It’s been a year since Hurricane Harvey made landfall and devastated the Texas Gulf Coast, and the Atlantic Basin is once again entering peak hurricane season. Among the widespread and prolonged effects of Harvey was the disruption of refinery and refined product pipeline capacity along the Gulf Coast, which then reverberated in downstream markets across Texas, and the U.S. East Coast and Midwest regions. As such, a closer look at Harvey’s timeline provides key insights into the importance of Gulf Coast refineries to the broader U.S. market. Today, we continue our series on Gulf Coast refining and pipeline infrastructure, and how a natural disaster along the coast can impact the rest of the country.
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.
It seems like everyone wants production out of the Permian these days — at least everyone who works for a pipeline company. The addition of five major greenfield crude oil pipes plus a host of expansion projects could bring Permian takeaway capacity up to 8.0 MMb/d from only 3.3 MMb/d today, with almost all of the incremental barrels destined for export markets. It’s a similar story for natural gas, with seven new pipes in the works to bring 2.0 Bcf/d each to Corpus Christi, Houston, or Louisiana, again with most of the molecules targeting exports. Not to be left behind, at least 27 new Permian gas processing plants are in development, and five new pipeline projects could bring 1.6 MMb/d of y-grade NGLs to the Gulf Coast. It’s a darned good thing that everyone in the global energy markets wants all that Permian production, right? What will this mean for the Permian and, for that matter, for the rest of the U.S. and the world? The only way to answer that question is to get the major players together under one roof and figure it out. That’s the plan for PermiCon 2018. Warning! Today’s blog is a not-so-subliminal advertorial for our upcoming conference.
On August 25, 2017, Hurricane Harvey made landfall as a Category 4 hurricane near the popular Gulf Coast vacation town of Rockport, TX, just east of Corpus Christi. Harvey was the first major hurricane (Category 3 or higher) to make landfall along the U.S. Gulf Coast since the devastating 2005 hurricane season that included hurricanes Katrina, Rita, and Wilma, and is tied with Hurricane Katrina as the most expensive storm ever to hit the country. Harvey also highlighted just how important the Gulf Coast refining and refined product pipeline infrastructure is to the rest of the U.S. Today, we mark the one-year anniversary of the devastating storm with a three-part series on Gulf Coast refining and pipeline infrastructure, and how a natural disaster along the coast can impact the rest of the country.
Florida’s increasing demand for natural gas for power generation isn’t new, but like a young alligator in the Everglades, its appetite is voracious and growing. More and more gas-fired power plants have been coming online, increasing gas demand and spurring the development of new gas pipeline capacity into the state. And, because of big shifts in where gas is being produced and where it’s flowing, the Sunshine State will soon be receiving an increasing share of its gas needs from the Marcellus region. Today, we begin a two-part look at how rising generation-sector demand for gas and a new pipeline are changing gas-flow dynamics in the U.S. Southeast.
The crude oil storage and distribution hub in the small town of Cushing, OK, is a marvel. With more than 90 MMbbl of tankage, 3.7 MMb/d of incoming pipeline capacity and 3.1 MMb/d of outbound pipes, Cushing’s nickname — “Pipeline Crossroads of the World” — is spot-on, not hyperbole. However, like a lot of other U.S. energy infrastructure in the Shale Era, Cushing’s role has been in flux. Permian oil production has been surging, the ban on U.S. oil exports is a fading memory, and the Gulf Coast — not Cushing — is where most U.S. crude production wants to go, for its concentration of refineries and export docks. That is not to say that Cushing is no longer important. Far from it. Today, we begin a blog series on how Cushing’s role has been morphing and why the Sooner State trading hub still provides critical support to producers, midstream companies and refineries alike.
With global demand for LNG rising and U.S. natural gas producers needing markets for their burgeoning output, it’s not a question of whether another round of U.S. liquefaction/LNG export facilities will be built, but which developer will be first and when it will make its final investment decision (FID). Odds are that the initial FID for this “next round” of projects is only months away, but as for the specific developer and project that will lead the pack, that has yet to be determined. We do know, however, that a handful of projects appear to be making real progress, and today we consider one of them: Tellurian’s Driftwood LNG project near Lake Charles, LA.
There are common drivers behind the handful of offshore crude oil terminals now under development along the Gulf Coast, chief among them the well-founded belief that shippers would prefer putting crude on Very Large Crude Carriers (VLCCs), which can only be fully loaded in deep water. But each of these projects also has unique nuances — its own specific rationale and characteristics. Tallgrass Energy’s plan is a case in point in that it involves a new pipeline from the crude hub in Cushing, OK, to the refinery center in St. James, LA, and to a new onshore crude storage and loading terminal a few miles down the Mississippi River, to be followed by a VLCC-ready offshore terminal capable of both exporting and importing crude. Today, we continue our review of made-for-VLCCs offshore terminals with a look at Tallgrass’s effort to deliver neat, unblended barrels directly from multiple inland plays to deep water — “shale-to-ship,” in other words.
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.
The countdown clock to January 1, 2020 — Implementation Day for the IMO 2020 rule on low-sulfur marine fuel — is ticking, and while that date may still seem far away, it is decidedly not. The impending switch from 3.5%-sulfur fuel oil to marine fuel with sulfur content no higher than 0.5% will affect a broad swath of the energy sector worldwide, not to mention consumers of diesel and other low-sulfur distillates that will be in much higher demand by this time next year as the run-up to IMO 2020 kicks into high gear. Already, complex and simple refineries alike are evaluating changes to their crude slates and planning to add equipment that will enable them to produce more high-value distillate and less “bottom-of-the-barrel” residual fuel oil, the source of high-sulfur marine fuel. U.S. midstream companies are gearing up to export more light, sweet crude from the Permian and other shale and tight-oil plays to simple refineries that will no longer be able to get by refining heavy, sour crudes. Marine-fuel suppliers are testing various blends to see which might produce IMO 2020-compliant fuel at the lowest cost. As for ship owners, they’re preparing for topsy-turvy fuel prices in late 2019 and 2020 as this wrenching change plays out. Today, we consider key market participants’ latest thinking on the likely effects of the new rule for low-sulfur marine fuel.
Since mid-July — only a few weeks ago — four proposals have been unveiled to build offshore crude export terminals along the Gulf Coast that would be capable of fully loading Very Large Crude Carriers. That’s an extraordinary burst of interest in new infrastructure development, and a signal that (1) more export growth is on the horizon and (2) VLCCs will play a much bigger role in transporting that crude. A leading contender in the race to construct new offshore terminals is Trafigura, the Swiss-based logistics and physical-trading giant, which in recent years has become a major player in U.S. energy markets. Today, we continue our review of made-for-VLCCs offshore terminals with a look at Trafi’s plan.
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.
Crude oil inventories at Cushing have been in a free fall. After last peaking at more than 69 MMbbl in April 2017, stockpiles have decreased to less than 22 MMbbl recently, nearing all-time lows for tank utilization at the Oklahoma crude-trading hub. While we’ve seen volumes drop quickly in the past, inventories have now declined for 12 straight weeks at a staggering pace. Traders, refiners, and other market participants are starting to fret. Is this just another cyclical trend or are market factors exacerbating the impact? Today, we examine the influence of historical pricing trends on Cushing inventories and why it seems that demand factors are speeding up the drop.
On Thursday, August 9, a U.S. District Court judge approved a request by a Canadian mining company to seize shares of a subsidiary of Petróleos de Venezuela SA (PDVSA) that controls CITGO Petroleum Corp. The ruling was made to satisfy a $1.2 billion arbitration award against the Venezuelan government. While details of the full ruling are yet to be released, this decision could have an enormous knock-on effect on the various other parties seeking payment from the struggling oil company for asset seizures and unpaid debts. Today, we review the assets of CITGO Petroleum Corp., the U.S. arm of PDVSA.
The trade war between the U.S. and China continues to intensify — and now the rhetoric is shifting from steel and soybeans to oil and gas. What started as just an exchange of escalating bluster has developed into real tariffs that will be enacted beginning August 23 — which will include petroleum-based products like LPG and refined products. The commodities that would have the biggest impacts on global trade flows, liquefied natural gas and crude oil, were under tariff threat as well. LNG is still on a list of potential commodities to receive tariffs in the future, while crude has since been removed. But, keep in mind that today’s state of affairs could change tomorrow, so tariffs on those two commodities should be considered very much on the table. Today, we examine the potential trade war fallout for growing exports of U.S. LNG and crude oil.