We wanted to share our latest production update, covering our revised Long term Forecast for oil and natural gas as well as general model updates. View the full update on the Energy Dashboard and tune into our Quarterly Production Webinar, this morning at 10am EST. 

This month's update is a substantial one, mostly driven by changes to the daily production model.  You can review those at the bottom.

Natural Gas Forecast 

Oil Forecast

2026's forecast is down 127 mbd to 236 mbd YOY on disappointing early actuals, though we expect the higher prices will persist and make meaningful change to 2027/8, leading to our 2027 forecast to be up 116 mbd, now at 386 mbd YOY, total 14.2 mmbd.  Similar to gas, our forecast is "tilted" up compared to last.

More expected Permian production should result from the elevated curve - but back loaded - as PLs unlock crude production and higher prices support activity.  We have already seen rigs trending up.  Permian is all of the Q-on-Q growth, and almost all of the US growth.  GOM appears to have peaked for the forecast period, with a return to declines in '27 and '28, as new projects aren't due until due in 2029.

As has been the case recently., virtually all of the growth continues to come from the Permian Basin, constrained primarily by residual gas takeaway capacity. Most other basins remain flat to declining.

Daily Production Model Changes

We've made three significant updates to our daily production model: a recalibration of our dry gas factors, a modification to how some Texas leases' production is allocated to the wells on those leases, and our usual refits to the latest state-reported data - most notably a recalibration of Haynesville production against LEG and NG3 flow data, and the incorporation of the first Gulf Coast Express expansion flows. These changes will be live in the morning of 12 Jun 26. Due to the Texas reallocation, the resulting changes to the short term forecast won't be live until Tuesday, 16 Jun.

Our L48 production estimate has been revised downward by an average of 0.56 Bcf/d over the last 6 months, while the current-day estimate has decreased by 0.61 Bcf/d. Unlike recent updates, the net effect at the L48 level is meaningful and is driven primarily by Texas, where lower (wetter) dry gas factors and the Haynesville recalibration outweigh upward revisions in the Permian, Oklahoma, West Virginia, and Wyoming.

1. Dry Gas Factor Recalibration

We have recalibrated the dry gas factors used to convert our gross production estimates into dry gas, following the methodology described in our last dry gas recalibration article. This recalibration affects our production history back to 2022, as far back as the EIA revisions reach.

The largest factor changes came in Texas. These were driven both by wetter revisions to the EIA dry gas numbers in 2022/2023, and by South Texas producing wetter gas than our previous projection. The South - TX factor moved from 0.775 to 0.722, while the other Texas sub regions saw only small changes.

The factor changes themselves look small, but because they multiply the entire gross production stream, even minor moves translate into large differences in the final dry gas numbers. The 0.05 change in the South - TX factor alone removes around 0.5 Bcf/d of production. The net change to the L48 from the recalibration was only around -0.1 Bcf/d over the last year, but with a significant redistribution amongst sub regions: while Texas decreased by roughly -0.6 Bcf/d, this was largely cancelled out by drier gas from Permian-NM, Oklahoma, and Wyoming.

2. Texas Production Reallocation

We have revised our lease allocation algorithm slightly, which has had the effect of moving some production from South/Central Texas to West Texas. We've This resulted in roughly 0.4 Bcf/d moving to West - TX, primarily from South - TX (-0.28 Bcf/d) and Central - TX (-0.14 Bcf/d). The net effect at the Texas state level is negligible.

Because of this reallocation, the resulting changes to the short term forecast will go live on Tuesday, 16 Jun.

3. State Refits

As usual, we have refit our model against the latest state-reported data. The most notable refit came in Haynesville Texas and Louisiana.

When the new Louisiana intrastate pipelines came online, we had originally assigned all LEG and NG3 related flows as incremental production. We now have enough stable data to calibrate that assumption. This reduced our estimated production for Haynesville Texas by around 0.3 Bcf/d, and Haynesville Louisiana by around 0.2 Bcf/d, a net change of -0.5 Bcf/d to our Haynesville production estimate over the last 6 months.

GCX Expansion Flows Begin

We've also seen the first flows from the Gulf Coast Express expansion on the new interconnects with Tennessee Gas (TGP) and Natural Gas Pipeline (NGPL) at Agua Dulce. Much of GCX's upstream interconnects are to other pipelines, not production, so we normally wouldn't count then towards production. But with Permian egress constrained and gas needing to flow east out of the basin, the new capacity is almost certainly carrying incremental production — so we're counting these flows as West - TX production initially.

Overall Texas Production Change

The three separate updates impacted our Texas production estimates the most. While the production reallocation had little net effect across the state, the combination of wetter-than-projected gas in South Texas and refitting against the reallocated state data resulted in an average change of -1.08 Bcf/d over the last 6 months.

Notable Sub Region Changes

South - TX

South - TX saw the largest revision of any sub region, down an average of 0.90 Bcf/d over the last 6 months. This is the combination of all three updates: a wetter dry gas factor (around -0.5 Bcf/d), the lease reallocation to West - TX (around -0.3 Bcf/d), and the refit against the reallocated state data.

Haynesville

Haynesville production has been revised downward by an average of 0.54 Bcf/d over the last 6 months, with Haynesville Texas down 0.31 Bcf/d and Haynesville Louisiana down 0.23 Bcf/d. Unlike South Texas, the other two updates had little impact here — a slightly drier dry gas factor (+0.05 Bcf/d) and the lease reallocation (-0.04 Bcf/d) roughly cancel — so the revision is almost entirely the recalibration of the LEG and NG3 related flows described above.

Permian (West - TX and Permian-NM)

Permian production has been revised upward by an average of 0.65 Bcf/d over the last 6 months. Permian-NM is up 0.38 Bcf/d on a drier dry gas factor, while West - TX is up 0.27 Bcf/d as the lease reallocation more than offsets a slightly wetter factor.

As usual, if you have any questions, please reach out to support@synmax.com.

Appendix: Updated Alignment Dates

When fitting our daily production estimates, we consider two key dates for each subregion:

• State alignment cutoff: the date up to which we align our daily production estimates to state-reported production.  On this day and prior the daily production model monthly averages are guaranteed to match state data.
• Last fitted date (or "last good" date): the date up to which we regress against the state data. The last fitted date can sometimes extend beyond the state alignment cutoff — this occurs when we are modeling reporting delays and therefore fitting against our own version of the state data (as discussed here).

The current alignment dates by subregion are shown below: