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.
Posts from David Braziel
On April 20, that fateful day in crude oil markets when the CME May contract for WTI at Cushing collapsed to negative $37.63/bbl, the number of contracts involved in the chaos was relatively small. So you might think that most producers sat on the sidelines, watching Wall Street paper traders writhe in stunning financial pain. But not so. Almost all producers saw their crude prices that day crashing in exactly the same magnitude. That’s because the daily price of the CME WTI contract is part of the formula pricing used in a very large portion of crude oil contracts in U.S. markets, both directly and indirectly. There are two formula mechanisms that are commonly used in crude oil sale/purchase contracts that are responsible for that linkage: the CMA and WTI P-Plus. These arcane pricing mechanisms are complicated, but in order to understand U.S. crude markets, it is critically important to appreciate how they work. Today, we continue our deep dive into crude oil contract pricing mechanisms.
The global economic shut-down caused by COVID continues to wreak havoc on U.S. markets. Last week, the dynamics that resulted in negative prices for NYMEX WTI thrust crude oil, and, more specifically, storage at Cushing, OK, into the national spotlight. The extraordinary imbalance in U.S. crude oil supply and demand has been pushing record volumes of oil into storage at the Cushing crude hub and tankage along the Gulf Coast. The same fundamental factors have also driven a surge in stocks of refined products like gasoline and diesel. Now the questions on everybody’s mind are, how long until storage tanks are completely full and what will that mean? Today, we’ll discuss recent trends and consider what record storage builds mean for the oil patch.
On Monday, front-month WTI at Cushing cratered to a negative $37.63/bbl. On Tuesday, the same futures price rose by nearly $48 to close at about $10/bbl — a positive $10, that is. As for WTI to be delivered in June, it lost well over a third of its value on Tuesday, ending up at less than $12/bbl, but over the past two days it has roared back to over $16/bbl. No doubt the WTI futures market will see more wild times in the days and weeks ahead as traders look to avoid the traps that ensnared the market as the May contract approached expiry. If there’s a lesson to be learned from the past week, it’s that it really helps to understand the ins and outs of the futures market — especially when it is so volatile. Perhaps the most important thing to wrap your head around is that while the futures market mostly involves financial players who will never take physical delivery of oil, the two markets — financial and physical — are fundamentally linked. Prompt-month futures converge on spot prices over time, while physical contracts are settled in part based on NYMEX futures, so producers will feel the sting of Monday’s negative prices when physical April deliveries are invoiced. Today, we begin a two-part blog series examining U.S. spot crude pricing mechanisms.
Like the proverbial dog who finally catches the truck he’s been chasing, only to wonder what to do next, midstreamers at long last have brought on enough crude oil pipeline capacity to move Permian barrels to the Gulf Coast. In fact, right now there appears to be more than enough pipeline space, with several pipes flowing less than their capacity. What midstream companies now face is a race to the bottom as their pipelines compete with each other to attract barrels by offering service to Gulf Coast markets at the lowest price — resulting in transportation rate compression. Today, we begin a blog series on the tug-of-war for barrels and its effect on prices.
The Houston Ship Channel (HSC) is one of the busiest shipping lanes in the U.S. Each year, thousands of vessels utilize the waterway, importing and exporting goods ranging from pharmaceutical products to what the Census Bureau classifies as “Leather Art; Saddlery Etc.; Handbags Etc.; Gut Art”. More to the point of today’s blog: over 10 million tons of energy products move through the channel each month. But as ships grow ever larger, the ports and canals that service them must also adapt to be able to handle their increased dimensions. The Houston Ship Channel now finds itself in a situation where it must adapt to meet increasing market demands. Today, we continue our series on the issues facing some Texas ports and the measures being taken to help alleviate them.
In terms of raw tonnage, the Port of Houston is by far the busiest in the United States. The 52-mile-long Houston Ship Channel (HSC) — running from just outside downtown Houston out to an area between Galveston Island and Bolivar Peninsula — is the artery that enables the heavy ship traffic, much of it tied to crude oil, LPG, petroleum products and other hydrocarbons. But in the same way that Houston’s Interstate 45 traffic backs up during the morning commute, the ship channel traffic, which normally runs at about 60% of peak levels, can be (and has been) subject to delays when there’s an accident, visibility problems, or a slow-moving double-wide taking up two lanes. With energy-related export activity on the rise, efforts are underway to address those issues. Today, we begin a series on the issues facing some Texas ports and the measures being taken to help alleviate them.
When crude oil prices crashed in the second half of 2014 and 2015, producers survived by becoming leaner and more efficient. That transition included drastic reductions in the rates paid to services companies while wringing ever more oil and gas out of each well and, in the process, permanently altering the economics of drilling and completion. This year, producers are again facing a lower-price environment; since early October (2018), crude prices have dropped more than 30%. In the current, more conservative investment environment, can producers do it again? Can additional value be squeezed out with bigger well pads and longer laterals? Today, we continue a series exploring the benefits and risks of these highly concentrated and highly complicated operations.
Dominator. Showboat. Brass Monkey. These are not player names in the re-established XFL; these are project names given to colossally proportioned drilling pads in the Permian and Appalachia. A single one of these well pads can be home to 20, 30, even 60 or more permitted well spots, each with miles-long laterals branching out in multiple directions. In today’s blog, we begin a series exploring the motivations that sparked this trend to larger pads and discuss the impact they’re having on the upstream and midstream sectors.
This past winter’s gas price spikes shined a bright light on the changing dynamics driving Eastern U.S. natural gas markets, especially the growth in gas-fired generation that is contributing to more frequent — and more severe — spikes in gas prices in the region on very cold days. There are other changes too. For one, gas is increasingly flowing from the Northeast to the Southeast as prodigious Marcellus/Utica production growth is pulled into higher-priced, higher-demand growth markets. In today’s blog, we conclude our series on ever-morphing gas markets on the U.S.’s “Right Coast” by examining how gas pipeline flows back East have changed on days besides the winter peaks, how much demand could be unlocked by forthcoming pipeline projects, and what that new demand will mean for flow and price patterns.
Could it get any worse? Possibly, but the last time we saw petchem margins this bad was in the depths of the 2008-09 economic meltdown, and back then the atrocious margin levels resulted in drastic plant curtailments and in some cases permanent shutdowns. But this time around the petchem industry is in the process of bringing on even more capacity! Is the current situation a fluke, or a harbinger of things to come? In today’s blog we examine recent trends in steam cracker margins, by far the largest demand sector for natural gas liquids (NGLs) and consider what these developments may mean for NGL markets in general, and ethane in particular.
The worst of this winter’s cold has passed, but the impact of structural changes in U.S. power generation will be felt in natural gas markets for years to come. The generation mix has been changing rapidly in recent years, and the switch from coal to gas is happening at an even faster pace on the East Coast than in the country overall. This switch reflects both coal-plant retirements and ongoing competition between remaining coal plants and gas plants. But low-cost gas supplies in the Marcellus and Utica plays don’t always have ready access to the biggest consuming markets, and this winter, we saw how the increasing call on gas for Eastern power generation can stress the gas pipeline grid and cause price blowouts. Today, we continue a series on Eastern power generation and prices by untangling the sources and drivers of gas-fired generation growth in the region.
After a three-year hiatus, winter returned to the U.S. natural gas market this year in the form of a “Bomb Cyclone” and more than a week of frigid temperatures. The cold weather pushed Henry Hub prices above $6/MMBtu and East Coast prices higher than $100/MMBtu on some days. This winter, the pain wasn’t just confined to New England. Prices at Williams’ Transcontinental Gas Pipeline (Transco) Zone 5, which includes the Carolinas, Virginia and Maryland, hit all-time highs on January 5. Exports from Dominion’s Cove Point terminal in Maryland are only just getting started so it’s not liquefied natural gas (LNG) exports from the East Coast that are driving prices higher. Instead, it’s gas’s increasing role in winter power generation that has been putting pressure on East Coast gas pipeline deliverability. Today, we begin a series explaining why prices have been so high on very cold days this winter and why more price spikes may be ahead.
It was a wild ride for Asian butane in 2017, driven by a range of diverse market factors, including U.S. ethane and LPG exports, a government program in India to encourage switching from firewood to LPG, the OPEC/NOPEC crude oil production cuts and LPG contract pricing set by Saudi Arabia. It was a textbook example of how today’s energy markets are buffeted by changes in production trends, government intervention and the growing influence of exports. Today, we introduce a series on the supply and demand dynamics that shaped Asian butane markets in 2017, and that will drive LPG markets in Asia, Europe and the U.S. in coming years.
Last week the U.S. NGL markets entered uncharted territory. According to OPIS, cash propane prices in the Conway, KS market reached almost $5.00/gallon for a time, responding to a massive product shortage across the entire eastern half of the country. But at the same NGL hub, OPIS also reported that the price for ethane/propane mix (EP mix) dropped deep into negative territory at $(0.50)/gallon. That’s crazy. The seller is paying the buyer to take the product. Nothing like this has been seen before in these markets. Propane inventories continue to drop, transport trucks are moving product hundreds of miles to markets, terminals remain on allocation and a state of emergency has been declared by at least 20 state governors. The inventory graphs look so scary that the Black Swan is frozen stiff. Today we begin a series on the NGL markets of 2014, a year that this industry will be talking about for a long time.