Introduction: The Counterintuitive Energy Landscape
When President Trump took office in January 2025, his administration launched an aggressive legislative and executive campaign aimed at cementing a doctrine of “energy dominance.” This policy framework sought to systematically dismantle federal support for clean technologies while artificially revitalizing the domestic fossil fuel and coal sectors.
Through sweeping initiatives – such as the landmark “One Big Beautiful Bill” (OBBB) Act, passed by Congress on July 3, 2025, and signed into law on July 4, 2025, and the direct freeze of billions in Inflation Reduction Act grants – the federal government attempted to pivot the American industrial landscape back toward hydrocarbons.
However, by 2026, this intervention triggered a profound economic paradox. Rather than suffocating renewable energy development, aggressive federal intervention inadvertently accelerated the market’s reliance on decentralized, resilient, and non-hydrocarbon alternatives.
When government intervention actively disrupts or forces an uncompetitive framework onto the market, private enterprise, capital networks, and local utility providers often engineer highly sophisticated workarounds to bypass the government entirely.
In the current energy landscape, this pushback has manifested across four distinct economic and behavioral phenomena: Market Determinism; the Volatility Hedge Paradox; Greenhushing; and the Structural Demand Squeeze. The article examines each phenomenon and cites additional articles and reports for readers who want to explore them in greater depth.
Ultimately, federal efforts to thwart the renewable transition did not break its momentum; they merely forced the market to take over, stripping the transition of its political rhetoric and rebuilding it on a foundation of pure commercial necessity.
I. Market Determinism: Why Capital Horizons Outlast Political Cycles
The defining feature of the post-2024 energy landscape is Market Determinism, an economic reality where deep-seated, secular market forces fundamentally override short-term government industrial policy. The Trump administration sought to eliminate the competitiveness of wind and solar by passing the OBBB Act, which systematically phased out clean energy production and investment tax credits for new wind and solar facilities placed in service after 2027, and by implementing freezes on renewable permitting on public lands.
Despite these regulatory roadblocks, federal energy data from the first half of 2026 revealed that U.S. wind and solar generation actually rose by 10% (reaching nearly 420 terawatt-hours, up from 382 TWh in the first half of 2025), effectively outstripping coal and nuclear in the national power mix for the first time on a comparable six-month basis.
This divergence highlights a structural decoupling between Washington, D.C.’s regulatory goals and Wall Street’s deployment of capital. Institutional infrastructure investments operate on 30-year amortization horizons that extend well beyond the four-year cycle of presidential administrations.
Because the levelized cost of energy for utility-scale solar and battery storage has plummeted globally, these technologies remain fundamentally cheaper to build and deploy per megawatt-hour than natural gas or coal, even when accounting for the loss of federal subsidies. New wind and utility-scale solar average roughly $68-69 per megawatt-hour over their lifetimes, compared with approximately $90 for new combined-cycle natural gas power.
Private utilities simply refused to reinvest in coal infrastructure because doing so would expose them to stranded-asset risks once the political pendulum swings back. There is no better example of government’s uphill battle than the U.S. Department of Energy’s (DOE’s) orders forcing coal-fired plants to stay open – in spite of the fact the utility owners have long planned the plants’ closures.
Colorado’s Craig Unit 1. For example, Craig Unit 1, an aging coal-fired power plant in northwestern Colorado, has operated for only two to three weeks since April 2026, according to plant operator Tri-State Generation. Nevertheless, repeated DOE emergency orders have kept the plant available beyond its scheduled December 2025 retirement date. DOE first intervened on December 30, 2025, via Order No. 202-25-14, and has since renewed the order at least three additional times – in March 2026 (Order No. 202-26-21), June 2026 (Order No. 202-26-31), and again on September 25, 2026 (extending the mandate through December 25, 2026).
Maintaining the infrequently used facility has cost millions of dollars, drawing legal challenges from the Sierra Club, GreenLatinos, Vote Solar, Public Citizen, Environmental Defense Fund, and Colorado Attorney General Phil Weiser, all raising concerns about potential rate increases for consumers.
Notably, in a unanimous three-judge panel decision issued on September 11, 2026, the U.S. Court of Appeals for the D.C. Circuit vacated a nearly identical Section 202(c) order covering a coal plant in Michigan (the J.H. Campbell plant), finding the department had exceeded its emergency authority – a ruling that directly undermines the legal basis for the Craig Unit 1 orders and has placed related litigation on hold pending further appeal. In this ruling, the panel led by Circuit Judge Cornelia Pillard held that long-term resource adequacy risks do not qualify as a grid emergency under Section 202(c) of the Federal Power Act, strictly limiting the federal government’s authority to override state-approved power plant retirements.
See a summary of the legal proceedings related to DOE orders issued pursuant to Section 202(c) of the Federal Power Act:
- Order No. 202-25-14 (Dec. 30, 2025)
- Order No. 202-26-21 (Mar. 30, 2026)
- 2026 DOE 202(c) Orders index (includes subsequent renewals)
Market Determinism in Detail
A recent article, “Renewable, Fossil Fuel, and Nuclear Energy Responses to Global Shocks: Lessons from China and the United States“1 provides empirical evidence via Bayesian Vector Autoregressive modeling demonstrating that long-term investment adjustments in the private sector are highly insulated from domestic regulatory policy uncertainty. The authors show that structural cost efficiencies and energy-security considerations dictate corporate capital allocation far more effectively than government-level regulatory rollbacks, with the U.S. increasing both fossil fuel and renewable energy production in response to different categories of global shocks.
In “The Future of U.S. Climate Policy: Costs of Delaying the Clean Electricity Transition,”2 Duke University’s modeling demonstrates that while the repeal of the U.S. Environmental Protection Agency’s (EPA) Final Greenhouse Gas Rule and the passage of the OBBB Act created significant administrative friction, it ultimately raised the long-term operational costs of fossil fuels relative to clean energy amid surging data-center demand. This widened the structural economic gap and incentivized private firms to opt for lower-cost renewables to protect profit margins.
II. The Volatility Hedge Paradox: Geopolitical Disruptions as a Clean Energy Catalyst
A primary objective of the post-2024 administrative pivot was to insulate the American economy through a rapid escalation of domestic drilling – a strategy popularized under the banner of “Drill, Baby, Drill.” In November 2025, the U.S. Department of the Interior announced plans to open approximately 1.27 billion acres of federal waters to oil and gas leasing across up to 34 lease sales, including contested areas off the coasts of California, Florida, and the Alaskan Arctic – intended to flood the market with cheap oil and gas and lower industrial overhead.
However, this policy ran headlong into the Volatility Hedge Paradox. This economic phenomenon occurs when a government’s hyper-fixation on a volatile commodity increases systemic risk, driving the market to aggressively pursue fixed-cost alternatives as a defense mechanism.
The current administration’s aggressive foreign policy and escalating trade tensions – culminating in severe geopolitical friction in the Middle East and a broader oil crisis – shattered the illusion of stable domestic fossil fuel pricing. Even though domestic crude oil production reached all-time highs, global commodity markets remained acutely vulnerable to supply-chain shocks, causing domestic retail gas and natural gas prices to experience intense spikes.
For consumers and corporate logistics fleets, this pricing chaos transformed renewable energy from an ideological choice into a vital risk-management tool. Because solar and wind assets have zero fuel-input costs, once they are built, their operational expenditures are fixed. When fossil energy costs spike, consumers respond by accelerating their adoption of residential solar and electric vehicles not out of environmental altruism, but to permanently insulate their balance sheets from global oil markets.
The Volatility Hedge Paradox in Detail
A 2026 mid-year industry analysis from Wood Mackenzie, “Power and Renewables 2026 Outlook: Half-Time Report,” illustrates how wild fluctuations in natural gas pricing – partially driven by federal shifts in export approvals and global trade standard adjustments – forced utility operators to aggressively shift their risk portfolios toward battery storage and flexible generation to hedge against supply-side shocks, even as oil and gas majors simultaneously retreated from renewable commitments to redirect capital upstream.
Another report, “An Inflection Point for the U.S. Power Sector,”3, provides comprehensive financial modeling showing that a fossil-fuel-heavy grid layout exposes regional utility networks to massive fuel-price volatility. It finds that planned fossil capacity in the development pipeline has risen from just 5% of new capacity in 2024 to roughly 30% today, driven in part by federal policies mandating continued coal plant operation and $850 million in federal coal support. The report confirms that, despite this fossil resurgence, the private market has continued counteracting the threat by prioritizing lower-cost, faster-to-build solar, wind, and storage wherever federal and state permitting allows.
III. Greenhushing: Corporate Adaptations to the Culture War
To culturally and politically delegitimize the transition to clean energy, the post-2024 executive branch leveraged federal procurement rules and antitrust rhetoric to target corporations utilizing Environmental, Social, and Governance (ESG) frameworks. Tax credit transfers to foreign buyers were heavily restricted, and high-profile climate research initiatives within DOE were defunded or buried.
The corporate response to this hostile regulatory environment was not a cessation of clean tech deployment, but rather a behavioral shift known as Greenhushing. Instead of abandoning their decarbonization targets, major corporations, institutional investors, and some utilities adapted to the policies by stripping all climate-centric terminology from their public prospectuses, substituting it with language centered on “energy pragmatism,” “grid reliability,” and “supply chain security.”
Despite the change in public messaging, private investment in clean energy continued. Approximately 73% of all new U.S. solar capacity deployed in 2025 was located in states that voted for President Trump in 2024, including Texas, Florida, Indiana, Ohio, and Arkansas. That trend continued into 2026, with 71% of new solar production in the first half of the year coming from red states. Local developers and corporate buyers in these regions recognized that clean energy was a powerful engine for local job creation and land-lease revenue.
By “hushing” the green rhetoric, the market successfully neutralized federal political hostility. This allowed private entities to quietly execute multi-gigawatt power purchase agreements based entirely on commercial utility.
Greenhushing in Detail
A peer-reviewed theoretical study, “An Integrated Analysis of Greenhush,”4 develops an integrated institutional-theory and stakeholder-theory framework explaining why corporations strategically under-report sustainability initiatives even while continuing to pursue them operationally. The paper’s framework helps explain the behavioral pattern observed across the U.S. corporate and utility sector following the 2025 political shift, in which companies faced competing stakeholder demands and regulatory uncertainty.
An industry-standard quarterly report, “U.S. Solar Market Insight, Q4 20255,” documents that 73% of all U.S. solar capacity installed in 2025 was built in states won by President Trump in 2024, with eight of the top ten installation states – Texas, Indiana, Florida, Arizona, Ohio, Utah, Kentucky, and Arkansas – represented among them.
The American Clean Power Association’s “2026 Q2 Clean Power Quarterly Market Report6” documents that clean power procurement hit 14.5 gigawatts in the first half of 2026 – up 23% year-over-year, with power purchase agreement announcements reaching an all-time first-half record – driven by corporate buyers often framing their acquisitions around data center optimization and infrastructure resilience rather than public-facing climate pledges.
IV. The Structural Demand Squeeze: The Unforeseen AI Bottleneck
Perhaps the most glaring policy backfire of the post-2024 era occurred at the intersection of economic deregulation and the technological sector, creating a phenomenon known as the Structural Demand Squeeze. The current administration took decisive steps to unleash the tech sector, roll back digital oversight, and incentivize massive domestic industrial manufacturing. This coincided with an unprecedented exponential explosion in the development of artificial intelligence (AI) and hyperscale data centers.
These AI data centers require substantial amounts of reliable electricity. The administration’s energy strategy assumed this demand shock would be met by its favored legacy fuels, leading the administration to revoke regulations affecting natural gas-fired plants and set aside hundreds of millions of dollars to artificially prolong the lifespans of obsolete coal plants.
However, the physical realities of the market completely broke this plan:
- The Time-to-Market Bottleneck: Designing, permitting, and building new natural gas pipelines and heavy turbine facilities takes anywhere from five to seven years due to supply chain complexities and localized legal challenges.
- The Modular Deployment Advantage: In contrast, utility-scale solar arrays and modular co-located battery storage systems can be permitted and fully deployed in less than 18 months.
- The Hyperscaler Mandate: Tech giants operating these data centers have strict corporate mandates that prohibit them from locking into long-term carbon-intensive generation, because doing so would trigger catastrophic capital pullouts from their own institutional investors.
Faced with an existential power shortage, tech companies bypass traditional utility frameworks entirely. They utilize their immense capital reserves to build independent, behind-the-meter solar, wind, and advanced battery microgrids directly adjacent to their data center campuses. The administration’s push for industrial growth created a demand squeeze so severe that the market was structurally forced to deploy renewables at scale, simply because fossil fuels could not physically scale fast enough to keep the servers running.
The Structural Demand Squeeze in Detail
The U.S. Energy Information Administration’s Preliminary Monthly Electric Generator Inventory, “New U.S. Electric Generating Capacity Expected to Reach a Record High in 2026,7” confirms that developers plan to add a record 86 gigawatts of new utility-scale generating capacity in 2026, with solar (51%), battery storage (28%), and wind (14%) together accounting for 93% of all planned additions. The report and related coverage directly attribute this concentration to the immediate operational timelines required by hyperscale computing facilities, which legacy fossil infrastructure cannot accommodate on comparable timescales.
An analysis, “The New U.S. Energy Policy: Energy Dominance or Fallback?8,” explores the friction between the administration’s “Drill, Baby, Drill” agenda and the structural requirements of the domestic tech economy. The analysis demonstrates that the administration’s focus on expanding liquefied natural gas export capacity – including approvals for the Commonwealth, Golden Pass, Delfin, Calcasieu Pass, and Port Arthur Phase II projects – risks constraining domestic gas availability for the power sector, even as data center electricity demand is projected to rise sharply (from roughly 176 TWh in 2023 to between 325-580 TWh by the early 2030s, according to DOE estimates cited in the report).
That report concludes that new generation assets, especially gas, nuclear, and hydroelectric, will take years to build, while aging coal assets remain largely uncompetitive – potentially forcing the administration to scale back its AI and data-center ambitions absent a faster buildout of flexible, modular generation such as renewables and storage.
Conclusion: The Inversion of Industrial Policy
The historical record of the post-2024 energy transition serves as a definitive case study in the limits of government intervention within highly integrated capital markets. The current administration utilized every available tool of federal power – from tax credit repeals via the OBBB Act to direct intervention in stopping coal plant retirements – to artificially mandate a fossil fuel renaissance.
Yet, by distorting the regulatory landscape, the administration unintentionally triggered an array of market defense mechanisms.
Market Determinism ensured that long-term asset management remained anchored to cost efficiencies rather than administrative decrees.
The Volatility Hedge Paradox transformed clean energy into a safe-haven asset against global supply disruptions.
Greenhushing insulated local economic actors from the political culture war.
And the Structural Demand Squeeze forced the world’s most capitalized technology firms to build an independent clean energy grid out of sheer operational survival.
As of this publication, the legal durability of the Trump administration’s signature intervention – i.e., the repeated Section 202(c) emergency orders keeping plants like Craig Unit 1 online – remains in serious doubt following the D.C. Circuit’s September 2026 rejection of a near-identical order in Michigan. Whether that precedent ultimately unwinds the Craig Unit 1 orders or similar interventions elsewhere will be an important test of how much further federal policy can bend market outcomes before the underlying economics simply reassert themselves.
Ultimately, federal efforts to thwart the renewable transition did not break its momentum; they merely forced the market to take over, stripping the transition of its political rhetoric and rebuilding it on a foundation of pure commercial necessity.
This blog was drafted by John L. Watson, an attorney in the Spencer Fane Denver, Colorado, office. For more information, visit www.spencerfane.com.
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1 Attílio, L. A., & Silva, E. C. D. (2026). Energy Economics, 160.
2 Ross, M., & Ewing, J. (2026). Durham, NC: Nicholas Institute for Energy, Environment & Sustainability, Duke University. Published September 17, 2026.
3 Environmental Defense Fund & Atlas Public Policy. Published October 13, 2026.
4 Hilton, Joshua, 2025.
5 Solar Energy Industries Association (SEIA) & Wood Mackenzie. (2025)
6 American Clean Power Association (ACP). (2026, September 3)
7 U.S. Energy Information Administration (EIA). (2026) Today in Energy.
8 Michel, T. (2025, September 4). Ifri Studies. Institut Français des Relations Internationales (Ifri).
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