This time last year, Appalachian natural gas production was approaching a steep springtime ledge as regional prices sank below economic levels and producers responded with real-time shut-ins. This year to date, regional gas prices have averaged $0.80-$0.90/MMBtu above 2020 levels for the same period, and production has been averaging more than 1 Bcf/d above year-ago levels. If production holds steady near current levels, the year-on-year gains would just about double to ~2 Bcf/d by mid-May, which is when the bulk of the springtime curtailments first took effect in 2020. This, just as Northeast demand takes its seasonal spring plunge, which means regional outflows are poised to rise in the coming weeks, potentially to record levels. How much more can the Appalachian takeaway pipelines absorb? In today’s blog, we continue our analysis of outbound capacity utilization, this time focusing on the routes to the Midwest.
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Daily energy Posts
Corporate mergers and asset acquisitions are the normal course of business in almost any industry, but the pace of this kind of activity has recently picked up among Canada’s natural gas producers. Battered by several years of low prices, market share loss, and declining production, the position for many already-struggling gas producers only got worse when COVID hit last year. As you might expect, better placed and stronger gas producers are looking at struggling companies that have attractive assets to see if they might make accretive asset purchases or outright corporate takeovers. Today, we examine some of the most prominent natural-gas-related transactions and the motivations behind them.
As part of the Paris Agreement and other regional sustainability goals, countries across the globe are formulating strategies to reduce greenhouse gas emissions. The resultant policies target numerous different areas such as stationary emissions, electricity production, and transportation fuel sourcing. Within the transportation sector, one aspect that has spurred quite a bit of investment relates to reducing the carbon intensity of transportation fuels. The “low carbon fuel” policies that are in place today, coupled with those that are being evaluated for the future, have the potential to displace a sizeable portion of the petroleum-based fuels in the regions where they are adopted. In today’s blog, we begin a series on low carbon fuel policies, the mechanisms being evaluated to meet increasingly stringent regulations, and the impact these regulations could have on refined-products markets.
Natural gas pipeline takeaway constraints out of the Northeast worsened in 2020 despite producer cutbacks in the region as high storage levels and weaker demand led to record volumes of Appalachian gas supplies needing to find outlets in other regions last fall. This year, storage levels are lower and could absorb more of the surpluses during injection season. However, Appalachian gas production so far in 2021 has been averaging higher than last year; and, gas prices are higher year-on-year, reducing prospects for the kinds of producer curtailments we saw last year. As for the “pull” from downstream demand, LNG exports along the Gulf Coast aren’t expected to experience the slump from cargo cancellations seen last summer. In other words, Appalachia’s outbound flows are likely to be robust, setting the stage for takeaway constraints and weak prices, particularly during the spring and fall shoulder seasons. How much outbound capacity currently exists and how much room is there for growth? Today, we continue our series on the Northeast gas market with an update on Appalachia’s southbound takeaway capacity and outflows, starting with a detailed look at the gas moving to the Southeast and to the Gulf Coast.
When it comes to energy markets analysis, there’s nothing quite like spending the better part of an afternoon piecing together a long chain of unit conversions only to find the next day you’ve misplaced the sticky notes on which you wrote them. We’ve all been there, though for most of us it’s become commonplace to memorize the few hydrocarbon conversions needed to get through a lunch or happy hour. Unfortunately, the same cannot be said when it comes to hydrogen, which brings its own set of unique units of measure, many of them not usually bantered around your typical business development discussion. Crunching through them is tough, in our experience, and we find ourselves writing them down over and over again. Which gave us an idea: why not write a blog on the topic? Fortunately, we are in that business, and today we continue our series on hydrogen with a look a green hydrogen production projects and the math needed to make sense of them.
The steady growth in Permian crude oil production that everyone was banking on just a couple of years ago didn’t happen as planned. When COVID intervened, Permian oil output sagged and then stabilized at just over 4 MMb/d until last month’s Deep Freeze, when production plummeted and then quickly rebounded. Still, in anticipation of increasing output from the Permian, new takeaway-pipeline capacity from West Texas to the Gulf Coast was built out over 2016-20, as was new crude storage capacity at hubs in the Delaware and Midland basins to support the operation of the new lines. So, with all that construction, the Permian must be sittin’ pretty from a midstream infrastructure perspective, right? Don’t be too sure. From a big-picture perspective, the region has more than enough takeaway capacity, but there are strong indicators — and recent evidence — that in-region storage capacity hasn’t kept pace to be able to handle any hiccups (and worse) that can occasionally rattle the oil patch. Or maybe it’s just that folks don’t fully understand where the Permian’s storage capacity is, how it’s interconnected, and how it’s used. Today, we begin a blog series on crude storage in West Texas and southeastern New Mexico.
The Moda Ingleside Energy Center (MIEC) in Corpus Christi, the Enterprise Hydrocarbons Terminal (EHT) in Houston, and the Louisiana Offshore Oil Port (LOOP) have been loading more crude oil than any of their Gulf Coast competitors over the last year. In fact, they accounted for nearly half of the total oil exported. As many of the crude exporters have learned the hard way, leading the pack today is no guarantee you’ll still be out front six, 12, or 24 months from now. Despite the global pandemic and the market disruptions it has caused, a number of new export terminals and expansions to existing terminals are still under development, and all of them hope to draw barrels from their rivals. Today, we conclude our series with a look at planned capacity additions to Gulf Coast export facilities.
It’s been over a month since the Deep Freeze swept across Texas, shutting down the power grid, curtailing natural gas supplies, and generally wreaking havoc on the state’s population and infrastructure. The petrochemical industry was hit particularly hard, with every ethylene-producing steam cracker in the state and many in nearby Louisiana forced into hard shutdowns — that is, production coming to a screeching halt with little or no preparation. The result was unit damage well beyond what typically happens with other weather-related events like hurricanes, where there is usually some ability to manage an orderly shutdown. Consequently, at least half of the industry’s capacity to produce ethylene and its by-products remains offline, a development that is ricocheting through supply chains across the economy. Today, we examine the magnitude of the damage, consider what is happening in ethylene markets — the epicenter of the turmoil — and contemplate the longer-term implications of the outages.
Production of synthetic crude oil that is processed from Alberta’s oil sands reached record highs at the end of 2020 after touching on two year lows just four months earlier. However, these highs could be undermined and sink to four-year lows for a short period of time this spring with what appears to be a heavier than usual slate of maintenance work on three of Alberta’s four upgraders, the immense processing units that produce synthetic crude oil from bitumen. In today’s blog, we take a closer look at the upgraders, the timing of maintenance, and what this might mean for synthetic crude oil production and exports.
It’s been an incredibly wild year for U.S. LNG exports. In the past year, global gas prices have seen both historic lows and highs, as markets swung from extreme demand destruction from COVID-19 for much of last year, to supply shortages by late 2020 and into early 2021 due to maintenance outages, weather events, Panama Canal delays, and vessel shortages. The U.S. natural gas market has also dealt with its share of anomalies, from a historic hurricane season in 2020 to the extreme cold weather event last month that briefly triggered a severe gas shortage in the U.S. Midcontinent and Texas and left millions of people without power for more than a week. Given these events, U.S. LNG feedgas demand and export trends have run the gamut, from experiencing massive cargo cancellations and low utilization rates to recording new highs. Throughout this incredibly tumultuous year, U.S. LNG operators have had to adjust, managing the good times and bad and proving operational flexibility in ways that will serve them for years to come. Here at RBN we track and report on all things LNG in our LNG Voyager report, and we’ve been hard at work enhancing and expanding our coverage to capture the rapidly evolving global and domestic factors affecting the U.S. LNG export market, including terminal operations, marginal costs and export economics, and international supply-demand fundamentals. Today, we highlight how U.S. LNG has changed in the past year and trends to watch this spring. Warning! Today’s blog is a blatant advertorial for our revamped LNG Voyager Report.
The crude oil hub in Patoka, IL, is in many ways a smaller version of the hub in Cushing, OK. Like its larger sibling, Patoka receives a broad variety of crudes from Western Canada, the Bakken, and other production areas, stores and blends oil, and sends it out to refineries and Gulf Coast terminals tied to export docks. In Patoka’s case, there are only five major incoming pipelines that directly connect to the hub, but many of them receive crude from a number of upstream systems, some as far away as the Alberta oil sands. Important for Patoka’s future, a few of the pipelines feeding the hub are being expanded. Today, we continue our series on the second-largest oil hub in PADD 2 with a look at the pipelines that flow into Patoka and the sourcing of their crude.
Last summer, Alberta natural gas prices staged a remarkable turnaround from the dismal lows and extreme volatility experienced the prior three summers. The price rise is widely credited to a temporary gas flow mechanism put in place by the operator of Alberta’s gas pipeline grid to combat congestion and oversupply issues associated with construction and maintenance during the summer of 2020. However, this temporary mechanism was just that — temporary — and will not be reinstated this summer. Without it, there is concern among Western Canadian gas producers that the weakness and volatility in gas prices seen during past summers might return this year. With warmer weather on the horizon, today we consider these issues and the potential for renewed price weakness in the Alberta natural gas market this year.
The competition for barrels and the top-spot ranking among the Gulf Coast’s crude oil export terminals is like any good PGA tournament or NASCAR race, with lots of changes in who’s out in front and the ever-present possibility of a surprise — the export-market equivalent of an eagle at the last hole at the Masters or a spin-out and multicar crash on the last lap at the Daytona 500. A couple of years ago, in the first quarter of 2019, the Enterprise Hydrocarbons Terminal in Houston was at the top of the crude-exports leaderboard, followed by Energy Transfer’s Nederland Terminal and Moda Midstream’s facility in Ingleside, TX. Since then, Enterprise has ceded the #1 spot to Moda, volumes out of Nederland have slowed to a trickle, and the Louisiana Offshore Oil Port, with its unique ability to fully load Very Large Crude Carriers, has rocketed to #3. Today, we continue our series on Texas and Louisiana’s oil export facilities with a look at the Gulf Coast’s second- and third-largest terminals by export volume.
ESG is quickly becoming one of the most frequently used acronyms in energy-company Zoom calls and quarterly earnings calls, joining the ranks of oldies-but-goodies like WTI, Bcf, and NGLs. Everyone — including investors — is pushing hydrocarbon producers, midstreamers, and end-users to improve their “environmental, social, and governance” performance nowadays. It’s not always easy, though, especially when the greener, pro-planet thing to do is a lot more expensive. The good news is that there are at least a few potential win-win opportunities out there where companies can both reduce their carbon footprint and save money. In today’s blog we’ll discuss why, in some situations, CNG makes sense as a clean fuel for use as a potential replacement for diesel, propane, and fuel oil in a wide range of energy, mining, forestry, and utility settings.
In the world of public equities, nothing speaks relevance like a PowerPoint slide in the earnings call and conference decks that companies put together for analysts and investors. If a topic’s not important, then it probably didn’t “make the deck” — or even the appendix, for that matter. As consultants, we at RBN are familiar with this concept and we’ve been watching for some time to see just how long it would take hydrogen, one of our favorite recent subjects, to make its way into the slide-deck line-ups at some of the largest energy companies. Well, that time has arrived, with two energy stalwarts prominently featuring 2021’s darling subject over the last few days. However, with a new topic comes a need to put things in context. No problem, we are here to help on that. Today, we continue our series on H2 with a look at some recent hydrogen-focused slides from ExxonMobil and Enterprise Products Partners.
Last year served as something of a bellwether for what’s to come for the Northeast gas market in the long term: increasing takeaway pipeline constraints and weakening gas price differentials by mid-decade. The region’s outflows surged to record highs in the fall of 2020 as production also reached fresh highs. Just a couple weeks ago, the region notched another milestone on the pipeline constraint yardstick: record outflows on some pipes and near-full utilization of southbound routes on the coldest days of winter — something we don’t normally see, as gas supply requirements in the Northeast peak with heating demand and less gas is available to flow out of the region. This time, the surge in outflows and the resulting constraints were driven more by spiking demand and gas prices downstream than by oversupply conditions at home, but the result was the same: the Northeast had by far the lowest prices in the country. This happened even as other regions recorded triple-digit, all-time high prices. Today, we examine how Appalachia outflows and takeaway capacity utilization shaped up during Winter Storm Uri.