NATURAL GAS PRICE OUTLOOK - August 9, 2021 - SpaceCraft
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NATURAL GAS PRICE OUTLOOK August 9, 2021
The EIA reported a small build last week of 13 bcf and this
was 5-7 bcf below market expectations and was 19 bcf below
the same week last year. This puts total storage levels at 2,727
bcf for the week ended July 30th and puts the respective
deficits to last year and five-year average at 542 and 185 bcf.
The next three weeks are likely to see a small-ish combined
build of 90 bcf. And if valid, this year’s storage falls even
further behind with the deficit to last year then at 597 bcf and
the five-year deficit then at 223 bcf.
The market began this injection season at deficits of 235 and
24 bcf respectively in early April. But as seen on the graph
below, weekly builds this year have seldom matched or
exceeded either of the prior averages. So, the market remains
set up for potential price spikes in 4Q if the storage levels do
not improve on a relative basis in September and October and
if there is any lasting below normal temps early this winter.
WEEK 2021 2020 FIVE YEAR AVG
4/2 20 30 8 160
SUMMER INJECTIONS
4/9 61 68 26
150
4/16 38 47 37 2021 2020 FIVE YEAR AVG
4/23 15 66 67 140
4/30 60 103 81 130
5/7 71 104 82
5/14 71 84 86 120
5/21 115 105 91 110
5/28 98 103 96
100
6/4 98 95 92
6/11 16 86 87 90
6/18 55 115 83 80
6/25 76 73 65
7/2 16 57 63 70
7/9 55 47 54 60
7/16 49 38 36
50
7/23 36 27 28
7/30 13 32 30 40
8/6 50 55 42 30
8/13 10 45 42
8/20 30 45 44
20
8/27 36 53 10
9/3 65 65
0
9/10 86 79
9/17 70 74 (10)
9/24 74 72 (20)
10/1 75 81
10/8 50 79
(30)
10/15 49 69 (40)
4/2
4/9
4/16
4/23
4/30
5/7
5/14
5/21
5/28
6/4
6/11
6/18
6/25
7/2
7/9
7/16
7/23
7/30
8/6
8/13
8/20
8/27
9/3
9/10
9/17
9/24
10/1
10/8
10/15
10/22
10/29
10/22 32 62
10/29 (27) 38
TOTALS 1,053 2,606 1,912
Estimate
The EIA reported actualized dry marketed production at an average of 92.4 bcf/d for May. And this level equates to a slight month-on-month gain of 0.1 bcf/d compared the 92.3 bcf/d level for April. And comparing such on a year-on-year basis has the gain at 4.6 bcf/d to May of 2020. While production is continuing to hang in above analysts’ previous expectations - the comparison to the same month last year is a bit misleading as May of last year saw acute shut-ins for crude oil and natural gas due the price collapse then and the full effect of Covid lockdowns then. Note the graph below; actual production reported keeps coming in higher than the EIA’s (and analysts) weekly estimates for same. For Jan-May, actual production averaged 91.2 bcf/d compared to the EIA’s weekly estimates of 90.2 bcf. And weekly estimates have been steadily rising since 1Q. So it could be that actual production is now pushing 94 bcf/d again. We still foresee production rising slightly into the end of year - despite producers’ new-found discipline on cap-ex. Prices are just too high to not expect some kind and the U.S. oil rig count has been continually increasing.
Total actual U.S. demand for May was at an average of 67.7 bcf/d and compares to 66.8 bcf/d for May 2020 representing a small gain of 0.9 bcf/d year-on-year. However, this is disappointing overall as May 2020 demand was so low due to the shut-downs related to Covid at that time last year. Demand for power-generation for May averaged 26.3 bcf/d and thus was lower by 0.6 bcf/d to the 26.9 bcf level in May 2020. The biggest miscalculation that we made going into the April-October period was expecting much more gas-to-coal fuel switching due to the higher gas prices than last year and prices clearly above the PRB Coal price. We had assumed this factor would loosen otherwise market tightness due to the high export levels. But whether due to a hot summer or a smaller pool of fuel-switchable load dispatch, this has not been the case as anecdotal data has most days this summer gas load matching or exceeding last year. Industrial demand was at 21.3 bcf/d for a 1.2 bcf/d gain over May 2020 - but disappointing in that 2021 is still not back to 2019 levels.
Net U.S. exports for the month of May averaged 11.93 bcf/d on an actualized basis - yet another all-time record. This total broke down as; (i) LNG exports at 10.16 bcf/d, (ii) pipeline exports to Mexico coming in at an average of 6.10 bcf/d, and off set by (iii) Canadian imports averaging 4.28 bcf/d during the month, and (iv) LNG imports at a level of 0.05 bcf/d (essentially nothing). The increased level of Mexican pipeline exports has been almost as impressive in the gains from the LNG export market this year running 1.38 bcf/d (30%) higher in April and May than the same months last year on actual data. And estimated data shows exports south of the border many days currently hitting 6.5 to 7.4 bcf/d with summer power demand. But this will likely back down by 1.0 – 1.3 bcf/d once cooling loads diminish deeper into September. The biggest risk right now to exports remaining at these elevated levels is once again that Covid-lockdowns begin occurring globally and accordingly reduce energy demand.
The European and Asian gas markets have been on a tear trending much higher for most of 2021. Part of this is due the “re-opening” of global economies post-Covid and the resultant demand surge therefrom. But there is another more compelling reason that we have all seen before at least for the surge in gas prices in Europe - good old government intervention. In complying with all the various and ever-increasing emissions limits in place over there - the price of carbon credits and emissions offset credits (“EUA” in the graphs below) have similar gone through the roof. Europe’s zealousness to reduce emissions (which they have) has outrun the pace of new-build renewable power generation available. Thusly, summer cooling demand over there has had to have more so been met with gas-fired generation. Stand-alone coal prices would allow for much more gas-to-coal switching - but not when adding on the additional absurdly high costs for carbon credits to burn coal. The net effect is that European gas storage continues to lag behind and the LNG export party overseas just rolls on. All of this global move to green energy continues to artificially raise prices for consumers.
Other than the effect of the February freeze-offs from Winter Storm Uri hitting Texas - U.S. total crude oil production has held steady to higher. The latest actualized data for the month of May 2021 has such 880,000 bbls/d below the level of May 2019 when total crude production was the highest that year heading for a peak in 4Q 2019. Net production has not declined further despite an oil rig count that has averaged 339 rigs operating since January 1st - an average 100 rigs below the same period last year and 480 rigs below the same period in 2019 (current oil rig count is running 207 rigs currently above the low ebb last summer). And the main reason (beyond greater individual well yields) that oil production has held in and is even slightly rising is due to the fact that producers are finally going back and completing previously drilled wells. “DUC” inventory is declining in almost all shale plays. We point this out not as much for the effect on global oil prices as the potential effect on U.S. natural gas prices. If U.S. gas production is going to increase later this year - net gains will likely be from increased oil production and associated gas therewith.
Much has been written and will be written about Winter Storm Uri’s effect on the ERCOT market. And we are going to revisit briefly here as more data has come to light in recent months. The load-shed against consumers would have had to happen even if the state had not lost so much generation. But the loss of gas supply to thermal plants was clearly the main reason that the grid was so short those few days. And ironically, come to find out that 45% of the lost production was due to power curtailment either at the wellhead or downstream infrastructure. And around 25% of the lost gas production was due to freeze-offs. The wellhead stream in Texas as a whole is wetter now with more production coming from associated gas. Note that Permian processing plant throughput was down by 80-85% for three straight days. A cold event will happen again in ERCOT - but with a softer price outcome due to weatherization and revised ERCOT protocols on load-shed for gas-flow.
Cum-to-date Cooling Degree Days this summer have averaged 1.0 degree above
normal and 0.4 degrees below last year for a warm but not crazy-hot resolution. CDD NORMAL CDD 2020 CDD 2021
Much like most of this summer, the forward forecasts (CFS and Euro models) JUN
JUN
37
43
46
59
37
68
have any above-normal temps limited to the northern high plains and far west. JUN 50 37 64
JUN 58 68 59
JUL 65 75 80
While temps within ERCOT have been mostly muted this summer with the rain, JUL
JUL
70
73
90
87
76
79
wind-avails have similarly been generally lower than normal. The next couple of JUL
JUL
75
75
94
91
74
85
weeks have strong wind this week, a lull over the weekend, then middling after. AUG 73 73 64
AUG 69 91
AUG 65 71
AUG 57 87
TOTALS 810 969 686
CUM-TO-DATE 619 720 686
CDD DELTA NA 101 67
# OF DAYS NA 70 70
AVERAGE CDD DELTA NA 1.4 1.0
CDD 2021 CDD NORMAL CDD 2020
110
100
90
80
70
60
50
40
30
20
JUN JUN JUN JUN JUL JUL JUL JUL JUL AUG AUG AUG AUGYou can also read
