Canada’s natural gas exports — which have been pushed out of the supply-rich U.S. Northeast in recent years — are also facing challenges in Western U.S. markets. Growing supply from North Dakota’s Bakken Shale is increasingly competing for capacity on the same transportation routes as imports and is targeting the same downstream markets. Meanwhile, the rise of renewable energy in the West region from wind and solar farms is limiting gas demand in those target markets. What does that mean for imports from Canada? Today, we look at how these factors are affecting Canada’s exports to the Western U.S.
In 2017, the U.S. Northeast sent more natural gas to Canada than it received, making the region a net exporter for the first time on an annual average basis. That marks another milestone in the ongoing flow reversal happening in the Northeast, led by the growth of local gas supply from the Marcellus/Utica shales. For now, the region still relies on Canadian gas during the highest winter demand months, but imports from Canada in all the other months are increasingly unnecessary as Northeast gas production balloons further. Today, we look at evolving dynamics at the U.S.-Canadian border in the Northeast.
This winter will be the last go-round for ISO New England’s Winter Reliability Program, under which the electric-grid operator in the natural gas pipeline-challenged region provides financial incentives to dual-fuel power plants if they stockpile fuel oil or LNG as a backup fuel. This coming spring, a long-planned “pay-for-performance” regime will go into effect, and gas-fired generators that can’t meet their commitments to provide power during high-demand periods — such as the polar vortex cold snaps that hit the Northeast in early 2014 — will pay potentially significant penalties. Today, we discuss the pitfalls that the pipeline capacity-challenged region may encounter as its power sector becomes increasingly gas-dependent.
Several large-scale gas pipeline expansions targeting the New England and New York City markets have been sidelined in the past year, either due to insufficient financial backing or the challenges of regulatory rigmarole in the region. But in recent weeks, a couple of smaller-scale projects along existing rights-of-way have managed to cross the finish line, allowing incremental gas supplies to trickle into the region. The new pipeline capacity will provide natural gas utilities and power generators in the region with greater access to additional gas supplies from the nearby Marcellus Shale this winter. Today, we look at recent capacity additions and their potential impacts.
Marcellus/Utica natural gas production volumes this past Saturday (November 4) set a record high of more than 23 Bcf/d, according to pipeline flow data. As a result, overall Northeast production flows on the same day also posted a milestone, with volumes approaching a record 25.3 Bcf/d. This is up ~2.7 Bcf/d from where they started the year. These gains have been made possible because of the numerous pipeline projects that have added takeaway capacity from the region, about 2.4 Bcf/d since last winter alone. Moreover, another ~4.3 Bcf/d in new takeaway capacity either was approved for in-service last week or is expected online before March 2018. Even at partial utilization through the winter, that’s a lot of capacity that could flood the market with new supply. Where is all that capacity headed? In today’s blog, we look at recent and upcoming capacity additions that will affect the gas market this winter season.
Lower-48 natural gas production has climbed more than 4.0 Bcf/d in the past 10 months. While Marcellus/Utica activity continues to drive the bulk of the recent increases in total volumes, crude-focused basins, like the Permian and SCOOP/STACK plays, also are picking up steam as a new generation of oil rigs is deployed to the fields and vying for market share. In other words, production growth is no longer a one-man — uh, one-basin — show. Today, we look at what’s happening with gas production outside the Northeast.
For a time after crude oil prices crashed in 2014-15, the Marcellus/Utica Shale — and also the Permian Basin to some degree — had something of a monopoly on natural gas production growth in the Lower 48. With oil prices lagging behind $50/bbl, associated gas from crude-focused plays were either in decline or, at best, in a holding pattern. But now with crude above $50 and gas above $3.00/MMBtu, just about all the major basins — including Permian, SCOOP and STACK, even Haynesville — are growing again. Nearly all of the new supply is targeting the Gulf Coast, hoping to capture market share of burgeoning export demand from the region. But not all of that supply will be able to get to where the demand is, which means, supply competition for transportation capacity and demand is bound to heat up. Today, we wrap up a blog series on our U.S. gas supply and demand outlook, in particular how we see these dynamics will shake out over the next several years.
A year ago, Lower-48 natural gas production was in steep decline and averaging less than 71 Bcf/d by the fall, down from nearly 74 Bcf/d in February 2016. The oil-price crash of 2014 had taken a toll on gas output, led by a drop in Texas. To add to that, Marcellus/Utica gas supply — which had helped prop up overall domestic gas production volumes — was no longer growing enough to offset those losses. The resulting decline in Lower-48 production helped to correct a huge storage imbalance that had developed in the market following the brutally mild winter of 2015-16. That’s a far different picture than what’s happened in 2017. Gas production began this year below 70 Bcf/d, but has climbed to more than 74 Bcf/d in the past couple of months. And just last Thursday (October 26), production set a new record of 75.7 Bcf/d, exceeding the previous single-day record of 75.1 Bcf/d set in April 2015. Several of the major supply basins are contributing to that uptick, but Marcellus/Utica gas production is again leading the pack. Today, we check in on Northeast gas production using pipeline flow data.
Midstreamers in recent years have been in overdrive to de-bottleneck the Marcellus/Utica natural gas supply region as well as other growing gas supply basins and connect producers to where the demand is increasing. Significant transportation capacity has been added in recent years and much more is on the way. Constraints are starting to ease and producers are finding relief. But with production growing again, there are signs of potential new bottlenecks on the horizon. The RBN Growth Scenario estimates that Lower-48 gas production could increase to 92 Bcf/d by 2022. Demand is expected to grow too — primarily from exports — but no more (and potentially less) than supply in the same timeframe, leaving the market in a precarious equilibrium over the next five years. Thus, it will be all the more critical that incremental supply can access what new demand there will be. At the same time, demand growth will be concentrated in one geographic region — in the Gulf Coast states. In today’s blog, we explore the potential risks of overproduction as producers crank up drilling activity.
Energy Transfer Partners Rover Pipeline’s Mainline A first began flowing natural gas west from the Marcellus/Utica on September 1, and volumes are now averaging about 1.0 Bcf/d. The bulk of that is being delivered into TransCanada’s ANR Pipeline and, pipeline flow data shows some of that, either directly or indirectly, is making it all the way south to the Gulf Coast, specifically toward Cheniere Energy’s Sabine Pass LNG liquefaction and export facility (SPL). Deliveries to the facility have climbed to nearly 3.0 Bcf/d in recent weeks as the fourth liquefaction train was brought online. Along the way, the Rover-ANR combo is increasing competition with other pipes that feed ANR, including other Marcellus/Utica takeaway pipelines such as REX and Dominion. Today, we look at how Rover has changed flow patterns for gas targeting Gulf Coast demand.
With the addition of new natural gas pipeline capacity, and crude oil and natural gas prices stabilizing near $50/bbl and $3/MMBtu, respectively, Lower-48 natural gas production this year is on the rise again and expected to increase by another 18 Bcf/d over the next several years. Gas demand is growing too, but a big chunk of the incremental demand will come not from domestic consumption, but from exports via pipeline deliveries to Mexico and to overseas markets in the form of LNG. Both of these outlets require substantial infrastructure development and will take time to ramp up. Moreover, much of this new demand will be concentrated in one geographic area — along the Gulf Coast. In addition to the Marcellus/Utica Shale region, several other supply basins are growing too and will compete for this new demand. How will these dynamics affect the gas market balance over the next few years? Will demand come on fast enough, and will all that new supply be able to find its way to the Gulf Coast? Or, is the market setting itself up for more transportation constraints? In today’s blog, we look at how supply and demand shifts will shape the gas market balance over the next several years.
Available ethane in the Marcellus/Utica is expected to increase 70% by 2022 to 800 Mb/d, from about 470 Mb/d this year. That should be good news for the slew of ethane-only steam crackers coming online in that time frame, primarily along the Gulf Coast. But unfortunately, there is limited ethane pipeline takeaway capacity out of the region and today more than half of the potential ethane supply is being rejected into the natural gas pipeline stream. Without additional takeaway capacity, that rejected volume is expected to grow and few additional ethane barrels will make their way to the Gulf Coast. The question is, will transportation economics support additional pipeline development to where the demand is growing the most? Today, we will explore how the changing ethane market is likely to impact the Marcellus/Utica producing region.
Lower-48 natural gas production is expected to surge 18 Bcf/d (25%) by 2022 to 90 Bcf/d, up from an average near 72 Bcf/d this year. Gas demand is also on the rise, mostly from exports. The U.S. is expected to add 8.0 Bcf/d of new LNG export capacity in the next few years. At the same time, there is ample new pipeline capacity available for gas deliveries to Mexico from Texas, with more on the way, and gas-fired power generation demand is also expected to increase steadily. Will all this new demand be enough to absorb the incremental supply, and what will be the timing of it? In today’s blog, we continue our five-year outlook series, this time with a focus on the demand side of the equation.
The U.S. natural gas market tightened considerably in 2016, with a pull-back in production volumes leaving total gas supply, including imports, within a hair’s breadth of total demand (including exports) on an annual average basis. In 2017, however, gas production has climbed again. And it’s not just from the Marcellus/Utica, which grew through even the downturn over the past few years, but also from other basins, particularly ones focused on crude oil. Current production economics and drilling activity suggest continued growth over at least the next five years. Could it be too much? Will demand expand fast enough and will all the growing supply regions be able to access that demand? Or, are producers headed for another contraction before they’re barely out of the last one? In today’s blog, we begin a series unpacking RBN’s five-year natural gas supply-demand outlook.
As new ethane-only steam crackers come online and ethane exports accelerate, ethane demand is ramping up from 1.3 MMb/d today to somewhere between 2.1 and 2.3 MMb/d in 2022. The good news is that a lot of new ethane supply is becoming available — from high-Btu Permian associated gas, more gas from other oil-focused plays, and of course rapidly growing Marcellus/Utica production. Depending on what happens to oil and gas prices, somewhere between 2.5 and 3.2 MMb/d of “potential” ethane could be available by 2022 to meet that demand. So, no problem, right? Not so fast. Some of this potential ethane will be very expensive to get to market, and some won’t be able to get to market at all due to pipeline capacity constraints. How these market dynamics play out raises the possibility of wide swings in ethane prices. Today we will explore how this may play out.