After a major decontracting and partial recontracting last fall, Tallgrass Energy’s Rockies Express Pipeline headed into 2020 with 839 MMcf/d in firm, long-haul commitments for natural gas moving east out of the Rockies for delivery into the Midwest. That volume is down from 1.3-1.8 MMcf/d in firm commitments previously. The contracted volume is also much lower than the peak — and even the average — historical gas flows on the route to the Midwest markets in recent years. At the same time, Tallgrass’s Cheyenne Connector pipeline and Cheyenne Hub Enhancement projects are expected to bring as much as 800 MMcf/d of new firm gas supply from the Denver-Julesburg (D-J) Basin to the REX mainline at Cheyenne Hub. What will these changes mean for Rockies’ eastbound flows and prices? Today, we wrap up our series on REX’s recontracting with an assessment of how the recent contract changes could affect REX gas flows.
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For much of the time since it began operations, the capacity on Tallgrass Energy’s Rockies Express Pipeline has been contracted and utilized at high rates for long-haul flows east from the Rockies to the Midwest. Specifically, the pipeline consistently has had between 1.3 and 1.8 Bcf/d out of a total 1.8 Bcf/d contracted, mostly for 10-year terms. That all changed in the past year, however, as the original long-term shipper contracts that took effect in 2009 came due and the pipeline experienced a major decontracting, with the bulk of the contracts rolling off in November 2019. Since then, a number of open seasons led to a partial recontracting. Tallgrass also is developing two projects — Cheyenne Connector and REX Cheyenne Hub Enhancement — that could increase flows to REX later this year. Today, we continue a series providing an update on eastbound pipeline contracts and gas flows on REX.
After holding above $2/MMBtu in the first half of January, the CME/NYMEX February natural gas futures contract caved in this week, closing Tuesday and Wednesday at $1.895/MMBtu and $1.905/MMBtu, respectively. The last time we saw prices this low was in March 2016. But to see such levels trading in January, typically one of the coldest and highest-demand months of the year, you’d have to go back more than two decades — to 1999. Today, we explain the fundamentals behind the price collapse earlier this week and its implications for the 2020 gas market.
Tallgrass Energy’s Rockies Express Pipeline (REX) has been through a lot in its 10-plus years of operation. Since its first eastbound-only segments started moving natural gas out of the Rockies in 2008, flows on the pipeline have evolved due to market events, primarily the onset of the Shale Revolution, which has resulted in a surge of gas supplies in the Eastern U.S. and increasing gas-on-gas competition across North America. Rising to the challenge, REX has undergone a number of transformations to adapt to the shifting gas flow patterns and price relationships, including reversing flows on the eastern zone of the pipe to move gas west from Ohio. In 2019, REX was again put to the test, this time on the western end of the pipe, where the bulk of its legacy long-term contracts for eastbound flows out of the Rockies expired, with the last of them rolling off on November 11, 2019. Some of that has since been recontracted, and the in-service of the REX Cheyenne Hub Enhancement and Cheyenne Connector projects could further shore up REX mainline flows. Today, we begin a short series providing an update on REX’s eastbound gas flows and contract changes.
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.
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.
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.
There’s a tough race underway among U.S. LNG developers jockeying for position in the global LNG market. U.S. supply growth has spurred the development of more than two dozen LNG export projects, the bulk of them along the Texas/Louisiana Gulf Coast. But regulatory bottlenecks and deepening oversupply conditions in international markets are creating strong headwinds and slowing the momentum for some of these massive projects, making it harder and harder for them to reach the regulatory and commercial milestones they need to pass before they can progress to the construction phase. That said, several projects have eked out big wins in recent weeks, including Tellurian’s $7.5 billion memorandum of understanding with India’s Petronet LNG Ltd for its Driftwood LNG project, signed just this past weekend, and LNG Ltd.’s 2-MMtpa sales and purchase agreement for its Magnolia LNG, inked early last week. Today, we provide highlights of recent regulatory and commercial developments that are pacing the proposed export capacity additions.
2019 was supposed to be a milestone year for U.S. LNG exports. And to a degree, it has been. Natural gas pipeline deliveries to liquefaction and export terminals have peaked above 6.5 Bcf/d in the past couple of weeks and averaged about 6 Bcf/d for that period, up nearly 2 Bcf/d from where they started this year and more than twice where they stood at this time a year ago. But the growth has come haltingly as under-construction projects have faced a number of setbacks and delays. Moreover, the longer-term, “second-wave” export projects still in the early stages of development and looking to pass “go” are facing challenges of their own, including global oversupply and collapsed margins. Today, we begin a short series providing an update on where U.S. LNG export demand and new projects stand.
TC Energy’s Columbia Gas and Columbia Gulf natural gas transmission systems’ recent expansions out of the Northeast — the Mountaineer Xpress and Gulf Xpress projects, both completed in March — are responsible for a large portion of the uptick in Marcellus/Utica production in the last few months and they’ve added an incremental 860 MMcf/d of capacity for Appalachian gas supplies moving south to the Gulf Coast. The two projects join a number of other expansions in recent years that have inextricably tied Marcellus/Utica supply markets to attractive demand markets along the Texas and Louisiana coasts. Where is that latest surge of southbound supply ending up? Today, we look at the downstream impacts of the completed projects, namely on Louisiana gas flows and LNG feedgas deliveries.
U.S. Northeast natural gas producers in recent months got a substantial boost in pipeline capacity to receive and move incremental gas production volumes to attractive Gulf Coast markets. TC Energy’s Columbia Gas and Columbia Gulf transmission systems in March completed the Mountaineer Xpress and Gulf Xpress pipeline expansions, respectively, increasing the combined system’s Marcellus/Utica receipt capacity by 2.7 Bcf/d in the producing region, while also bumping up the Marcellus/Utica’s takeaway capacity to the Gulf Coast by nearly 900 MMcf/d. The duo of expansions is among the biggest takeaway capacity additions to be completed out of the Northeast, volume-wise, and among the handful that inextricably connect Marcellus/Utica supply markets to well-sought-after LNG exports markets along the Texas and Louisiana coasts. One of the export terminals these projects are designed to serve is Sempra’s Cameron LNG, where Train 1 began commercial operations in recent weeks. Today, we provide an update on the upstream and downstream implications of the recently installed Northeast-to-Gulf Coast pipeline capacity.
The battle between Bakken and Western Canadian natural gas supplies for the Chicago market seems to be advancing toward a final showdown of sorts. Associated gas production from the crude-focused Bakken has been rising sharply, but capacity on the Bakken’s two gas takeaway pipelines — Northern Border and Alliance, also utilized by Western Canadian Sedimentary Basin (WCSB) supplies — has been maxed out for a few years now. The result is that Bakken gas is increasingly encroaching on — and pushing back — imports from the WCSB. Bakken gas flows already overtook Canadian gas receipts on Northern Border a year ago. Since then, the gas-on-gas competition and the resulting pipeline constraints have escalated, and things are likely to get worse. Today, we break down the forces at play in the competition for market access.
After sustaining a record pace since March, natural gas storage injections have been slowing dramatically and are projected to fall below the 5-year-average rate over the next few weeks. While weather has factored heavily into the swing in storage activity, increased baseload demand for gas in the power sector has amplified the effects of weather anomalies and electricity demand seasonality on overall gas demand. As a result, gas demand volumes have diverged from historical levels on a temperature-adjusted basis. Today, we examine the changing historical relationships of power burn and storage injections to weather and electricity demand.