Natural gas storage activity this spring suggested extremely bearish fundamentals. The market injected gas into storage at a record pace, well above year-ago and 5-year-average levels. The high injection rate was in part a result of demand loss as weather abruptly moderated in April and May. However, a look at injections on a weather-adjusted basis suggests there’s another dynamic at play — namely, that increased baseload demand for gas in the power sector amplified the effects of the mild weather this spring, lowering demand even more than temperatures alone would indicate. Moreover, that same dynamic could have an opposite, equally extreme effect during the hotter months when power generation is the primary driver of gas demand. Today, we look at the latest gas storage and demand trends, and what they can tell us about the balance of injection season.
Natural Gas
Persistent natural gas takeaway constraints out of the associated gas-rich Permian have pushed Waha Hub prices to between $1 and $9/MMBtu below the Henry Hub benchmark for most of 2019. Concerns about gas flaring have flared. Tanker trucks transporting diesel fuel to drilling and completion operations in West Texas and southeastern New Mexico are clogging the region’s roads. And diesel’s not cheap, especially if you’re using thousands of gallons of it a day. With Permian wells producing far more natural gas than takeaway pipelines can handle, and with gas essentially free for the taking, is this the year when electric fracs — hydraulic fracturing powered by very locally sourced gas — gain a foothold in the U.S.’s hottest shale play? Today, we look at the economic and other forces at play in the e-frac debate.
A raft of natural gas pipeline projects completed in the past couple of years has — for the first time — left room to spare on most takeaway routes out of the Northeast and provided Marcellus/Utica producers a reprieve from the all-too-familiar dynamic of capacity constraints and heavily discounted supply prices, even as regional production continues achieving new record highs. There’s on average close to 4 Bcf/d of unused exit capacity currently available — more in the winter when higher in-region demand means more of the production is consumed locally and less than that (but still more than in past years) in the spring, summer and fall seasons, when greater outbound flows are needed to help offset the relatively lower Northeast demand. But we’re expecting Northeast production to grow by another 8 Bcf/d or so over the next five years. And the list of projects designed to add more exit capacity has dwindled to just a few troubled ones that, even if built, wouldn’t be enough to absorb that much incremental supply. When can we expect constraints to re-emerge? Today, we conclude this series with a look at RBN’s natural gas production forecast for the Marcellus/Utica and how that correlates to the region’s pipeline takeaway capacity over the next five years.
Just two years ago, severe transportation constraints and steep price discounts were part and parcel of the Northeast natural gas market. Midstreamers were racing to add much-needed pipeline capacity out of the region, but not fast enough for producers. It was an inevitability that any pipeline expansions would instantaneously fill up. Gas production records were an almost monthly or weekly occurrence, and just as unrelenting were the takeaway constraints and pressure on the region’s supply prices. Not so today. Northeast gas production in June posted a record high, with the monthly average exceeding 31 Bcf/d for the first time. Yet, June spot prices at Dominion South, Appalachia’s representative supply hub, were the strongest they’ve been in six years relative to national benchmark Henry Hub. Why? The spate of pipeline expansions and additions in the past two years have not only caught up to production but capacity now far outpaces it, and consequently, producers now have something they haven’t had in a long time — optionality. Today, we break down how much spare capacity is available and its effect on regional pricing.
The Northeast gas market has come a long way since 2013, when it first began net exporting gas supply to the rest of the U.S. The past several years were marked by dozens of pipeline expansions to relieve takeaway constraints and to balance oversupply conditions in the region; as a result, takeaway capacity is finally outpacing production growth. How much spare capacity is there now, and how long will it be before production growth hits the capacity wall again? Today, we continue our series on Northeast gas takeaway capacity vs. production, this time examining the utilization of pipes in the Northeast-to-Gulf Coast corridor.
Permian midstream development activity has been happening at a rapid pace over the past few years, and we’ve featured many of those projects in the RBN blogosphere. One of the most aggressive players has been Salt Creek Midstream, which is in the midst of a big Permian buildout focusing on natural gas, crude oil, natural gas liquids and even produced water. Salt Creek isn’t only developing local midstream infrastructure; it’s also at work on long-haul solutions that will enable Permian producers to access markets along the Texas Gulf Coast — a wellhead-to-water strategy, you might call it. Helping Permian producers meet their needs to take away all three hydrocarbons plus produced water with integrated transport and pricing options is the key to Salt Creek’s effort. Today, we dive into the details of the company’s expansive Permian infrastructure development plan.
Permian gas marketers were likely breathing a sigh of relief earlier this month when news came that the developers behind the Whistler Pipeline had made a final investment decision (FID) to proceed with the new 2.0-Bcf/d link between the Permian and South Texas. The project provides a crucial link in the gas takeaway picture for the Permian and makes it less likely that gas pipeline capacity constraints in the future will result in the negative prices that are plaguing the present-day gas markets in West Texas. Combined with the two other Permian greenfield gas pipelines that have taken FID — Kinder Morgan’s Gulf Coast Express (GCX) and Permian Highway Pipeline (PHP) — there is now ~6 Bcf/d of incremental Permian supply pointed at the Texas Gulf Coast over the next two years. That’s great news for Permian producers, as well as demand centers along the coast, where tremendous growth in LNG exports is under way. Today, we detail the third natural gas pipeline being built from the Permian to the Texas Gulf Coast.
This much seems clear: natural gas demand along Texas’s Gulf Coast will be rising sharply, as will gas supply from the Permian and other inland plays to the coast. The catch is that, like clumsy dance partners, the increases in demand — mostly from new liquefaction/LNG export terminals and Mexico-bound gas pipelines — and the incremental supply to the coast via new, large-diameter pipes from the Permian are likely to be out of sync. That shifting imbalance, in turn, may well cause volatility in Houston Ship Channel gas prices as they relate to Henry Hub. In fact, we’re already seeing signs of what’s to come. Today, we continue our look at upcoming gas infrastructure expansions and their potential impact on the greater Texas Gulf Coast gas supply-demand balance.
Natural gas pipeline takeaway capacity additions out of the Northeast over the past year or two, along with suppressed gas production growth in recent months, have relieved years-long and severe constraints for moving Marcellus/Utica gas out of the region and even left some takeaway pipelines less than full. That, in turn, has supported Appalachian supply prices. Basis at the Dominion South hub in the first five months of 2019 averaged just $0.26/MMBtu below Henry Hub, compared with $0.46 below in the same period last year and nearly $1.00 below back in 2015, when constraints were the norm. Today, we continue our series providing an update on pipeline utilization out of the region, and how much spare capacity is left before constraints reemerge.
When it comes to Texas natural gas markets, the Permian has been getting much of the attention lately, with its rapid supply growth, limited pipeline takeaway capacity and sometimes negative prices. However, a wave of gas infrastructure development just starting to come online along the Texas Gulf Coast is set to steal some of the Permian’s spotlight over the next few months. Two large liquefaction/LNG export facilities are ramping up on the coast, as are the pipeline reversal projects designed to supply them. Also, three announced Permian-to-Gulf-Coast gas pipelines slated for completion over the next 24 months will move supply cross-state to destinations spanning the area from the Houston Ship Channel to the Agua Dulce Hub near Corpus Christi. That’s a lot of change ahead for these key Texas gas markets. Today, we turn our attention downstream of the Permian to the Houston Ship Channel market, including upcoming gas infrastructure expansions and their potential impact on the greater Texas Gulf Coast gas supply and demand balance.
Three months ago, the Pacific Northwest natural gas market recorded the highest trade in U.S. spot gas price history. The region at the time was dealing with extreme winter heating demand, a pipeline outage that limited access to gas supply and storage deliverability issues –– all of which were compounding constraints in the power markets. The result was a feeding frenzy that led gas prices to skyrocket to as much as $200/MMBtu at the Sumas, WA, hub on March 1. Fast forward to today — prices there have crumbled, falling to as low as $0.80/MMBtu in trading last week. Winter demand has dissipated, pipeline and storage constraints have eased, and the region is now dealing with an entirely different — even opposite — set of problems. Today, we take a closer look at the factors behind these latest price moves.
The Northeast natural gas market turned a new leaf in 2018, when takeaway pipeline capacity to move supply out of the Marcellus/Utica producing region finally caught up to — and even began outpacing — production growth. More than 4 Bcf/d of takeaway expansions entered service in 2018. Prices at the region’s Dominion South supply hub improved relative to Henry Hub and other downstream markets. And for the first time in years, Appalachian gas producers and marketers caught a glimpse of what an unconstrained, balanced market driven by market economics (as opposed to transportation constraints) could look like. 2019 will be the first full year of operation for many of those takeaway expansions that came online in 2018. Northeast production growth flattened through the first few months of 2019, but has ticked up in the past couple of months, albeit modestly, and the slate of future takeaway expansion projects has shrunk to just a couple stalled projects. Where does that leave capacity utilization out of the region this summer, and how long will it be before production growth hits the capacity wall again? Today, we begin a series providing an update on the Northeast gas market and prospects for balancing takeaway capacity with production growth.
There’s never a dull moment in the Permian gas market these days, as prices at the major trading hubs remain extremely volatile, fueled by insufficient natural gas pipeline takeaway capacity. After prices tumbled to fresh lows in late April, with the Waha hub trading as much as $9/MMBtu below zero, the market appeared to regain its footing somewhat in early May as production curtailments lifted prices above zero. However, that reprieve was short-lived; prices last week again fell into negative territory heading into Memorial Day weekend. That said, the possibility of new takeaway capacity materializing in the weeks ahead, earlier than expected, has renewed hope among some market participants that the Permian gas price woes will soon be a thing of the past. How likely is that really, and will it be enough to equalize the beleaguered market? Today, we look at potential near-term developments that could support Permian gas prices.
While it’s widely known that Canada’s natural gas prices and exports have been under increasing pressure from rising gas supplies in the U.S., forcing an ever-deeper discount for AECO — Canada’s primary gas price benchmark — versus U.S. benchmark gas prices, a homegrown development is making the situation worse. Growing unconventional gas supplies from the Montney and related plays in Western Canada are bumping up against insufficient pipeline takeaway capacity from this producing region. Will Canadian gas markets be able to adapt to all of these growing supplies on both sides of the border or simply wither away as U.S. supplies take more and more market share? Today, we kick off a multi-part series examining the highly complex problems facing Western Canadian gas producers.
Permian natural gas prices have been on a wild ride lately, trading more than $5/MMBtu below zero in early April before recovering to just above zero over the last few weeks. It’s hardly a secret that the Permian’s gas market woes have been the direct result of production exceeding pipeline capacity. That situation is set to change in a few months, when Kinder Morgan starts up its 1.98-Bcf/d Gulf Coast Express Pipeline, providing much needed new takeaway capacity. And that’s not all GCX will do. Its start-up will shift huge volumes of gas toward the Texas Gulf Coast that currently flow out of the Permian to other markets, likely causing a ripple effect across more than just the West Texas gas market. Today, we look at how Kinder Morgan’s new gas pipeline will redirect significant volumes of Permian gas currently flowing north to the Midcontinent.