It Don't Come Easy, Part 3 - In Quest to Lower Methane Emissions, Picking the Right Technology is Key
The oil and gas industry is being pushed by regulators, third parties and investors to better identify and mitigate its methane emissions, especially the few “super-emitter” sites that make outsize contributions to overall emissions. But while operators are ramping up capital spending on new technology, one thing has become clear: There is no silver bullet when it comes to reducing emissions, and each option includes one or more drawbacks, including source attribution, costs, quantification, and detection limits. In today’s RBN blog, we’ll break down the advantages and disadvantages of the different measurement technologies.
Analyst Insights are unique perspectives provided by RBN analysts about energy markets developments. The Insights may cover a wide range of information, such as industry trends, fundamentals, competitive landscape, or other market rumblings. These Insights are designed to be bite-size but punchy analysis so that readers can stay abreast of the most important market changes.
It was a good week for crude oil, with the price of WTI up 9.3% since last Friday. Today WTI settled at $75.67/bbl, up $1.30/bbl. The primary driver continues to be the export cuts of 450 Mb/d from Iraq's Kurdistan region. Oil production in the region is being shut in at several oil fields due to curtailments on a Turkish pipeline. Crude prices are also being supported by economic data (the U.S.
US oil and gas rig count declined this week after two consecutive weeks of growth, falling to 755 for the week ending March 31 vs. 758 a week ago according to Baker Hughes. The Permian (-1), Haynesville (-1) and All Other Basins (-1) all posted small declines. Total US rig count is down 24 in the past 90 days, and up 82 vs. one year ago.
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Daily Energy Blog
We can’t conjure up a more old-school, more intrinsically American industry than whiskey-making, or more iconic whiskey names than Jack Daniel’s and Jim Beam — the latter, of course, being a bourbon, a particular type of whiskey. The recipes for both “Jack” and “Jim” have remained unchanged for generations and their distillers in Tennessee and Kentucky, respectively, are traditionalists to their core. That doesn’t mean, though, that they’re unaware of the need to reduce their greenhouse gas (GHG) emissions — or are blind to the opportunities that decarbonization may present. Now, as we discuss in today’s RBN blog, both Jack Daniel’s and Jim Beam are all-in on producing renewable natural gas (RNG) from spent grains.
With the war in Ukraine ongoing and Europe largely cut off or quitting Russian natural gas imports, many feared that global gas prices would skyrocket this winter, but prices have fizzled out instead and are at their lowest level since September 2021. That’s not to say gas prices are low, as they are still well above historic norms and high enough to incentivize LNG imports and the development of future LNG capacity. But despite losing its largest gas supplier, and prices running up in the months ahead of this winter, Europe appears to be in much better shape than it was last winter and gas prices have been relatively calm and on the downswing. So why is that? The difference between this winter and last largely boils down to storage inventories and the ability to attract LNG cargoes. In today’s RBN blog, we look at the European gas market, the impact of U.S. LNG supplies, and what it all means for developing LNG projects.
If pipeline-constrained Haynesville Shale producers’ New Year’s resolution was to grow volumes, they just got a big boost: Energy Transfer recently placed in service its new Gulf Run Transmission natural gas pipeline in Louisiana, increasing north-to-south capacity in the state by 1.65 Bcf/d. It’s the first of several pipeline projects due online in 2023 — and among others proposed for subsequent years — that will be critical for debottlenecking the Louisiana pipeline network and connecting Haynesville and other gas production volumes to LNG export projects vying for feedgas supply on the Louisiana coast. U.S. LNG developers are in a race to capitalize on the tight global LNG market and finalize terminal plans, with much of the next wave of liquefaction and export capacity additions planned for the Louisiana coast which may, in time, help alleviate energy security concerns, particularly across the pond in Europe. If these pipeline projects don’t get built on time, the resulting supply shortage in southern Louisiana would not only wreak havoc on Henry Hub and the domestic gas market but would reverberate around the globe. Gulf Run’s in-service is good news for at least one facility: the under-construction Golden Pass LNG, which is the anchor shipper on the pipeline and due to begin commissioning later this year. In today’s blog, we look at what the new capacity could mean for flows and production growth in the short- and long-term.
Tallgrass Energy last month snagged an early Christmas present: It won a bid for Ruby Pipeline, the beleaguered Rockies-to-West Coast natural gas system that has long been underutilized and cash-poor. In doing so, it beat out one of the largest midstream companies in North America and a long-time co-owner of Ruby — Kinder Morgan. Ruby may be a languishing asset, but for Tallgrass it’s more like a crown jewel in its quest to be the only transcontinental header system in the country that would connect trapped Appalachian gas supply with premium West Coast markets. Tallgrass’s Rockies Express (REX) pipeline is already moving Marcellus/Utica molecules west to the Rockies — the opposite direction than it was originally built for in the pre-Shale Era. The Ruby acquisition, which has yet to close, would allow Tallgrass to extend its reach farther west, directly into the premium West Coast markets. The Ruby deal comes at a time when California’s aggressive decarbonization goals are leading to gas shortages and exorbitant fuel premiums out west, and there’s an immediate need to debottleneck routes to get gas there. In today’s RBN blog, we begin a series delving into how Ruby fits into the Western U.S. gas market and what the acquisition would mean for Tallgrass.
In a part of the world where enduring a cold winter is often seen as a badge of honor, the latest cold blast that descended on Canada just before Christmas — and during Christmas in the U.S. — was another one for the natural gas record books. By almost every measure, the recent frigid temperatures, though not long-lasting, set new Canadian records for daily demand, storage withdrawals, and net exports to the U.S., and went well beyond the records set during Winter Storm Uri in February 2021. In today’s RBN blog, we delve into the latest record-busting Canadian gas data.
The Biden administration’s first foray into reducing methane emissions from oil and gas operations, released in November 2021, promised to reduce emissions from hundreds of thousands of existing sites, expand and strengthen emission-reduction requirements, and encourage the use of new technologies. It was clear about one other thing too, namely that more was already in the works. And sure enough, the Environmental Protection Agency (EPA) recently followed up with a proposal that significantly broadens the initial plan. In today’s RBN blog we look at that supplemental proposal, its targeting of so-called “super-emitters,” and why third-party groups will play a bigger role in mitigating methane emissions in the years ahead.
This year there’s been unprecedented forward momentum for LNG development. Since 2022 began, two U.S. projects have reached a final investment decision (FID), with a third expected to reach that milestone in early 2023. Offtakers have committed to 38 metric tons per annum (MMtpa), or 4.9 Bcf/d, of long-term LNG contracts from these and other proposed terminals this year and there’s another handful of U.S. projects with a realistic shot at FID in the next year or so, not to mention others in Mexico and Canada. Progress on the LNG front has been dominated by three companies: Cheniere, Sempra and Venture Global. While there are other projects inching closer to FID, those from the proven LNG developers — our “three kings” — have leapfrogged to the front of the line. In today’s RBN blog, we look at what those three have under development and what it means for everyone else trying to build LNG export capacity.
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.
As U.S. LNG export project development accelerates along the Gulf Coast, one of the big uncertainties is where will all that feedgas come from? We estimate that there are a dozen Gulf Coast projects totaling 16 Bcf/d of export capacity in the running for completion in the next decade, with 60% of that capacity sited along a less-than-100-mile stretch of coastline straddling the Texas-Louisiana border. One of the major factors that will influence the timing and commercialization of the projects is the availability of feedgas supply where and when it is needed. With pipeline projects and production growth in the Marcellus/Utica shales at a veritable standstill, the Texas and Louisiana production regions — the Permian, Eagle Ford and Haynesville — are the frontrunners for serving the bulk of the resulting Gulf Coast demand growth. Assuming no midstream constraints, RBN’s Mid-case production forecast anticipates growth from the three basins will total 15.5 Bcf/d by 2032. In today’s RBN blog, we look at how well (or not) production levels will line up with feedgas demand.
Thanks to a warm start to the season and low Asian demand for LNG, Europe has so far been able to stave off a worst-case scenario for natural gas supply this winter. Still, the European market is keeping a keen eye on the years ahead, when the continent will need to rely on new sources of LNG to meet demand and refill inventories with little chance of any Russian gas. The call for more LNG has ushered in a new wave of export-project development, with two U.S. projects reaching a positive final investment decision (FID) this year and LNG offtakers in Europe and elsewhere committing to an incredible 37 MMtpa (4.9 Bcf/d) of long-term contracts from pre-FID sites in North America. This momentum has revived a number of projects from the COVID-induced wasteland, including Sempra’s Port Arthur LNG. In today’s RBN blog, we continue our series on U.S. LNG projects by taking a closer look at Port Arthur, the one most likely to take FID next.
Natural gas pipeline project permitting sits at the nexus of the debate about the best path toward decarbonization. Industry proponents rightly point out that pipelines can reduce aggregate emissions by displacing much higher burner-tip emissions from coal in power generation. Environmental opposition, though, highlights that a high rate of methane emissions along the gas value chain could undermine those potential improvements. In today’s RBN blog, we consider the net decarbonization impact of new gas pipelines, including the importance of quantifying upstream methane emissions, by looking at a couple of canceled or long-delayed pipeline projects that could make a big difference.
Last week, even as natural gas day-ahead prices went negative in the Permian’s Waha Hub in West Texas, spot prices at northern California’s PG&E Citygate last week traded at a record-smashing $55/MMBtu, according to the NGI Daily Gas Price Index — close to 100x the Waha price. Other hubs west of the Continental Divide also surged to record levels, while markets just east and north of there were largely unruffled — a sure sign of bottlenecks for moving gas into West Coast markets. This is just the latest instance of severe gas supply shortages and constraint-driven price disruptions out West in recent years (even ignoring Winter Storm Uri and the Deep Freeze of February 2021). Moreover, it’s arguably taking progressively more benign market events to trigger similar or worse shortages. What’s going on? In today’s RBN blog, we break down the factors driving the latest Western U.S. gas price spikes.
The first wave of Gulf Coast liquefaction and LNG export facilities was well-timed, coming as it did with fast-rising natural gas supplies in the Lower 48 and a slew of pipeline reversals and expansions that enabled billions of cubic feet a day of low-cost Marcellus-Utica gas supplies to reach Gulf Coast markets. Permian and Haynesville supplies helped too. The next wave of LNG development, which will kick off in earnest in 2024, may not go quite as smoothly, however. Global demand for LNG is there — there’s little doubt about that. But the next phase of export capacity growth may well be hemmed in by domestic factors, namely the timing and availability of gas supplies to the Gulf Coast due to potentially serious midstream constraints. In today’s RBN blog, we look at where the feedgas supply is likely to come from and what that will mean for pricing dynamics.
Despite many challenges, natural gas production in Western Canada has been hitting record highs this year, powered by what seems to be the inexhaustible energy of the unconventional Montney formation. This immense resource remains the primary focus of most Canadian gas producers, and those that operate in the British Columbia portion of the Montney know they have their work cut out for them in the next few years if they are to meet the growing need for gas, especially when the LNG Canada export terminal comes online mid-decade. In today’s RBN blog, we update the Montney’s production and productivity trends in British Columbia and evaluate whether enough progress is being made.
The need for more LNG export capacity, driven both by Europe’s push to wean itself off Russian gas and long-term Asian demand growth, is resulting in a new wave of development. Two major U.S. projects have reached a positive final investment decision (FID) in the past six months and more are likely to do so soon, both in the U.S. and elsewhere. But conventional export terminals take time to build, leading at least some, like New Fortress Energy, to explore the potential for floating LNG (FLNG) facilities — basically, an LNG export terminal located on the topside of a large tanker — which can bring new capacity online faster, much like the floating storage and regasification units (FSRUs) that are now boosting European import capacity. In today’s RBN blog, we take a look at FLNGs, what’s already out there, and what could be coming to North America in the next few years.