New and expanded efforts to reduce greenhouse gases, most notably carbon dioxide, have been making headlines globally on a daily basis for a while now. Canada’s energy industry has been increasingly contributing to that newsfeed this year, with two large projects announced in Alberta that will capture, use, and sequester large volumes of CO2 generated from the oil sands as well as other sources of oil and gas production in Western Canada. In today’s blog, we review the emissions profile of the Canadian oil and gas sector and discuss two of the largest carbon capture, use, and sequestration projects announced to date.
Significantly reducing greenhouse gas emissions is an all-hands-on-deck kind of thing. More wind power? More solar? Electric vehicles? Yes, yes, and yes. Another great way to slash GHGs is to use man-made or “anthropogenic” carbon dioxide for enhanced oil recovery. EOR is an extraordinarily efficient way to permanently store CO2 deep underground. And today, the economics for EOR are being turned on their head — in a good way. For decades, the acquisition of CO2 has been a significant cost for EOR operators, requiring volumes to be produced from natural geological formations and then to be pumped to the oil fields where the CO2 is used. But things are changing. Now companies are planning to spend big bucks to capture and dispose of their CO2, meaning they may be paying someone to get rid of it. And if they pay, that flips CO2 from an operator cost to a revenue stream. The implications are profound, with operators historically motivated to use CO2 as efficiently as possible set to morph their operations to use as much CO2 as can be safely sequestered. In today’s blog, we continue our series on CO2-based EOR by looking at the coming transition in CO2/EOR economics.
The handful of enhance-oil-recovery producers in the Permian Basin secure virtually all of the carbon dioxide they use from natural CO2 reservoirs located thousands of feet below the surface. In essence, they are taking CO2 out of the ground and putting it back in during the EOR process — producing more crude oil and demonstrating that the CO2 is safely and securely stored underground. Now the challenge is to transform this proven process in a way that reduces greenhouse gas emissions. To do that, EOR producers would need to use man-made or “anthropogenic” CO2 that is captured from industrial and other sources. Well, that’s exactly what’s already happening to a significant degree in EOR operations along the Gulf Coast and in the Rockies, with plans by a leading producer in both regions to use “A-CO2” for the vast majority of its CO2 needs within a few years. In today’s blog, we continue our series on CO2-based EOR with a look at how Denbury Inc. is shifting from naturally sourced CO2 to the man-made stuff.
Using carbon dioxide for enhanced oil recovery offers tremendous potential for CO2 sequestration. The problem is, most the CO2 used in EOR today is produced from natural underground sources, only to be piped to EOR sites and put underground again. Realizing the full promise of CO2-for-EOR would require sourcing more and more anthropogenic CO2, or A-CO2 — in other words, “man-made” CO2 that is captured from power generation and industrial processes. In addition to the environmental benefits, there are two other drivers for making this switch from natural CO2 to A-CO2: the first is that some of the natural sources of CO2 used today for EOR are dwindling, and the second is that the push to sequester man-made CO2 is backed by tax credits and other government-backed incentives. No matter the CO2 sourcing, CO2-for-EOR requires pipelines to transport the CO2 from where it is produced to EOR sites. Today, we continue our series on the rapidly evolving CO2 market and the huge opportunities that may await those who pursue them.
Renewable diesel is a popular topic in the transportation fuel space, and for good reason. For one, RD provides a lower-carbon, renewable-based alternative to petroleum-based diesel; for another, it’s a chemical twin of and therefore a “drop-in” replacement for ultra-low sulfur diesel. But, most of all, there are the large financial incentives provided by California’s Low Carbon Fuel Standard, the U.S. Renewable Fuel Standard, the U.S. Biodiesel Tax Credit, and other programs, which can make RD production highly profitable. Driven by these factors, there’s a lot of renewable diesel production capacity under construction or on the drawing board: everything from greenfield projects to expansions of existing RD refineries to conversions of old-school refineries so they can make RD. Today, we put the spotlight on RD and discuss how it differs from biodiesel, how it’s produced, and the new RD capacity coming online in North America.
Hydrocarbons — mostly natural gas and coal — are still the energy source behind the lion’s share of electric power generation in the U.S. However, renewables like wind and solar are now the frontrunners when it comes to scheduled capacity additions. In fact, renewables account for about 70% of the total 37.9 gigawatts (GW) of new generating capacity under construction in 2021. Recent announcements such as final federal approval for the mammoth Vineyard Wind 1 project — by far the largest permitted offshore wind project in the U.S. to date — only bolster the view that wind power’s role in U.S. power generation will continue to grow through the 2020s. Today, we look at the surge in construction of onshore and offshore wind farms and what it means for the overall power generation mix.
With all the hype about hydrogen you hear these days, you’d think the gas was just discovered yesterday. But, of course, it’s been around for a while — like back to the Big Bang 13.8 billion years ago. It does a nice job powering the sun and, when combined with oxygen, provides another building block of life on our planet: water. And that’s not all. For decades, a lot of hydrogen has been used as industrial feedstock to produce low-sulfur refined products, ammonia, methanol, and other useful stuff. However, this hydrogen production isn’t “green,” the color code for the highly exalted hydrogen produced from zero-carbon sources. No, most of the hydrogen used today goes by the drab hue of “gray” and is generally ignored by the carbon-neutral buzz that permeates the decarbonization dialogue. It shouldn’t be disregarded, though. Over 13 Bcf/d of this gray hydrogen is produced on purpose or as a byproduct each day, more than the volumetric equivalent of all Permian natural gas production. And if the carbon dioxide produced along with that hydrogen is stored permanently underground, then gray hydrogen magically becomes “blue” — almost as good as green. Today, we begin an exploration of the gray hydrogen market, and how it has the potential to impact decarbonization goals far more than green hydrogen over the next decade.
With Environmental, Safety, and Governance (ESG) conscientiousness on the rise and the push to rein in greenhouse gas emissions gaining momentum by the day, many traditional players in the hydrocarbon sector are considering alternative energy sources to invest in. Two key questions they ask themselves when evaluating these options are: Does it make economic sense once you’ve factored in tax credits and other incentives, and can it be incorporated into North America’s existing energy infrastructure. Wind and solar power clearly fit the bill. So does renewable diesel, which also benefits from governmental programs and that it can be blended into petroleum-based diesel. Another alternative gaining traction is renewable natural gas, which is “produced” by capturing methane from landfills and wastewater treatment plants. Today, we discuss the potential and pitfalls of “the notorious RNG.”
We get that the primary focus for oil and gas producers, midstream companies, and refiners needs to be on the business side of things — the strategies and capital plans they develop and implement to survive and hopefully thrive, and the day-to-day decisions they make to keep things running smoothly — and that’s what we at RBN devote most of our time to as well. Still, it seems increasingly apparent that many of these same companies need to pay more attention to environmental, social, and governance issues, not only because ESG is a front-and-center concern of investors and lenders but because addressing these issues in the right way can help to improve a company’s operations and prospects. The environmental element of ESG typically gets the spotlight, at least for companies that produce, transport, or process oil and gas, but the social and governance parts are important too.
We get the sense that many hydrogen-market observers are looking for a silver bullet — the absolute best way to produce H2 cheaply and in a way that has an extremely low carbon intensity. If anything has become clear to us over the last few months, however, there isn’t likely to be an “Aha!” or “Eureka!” moment anytime soon. Rather, what we have seen so far in regard to hydrogen production has been a veritable smorgasbord of production pathways, with varying degrees of carbon intensity. While costs vary by project, it is also fair to say that a front-runner has yet to emerge when it comes to producing inexpensive hydrogen at scale. There is a silver lining though, if not a bullet, and that is the realization that there are many options when it comes to procuring environmentally friendly hydrogen. Today, we provide an update of currently proposed hydrogen projects.
Biodiesel has long constituted a small but stable portion of the diesel fuel diet in North America, its production being driven primarily by the U.S. Renewable Fuel Standard and Biodiesel Income Tax Credit (BTC). Produced from a variety of feedstocks, including soybean oil, corn oil, animal fats, and used cooking oils, biodiesel offers a low “carbon intensity,” or CI — a big plus in California and other jurisdictions with low carbon fuel regulations. The incentives for producing biodiesel are substantial, but there are two big catches with the fuel: a limited supply of feedstocks and properties limiting how much can be blended with petroleum-based diesel. Today, we continue our series on low carbon fuel standards with a look at biodiesel’s pros, cons, history, and prospects.
No doubt about it. The global effort to reduce emissions of carbon dioxide — the most prevalent of the greenhouse gases — is really heating up. Yes folks, CO2 is in the spotlight, and everyone from environmental activists and legislators to investors and lenders want to slash how much of it is released into the atmosphere. There are two ways to do that. First, produce less of it. That’s what the development of no- or low-carbon sources of power and the electrification of the transportation sector are intended to accomplish. The second way is to capture more of the CO2 that’s being emitted and make it go away, and the most cost-effective means to that end is sequestration — permanently storing CO2 deep underground, either in rock formations or in oil and gas reservoirs through a process called enhanced oil recovery, or EOR. Sure, there’s an irony in using and sequestering CO2 to produce more hydrocarbons, but the volumes of CO2 that could be squirreled away for eternity through EOR are enormous, and the crude produced might credibly be labeled “carbon-negative oil.” In today’s blog, we continue our look at the rapidly evolving CO2 market and the huge opportunities that may await those who pursue them.
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 the encore edition of today’s blog, we take a look at the possible intersection of natural gas, particularly RNG, and hydrogen.
There’s a fresh breeze blowing through the energy patch. Oil and gas companies seem to have turned a corner and are piling on the climate change bandwagon. They’re talking green, walking green, and many are in hot pursuit of government subsidies and tax breaks that are here today, with expectations that more incentives are on the way. Carbon dioxide is their primary target — it’s by far the most prevalent greenhouse gas and technologies already exist for permanently depositing captured CO2 deep underground. In fact, the U.S. is #1 in the world at this, accounting for about 80% of all the CO2 being stored globally. But it may surprise you to learn that much of the CO2 being squirreled away for eternity isn’t captured from industrial processes or exhaust. Instead, a lot of it comes from CO2 reservoirs in Colorado and New Mexico, tapped on purpose to bring vast volumes of CO2 to the surface. Why? So that CO2 can be put right back into the ground. Sound crazy? Well, it’s not. In the blog series we begin today, we explore the rapidly evolving CO2 market and the huge opportunities that await those with the ambition to pursue them.
When it comes to hydrogen regulation, there are two buckets. The first includes safety and environmental regulations related to building and operating facilities that produce, transport, store, and consume hydrogen. There’s not much mystery here, just a multitude of rules from various organizations in place to cover the physical side of the hydrogen industry. That said, as hydrogen use is expected to grow over time, this bucket of regulation is likely to expand and maybe morph. The second bucket includes rules that are designed to provide market structure and incentives for hydrogen. This bucket is mostly empty, though, and for hydrogen markets to succeed, it will need to be filled up. Put another way, hydrogen needs rules and incentives that make it clear the powers-that-be want hydrogen to be around and thriving. In today’s blog, we look at existing hydrogen regulations and highlights the gas’s need for further regulatory incentives and clarity.