regulation

Refineries with hydrofluoric acid alkylation units account for about 40% of total U.S. refining capacity. Many in the refining sector are concerned that an Environmental Protection Agency (EPA) proposal to compel refineries to conduct exacting studies of newer, alternative alkylation technologies could be leveraged to discourage and effectively ban HF alkylation, and as a result, potentially lead to more refinery closures. The U.S. already has lost more than 1.3 MMb/d of refining capacity since 2019 — losses that exacerbated the run-up in motor fuel prices through the first half of last year — and the specter of another round of refinery closures on the horizon looms large. In today’s RBN blog, we consider the challenges that refineries with HF “alky” units might face if they were required to replace them.

Since 2019, more than 1.3 MMb/d of U.S. refinery capacity has been either shut down for economic reasons or converted to renewable diesel production. The decline in the nation’s ability to produce gasoline and diesel hampered the refining sector’s response to the post-COVID demand recovery and exacerbated the big run-up in motor fuel prices that followed Russia’s invasion of Ukraine last February. Now, there may be a new threat to U.S. refining, namely the possibility that a proposed Environmental Protection Agency (EPA) rule on hydrofluoric-acid-based alkylation could, over time, spur an even larger round of refinery closures. In today’s RBN blog, we continue our look at alkylate — a critically important part of the U.S. gasoline pool — the prospective regulation and its possible effects.

On December 15, the Federal Energy Regulatory Commission (FERC) issued a permanent certificate authorizing the Spire STL natural gas pipeline serving the St. Louis area to continue operations. Spire STL had been on a treacherous legal roller-coaster, wherein its owner got a FERC certificate in 2018, built and started operation of the 65-mile pipeline in 2019, then in 2021 saw its certificate “vacated” — wiped out — by a U.S. Court of Appeals. Then, during the white-knuckled tail end of the ride, with the winter of 2021-22 looming, Spire STL got emergency/temporary authorization from FERC to keep operating while a brand-new application for a certificate was being considered. In today's RBN blog, we discuss the case — in which RBN played a part — and what it means for upcoming midstream projects.

Alkylate is an important and valuable part of the U.S. gasoline pool, prized for its high octane, low volatility and low sulfur content. There are two primary catalysts that refiners can opt to use in the production of alkylate: hydrofluoric acid, or HF, and sulfuric acid, or H2SO4.  Each is quite popular, with HF and sulfuric acid technologies each representing about half of domestic alkylation capacity — and with those shares varying significantly on a regional basis. While refiners have been safely operating both types of “alky” units for many decades, HF alkylation for some time has been in the crosshairs of the Environmental Protection Agency, which recently proposed that refiners be required to undertake extensive evaluations of potentially safer alternative technologies. It’s hard to know for sure, but if EPA’s proposed rule is made final it could ultimately force many refineries to make very costly changes — into the hundreds of million dollars per unit — or maybe even shut down entirely. In today’s RBN blog, we look at alkylate, how it’s made, and the potentially profound effects of the impending regulation.

The U.S. natural gas market is one of the most transparent, liquid and efficient commodity markets in the world. Physical trading is anchored by hundreds of thousands of miles of gathering, transmission and distribution pipelines, and well over 100 distinct trading locations across North America. The dynamic physical market is matched by the equally vigorous CME/NYMEX Henry Hub natural gas futures market. Then, there are the forward basis markets — futures contracts for regional physical gas hubs. These pricing mechanisms play related but distinct roles in the U.S. gas market, based on when and how they are traded, their respective settlement or delivery periods, and how they are used by market participants. In today’s RBN blog, we continue a series on natural gas pricing mechanisms, this time with a focus on the futures and forwards markets.

Europe is trying to wean itself off Russian natural gas, and few things would help it more than an expansion of U.S. LNG export capacity. But LNG projects don't just need long-term commitments for their output, they also need pipelines to transport natural gas from the Marcellus/Utica and other distant production areas to their coastal liquefaction plants. And, in case you hadn't noticed, new interstate gas pipelines face a lot of hurdles during the regulatory review process these days — getting a pipeline approved is tougher than snagging a Saturday morning tee time. Which brings us to, of all things, an important court ruling. In today's RBN blog, we discuss the implications of the DC Circuit's decision in City of Oberlin v. FERC

The U.S. natural gas market is one of the most transparent, liquid and efficient commodity markets in the world. Physical trading is anchored by hundreds of thousands of miles of gathering, transmission and distribution pipelines, and well over 100 distinct trading locations across North America. The dynamic physical market is matched by the equally vigorous CME/NYMEX Henry Hub natural gas futures market. Then, there are the forward basis markets — futures contracts for regional physical gas hubs. These primary pricing mechanisms play related but distinct roles in the U.S. gas market, based on when and how they are traded, their respective settlement or delivery periods, and how they are used by market participants. In today’s RBN blog, we take a closer look at the primary pricing mechanisms driving the U.S. gas market.

If you’re going to be involved in any aspect of U.S. natural gas, it’s critically important to understand how physical, futures, and forward gas markets work and how pricing is determined. That reality was emphasized almost exactly a year ago when physical spot prices for U.S. natural gas had their most volatile and bizarre weeks ever as Winter Storm Uri sent a blast of bitter-cold, icy weather down the middle of the country, wreaking havoc on gas infrastructure just when heating demand was at its highest. Prices in the Northeast, which normally see winter spikes, barely reacted, while prices across the Midcontinent and Texas rocketed to record-shattering levels, above $1,000/MMBtu. The events of the Deep Freeze of February 2021 have since brought renewed scrutiny to the various aspects of the gas and power markets, and a need among legislators, regulators and everyone who deals with energy commodity markets to understand how gas is traded in the U.S. and how prices are set. We’re here to help. So, in today’s RBN blog, we begin a deep dive into the process, quirks and idiosyncrasies of U.S. gas pricing.

Oil and gas pipeline regulation have two things in common: They’re both regulated by the Federal Energy Regulatory Commission (FERC), and they were both brought under regulatory oversight in the first place by a Roosevelt — oil pipelines by Teddy Roosevelt and gas pipelines by Franklin Roosevelt. However, that’s where the similarities end. They’re regulated under different statutes, with wildly different histories that have led to very different types of oversight and rate structures. These rules tend to offer oil pipelines a higher degree of flexibility, but in doing so, they also make their rate structures less predictable. Today, we wrap up our review of oil and gas pipelines, and how their separate histories led to the current differences in pipeline rate structures, this time with a focus on oil pipeline ratemaking.

The uninitiated might be forgiven for thinking that oil and gas pipeline operations are similar. After all, they’re just long steel tubes that move hydrocarbons from one point to another, right? Well, that’s about where the similarity ends. While the oil and gas pipeline sectors are interlinked, they developed in quite distinctly different ways and that’s led to a vast chasm in both the way the two are regulated and how their transportation rates are determined. Bridging that gap between oil and gas can be a perilous and chaotic endeavor because you’ve got to consider how each sector evolved over time and the separate sets of rules that have been established to form today’s competitive marketplace. In today’s blog, we continue our review of oil and gas pipelines and how their separate histories led to the current differences in pipeline rate structures.

Here at RBN, we’ve built our analytics around the concept that hydrocarbon commodity markets — crude oil, natural gas, and NGLs — are fundamentally and closely linked. That’s why in all that we do, we emphasize that, in order to have an understanding of one market, you must also be competent in the others. That can be difficult at times when not only the market structure, but the very rules governing the upstream, midstream, and downstream sectors of oil and natural gas transportation are so different from each other. For example, consider the many contrasts between how oil and natural gas pipelines are regulated. Today, we look at how federal oversight of pipelines has evolved and why it matters for folks trying to move a barrel of crude oil or an Mcf of natural gas from Point A to Point B.

Just before the holidays, the Federal Regulatory Commission issued its final decision on the oil pipeline index rate for the next five years. The what?? Well, once rates for interstate oil pipelines are set and accepted by FERC, the rates can move around to match the market, but any increases are capped by an annual index announced by the FERC each year. The index is equal to the current year’s inflation rate, plus an “adder” that is calculated by the FERC every five years based on an examination of the industry’s results from the previous five years. In today’s blog, we explain how a few tweaks in the way FERC calculates the cost-of-service-based adder will significantly affect how much liquids pipeline rates can rise through the first half of the 2020s.

There has been a lot of acrimony and polarization among the natural gas industry, the environmental community, various consumer advocates, industrial energy users, organized power markets and renewables developers in recent years. However, the ongoing government efforts to prop up the power sector’s coal-fired and nuclear generators have succeeded in uniting all those disparate interests into a single voice saying a single word: No! Today, we discuss the history of the administration’s planned support of coal and nuclear, the unusually unified reaction to it from groups that are more often at odds with each other, and some underlying assumptions about natural gas that aren’t — well — how the gas industry says it works.

It’s no secret that the political and regulatory environments for new pipeline development in New York and the New England states are notoriously challenging. That reputation has been reaffirmed recently, as several natural gas pipeline projects targeting the region have been sidelined by permitting delays or denials. As a result the region continues to experience gas transportation constraints and price spikes during peak demand periods. But midstreamers have had some success penetrating the New York City metropolitan market (including the Lower Hudson Valley, Long Island and northern New Jersey), which may bode well for the handful of projects currently looking to serve the area. Today, we review recent and planned capacity additions into The Big Apple and its greater metro area.

New “Tier 3” requirements to limit sulfur content in gasoline are set to take effect in just over two months — on January 2017. In March 2013, the Environmental Protection Agency (EPA) proposed to limit the sulfur content of gasoline produced or imported into the U.S. to no more than 10 parts per million (ppm) from the current “Tier 2” 30 ppm standard by January 1, 2017.   With these upcoming “Tier 3” requirements, refiners have been developing their strategies to meet the regulations and in some cases have already invested hundreds of millions of dollars in their facilities. Today, we look at the various approaches refiners can take for compliance and their impacts on the industry.