For U.S. refineries, the severe demand destruction that occurred this spring led to the worst financial performance in recent history. Not only did refiners produce less diesel, motor gasoline, and jet fuel in the second quarter than any quarter in recent memory, their refining margins were sharply lower than the historical range — a one-two punch that hit their bottom lines hard. The situation has improved somewhat this summer, but it’s still tough out there. So tough, in fact, that it’s reasonable to ask, does the coronavirus and its impacts to the energy sector signal the end of an era for refiners across the U.S.? Today, we review the decline in fuel demand and profitability in the second quarter and discuss the uncertainties refiners face in the second half of 2020 and beyond.
Daily energy Posts
In the first eight months of last year, the Corpus Christi area ranked third among its Gulf Coast brethren in crude oil export volumes — Houston was consistently #1 then, and Beaumont was the regular runner-up. Since September 2019, though, Corpus has been out front, often by a wide margin, and there’s good reason to believe it will stay ahead of the pack, at least for a while. What’s driving the South Texas port’s export-volume growth? First, there are three big new pipelines now moving crude from the Permian to Corpus: Cactus II, EPIC Crude and Gray Oak. Second, Corpus Christi and nearby Ingleside, TX, have a lot of existing storage and marine-dock capacity, and more is being developed. Today, we continue our review of crude export facilities with a look at three terminals along Corpus’s Inner Harbor.
Though crude oil prices have been rebounding lately, this spring’s price crash sent shockwaves through the U.S. midstream industry, which had just 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 new Spotlight report on Targa.
Mexican demand for motor gasoline and diesel has plummeted this spring due to COVID-19 — so has demand for LPG. So far, Pemex — Mexico’s state-owned energy company and by far the country’s largest supplier of these commodities — has responded by slashing how much gasoline, diesel and LPG it is importing from the U.S. and holding its own production steady, despite the fact that Pemex’s refining margins are now deep in negative territory. What does Pemex’s focus on money-losing refining mean for U.S. exports to Mexico going forward? Today, we begin a short series on the ongoing competition between U.S. refiners and Pemex for market share south of the border.
Up in Canada, there is finally a regulatory timeline for reviewing Enbridge’s long-standing proposal to revamp how it allocates space — and charges for service — on the company’s 2.9-MMb/d Mainline. But the plan to convert the largest crude oil pipeline system out of Western Canada from one whose space is 100% uncommitted and allocated every month to one with 90% of its capacity locked in via long-term contracts remains controversial, especially among producers. Plus, the world has changed in the past few months. Oil sands and other production in Alberta and its provincial neighbors is off sharply in response to pandemic-related demand destruction and low oil prices, and the always-full Mainline has been running at well under 90% of its capacity lately. Further, the Trans Mountain Expansion and Keystone XL projects — competitors to the Mainline in a way — have progressed this year, making shippers wonder whether to lock in capacity on the Mainline if TMX and KXL’s completion may be imminent. Today, we begin a short series on the prospective shift to a contract-carriage approach on the primary conduit for heavy and light crudes from Western Canada to U.S. crude hubs and refineries.
Energy markets balance — eventually. In the midst of the turmoil we’ve experienced this year, there have been periods when it seemed like markets were going to hit the wall. But even with the historic WTI oil price glitch on April 20, the physical crude oil markets continued to function. That’s the way it is supposed to work, and it’s good news. The bad news is that figuring out how these markets are balancing in these volatile conditions can be challenging if not downright perplexing. Nowhere is that more true than the market for U.S. propane. Production is down, but so is demand. Inventories are up, and so are prices. Propane continues to be exported, even though global demand has been whacked by COVID. In today’s blog, we explore these developments and put the spotlight on RBN’s NGL Voyager, our subscriber report and data service that we have just reformatted, upgraded and generally reconstructed to meet the information needs of today’s NGL marketplace.
Natural gas prices in the U.S. were under pressure for many years, long before the COVID crisis gripped the world and threw energy markets into flux. Shale gas production, from both crude- and gas-focused basins, has driven U.S. output to incredible levels over the last 10 years. That growth has led to persistently low U.S. gas prices across the Lower 48, with the benchmark Henry Hub being no exception. The upshot of low gas prices has been steadily increasing demand, both in the domestic market and for exports of liquefied natural gas (LNG) to various markets around the globe. Until recently, those international markets had often been viewed as an insatiable demand sink, but reality has set in over the past year. Prices in Europe, one of the most popular destinations for U.S. LNG, have crashed below Henry Hub, and are threatening the once-steady flow of LNG. Market participants in the U.S. and Europe now find themselves poring over the fundamental details of both markets to determine how long the price weakness will last, or if it will only get worse from here. Today, we look at the increasingly interconnected gas markets on both sides of the Atlantic.
Do not try and refine the Brent; that's impossible. Instead, only try to realize the truth...there is no Brent. Then you will see it is not the Brent that gets refined; it is only yourself. For those who are not fans of The Matrix, that sentence may seem a little cryptic, but it makes a point that is little understood outside the rarified world of crude oil trading. The production of North Sea Brent crude oil is down to less than a couple of hundred barrels per day. Soon it will be gone altogether. But 70% of all crude oil in the world is tied either directly or indirectly to the price of Brent. How is that possible? Well, it’s because Brent is no longer simply a grade of crude oil. Over the past two decades, it has evolved into an intricate, multi-layered matrix of trading instruments, pricing benchmarks and standard contracts that is a world unto itself. A world with a huge impact across almost everything in today’s energy markets. Unfortunately, no one can be told what Brent is. You have to see it for yourself. So that’s where we’ll go in this blog series. Warning: To read on is like taking the red pill.
U.S. Northeast natural gas producers may be on the other side of a years-long battle with perpetual pipeline constraints and oversupply conditions. But they’re now facing new challenges to supply growth, at least in the near-term, from low crude oil and gas prices and the decline of a major downstream consumer of Appalachian gas supplies: LNG exports along the Gulf Coast. Most of the U.S. well shut-ins since the recent oil price collapse are concentrated in oil-focused shale plays, and gas volumes associated with those wells will be the hardest hit. However, a number of gas-focused Marcellus/Utica producers also have announced or escalated supply curtailments in recent weeks, as they wait for associated gas declines to buoy prices enough to support drilling. The pullback has had immediate effects on the region’s production volumes and supply-demand balance. Today, we provide an update on the latest Appalachia gas supply trends using daily gas pipeline flow data.
Canada’s energy sector has been hit hard by the recent oil price collapse that was initially set off by the now-ended Saudi Arabia-Russia price war and made much worse by the demand-destroying effects of the global COVID-19 pandemic lockdowns. The impacts on Canada’s crude oil and natural gas sectors have been both dramatic and nuanced. For example, oil supply cutbacks have been rapid and substantial, while there has been virtually zero impact on natural gas supplies. Oil demand has been similarly affected, with refined product demand seeing a large swoon, while natural gas demand has suffered only a modest pullback. And for Canada’s energy exports, these have experienced some jolting swings in a matter of weeks, putting the whole sector under pressure to adapt where possible. Today, we highlight some of the recent market disruptions and their implications.
Through the second half of the 2010s, the Permian Basin’s crude oil supply trajectory was clear: up, up and up. From the start of 2015 to the end of last year, crude production in the world’s leading shale play increased by an amazing 3 MMb/d, from 1.7 MMb/d to 4.7 MMb/d. Three new pipelines with a combined capacity of more than 2 MMb/d were built to move a lot of those incremental barrels to Corpus Christi, which — thanks in part to newly developed storage and docks — has become the U.S.’s #1 port for crude exports in recent months. But Permian producers have trimmed their crude output by at least several hundred thousand barrels a day this spring in response to falling demand and low prices. Has the Permian been thrown off course, and if it has, what would that mean for marine terminals in Corpus? Today, we continue our series of Gulf Coast crude export facilities with a look at the three newest terminals along the Corpus Christi Ship Channel.
Progress for the second wave of U.S. LNG export projects, which already had begun slowing in the latter half of 2019, has come to a near standstill this year, with several developers delaying final investment decisions (FIDs). The economics for U.S. LNG exports have evaporated in recent weeks, and for the first time in the four years or so since the Lower 48 began exporting LNG, cargo cancellations have become a regular part of the U.S. gas market’s vernacular. International prices are signaling that oversupply conditions will linger for a while, likely well after COVID’s impacts on demand ease. Nevertheless, projects that are already under construction are pushing forward, including the last of the first-wave expansions and two facilities from the second wave of proposed projects. There’s also one more second-wave development that could take FID this year. Today, we provide highlights from RBN’s latest LNG Voyager Quarterly report.
Crude oil markets have been anything but dull lately. After imploding to unimaginable, negative values last month, prices have been on a tear since and are now sitting in the low $30s/bbl range. That’s not great for producers, but kind of like social distancing flattens the curve, the current price level should keep production volumes in check and stave off the worst of the potential financial distress for most Permian producers, for now. So, what has been driving the price rise? Similar to the pauses in economic and social activity that many cities have taken lately, many Permian producers have recently decided to take a wait-and-see approach on crude prices and throttle back output. Today, we provide an update on the always-dynamic Permian Basin crude oil market and how producer curtailments have materialized in May.
COVID-19 has created a number of challenges across the energy value chain, including lower demand for motor gasoline and jet fuel and, subsequently, surplus crude oil. However, even with diminished demand, the facilities that produce and process these fuels have to keep operating at some level, as do petrochemical plants. Workers in the energy industry are considered essential due to the importance of having fuel available to power vehicles and manufacturing facilities, natural gas to enable continued operation of power industries, and logistical infrastructure to ensure that feedstock supply can make it to processing facilities and eventually consumers. Given the need for round-the-clock operations, COVID-related social distancing measures have presented a unique challenge for refinery and petrochemical facilities. To maintain adequate staffing while protecting personnel from the coronavirus, these facilities have been making major adjustments. If, as we all hope, things begin moving back toward “normal” in the coming months and refinery and petchem utilization ramps up, these efforts to keep workers safe will only gain in significance. Today, we discuss staffing issues in these key industry sectors during the pandemic.
The Marcellus/Utica production region in the northeastern U.S. is not immune to the upheaval in global energy markets. There, a number of E&Ps are implementing further cutbacks in their natural gas production. That will result in lower NGL production, which may have serious implications for regional supplies of propane for heating this coming winter. LPG exports out of the Marcus Hook terminal near Philadelphia also may be impacted. Today, we look at recent developments in the Marcellus/Utica and the potential effects of lower NGL production in the region.
Very Large Crude Carriers offer economies of scale and are the oil transporters of choice for shippers moving massive volumes of crude from the U.S. Gulf Coast to distant customers in Europe and Asia. VLCCs also can serve as cost-effective floating storage — in the current contango market, a growing number of these 2-MMbbl behemoths are being used to stockpile crude until its value increases in the coming months. VLCCs can be loaded to the gills through reverse lightering at a number of deepwater points off the coast of Texas, but only one facility, the Louisiana Offshore Oil Port, can fill the supertankers to the brim at the port itself. LOOP also can receive fully loaded VLCCs, of course, and another ace up its sleeve is its 72 MMbbl of cavern and tank storage a few miles inland at Clovelly, LA. Today, we continue our series on Gulf Coast export facilities with a look at LOOP.