The demand for ethane by Alberta’s petrochemical industry has experienced a slow expansion in the past 20 or so years. However, that demand is likely to increase sharply by the end of the decade now that Dow Chemical has sanctioned a major expansion at its operations in Fort Saskatchewan, AB, that will more than double the site’s ethane requirements. As we discuss in today’s RBN blog, this will call for an “all-hands-on-deck” approach to increasing Alberta’s access to ethane supplies from numerous sources. 

Think energy markets are getting back to normal? After all, prices have been relatively stable, production is growing at a healthy rate, and infrastructure bottlenecks are front and center again. Just like the good ol’ days, right? Absolutely not. It’s a whole new energy world out there, with unexpected twists and turns around every corner — everything from regional hostilities, renewables subsidies, disruptions at shipping pinch points, pipeline capacity shortfalls and all sorts of other quirky variables. There’s just no way to predict what is going to happen next, right? Nah. All we need to do is stick our collective RBN necks out one more time, peer into our crystal ball, and see what 2024 has in store for us. 

Rumors about potential oil and gas mergers are always swirling, but the announcement of ExxonMobil’s record-breaking deal to acquire Pioneer Natural Resources a couple of weeks ago generated a fever pitch of speculation about potential matchups. In the past week, we’ve seen media reports of possible courtships between Devon Energy and Marathon Oil and then Chesapeake Energy and Southwestern Energy. However, it was Chevron that shocked the oil patch by swiping right on former integrated oil company Hess Corp., opting for a $60 billion acquisition of an E&P with no Permian Basin exposure. In today’s RBN blog, we analyze the drivers and implications of what is now the second-largest U.S. upstream transaction ever. 

Even now, three-plus years after the start of the oil and gas industry’s biggest consolidation in a quarter century, hardly a month goes by without another major M&A announcement. Just this week, Civitas Resources said it will acquire acreage and production in the Permian from Vencer Energy for $2.1 billion. The primary drivers of these deals — many of which are valued in the billions of dollars — are clear. Among other things, E&Ps are seeking scale and the economies of scale that come with it. They also have come to believe that it makes more sense to grow production through M&A than through aggressive capital spending. And, for some producers not yet involved in the all-important Permian, acquiring even a smaller E&P there provides a foothold to build on. In today’s RBN blog, we discuss highlights from our newly released Drill Down report on the past 12 months of upstream M&A activity in the U.S. oil patch.

Over the past four years, Energy Transfer (ET) has completed several major acquisitions, all aimed at giving the company the additional size and reach it will need to compete in an increasingly consolidated midstream sector. On Wednesday, ET announced one of its biggest purchases yet: a $7.1 billion deal to acquire Crestwood Equity Partners, which has extensive gathering and processing assets in the Permian, Powder River and Williston basins, as well as NGL terminal and storage facilities east of the Mississippi. In today’s RBN blog, we look at how the addition of Crestwood’s holdings will extend ET’s value chain and complement its fractionation assets at Mont Belvieu and its export capabilities at both its Nederland and Marcus Hook terminals.

With ever-increasing volumes of Permian crude oil being exported and the recent inclusion of WTI Midland in the assessment of Dated Brent prices, the issue of iron content — especially in some Permian-sourced crude — is coming to the fore. This has become such a point of emphasis for exported light sweet crude because many less complex foreign refineries do not have the ability to manage high iron content adequately. Iron content that exceeds desirable levels could have far-reaching repercussions, from sellers facing financial penalties for not meeting the quality specifications to marine terminals being excluded from the Brent assessment if they miss the mark. It’s a complicated issue, with split views on what causes the iron content in a relatively small subset of Permian oil to be concerningly high — and how best to address the matter. In today’s RBN blog, we look at iron content in crude oil, why it matters to refiners, how it affects prices, and what steps the industry is taking to deal with it.

It would be an understatement to say we’re sensing a trend here. Over the past couple of years, there’s been an absolute frenzy of producer M&A activity in the Permian, much of it involving big E&Ps getting bigger and private equity cashing in on assets they’ve been developing since the 2010s. The latest multibillion-dollar deal involves Ovintiv, whose recently announced plan to acquire the Midland Basin assets of three EnCap Investments-backed producers will nearly double Ovintiv’s oil and condensate output in West Texas, lower its per-barrel production costs, and add more than 1,000 well locations to its inventory. Oh, and via a separate but related deal, Ovintiv will exit the Bakken by selling its assets there to another EnCap affiliate. In today’s RBN blog, we look at what the M&A artist formerly known as Encana is up to.

The pandemic-induced shackles on U.S. E&P capital spending were shattered by rising commodity prices in 2022, and total investment for the 42 producers we follow rose a dramatic 54% over 2021. But E&Ps haven’t abandoned the fiscal discipline or focus on cash-flow generation that allowed them to survive COVID-related demand destruction and resuscitate investor interest. Their 2023 capital budgets generally sustain the pace of Q4 2022 spending and reflect a modest 17% increase over full-year 2022. However, commodity price trends and changes in investment opportunities have resulted in significant shifts in the allocation of the total investment among the major U.S. unconventional plays. In today’s RBN blog, we’ll analyze 2023 capital spending, region by region.

Buoyed by still-elevated crude oil, natural gas and NGL prices — and discipline on capital spending and production growth — U.S. E&Ps have been generating unprecedented cash flow and using much of that bounty to reduce debt, increase dividends and buy back shares. A number of producers have also been investing some of that cash to expand their holdings, mostly to complement their existing acreage in the Permian and other plays and thereby allow for increased efficiency and, in many cases, longer laterals. Few have been doing more in this regard lately than Devon Energy, the Oklahoma City-based E&P, which completed a big bolt-on acquisition in the Bakken in late July and just followed that up with a plan for an even bigger buy in the Eagle Ford. In today’s RBN blog, we look at the company’s strategy.

Extreme blizzard conditions wreaked havoc on North Dakota energy infrastructure last weekend, taking offline as much as 60% of the state’s crude oil production and more than 80% of natural gas output, and leaving utility poles and power lines strewn across the landscape. On the gas side, the unprecedented supply loss is having a never-before-seen impact on regional and upstream flows and storage activity. It is also compounding maintenance-related production declines in other basins, leaving Lower 48 natural gas output at its lowest since early February. Moreover, the extent of the storm-related damage to local infrastructure could prolong the supply recovery. In today’s RBN blog, we break down the aftereffects of the offseason winter storm on regional gas market fundamentals.

So far, most of the merger-and-acquisition activity among crude-oil-focused producers in the COVID era has occurred where you would expect it: the Permian, which seems to dominate almost every discussion about the U.S. energy industry. More recently, though, there has been an uptick in E&P consolidation in the Denver-Julesburg Basin in the Rockies and, earlier this month, in the Bakken. There, Whiting Petroleum and Oasis Petroleum — two once-struggling producers — have agreed to a merger of equals that will create the Bakken’s second-largest producer and the largest pure-play E&P. In today’s RBN blog, we discuss the companies’ stock-and-cash deal, which will result in a yet-to-be-renamed entity with an enterprise value of about $6 billion.

Trans Mountain Pipeline, the only pipeline that connects crude oil production areas in Alberta to Canada’s West Coast and the U.S. Pacific Northwest, has started to resume operations after a three-week shutdown. The pipeline closure — the longest in TMP’s 68-year history — began November 14 after major flooding exposed portions of the 300-Mb/d conduit, which also carries some refined products. Fortunately, Trans Mountain did not suffer any severe damage, breaks, or spills, and its operators were able to initiate a phased restart on December 5 at reduced pressures. Full service is expected to be restored soon. So what happens when a primary source of crude oil to five refineries — four in Washington state and one in British Columbia — is removed from service with little notice? In today’s RBN blog, we discuss the impacts.

The U.S. oil and gas industry’s upstream sector has seen more than its share of mergers and acquisitions in the year and a half since COVID-19 put energy markets on a wild roller coaster. ConocoPhillips buying Concho Resources and then Shell’s Permian assets. Chevron snapping up Noble Energy. Pioneer Natural Resources acquiring Parsley Energy. And yesterday’s big news: Continental Resources’ planned purchase of Pioneer’s assets in the Permian’s Delaware Basin. It’s not just hydrocarbon producers that are consolidating and expanding, however. There’s also been a flurry of large-scale M&A activity in the midstream sector, mostly involving oil and gas gatherers in the Permian and the Bakken — the nation’s two largest crude oil-focused basins. What’s driving these combinations? In today’s RBN blog, we begin a review of recent, major pipeline-company combinations and the benefits participants expect to realize from them.

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.

Over the past quarter-century, through a combination of greenfield development and acquisitions, Energy Transfer (ET) has built out integrated networks of midstream assets that add value — and generate profits — as they move crude oil, natural gas, and NGLs from the wellhead to end-users. A couple of weeks ago, ET took another big step in its expansion strategy, announcing its plan to buy Enable Midstream in a $7.2 billion, all-equity deal expected to close in mid-2021. The assets to be acquired will augment the synergies ET has already achieved, particularly regarding NGL flows into its Mont Belvieu fractionation and export facilities as well as flows of natural gas through Louisiana’s central gas corridor to LNG and industrial demand on the Gulf Coast. Today, we examine how the Enable Midstream acquisition may help propel ET forward.