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.
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Daily energy Posts
Nearly 300 million COVID vaccine doses have been administered in the U.S., and normal life is returning to public places across America. Actual fans are replacing cardboard facsimiles in ballpark seats, corner pubs and corner offices are filling up, and family gatherings now feature hugs instead of half-inch squares on a Zoom screen. And another powerful antidote, in the form of higher oil prices, has spurred a significant revival in the fortunes of the pandemic-battered upstream oil and gas industry. The spring-of-2020 crude oil price crash hit the E&P sector like a tsunami, shattering capital and operating budgets, upending drilling plans, eviscerating equity valuations, and raising concerns about whether some companies could generate sufficient cash flow to keep the lights on. Remarkable belt-tightening allowed most producers to survive, and the swift rise of oil prices beginning last fall dispelled the COVID clouds. But the recovery in profitability and cash flow generation was slow. Today, we review the dramatic surge in E&P profits and cash flows in the first quarter of 2021.
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.
Much like the world at large, the crude oil market has been healing from the ravages of COVID-19. Overall, market conditions are far better than they were in April 2020, when global oil consumption, crushed by pandemic-related lockdowns, slumped to 80.4 MMb/d, a 17% decline from the start of last year and a 20% drop from April 2019. Demand has been rebounding in fits and starts for a full year now — recovering from downturns is what markets do. But this recovery has gotten a big assist: 10 members of the Organization of the Petroleum Exporting Countries (OPEC), acting in concert with 10 non-members, have restrained crude oil production in a program unprecedented in scale and duration. Now, oil prices are high enough to revive activity by some producers outside the so-called OPEC+ group. For at least the rest of this year, in fact, the market looks like a steel-cage match between crude supply subject to coordinated management and supply governed only by raw market signals. Today, we look at oil-market projections from three important agencies and estimate demand for oil not supplied by the OPEC+ exporters.
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.
Over the past year, we have witnessed a sort of slow-motion meltdown among the second wave of North American LNG export projects. Appetite for new LNG expansions was already waning due to oversupply even before the pandemic affected demand, but COVID-19 brought project developments to a standstill. Offtake agreements have expired, final investment decisions (FIDs) delayed, and projects have lost funding or been officially put on hold or even cancelled. Just one project, Sempra’s ECA LNG in Mexico, was able to reach an FID last year, and with the pandemic still raging, for a while it looked as if that would be the last project in North America to take FID in the foreseeable future. It’s abundantly clear that many more of the remaining proposed projects will be postponed indefinitely, and probably never be built at all. However, the news isn’t all bad. With the worst of COVID-19’s impacts on international gas demand appearing to be over and the ongoing extended run of high global gas prices, all eyes are back on the second-wave projects that are in various stages of pre-FID development. The pandemic may have forced a culling of the proposed projects, but those near the top now have a clearer path ahead. In fact, several projects could realistically achieve FID in the next few years. Today, we begin a short series providing an update on the second-wave projects.
It’s not often these days that you read about gas markets in the San Juan Basin. In fact, the subject was probably never much of a hot topic because the San Juan has been something of an afterthought when it comes to Western gas markets, just a stop on the road between the Permian and markets along the West Coast and in the Rockies. However, those Western gas markets are setting up to be quite interesting this summer, as is the Waha gas market in the Permian, and understanding the mechanics of the San Juan is just one piece of the overall Western puzzle. In today’s blog, we take a look at the far-flung but increasingly interesting markets west of the Permian Basin.
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.
IMO 2020, the mandate that ships plying most international waters slash their sulfur emissions starting in January of last year, was only another step in the International Maritime Organization’s long-running effort to ratchet down the shipping industry’s environmental impact. The group’s next focus, as you might expect, is reducing shippers’ carbon footprint — while no specific rules have been set, the IMO in 2018 laid out the goal of cutting ships’ carbon dioxide emissions by 40% from their 2008 levels by 2030. One way to move toward that goal would be fueling more ships with LNG, which emits 20-25% less CO2 than very low sulfur fuel oil. But as we discuss in today’s blog, shippers could augment those emission reductions by moving from the LNG trade’s traditional point-to-point model to optimization through cargo swapping.
Over the next few months, a variety of market players — crude oil producers, midstreamers, refiners, and exporters — will be making preparations for one of the most anticipated infrastructure additions in recent years. Actually, it’s not technically new; it’s the long-planned reversal of the 632-mile, 40-inch-diameter Capline, which for a half-century transported crude north from St. James, LA, to Patoka, IL. Line-filling will begin this fall and Capline will start flowing south from Patoka in January 2022, providing Western Canadian and other producers with new pipeline access to Gulf Coast markets. Upstream of Patoka, the impending reversal has been spurring the development of new pipeline capacity to supply the soon-to-be-southbound Capline, and in Louisiana, refiners and exporters have been making plans for the crude that will be flowing their way into St. James. Today, we discuss the broad impacts of the “new” Patoka-to-St.-James pipeline.
Today is a sad day for the world of oil tankers. Unless a miracle happens by 10 a.m. local time at the Hawaii Department of Transportation's Harbors Division, the last surviving iron-hulled, sail-driven oil tanker is headed to Davy Jones’ Locker. The once-proud, four-masted, 143-year-old windjammer will soon be scuttled by deliberately sinking her at sea off the shores of Honolulu. How could things have come to this? In today’s blog, we’ll take a trip down memory lane to explore how a spectacular, fully rigged oil tanker could have survived for so long, plying the oceans for this author’s former employer, only to be betrayed in her final years.
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.
The Montney Formation in British Columbia and Alberta is exclusively responsible for the turnaround in Western Canada’s natural gas production in the past decade. Gas production in the Montney — a vast area with extraordinary reserves — has doubled in that time, with most of that growth coming from the BC side of the formation. This phenomenal growth story stems from a few key factors, including steadily improving gas well performance and increasing wellbore length, coupled with access to an established network of gas pipelines. Today, we delve into what has made BC’s portion of the Montney such as standout.
On the surface, it may seem that the LNG market has normalized after the past year’s tumult, and it’s true that many of the day-to-day disruptions that plagued LNG offtakers and operators have subsided. Mass cargo cancellations are a distant memory, and U.S. LNG exports have been flowing at record levels. Global demand has recovered, and buyers are back to worrying more about what they normally worry about: storage refill and securing enough supply for the next winter. However, in other ways, the pandemic and the more decisive shift toward decarbonization measures in many ways have fundamentally changed how deals for future LNG development will get done. Today, we look at what the global initiative to reduce greenhouse gas emissions will mean for LNG project financing.
Appalachia natural gas producers hoping to get a big boost in pipeline takeaway capacity later this year were dealt some bad news recently. On May 4, Equitrans Midstream officially pushed back the in-service date for the already-delayed Mountain Valley Pipeline. The 2-Bcf/d, greenfield project is the last of the major planned expansions that would add substantial capacity from the prolific Appalachia gas-producing region and help stave off severe seasonal pipeline constraints, at least in the near- to midterm. Previous guidance had it coming online late this year, but Equitrans said it is now targeting start-up in the summer of 2022, pending water and wetland crossing permit reviews. The news is far from surprising considering the numerous regulatory and legal challenges midstream projects, including MVP, have previously faced in the Northeast over the past decade or so. But the resulting uncertainty leaves Northeast producers in a tight spot. In today’s blog, we will consider the implications of the MVP delay for Appalachia’s outflows.
A lot of people know that Permian natural gas prices have spent many days in negative territory over the last few years, only to skyrocket over $100/MMBtu during the Deep Freeze in February. Those events were mostly viewed as transitory, driven by a chronic lack of pipeline capacity in the former case and a crazy round of arctic weather in the latter. It may come as a surprise to hear that forward basis prices for natural gas in the Permian are trading at a premium to Henry Hub for at least some months over the next year or so. How could it be that gas from a supply basin way out in West Texas, where gas is considered a byproduct, trades at a premium? The answer lies in the key infrastructure changes expected in the weeks ahead and a premium in forward basis for the Houston Ship Channel gas market. How long the Texas premiums will last depends on Permian gas production, which is starting to take off again. Today, we aim to explain the latest developments in Permian and Texas natural gas markets.