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.
Appetite for new North American LNG export capacity had been waning already when COVID-19 brought it to a screeching halt. The global gas market was expected to be well-oversupplied through the mid-2020s as U.S. liquefaction capacity additions, combined with supply growth from Australian LNG projects, were far outpacing any increase in demand. However, the past year or so has proven how quickly things can swing from oversupplied to undersupplied. The extended run of high global gas prices is bringing renewed interest in expanding North American LNG export capacity. Although COVID dashed the prospects of many LNG projects, a handful have emerged from the morass of the past year stronger and with a clearer path to FID than ever before. Those that remain will be better positioned if they can navigate four emerging trends that are key for offtaker agreements in the post-COVID era: shorter contract terms, increased pricing or deal-structure diversity, reduced environmental impact, and a prioritization of brownfield expansions or phased greenfield projects. Today, we conclude the series on the status of the second wave of LNG projects.
In the world of public equities, nothing speaks relevance like a PowerPoint slide in the earnings call and conference decks that companies put together for analysts and investors. If a topic’s not important, then it probably didn’t “make the deck” — or even the appendix, for that matter. As consultants, we at RBN are familiar with this concept and we’ve been watching for some time to see just how long it would take hydrogen, one of our favorite recent subjects, to make its way into the slide-deck line-ups at some of the largest energy companies. Well, that time has arrived, with two energy stalwarts prominently featuring 2021’s darling subject over the last few days. However, with a new topic comes a need to put things in context. No problem, we are here to help on that. Today, we continue our series on H2 with a look at some recent hydrogen-focused slides from ExxonMobil and Enterprise Products Partners.