The $121 Billion Question: What Constraining Solar and Wind Would Cost Every Ratepayer
By Keith Reynolds | Publisher & Editor, ChargedUp!
NERA Economic Consulting’s Cost of Constraining New Solar and Wind study for CEBA estimates $121.2B in extra U.S. energy costs from 2027–2033 if new solar and wind are restricted. Average wholesale prices rise 6.1% ($37.40 → $39.70/MWh), peak gas reliance jumps from 27% to 43%, and ERCOT could see up to a 22.2% increase. For CRE, this shifts a policy debate into an underwriting variable.
Markets punish wishful thinking. Say “no” to the cheapest new electrons and the bill arrives as fuel exposure, equipment scarcity, and region‑specific spikes. The NERA cost of constraining solar wind analysis, prepared for the Corporate Energy Buyers Association (CEBA), quantifies that bill—and moves the conversation from ideology to cash flow.
What are the headline findings?
$121.2B total added energy cost (2027–2033) if new solar and wind are constrained.
Average wholesale price: $37.40/MWh (open competition) vs. $39.70/MWh (constrained) — a 6.1% increase.
Peak‑hour natural gas share: diversified 27% (open) vs. 43% (constrained).
Households: +$81.2B (≈+$59/yr for gas and +$26/yr for electricity per typical household).
Commercial & industrial: +$40B in electricity costs (≈$5.7B/yr).
ERCOT up to +22.2% (≈$21B cumulative; ≈$2B/yr for Texas C&I), NYISO ≈+11%, West up to +9%.
Gas capacity additions 60–72% above baseline; +32–38 GW new gas needed to meet demand.
What does NERA’s $121.2B estimate include?
NERA modeled two scenarios for 2027–2033 across U.S. power markets: open competition (all new resources compete) and constrained (limits on new solar and wind). Under constraints, average wholesale prices rise from $37.40 to $39.70/MWh. The model attributes $81.2B to households (electricity and gas) and $40B to commercial and industrial electricity consumption.
Mechanically, restricting low‑cost solar and wind concentrates the system on a single volatile fuel—natural gas—raising both the price level and the risk of future spikes.
How do constraints on solar and wind raise costs?
Fuel concentration: With fewer low‑marginal‑cost hours from renewables, gas must run more. Peak‑hour gas share reverses from a diversified 27% (open) to 43% (constrained).
New gas build requirement: NERA estimates 60–72% more gas capacity than baseline is needed, adding 32–38 GW above EIA projections just to meet reliability.
Volatility exposure: More dependence on natural gas links power bills to commodity swings rather than fixed‑price solar or storage contracts.
Why does gas‑turbine scarcity magnify the risk?
NERA identifies real‑world procurement friction: advanced gas turbines are booked years out amid data‑center growth, and delivered costs are running ≈36% above plan. Forcing the grid to lean harder on gas means competing for equipment that is already scarce—and getting pricier.
This echoes grid hardware constraints we’ve covered in our transformer bottleneck analysis. Constraining the cheapest, fastest‑to‑deploy supply (solar + storage that can energize in months) pushes the system toward the slowest, scarcest path at the exact moment data center load is absorbing capacity.
Which regions pay most—and why?
Competitive wholesale markets see the steepest effects. NERA projects ERCOT could face up to a 22.2% electricity price increase under constrained scenarios—about $21B cumulative—while Texas C&I customers pay ≈$2B/yr more. NYISO follows at ≈11%, and the broader West up to 9%.
For CRE underwriting, this concentration matters: the same regions attracting heavy data center investment are where constraining renewables would most sharply raise rates. Model scenarios accordingly for assets in Texas, the West, and Northeast competitive markets.
Is the market already moving to the lowest‑cost resources?
Yes. Developers are following the economics. Solar and storage represented 91% of new nameplate capacity additions in Q1 2026, and the U.S. set a first‑quarter storage record at 3.3 GW/8.4 GWh. The EIA expects24 GW of new battery storage in 2026, up from a 15 GW record in 2025. Constraining these resources runs counter to where capital is already flowing.
What should building owners and tenants do now?
Translate policy risk into a building‑level hedge. On‑site generation and storage mitigate three exposures at once: utility rate increases, interconnection delays, and the macro scenario that grid‑tied costs rise if the market can’t deploy the cheapest supply.
Use this 90‑day, building‑first checklist:
Load and tariff audit: 12–24 months of interval data; identify peak‑demand drivers and demand‑charge share (often 30–60% of C&I bills).
Feasibility screen: Roof/ground area, shading, structural reserve, easements; prelim interconnection check; backup‑critical load mapping.
Right‑sizing storage: Start with 2–4‑hour BESS for peak shaving and TOU arbitrage; test incremental value from 6–8 hours if outage economics matter.
Contracting path: Compare cash/loan vs. PPA/lease; include escalation scenarios at baseline (3–4%) and policy‑risk cases (5–8%).
Revenue stacking: Demand response/VPP participation; consider resilience premiums for tenants with sensitive uptime (labs, cold storage).
Portfolio view: Rank sites by blended IRR under utility‑rate escalators; proceed where on‑site MWh displace the most expensive kWh.
For a deeper underwriting lens, see our Energy‑Equity Connection white paper, which shows how resilience is moving beyond an environmental amenity to become a property‑value variable.
As CEBA’s Rich Powell notes, the question is competition, not technology preference. For owners, that translates into a straightforward posture: pay today’s utility rate—or own more of tomorrow’s certainty.
Frequently Asked Questions
What is the core finding of NERA’s Cost of Constraining New Solar and Wind study?
Restricting new solar and wind adds $121.2B to U.S. energy costs from 2027–2033, raises average wholesale power prices 6.1% ($37.40 → $39.70/MWh), and pushes peak‑hour gas reliance from 27% to 43%.
Who pays the $121.2B and over what period?
Households account for about $81.2B (electricity and natural gas combined) and commercial/industrial customers about $40B (electricity only) across 2027–2033.
Which regions see the biggest price impact?
ERCOT (Texas) faces up to a 22.2% increase (≈$21B cumulative), NYISO about 11%, and the West up to 9%, per NERA’s constrained scenarios.
Why does constraining renewables increase reliance on natural gas?
With fewer low‑marginal‑cost renewable hours, the system must dispatch more gas, requiring 60–72% more gas capacity additions (+32–38 GW above baseline) and shifting bills toward commodity risk.
What can building owners do to hedge this risk?
Evaluate onsite solar + storage for peak shaving and TOU arbitrage, run IRR sensitivity with higher utility escalators, and pre‑screen interconnection while exploring DR/VPP revenues and resilience value.
