Balance

So far this winter, front-month CME/NYMEX natural gas futures have fallen, risen and fallen again but, until their most recent dip, generally remained within the same $2.30-to-$3.30/MMBtu range where they have been lingering since mid-2023. With production sustaining near-record levels, LNG export volumes down from the winter highs, and temperatures back to normal, the supply of gas remains plentiful — a bearish scenario. In today’s RBN blog, we look at why there’s been a lid on natural gas prices — and the odds that the situation might change before the rapidly-approaching end of the winter season.

The CME/NYMEX Henry Hub prompt natural gas futures prices have been relatively rangebound this injection season and have averaged around $2.60/MMBtu since June — a third or less of where prices stood during the same period last year, in the $7-$9/MMBtu range, and at or below most natural gas producers’ breakeven costs. Yet, this is a much rosier scenario than it could have been considering that the first quarter of 2023 was one of the most bearish in over a decade and led to a massive storage surplus vs. last year that persisted through much of the summer. Since setting the year-to-date monthly average low of $2.19/MMBtu in April, prompt futures rose to an average of nearly $2.50/MMBtu in June, ~$2.65/MMBtu in July and August, and have mostly stayed in the $2.50-$2.75 range in September to date. In today’s RBN blog, we break down the factors that kept prices from unraveling this injection season to date and the implications for the rest of the shoulder season. 

The CME/NYMEX Henry Hub prompt natural gas 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.

The Lower 48 natural gas market has had the most bearish start to a new year in a long time. Production has been at record highs, an exceptionally warm start to January suppressed demand, and LNG exports have been hobbled since last June when Freeport LNG went offline. The CME/NYMEX Henry Hub February gas futures contract slid to an 18-month low of $2.94/MMBtu last Thursday and expired Friday at $3.109/MMBtu, down 54% from where the prompt contract closed just two months earlier. The March contract extended the slide Monday to a 20-month low of $2.677/MMBtu. Freeport’s eventual return will restore existing export capacity, but there’s no new LNG export capacity due online this year — for the first time since 2016. After one of the tightest gas markets of the last decade in 2022, the stage is set for one of the most oversupplied markets we’ve seen in years. But the bulls out there can take solace: 2023 will also mark the final throes of the kind of oversupply conditions that defined the Shale Era as we know it. In today’s RBN blog, we discuss how we got here and RBN’s outlook for natural gas supply and demand.

Lower 48 natural gas production this month hit a once-unthinkable milestone, topping the all-important psychological threshold of 100 Bcf/d for the first time. Volumes have remained at record highs through mid-September, with year-on-year gains expanding to a breathtaking 7-9 Bcf/d above last year at this time (when hurricane-related shut-ins were in effect). The record production levels coincided with a seasonal decline in weather-related demand, as well as the ongoing outage at the Freeport LNG export terminal. Remarkably, however, even with all-time high, ~100 Bcf/d natural gas production and Freeport LNG offline, the Lower 48 gas market balance averaged tighter year-on-year — a testament to just how strong consumption has been lately, and for much of this summer for that matter. In today’s blog, we look at how the supply-demand balance has shaped up this month and where it’s headed near-term.

Prompt CME/NYMEX Henry Hub natural gas futures prices averaged $4.54/MMBtu this winter, up 67% from $2.73/MMBtu in the winter of 2020-21 and the highest since the winter of 2009-10. Prices have barreled even higher in recent days, despite the onset of the lower-demand shoulder season, with the May contract hitting $6.643/MMBtu on Monday, the highest since November 2008 and up more than $1 from where the April futures contract expired a couple of weeks ago. Europe’s push to reduce reliance on Russian natural gas has turned the spotlight on U.S. LNG exports and their role in driving up domestic natural gas prices. However, a closer look at the Lower 48 supply-demand balance this winter vs. last suggests that near-record domestic demand, along with tepid production growth, also played a significant role in drawing down the storage inventory and tightening the balance. Today’s RBN blog breaks down the gas supply-demand factors that shaped the withdrawal season and contributed to the current price environment.

The natural gas futures contract for the prompt month barreled a net ~$1.00 (26%) higher in the past 12 days as the potential for prolonged production shut-ins in the Gulf of Mexico after Hurricane Ida amplified already-heightened supply fears in both the U.S. and international gas markets. The blistering price action sent the CME/NYMEX Henry Hub October futures contract soaring on Wednesday to an intraday high above $5/MMBtu and a settle of $4.914/MMBtu, the highest during September trading since 2008, while the prompt December and January contracts settled above $5/MMBtu for the first time in years. Prices at European and Asian gas/LNG hubs have similarly rallied this summer to multi-year or even all-time highs. Offshore Gulf gas production has since begun to recover, slowly, after the Ida-damaged Port Fourchon in Louisiana, the base of offshore oil and gas operations, reopened over the Labor Day weekend, but the bulk of it remains offline as power outages and other operational challenges persist. The shut-ins are exacerbating an already tight market, marked by record LNG exports, lackadaisical production growth, and a growing inventory deficit compared with year-ago and five-year average levels. Those underlying fundamentals will remain a trigger point for price spikes well after Ida-related shut-ins recover. Today, we discuss where the gas market stands heading into the final months of the injection season and the implications for winter gas pricing.

You wouldn’t know it from the $2.50-plus/MMBtu Henry Hub prompt natural gas futures prices in the past couple of months, but the U.S. gas market this injection season just barely managed to avoid a complete meltdown. Despite gas production volumes trailing year-ago levels all summer long, it wasn’t until the last month or two of the traditional injection season (April through October) that the market tightened enough to escape a major storage crunch. In reality, it took the multi-pronged effects of production cutbacks — in part from hurricane-related disruptions — higher LNG and pipeline exports, and cooler fall weather, to make that happen. Today, we review the U.S. natural gas supply/demand balance and implications for 2021.

U.S. Northeast natural gas production has tumbled nearly 900 MMcf/d in the past month alone since EQT Corp., Cabot Oil & Gas, and others began curtailments in response to low gas prices, and is averaging nearly 2 Bcf/d below last November’s peak of 32.9 Bcf/d. But regional gas demand has lagged this year, storage inventories have surpassed five-year highs and outbound flows to the Gulf Coast are being challenged by reduced takeaway capacity and drastically lower demand from LNG export facilities.  Today, we examine the net impact of these competing fundamental factors on the region’s supply-demand balance and the resulting implications for Appalachian supply prices.

While the crude oil market meltdown has taken center stage in recent weeks, and for good reason, the natural gas market is bracing for its own fallout. The CME/NYMEX Henry Hub April futures price, which was already at a multi-year low, buckled last week, falling to as low as $1.602/MMBtu on March 23, and expired Friday at $1.634/MMBtu, the lowest April expiration settle since 1995. On its first day in prompt position, the May futures contract yesterday eked out a late-day, 1.9-cent gain that brought it back up near $1.70/MMBtu as traders continued weighing competing market factors. Gas futures earlier in March were initially buoyed by the assumption that the low oil-price environment would slow associated gas production — and it will, eventually. But that initial bullish sentiment was quickly usurped by the more immediate effects of demand losses resulting from the economic slowdown caused by COVID-19, as well as from mild weather. Today, we look at how these developments are shaping gas supply-demand fundamentals heading into the gas storage injection season.