withdrawal season

The Canadian natural gas market has exited the most recent heating season in reasonable shape. Storage withdrawals were below average thanks to mild winter temperatures, but overall storage levels at the end of the season were not too far out of line with the five-year average thanks to below-average storage levels in the west more than offsetting above-average storage levels in the east. However, Canadian gas storage may be facing a most unusual test this coming summer as storage injection activity will be influenced by reduced gas demand in the U.S. due to COVID-19 disruptions, as well as the potential for similar pandemic-driven weakness in homegrown demand, especially in Alberta’s gas-intensive oil sands. How the various pushes and pulls on gas flows play out this summer could very well determine if Canadian gas storage might test capacity limits this injection season. Today, we consider this possibility.

Just a month ago, the CME/NYMEX Henry Hub prompt natural gas futures contract was trading at a six-month high of $3.21/MMBtu (on November 10), and the U.S. gas storage inventory was at a three-year low, setting the stage for a bullish winter — assuming normal wintry weather. Since then, the prompt-month contract has tumbled about 50 cents to a settle of $2.715/MMBtu as of this Wednesday. In that time, temperatures fell across the country and seasonal demand for heating homes and businesses kicked in, and LNG exports ticked up slightly. But supply also grew by a lot, with natural gas production surging by 1.0 Bcf/d since then to a new record high of 76.9 Bcf/d just this past Monday. How did the fundamentals shake out in November, and what do current fundamentals mean for the balance of winter? Today, we reconcile these latest shifts in gas market fundamentals.

Three weeks ago, Hurricane Harvey threw a wrench in — well in a lot of things — but also into the natural gas market, curbing gas demand for power generation, curtailing pipeline exports to Mexico and stymying LNG exports. The market is still digesting the full impact of these disruptions and their potential effects on the gas market balance and storage. Adding to recent market shifts is the start-up of Energy Transfer Partners’ (ETP) Northeast-to-Midwest Rover Pipeline Phase 1A on September 1, which already is flowing 0.7 Bcf/d and lifting gas production out of Ohio. The market is hurtling towards winter, with just five weeks or so left until heating demand typically starts showing up and storage facilities officially begin to flip into withdrawal mode. What can recent supply and demand volumes tell us about what to expect from the gas market this winter? Today, we wrap up our most recent gas market update series with a forward look at potential scenarios for supply, demand and storage in the coming withdrawal season.

The CME/NYMEX Henry Hub January contract settled yesterday at $3.54/MMBtu, about 30.8 cents (~10%) above where the December contract expired ($3.232) and 77.6 cents (28%) higher than where November settled ($2.764). The natural gas winter withdrawal season is officially underway—it’s a lot colder and gas demand has spiked. But this week also marks another key bullish threshold: as today’s Energy Information Administration (EIA) storage report will likely show, the U.S. natural gas inventory has fallen below the prior year’s levels for the first time in two years (since early December 2014). That’s in sharp contrast to where the inventory started the injection season in April—more than 1,000 Bcf higher compared to April 2015. Moreover, we expect the emerging deficit to grow substantially over the next several weeks. Today we look at the supply-demand fundamentals driving this shift and what it means for the winter gas market.