The 2018 mid-term elections brought about significant change to party control in states across the country, with newly-emboldened legislators taking aggressive action on energy and climate policy.
In particular, several states have moved rapidly to enact 100% clean energy targets this year, including Washington, New Mexico, Maine and New York. Others have proposed similar policies and, given the make-up of their legislative chambers, may succeed in passing them ahead of the 2020 elections — see Figure 1.
Figure 1 - Key State 100% Clean Energy Initiatives
In the past, states have primarily relied on renewable energy credit (REC) markets to incentivize new developments to meet their renewable portfolio standard (RPS) targets. REC markets were largely successful given the relatively low RPS requirements, which generally weren't aggressive enough to affect grid reliability or price formation (with the exception of California).
However, states are shifting strategies to meet their ambitions and turning to a portfolio of measures to supplement REC markets. For example, New England states, New York and California have embraced state-led resource procurements to more directly control progress — with the Northeast focused on offshore wind — thereby limiting the market for merchant renewables.
Several states are also using or working toward market mechanisms that would supplement RECs, including California's carbon cap-and-trade program, the NYISO proposal to instate a carbon adder on energy prices, and Washington legislators' continued attempts to pass a carbon tax. Each of these measures could boost power prices and incentivize cleaner sources of energy, situationally improving the economics for more efficient natural gas-fired generators.
These policies — which cut across several U.S. regions — are supplemented by growing clean energy demand from large commercial and industrial customers (like tech firms and retailers) and municipalities (particularly California's Community Choice Aggregators).
Such entities generally intend to procure renewable power additional to their states' targets. In the case of a state with a 100% target, this entails achieving such ambitions ahead of schedule.
This combination of factors is driving accelerated demand for renewables and shifting the risk profile of different classes of power generation assets. However, more-efficient, existing natural gas-fired assets may still benefit in the near- to medium-term in helping to firm the intermittency of new-build renewables and taking advantage of power price volatility.
Changing resource mixes and carbon price adders may raise power prices for these assets more than what they would pay in increased costs. For example, in California, the drop off in solar generation in the evening has driven price increases as flexible natural gas-fired assets ramp and gas balancing fees push prices higher — see Figure 2.
Figure 2 – California Energy Market Price Formation
Due to its aggressive renewables targets (with procurement carve-outs for solar), potential for carbon prices, and constrained gas pipeline network, New York may next witness such changes in price formation. Seasonal variations of the same phenomena may also occur when new thermal generator development is deferred in favor of intermittent renewables, such as price spikes in the summer for ERCOT and in winter for ISO-NE.
Accelerating renewable demand may also affect capacity value, whether via formal markets or bilateral contracts. Where clean energy policies force thermal generator retirements, capacity value generally increases and compounds value for remaining capacity that can also capture increased power price volatility. Additionally, the value for dispatchable assets is likely to increase as these resources will be necessary for maintaining reliability in a grid overwhelmed by intermittent generators.
Meanwhile, FERC and grid operators (i.e., PJM and ISO-NE) are taking steps to minimize any suppressive impact of state-led policy initiatives on capacity markets. While not perfect, these efforts provide some protection for existing generators.
Despite the tailwinds of growing demand for renewables, developers of these assets will still face challenges.
A higher penetration of renewables changes price profiles (e.g., as seen in California, ERCOT and the Midwest), complicates transmission dynamics (e.g., basis differentials on CREZ lines) and creates covariance risk as realized power prices are impacted by renewable generation profiles. Owners of existing natural gas-fired generation will similarly need to weigh the risks of a turbulent policy landscape against opportunities to capture greater value via flexible operations and reliable capacity.
Across the industry, investors will need to identify and understand the relationship between these risks and opportunities to make decisions that will continue to provide value across their portfolios; tools that can account for evolving power price shapes, congestion patterns and capacity compensation will help shape business strategy and build investor confidence.
Looking ahead, several states have also enacted economy-wide greenhouse gas reduction targets, which will require the electrification of the energy-intensive transportation, industrial and building sectors. Such transitions will increase reliance on electricity and provide new avenues for load growth.
Despite the risks arising from aggressive clean energy targets, the future holds new opportunities for a variety of asset types provided this new set of risks is properly understood.
Ryan Hardy, Salem Esber and Dan Esposito are energy markets experts at PA Consulting
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