The Power Line is a newsletter series that reviews key stories in the electric power sector—ranging from grid reliability, transmission issues, and emergent technology and business models. The Power Line will highlight the connections and relevance between the sector’s technical, local, and often esoteric stories to high-level public policy conversations on climate and energy taking place in Washington, D.C.
A brief step beyond the confines of the U.S. electric power sector delivers an interesting perspective on domestic developments.
Last week, Germany approved an updated power plant strategy which will procure 10 gigawatts (GW) of gas-fired power generation in the coming years through roughly $17 billion in subsidies. Though the power plants are to be hydrogen-ready, they will burn natural gas over the near term. The plan also envisions a new technology-neutral capacity payment mechanism to be introduced by 2028 which would allow other resources like battery storage or wind compete with the new plants for capacity payments. Nonetheless this competitive capacity mechanism will likely channel additional funds to the new plants.
The new procurement strategy is necessitated by Germany’s plans to retire the existing coal-fired generation fleet entirely by 2030, which represents a loss of roughly 38 GW of capacity. Germany also closed its last three nuclear reactors in 2023, representing another 4 GW in lost capacity. Though Germany is deploying significant wind and solar resources, there exists a clear gap in firm dispatchable power in the German resource mix in the years to come.
Despite the clarity of the requirement from a planning perspective, current market dynamics create a poor economic case from the perspective of private project developers. The dominance of zero-marginal cost wind and solar resources and their ongoing rapid deployment means that a new dispatchable gas-fired plant will run with low-capacity utilization factors and regularly cycle offline. These operational patterns combined with the higher upfront costs associated with hydrogen capability undermine project economics and deter private development without further policy sweeteners.
The China Example
Moving now to China, where in November of 2023 a capacity payment mechanism for coal-fired power plants was announced. In this case, the policy mechanism will pay coal-fired plants a fixed per-kilowatt fee to a maximum of 30 percent of their capital costs. The funding will come through a tariff assessed on industrial and commercial loads.
Though China leads the world in renewables deployment by a large margin and is likewise leading in nuclear power deployment in 2022 it suffered a significant energy shortfall. The new policy is directed toward ensuring adequate capacity of coal-fired capacity to ensure electric reliability.
Though the mechanism channels new funding to coal-fired coal plants, it may create increased opportunities for flexible dispatch of coal-fired power. The new policy creates an additional income stream beyond payment for energy produced; accordingly, power plant owners and grid operators have increased flexibility to run coal-fired power plants at lower utilization rates without undermining their economic viability.
Though the targeted resource class is different, the overall market conditions and policy response are very similar to the German case. The forthcoming capacity payment mechanism Germany seeks will take on a function very similar to the Chinese version. To be sure, the Chinese mechanism uses administratively set prices, rather than competitive price formation, as in for example, a capacity auction structure. And the Chinese model is resource-specific rather than technology neutral. Both features are something the German model will likely seek to implement. Despite the differences, the high-level story from both cases is clear; a mechanism to fund capacity is an emergent policy response to a sectoral dynamic in which generation assets crucial for grid reliability cannot otherwise achieve financial viability.
Bringing It All Back Home
With these international examples in mind, Texas’s decision in 2023 to procure firm capacity resources through an outside-the-market subsidy mechanism appears typical rather than anomalous. Electric power systems in all three locations (Germany, China, Texas) sit at the leading edge of variable renewable energy penetration rates. And in all three, the procurement of firm dispatchable capacity necessary to preserve security of supply is financially unviable without new policy intervention.
The previous Power Line commentary noted that the Texan power market, ERCOT, made it safely through this year’s winter test thanks in part to massive year over year deployments in new capacity, primarily solar, wind, and storage. Though it’s important to note that these resources benefit from federal subsidy, they are being deployed at a feverish rate by private project developers due to a strong financial model that attracts private capital. The ongoing interconnection of these resources should continue to depress wholesale market prices (and ancillary service market prices), and push gas-fired power generation out of the supply stack, lowering annual capacity factors for gas-fired power and undermining financial prospects. It seems likely that the new plants built in Texas on the back of state subsidized loans will struggle to turn a profit over the long-term. This raises the prospect of the need for further capacity payment mechanisms in the future.
Crucially, whether we are in Texas, Germany, or China, the cost of capacity adequacy policy ends up on the rate-payers bill (or is transferred to the taxpayer balance sheet). Therefore, efficiently procuring this capacity resource is crucial to keeping rate-payer costs low.
Given that renewable deployment will continue at its current rapid clip and given that firm dispatchable capacity remains fundamental to the reliable operation of the power grid, the challenge of procuring these resources will only grow in the years to come. Crucially, this problem extends beyond fossil-fired power into clean-firm technology like nuclear small modular reactors or long-duration energy storage.
Alongside the challenge of transmission planning and cost allocation, the emerging capacity adequacy procurement issue is likely to be the pressing question for federal policymaking in the electric power sector in the years to come.
What We’re Reading
“It’s Time to Reconsider Single-Clearing Price Mechanisms In U.S. Energy Markets,” Commissioner Mark C. Christie
“Texas Got Early Warnings About Costly Grid Policy,” Rachel Adams-Heard and Naureen S. Malik, Bloomberg
“Estimating Interregional Transmission Expansion Under the BIG WIRES Act,” Joshua Rhodes, Abraham Silverman, and Zachary A. Wendling, Columbia Center on Global Energy Policy
Cy McGeady is a fellow with the Energy Security and Climate Change Program at the Center for Strategic and International Studies in Washington, D.C.
