Crude oil production in U.S. shale and tight-oil plays still hasn’t recovered fully from the demand destruction wrought by COVID-19 in the last year or so. It could be argued, though, that producers in the offshore Gulf of Mexico (GOM) have faced even tougher times as they had to deal with not only pandemic-related staffing issues and project setbacks but the most active hurricane season on record. Offshore GOM production averaged only 1.65 MMb/d in 2020, a 13% decline from the previous year and the lowest since 2016. By August, production fell to less than 1.2 MMb/d, the lowest for that month in seven years. Many new projects were delayed as well, but things may finally be looking up, with first oil from a number of projects coming later this year or in early 2022 and final investment decisions (FIDs) on two major projects expected soon. Today, we discuss the wild ride that GOM producers experienced in 2020 and whether better days can be expected in the future.
We’ve been writing on hydrogen for a few months now, covering everything from its physical properties to production methods and economics. Given the newness of the subject to most folks, who have spent their careers following traditional hydrocarbon markets, we have attempted to move methodically when it comes to hydrogen. However, we think that things may get more complicated in the months ahead. Why, you may ask. Well, the development of a hydrogen market — or “economy”, if you will — is going to be far from straightforward, we believe. Not only will hydrogen need some serious policy and regulatory help to gain a footing, the new fuel will have to become well-integrated into not only existing hydrocarbon markets, but also some established “green” markets, such as renewable natural gas, or RNG. So understanding how renewable natural gas is produced and valued is probably relevant for hydrogen market observers. In today’s blog, we take a look at the possible intersection of natural gas, particularly RNG, and hydrogen.
This time last year, Appalachian natural gas production was approaching a steep springtime ledge as regional prices sank below economic levels and producers responded with real-time shut-ins. This year to date, regional gas prices have averaged $0.80-$0.90/MMBtu above 2020 levels for the same period, and production has been averaging more than 1 Bcf/d above year-ago levels. If production holds steady near current levels, the year-on-year gains would just about double to ~2 Bcf/d by mid-May, which is when the bulk of the springtime curtailments first took effect in 2020. This, just as Northeast demand takes its seasonal spring plunge, which means regional outflows are poised to rise in the coming weeks, potentially to record levels. How much more can the Appalachian takeaway pipelines absorb? In today’s blog, we continue our analysis of outbound capacity utilization, this time focusing on the routes to the Midwest.
Well, it’s been 365 days since the unthinkable happened: the price of WTI at Cushing went negative last April 20, and by a solid $37.63 a barrel at that. The insanity didn’t end there, though. The pandemic that many thought would be behind us in a season or two at most had a second wave, then a third and, some say, a fourth. U.S. refinery demand for crude oil, which plummeted by more than 3 MMb/d last spring, still has only recouped only half that loss. E&Ps, who shut in thousands of wells when oil demand and prices tanked, still are only producing 11 MMb/d — 2 MMb/d less than they were pre-COVID. LNG exports took a big hit too, another victim of demand destruction. As if all that weren’t enough, a couple of months ago, just as new vaccines were providing hope that everything would soon be returning to normal, the Deep Freeze put the Texas economy on ice and slowed production and refining once again. Strange times indeed. But we’re learning from it all, right? Today is the one-year anniversary of oil price Armageddon, so we take a look back at 12 months of market madness that no one could have predicted.
As the U.S. starts to emerge from under the dark cloud of the COVID-19 pandemic, one hopes that some valuable lessons have been learned as a result of the hardships and sacrifices so many have endured. While the most profound impacts were on government, healthcare and other essential services, the sudden drop in hydrocarbon demand a year ago triggered severe financial hardships for the E&P sector and provoked unpleasant memories of previous energy industry crises in 2008 and 2014-16. Producers have historically put the brakes on capital spending when commodity prices fell, then stomped on the accelerator like a race car heading into a straightaway when prices rose. But recently unveiled 2021 budgets for many E&Ps suggest that, even with the rebound in prices, they are maintaining a conservative investment paradigm that highlights strengthening balance sheets and rewarding shareholders at the expense of rapid production growth. Today, we’ll analyze the 2021 capital spending plans of the 39 E&Ps we monitor and the likely impact on their crude oil and natural gas output.
Methane, the primary component of natural gas, is the second-most-abundant greenhouse gas tied to human activity after carbon dioxide, and pound-for-pound has 25 times the heat-trapping potential of CO2. We also know that a considerable portion of methane emissions come from the oil and gas industry, not just from leaks but from intentional releases such as “blowdowns,” when operators vent natural gas into the atmosphere to relieve pressure in the pipe and allow maintenance, testing, and other work to take place. Sure, it would be better for the environment and most everybody involved if there was a way to capture natural gas instead of releasing it. (Spoiler alert: there is.) But what are the incentives for producers, pipeline owners, or local distribution companies invest in a solution? Today, we consider what midstreamers, transmission operators, and LDCs can do to minimize blowdowns.
The U.S. and Canada make quite a team. Friends for most of the past century and a half — and best buddies since World War II — the two countries have highly integrated economies, especially on the energy front. Large volumes of crude oil, natural gas, NGLs, and refined products flow across the U.S.-Canadian border, and a long list of producers, midstreamers, and refiners are active in both nations. One more thing: since the mid-2000s, the development of U.S. shale and the Canadian oil sands in particular has enabled refiners in both countries to significantly reduce their dependence on overseas oil — a big victory for North American energy independence. However, due to its smaller population and economy, Canada typically gets far less attention than its southern neighbor, so in today’s blog we try to right that wrong by discussing highlights from a new, freshly updated Drill Down Report on Canada’s refining sector.
Every gas storage injection season gives us a chance to size up how supply and demand components might influence how much gas can be stuffed away in underground reservoirs prior to the next heating season. For the Canadian storage injection season that is just getting underway, a number of factors have shifted that balance, resulting in a slowing rate of gas storage builds this year. A slower build, and subsequently lower storage levels by the end of the injection season than last year, seems likely to provide solid support for Canadian gas prices. Today, we review the latest developments and outlook for gas fundamentals in Canada.
After a roller coaster over the past year, U.S. LNG feedgas demand has been holding steady at record levels of around 11 Bcf/d for nearly a month now, with the exception of a few days due to pipeline maintenance. With Train 3 at Cheniere Energy’s Corpus Christi Liquefaction facility online and price spreads to global markets favorable for U.S. exports, that’s where it’s likely to stay, except for maintenance periods — at least until new liquefaction trains start commissioning later this year. Two Louisiana projects, Venture Global’s new Calcasieu Pass facility and the sixth train at Cheniere’s existing Sabine Pass terminal, have both indicated that they will begin exporting commissioning cargoes by year’s end — ahead of their originally proposed construction schedules — a prospect that could boost Gulf Coast feedgas demand to even greater heights by the fourth quarter of 2021. In today’s blog, we wrap up this short series with a detailed look at the two projects and implications for LNG feedgas demand this year.
It is impossible to overstate the significance of the crude oil hub in Patoka, IL, to refineries in the Midwest. The seven-terminal hub, whose 80-plus above-ground tanks can hold more than 17 million barrels of crude oil, serves as the primary storage, blending, and staging site for a dozen refineries in five states with a combined capacity of more than 2.6 MMb/d. In other words, if the folks that keep Patoka running decide to take a couple of days off, Midwest refining would pretty much grind to a halt. And that’s not all: the southern Illinois hub also plays a critical role in sending crude oil south to the Gulf Coast. Today, we conclude our series on the Patoka hub with a look at the infrastructure within the facility’s boundaries and the pipes that transport oil out of it.
Each sector of the oil and gas industry — upstream, midstream, and downstream — faces its own unique set of challenges in dealing with the ongoing transition to a lower-carbon global economy and in addressing the increasing ESG-related demands of investors and lenders. Refiners are no exception. Their highly complex facilities may be capable of converting crude oil into gasoline, diesel, and jet fuel, but the fact remains these refined products generate greenhouse gases when they are produced and consumed. What can refiners do to prepare for an era of low- or no-carbon fuels and improve their enviro-cred at the same time? Many have been investing heavily in renewable fuels production, such as renewable diesel and ethanol, and in sourcing at least some of their electricity needs from wind and solar. Today, we continue our series on the environmental-social-governance movement in the oil and gas industry with a look at what refiners are doing on the ESG front.
When it comes to blogs on the developing hydrogen sector, many subjects can seem quite foreign to the traditional hydrocarbons expert. We have found ourselves spending a considerable amount of time over the last few months slowly peeling back the layers on this sector in an effort to be prepared should hydrogen enter a new phase of importance in the energy industry. Today’s blog is likely a much more straightforward one for the typical hydrocarbon-focused reader. That’s because, in our view, Monolith Materials’ unique process for transforming natural gas into “turquoise” hydrogen while sequestering the carbon, is easier to wrap your head around. This is not just because of the company’s clear goals and process, but also because what it does is proving to be economically viable. That’s not always the case when we discuss hydrogen, so covering Monolith’s operations is a welcome break. Today, we detail a truly one-of-a-kind method of low-carbon hydrogen production.
Just one year ago, the onset of the COVID-19 pandemic plunged the energy industry’s exploration and production (E&P) sector — already reeling from a steep decline in oil prices in late 2019 — into a memorably brutal spring that threatened its survival. Demand cratered, price realizations fell to the lowest point in a decade, and cash flows dried up. Sure enough, E&P results for the first half of 2020 were a train wreck, with the three-dozen companies we track reporting a whopping $45 billion in losses, including impairments. But the dark clouds hovering over the industry began to clear in the second half of the year as the combination of production cutbacks and recovering demand triggered rising prices. With the massive price-related impairments largely in the rear-view mirror, year-end 2020 results revealed that most E&Ps had clawed their way back to near-profitability. Today, we review their latest numbers and preview what we expect will be a sunny 2021 for the industry.
U.S. presidential transitions often bring policy changes, but few have been as dramatic and swift as the shift in energy policy that came with President Biden’s inauguration in January. Among his first acts after being sworn in was the signing of an executive order that revoked the Presidential Permit for TC Energy’s long-planned Keystone XL crude oil pipeline. Among other impacts, the move put on ice more than one-third of the Canadian midstream giant’s C$37 billion capital spending program for the 2021-24 period and unraveled TC Energy’s plan to balance its natural-gas-weighted pipeline portfolio with more crude oil pipes. So, what’s next for the midstreamer now that KXL is a no-go? In today’s blog, we’ll discuss highlights from our new Spotlight report on TC Energy which lays out how the company arrived at this juncture and where it goes from here.
If there’s one word that sums up the U.S. LNG export market over the past year, it’s resilience. After taking a pummeling last year, feedgas demand and exports have roared back, reaching new heights in recent weeks, and are headed still higher in the coming months as new liquefaction capacity is commissioned at a faster pace than expected. Train 3 at Cheniere Energy’s Corpus Christi LNG facility came online on March 26, increasing U.S. LNG export capacity to 75 MMtpa (~9.9 Bcf/d), which equates to a total feedgas demand of nearly 11 Bcf/d. Two more export projects — 18 modular trains at Venture Global’s new Calcasieu Pass facility and the sixth train at Cheniere’s existing Sabine Pass — are on track to ship their first commissioning cargoes later this year, ahead of their originally proposed construction schedules, and will be fully operational in 2022. This is quite a different picture from last year, when nothing but uncertainty loomed on the horizon in a COVID-hit world and progress for just about every project was in jeopardy. Today, we start a short series providing an update on the status of operational and under-construction export capacity and where LNG feedgas demand is headed this year.