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.
Posts from David Braziel
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.
Here at RBN, we have an often repeated view that the flood of oil and gas being produced from unconventional plays will change everything we once knew about energy markets (see Top Ten Energy Prognostications for 2014). One such fundamental change is that the U.S. is now producing more natural gas, NGLs and some grades of crude oil than we can use (except for the past three weeks of Polar Vortex weather, of course). Consequently the U.S. has shifted from a position of hydrocarbon shortage to one of surplus. That is great news. But just down the road there are potential problems developing – distortions in the markets. Some of those surplus products can be exported, some can’t. The rules regarding exports of these hydrocarbon products that we are living with today were all put on the books during the decades of shortage. When you look closely at what those rules really say, you’ve got to scratch your head. Today we begin a series to examine those rules.