The winter 2018-19 natural gas market was one of the most chaotic in recent memory, with the NYMEX Henry Hub futures contract last fall rocketing up to nearly $5/MMBtu in a matter of weeks, only to collapse in late 2018/early 2019 to an average $2.60 in January. The physical gas market also swung to extremes in recent months, setting both the highest ($200/MMBtu at the Sumas, WA, hub) and lowest (negative $9.00/MMBtu at the Waha hub) trades ever recorded in the U.S. These anomalies occurred amid steep supply growth from the Marcellus/Utica and Permian producing regions and rapidly advancing demand, particularly from burgeoning LNG exports along the Gulf Coast, while infrastructure scrambled to keep pace to bridge the two. And there’s more of that volatility ahead. Close to 5 Bcf/d more LNG export capacity is being added this year alone, and Lower-48 gas production is poised to continue growing. Today, we lay out our view of the recent volatility and the biggest factors shaping the gas market over the next five years, based on Rusty Braziel’s Backstage Pass Fundamental Webcast last week.
This past winter was one of records and extremes. Gas production continued to set new highs, topping 89 Bcf/d for the first time at the end of March and averaging just under 88 Bcf/d for the November-March period. Marcellus/Utica production growth slowed a bit in recent weeks, in part due to weather-related freeze-offs and some pipeline outages. But the increases before that were astronomical, with average volumes this winter (November through March) up by a whopping 9.5 Bcf/d from a year earlier — and, as we’ll get to later, we haven’t seen the last of it. Domestic demand also set records, led by the power sector. But, by far, the biggest movement on the demand side was in exports, which peaked at nearly 10.5 Bcf/d in mid-March, up 3.2 Bcf/d (or 40%) year-on-year, with the bulk of that increase coming from LNG exports, primarily from the Gulf Coast. At the 10.5-Bcf/d level, that’s about 12% of total Lower-48 gas production moving to export markets now.
The physical gas market clearly felt the effects of the rapidly shifting regional supply-demand balances and the infrastructure that’s straining to keep pace. On March 1, we saw day-ahead prices at the Sumas, WA, gas hub — a U.S.-Canada border-crossing point where Enbridge’s Westcoast Energy Pipeline (WEP) delivers Canadian gas to Williams’s Northwest Pipeline (NWPL) — run up to as high as $200/MMBtu in intraday trading and settle at $161/MMBtu — all-time highs for the U.S. gas market. As we detailed in Baby I Need Your (Gas), the Pacific Northwest has very few options to source gas supply, and two of those were compromised when the polar vortex descended at the end of February and spread sub-freezing temperatures across much of the U.S. WEP deliveries to Sumas were running at about 80% of normal for that time of year as the pipeline completed repairs and integrity testing following a rupture on October 9 (2018) that had initially sent those cross-border flows to zero. And to make matters worse, Jackson Prairie, the region’s largest gas storage facility, experienced compressor problems starting February 9, which severely limited its deliverability during the polar-vortex event.