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.
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Daily energy Posts
Based on the response we received to our first-ever hydrogen blog last fall, it’s fair to say we didn’t waste this space on a fringe subject. To be honest, the level of interest in hydrogen far exceeded our expectations, and suggested that we might have even been a little bit late to the party — but fashionably so, if you ask us. In the weeks since then, we’ve spent a fair amount of time distilling the tremendous amount of news flow and reading material that was either sent our way or popped up in the daily news feeds. You could go a lot of different directions with hydrogen and it’s still very easy, in our view, to get lost in the forest of green energy technology. So, as we are wont to do, we have stuck to our simple approach of tackling this fuel just like we do with hydrocarbons, and we are first turning our attention upstream. Today, we continue our series on hydrogen with a look at the top production methods for the fuel.
In the spring of 2020, as the COVID-19 crisis started hitting the energy sector hard, many refiners made the tough decision to dramatically cut back capital spending plans and operating costs for the year in order to weather the storm. While these cuts were swift and sizeable, they were not absolute — they couldn’t be, given that refining is a capital-intensive industry with complex assets that require seemingly constant maintenance, equipment swap-outs, and upgrades. And then there’s the added pressure that refiners also need to invest in keeping their facilities in compliance with changing environmental rules, and to consider the overall impact of investments in new, “greener” fuels, such as renewable diesel, that may help them improve their profitability going forward. Today, we look at refiner capital spending in the context of recent history and highlights some of the growth projects being pursued in the sector.
Everywhere you look these days, someone is talking about hydrogen and, if you’re not well-versed in emerging technologies aimed at reducing carbon, you may not know what any of it means. A quick internet search isn’t much help either, as you will likely get lost quickly in discussions of fuel cell efficiency and electrolysis technology developments, not to mention the various “colors” of hydrogen and the myriad of ways it can be stored and transported. Don’t bother turning to your traditional green energy gurus either, as hydrogen is just one of many competing approaches to reducing the world’s carbon footprint, and electric vehicle folks like Elon Musk aren’t big fans. All the same, hydrogen news and investment plans seem to proliferate daily, and understanding this fuel — which, by the way, is not new to the energy space — seems prudent. At least that’s our view, which is why we today start a series to help us hydrocarbon experts unravel the mysteries behind the recent hydrogen ruckus.
There’s no doubt about it: California’s decade-long efforts to expand the use of solar, wind, and other renewable energy and improve energy efficiency have enabled the state to significantly reduce its consumption of natural gas for power generation. But the Golden State’s rapid shift to a greener, lower-carbon electricity sector — and its push to shut down gas-fired power plants — has come at a cost, namely an increased risk of rolling blackouts, especially during extended heat waves in the West when neighboring states have less “surplus” electricity to send California’s way. The main problem is that while solar facilities provide a big share of the state’s midday power needs, there’s sometimes barely enough capacity from gas plants and other conventional generation sources to take up the slack when the sun sinks in the late afternoon and early evening. Today, we discuss recent developments on the power front in the most populous state, and what they mean for natural gas consumption there.
The U.S. power sector’s shift to natural gas over the past few years has been a boon to gas producers across the Lower 48, especially in the Northeast. Scores of new gas-fired power plants have been built there during the Shale Era, and a number of coal-fired, oil-fired, and nuclear plants have been taken offline. New England is a case in point; gas-fired power now accounts for about half of the installed generating capacity in the six-state region (Connecticut, Rhode Island, Massachusetts, Vermont, New Hampshire, and Maine) — three times what it was 20 years ago. But New Englanders have a love-hate relationship with natural gas, and with renewables and energy storage on the rise, gas’s role in the land of the Red Sox, hard-to-understand accents, and lobsta’ rolls may well have peaked. Today, we discuss recent developments on the natural gas and power generation fronts in the northeastern corner of the U.S.
They’re generally small in size, but renewable diesel refineries are popping up in many parts of the U.S., incentivized by government programs aimed at reducing carbon emissions and very gradually weaning Americans — and Canadians — from crude oil-based diesel fuel. Recently, HollyFrontier Corp. announced that it will be converting its decades-old Cheyenne, WY, refinery into a renewable diesel facility. While the news of another entrant into the renewable diesel market is not surprising, the complete shutdown and transformation of an existing refinery for this purpose marks only the second time this has occurred in the U.S. Today, we discuss HollyFrontier’s plans and provide an update on renewable diesel supply and demand dynamics.
Solar photovoltaic projects accounted for an impressive 40% of all the new electric generating capacity installed in the U.S. in 2019 — the third time since 2015 that solar additions outpaced installations of natural-gas capacity. And the early 2020s are shaping up as another good period for solar, especially in states that offer both intense sun and the broad expanses of land required for large-scale solar projects. Texas is a case in point; some 8,000 megawatts (MW) of new solar capacity is expected to be added there in the 2020-22 period. Solar power, like wind power before it, has come to be so prolific in the Lone Star State that you’d think it would be having a significant impact on how much gas-fired generation is needed day to day, right? Today, we discuss the increasing role of solar generation in the second-largest state and its impact on the demand for traditional power plant fuels.
Production of alternative, non-petroleum-based fuel continues to be a hot topic around the globe as government policies have incentivized or even mandated these products with the aim of reducing greenhouse gas emissions. In the U.S., we’ve seen waves of ethanol and biodiesel enter the fuel supply chain, but the latest commodity that has piqued industry interest is renewable diesel, whose chemical characteristics make it a particularly desirable replacement for conventional distillate. Today, we provide an overview of the renewable diesel market, the legislative programs in North America that are incentivizing its production, and the projects currently on the books to produce it.
Renewable and hydroelectric generation has chomped away at natural gas market share of total power generation along the West Coast this year. The latest electric generation data from the Energy Information Administration shows power sourced from renewables (not including hydro) in California, Oregon and Washington combined in April 2017 through July 2017 edged up about 1% year-on-year, while hydroelectric generation averaged 23% higher year-on-year. At the same time, natural gas-fired generation fell 16% year-on-year. The reduced gas-fired generation demand, along with reduced gas storage capacity in the West, has displaced natural gas from the region and disrupted recent gas flow patterns. These shifts provide a glimpse of what gas flows and pricing dynamics could look like as more renewable capacity is added. In today’s blog, we analyze the effects of electric generation trends on regional gas flows.
The Western states continue to ramp up their renewable energy mandates—California and Oregon, for instance, plan to get at least 50% of their electricity from renewable sources, and Colorado has set a 30% requirement. Ironically, this renewable energy trend puts a spotlight on natural gas, whose at-the-ready supply will be needed to fuel the West’s increasing number of gas-fired power plants at a moment’s notice to offset the up-and-down output of solar facilities and wind farms. One way to help ensure natural gas availability is have gas storage capacity close at hand. Today we look at ongoing efforts to add tens of billions of cubic feet of natural gas storage in the Western U.S., primarily to help ensure the fueling of nearby gas-fired power plants that back up variable-output solar and wind.
Over the past few weeks, publicly traded independent refining companies reported their latest quarterly results, and nearly all lamented on a common theme: the cost of Renewable Identification Numbers (RINs) is out of control. However, the financial burden is not felt equally across the industry, as companies with integrated marketing operations (refining, blending and retailing) don’t face the same RINs-cost albatross as merchant refiners who don’t have retail operations. Today we review the escalating RIN costs that obligated parties have endured this year and explain how the degree of financial pain depends on the level of refiners’ downstream integration.
Renewable Identification Numbers (RINs) have grabbed the attention of refiners this spring and summer, and for good reason. The price of RINs –– ethanol credits used by refineries to prove compliance with the federal Renewable Fuel Standard –– have soared, and the credits are having an outsized negative effect on some refiners’ costs and profitability. Part of the RIN price spike can be attributed to concerns that there may not be enough to go around this year, and that the situation in 2017 may be far worse. But the rocketing cost of the credits is also raising questions about whether the largely unregulated and opaque RINs market is being manipulated or even cornered by those hoping for a quick, Powerball-size profit. Today, we continue our review of the RINs market with a look at which types of refiners are hit hardest by high RIN prices, and at whether we might be heading off a RIN-availability cliff.
The rising cost of Renewable Identification Numbers (RINs) –– ethanol credits used by refineries to prove compliance with the federal Renewable Fuel Standard –– is putting added financial pressure on the refining sector, which already is squeezed by too-high inventories and thin crack spreads. In fact, for some refiners RIN expenditures may soon be their biggest single operating cost category. (Yes, you read that right.) The cost of ethanol credits is being driven up to record levels by several factors, chief among them the concern there may not be enough to go around this year and next. And things may only get worse from there. In today’s blog, we begin a two-part examination of the 2016-17 market for RINs, a regulatory must-do that rankles and vexes most refiners and gasoline importers.
After averaging more than a nickel below Henry Hub all this year, the California Border natural gas price spiked to 66 cents/MMbtu above Henry on Friday. This kind of price volatility is no surprise to anyone following the radical shifts in California energy markets, starting five years ago when the state legislature enacted its 33%-by-2020 renewable portfolio standard (RPS) law. By mid-2015, more than 14,000 MW of new solar and wind power had pulled down gas demand in California to the point that natural gas prices at the SoCal Border were averaging a negative basis to Henry Hub. Still not satisfied, last year California legislators voted to establish a 50% renewables target for 2030. On top of it all, the West Coast was coming up on a La Niña year that would bring more rain –– and hydroelectric generation –– to the Pacific Northwest and eventually into California. With all that renewable power (solar, wind and hydro), California seemed headed for an unprecedented period of low gas prices, but it did not turn out to be so simple. In today’s blog, we continue our look at California’s power and gas markets with the events and drivers that shaped late 2015 and the first six-plus months of 2016, and consider what’s to come.
California energy markets look quite a bit different today than they did five years ago when the state enacted a renewable portfolio standard (RPS) law that requires every utility and other electricity retailer to serve 33% of their load with renewable energy by 2020. Since then, California has seen huge changes in its energy balances – it shut down the nuclear generating plants at San Onofre, regulators expedited the build-out of new transmission lines to get more wind and solar power into the market, the state implemented a carbon cap-and-trade program, the legislature increased the RPS target to 50%, and SoCal Gas’s Aliso Canyon natural gas storage facility sprung a leak. Today, we look at the changes in California’s energy markets since 2011, and what they mean for future developments in a state far out front in the adoption of renewables and environmental regulation.