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closure due to safety concerns. In Illinois, the policy prevented the closures of the Clinton and Quad Cities nuclear plants. Both state programmes were upheld in court challenges. More recently, in 2019, New Jersey passed legislation to provide ZECs to its nuclear capacity at the Salem-Hope Creek nuclear plant (Exelon’s Oyster Creek plant was shuttered last year). Elsewhere, however, state governments have resisted such support for nuclear, including in places facing imminent plant closures, such as Pennsylvania, Ohio and California.

Net metering

A number of US states also have net metering laws in place, which permit residential and commercial customers (mostly rooftop solar) who generate their own renewable power to sell surplus electricity (usually at retail rates) back to the grid. The success of rooftop solar policies in several states has occasionally resulted in an abundance of solar power fed into the grid, creating challenges for utilities in balancing demand with more unpredictable supply. The issue is particularly acute during the afternoon hours, when the maximum amount of sunlight can generate more electricity than the load requires. Subsequently, demand tends to pick up again during the evening hours after people return home from work, when the sun is no longer shining. In some cases, the amount of rooftop solar generation can result in surplus power on the grid that creates negative electricity pricing and forces curtailment. In response, some states are adjusting their net metering rules to better align rooftop solar payments with grid requirements, including by introducing time-of-use rates and location-specific rates. Other states, such as Indiana, however, are phasing out net metering payments entirely, which will significantly slow down rooftop solar buildouts in those parts of the country.

System integration of renewables

As the US power mix shifts, and as more variable renewables are introduced into the system, bolstered by state policy goals, the question of smoothly and cost-effectively connecting new generation sources to the grid has already become more salient, and will grow increasingly pressing in the coming years (also see section on Grid Reliability and Resilience below). In particular, grid operators are already grappling with some misalignments between state policies such as RPS and ZEC programmes and their price formation rules (Joskow, 2019).

A number of US states are adopting storage targets to accompany their renewables targets, led in large part by California. To complement its 2030 target of 50% renewables, the state adopted an ambitious storage mandate in 2013, which required utilities to procure 1 325 MW of energy storage by 2020 (to be online by 2024). In response to the Aliso Canyon natural gas storage facility leak in 2015, the state in 2016 followed up by legislating that utilities procure an additional 500 MW of storage capacity. Importantly, California regulators have also modified market rules to ensure that battery storage options are valued more accurately in the wholesale power market. California’s efforts have been followed by Massachusetts, which established a target of 1 000 MWh by 2025 (up from the previous target of 200 MWh by 2020). More recently, New York state regulators in December 2018 approved storage targets of 1.5 GW by 2025 and 3 GW by 2030, as directed by 2017 legislation, while New Jersey in 2018 legislated a storage target of 2 GW by 2030. Oregon has a very small storage target of 5 MWh by January 2020, which has not mobilised investments in the state.

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Other states are also seeing solar-plus-storage installations bid at increasingly competitive rates into power auctions, even without storage mandates. For example, in January in Minnesota, Xcel Energy launched a tender for a solar-plus-storage facility that received bids (which reflect subsidies) as low as USD 36/MWh, while a tender for wind plus storage received a median bid of USD 21/MWh. Meanwhile in Arizona, NextEra signed a deal with Tucson Electric Power in May 2017 for a solar-plus-storage power purchase agreement at USD 45/MWh, while First Solar’s February 2018 bid for a solar- plus-storage system topped those from gas peakers. Markets with traditionally high power prices, such as Hawaii, will also be suitable markets for more battery storage options to complement ambitious 100% renewables targets.

At the federal level, in response to the growth in renewables deployment, FERC in February 2018 issued Order 841, which required RTOs and ISOs to adjust rate structures to facilitate the participation of energy storage resources in regional wholesale power markets. The move places energy storage on a level playing field with other generation sources, and is expected to open up more opportunities for energy storage investments.

To further support efforts to ensure smooth integration of renewables into the grid and manage risks stemming from the retirement of baseload generation, FERC also issued Order 842 in February 2018, which requires new generators to install equipment capable of providing primary frequency response as a precondition for grid interconnection. There are lingering concerns that higher levels of renewables penetration could impact frequency response capabilities in power grids, given that synchronous baseload generation such as coal plants – which have maintained system frequency – are increasingly facing retirement. Wind and solar facilities are now required to install technologies such as inverters and battery storage to ensure primary response capabilities. More broadly, storage solutions – including those promoted by Order 841 – can help provide frequency response services.

Transmission

An important aspect of grid planning to accommodate growing shares of renewable energy is the building of transmission lines to carry electricity from often-remote generation sites to urban load centres. Examples of challenges facing large renewables projects due to transmission setbacks include the rejection by New Hampshire regulators of the Northern Pass Transmission project, meant to carry hydropower from Quebec through New Hampshire to Massachusetts. Moreover, the buildout of renewables and distributed energy resources would require more sophisticated and flexible transmission infrastructure, which is misaligned with the ageing state of the existing infrastructure. In 2015, FERC estimated that around 70% of transmission infrastructure was over 25 years old (Lawrence Berkeley National Laboratory, 2017).

In response, FERC in 2011 finalised Order No 1000, which revised rules for transmission planning, cost allocation and competitive bidding for transmission. The intent of the order was to shift the market towards competitive, cost-effective regional transmission plans that allocate costs to beneficiaries and accommodate state policy goals, especially with respect to renewables. The order also promoted interregional transmission solutions based on increased co-ordination between regional planners. In the eight years since the order was issued, a number of projects have been selected for regional cost allocation. Of these, some but not all have been selected through competitive processes. Many projects have also been selected through regional planning processes managed by

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