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.
With natural gas prices reaching levels not seen in seven years, Western Canada is doing all it can to help increase gas supply, with recent data showing monthly production hitting multi-year highs. Moreover, Canadian forward gas prices are at the highest levels since 2014, gas pipeline expansions are in place or being constructed to accommodate future supply expansion, and gas-focused drilling activity remains strong — all of which may as well be a prescription for sending gas production to record levels later this year and in 2022. In today’s RBN blog, we provide an update on the recent gas production growth in Alberta and neighboring provinces and why more growth is coming.
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.
Northeast natural gas production in 2021 to date has averaged 34 Bcf/d, up 1.4 Bcf/d year-on-year, and the higher gas price environment currently is signaling more upside to production in the years to come. At the same time, downstream feedgas demand from LNG export facilities is at a record high and also headed higher as more liquefaction capacity is set to come online in the coming months. So, despite lower-than-normal inventory levels in the Northeast, outflows from the Appalachian basin have soared to new highs this year, and utilization of outbound pipeline capacity is up to an average 90%, a level we haven’t seen since the 2016-17 timeframe. Unlike 2016-17, when there was a slew of major pipeline projects to expand egress, now there are just two or three at most — and two of those are greenfield projects that face an uncertain future. As such, spare exit capacity is getting increasingly sparse, and Appalachian producers are bound to hit the capacity “wall” in the next two years. When will the Northeast run out of exit capacity and how bad could constraints get? Today, we provide highlights from our new Drill Down report, which brings together our latest analysis on Northeast gas takeaway capacity and flows.
It’s been a while since the Appalachian natural gas market has looked this bullish. Outright cash prices at the Eastern Gas South hub are at multi-year highs. Regional storage inventories are sitting low, setting the stage for supply shortages and still higher prices this winter. But the potential for severe takeaway constraints and basis meltdowns are lurking, and by next year, they could become regular features of the market again like they were in the 2016-17 timeframe, or worse — at least in the spring and fall when Northeast demand is lowest. Regional gas production is still being affected by maintenance and has been somewhat volatile lately as a result, but it averaged 34.5 Bcf/d in June, just 300 MMcf/d shy of the December 2020 record. What’s more, at current forward curve prices, supply output could surpass previous highs by next spring and grow by ~ 5 Bcf/d (15%) by 2023. Outbound flows set their own record highs this spring, running at over 90% of takeaway capacity, and will head higher, which means that spare exit capacity for supply needing to leave the region is shrinking. The handful of planned takeaway expansions that remain are facing environmental pushback and permitting delays, and the few that are targeting completion in the next year may not be enough. Today, we provide the highlights of the latest forecast from our new NATGAS Appalachia report.
Outbound natural gas flows from Appalachia over the weekend hit a new record high of 17.3 Bcf/d and averaged 16.7 Bcf/d for April — an all-time high for any month. That’s despite pipeline maintenance season being well underway last month and intermittently curtailing production and outflow capacity. Utilization rates of takeaway pipelines from the region are soaring above 90%, with little more than 1 Bcf/d of spare exit capacity for outflows of surplus Northeast production. Whether that will be enough to stave off severe constraints and discounted pricing in Appalachia in what’s left of the spring season, and again in the fall will depend on how much surplus gas is left after meeting in-region consumption and storage refill requirements. What happens when seasonal demand declines occur in May and June? In today’s blog, we wrap up our analysis of current outbound capacity utilization and where that leaves the Northeast gas market this spring.
This time last year, Appalachian natural gas production was approaching a steep springtime ledge as regional prices sank below economic levels and producers responded with real-time shut-ins. This year to date, regional gas prices have averaged $0.80-$0.90/MMBtu above 2020 levels for the same period, and production has been averaging more than 1 Bcf/d above year-ago levels. If production holds steady near current levels, the year-on-year gains would just about double to ~2 Bcf/d by mid-May, which is when the bulk of the springtime curtailments first took effect in 2020. This, just as Northeast demand takes its seasonal spring plunge, which means regional outflows are poised to rise in the coming weeks, potentially to record levels. How much more can the Appalachian takeaway pipelines absorb? In today’s blog, we continue our analysis of outbound capacity utilization, this time focusing on the routes to the Midwest.
Natural gas pipeline takeaway constraints out of the Northeast worsened in 2020 despite producer cutbacks in the region as high storage levels and weaker demand led to record volumes of Appalachian gas supplies needing to find outlets in other regions last fall. This year, storage levels are lower and could absorb more of the surpluses during injection season. However, Appalachian gas production so far in 2021 has been averaging higher than last year; and, gas prices are higher year-on-year, reducing prospects for the kinds of producer curtailments we saw last year. As for the “pull” from downstream demand, LNG exports along the Gulf Coast aren’t expected to experience the slump from cargo cancellations seen last summer. In other words, Appalachia’s outbound flows are likely to be robust, setting the stage for takeaway constraints and weak prices, particularly during the spring and fall shoulder seasons. How much outbound capacity currently exists and how much room is there for growth? Today, we continue our series on the Northeast gas market with an update on Appalachia’s southbound takeaway capacity and outflows, starting with a detailed look at the gas moving to the Southeast and to the Gulf Coast.
