The Final Countdown, Part 2 - RBN's Five-Year Natural Gas Market Outlook
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Sunday, 02/12/2023Published by: Sheetal Nasta
The CME/NYMEX Henry Hub prompt futures price has fallen precipitously in recent months and 2023 has the potential to be one of the most bearish in recent history. But longer term, the stage is set for tighter balances, price spikes and increased volatility. After a slowdown in 2022-23, LNG export capacity additions will come fast and furious over the next several years. As they do, they will outpace production growth, which will increasingly depend on pipeline and other midstream expansions. In other words, 2023 will be the last aftershock of Shale Era surpluses. We got a taste of what that could look like in 2022, but just how out-of-whack could the gas market get? In today’s RBN blog, we discuss the supply and demand trends that will shape the gas market over the next five years.
In Part 1, we summarized the various factors that sent gas prices tumbling from 14-year highs nearing $10/MMBtu six months ago to the sub-$3/MMBtu prices seen in recent weeks. It started with the shutdown of the Freeport LNG export facility after a fire last June that took nearly 2 Bcf/d of demand out of the market instantly. On top of that, a mild fall shoulder season dampened demand further even as production hit single-day highs of 100 Bcf/d or more. And the final death knell for bullish prospects in the near-term? One of the most bearish starts to the new year in at least 13 years — possibly ever. An exceptionally warm January crushed demand and domestic consumption dropped to six-year lows for January and lagged by more than 14 Bcf/d year-on-year, while the Freeport outage kept exports flat. At the same time, the warmer weather kept wellhead freeze-offs at bay and dry gas production surpassed 100 Bcf/d on a monthly average basis for the first time in January, averaging 6.2 Bcf/d higher than last year. As a result, the supply-demand balance was the loosest we’ve seen in January going back to at least 2010, and ~20 Bcf/d looser than last year.
These trends compounded what was already a bearish scenario for 2023. That’s because for the first time since 2016, there is little upside to LNG export growth expected this year. Freeport is in the process of restarting operations, but that is the return of existing capacity. And while Venture Global’s Calcasieu Pass will be commercialized this year, it was already taking feedgas for much of last year at a rate consistent with full utilization. Beyond that, there’s no new export capacity due online this year. On the other hand, Lower 48 dry gas production is on track to notch a healthy year-on-year gain. To the extent that storage has to absorb the rest, we are likely to see surpluses swell, which will not only mean lower prices versus 2022 but a return to the kind of rangebound price action we saw pre-COVID.
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But as we also mentioned in Part 1, the 2023 downturn is likely to be short-lived, as the next wave of LNG export capacity starts to ramp up in 2024 and accelerate over the coming years (more on the latest project timelines in an upcoming blog). Overall, production will most likely keep up, but as the market tightens, the potential for mismatched timing between LNG exports and production growth will make it touch-and-go in some years. That brings us to our five-year outlook and how balances are likely to shape up by year.
Figure 1 below summarizes the components of the Lower 48 gas supply-demand balance equation in our Mid-case scenario through 2028, assuming the current futures curve. The stacked layers in the background represent annual averages for the supply components, including dry production (navy) and net imports from Canada (red). (LNG imports, which used to be a more important source of supply, are now minimal to none, depending on the time of year.) The columns in the foreground stack up the various sources for gas demand, including lease, plant and pipe fuel (gray), residential and commercial (peach), industrial (brown), gas-fired power generation (yellow), exports to Mexico (green), and LNG exports (the blue bars at the top of the stack).
Figure 1. RBN’s Lower 48 Natural Gas Supply-Demand Balance Mid-Case Scenario. Source: RBN
We’ll start with our full-year outlook for 2023. After accounting for actuals to date, RBN has domestic demand — including power, industrial, res/comm, and lease, plant, pipe loss and storage combined — averaging 87 Bcf/d, down almost 1 Bcf/d from 2022, assuming normal weather. (Last year was marked by cooler-than-normal winters and a warmer-than-normal injection season, which contributed to record consumption). Exports to Mexico are slated to average 6.3 Bcf/d, up from 5.7 Bcf/d last year, while LNG feedgas deliveries (blue bar segments) are estimated to come in at 11.7 Bcf/d, up ~1 Bcf/d year-on-year. That brings total demand, including exports, to about 105 Bcf/d, up a net 0.8 Bcf/d year-on-year. However, at that level, demand would fall short of supply (dashed black circle).
On the supply side, dry gas production in our forecast averages ~102 Bcf/d in 2023, up about 5 Bcf/d year-on-year. This assumes that production out of Appalachia will be constrained by pipeline capacity, but that the other basins will grow unconstrained as midstream capacity will get built in time to support growth. Net imports from Canada responded to the tight Lower 48 gas market last year, but we would expect that to moderate to 4.8 Bcf/d this year, down from 5.5 Bcf/d in 2022. That leaves the Lower 48 balance 1.7 Bcf/d long supply in 2023 (106.8 Bcf/d total supply minus 105.1 Bcf/d total demand).
However, it will be an entirely different story in the ensuing years as the next wave of LNG projects comes online but production becomes increasingly dependent on the next pipeline project to grow (see the Where It’s At blog series). The surpluses will flip to a deficit as LNG export capacity additions begin to outpace production gains. Based on what RBN identifies as Tier 1 or better LNG projects in our LNG Voyager report, after slowing in 2022-23, LNG capacity additions will accelerate, bringing on an incremental ~3 Bcf/d of feedgas demand each year on average between 2024 and 2026, and another 1.8-1.9 Bcf/d in 2027 and 2028. That’s an incremental 14 Bcf/d of demand from LNG exports alone compared with 2022 levels (and doesn’t include capacity additions in Canada or Mexico). Combined with domestic demand, that means total demand in our Mid-case scenario grows ~18 Bcf/d (an average of 3 Bcf/d per year) from the 2022 level to 122.2 Bcf/d by 2028.
By comparison, our Mid-case scenario for total supply, including imports, is slated to grow by a much more modest 16.6 Bcf/d in the same period to 119 Bcf/d by 2028. Breaking that down further, we expect production to grow by 17.9 Bcf/d to a total of 114.8 Bcf/d by then. After this year, we expect growth to moderate and average 2.5 Bcf/d per year through 2028. Net imports from Canada are also expected to taper somewhat in the coming years, as LNG exports emerge as a major demand source in Western Canada and compete with pipeline exports for production and pipeline capacity. What that means for our Mid-case supply-demand scenario is that the Lower 48 balance goes from being supply-long in 2023 to being ~2 Bcf/d short by 2024, and worse, to negative 4.3 Bcf/d by 2027.
In other words, the Lower 48 gas market is headed for a period of gas shortages, driven by export growth and piecemeal production growth dependent on midstream development. Of course, there are risks to this outlook. A massive storage surplus this year could spill into next year and delay the onset of a gas shortfall. A delay in LNG export capacity additions, or extended disruptions like the Freeport outage, would have a similar effect. On the other hand, midstream constraints that stymie production growth could bring it on sooner. And weather will remain the constant wildcard. But the bottom line is that with the onslaught of LNG exports, the odds of oversupply conditions extending beyond 2023 in the Lower 48 gas market have vastly diminished.