A blast of Arctic air plunges the Midwest and Northeast into deep freeze. Already-low propane inventories result in supply shortages in local markets. Propane transport trucks move product hundreds of miles from storage hubs to replenish regional terminals as markets scramble to meet surging propane demand. Are we talking about the nightmarish polar vortex winter of 2013-14, when regional propane inventories were sucked down dangerously low and Conway, KS, propane prices skyrocketed to almost $5.00/gal? No. We are talking about now. This is a description of what is happening today in U.S. propane country –– that belt of northern states that depend heavily on propane for heating. But this is not 2013-14. Things have changed. So in today’s blog we’ll explore how the latest polar vortex could be quite different than that weather-driven crisis seven years ago.
The biggest news on the Permian natural gas infrastructure front in the past couple of months was surely the start-up of the 2-Bcf/d Permian Highway Pipeline (PHP), which began flowing gas in the fourth quarter of 2020 and officially entered full commercial service on New Year’s Day. Next among the headlines would be the late-January completion of a 1.8-Bcf/d expansion of the Agua Blanca pipeline system, which increased the capacity of the Delaware Basin-to-Waha network to a staggering 3 Bcf/d. Just as important though is that midstream companies active in the Permian have been completing a number of new gas processing plants in key production areas within both the Midland and Delaware basins, thereby supporting the continuing development of the U.S.’s premier crude oil production region. Today, we begin a short series on all the new gas-handling capacity coming online in the Permian.
It’s never easy in the commodity world, and despite oil prices comfortably above $50/bbl across the Permian, a new worry has come to the fore as we start the second month of 2021. No, it’s not a Reddit movement focused on the oil market, not even an OPEC+ action this time. The latest news that has wildcatters muttering through clenched teeth came from Washington D.C., where the Biden administration recently announced a pause on leasing federal lands for oil and gas development. While it’s far too early to discern what this decree — or future actions — will mean for the Permian, we get the sense that the headlines aren’t capturing the nuances of drilling activity in West Texas and southeastern New Mexico. In our view, at its worst, a long-term ban on drilling on federal lands would produce some clear winners and losers, while the near-term impact is potentially just a ripple in the ocean. Today, we examine what the latest drilling data from the Permian tell us about the possible outcomes of the new administration’s recent actions.
Canada may be the land of backyard hockey, lacrosse, and loonies, but Canadians have many similarities to folks in the U.S. The same holds true for Canada’s refining sector, which like its American counterpart has been adjusting to big changes in domestic crude oil production, a declining need for imported oil, and, most recently, a period of severe refined-product demand destruction caused by the pandemic. What Canadian refiners lack, though, is the attention they deserve. After all, nearly 2 MMb/d of crude oil flows through their 17 refineries. And, by the way, they now turn to U.S. producers for virtually all their oil imports — a far cry from where things stood before the Shale Era. Today, we kick off a three-part series that examines Canada’s refining sector in greater detail.
For many midstream companies, the experience of the past 12 months has been akin to falling down a flight of stairs. The fortunate sit at the bottom — stunned a bit, with arms and legs akimbo — and gradually determine that they’re generally alright, and that they’ll be more careful next time. The less lucky? They’re banged up and bloodied, and maybe headed to the ER and, after that, weeks of physical therapy. But were the “fortunate” really just lucky? Or were they in better shape, more athletic, more prepared for any eventuality? And what about companies when they’re hit hard with a sudden, negative shift in market conditions, out of the blue? Today, we discuss highlights from the second part of East Daley Capital’s 2021 edition of Dirty Little Secrets report, which examines the assets and outlooks of 26 leading midstream companies. We’ll focus on two representative midstreamers: Energy Transfer and EnLink Midstream.
Despite Northeast natural gas producers battling stiff headwinds last year — the lower rig count, sub-$1.50/MMBtu spot prices, lower demand, and price-responsive shut-ins in the shoulder periods — Northeast gas production volumes still managed to hit record highs in 2020, both for daily output as well as on an annual average basis. Regional production flows averaged 32 Bcf/d in 2020, up from 31.3 Bcf/d in 2019, and daily pipeline flow data shows volumes sustained year-on-year gains through January 2021. Today, we continue our series on the Northeast gas market fundamentals, this time with a sharper focus on production trends.
It’s a well-known fact in the energy and petchem industries that ethane is either “rejected” into natural gas or used as a feedstock for steam crackers. But piping ethane to NGL hubs, crackers, or export docks only makes sense if it’s economically viable or if there’s no other alternative, and ethane rejection has its limits — ethane has a 70% higher Btu value than methane, and too much rejection can make pipeline gas “too hot” for downstream consumers. Well, there’s another way to make economic use of ethane: burn it — typically in a blend with natural gas — to generate electric power. Burning ethane for power is super-rare though, and only happens in places where the lightest of all NGLs is so abundant that folks don’t know what to do with it. The Marcellus/Utica region in Appalachia for one, and now — just maybe — the Bakken Shale in western North Dakota. Today, we discuss plans for what would be only the second major U.S. power plant to be fueled by a blend of natural gas and ethane.
Based on the response we received to our first-ever hydrogen blog last fall, it’s fair to say we didn’t waste this space on a fringe subject. To be honest, the level of interest in hydrogen far exceeded our expectations, and suggested that we might have even been a little bit late to the party — but fashionably so, if you ask us. In the weeks since then, we’ve spent a fair amount of time distilling the tremendous amount of news flow and reading material that was either sent our way or popped up in the daily news feeds. You could go a lot of different directions with hydrogen and it’s still very easy, in our view, to get lost in the forest of green energy technology. So, as we are wont to do, we have stuck to our simple approach of tackling this fuel just like we do with hydrocarbons, and we are first turning our attention upstream. Today, we continue our series on hydrogen with a look at the top production methods for the fuel.
Things move fast in today’s propane market. Two weeks ago, Mont Belvieu propane was going for almost 95 cents/gal, up 86% from the mid-November price of only 51 c/gal. Midcontinent propane assessed in Conway, KS, spiked even higher, doubling over the same time frame to more than a dollar per gallon. But last week some air came out of the balloon, with Mont Belvieu and Conway prices pulling back to the low 80s. That didn’t last long either. This week, Mont Belvieu is back up to the high 80s c/gal. What gives? Is the market simply being bounced around by vacillating weather forecasts? Or is there more to it than that? Could it be that we are seeing symptoms of an export-driven transformation that is making propane markets behave quite different than they have in the past? Today, we’ll consider these questions and where the propane market may be headed in 2021 and beyond.
After a two-year reprieve from a nearly decade-long period of severe pipeline constraints and debilitating prices, Northeast natural gas producers are again headed for a constraint-driven market in the next five years. Appalachian supply prices last year weakened relative to national benchmark Henry Hub, reversing the gains of the past few years, and fell to historic lows as oversupply conditions prevailed and at times strained available takeaway capacity. All that despite the rig count hitting a four-year low and shale producers’ best — even unprecedented — efforts to respond to low prices with short-term production cutbacks during the shoulder seasons. So what happens when rig counts and production recover in the coming years? How long before pipeline constraints worsen and what are the prospects for new pipeline development? Today, we begin a blog series detailing recent supply-demand trends in the region and our outlook for 2021 and beyond.
Sure, there was at least some hope among Keystone XL’s supporters that President Biden might back away from his promise to kill the much-maligned crude oil pipeline project. After all, KXL developer TC Energy had done all it could to make the 1,210-mile project more palatable to the incoming administration by making Canadian First Nation groups partners in the project, reaching a favorable labor agreement with the four U.S. unions that would build the pipeline, and, most recently, committing to invest in renewable energy to power KXL’s pumps and other equipment. But it wasn’t enough, and now, with Biden’s decision to revoke the project’s Presidential Permit, it appears that the Alberta-to-Nebraska pipeline is all but dead, and that Western Canada will need to get by without its 830 Mb/d of southbound capacity. The looming question now is, what does that mean for Alberta’s producers — particularly those that have signed up for more than 500 Mb/d of space on KXL? Today, we discuss what’s ahead.
In the past few years, the Netherland’s Title Transfer Facility (TTF) overtook the UK’s National Balancing Point (NBP) to become the premier gas trading hub in Europe. TTF has gained favor over NBP largely due to its location closer to more markets, supply pipelines, plentiful storage, and also the Netherlands’ Gate LNG import terminal, which has become paramount given Europe’s growing need for imported gas. As imports have grown, so has TTF in terms of its volume and its liquidity — a trend that is expected to continue as the European gas market evolves. TTF now shares the stage with Henry Hub and the Japan Korea Marker (JKM) as one of the key global benchmarks for LNG and natural gas. Though traders use TTF as a price index for LNG, much like its cross-Atlantic peer, Henry Hub, TTF is also heavily influenced by regional pipeline gas and storage levels. Today, we’ll look at the history of Europe’s premier natural gas index and the fundamentals affecting it.
There are no absolute certainties in the energy industry, but one thing a lot of people are betting on is increasing demand for LNG in Asia. A long list of countries there — China, Japan, and South Korea among them — have been shifting from nuclear and coal-fired power generation to natural gas, and as they do, their demand for LNG will be mind-blowing. The U.S. has emerged as a major supplier, but shipping LNG from the Gulf Coast to Asia involves either transiting the busy and costly Panama Canal or taking much longer routes through the Suez Canal or around the Cape of Good Hope. All of that has helped spur interest in developing LNG export terminals in western Mexico that would pipe in and liquefy Permian gas, then ship it straight across the Pacific Ocean. Today, we discuss plans for a large-scale liquefaction/export project aimed squarely at Asian buyers.
U.S. crude oil imported from Western Canada averaged almost 3.6 MMb/d in the first 10 months of 2020 and accounted for 60% of total imports over the period. That’s some growth! Ten years ago, Canada was sending less than 2 MMb/d south and contributing only 21% of total U.S, import volumes. Alberta oil sands producers are planning for more production and export growth through the 2020s, with most of the incremental volumes bound for Midwest and Gulf Coast refineries and export docks. If that happens — and there’s no certainty it will — more north-to-south pipeline capacity through the U.S. heartland will be needed. Today, we continue our series on the efforts to expand or reverse crude oil pipelines between the U.S./Canada border and the Gulf of Mexico.
Western Canada’s crude oil production, like in many other regions of the world during the spring of 2020, had to pull back sharply in response to the price and demand chaos brought about by COVID-19. By the end of 2020, oil production almost everywhere remained much lower or was being carefully managed to avoid creating another supply glut. In contrast, production in Western Canada has almost fully rebounded, and is being primed to increase to what could be all-time highs this year. With Alberta’s oil sands producers renewing their role as the long-standing driver of oil supply growth and the recent suspension of production limits in the province, the stage is set for us to review the most recent oil supply developments and future growth prospects.