New U.S. liquefaction trains and LNG export terminals are entering an increasingly oversupplied global market in which international LNG prices are well below where they stood a year and a half ago and price spreads from the U.S. have collapsed. That hasn’t deterred U.S. LNG exports from increasing with each new liquefaction train and capacity contract that goes into effect, as long-term offtake contracts, which anchor more than 90% of the U.S. liquefaction capacity, have made cargo liftings relatively insensitive to global prices. However, the destinations for U.S.-sourced LNG have been in flux based on the types of offtakers holding capacity on newly commercialized trains as well as shifting global prices. Today, we continue a series on cargoes and destinations, this time focusing on how contracts impact cargo destinations.
The once unthinkable level of 100 Bcf/d for U.S. natural gas production is just around the corner, it would seem. Lower-48 gas production last week hit a new high of 96.4 Bcf/d, after surpassing 95 Bcf/d not too long ago (in late October). That’s remarkable considering that production was only 52 Bcf/d just 12 years ago. Gas demand from domestic consumption and exports this year has set plenty of records of its own, but the incremental demand has not been nearly enough to keep the storage inventory from building a significant surplus compared with last year. CME/NYMEX Henry Hub prompt gas futures prices tumbled nearly 40 cents last week to $2.28/MMBtu, the lowest November-traded settle since 2015. Today, we break down the supply-demand fundamentals behind this year’s bearish storage and price reality.
U.S. LNG export capacity has increased 40% in the last seven months, from 4.3 Bcf/d in April to about 6 Bcf/d now, and feedgas demand at the terminals already exceeds that, with more than 7 Bcf/d flowing to the facilities in recent weeks. With each new liquefaction train coming online, feedgas deliveries to export terminals have steadily climbed, and, for the most part, have sustained at rates that suggest consistently high utilization of the facilities’ capacity, particularly once they begin commercial operations and regardless of international market dynamics. And, that demand is expected to increase further as more liquefaction capacity comes online in 2020 and beyond. The emergence of this seemingly inelastic demand with a baseload-like pull on domestic gas supplies marks an underlying shift in the U.S. gas market that, along with the rising baseload demand from power generation, will make national benchmark Henry Hub prices more prone to spikes. Today, we explain how ever-increasing LNG exports will reshape the U.S. demand profile and, in turn, Henry price trends.
U.S. natural gas prices are increasingly susceptible to periodic spikes and volatility as baseload demand for gas — or the minimum level of demand that must be met on a daily basis — specifically from power generators and liquefaction plants, has rapidly climbed in recent years, and is still rising. The power sector has upped the ante on its gas consumption, with gas replacing coal as the most cost-effective go-to fuel for meeting baseload electricity demand. On top of that, feedgas deliveries to LNG export terminals have added 7 Bcf/d of demand to the gas market in the past three years, much of which is flowing at high, baseload-like rates, and that demand is set to increase further as more liquefaction projects are completed. These two market components together — LNG exports and gas-fired power generation — will take a bigger slice of domestic gas supplies, making the gas market ever more sensitive to weather, maintenance and other factors that disrupt that baseload level of demand or the supplies that serve it. We’ve already begun to see the effects of this phenomenon on Henry Hub and other regional gas prices. Today, we delve into this fundamental shift and what it could mean for the gas market.
Limited natural gas export options and persistently weak gas prices are not new phenomena in Western Canada. But market conditions in the past couple of years have become particularly untenable. Western Canadian Sedimentary Basin (WCSB) gas supply has ratcheted higher and shows signs of further growth, even as its share of export markets has been shrinking with the rise of U.S. shale gas. In-region oversupply conditions have worsened, creating transportation constraints further and further upstream in the WCSB, and prices at the regional benchmark AECO hub have seen historical lows as a result. To deal with this, and perhaps provide a long-term solution to weak natural gas prices, pipeline egress will have to expand again after a decade of decline and stagnation. New takeaway capacity is now starting to be developed. The question is, will it be enough? Today, we discuss highlights from our new Drill Down Report, which assesses the expanding gas pipeline options out of Western Canada, including when, where and how much takeaway capacity will be developed.
After a months-long regulatory delay, two Tallgrass Energy-led natural gas projects have progressed in the past month that will expand takeaway options out of the growing Denver-Julesburg (D-J) production area. Tallgrass in early October began construction on the Cheyenne Connector pipeline and the Rockies Express Pipeline’s Cheyenne Hub Enhancement — aimed at expanding outbound capacity and destination optionality for growing natural gas supplies from the Denver-Julesburg play in the Niobrara Shale, as well as providing a new outlet for Powder River Basin gas. The projects also have secured additional capacity commitments in recent weeks. And in its earnings call last week, Tallgrass said that DCP Midstream, which was already a shipper on Cheyenne Connector, has exercised its option to purchase 50% interest in the project. The influx of gas supply at Cheyenne Hub resulting from these projects will boost eastbound flows on Rockies Express (REX), which is in the midst of recontracting its capacity as existing long-term contracts roll off today. Next, we provide an update on the company’s plans to increase takeaway capacity out of the D-J basin and PRB.
A number of proposed liquefaction plants and LNG export terminals along the U.S. Gulf Coast are racing to secure regulatory approvals and line up sales and purchase agreements, all in the hope of reaching final investment decisions before their rivals. Yet, these Texas and Louisiana projects now face competition from a facility that would be sited more than 3,000 miles away, in the icy waters just off the North Slope of Alaska. Qilak LNG would use a “near-shore” liquefaction plant in the Beaufort Sea off Point Thomson, AK, to supercool the region’s nearby, abundant and now largely stranded supplies of natural gas, load the resulting LNG onto ice-breaking carriers, and use these carriers to make shuttle runs to and from LNG customers in Asia. Today, we review the Qilak LNG project and the economic and logistic rationales driving it.
New U.S. liquefaction trains and export terminals coming online are entering an increasingly oversupplied, lower-priced global market. Even so, domestic LNG exports have continued to climb with each new train that is commissioned and commercialized. Feedgas deliveries to the terminals hit an all-time high well above 7 Bcf/d this past week and have stayed up there the past several days. That’s because more than 90% of the operating or commissioning liquefaction capacity is underpinned by long-term Sales and Purchase Agreements (SPAs) that keep cargoes flowing. Planned facilities still under construction are contracted at a similar level, and we expect that to keep U.S. LNG exports on a growth trajectory that’s in line with the commissioning and construction schedules of new plants, to a large extent regardless of international price trends. Today, we continue a series on U.S. LNG export cargoes and destinations, this time with a focus on the existing capacity contracts for operational and commissioning terminals.
If it’s not one thing, it’s another in the Permian natural gas market. Just as it appeared that prices in the West Texas basin were finally turning a corner and strengthening with the full start-up of Kinder Morgan’s Gulf Coast Express Pipeline (GCX) late last month, various issues have again conspired to send daily Permian cash prices back down to near zero yet again. And it’s not just the daily spot markets that have come under pressure; forward prices were also severely discounted a few days ago when Kinder Morgan announced that the in-service date of its next long-haul pipeline from the region — the Permian Highway Pipeline project — would be delayed from late 2020 to early 2021. Keeping track of the roller-coaster ride of Permian gas prices and the drivers behind the highs and lows continues to keep heads spinning. Today, we explain the latest wild moves in the Permian natural gas market.
For some time now, natural gas producers in the Permian and the Eagle Ford have been counting on rising pipeline exports to Mexico to help absorb a lot of the incremental production in their plays. Their hopes have been bolstered in the past couple of years by the build-out of a number of new pipelines from the Waha and Agua Dulce gas hubs to the U.S.-Mexico border. Gas pipeline development south of the border hasn’t kept pace, though, mostly due to regulatory and construction delays. Also, a recent dispute over tariffs on a newly completed large-diameter pipeline, extending from the southern tip of Texas to key points along Mexico’s Gulf Coast, had left the pipe sitting empty this summer. That tiff has since been resolved and gas is flowing on the new pipeline, allowing those piped southbound exports to hit a daily record high near 5.9 Bcf/d earlier this month and average above 5.5 Bcf/d this month to date. Plus, progress is being made on other planned Mexican pipes too. This all leads us to ask, is the long-promised surge in U.S. gas exports to Mexico just around the corner? Today, we look at the latest developments regarding Mexico’s natural gas pipeline infrastructure additions.
The Western Canadian natural gas market remains a challenging environment from every angle: rising supplies, lack of available pipeline export capacity, and demand that can’t seem to rise fast enough. This has resulted in a price environment which, of late, has become the weakest in North America. The long-term solution to anemic prices and future supply growth is to increase pipeline export capacity from the region and ensure that demand continues to grow. We conclude this series today with a look at how forecasted supply and demand growth will stack up against planned export pipeline capacity additions to determine if the embattled region’s prospects can turn around in the next few years.
The Northeast natural gas market was supposed to have turned a new leaf. After years of pipeline takeaway constraints and constraint-driven prices, the region as of late 2018 had ample, even excess, takeaway capacity on its hands. Regional prices strengthened on both an absolute basis and relative to downstream markets, and Marcellus/Utica producers had room to grow. But bearish fundamentals have rattled the Northeast — and U.S. — market in recent months. In-region demand has lagged, even as production has set new highs. Since August, capacity reductions on Texas Eastern Transmission, a key Northeast takeaway route, have limited outflows. And, to top it off, Dominion’s Cove Point LNG went offline last month for an annual three-week-long maintenance, taking another 700 MMcf/d of demand out of the market for a time — it has since come back online, as of this past Monday. But regional prices in late September and early October were pummeled in the process, raising the question: are the Northeast’s takeaway constraints back? Today, we analyze the impacts of shoulder-season dynamics on regional storage and takeaway capacity utilization.
Despite pipeline takeaway constraints being relieved this year, Northeast natural gas prices have averaged lower than last year through much of the injection season. They’ve been especially weak in recent weeks, with spot prices at Appalachia’s Dominion South hub averaging $1.27/MMBtu in October to date, which is about half of where they stood this time in 2018 and the lowest in two years. And earlier this month, on October 4, regional prices went into apocalyptic territory, plunging 30-50% to less than $1/MMBtu — reminiscent of the deep discounts of recent years when Marcellus/Utica producers were operating under severe pipeline constraints. Prices rebounded the very next trading day, but they remain depressed relative to last year. Today, we look at the fundamentals behind the recent price weakness. Starting today, you can also tune into an audio version of the current day’s blog. Click here to find out how to subscribe or start listening by clicking on the play button above.
The CME/NYMEX prompt Henry Hub natural gas price yesterday settled at about $2.28/MMBtu, down 40 cents from the summer peak of $2.68 in mid-September. That’s also a long way down from the $3-plus prices seen at this time last year. What’s more, daily prompt-month contract settlements this injection season, from April to present, have averaged the lowest in over 20 years. This, despite the Lower-48 gas storage inventory starting the 2019 storage injection season in April well below year-ago and five-year-average levels. How did we get here? Today, we begin a short series breaking down the supply-demand fundamentals that brought the gas market to its knees in recent months.
With another month of anemic storage injections in September, Alberta natural gas storage levels remain on track to start the next heating season at a 13-year low. Still, while Alberta gas storage has been lagging well behind in terms of average injection rates and storage levels for many months now, forward winter contract prices for the Western Canadian gas price benchmark of AECO have budged only a little. There is potential for an improvement in storage injection rates during October after a recent regulatory approval affecting the Alberta gas pipeline system, but there is little time remaining in the current injection season to make much of a difference in inventory levels going into winter. Today, we conclude this two-part series with a look at why the AECO forward market remains largely unconcerned with low Alberta gas storage levels.