The U.S. natural gas market last week was again reminded of the hair-trigger conditions that Permian producers and marketers are operating under — with gas production pushing against available takeaway capacity, all it takes is an otherwise minor/routine maintenance event on even one West Texas takeaway pipeline to send regional gas prices spiraling into negative territory. Waha Hub gas prices last week collapsed to their lowest level ever, with intraday trades even going negative — meaning some had to pay the market to take their gas. This wasn’t the first time that’s happened in the Permian — a similar event occurred in late November 2018 — but it was the worst to date and signals a heightened supply glut in the region, at least until the first new takeaway pipeline comes online in the fourth quarter of this year. Today, we explain the recent price weakness in West Texas and implications for Permian basis in 2019.
Daily energy Posts
During 2018, U.S. crude oil, natural gas and NGL production hit new all-time highs almost every month. Oil production grew by a staggering 1.7 MMb/d from January to December, an increase of about 18%. NGLs soared even more: by 27%, up 1.0 MMb/d over the same 12-month period. Natural gas production zoomed skyward by 10 Bcf/d, a gain of about 13%. All this new supply came on in a price environment marked by wild swings. WTI ran up from $60/bbl to $75, then collapsed below $50. Henry Hub gas spiked to nearly $5/MMBtu, then beat a hasty retreat back to the $3/MMBtu range. Permian gas traded negative. Ethane prices blasted to the moon (62 c/gal), then crashed back to earth (below 30 c/gal). Is this the way it’s going to be? Massive production growth, extreme price volatility, widespread market uncertainty? It’s impossible to answer such a question, right? Nah. All we need to do is stick our collective RBN necks out one more time, peer into our crystal ball, and see what 2019 has in store for us.
One way or the other, all of 2018’s Top 10 blogs had something to do with infrastructure. There’s not enough. Or it’s taking too long to come online. Or there is too much being built too soon. Even the financial underpinning of U.S. energy infrastructure development — the MLP model — ran into tough sledding in 2018. Then, toward the end of the year, all of the best-laid infrastructure planning got whacked by the crude-market wild card: prices crashing below $50/bbl. We scrupulously monitor the website “hit rate” of the RBN blogs that go out to about 26,000 people each day and, at the end of each year, we look back to see what generated the most interest from you, our readers. That hit rate reveals a lot about major market trends. So, once again, we look into the rearview mirror to check out the top blogs of the year based on the number of rbnenergy.com website hits.
Production of natural gas liquids in the Rockies has increased by half since the end of 2012, with the bulk of the output — and those gains — coming from the greater Niobrara play in Colorado and Wyoming. As a result, a number of NGL pipelines out of the Rockies are now running full or close to it, and midstream companies are planning a mix of new pipelines, pipeline expansions and pipeline conversions with the aim of easing takeaway constraints by the latter half of 2019. But, with crude oil prices tanking and crude-focused producers reevaluating their drilling and completion plans, could the Niobrara be headed for an NGL takeaway over-build? In today’s blog, we continue our series with a look at existing and planned NGL pipes out of the Denver-Julesburg (D-J) and Powder River basins.
After somewhat of a lull in U.S. LNG export growth through much of 2018, demand for feedgas has revved up this fall. Total feedgas deliveries to U.S. LNG export terminals topped 5 Bcf/d for the first time this past weekend, thereby also surpassing exports to Mexico for the first time. All five commercialized liquefaction trains — four at Cheniere Energy’s Sabine Pass and one at Dominion’s Cove Point LNG — are operating at or near full capacity for the first time. Simultaneously, commissioning activity is under way now for four new liquefaction trains, including the initial trains at two new export terminals. This steady gas demand is underpinned by gas pipeline expansions designed to provide more direct and economical connectivity between U.S. producing regions and the export terminals. Today, we continue our blog series looking at feedgas pipeline projects and their effect on feedgas flows, this time with a focus on Dominion’s Cove Point LNG.
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.
Crude oil takeaway constraints out of the Permian are a fresh reminder that, in the Shale Era, production gains can far outpace the ability of the midstream sector to build new pipelines. Similarly, an increasing share of the rising volumes of crude flowing through the Cushing, OK, hub wants to move to the Gulf Coast, but the existing Cushing-to-coast pipeline systems are full and midstreamers are scrambling to add more capacity. Pipeline constraints aren’t limited to crude, of course. In the Niobrara’s Denver-Julesburg Basin, rapid gains in NGL production threaten to overwhelm the pipelines carrying mixed NGLs to fractionation hubs. What can be done? In at least some cases — including all of those mentioned above — there are opportunities to convert NGL pipelines to crude service, or vice versa. Today, we look at efforts under way to repurpose existing pipes to add needed takeaway capacity pronto.
While U.S. refineries are again running hot and heavy after the end of this year’s seasonal fall maintenance period, Mexico’s refineries have continued to struggle to operate at more than 30% of their capacity, a decline that is exacerbated by that country’s tumbling oil production. In recent years, Mexico’s dismal refinery utilization rate has been a boon for U.S. refiners on the Gulf Coast who can ship, pipe or truck gasoline to America’s southern neighbor in short order. Now, Mexico’s new president, Andrés Manuel López Obrador (AMLO), is pushing to solve Mexico’s refinery problems by building a new one. Today, we discuss Mexico’s growing dependence on U.S. gasoline, and whether building a new refinery south of the border will change things.
The Cushing, OK, storage and trading hub plays critically important roles in both the physical and financial sides of the crude oil market. Located at a central point for receiving crude from a wide range of major production areas — Western Canada, the Bakken, the Rockies, SCOOP/STACK and the Permian among them — the hub also has numerous pipeline connections to Gulf Coast refineries and export docks, and to a large number of inland refineries. And, with Cushing’s 94 MMbbl of storage capacity and status as the delivery point for NYMEX futures contracts for West Texas Intermediate, the hub’s inventory levels and the WTI-at-Cushing price are closely watched market barometers. But like a lot of other U.S. energy infrastructure in the Shale Era, Cushing’s place in the energy world has been in flux. Most importantly, Permian 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. Today, we discuss Cushing’s changing role and highlights from RBN’s new Drill Down Report on the U.S.’s most important crude hub.
The latest weather forecasts for the second half of December have taken the edge off the U.S. natural gas market and reduced the chance of a true doomsday storage scenario. But U.S. gas storage inventories nonetheless remain at historically low levels, and long-term weather forecasts are notoriously fickle. So this winter could still see a resurgence in volatility before the market finds a balance. And while Henry Hub prices went on a wild ride earlier this month before settling back in below $4/MMBtu, for most of December thus far, Eastern gas prices have traded at levels that make LNG exports from there uneconomic. In today’s blog, we continue our review of the winter U.S. gas market with a closer look at how Cove Point Liquefaction (CPL) might respond to high prices.
Feedgas demand at U.S. LNG export terminals has climbed 1.3 Bcf/d, or ~40%, in just three months to an average 4.4 Bcf/d in December to date and hit an all-time single-day high of over 4.6 Bcf/d last Tuesday. The big jump in demand came as U.S. Gulf Coast LNG operators have begun commissioning three new liquefaction trains, including the initial trains at two new export terminals. At the same time, pipeline expansions targeting both existing and newly active terminals have been completed to meet that demand. How are the new trains being supplied and what’s the effect on gas flows? Today’s blog takes a closer look at recent changes in liquefaction and feedgas delivery capacity and their effect on feedgas flows, starting with Cheniere Energy’s Sabine Pass Liquefaction.
Gross production of natural gas in the Niobrara region topped 5 Bcf/d for the fourth consecutive month in November 2018, according to the Energy Information Administration, and it's estimated that regional output this month will hit another record: nearly 5.2 Bcf/d. These production gains, and the concentration of new wells in or near Weld County, CO — the epicenter of the Niobrara’s Denver-Julesburg Basin — are straining the ability of existing gas processing plants to keep up, and spurring the rapid development of new processing capacity. The scale of the build-out in the D-J is impressive: some 2.7 Bcf/d in new cryogenic plants are either under construction or in various stages of pre-construction planning in northeastern Colorado. Today, we continue our review of Rockies crude oil, gas and NGL production and infrastructure, this time focusing on gas-processing needs in the sky-high D-J.
The third quarter of 2018 was a moment in the sun for U.S. exploration and production companies. The 44 major companies we track reported a 35% increase in pre-tax operating income over the previous quarter and seven-fold increase from the year-ago period on rising commodity prices and narrowing differentials in some key regions. Oil-Weighted producers outside the infrastructure-constricted Permian posted generally higher realizations, and a number of Permian-focused E&Ps minimized the impact of takeaway constraints by employing basis hedges, utilizing firm transportation contracts and reducing their operating costs. Diversified producers saw higher quarterly per-unit profits thanks to the tilt of their portfolios toward oil. And as lower Appalachian differentials lifted the realizations of Gas-Weighted producers, portfolio readjustments and the liquids content of production also positively impacted their profitability and cash flow. Today, we analyze third-quarter results by peer group, and discuss the potential impacts of the sudden plunge in oil prices this fall.
The U.S. natural gas market’s supply-demand balance in 2018 has been razor thin, with demand ramping up to match strong production gains. The result has been a large and stubborn storage deficit compared to prior years and price volatility, the likes of which the market hasn’t seen in a decade or more. How will the current storage level affect the winter gas market, and what are the prospects for storage to catch up before the winter is up? Today’s blog considers potential scenarios for the season-ending gas inventory balance.
The IMO 2020 rule, which calls for a global shift to low-sulfur marine fuel on January 1, 2020, is likely to require a ramp-up in global refinery runs — that is, refineries not already running flat out will have to step up their game. Why? Because, according to a new analysis, the shipping sector’s need for an incremental 2 MMb/d of 0.5%-sulfur bunker less than 13 months from now cannot be met solely by a combination of fuel-oil blending, crude-slate changes and refinery upgrades. The catch is, most U.S. refineries are already operating at or near 100% of their capacity, so the bulk of the refinery-run increases will need to happen elsewhere. Today, we continue our look into how sharply rising demand for IMO 2020-compliant marine fuel may affect refinery utilization.
There’s a reason why more than half a dozen midstream companies and joint ventures are clamoring to build deepwater loading terminals on the Gulf of Mexico: because it’s a major pain to load Very Large Crude Carriers (VLCCs) any other way. These days, the standard operating procedure for loading the vast majority of VLCCs along the Gulf Coast involves a complex, time-consuming and costly process of ship-to-ship transfers called reverse-lightering, in which smaller tankers ferry out and transfer crude to VLCCs in specified lightering areas off the coast. Today, we ponder the current dynamics for U.S. crude exports via VLCC.