Natural Gas Weekly: January 17, 2024
Flows – A mid-January Arctic blast has put a serious dent in Lower 48 gas production and sent cash prices soaring at many hubs. East Daley estimates dry gas production fell below 96.0 Bcf/d on Monday (January 15), a decline of ~8.0 Bcf/d (-7.7 %) from levels seen the week ending January 11, and supply remains much lower this week.
The largest declines from the front, dubbed Winter Storm Heather, have occurred in the Williston, Anadarko, Permian and ArkLaTex basins. EDA estimates Permian supply declined nearly 3.0 Bcf/d over the weekend, while Haynesville production fell nearly 1.0 Bcf/d.
Cash prices at the Henry Hub traded at $13/MMBtu over the long weekend and Tuesday (January 16), and prices exceeded $30 in the Texas Panhandle and upper Midwest. Prices spiked on Wednesday (January 17) across the East Coast as bitterly cold temperatures pushed eastward. Transco Zone 5 traded over $19 while Tetco M3 prices in the Mid-Atlantic spiked to $21.
Production started falling last Thursday (January 12) from wellhead freeze-offs. Regional pipe samples have declined by 6 Bcf/d over the latest five days (January 12-16) vs the trend to date in January (see figure). The Haynesville (-1.6 Bcf/d), Anadarko (-1.2 Bcf/d) and Williston (-0.9 Bcf/d) have seen the largest declines in pipeline samples over the 5-day period.
While production freeze-offs are a concern during cold weather, the impact on storage inventories could be more serious. With less produced gas and elevated Res/Com demand, storage withdrawals are likely to be significant.
Despite the bullish weather, futures prices have fallen. The prompt month February contract ended trading last Friday at a high of $3.37/MMBtu but has since retreated down to $2.87 on Wednesday (January 17). Futures appear to be discounting the impact given a quick warm-up is expected. NOAA predicts in its 6-10 day outlook that much of the country, including heavy gas consuming areas in the Midwest, will see above-normal temperatures as soon as Wednesday evening.
Infrastructure – Developers continue to make progress signing customers to new LNG projects, firming up the long-term outlook for natural gas demand.
On January 16, Mexico Pacific signed ExxonMobil LNG Asia Pacific (EMLAP) to an additional 1.2 Mtpa (~0.16 Bcf/d) contract for Train 3 of the proposed Saguaro Energia LNG facility. The contract will supply EMLAP with LNG on a free-on-board basis for a 20-year term from the project on Mexico’s western coast.
Mexico Pacific already has 1.3 Mtpa of binding offtake agreements with EMLAP signed last February. EMLAP also holds an option to purchase another 1 Mtpa from T4 of the Saguaro terminal.
This SPA puts Saguaro Energia at 81% contracted in total. East Daley expects the facility to take a final investment decision (FID) this quarter.
The Saguaro facility will be supplied in part by ONOEK’s proposed Saguaro Connector out of the Permian Basin. In September, OKE management said FID of the pipeline is dependent on Mexico Pacific’s export facility reaching FID. Both projects may be waiting on progress on the Saguaro Energia Gas Pipeline, a joint development between Mexico Pacific and the Mexican Comision Federal de Electricidad (CFE), which will connect to OKE’s Saguaro Connector at the border.
On January 11, EQT signed a heads of agreement (HoA) with Glenfarne’s Texas LNG for 0.5 Mtpa for a 15-year term. East Daley does not include Texas LNG (4 Mtpa export capacity) in our LNG export forecast because the facility has no binding offtake agreements. Before the latest HoA, the project had no supply agreements of any kind.
EQT also signed an HoA with Commonwealth LNG to produce 1 Mtpa under a 15-year tolling agreement in September ‘23. Commonwealth LNG expects to reach FID in the 1Q24 but would need to convert several HoAs to binding agreements to do so. Thus far, the 8.4 Mtpa project is only 30% contracted under a single SPA with Woodside. However, Commonwealth has an additional 7.5 Mtpa of HoAs going back to 2019 that could be converted to binding contracts.
Storage – Traders and analysts expect the Energy Information Administration (EIA) to post a -155 Bcf withdrawal from working gas storage inventories for the week ending January 12. However, most attention will be on the following report for the January 18 week, when the EIA survey will account for potentially record-high demand amid this week’s Artic blast.
The 5-year average withdrawal for the week ending January 18 is 153 Bcf. Early withdrawal estimates were around 180 Bcf prior to the storm. With lower production and increasing demand through mid-week, withdrawals could near the 300 Bcf mark.
The weekly highwater mark for storage withdrawals occurred the week ending January 5, 2018 at 359 Bcf. Winter Storm Uri in late February 2021 saw a withdrawal of 338 Bcf for the week ending February 19, 2021. Those are the only two weeks in recorded history with 300+ Bcf withdrawals.
EIA reported a -140 Bcf withdrawal for the January 5 week, far exceeding market estimates for a -114 Bcf storage pull and suggesting a tightening market.
East Daley estimates inventories could fall to around 2,750 Bcf by the January 25 week and take a sizable bite out of the storage surplus. A withdrawal of this size would narrow the surplus to 167 Bcf over the 5-year seasonal average. In the latest Macro Supply and Demand Forecast, EDA forecasts storage to exit March 2024 at ~1,949 Bcf.
Rigs – US rigs increased by 3 W-o-W to bring the total count to 591. The Bakken is up 2 rigs for the January 7 week, and the Marcellus+Utica and Eagle Ford are up 1 rig each. The Permian lost 2 rigs and the ArkLaTex is down 1 rig.
On the midstream side, ONEOK (OKE) is up 2 rigs on its Bakken and Anadarko systems. Energy Transfer (ET) is up 2 rigs across its Permian and Anadarko systems. EnLink Midstream (ENLC) is down 2 rigs with losses on its Anadarko system. Kinder Morgan (KMI) is down 3 rigs on its ArkLaTex and Uinta systems.