmission customers in both RTOs will be consistent with the objectives of the JTIQ Study and will satisfy regulatory requirements for transmission cost allocation.” How this “novel approach” develops may inform similar efforts across the nation to address the challenge of interconnecting remote renewable resources with centralized demand locations.
In the Northeast, there is a lot of discussion focused on the decarbonization of the electric grid. These discussions have resulted in several laws having been passed with the intent of meeting these goals. Below is a summary of the efforts in the northeast states at a cost of approximately $1.8 billion.
Massachusetts’ Global Warming Solutions Act (“GWSA”), enacted in 2008, is a comprehensive legislative initiative to reduce greenhouse gas emissions and take steps to address climate change. The GWSA requires a 25% reduction in greenhouse gas emissions from all sectors of the economy below the 1990 baseline emission level in 2020 and at least an 80% reduction in 2050. In December 2010, a limit was established of 25 percent below the 1990 level as the emissions limit for 2020 and the Massachusetts Clean Energy and Climate Plan for 2020 (“2020 CECP”) was released, outlining a portfolio of policies. In 2020, Massachusetts released its 2050 Decarbonization Roadmap, a plan to reach a net-zero greenhouse gas emissions goal by 2050. On June 30, 2022, the state certified the compliance with the 2020 emissions limit of 25% below the 1990 level, with an estimated emissions reduction of 31.4% below the 1990 level in 2020.
In Connecticut, two recently enacted laws: (1) the Act Concerning Climate Change Mitigation (“Mitigation Act”); and (2) the Act Concerning Clean Energy Tariff Programs (“Clean Energy Tariff”), further Connecticut’s commitment to mitigating the impacts of the climate crisis. The Mitigation Act, codified into law by a 2019 Executive Order, aimed to make the electric grid zero-carbon by 2040. The Mitigation Act, which became effective July 1, 2022, unifies policymakers and the electricity sector in their efforts to “fully transition[] Connecticut’s electric supply away from relying on natural gas oil to power its electric grid.” The Clean Energy Tariff, which will go into effect October 1, 2022, will expand programs that support distributing renewable energy generation, as well as small, renewable generation that is located on-site and helps reduce the energy burden of participating customers. The Clean Energy Tariff creates two categories of programs: (1) one which promotes an annual auction of Class 1 renewables (like solar and fuel cells) for commercial customers; and (2) another that includes an annual auction for Class 1 renewables but also provides “on-bill credits to subscribers in the same electric distribution service territory, mostly targeting low to moderate-income customers.”
On April 14, 2021, Governor McKee signed Rhode Island’s Act on Climate (the “Act”) into law, requiring all state agencies (as well as intuitions of higher education and quasi-public agencies) to commit to bold actions to push the state towards a “future of net-zero emissions.” The Act created the Executive Climate Change Coordinating Council, or EC4, which is working to assess, integrate, and coordinate climate change efforts throughout state agencies and strengthen environmental justice in the communities most susceptible to climate change and greenhouse gas emissions. Under the liberal construction of the Act, state agencies may “promulgate rules and regulations necessary to meet greenhouse gas emission reduction” goals the Act sets forth. The Act requires agencies and regulators in the state to take into account the Act’s climate reduction goals when considering all utility projects and regulations in general. The goals set forth by the Act include a 45% reduction in 1990 levels by 2030, and net-zero emissions by 2050. Like neighboring states, Rhode Island is working to achieve these goals by pushing for the increased development of off-shore wind facilities which aims to provide clean energy to the state in the coming years.
New Jersey’s Global Warming Response Act requires the state to reduce greenhouse gas emissions by 80% from their 2006 levels by 2050. The state’s 2019 Executive Order No. 89 outlines that by 2030, the state wishes to have a 50% reduction in greenhouse gas emissions, and by 2050, the state hopes to achieve a 100% carbon-free power supply. The Executive Order creates a climate resilience council, comprised of 16 state agencies tasked with carrying out the state’s reduction goals, as well as a costal resilience plan developed by the state to protect the state’s coasts after hurricanes over the past several years devastated the shoreline. As directed by the Executive Order, on October 12, 2021, the state published a Climate Change Resilience Strategy that includes 125 recommended actions across six priority areas to promote the long-term resilience of New Jersey to climate change.
New Hampshire has called for a reduction of greenhouse gas emissions to 80% below 2006 levels by 2050, though unlike many northeastern states, this target is not statutory. The target comes from 2009, when the state put out their Climate Action Plan. While the plan is not yet codified, the state runs many programs to financially incentivize renewable energy usage. In 2020, New Hampshire produced 19% of net electricity generation within the state itself. New Hampshire is also generating 60% of their in-state net electricity from the Seabrook Station nuclear plant, a carbon-free yet controversial method of electric generation. The political landscape of the state has yet to take strong legislative action. Although the governor has promoted off-shore wind development, the state is the only New England state electric grid that has not mandated greenhouse gas reductions throughout the economy.
Like the other northeastern states, Maine put forth their own climate action plan in 2020, titled “Maine Won’t Wait.” “Maine Won’t Wait” is a sweeping and ambitious plan to implement Maine’s climate action goals, including to cut Maine’s greenhouse gas emissions by 30% over the next 30 years. In May 2022, the Maine legislature passed into law “An Act Regarding Utility Accountability and Grid Planning for Maine’s Clean Energy Future” (the “Act”) requiring Maine’s utilities “to undergo a transparent ‘integrated grid planning’ process for developing a reliable electric grid that supports the transition to clean energy at the lowest possible cost.” The Act will work to incorporate public input to ensure transparency in the planning process and will also consider environmental justice and inclusion. The Act directs the Maine Public Utilities Commission to launch the first grid planning proceeding on November 1, 2022.
New York’s Climate Leadership and Community Protection Act (the “Climate Act”) aims to reduce carbon emissions 40% by 2030 and 85% by 2040, and a 100% zero-emission electricity by 2050. The Act developed the Climate Action Council, which oversees the state’s clean energy and climate goals, and the Climate Justice Working Group, which aims to provide strategic advice to stakeholders to ensure disadvantaged New Yorkers are considered in climate policies. On December 30, 2021, the Climate Action Council released a Draft Scoping Plan, which provides several scenarios informed by proposed policies and actions to help the state meet its ambitious climate directives as part of the Climate Act. The public comment period on the Draft Scoping Plan closed on July 1, 2022 and a final scoping plan is expected to be released by January 1, 2023.
Pursuant to Vermont’s Global Warming Solutions Act, the state must reduce greenhouse gas pollution to 26% below 2005 levels by 2025; emissions need to be 40% below 1990 levels by 2030 and 80% below by 2050. In December 2021, Vermont released its Climate Action Plan (the “Plan”) which will study and report to the Vermont Climate Council recommendations on many aspects of decarbonization, as well as a general shift away from fossil fuels and fossil fuel-dependent equipment. Additionally, the Plan will improve on electric vehicle charging station availability, provide incentives for electric cars, strengthen preservation efforts and invest in agriculture and land management practices that help reduce emissions. The Climate Council is currently working on funding for projects and is “engaging the public in the recommendations” regarding the Plan.
Severe storms and their costs are evolving into annual matters for more electric utility regulators in the Southeast. Accordingly, utilities are seeking and receiving base rate increases for non-storm operations plus rate increases for storm restoration and storm protection investments.
For the second year in a row, a major hurricane made landfall in Louisiana causing billions of dollars of storm restoration costs. In August 2021, Hurricane Ida made landfall at Port Fourchon as a category 4 hurricane, with 130- knot winds equaling the intensity of Hurricane Laura, the most intense most devastating hurricane to make landfall in Louisiana. A devastating storm surge accompanied Ida and penetrated well inland from the immediate coastline across portions of southeastern Louisiana, with maximum inundation levels occurring on the east bank of the Mississippi River. The estimated damage in Louisiana from Ida’s winds and storm surge was $55 billion, but Ida was also responsible for billions in damages as far away as Pennsylvania, New York, and New Jersey due to freshwater flooding. Additionally, Ida was responsible for 6 direct deaths and 28 indirect deaths, including 13 from post-storm heat exhaustion. Entergy Louisiana, LLC (“ELL”) and Entergy New Orleans, LLC reported approximately $2.7 billion of estimated storm restoration costs associated with Ida and decreased revenues from extended power outages resulting from the hurricane.
Less than a month after Hurricane Ida, ELL filed its Application for Approval of Ratemaking Adjustment for Interim Hurricane Ida Financing and Request for Expedited Treatment with the Louisiana Public Service Commission (“LPSC”). Therein, ELL explained its plan to issue up to $1.0 billion in short-term first mortgage bonds to provide temporary financing of storm restoration costs at a reduced cost to customers pending further regulatory proceedings. Further, ELL requested and the LPSC granted authorization for ELL to exclude short-term debt up to $1.0 billion from the derivation of ELL’s capital structure and cost of debt for ratemaking purposes, including the determination of the allowance for funds used during construction.
In Florida, storm protection has become a regular part of the Florida Public Service Commission’s (“FPSC”) calendar as electric utilities there seek to recover their storm protection costs associated with protecting and strengthening transmission and distribution electric utility infrastructure from extreme weather conditions. Florida statute requires the Florida electric utilities to file ten-year storm protection plans and established annual proceedings to review the prudence of storm protection plan (“SPP”) costs and set SPP cost recovery clause rates to recover SPP costs. In August 2021, the FPSC approved the calendar year 2022 SPP cost recovery clause revenue requirements of $104.3 million for Duke Energy Florida, LLC (“DEF”); $233.1 million for Florida Power & Light Company (“FP&L”) and Gulf Power Company (“Gulf”) combined; and $48.0 million for Tampa Electric Company (“TECO”). Assuming usage of 1,000 kilowatt-hours per month, these amounts add from $2.14 to $3.29 to a Florida residential customer’s monthly bill, depending on the utility.
On top of that, the FPSC approved rate increases for FP&L, TECO, and DEF. The FPSC approved a stipulation unifying FP&L and Gulf’s rates and granting a rate increase of $692 million effective January 1, 2022 and an additional rate increase of $560 million effective January 1, 2023. The stipulation provides for an authorized return on common equity (“ROE”) range of 9.7% to 11.7% with all rates being calculated using a 10.6% ROE subject to readjustment in the event of a significant interest rate increase. The FPSC also approved a stipulation granting TECO granting an initial rate increase of $122.7 million effective January 1, 2022 and additional rate increases of $49 million effective January 1, 2023 and $79 million effective January 1, 2024. The stipulation provided for an authorized ROE range of 9.00% to 11.00% with all rates being calculated using a 9.95% ROE (subject to readjustment in the event of a significant interest rate increase) with a fixed equity ratio of 54%. Finally, the FPSC approved a stipulation granting DEF granting an initial rate increase of $67 million effective January 1, 2022 and additional rate increases of $49 million effective January 1, 2023 and $79 million effective January 1, 2024. The stipulation provides for an authorized ROE range of 8.85% to 10.85% with all rates being calculated using a 9.85% ROE subject to readjustment in the event of a significant interest rate increase.
The Georgia Public Service Commission (“GPSC”) did not have to address storm-related issues but did have to approve a rate increase for the expected commercial operation of Vogtle Unit 3. The GPSC approved a stipulation establishing Georgia Power Company’s rates when Vogtle Unit 3 reaches commercial operation in the middle of 2022. The stipulation provides for a deemed prudent amount of $3.5 billion for Unit 3 and Common plant resulting in a rate base increase of $2.1 billion the month after commercial operation occurs and further set a depreciation rate of 1.677% but deferred depreciation expense until the conclusion of the GPSC’s prudency review. The stipulation lowered the expected rate adjustment for Unit 3 from $370 million to $300 million.
MISO continues to address reliability issues associated with extreme weather events and its changing resource mix. In September 2021, MISO released its comprehensive report on the February 2021 extreme winter weather event. The report underscored the importance of the Reliability Imperative in detailing the 2.93 GW of emergency load reductions MISO ordered throughout the region for February 15-16, 2021. The report emphasized five areas for improvement: (1) ensure generation meets its delivery commitments when needed through winterization, with emergency load reduction remaining a last resort; (2) a switch to seasonal resource adequacy approach as supply and demand equilibrium becomes more common; (3) new transmission capacity with improved interregional coordination and interconnection will facilitate reliability; (4) improved access to data through automation and advanced analytics is essential to support event and post-even analyses; and (5) holistic support and alignment of all stakeholders to ensure reliability through forward-looking plans and decisions.
The 2022 Organization of MISO States (“OMS”) and MISO Survey predicted an accelerated reduction in capacity and substantial increases in load in the region in its 2022 survey. This is a significant change over its 2021 survey. OMS states that MISO will be reliant on emergency or non-firm resources, such as imports to offset this deficit, which are not reflected in the survey. The Independent Market Monitor (“IMM”) for MISO has also identified the operation of MISO’s capacity pricing market as a driver behind lack of investment in new capacity in the MISO footprint. The IMM recommended a reliability-based sloped demand curve that assigns value to deferred resource retirements and incents investment in capacity by rewarding capacity-suppliers with revenues that reflect their contribution to the system’s reliability needs to address this issue.
It is in this context—extreme weather events, particularly above-normal summer peak load, and tighter than normal anticipated reserve margins—that this summer NERC assessed that MISO’s expected resources do not meet operating reserve requirements even under normal peak-demand and outage scenarios.
In September 2021, Illinois Governor J.B. Pritzker signed the omnibus Climate and Equitable Jobs Act (“CEJA”) into law. The CEJA includes sections on time-of-use pricing, a distributed generation rebate, net metering, energy efficiency program reform, transportation electrification, and an equitable energy upgrade program. The bill codifies several policies supporting the state’s transition to 100% clean energy by 2050, including the preservation of existing nuclear generation, doubling the minimum nameplate capacity required for utility-scale wind and solar projects, and investigating alternative technologies, such as energy storage. The CEJA mandates the retirement of all investor-owned and municipality-owned coal plants by 2030 and 2045, respectively, and requires greenhouse gas emitting units, such as gas-fired generation resources, to retire or reduce emissions to zero through hydrogen or similar technology by 2045. The new law also requires large utilities to file a “Multi-Year Integrated Grid Plan” with the Illinois Commerce Commission (“ICC”) by 2026, whereupon the ICC must consider the plan in the context of the CEJA and the specific objectives of the Grid Plan Program. The CEJA mandates a variety of programs to incent EV uptake and offer rates that optimize charging times. Large utilities are required to request a public interest determination from the ICC on their Beneficial Electrification Plan by July 1, 2022.
In 2021, the Indiana legislature codified a pathway for securitization of retired electric utility assets and directed the Indiana Utility Regulatory Commission (“IURC”) to conduct a rulemaking for the securitization program on an expedited basis. The IURC promulgated the rule in December 2021. In 2022, the legislature took steps to manage the state’s transition from coal-fired generation by passing legislation establishing regulatory pathways for small modular nuclear reactors (SMRs) and underground pumped storage hydropower. The legislature modified the Indiana Code regarding certification of convenience and necessity (“CCN”) for power plant construction to include a subsection on small modular nuclear reactors (“SMRs”). The new law requires the IURC to consider whether a utility petitioning for a SMR CCN is replacing existing hydrocarbon-based generation facilities and to what extent the utility could use the same site for the SMR. In addition, the legislature added underground pumped storage hydropower using abandoned coal mines to the definition of a “clean energy resource.” SMRs and underground pumped storage hydropower now qualify for IURC approval as clean energy projects eligible for certain financial incentives. Finally, House Bill 1221 defined the IURC’s role in regulating transportation electrification. The bill exempts (non-utility) owners and hosts of EVs and EV charging stations from regulation by IURC, authorizes hosts and owners of EV supply equipment who make the equipment available to the public to charge by the kwh, defines an electric utility “EV pilot” program for jurisdictional utilities, authorizes utilities to file for approval of pilot programs, and authorizes the IURC to approve the pilot programs and the associated cost recovery.
In January 2022, MidAmerican Energy Company filed a Request for Approval of Ratemaking Principles with the Iowa Utilities Board for its proposed Wind PRIME Project. If approved, the project would add over 2 GW of new wind generation and up to 50 MW of solar generation. MidAmerican stated in its application that the project would allow it to serve 111% of its customers’ projected annual energy needs with renewable generation in 2025 and keep its resource mix at the 100% level into the next decade. The filing proposed a “Technology Study Costs” ratemaking principle to address the treatment of costs associated with a range of studies related to carbon capture and sequestration, energy storage, and small modular nuclear reactors.
In 2021, Kansas passed the Utility Financing and Securitization Act, allowing public utilities to retire aging generation earlier than planned through securitization of the energy transition costs associated with the asset. The bill requires the Kansas Corporation Commission to determine whether the energy transition costs are reasonable. Like the Missouri law, permissible costs include the undepreciated investment in retired or abandoned electric generating facilities, costs of decommissioning and restoring the site, as well as other applicable capital and operating costs, accrued carrying charges, and deferred expenses. The Kansas law also permits the securitization of “qualified extraordinary costs” tied to extreme weather events.
Governor Whitmer set the state’s carbon neutrality target to 2050 via executive order back in 2020. The Michigan Public Service Commission issued an order on August 11, 2021 encouraging investor-owned utilities to propose utility-scale energy storage pilot programs as part of their upcoming rate cases. Uptake of pilot programs by utilities will be an important first step if Michigan is to reach 4000 MW of storage capacity by 2040 and reach its carbon neutrality deadline. Another development this year that may have larger future implications for the deadline is a plan from WEC Energy Group to test a 25/75 percent fuel blend of hydrogen and natural gas at a natural-gas fired plant in the Upper Peninsula of Michigan.
The Minnesota Public Utilities Commission (“MPUC”) approved Northern States Power Company’s Integrated Resource Plan (“IRP”) with modifications in an order issued April 15, 2022. The modifications did not affect the key aspects of the plan: retirement of all of the utility’s coal-fired generators in the jurisdiction, extension of Monticello Nuclear Plant’s operating life by ten years, and adding substantial amounts of solar- and wind- powered generation. The MPUC ordered the utility to report on integration of advanced technologies—namely utility-scale storage and hydrogen fuel. As part of its ongoing EV planning process, the MPUC approved Xcel Energy’s EV Optimization Pilot to study the management of EV grid impacts by incentivizing customers to schedule their daily EV charging outside of the utility’s system peak hours. The pilot evaluates how managed charging can reduce EV impact on the bulk electric system during peak hours and support the utility’s demand-management programs and rates related to EVs.
In July 2021, the Missouri governor signed into law a securitization bill that permits utilities to petition to the Missouri Public Service Commission (“MPSC”) for authority to issue bonds to finance early retirement of generation units. The legislation provides utilities a mechanism to guarantee recovery of undepreciated investment in plant through the non-bypassable securitized bonds. The rate of return on such bonds are lower than utility’s cost of capital, which is key to making early retirement of aging generation an attractive option for both utilities and ratepayers. Under the new law, the MPSC must determine that early retirement of the asset is reasonable and prudent, and that the “energy transition costs.” Permissible costs include the undepreciated investment in the retired or abandoned electric generating facility and any ancillary facilities, costs of decommissioning and restoring the site of the electric generating facility, other applicable capital and operating costs, accrued carrying charges, and deferred expenses. The law also allows for securitization of “qualified extraordinary costs” tied to extreme weather events.
In April 2022, Wisconsin’s Office of Sustainability & Clean Energy published the state’s Clean Energy Plan (“CEP”), which lays out the state’s vision for achieving 100% carbon-free electricity by 2050. The CEP recommended legislation authorizing the Public Service Commission of Wisconsin (“PSCW”) to consider the social cost of carbon when evaluating construction certifications and all other resource allocation decisions. The CEP also recommended legislation permitting a securitization mechanism for utilities to retire power plants using environmental trust bonds. The CEP recommended that the PSCW develop an IRP process requiring all Wisconsin utilities to file a plan on a regular schedule indicating the utility’s short- and long-term resource mix. The CEP also recommended the PSCW incentivize load management and demand response through new programs. The PSCW has opened a rulemaking to update interconnection standards with a view to specifically addressing energy storage, and enabling small-scale renewables more generally in the state. The PSCW has already opened a docket to address issues related to the CEP’s recommendation to expand the state’s renewables incentivization program, “Focus on Energy.” The same docket will address the CEP’s recommendation that PSCW grant programs to support community microgrids. Finally, the PSCW has opted to address the CEP’s recommendations on EV adoption and infrastructure on a case-by-case basis.
ERCOT and the Public Utility Commission of Texas (“PUCT”) made progress over the past year implementing the numerous bills the Texas Legislature passed in May 2021 to overhaul the Texas electricity market and grid in response to Winter Storm Uri, which struck Texas in February 2021.
With regard to grid reliability, the PUCT adopted new weatherization rules for generation entities and transmission and distribution service providers in ERCOT, as required by Senate Bill 3 (“SB 3”), in October 2021, and revised its state-wide emergency operations plan requirements in February 2022. With regard to the wholesale market redesign element of SB 3, the PUCT developed and approved a two-phase “blueprint” in December 2021. Phase One of the blueprint focuses on immediately actionable items to be implemented in 2022 to improve price signals and operational reliability and to enhance ancillary services, while Phase Two focuses on longer-term wholesale market redesigns.
As part of Phase One of the blueprint, the PUCT has already modified the operating reserve demand curve to raise the minimum contingency level (“MCL”) from 2,000 megawatts (MW) to 3,000 MW and to lower the high system-wide offer cap and value of lost load (“VOLL”) from $9,000 per megawatt-hour to $5,000 per megawatt-hour. The PUCT further indicated it would, in the future, decouple the system-wide offer cap and VOLL and “establish a new VOLL based on quantitative analysis of new revenue to the market that would be directed to reliable generation assets during scarcity events.”
Phase One of the blueprint also indicated the PUCT would adopt changes to allow for more targeted demand response to increase utilization of load resources for grid reliability, including (1) pursuing measures to change demand response pricing from zonal to locational marginal pricing, (2) setting higher performance standards for energy efficiency programs, and (3) directing ERCOT to evaluate actions already taken to accommodate customer aggregation participation as “virtual power plants” (“VPPs”) and to identify barriers for VPP participation in the real-time and ancillary services markets.
The PUCT also modified the emergency response service (“ERS”), which can be provided by load and distributed generation, by authorizing earlier ERCOT deployment of ERS (at MCL instead of waiting until after calls for conservation) and indicating it would determine whether the approach to limits on ERS procurement should be changed to be based on a specific MW quantity instead of the existing fixed dollar limit and whether the ERS program should include a seasonal apportionment.
In Phase One of the blueprint, the PUCT also ordered several new ancillary services including fast frequency response service (which can often be provided by energy storage resources), the expansion of non-spin ancillary service to allow load participation, a firm-fuel product to provide additional grid reliability from resources with certain fuel storage capabilities during extreme cold weather, voltage support compensation for resources that can provide voltage support, and ERCOT contingency reserve service, a “ramping” product to help manage increasing variability and ramping issues associated with higher renewable generation penetration on the grid.
ERCOT detailed how it would implement the Phase One directions and estimated timelines in a January 10, 2022 compliance filing.
With regard to Phase Two of the blueprint, the PUCT plans to develop a “load-side reliability mechanism” to provide economic incentive to ensure sufficient dispatchable supply to meet ERCOT demand. Under the agreed blueprint, this mechanism may take the form of a load‑serving entity obligation, or be based on dispatchable energy credits, or a hybrid of the two. Second, the PUCT will develop a backstop reliability service to prospectively target specific reliability needs that will not be met by ERCOT's real-time and ancillary services markets by procuring accredited new and existing dispatchable resources to serve as “an insurance policy” to help prevent emergency conditions in ERCOT.
In February 2022, ERCOT identified issues and questions to be addressed by stakeholders and the Commission as it moves forward with Phase Two. In May 2022, the PUCT engaged a third-party consultant to recommend implementation strategies and support the PUCT in the further development of business strategies for the Phase One and Two reforms.
In May 2022, the Independent Market Monitor (“IMM”) for ERCOT filed its annual “state of the market” report and indicated that, in 2021, over 7,000 megawatts (“MW”) of new wind and solar resources, 820 MW of energy storage resources, and approximately 700 MW of natural gas supply came online in ERCOT. The IMM also explained that changes to ERCOT’s operational posture implemented in the second half of 2021 substantially affected market outcomes, including increased non-spinning reserve requirements, more routine use of reliability unit commitments, and adjusting the selection of forecasts to more frequently rely on the highest load forecast and the lowest wind and solar forecasts. Finally, according to the IMM, the most important market change under way is ERCOT’s improvement of its real-time market to optimize the scheduling of its resources every five minutes (i.e., real-time co-optimization (“RTC”)), but, due to significant issues identified after Winter Storm Uri, ERCOT has postposed RTC past its previously planned go-live goal of 2025. The IMM recommended that RTC be prioritized because of its promise to improve pricing during supply shortages and to better utilize the existing fleet.
Another major aspect of the governmental response within ERCOT to the financial impact of Winter Storm Uri was implementation of securitization (the issuance of low-interest bonds funded by non-bypassable charges on customer bills) to improve liquidity in the market and ensure an orderly reimbursement of funds owed by and to market participants. The Texas Legislature authorized securitization through several additions to the Texas Public Utility Regulatory Act. First, ERCOT was authorized to finance the payment of Winter Storm Uri default balance of roughly $800 million with the Texas economic stabilization fund, rather than through uplift charges to market participants, which, under existing rules, would have taken decades to implement. The PUCT issued a debt obligation order concerning the default balance on October 14, 2021. Second, the legislature provided for financing of the uplift balance owed by load-serving entities—municipally owned utilities, electric cooperatives, and retail electric providers— through securitization in an amount of up to $2.1 billion, which financing would be allocated to participating load-serving entities on a load ratio share basis. The PUCT issued a debt obligation order concerning the uplift balance on October 13, 2021. Finally, the legislature created a securitization financing mechanism for electric cooperatives to finance recovery of extraordinary costs and expenses incurred during Winter Storm Uri and owed to ERCOT. Under the statutory provisions, the board of the cooperative (and not the PUCT) issues the financing order stating the amount to be recovered and the period over which the non-bypassable charges are to be recovered. In February 2022, Rayburn Electric Cooperative become the first such cooperative to securitize its Winter Storm Uri debt, issuing bonds for over $900 million.
In December 2021, the New Mexico Public Regulation Commission (“NMPRC”) rejected Avangrid’s application for approval of its proposed acquisition of PNM Resources, including PNM’s subsidiary Public Service Company of New Mexico. Avangrid is a subsidiary of Spanish power giant Iberdrola. The unanimous denial was issued despite almost all intervenors—including customer and clean energy advocates—stipulating to an agreement in support of the transaction. Intervenor New Energy Economy did not support the agreement and had urged the NMPRC to deny the application in large part because it claimed Avangrid, which owns eight electric and gas utilities in the Northeast, had faced extensive fines, penalties, and rate reductions for unreliable and expensive electric service in those other jurisdictions. The NMPRC adopted the recommendation of its hearing examiner to reject the stipulation and the application. In explaining its decision, the NMPRC contrasted the financial assurances put forward by Avangrid to the potential “ongoing” nature of the risk of “quality-of-service issues, including reliability, as well as risks of improper subsidization of non-utility activities” should the deal go ahead. Avangrid has appealed the NMPRC’s decision to the New Mexico Supreme Court.
In July 2021, after several years of consideration and voluminous input from commissioners, staff, and the public, the Arizona Corporation Commission (“ACC”) published a rulemaking to revise numerous rules affecting resource planning for the state’s electric utilities. Among other things, the revised rules would require each electric utility to seek approval every three years, from the ACC, of a Clean Energy Implementation Plan through which the electric utility would be required to achieve standards for energy efficiency savings; energy storage systems (including distributed storage); carbon emissions reductions; and, for load-serving entities (“LSEs”), demand-side resource capacity. The carbon emissions goals include an interim goal of 50% reduction by 2032 and an ultimate goal of 100% reduction by 2070. Additionally, the proposed rules would create a new resource planning process for LSEs, including approval processes for the LSE’s load forecast and needs assessment and a new process to be used for virtually all new resource procurement. In January 2022, the ACC rejected the adoption of the proposed energy rules in a 3-2 vote. The Chair and other Commissioners that voted against the proposed rules stated their support for allowing the energy efficiency and resource planning standards to go forward in separate rulemakings. Commissioner O’Connor, who opposed the rulemaking, stated that state-level carbon-reduction rules were not necessary in light of Arizona utilities’ “serious and sincere” commitment to decarbonization.
On December 13, 2021, Salt River Project Agricultural Improvement and Power District (“SRP”) filed an application with the ACC for approval to expand its existing Coolidge Generating Station, a natural-gas-fired simple-cycle power plant located in Coolidge, Arizona. The proposed expansion would consist of 16 individual simple-cycle combustion turbine generator units, each producing up to 51.25 MW, for a total of 820 MW, and associated interconnection facilities including new 500 kV transmission lines and a new 500 kV switchyard. SRP stated that the expansion would allow SRP to meet near-term capacity needs in its service territory, which, it asserted, is among the fastest growing regions in the nation, while also providing needed capacity and reliability to facilitate the integration of additional renewable resources.
In April 2022, the ACC denied the SRP’s application, citing insufficient evidence and community impacts. In its order, the ACC accepted that there was a need for the project, but noted that SRP did not perform an all-source request for proposals (“RFP”) prior to its board voting to proceed with the project even though its 2018 Integrated Resource Plan specifies that the utility should go through an all-source RFP for new contracts for new-build generation. Further, in its order, the ACC explained that the closest community to the plant is the unincorporated community of Randolph, a historic Black community, currently with approximately 150 residents, established in the 1920s. The ACC found that the conditions contained in the application do not adequately compensate the citizens of Randolph for the damages they would incur as a result of approving the project and as such, the balance of the need for adequate, economical and reliable power with the effects on the total environment did not weigh in favor of approving the application. The ACC voted to deny SRP’s motion for rehearing on June 6, 2022.
Also impacting resource planning in Arizona, Arizona House Bill (“HB”) 2101 was signed into law by Governor Ducey in April 2022, repealing retail choice in the state by removing a statutory pathway for competitive access by retail electricity providers in the service territories of public utilities. Tying its purpose to promoting reliability to avoid the types of disruptions seen recently in other states, HB 2101 expressed the public policy of Arizona that “electric service requires infrastructure planning and investments by the public service corporation responsible for its service territory in order to maintain reliable and affordable electric service.” Green Mountain Energy, which had sought to enter the Arizona market as a retail electric service provider, called the law a maneuver by Arizona utilities to deny Arizonans retail choice, stating “monopolies do not like competition.”
The State of New Mexico and Pattern Energy executed 11 leases enabling a portion of Pattern’s SunZia wind project, clearing the way for the developer to erect turbines on 230 square miles of state trust land. The leases collectively mark the largest leasing of trust land in New Mexico history. Pattern’s wind projects in the state are expected to add an additional 3,000 MW to Pattern’s wind portfolio in the region. Pattern has already brought four wind projects online in central New Mexico with a combined capacity in excess of 1,000 MW.
The SunZia project also involves significant transmission development. In particular, work continues in New Mexico and Arizona on developing the SunZia Southwest Transmission Project, which consists of two planned 500 kV transmission lines located across approximately 520 miles of federal, state, and private lands. The purpose of the project is to transport up to 4,500 MWs of primarily renewable energy from New Mexico to markets in Arizona and California. The project was evaluated through the National Environmental Policy Act process from 2009 to 2015, when initial approval was obtained for a right-of-way grant on federal lands administered by the Bureau of Land Management (“BLM”). SunZia recently submitted a new application to amend its existing right-of-way grant to reflect a number of route modifications, to move the east substation closer to proposed wind generation projects, and the addition of a substation (SunZia West) on private land in Arizona. The BLM is taking comments on the application and a revised Environmental Impact Statement through August 2022.
In Texas, the PUCT issued an order in October 2021 requiring the construction of new transmission facilities to ease the transmission constraints that currently limit the flow of electricity in and out of the South Texas region. In particular, the PUCT ordered the construction of a new second circuit on an existing double-circuit-capable 345-kV transmission line and new transmission facilities to “close the loop” between the end of the new second circuit and other facilities in the South Texas region. This was one of the first instances of the PUCT using its authority to mandate the construction of new transmission facilities for reliability reasons. As directed, two area transmission service providers, AEP Texas and Sharyland Utilities, filed an application to address routing issues for the new transmission facilities in June 2022.
The past year has seen increased activity in the low and zero-carbon hydrogen space across the southwestern states. Hydrogen is regarded by many as a potentially important part of a carbon-neutral energy mix. States in the southwest region explored incenting renewable hydrogen production through legislation to varying degrees in 2022.
Oklahoma legislators passed a number of new laws establishing the legal framework to encourage the state’s residents and businesses to develop Oklahoma into a regional hub for hydrogen power. Senate Bill (“SB”) 1853 set a production target of two million metric tons of hydrogen fuel using “a low or zero carbon source of energy annually by 2028.” SB 1853 expressly states that hydrogen fuel produced from “low carbon sources such as natural gas” qualifies for inclusion in the production target. In Arizona, the state legislature passed SB 1396, which established a hydrogen study committee tasked with investigating a legal framework for hydrogen infrastructure and hydrogen production “from any fuel source.”
In contrast to Oklahoma and Arizona, the New Mexico Legislature’s Commerce and Economic Development Committee rejected HB 288, otherwise known as the Hydrogen Hub Development Act, in February 2022. HB 288 offered tax incentives to companies based on the carbon intensity of their hydrogen production. However, environmental groups claimed that those incentives were too generous and that incenting hydrogen production would detract from decarbonziation.
In Texas, an electric utility proposed construction of a hydrogen-fueled electric power plant. In September 2021, Entergy Texas filed an application to amend its certificate of convenience and necessity to construct, own, and operate a new combined-cycle combustion turbine facility in Bridge City, Texas. According to the application, the proposed 1,215 MW project is based on modern, commercially-proven combustion turbine technology with dual fuel capability, able to co-fire up to 30% hydrogen by volume upon commercial operation and upgradable to support 100% hydrogen operations in the future, as market conditions dictate. A hearing on the merits of the application took place in June 2022.
In December 2021, the ACC adopted Phase II of the state’s transportation electrification (“TE”) plan when it approved the joint application of Arizona Public Service Company, UNS Electric, Inc., and Tucson Electric Power Company. Phase I was approved in 2019 and provided a conceptual framework for TE planning in the state. Under the plan approved for Phase II, near-term actions (one year) will include continued stakeholder engagement and coordination, charging station siting studies, and interconnection process support; while medium-term actions (one to four years) will include pilot program development, enacting TE legislation, and charging station deployment. Under the ACC’s order, the utilities were directed to file semi-annual progress reports detailing the status and implementation of the plan and, beginning on June 1, 2022, and at a minimum every three years thereafter, the utilities shall file a new TE implementation plan for review and approval, within 180 days, by the ACC.
In New Mexico, the NMPRC also began approving utility TE plans. El Paso Electric, Southwestern Public Service Company, and the Public Service Company of New Mexico all had TE plans approved by the NMPRC. The plans were filed pursuant to the New Mexico Transport Electrification Statute, which became law in 2019 and required investor-owned utilities to seek the NMPRC’s approval to expand transportation electrification efforts. The TE statute further provided that a public utility which undertakes measures to expand TE under the statute would have the option of recovering its reasonable costs for the expansion through a commission-approved tariff rider or base rates, or both.
Under the New Mexico TE statute, utilities are permitted to seek recovery of costs associated with incentives or investments that facilitate transportation electrification, rate designs or programs that encourage transportation electrification, and customer outreach and education programs associated with electrification. The TE plans are considered in light of statutory criteria regarding, among other goals, efficiency and flexibility, increased access to use of electricity as a transportation fuel (including such access by low-income users and underserved communities), reduction of air pollution and greenhouse gases, increased choices in electric vehicle charging, and whether the programs are otherwise reasonable and prudent. In April 2022, following its approval of the three TE plans, the NMPRC opened a rulemaking with the general goal of considering further policy options regarding TE, matters of statutory construction, and other issues that may be addressed through rulemakings.
In May 2022, the PUCT issued a request for comments on questions regarding distributed energy resources (“DER”) to assist the PUCT in identifying relevant issues and scoping further inquiries in this area for the State of Texas. The question topics focused on distribution planning and control, transmission and distribution modifications, cost quantification, and data accessibility. More than 50 sets of comments were filed in response.
Among other things, the project may address the request of Hunt Energy Network, LLC, Broad Reach Power LLC, and Jupiter Power, LLC that the PUCT determine appropriate policies necessary for nondiscriminatory interconnection and operation of battery energy storage systems at distribution voltage, as well as comments previously filed by Tesla Inc. explaining that that the market for demand response could be much larger, and residential demand response and DER aggregations serving as “virtual power plants” can dramatically improve the reliability of the ERCOT grid.
Securitization continues to be a popular legislative remedy to balance the interests of customers by spreading the burden of cost recovery for significant weather events over a longer period of time with the interests of utilities through the provision of carrying costs at more favorable interest rates. As described in the ERCOT section above, the Texas legislature approved several financing measures including securitization to help address cost recovery and liquidity issues in ERCOT due to the impact of Winter Storm Uri. Additionally, the Texas Legislature authorized securitization financing mechanisms following Winter Storm Uri for Texas utilities outside of the ERCOT market. In January 2022, the PUCT approved securitization of Entergy Texas’s system restoration costs related to Hurricanes Laura and Delta as well as Winter Storm Uri.
Oklahoma also employed securitization to address Winter Storm Uri cost issues. In particular, SB 1050 provided a path for the state’s utilities to securitize costs incurred due to Winter Storm Uri after review and approval by the Oklahoma Corporation Commission (“OCC”). Orders approving requests for securitization for Oklahoma Gas and Electric Company and Public Service Company of Oklahoma were issued by the OCC in December 2021 and February 2022, respectively.
The Alaska Legislature extended the state’s exemption from regulation as a public utility for plants and facilities generating electricity entirely from renewable energy resources from July 1, 2021 to July 1, 2028.
On November 19, 2021, the California Air Resources Board (“CARB”) approved its largest proposed annual investment in clean transportation to date, directing over $1.5 billion towards consumer rebates and incentives for zero-emission vehicles in its 2021/2022 Funding Plan. The dollar amount apportioned by the Funding Plan is a direct result Governor Newsom’s 2020 executive order directing that all new cars and passenger trucks sold in California by 2035 be zero-emission vehicles (“ZEVs”). This year’s $1.5 billion investment is the first tranche of the $3.9 billion earmarked for ZEV acceleration by Newsom’s 2020 order.
The CARB’s Funding Plan assigns $874 million to heavy-duty and off-road equipment— the largest allocation among project categories. CARB says that a portion of this amount will be assigned to a portfolio of technologies at various stages of development in order to meet current and future needs. The CARB believes this portfolio approach to funding technology in the past has enabled this year’s Funding Plan to prioritize heavy vehicles, such as drayage trucks and buses. Another major area of focus for the Funding Plan is the Clean Vehicle Rebate Project (“CVRP”), with an allocation totaling $525 million. CVRP is a three-year plan with a ramp-down based on cumulative electric vehicle sales. Consistent with the equity focus of the Funding Plan overall, the CVRP’s ramp-down will be followed by transition to assisting lower income ZEV purchasers.
The first ramp down of the CVRP’s rebate structure, set to one million ZEVs sold in California, has already been reached. Given the state’s rapid adoption of ZEVs and ZEV acceleration policy, the development of adequate infrastructure within the state is of critical importance. The Infrastructure Investment and Jobs Act will play a role in this through the $5 billion National Electric Vehicle Infrastructure (“NEVI”) program, which will distribute federal funding to states by formula with the goal of “strategically deploy[ing] electric vehicle charging infrastructure and to establish an interconnected network to facilitate data collection, access, and reliability.” The California Energy Commission (“CEC”) and CalTrans are tasked with submitting the state’s proposal for deployment of the state’s NEVI allocation. On June 10, 2022, the agencies published their Deployment Plan. The Deployment Plan’s proposal states that it will build out EV charging stations to “at least the minimum standards outlined in the NEVI Program guidance” and reiterates the state’s goal of reaching 250,000 battery-electric vehicle chargers in California by 2025, and 1.2 million by 2030. The California Agencies are due to submit their NEVI application to the Department of Transport and Department of Energy by August 1, 2022.
On December 10,2021, a California Public Utilities Commission (“CPUC”) Administrative Law Judge issued a proposed decision for CPUC consideration in reforming the second iteration of the state’s net metering policy to a third version, termed NEM 3.0. NEM 2.0 provides kWh credits for excess solar energy generated by customer-owned solar panels, which offset kWh customers draw from the grid when needed at other times. NEM 2.0 had introduced requirements for solar owners to use time-of-use billing rate plans and reduced solar owners’ allocation of credits for excess energy. NEM 3.0 has the potential to introduce potential disincentives for solar owners—new fixed monthly fees, further decreases to the kWh offset credit or a removal of the offset altogether in favor or a model where the solar owner sells all the power they generate and buys all the power they need. Opponents of the reforms to NEM 2.0 assert that these changes proposed for NEM 3.0 may impose new fees of more than $600 per year—the highest in the country, and increase the pay-back period for rooftop solar to 20 years. However, proponents state that it is time to reform NEM 2.0 because the program both pays solar owners the full retail energy price for excess energy and allows solar owners to avoid paying the retail energy price on the their consumption. The resulting lost utility revenues are shifted to non-solar owners. The CPUC , along with the CEC and the CARB, highlighted both the large uptake of rooftop solar in the state and the fact it is an important element of the DER needed for the state to achieve its decarbonization goals in its 2021 joint report to the California legislature on achieving a 100% clean energy future. The CPUC has tabled NEM 3.0 pending further comment elicited by the ALJ in the proceeding.
On June 21, 2022, the CPUC issued a resolution simplifying the distribution-level interconnection rules and regulations for Pacific Gas and Electric Company, San Diego Gas & Electric Company, and Southern California Edison Company— the largest utilities in the state. The modification allows those utilities’ smaller DER projects seeking to interconnect to California’s grid to use an integration capacity analysis to analyze whether reliability concerns would arise from interconnection. If the projects are less than 90% of available capacity under the integration capacity analysis, they qualify for fast track interconnection treatment. Advocates for the resolution believe that this simplification could lead to smaller DER projects seeing interconnection in a matter of months rather than a year or more.
In accordance with nationwide trends establishing support for transportation electrification, the Hawaii Legislature modified the Hawaii Public Utility Commission’s (“HPUC”) access to its special fund by adding a mechanism for HPUC to fund an electric vehicle charging system account for rebates incentivizing installation or upgrade of such systems. The rebate program entered into effect on June 30, 2022.
Oregon Agencies began implementation of the June 2021 state legislature-set target of achieving a 100% reduction of greenhouse gases associated with electricity sold to Oregon consumers by 2040. Oregon’s two largest investor-owned utilities—Portland General Electric (“PGE”) and Pacific Power—will play a central role in reaching this goal. HB 2021 required both to file a clean energy plan with the Oregon Public Utility Commission (“OPUC”) as part of any IRP filed after January 1, 2022. The utilities’ clean energy plans must holistically define the way the electric companies incorporate the target set by the state through: annual goals for acquisition of non-emitting generation, energy efficiency measures, and demand response resources; assessment of resiliency costs, consequences, outcomes and benefits based on “reasonable and prudent” industry resiliency standards and guidelines set by the OPUC; an examination of costs and benefits arising from community-based renewable energy as an alternative to fossil fuel-based generation; and a demonstration that the company is making “continual progress” within the planning period;” resulting in an affordable, reliable and clean electric system.
PGE did not fulfill its clean energy plan obligation, but the OPUC extended the filing deadline in light of the recency of HB 2101. Nevertheless, PGE indicated its direction on December 16, 2021, filing an RFP seeking approximately 1,000 MW of clean or renewable resources and 375MW of non-emitting capacity to be online by 2024 while also “working to accelerate its exit from the coal-fired Colstrip plant” by 2025. PGE states in the RFP that it forecasts a 372 MW capacity need, so achieving these renewable and non-emitting capacity goals is vital. The second of PGE’s December 16, 2021 filings demonstrated the company’s intent to fulfill much of this capacity through DER. PGE stated in its Distribution System Plan that DER will provide the up to 25% of the “flexibility” needed when it replaces thermal base load-serving assets with variable renewable energy. Central to this forecast is PGE’s “in-house, bottom-up adoption model applied to behind-the-meter DERs and electrification called “AdopDER.” AdopDER modeling will be used to develop PGE’s IRP when filed in 2023.
On March 2022, the OPUC approved all but one set of the action items in Pacific Power’s IRP filed in September 2021, before the date all IRPs need to include a clean energy plan. The OPUC determined that the utility’s proposal to build an experimental 500 MW nuclear project in Montana—the Natrium Demonstration Project—using a molten sodium-cooled nuclear reactor paired with a molten salt thermal energy tank was too risky to be included in the IRP. However, OPUC made clear that it did not want to eliminate Natrium from consideration but to reserve judgment until the project is more developed.
On March 31 2022, Washington Governor Jay Inslee signed Senate Bill 5974 into law, which mandates a “target for … the state that all publicly owned and privately owned passenger and light duty vehicles of model year 2030 or later that are sold, purchased, or registered in Washington state be electric vehicles.” Along with SB 5975, an additive budget bill passed concurrently, SB 5974 augments the state’s “Move Ahead Washington” $16.9 billion, 16 year, transportation reform effort. The EV mandate is a particularly headline-catching aspect of the Move Ahead Washington program because 2030 is a full five years ahead of California’s similar goal for 2035. SB 5974 established the “Interagency Electric Vehicle Coordinating Council” led by the Washington’s departments of commerce and transportation with participation from seven other state agencies. The Council’s initial task is to develop the state’s transportation electrification strategy and identify and coordinate grant funding related to advancing that effort. The Council is required to complete a scoping plan for achieving the 2030 target by December 31, 2023. The 2030 deadline has been identified as an overly ambitious and needlessly top-down approach by some, whereas others have noted that such mandates, like the Clean Air Act of 1963, have spurred industry action in the past.
On August 4, 2021, the Washington Department of Ecology (“WDE”) announced its rulemaking for developing cap-and-invest program rules, which are required by the state’s Climate Commitment Act (“CCA”). The CCA directed WDE develop rules that cap carbon emission, mechanisms for the sale and tracking of tradable emission allowances, along with oversight and enforcement measures. The CCA also directs the WDE to recognize similar programs in other jurisdictions. The WDE published the proposed rule on May 16, 2022. Electric utilities that are not required to report emissions on Washington will nevertheless be required to register in order to receive a no-cost allowance under the program. The rule sets out a cost-burden methodology for assigning allowances for electric utilities. One allowance is allocated for each metric ton of emissions of the cost burden-effect for each electric utility for each emissions year. The proposed rule also allows no-cost allowances to be auctioned for the benefit of ratepayers, transferred at no cost to electric generating facilities, or deposited for compliance. The comment period for the rule ended July 15, 2022.
