Total demand for U.S. natural gas is up 10.8% y-o-y to 101 bcf/d.
Total U.S. natural gas supply is up 7.8% y-o-y to 103.2 bcf/d.
LNG exports almost reached a new all-time high.
We currently expect the EIA to report a draw of 1 bcf next week, which is 43 bcf larger than a year ago and 31 bcf larger vs. 5-year average.
We expect dry gas production to peak this year and remain essentially flat for the whole of 2020.
This report covers the week ending November 8, 2019.
We estimate that the aggregate demand for American natural gas (consumption + exports) totaled around 710 bcf for the week ending November 8 (up 7.4% w-o-w (week over week) and up 10.8% y-o-y (year over year)). The deviation from the norm remained positive and actually increased from +26.0% to +30.0%. We estimate that total demand has remained above the 5-year norm for 43 consecutive weeks now.
Source: Bluegold Research estimates and calculations
This week, the weather conditions have cooled down significantly across the Lower-48 states. We estimate that the number of nationwide cooling degree-days (CDDs) dropped by 12.2% w-o-w (from 9 to 8), while the number of heating degree-days (HDDs) jumped by 17.3% (from 102 to 120). Total energy demand (measured in total degree-days - TDDs) was approximately 13.9% above last year's level and around 26.5% above the norm.
However, non-degree-day factors were predominantly bearish (vs. last year). The most important four non-degree-day factors that we are looking at are: nuclear outages, the spread between natural gas and coal (coal-to-gas switching), wind speeds and hydro inflows.
- Nuclear outages were mostly below the norm (15.1 GW per day on average) - see the chart below.
- The average spread between natural gas and coal increased by +$0.266 per MMBtu (as the price of natural gas surged, while the price of coal remained essentially unchanged). We estimate that coal-to-gas switching averaged around 5.4 bcf/d this week (down 0.1 bcf/d vs. 2018 and down 0.5 bcf/d vs. the 5-year norm).
- Wind speeds and hydro inflows were mostly stronger y-o-y. On balance, in the week ending November 8, these two factors probably displaced some 100 MMcf/d of potential natural gas consumption in the Electric Power sector (compared to the same period in 2018).
Source: U.S. Nuclear Regulatory Commission
Overall, the net cumulative effect from non-degree-day factors this week should be positive at around +2.7 bcf/d of potential natural gas consumption in the Electric Power sector. However, that positive figure is some 0.3 bcf/d below last year's results.
Total exports were up 9.4% w-o-w - primarily due to stronger pipeline exports into Canada and robust LNG sales (please note that our LNG export estimates are based on the vessels tracking system, not on the liquefaction flows). According to Marine Traffic, U.S. LNG export terminals (Sabine Pass, Cove Point, Corpus Christi, Cameron, and Freeport) served 12 LNG vessels with a total natural gas capacity of 41 bcf, just 0/6 bcf short of an all-time record. Total LNG feed gas flows averaged 7.2 bcf/d. In annual terms, total exports increased by 14.1% in the week ending November 8.
Currently, we expect natural gas exports to average 13.12 bcf/d in November, 13.82 bcf/d in December, and 14.42 bcf/d in January (see the chart below). The share of LNG exports should reach 46% by 2020.
Source: Bluegold Research estimates and calculations
We estimate that dry gas production has been expanding in annual terms for 127 consecutive weeks now, but the growth rate is weakening due to base effects. Currently, we project that dry gas production will average 95.3 bcf/d in November, 93.5 bcf/d in December, and 92.8 bcf/d in January. In the week ending November 8, we estimate that the aggregate supply of natural gas (production + imports) averaged around 103.2 bcf per day (up 0.7% w-o-w and up 7.8% y-o-y).
Our research shows that U.S. dry gas production is at a major long-term peak. Indeed, we expect dry gas production to remain essentially flat for the whole of 2020. Production may even decline slightly (in annual terms) in spring/summer of 2020. Near-term shale production is already declining because output declines at legacy wells outrun new production coming online, as fewer new (and productive) wells are being drilled compared to last year.
Overall, total "non-adjusted" supply-demand balance for the week ending November 8 should be positive at around +2.14 bcf/d, which is approximately 2.3 bcf/d tighter compared to the same week in 2018 (see the chart below). However, next week (ending November 15), the balance is projected to get looser. Annual difference should be positive, at around +5.23 bcf/d (i.e., -10.55 bcf/d in 2019 vs. -15.78 bcf/d in 2018) - see the chart below.
Source: Bluegold Research estimates and calculations. Please note that total SD balance does not equal storage flows.
Weather-neutral SD balance (see the definition below) is projected to tighten slowly compared to the previous year. As of today, we estimate that the weather-neutral SD balance is around +5.39 bcf/d (vs. 2018), but we expect the balance to drop to -0.02 bcf/d (vs. 2019) by January 17, 2020.
Source: Bluegold Research estimates and calculations. Weather-Neutral SD Balance (yellow curve on the chart above) = production + imports - exports.
Currently, we expect the EIA to report a draw of 1 bcf next week (final estimate will be released on Wednesday). Overall, at this point in time, we expect storage flows to average -47 bcf over the next two weeks (three EIA reports). Natural gas storage "surplus" relative to the 5-year average is currently projected to narrow (and turn into "deficit") from +29 bcf today to -52 bcf for the week ending November 22.
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