November 1, 2017 | By Warren Waite
The U.S. natural gas market is well poised to handle whatever Old Man Winter throws its way for the winter 2017-18 heating season. Current dry gas production is hovering at record highs near 75 billion cubic feet per day (Bcf/d) and storage inventory levels are at 3,710 Bcf for week ending Oct. 20, 2017, or 189 Bcf less than last year and 46 Bcf below the five-year average. This combination leaves the market well equipped to meet the lofty demand needs of the coming winter (November – March).
With summer 2017 (April-October) now in the record books, a quick recap of this past season’s activity is valuable as it helps establish where PointLogic expects the market to head this winter and beyond. This is important since PointLogic foresees numerous record breaking events unfolding in the coming months—despite the assumption of normal weather in our forecasts.
Last spring, PointLogic forecast total lower 48 supply for summer 2017 to ring in at 76.9 Bcf/d and total demand to average 69.0 Bcf/d with a storage carryout of 3,753 Bcf. Based on estimates through Oct. 31, that forecast ended up short by 0.2 Bcf/d on a seasonal basis. Inventories in the ground ahead of this winter are expected to instead hit 3,796 Bcf due to a more robust response in production than anticipated and an offsetting effect from stronger gas-fired power generation.
In general, summer-on-summer production grew by 1.0 Bcf/d due to several reasons: the continued surge in Northeast production resulting from newly minted infrastructure; associated gas gains from the Permian; and a slowdown in the decline rates from other plays. For more on this phenomenon see The Stealth Big Production Turn Around and Rise and Shine; Northeast Outflows Carry Forward.
With overall supply increasing this past summer, the lack of gas-fired power generation added roughly 1.9 Bcf/d of additional market length. Back in July, we took A Closer Look at Summer 2017 Power Demand and explored the impacts of mild weather, price and competition from coal. Power demand is sensitive to price, weather and competing fuels used in the generation of electricity.
In the end, total U.S. population weighted degree days totaled 1,120 for summer 2017, or 115 degree days less than summer 2016 and 56 degree days more than the five-year average. Likewise, as a high level barometer, Henry Hub cash prices were $2.97/MMBtu, or 43 cents above last year and 20 cents below the five-year average.
With domestic gas consumption declining summer-on-summer, exports rose significantly with pipeline exports to Mexico up 0.3 Bcf/d to average 4.2 Bcf/d and LNG exports (all from Sabine Pass) averaging 2.1 Bcf/d, a 1.6 Bcf/d summer-on-summer increase. Sabine Pass is currently operating four liquefaction trains whereas by the end of summer 2016 there were only two. Feed gas deliveries into Sabine Pass averaged 2.1 Bcf/d during summer 2017, inclusive of maintenance periods and a stint of reduced activity in the aftermath of Hurricane Harvey. In the latter half of October, demand at Sabine Pass surpassed 3.0 Bcf/d on ten days.
Based on the above, the implied market balance for summer 2017 is 1.4 Bcf/d longer than last year. Moreover, when doing the same analysis and comparing market conditions against the prior five-year average, a similar theme persists. Total supply remains elevated, yet total demand is actually a bit higher. Over time, the increased utilization and build-out of gas-fired power plants has trended to facilitate greater and greater power demand. Thus, summer 2017 power demand is greater than the prior five year (2012-2016) summer average.
Transitioning into a Net Exporter
One of the key fundamental differences that began to take shape this past summer is the lower 48’s transition from net importer status to that of a net exporter. This is defined as taking the net imports from Canada and subtracting out pipeline exports to Mexico and liquefied natural gas (LNG) headed overseas. Even though the U.S. became a net exporter for the first time on a monthly average basis back in November 2016 (a low demand month) the U.S. wasn’t consistently a net exporter on a monthly basis until February 2017 and has remained that way ever since.
On a seasonal basis, the contiguous U.S. was a net importer of 1.6 Bcf/d back in the summer of 2016, then averaged 0.1 Bcf/d of net imports during the winter 2016-17 season. Summer 2017 averaged 0.6 Bcf/d of net exports.
Winter 2017-18 will be the first winter period ever where the gas market exports more gas than what is imported, averaging 0.6 Bcf/d, according to PointLogic Energy’s Two Season Balanced Supply and Demand Forecast. As additional pipeline gas is sent to Mexico and the addition of LNG exports at Cove Point, Elba Island, Freeport and Cameron LNG terminals, net exports could average 2.6 Bcf/d by winter 2018-19.
Demand to Reach Higher Heights
Looking ahead at winter 2017-18, total demand is poised to reach new heights, surpassing seasonal demand levels of the past. In fact, total domestic demand plus exports, or total demand, is forecast to average 97.1 Bcf/d, which is greater than total demand of the polar vortex winters that occurred in 2013-14 and 2014-15.
Domestic demand for winter 2017-18 is forecast to average 90.0 Bcf/d, which is the sum of power burn, industrial, residential and commercial load plus pipeline and fuel loss. Note, this forecast assumes normal weather and that domestic demand is actually less than domestic demand from the polar vortex winters a few years ago. However, normal weather assumption lift domestic demand above the two back-to-back mild winters of 2015-16 and 2016-17. As previously mentioned, it is the growth in export demand, primarily LNG, which is lifting total demand to higher heights.
Of course, if actual weather turns out to be colder or warmer than normal then that will impact our forecasts in numerous ways, with the largest impact weighing on residential and commercial demand.
Production Primed and at the Ready
Following a prolonged production rut throughout 2016 (a result from reduced capital investments and a pullback in new drilling post oil price collapse) production began to march upwards over the course of summer 2017, averaging 72.8 Bcf/d and an increase of 2.1 Bcf/d over winter 2016-17.
Summer 2017 also endured a very active hurricane season, which hindered Texas, Southeast and Gulf of Mexico production during key periods in August and September. Once fully recovered and in combination of the start-up of several key Northeast infrastructure projects, October production maintained an average of 74.0 Bcf/d. During the last week of October, daily production averaged 75.6 Bcf/d from a short-term demand inspired production pop in captive portions of the Northeast and associated gas gains from the Permian Basin.
Looking ahead to this winter, PointLogic forecasts production to average 76.2 Bcf/d and come close to 78.0 Bcf/d by March 2018. Keep in mind production is currently a few ticks above 75.0 Bcf/d, so the height of the production mountain to climb isn’t as steep. Again, this feat can be reached by continued growth within the Marcellus and Utica Shales along with support from the Permian, Haynesville and others.
How cold winter 2017-18 ends up being no one knows. Barring an extremely mild winter, it is likely that numerous record highs will be set: total demand, inclusive of record high exports; gas production; and for the first time ever the U.S. gas market will maintain a net exporter status for an entire winter season. If our forecast comes to fruition, the market should exit winter with roughly 1,700 Bcf of storage in the ground, or near the five-year average.
Stay tuned to future Get the Point postings as winter evolves and new dynamics unfold.
Join PointLogic on November 16-17 in Houston for our Natural Gas Next: 2018 and Beyond workshop where we will be providing detailed regional deep dives and an update of our analysis and forecasts.