Though crude oil prices have been rebounding lately, this spring’s price crash sent shockwaves through the U.S. midstream industry, which not too long ago had emerged from a decade of massive infrastructure investment in response to unprecedented upstream production growth. Just as midstreamers were looking forward to steady earnings growth, waves of huge capex cuts and well shut-ins by producers shattered forecasts and shifted strategic instincts toward survival instead of growth. Every company is different, of course, but a lot can be learned by examining a single firm in detail to see how it will fare in the current market environment, given its particular set of assets and arrangements. Take Targa Resources. An analysis of its performance provides insights into the outlook for integrated natural gas and NGL assets, especially in the Permian Basin, as well as the value of forming joint ventures. Today, we preview our Spotlight report on Targa.
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Daily energy Posts
The Canadian natural gas market has exited the most recent heating season in reasonable shape. Storage withdrawals were below average thanks to mild winter temperatures, but overall storage levels at the end of the season were not too far out of line with the five-year average thanks to below-average storage levels in the west more than offsetting above-average storage levels in the east. However, Canadian gas storage may be facing a most unusual test this coming summer as storage injection activity will be influenced by reduced gas demand in the U.S. due to COVID-19 disruptions, as well as the potential for similar pandemic-driven weakness in homegrown demand, especially in Alberta’s gas-intensive oil sands. How the various pushes and pulls on gas flows play out this summer could very well determine if Canadian gas storage might test capacity limits this injection season. Today, we consider this possibility.
The U.S. natural gas market has been on edge as it awaits more clarity on the extent of the demand destruction that could transpire, both from COVID-related commercial and industrial closures and potential disruptions to U.S. LNG export activity from demand losses downstream, particularly in Europe and Asia. The CME/NYMEX Henry Hub prompt contract last week set at all-time lows for April trading — twice — before gaining ground again this week as forecasts turned decidedly more bullish for April. But the market remains under pressure, as it heads into the storage injection season with an inventory that’s well above the year-ago and five-year average levels. With the economic slowdown likely persisting, in the U.S. and globally, in the coming weeks and months, the question is, could potential demand loss send the inventory barreling toward record-high, or even capacity-testing, levels by this fall? How much demand loss would it take for that to happen? Today, we assess the potential impacts of domestic demand loss and possible LNG cargo cancellations on the U.S. gas market.
While the crude oil market meltdown has taken center stage in recent weeks, and for good reason, the natural gas market is bracing for its own fallout. The CME/NYMEX Henry Hub April futures price, which was already at a multi-year low, buckled last week, falling to as low as $1.602/MMBtu on March 23, and expired Friday at $1.634/MMBtu, the lowest April expiration settle since 1995. On its first day in prompt position, the May futures contract yesterday eked out a late-day, 1.9-cent gain that brought it back up near $1.70/MMBtu as traders continued weighing competing market factors. Gas futures earlier in March were initially buoyed by the assumption that the low oil-price environment would slow associated gas production — and it will, eventually. But that initial bullish sentiment was quickly usurped by the more immediate effects of demand losses resulting from the economic slowdown caused by COVID-19, as well as from mild weather. Today, we look at how these developments are shaping gas supply-demand fundamentals heading into the gas storage injection season.
The natural gas market dynamics that were expected to turn gas flow patterns and price relationships in the Eastern U.S. on their heads and, in turn, transform supply-demand dynamics in Louisiana — including around the U.S. price benchmark Henry Hub — have come to fruition. LNG exports have surged as new liquefaction and export terminals have come online, injecting a new demand source along the Louisiana coastline. Producers have lined up to serve that demand. And midstreamers have worked to get the gas there, reversing and expanding existing northbound pipelines to move gas south into and through the Bayou State. Now, Louisiana’s gas market is nearing a critical juncture: the pipelines that connect the supply gateways in northern Louisiana to the demand centers along the Gulf Coast are nearing saturation. Today, we begin a series providing an update on Louisiana’s gas pipeline constraints and the projects lining up to alleviate them.
New U.S. liquefaction trains and export terminals have added LNG to an oversupplied global market. International gas prices are at their lowest levels in several years, price spreads between the U.S. and destination markets have collapsed and — to make matters even worse — a coronavirus pandemic threatens to undermine LNG demand growth. U.S. LNG exports nevertheless have been increasing with each new liquefaction train that comes onstream, though, mostly because their long-term offtake contracts make cargo liftings relatively insensitive to global prices. The question is, will dire global market conditions somehow undo U.S. LNG production growth? Today, we discuss highlights from our new Drill Down Report on the future of U.S. LNG exports.
Unlike most natural gas producing jurisdictions in North America facing a pullback in drilling and capital spending, producers in Western Canada appear to be doing the opposite and lining up for a year of rising production, higher average prices and additional pipeline capacity from producing basins. In short, 2020 should be a year in which supplies in the region mount a comeback after the dismal down year for supplies — and prices — that characterized 2019. A good part of that supply and pipeline capacity growth optimism has to do with a major pipeline expansion out of the Montney Basin in northeastern British Columbia that just recently entered service. Dubbed the North Montney Mainline and operated by Canada’s largest gas pipeline company, TC Energy, this vital piece of new pipeline egress from one of the most prolific unconventional gas basins in North America is setting up Western Canadian gas supplies for recovery in 2020 and beyond. Today, we continue our series with a look at what this may portend for gas supplies this year.
Given that Permian natural gas prices are once again hovering under $0.50/MMBtu, Texas’s other gas markets get little attention these days. That doesn’t mean that major shifts in the Lone Star State’s natural gas supply and demand markets aren’t occurring outside of West Texas, however. In fact, it’s quite the contrary, particularly when it comes to the Houston Ship Channel gas market. There, major changes — new gas pipelines, pipeline reversals and new LNG trains — continue to influence flows and prices. Today, we provide an update on the latest in gas infrastructure changes along the Texas coast and their potential impacts on the region’s supply and demand balance.
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.
Natural gas supplies in Western Canada fell into a hole in 2019, registering their first decline in a half-dozen years. That drop was led by a supply pullback on TC Energy’s Nova Gas Transmission Limited (NGTL) system, the largest gas pipeline network in the region, as producers grappled with widespread pipeline maintenance, shrinking budgets, and wellhead shut-ins due to ultra-low prices, especially during the summer months. That supply hole is going to be fixed in the months ahead, thanks to a major pipeline expansion — the North Montney Mainline — that recently entered service with a direct connection into the NGTL system. With this new pipeline tapping deeper into the vast Montney formation in northeastern British Columbia, gas supplies are showing signs of pushing higher, and more upside is expected in the months ahead. Today, we examine the new pipe and what it means for gas supplies on NGTL.
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.
The development of Appalachia’s Marcellus and Utica shales has flipped regional natural gas prices in the U.S. Northeast from their long-time premiums to Henry Hub, to trading at a significant discount and, in the process, reversed inbound gas flows, including from Eastern Canada. But there is an exception: from an entry point at the northern edge of New York, the Iroquois Gas Transmission pipeline is still importing Canadian gas supply nearly year-round to help meet local demand, despite its proximity to Marcellus/Utica production via other Northeast pipelines. This has kept prices along the Iroquois pipeline system at a premium to the other points in the region. And with the new, 1,100-MW Cricket Valley Energy Center power plant due online this spring, Iroquois prices are likely to strengthen. Today, we examine the dynamics driving Iroquois prices and gas flows.
When it comes to Texas natural gas markets, the Permian tends to steal the show. With its roughly 2 Bcf/d of annual production growth, constrained pipelines and absurdly cheap — sometimes even negative — pricing, it’s hard for the other gas hubs in the Lone Star State to garner much attention. However, the myopic focus on West Texas overlooks a noteworthy gas market shake-up taking place on the Texas Gulf Coast, where most of the Permian’s incremental gas production is headed and where multiple new liquefied natural gas facilities are coming online to move the new supplies into world markets. Also, new export pipelines are moving increasing volumes south of the border to Mexico. Today, we provide an update on the latest in Texas Gulf Coast gas infrastructure changes and their potential impacts on the region’s supply and demand balance.
The rapid increase of natural gas processing capacity in the Bakken in recent months has helped to ease producers’ growing pains, clearing the way for more crude oil and associated gas to be produced there and more Bakken gas to flow into the Midwest. That good news is countered, however, by bad news for Western Canadian gas producers, whose long-standing pipeline takeaway constraints only worsen as more Bakken gas flows into the Northern Border pipeline that cuts through North Dakota on its way to Chicago and other downstream markets. Today, we continue our series on the fight between Bakken and Western Canadian producers for space on Northern Border with a look at incremental flows into that key pipe.
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.
Canadian oil and natural gas producers were dancing very much to the same tune as their U.S. counterparts in 2019: reduce capital spending, live within cash flow and improve returns to investors. The only major difference for Canadian gas producers is that they were forced to dance even faster due to abysmal natural gas pricing during the summer of 2019, which cast a very negative pall over the whole sector for the remainder of last year. Although the focus on spending restraint, cash flow and returns has not changed for these producers upon entering 2020, there are encouraging signals that Canadian gas pricing will be materially improved this year, especially during the summer months, supporting higher cash flows and a cautious expansion in capital spending. Today, we examine the drivers behind what might increase capital spending by gas producers and lead to an increase in supplies.