RBC Capital's take on the U.S. Natural Gas Market - May 25

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RBC Capital's take on the U.S. Natural Gas Market - May 25

Post by dan_s »

Helima Croft, Head of Global Commodity for RBC Capital Markets and her team are FIRST CLASS. Helima is one of the smartest humans on Earth.
> As I have been telling you, "Market Forces" will rebalance the U.S. gas market, which today is not far out of balance.
> Weather will always be a major factor on the demand side for natural gas.
> May is the month of weakest seasonal demand and therefore the largest storage builds.

May 25, 2023
Natural Gas Navigator

Model Update
For the last several months, natural gas has been trading within a one-dollar range, mostly closer to $2/MMBtu than to $3/MMBtu. In this
report, we maintain all price scenarios—note that the base/middle scenario is above the curve until November 2023. Currently, managed money
positioning appears weak, and with prices in the weaker end of the recent range during a seasonally weak period, we think we are walking on a
somewhat firm floor. Once we get through the current bout of price weakness, we think gas prices should be closer to and eventually pass the
$3/MMBtu mark at times.
We also think that at specific points this summer, prices may need to reflect the growing burden that warmer than
normal weather would imply. Current prices have certainly begun to eat into supply-side activity (rig counts have dropped), but elsewhere the
themes remain consistent: no large-scale structural demand growth is set to occur outside of chunky LNG additions coming online later in 2024 and
into 2025, which are set to turn the cycle in our new world of clearer and potentially shorter gas price cycles. We reiterate our view with the caveat
that there may be further upside price risks building in the latter half of 2024.

 Supply and Price Impact: While ytd supplies continue to average around 100 Bcf/d and are set to result in healthy annual average production
growth in the lower-48 (averaging over 6 Bcf/d higher y/y ytd), lower gas price outlooks have taken their toll on drilling activity, resulting in
falling rig counts. While we still have 2023 production in the lower-48 averaging around 99.5 Bcf/d, we have trimmed our 2024 number from
over 101 Bcf/d to 100.5 Bcf/d on average, primarily because of the Haynesville, despite associated gas, particularly from the Permian, being a
more durable contributor in our forecasts into next year. Regardless, even this outlook still does a lot of the leg work to keep a lid on prices.

 Seasonal Impacts, Demand and Weather: While much of the 2022/23 withdrawal season being warmer than normal allowed end-of-season
storage to beat our expectation in 2023, our latest turn of the balance still makes adjustments, albeit minor, to our storage outlook, with endof-season storage numbers being 3.8 Tcf in November 2023 and 1.8/3.9 Tcf in 2024 (rounded). In terms of weather, while warmer than normal winter
months loosened the balance, 2022 presents a tough comp y/y for overall demand in 2023, largely due to a hot summer. That said, mediumterm forecasts point to 15.7% higher CDDs in the next 45 days, and the latest NOAA three-month outlook for the June-July-August period points
to higher probabilities of above-normal temperatures for much of the country outside the Midwest, hence our view that summer prices may
be stronger than expected at certain points.
Elsewhere, thematically our view has not changed much. Industrial demand is subject to the most
non-weather-related demand risks in the event of a more sizable recession. Likewise, little has changed for our rescomm view, although the
new natural gas hook-up bans like that seen in New York state do have a longer-term impact on demand growth in the sector.

 LNG and Global Gas: LNG flows from the US have been tepid recently (contributing to some of the near-term price weakness), with tepid spot buying and rising floating storage as well as usual seasonal trends. This tepid period and high EU storage levels do not, however, mean that a
crisis will for sure be averted. While EU storage has filled quickly, this coming winter will be an important test, assuming more normal weather.
Europe and Asia will potentially be bidding against each other for LNG cargos at a time when weather is not so cooperative. Additionally, with
no new US capacity coming online for this winter, the likelihood of substantial incremental US cargoes y/y is limited. Likewise, while Russian
gas does still flow to Europe in diminished but consistent quantities (which has taken a toll on Russian gas production and tax revenues); our
pipeline cutoff watch simply gets pushed out to next winter (if a particular pain point materializes). Thus, while US LNG export demand has
been tepid recently, it won’t necessarily stay so. Total natural gas feed gas volumes reached well above 14 Bcf/d with Freeport back online last
month, and more recently volumes have been more challenged, around 12.8 Bcf/d. While we expect average LNG export feedgas to be closer
to and somewhat above the 13 Bcf/d mark this year and next, from the perspective of US balances, utilization levels are key to watch, at least
until the next round of export capacity additions comes online and perhaps starts another cycle.
Dan Steffens
Energy Prospectus Group
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