EIA Storage Report April 16: NGI Forecasts 62 Bcf Injection — More Than Double Prior Consensus as Henry Hub Drops to $2.58
UPDATE (April 16): The EIA reported an actual net injection of 59 Bcf for the week ending April 10 — slightly below the revised NGI forecast of 62 Bcf but more than double the initial 27 Bcf consensus. Total working gas in storage reached approximately 1,970 Bcf, widening the surplus to 119 Bcf above the five-year average — the most comfortable storage position of the 2026 injection season. Despite the bearish data, Henry Hub rallied 3.4 cents to $2.644/MMBtu, supported by strong LNG feedgas demand and constrained production — signaling the market views current lows as a floor rather than a ceiling. The procurement window remains open but the floor may be firming.
Executive Impact
- →Procurement Window: Act Now. $2.58/MMBtu Henry Hub with a 122 Bcf storage surplus is the most bearish gas price environment since Q4 2025. Fixed-price gas contracts for 12-24 months and gas-indexed electricity supply agreements are available at levels that may not recur this year. If your organization has authority to execute, the signal is clear: this is the window.
- →Prior Consensus Was Wrong. Our April 13 preview article projected 27 Bcf based on the Estimize consensus available at the time. The NGI revision to 62 Bcf reflects updated weather models and LNG maintenance data that became available Monday-Tuesday. This underscores why commercial buyers should never anchor procurement decisions to a single forecast — wait for the Tuesday/Wednesday revision cycle before acting on Thursday's report.
- →Summer Forward Curve Implications: If the 62 Bcf print materializes, the NYMEX summer strip (Jun-Sep) will likely compress from its current $3.10-$3.18 range toward $2.90-$3.00. This means gas-indexed electricity contracts for summer delivery can be locked at even lower rates than currently quoted — request updated pricing from your supplier tomorrow morning.
Why the Consensus Doubled: From 27 Bcf to 62 Bcf
The massive upward revision from Sunday's 27 Bcf Estimize consensus to NGI's 62 Bcf forecast reflects three factors that became clearer Monday through Tuesday:
- Mild Weather Confirmed: The GFS and ECMWF weather model runs updated Monday confirmed that the week ending April 10 was materially milder than initially expected. Heating degree days (HDDs) across the Lower 48 came in near zero, while cooling degree days (CDDs) were minimal outside of far South Texas. This low thermal demand freed gas for storage.
- LNG Maintenance Window: Feedgas deliveries to LNG export terminals dipped from the prior week's 13.4 Bcf/day record to approximately 12.8 Bcf/day due to brief maintenance at one Gulf Coast facility. Each 0.5 Bcf/day reduction in LNG feedgas frees approximately 3.5 Bcf/week for domestic injection.
- Robust Production: Dry gas production held steady near 104.5 Bcf/day. The combination of sustained production, reduced LNG demand, and minimal weather-driven consumption created ideal injection conditions.
Storage Surplus Analysis
If the 62 Bcf injection materializes, total working gas would reach approximately 1,973 Bcf — now 122 Bcf above the five-year average for this time of year. To put this in context:
- The surplus was 87 Bcf above average last week (post-50 Bcf build).
- The surplus widened by 35 Bcf in a single week — the fastest expansion rate of the 2026 injection season.
- At this pace, end-of-injection-season storage (late October) could reach 3,600-3,700 Bcf, which would be the most comfortable pre-winter level since 2020.
This surplus trajectory is structurally bearish for Henry Hub through mid-summer. Without a sustained heat wave that drives power burn above 40 Bcf/day (the June-August average is typically 38-42 Bcf/day), there is no demand-side catalyst to tighten the market.
Henry Hub at $2.58: The Procurement Math
For commercial electricity buyers in gas-dependent ISO markets, Henry Hub at $2.58/MMBtu translates directly to marginal generation costs:
- Combined Cycle Gas Turbine (7,000 Btu/kWh heat rate): $2.58 × 7.0 = $18.06/MWh fuel cost
- Simple Cycle Peaker (10,000 Btu/kWh heat rate): $2.58 × 10.0 = $25.80/MWh fuel cost
- Adding VOM and emissions costs: All-in marginal cost of $28-$35/MWh for efficient units
This means wholesale electricity prices in gas-dependent markets should be trading in the $28-$35/MWh range during off-peak hours — and commercial supply rates reflecting this environment should be available at 6-8¢/kWh all-in for buyers with favorable load shapes in PJM, ERCOT, and MISO.
Commercial Buyer Action Items
- Request Updated Quotes Today: If your current supply contract expires in Q3 or Q4 2026, contact your gas supplier or electricity REP for updated 12-24 month pricing. The $2.58 spot anchor and bearish forward curve create leverage for aggressive negotiation.
- Layer Your Procurement: Don't go all-in at one price point. Lock 50% of anticipated volume now at $2.58-based pricing, then layer the remaining 50% over the next 4-6 weeks. If prices drop further, you capture additional savings. If they bounce, you've locked favorable base pricing.
- New England Basis Alert: With Henry Hub at $2.58 and spring Algonquin basis near $0.20, effective delivered gas costs in New England are below $2.80/MMBtu — the cheapest since winter 2024. ISO-NE commercial electricity rates should reflect this within 1-2 billing cycles.
- Watch Thursday Morning: If the actual EIA number exceeds 62 Bcf — signaling even greater oversupply — Henry Hub could test $2.45-$2.50 support. Have your procurement team ready to execute same-day if a bearish surprise materializes.