Today’s report (week ended 18 Jan): EIA: net change: -163 bcf, EA: -163 bcf
- A nearly 3 bcf/d increase in power generation demand and another 9.5 bcf/d rise in the res-com sector propelled withdrawal activity.
Next Thursday’s report (week ending 25 Jan): EA preliminary: -187 bcf
- Freeze-offs will crimp supply by 1.2 bcf/d w/w. Res-com demand will rise by more than 3 bcf/d due to the cold, more than offsetting a 0.4 bcf/d w/w decline in gas-fired power.
NYMEX gas prices have been riding the weather forecast rollercoaster, but our balances are still calling for an end-March carryout near 1.2 tcf, chipping some 25 bcf w/w off our end-of-season carryout. As we indicated last week, weather conditions were set to lead to freeze-offs in Appalachia. The basin has lost 9-10 bcf of production on a cumulative basis since last week due to freeze-offs, according to our flow data. The 15-day forecast still suggests a top-five largest-ever withdrawal for the week ending 1 February, but there remains a chance that the withdrawal could be even larger and break the record to become the second-largest withdrawal in the EIA weekly series. If the predicted deep cold of some commercial forecasters does materialise in the Midwest, with low temperatures below -20°F in Chicago, our balances would point to an even deeper withdrawal for the week ending 1 February, broaching 300 bcf and taking our end-February carryout to 1.22 tcf.
With such storage activity dictated by the near-term weather forecast, fundamentals have not turned bearish since last Thursday’s Panorama—though the price backdrop would suggest otherwise, with Feb-19 trading at $3.15/mmbtu as of 1:00 New York time on 24 January. With the notable step up in withdrawal activity in late January and early February (see Fig 1), the Feb-19 and Mar-19 contracts look poised to be dragged higher by a cash-led rally.
Weather has stoked demand, but production is bearing the mark of that cold as well. Production in January appears on track to drop by 1.1 bcf/d m/m, in part due to early month freeze-offs in San Juan and the Rockies as well as the latest cold bout in the Northeast. Importantly, this forecast assumes a normalising level of production through the end of the month, though there is a risk the massive cold in the last week of January could buttress even more weakness in production and further tighten balances. Currently, low temperature forecasts point to a risk of Appalachian (but not Haynesville or Permian) freeze-offs once more at end-January through the first week of February. Consequently, our forecast withdrawals could skew tighter than currently indicated, especially in the week ending 1 February (please see page 4 of the attached report for our weekly supply-demand forecast).
|Fig 1: Projected storage y/y change, bcf/d||Fig 2: Appalachia output (bcf/d) vs low temperature in Washington, PA (°F)|
|Source: EIA, Energy Aspects||Source: Ventyx, Weatherbell, Energy Aspects|
Of course, in addition to freeze-offs the Northeast region is now dealing with acts of God—namely the sinkhole taking Mariner East 1 offline and Monday’s explosion on Texas Eastern (TETCO). The latter has a significant impact on flows through the Berne Compressor and flows south, and its ultimate duration will have a bearing on M2 basis. There is a strong chance of no gas flows to the facility into February. Flows in the region are currently commingled with losses from the cold weather, but Fig 3 shows this morning’s (24 January) cycle of flows through Berne. Meanwhile, impacts of the outage at Mariner East 1 appear to be near nil on the gas side as processing plant receipts have not dropped on our flow sample.
For TETCO, a full outage lasting beyond early February appears unlikely based on precedent. The closest historical analogue is an explosion on Texas Eastern’s pipeline network in southwest Pennsylvania on 29 April 2016. The downstream compressor station in that case, Delmont, was not operational for 11 days. Partial flows were restored on 10 May, and full service did not resume until late November 2016, as the facility operated at just over half of its pre-accident baseline in the intervening period (Fig 4). Since Enbridge crews have already shut-in area pipelines affected by the accident and are working towards early repairs to restore gas to Berne, it seems likely that some flows will be restored in early February. A full fix to the damage from the explosion will likely last much longer though.
These production losses are being partially offset by lower feedgas volumes into LNG export facilities. Notably, Cove Point is running full bore on feedgas. Sabine Pass saw a minor dip from NGPL maintenance, but Corpus Christi volumes have dropped in the past eight days to essentially zero. Last week, our models indicated that Corpus Christi was near tank tops, but since then a laden ship departed the facility. The significant slowdown in intake could signal on-site maintenance is taking place as Train 1 prepares for commercial operations. If the interruption/issue continues through month-end, it would shave 0.35 bcf/d off feedgas demand compared to our previous estimate.
Canadian net trade and US LNG sendout are responding to the cold. Elba Island took in an import on 5 January, while a tanker stands in Boston Harbor, likely awaiting higher prices for sendout through Everett. Canadian net flows have already jumped to levels not seen since last winter’s bitter cold.
While our balances have a bullish tilt, any retracement in the predicted ’polar pig’ could see the market shave off recent gains and then some, with the number of days left in the traditional heating season dwindling. But with bitter cold looming, short-term weather forecasts are still in control.
|Fig 3: Flows to the Berne compressor, bcf/d||Fig 4: Flows to the Delmont compressor, bcf/d|
|Source: Ventyx, Energy Aspects||Source: Ventyx, Energy Aspects|