On June 1, Energy Transfer Partners’ new Rover Pipeline began service on its market segment from northwestern Ohio into southern Michigan, effectively sending nearly 800 MMcf/d of Marcellus/Utica gas production to Vector Pipeline and its northern destinations in Michigan, and, by extension, to the Dawn Hub. This latest in-service has already shuffled flows in the region and pushed back on other supplies targeting the same markets, including Canadian gas imports. And that’s even before the project has achieved its full expected capacity of 3.25 Bcf/d. Today, we analyze the early effects of Rover’s first flows to the Michigan/Dawn markets via Vector.
With natural gas production growth outpacing gas-demand growth in both the U.S. and Canada, gas producers in both countries are engaged in an increasingly fierce and costly fight for market share. Until recently, there were only skirmishes. For instance, when burgeoning Marcellus/Utica shale gas supplies lowered Northeast destination prices, TransCanada cut transportation rates on its mainline to help Western Canadian suppliers compete. When Northeast supply eventually exceeded Northeast demand on an annual basis, Canadian producers and shippers redirected more gas exports to the Midwest and West markets. But now, supply congestion on both sides of the U.S.-Canada border is worsening in every border region, to the point where options to maneuver into alternative markets are shrinking. This is war, folks — competition for U.S. gas market share between Canadian and U.S. producers is about to get much stiffer and the price discounts much deeper — deep enough to eventually price some production basins out of the market. Today, we discuss highlights from RBN’s new Drill Down Report on the subject.
For years, the U.S. Midwest has been a perennial net exporter of natural gas to Eastern Canada. But with Marcellus/Utica and Canadian gas supplies barraging the region, that’s changing. Less Midwest gas is flowing across the border into Ontario. At the same time, Canadian gas supply that used to serve U.S. Northeast demand is being displaced to the Midwest. That’s on top of Marcellus/Utica gas that’s physically moving to the Midwest via new capacity on the Rockies Express and Rover pipelines. The result is that the Midwest’s net exports to Canada are declining and even flipping into net imports during some summer months when the market is in storage injection mode. Thus far, this reshuffling of supply has occurred at the expense of Gulf and Midcontinent gas that historically has served the Midwest. But now there’s little of that left to displace from the Midwest, even as still more supply is expected to move there. Canadian producers are banking on capturing more of the Midwest market, as are Northeast producers via expansions like Rover’s Phase II and NEXUS. In other words, there’s a fierce battle brewing for Midwest market share. Today, we look at flow dynamics and factors affecting Canadian gas flows to the U.S. Midwest.
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.