RBN Energy

The COVID-19 pandemic has undone a number of long-standing energy-market expectations. Just a few months ago, U.S. crude oil production was hitting new heights, export volumes were rising fast, and producers, shippers, and others were worried whether there would be sufficient marine-terminal capacity in place. Now, crude production is down sharply, and while crude exports have held up during this year’s market turmoil, the old belief that exports would keep rising through the early 2020s is out the window. Where does that change in expectations leave all those crude export terminals along the Gulf Coast, many of which were recently built or expanded to help handle the flood of crude that was supposed to be heading their way? Today, we discuss highlights from RBN’s new Drill Down Report on crude-handling marine facilities along the Texas and Louisiana coast.

The fundamental drivers of global energy markets are shifting as the world begins to recover from the crisis induced by COVID-19. North American natural gas markets have been upended this year by a multitude of events, chief among them the plunge in crude oil prices and a dramatic drop in LNG exports. Other smaller, yet relevant, factors have been gyrating as well, including natural gas exports to Mexico by pipeline. After climbing to new highs last fall, piped gas exports to our southern neighbor suffered significantly during the worst of this spring’s series of calamities, but things are looking up. Total exports across the border have reached new highs this month, with just-completed infrastructure in Mexico assisting in the jump. Perhaps things are getting back to normal, at least in this small corner of the energy markets. Today, we provide an update on exports of natural gas from the U.S. to Mexico.

U.S. Northeast natural gas production has surged nearly 1.5 Bcf/d in the past four weeks as wells that were shut-in this spring came back to life. The supply gains have been matched by strong intraregional demand, which has posted at or near record highs on a monthly average basis in recent months. But the returning supply volumes raise the question: what happens when summer cooling demand begins to fade? Storage will only be able to absorb so much, as regional storage inventories are already well above year-ago levels and the historical average for this time of year. That leaves flows out of the region as the only other outlet for excess supply, and those may be limited as well, as pipeline issues and drastically reduced downstream demand from LNG exports have stymied outflows. So, is the Northeast gas market headed for a shoulder-season meltdown? Appalachian gas supply prices this month already have weakened relative to the national benchmark Henry Hub, and these dynamics suggest there is more tumult ahead. Today, we consider what’s in store for the Northeast gas market this fall given the latest fundamentals.

On July 20, 2020, Chevron struck the first major energy sector deal since the onset of the pandemic, announcing a $13 billion agreement to acquire U.S. E&P Noble Energy. The transaction comes 15 months after the oil major bowed out of a bidding war with Occidental Petroleum to acquire Anadarko Petroleum, a landmark, $56 billion deal in which the winner may eventually end up as the loser after taking on massive debt. Oxy is just one example of how the sharp decline in oil demand and prices has ravaged producer cash flows and earnings, virtually freezing the M&A market. Despite widespread speculation that a resumption in deal activity would target the most distressed E&Ps, Chevron has broken the market wide open with a blockbuster deal for a premier E&P. The target this time, Noble Energy, has a portfolio very similar to that of Anadarko, and is being acquired at a small fraction of the cost. Today, we examine the strategies that drove this transaction, the impacts on buyer and seller, and the implications for the upstream M&A market going forward.

Associated natural gas production out of the Permian Basin rebounded sharply a few weeks ago, indicating production curtailments that went into effect in May in response to low crude oil prices are coming back online. Just as abruptly as gas production dived in early May, it lurched upward in late June, nearly back to where it was before the shut-ins began. But the rig count has continued falling to a record low, and indications are that many of the wells drilled over the past few weeks have not been completed. The meager drilling and completion activity suggests that the natural declines of existing wells, which were temporarily exaggerated by the shut-ins, will now be felt — and felt for as long as rig counts remain depressed — not just in the Permian but also in other oil-focused basins. Daily gas production volumes in the Permian in the past 10 days or so already are slipping, despite shut-ins tapering. Today, we examine the latest production trends in the Permian and what it will mean for the gas production outlook.

In many parts of the world, the shift away from coal-fired to natural gas-fired generation and renewables has been gaining momentum in an attempt to curtail the output of carbon dioxide (CO2) and other greenhouse gases. The Canadian province of Alberta kicked off such an initiative in 2016 to eliminate all of its coal-fired power generation sources and replace these with either gas-fired plants, wind farms, or solar by 2030. In the past two years, the province’s major electric utilities and independent power producers (IPPs) have been accelerating these plans, such that the complete phase-out of coal will be accomplished many years in advance of the original deadline. Today, we consider this transition and highlight what should be a pivotal year for Alberta’s use of natural gas in power generation.

For a few years now, U.S. natural gas producers have benefited from the electric-power sector’s shift from coal-fired plants toward gas-fired ones. The ongoing transition makes sense. Not only is gas-fired generation cleaner, it’s mostly been cheaper than the coal alternative. Better still, gas turbines and combined-cycle plants are very flexible companions to all those new wind farms and utility-scale solar facilities, whose variable output requires at-the-ready replacement power when the wind’s not blowing and the sun’s not shining. But with the continued push by many state regulators — and many utilities — for lower-carbon generation fleets, gas-fired plants are facing a growing challenge from energy storage, mostly in the form of very big lithium-ion batteries. Today, we look into the increasing use of large-scale batteries in utility settings and whether they might pose a serious threat to gas-fired power in the 2020s and beyond.