For the first time in years, natural gas takeaway capacity constraints from the Marcellus/Utica producing region appear to be easing, even as production volumes from the area continue to record new highs. That’s allowed regional supply prices this year to strengthen dramatically relative to national benchmark Henry Hub. A closer look at pipeline flow data indicates these developments stem from shifting gas flows that coincide with the ramp-up of Energy Transfer Partners’ Rover Pipeline. In today’s blog, we continue our update of the Northeast gas market with the latest on Rover’s gas receipts, along with its effects on other regional takeaway capacity and price relationships.
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The Marcellus/Utica region is in the midst of a major turning point. Natural gas production from the region continues to post record highs. But regional basis differentials to Henry Hub are the strongest they’ve been at this time of year since 2013. Spot prices at Dominion South — the representative location for the overall Marcellus-Utica supply — averaged at a $0.35/MMBtu discount to Henry Hub this August, compared with a $1-plus discount to Henry in each of the past four years. The deep discounts in previous years reflected the inadequate takeaway capacity and the resulting pipeline constraints to get gas out of the region. Now, basis shifts suggest those constraints are easing somewhat — a trend that will redefine pricing relationships across the broader gas market. In today’s blog, we continue a series examining the changing flow and price dynamics in the Northeast gas market.
The U.S. Northeast’s reign on natural gas supply growth has factored heavily into broader U.S. gas supply-demand dynamics ever since the Marcellus/Utica shales burst onto the production scene. This year is no different. Lower-48 gas production in 2018 to date has averaged 8 Bcf/d higher year-on-year. Nearly 50% of that growth has come from the Northeast, and, what's more, the bulk of that incremental supply has flowed out of that region, flooding markets in neighboring areas. Now, the Marcellus/Utica is in the midst of yet another major inflection point. After years of perpetual pipeline constraints, pipeline utilization data indicates that some Northeast takeaway pipelines have a little bit of capacity to spare — a trend that has major implications for regional pricing relative to downstream markets. At the same time, more pipeline expansions are on the horizon that promise to bring on even more gas supply from Marcellus/Utica producers. (Just last Thursday, Energy Transfer’s Rover Pipeline was approved to begin service on two additional supply laterals — Majorsville and Burgettstown — and Williams’s Atlantic Sunrise expansion of Transco Pipeline is due for completion within weeks.) What does this new reality look like and what does it mean for the broader U.S. gas market? Today, we begin a short series providing our latest analysis of the Northeast gas market, starting with how it fits into the current U.S. supply-demand picture.
Natural gas production volumes from the Haynesville Shale have raced up over the past 18 months or so, from about 5.3 Bcf/d in December 2016 to more than 8 Bcf/d now. In fact, volumes are now just 1 Bcf/d or so shy of the all-time peak of 9.5 Bcf/d in January 2012. Despite the gains, there’s been a cloud of skepticism hanging over the play’s longer-term growth prospects — most of the recent gains have come from a relatively small footprint in the play’s western Louisiana sweet spot, and many of the surrounding areas are fraught with geological challenges, such as high water and clay content. But now the Haynesville story is changing once again, with a shift in rigs to the Texas side. How does this shift affect Haynesville’s growth prospects? Today, we provide an update of our view of the Haynesville Shale.
A perfect storm of hot weather, transportation constraints and limits on storage use recently sent natural gas prices in Southern California surging to the highest levels seen in that market going back to at least 2007. Spot prices at the SoCal Citygate hub averaged close to $40/MMBtu in late July and were again up over $20/MMBtu last week, levels that were several times higher than the national benchmark Henry Hub — and, for that matter, every other U.S. market hub — on the same day. Prices since then have retreated, but the whipsawing price action raises questions about what’s in store for SoCal this coming winter. Today, we analyze the factors behind the recent record prices and prospects for continued volatility at SoCal.
After idling near the 4.6-Bcf/d level for months, piped gas flows to Mexico raced to a record of more than 5 Bcf/d for the first time earlier in July, and have hung on to that level since. This new export volume signifies incremental demand for the U.S. gas market at a time when the domestic storage inventory is already approaching the five-year low. At the same time, it would also signify some much-needed relief for Permian producers hoping to avert disastrous takeaway constraints — that is, if the export growth is happening where it’s needed the most, from West Texas. However, that’s not exactly the case. What’s behind the sudden increase, where is it happening and what are the prospects for continued growth near-term? Today, we analyze the recent trends in exports to Mexico.
Despite intensifying competition from U.S. natural gas producers — or because of it — Western Canadian gas producers are ramping up their long-term commitments for intra-basin takeaway capacity from the Montney Shale, as well as for capacity at both intra-provincial and export delivery points. Not only has there been a slew of new project announcements in the region, but in some cases, commitments reportedly have exceeded proposed capacity during open seasons. Today, we provide an update of gas pipeline expansion projects in Western Canada.
Lower 48 dry gas production has climbed 3 Bcf/d since April to nearly 82 Bcf/d this month to date, which is an average ~9 Bcf/d — or 12% — higher year-on-year. Despite that meteoric rise in supply, the U.S. gas storage inventory, which started the injection season well below year-ago and five-year average levels, continues to carry a substantial deficit. That’s because record demand volumes thus far have managed to keep storage injections in check. Today, we provide an update of the demand factors affecting the 2018 gas injection season.
After treading near the 79-Bcf/d level this past spring, Lower 48 natural gas production surged about 1.5 Bcf/d higher in the last three weeks of June to record highs approaching 82 Bcf/d by month’s end. The supply gains suspended the market’s bullish view of the persistently large storage deficit compared with last year and the five-year average and reeled in the prompt CME/NYMEX Henry Hub futures contract from the $3/MMBtu mark — at least for now. Where did the gains occur and how much of that influx truly is new production versus volumes returning from seasonal maintenance? Today, we examine the drivers behind the recent production jump.
This spring, TransCanada launched service for its 230-MMcf/d Sundre Crossover expansion, increasing transportation capacity for moving Alberta natural gas production to the U.S. Pacific Northwest. That may seem like a trifling volume in the big scheme of the North American gas market. But considering that Canadian and U.S. producers already are locked in a heated battle for market share of U.S. demand and pipeline capacity, it’s enough for Canadian supply to gain ground. Since the Sundre in-service date, deliveries to the Kingsgate point at the British Columbia-Idaho border have ratcheted up to the highest levels in at least a decade. As a result, Canadian exports have managed to elbow out Rockies gas from the California market, and set off a ripple effect that’s pushing more gas east to the Midcontinent. Today, we examine the shifting gas flows in the West.
Crude oil and natural gas production in the Bakken are at record highs, and with the surge in production has come infrastructure constraints and higher rates of flared gas, renewing concerns about possible production shut-ins. As gas production volumes exceeded gas processing capacity, the flaring rate in April 2018 rose to 15% of total monthly volumes –– precisely the current limit set by North Dakota’s gas capture plan and three percentage points above the 12% cap due to kick in this November. Rig counts, producers’ drilling plans and $70/bbl crude oil prices all point to further production growth, which means that without additional processing capacity — or a change in the gas-capture policy — it will be increasingly difficult for producers and processors to comply. Today, we look at the latest developments in Bakken gas production, gas-related infrastructure and the gas capture policy.
As U.S. LNG exports play an increasing role in the global market, the U.S. will not only be exporting its vast natural gas supplies but also to a degree its market realities — namely, the risks, opportunities and, at times, volatility of a highly liquid, fungible and economically-driven spot market. The global LNG market also has shifted toward more flexible and spot-oriented trade, opening the window for some ad lib wheeling and dealing based on the prevailing economic conditions at any given time. These two factors together will come with significant implications across the supply chain — from the producing basins to the pipeline transport routes and from the export terminals to the destination markets they are serving. This month, with feedgas receipts at Sabine Pass LNG down and an explosion on a key supply route from Appalachia to Louisiana, we are starting to see how this integration of the U.S. and global markets is likely to play out. To help you keep up with this complicated dynamic and extrapolate the big-picture impacts, today we introduce RBN’s new LNG Voyager Report, featuring a comprehensive, pipe-to-port-to-destination approach to understanding how U.S. LNG fits into the global market.
An influx of natural gas supply in northern Louisiana — from Marcellus/Utica inflows and the rebound in Haynesville Shale production — is not only reversing long-held flow patterns but is also starting to fill up existing pipeline capacity on routes to the Southeast U.S. and the Louisiana Gulf Coast, where demand is growing. As more LNG export capacity comes online in the Bayou State, more gas will be needed at the coast, and, with existing routes to the coast filling up, more pipeline capacity will be needed as well. These factors are expected to transform the Louisiana gas market over the next several years, with impacts to prices, transportation values and basis, and with repercussions for both the U.S. gas market and global LNG trade. Today, we discuss highlights from our new Drill Down Report on the fast-changing Louisiana gas flow patterns and the need for more pipeline capacity.
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.
Gas producers in the Permian are facing the prospect of severe transportation constraints over the next year or so before additional gas takeaway capacity comes online. Left unchecked, continued production growth could send gas at Waha spiraling to devastatingly low prices for producers. However, there are a number of ways producers and other industry stakeholders could mitigate the growing supply congestion in West Texas, at least in part, and possibly dodge the proverbial bullet. The longer-term solution will come in the form of new pipeline capacity, which will shift vast amounts of Permian gas east to the Gulf Coast and potentially create a new problem — supply congestion and price weakness along the Gulf Coast, at least until sufficient export capacity is built there to absorb the excess gas. Today, we wrap up our Permian gas blog series, with our analysis of how these events will unfold, including an outlook for Waha basis.