Permian crude oil markets are getting interesting again, with triple-digit prices making daily headlines and boosting producers’ cash flows. But there have been few parties in the Permian oil midstream space. There, excess long-haul capacity has been the story for some time, a situation that became more pronounced when Wink-to-Webster (W2W) — the last of the new greenfield pipelines to the Texas Gulf Coast — started up earlier this year. There’s so much capacity in place that price spreads have remained tight and competition for barrels has been fierce. That said, there’s a positive story flying under the radar in the Permian oil markets. One of the new pipelines that started up out of the Permian in 2019 is now full. That may surprise some folks, kind of like when the Texas A&M Aggies pulled in the #1 football recruiting class in the country earlier this year. While Alabama’s coach is apparently still trying to swallow that news, you’re not likely to find yourself doubting the ability of a newbuild to get full in today’s competitive environment. At least you won’t after we tell you the story of the EPIC Crude Pipeline, which we do in today’s RBN blog.
Daily Energy Blog
Just like there’s room for Amazon and Etsy in the e-commerce world — one for mass marketers and the other for artisans — there’s room in the energy industry for both large- and small-scale LNG companies and plants. By focusing on the development of niche markets and scaling their production and distribution operations accordingly, a number of smaller (but growing) players in the LNG space have been making natural gas available to a surprising variety of customers: from industrial, oil-and-gas and mining companies to rocket launchers, Caribbean resorts and island utilities. ESG is a big driver — the LNG supplied often replaces diesel, fuel oil and propane, which can have bigger carbon impacts. In today’s RBN blog, we continue our series on small-scale LNG with a look at a cross-section of key players in this space and how they’ve been growing their businesses.
Natural gas futures prices have rocketed to 14-year highs in the past couple of months — during the lower-demand spring months, no less — and they are now trading at 3x where they were at this time last year. The CME/NYMEX Henry Hub futures for June delivery shot up to a high of $9.40/MMBtu in intraday trading last Thursday, the highest level we’ve seen since summer 2008, before expiring at $8.908/MMBtu, nearly $6 (~200%) higher than the June 2021 expiration settlement at just under $3/MMBtu. The newly prompt July futures retreated ~17 cents Friday to about $8.73/MMBtu, but that’s still nearly triple where July futures traded last year. It’s safe to say the low fuel cost of gas-fired power generation that defined the Shale Era has evaporated. Historically, at today’s sky-high prices, gas would have given up market share to coal in the power sector. However, the coal market is battling its own supply shortage and Eastern U.S. coal prices are at record highs. What does that mean for generation fuel costs and fuel switching? In today’s RBN blog, we break down the math for comparing gas vs. coal fuel costs.
Supply chains are screwed up. Inflation has returned with a vengeance. And the politics of energy in the U.S. are all over the place, with demands for energy companies to do more today even as plans are being made to phase them out of existence tomorrow. This is today’s world — traditional energy markets learning to live with the impact of renewables, decarbonization and sustainability initiatives, while at the same time dealing with the aftermath of a pandemic and the consequences of a war with a totally uncertain trajectory — and it’s likely to be with us for a long time to come. That was the focus of our Spring 2022 School of Energy and it’s the subject of today’s RBN blog. Warning: Today’s blog includes a couple of blatant plugs for a newly available replay of our recent conference in Houston.
Supply chains are screwed up. Inflation has returned with a vengeance. And the politics of energy in the U.S. are all over the place, with demands for energy companies to do more today even as plans are being made to phase them out of existence tomorrow. This is today’s world — traditional energy markets learning to live with the impact of renewables, decarbonization and sustainability initiatives, while at the same time dealing with the aftermath of a pandemic and the consequences of a war with a totally uncertain trajectory — and it’s likely to be with us for a long time to come. That was the focus of our Spring 2022 School of Energy and it’s the subject of today’s RBN blog. Warning: Today’s blog includes a couple of blatant plugs for a newly available replay of our recent conference in Houston.
The pace of multibillion-dollar M&A activity among oil and gas producers may have slowed a bit from 2020 and 2021, but big deals are still happening. Just last week, publicly held Centennial Resources Development and privately held Colgate Energy Partners III announced plans for a $7 billion “merger of equals” that will combine two midsize E&Ps in the Permian’s Delaware Basin to form one of the area’s larger producers. Each of the companies brings similar and complementary production assets to the deal, as well as corporate leaders very much in sync about the significance of scale in today’s increasingly concentrated upstream sector — and the importance of returning a big chunk of free cash flow to investors. Speaking of investors, an extraordinary 12% stake in the combined Centennial and Colgate will be held by the pro forma company’s management — that’s about 12x the norm among its peers. In today’s RBN blog, we discuss the Centennial/Colgate merger and what’s driving the ongoing consolidation in the U.S.’s most prolific hydrocarbon play.
In case you hadn’t noticed, many of the largest, most successful companies in the U.S. and Canada are placing big bets on the energy transition. Take “blue” hydrogen, which is produced by breaking down natural gas into hydrogen and carbon dioxide and capturing and sequestering most of the CO2, and blue ammonia, which is made from blue hydrogen and nitrogen. Last fall, Air Products & Chemicals announced a multibillion-dollar project in Louisiana, and now it’s a joint venture of Enbridge and Humble Midstream, which is planning a large, $2.5 billion-plus blue hydrogen/ammonia project down the Texas coast, at Enbridge’s massive marine terminal in Ingleside. In today’s RBN blog, we discuss what we’ve learned about the companies’ plan.
U.S. diesel inventories are at their lowest level for May since 2000 and East Coast stocks recently hit their lowest mark for any week or month since the EIA started tracking them in 1990. Crack spreads for diesel — and, more recently, for gasoline — have gone parabolic, giving refiners the strongest financial signal ever to produce more diesel and gasoline as we enter the summer travel season. More jet fuel too. The problem is, U.S. refineries already are running flat-out. And Europe? It’s facing big cuts in crude oil and refined-products imports from Russia as well as much higher prices for — and possible shortages of — oil and natural gas, the latter being the primary fuel for operating refinery hydrocrackers, which upgrade low-quality heavy gas-oils into high-quality diesel, gasoline and jet. It’s a mess, and not easily fixable, as we discuss in today’s RBN blog.
At the most basic level, carbon-capture technology is not new, but it has attracted a lot more attention in recent years amid discussions about how best to transition to a net-zero world by 2050. Efforts to ramp up carbon capture have faced a number of hurdles, however, including the difficulty in capturing some emissions at the point where they’re generated. That’s where direct air capture (DAC) — which essentially works as a large-scale air filter and can be located just about anywhere — comes into play. In today’s RBN blog, we take a closer look at the still-emerging technology and its limitations, a project in Iceland that is the largest currently in operation, and plans by Occidental Petroleum to make Texas home to the world’s largest DAC facility.
The race is heating up for building natural gas pipeline takeaway capacity out of the Permian. Associated gas production from the crude-focused basin is at record highs this month and gaining momentum, which means that without additional pipeline capacity, the Permian is headed for serious pipeline constraints — and potentially negative pricing — by late this year or early next, which would, in turn, limit crude oil production growth there. Midstreamers are jockeying for the pole position to move surplus gas from the increasingly constrained basin to LNG export markets along the Gulf Coast. One of the contenders, Matterhorn Express Pipeline (MXP), a joint venture (JV) between WhiteWater, EnLink Midstream Partners, Devon Energy and MPLX, announced its final investment decision (FID) late yesterday. In today’s RBN blog, we provide new details on the greenfield project.
In the nearly 60 years since its inception, the LNG industry has changed significantly. Once a market in which cargoes were sold under long-term, point-to-point contracts in dedicated ships, it has evolved into one in which destination flexibility accounts for an increasing share of LNG trade, with more volumes being sold under short- and medium-term contracts. The changes reflect a trend toward the increasing commoditization of LNG, with the similarities between the LNG and crude oil markets becoming apparent. In today’s RBN blog, we look at the differences in how the oil and LNG markets have developed, whether LNG might achieve the same commodity status as oil, and why the major market players may not want LNG to follow the path of its older cousin.
Hydrogen has been touted as a zero-emissions vehicle fuel, as a clean power generation source and, more generally, as a big part of the move toward decarbonization. Much of the current interest in hydrogen is its possible role as a grid-scale energy storage solution — one that might help support the growth of wind and solar renewable power generation. However, if we convert renewable energy to hydrogen, how do we store it? And how do we get it to end-use markets? As appealing as a hydrogen solution may be, these questions require thoughtful answers given some of hydrogen’s unique characteristics. With this in mind, a new set of stakeholders are beginning to take an interest in the natural gas pipeline network with an eye toward repurposing it to include hydrogen blends. In today’s RBN blog, we look at some reasons why hydrogen blending is being discussed and even being implemented on a limited basis in Europe and North America.
It took a while, but domestic air travel is finally returning to pre-pandemic levels and international travel to and from the U.S. is showing signs of recovering too. As a result, U.S. production of jet fuel has been rising steadily in recent months and, since most jet fuel needs to be transported long distances from refineries to airports, so have flows of jet fuel on U.S. refined products pipelines. All of that is good news, but as pipeline flows rise, so may the stresses on some elements of the U.S. refined products/jet fuel distribution network, including pipelines, storage facilities and “last mile” jet fuel delivery trucks. In today’s RBN blog, we continue our look at jet fuel, this time with a look at the extensive web of U.S. refined products pipelines.
Since the first OPEC oil embargo nearly a half-century ago — and more recently with Russia’s invasion of Ukraine — energy producers and consumers alike have learned important lessons about the significance of energy commodity sourcing. It all comes down to this, really: (1) know what you’ll need going forward; (2) diversify your sources of supply, focusing on suppliers who are reliable and friendly; and (3) don’t screw up by becoming overly dependent on suppliers who could prove to be sketchy. For decades, the industry’s focus was on oil and gas — which is still critical, as Europe knows all too well. But as policymakers attempt to transition to renewables and electrification, a whole new set of commodity-supply concerns is coming to the fore. In today’s RBN blog, we discuss the challenges associated with securing the key materials required to build the machinery of the energy transition.
Electric vehicles (EVs) in the U.S. may be at a turning point, with high gasoline prices prompting would-be car buyers to give them a second look — or a first look, in many cases. EV adoption has been slow to pick up speed in the U.S. for a variety of reasons, including the lack of a nationwide charging network and concerns about “range anxiety.” But a major factor has always been that gasoline-fueled cars have been cheaper to purchase and operate than EVs. The recent run-up in gasoline prices, amplified by Russia’s invasion of Ukraine, has changed the math in those comparisons, at least in the short-term. Is the pace of EV adoption about to accelerate, or will trends in gasoline and electric power prices put the transition into cruise control, or even neutral? In today’s RBN blog, we look at how forecasts for power and gasoline prices might shape the conversations around EVs through 2030.
