The folks who transport bitumen from the Alberta oil sands to faraway markets depend on light hydrocarbons collectively known as diluent to help make highly viscous bitumen flowable enough to be run through pipelines or loaded into rail tank cars. The catch is — or was, we should say — that Western Canada wasn’t producing nearly enough condensate and other diluent to keep pace with fast-rising demand, so a few years ago, two pipelines from Alberta to the U.S. Midwest were repurposed to allow diluent to be piped north. More recently, though, Western Canadian production of diluent has been soaring and new pipeline capacity has been built within Alberta to deliver it to the oil sands. That has the potential to reduce the need for imports from the U.S. and may soon lead to at least one of the import pipes being repurposed yet again. Today, we continue our series on diluent with a review of the pipeline systems that collect locally produced light hydrocarbons that are eventually employed in the oil sands.
Lower crude oil prices whack oil-directed drilling, slashing crude production, which cuts associated gas output, tightening the gas supply-demand balance, and boosting gas prices enough to spur more gas-directed drilling — it’s a classic case of commodity market schadenfreude, where one product benefits at the expense of another. That’s the way it was supposed to work, according to various trading strategies touted a few weeks back. But here we sit, with crude oil prices still around $40/bbl and gas prices languishing at a paltry $1.66/MMBtu. Was there something wrong with the schadenfreude thesis, or do we have to look deeper to understand how prices will behave in this convoluted COVID era? In today’s blog, we’ll explore this question and what it may mean for natural gas prices in the coming months.
On Thursday, June 18, the Federal Energy Regulatory Commission (FERC) issued a Notice of Inquiry (NOI) to reset the index that’s used to make annual changes to the rate ceilings for interstate pipelines that transport crude oil, refined products, and other hydrocarbon liquids. Every year, the highest rate an indexed oil pipeline can charge goes up or down — almost always up — using the FERC index. The commission’s new proposal, which would become effective in July 2021, follows an already-approved index adjustment that will take effect a week from Wednesday, on July 1. Taken together, the two changes would reduce the maximum annual increase in the rate ceiling from more than 4% now to less than 1%, which could have a major impact on liquids pipeline owners. Today, we discuss the NOI, the meaning of the pipeline index, where it came from, and where it might be headed.
365手机登录网页Enbridge’s proposal to have crude oil shippers on its now fully uncommitted Mainline sign long-term contracts for as much as 90% of the 2.9-MMb/d pipeline network’s capacity is a big deal — and controversial. Refiners and integrated producer/refiners generally 365手机登录网页 the plan, which is now up for consideration by the Canada Energy Regulator, while Western Canadian producers with no refining operations of their own — and, for many, no history of shipping on the Mainline — mostly oppose it. What’s driving their contrasting views? It’s complicated, of course, but what it really comes down to is that everyone wants to avoid what they see as a bad outcome. Refiners and “integrateds” fear that if the current month-to-month approach to pipeline space allocation remains in place, cost-of-365手机登录网页-based tariffs on Mainline will soar when new takeaway capacity is built on the Trans Mountain and Keystone systems and fewer barrels flow on Mainline. Producers, in turn, are wary of making multi-year, take-or-pay commitments to Enbridge if they’ll soon have other takeaway options, and are equally concerned that they’d be left in the lurch if they don’t commit to Mainline and the Trans Mountain Expansion and Keystone XL projects don’t get built. Today, we consider both sides of this important debate.
Since last summer, the Corpus Christi area has emerged as the U.S.’s leading crude export venue. In the first five and a half months of 2020, it accounted for an astounding 45% of the barrels being shipped abroad — astounding because in the same period last year, the Corpus area held less than a 20% share. What is sometimes forgotten, though, is that little Ingleside, TX, located across Corpus Christi Bay from Corpus proper, is the area’s crude-export leader, with the Moda Midstream and Flint Hills Resources terminals responsible for just over half of Greater Corpus’s total export volumes. And, with the new South Texas Gateway Terminal nearing completion, Ingleside’s role will only increase in the coming months. Today, we conclude a series on Gulf Coast export terminals with a look at what has been going on in Ingleside.
March’s crude oil price crash hit the E&P sector like a tsunami, shattering capital and operating budgets, upending drilling plans, and eviscerating equity valuations. The initial responses by producers to the price collapse included a flood of capex reductions, corporate belt-tightening, and scattered production shut-ins. But first-quarter earnings reports issued in late April and early May provided the first detailed insight into the financial wreckage the crisis unleashed on U.S. E&Ps. It wasn’t pretty. The plunge in the WTI oil price to $20/bbl at the end of the first quarter triggered a combined $60 billion in impairments of oil and gas reserves across the 41 E&Ps we track, as well as a 16% decline in average revenue per barrel of oil equivalent (boe) from the pre-pandemic fourth quarter of 2019. More trouble may be ahead: the average oil price in the second quarter is on track for a 35% decline from the first quarter, which will dramatically impact the cash flows that allow companies to pay their staff, keep the lights on, and hold creditors at bay. Today, we analyze the first-quarter earnings results of our representative sample of U.S. producers and take a look forward to the potential effect of lower pricing on second-quarter earnings.
Brent is by far the most important crude oil benchmark in the world, with well over 70% of all global crudes tied either directly or indirectly to the North Sea crude’s price. But the original Brent crude oil production is almost played out, with all of the offshore Brent producing platforms soon to be decommissioned. This might seem to be a big problem, but in the world of crude oil trading, it is a total non-issue, because Brent is no longer simply a grade of crude oil. It is a multi-layered matrix of trading instruments, pricing benchmarks, and standard contracts linked together by price differentials traded across a number of mechanisms and platforms that form the foundation of a robust, vibrant, and extremely important marketplace. Today, we delve further into the mechanics of the Brent complex, the key components that make it work, and the transactional glue that binds them together.
Crude oil supply news comes in from all angles these days, bombarding the market daily with fresh information on producers’ efforts to ramp their volumes back up now that the global economic recovery is cautiously under way. Crude demand is rising, storage hasn’t burst at the seams yet, and prices have come a long, long way in just a few weeks. Permian exploration and production companies, having avoided a fleeting, longshot chance that the state of Texas might regulate West Texas oil production, are responding to higher crude oil prices as free-market participants should. The taps are quickly being turned back on, unleashing pent-up crude and associated gas volumes that, you could say, were under a sort of quarantine of their own for a while. Today, we provide an update on the status of curtailments in the Permian Basin.
U.S. Northeast natural gas production has tumbled nearly 900 MMcf/d in the past month alone since EQT Corp., Cabot Oil & Gas, and others began curtailments in response to low gas prices, and is averaging nearly 2 Bcf/d below last November’s peak of 32.9 Bcf/d. But regional gas demand has lagged this year, storage inventories have surpassed five-year highs and outbound flows to the Gulf Coast are being challenged by reduced takeaway capacity and drastically lower demand from LNG export facilities. Today, we examine the net impact of these competing fundamental factors on the region’s supply-demand balance and the resulting implications for Appalachian supply prices.
Bitumen, the heavy, viscous form of crude oil associated with Alberta’s oil sands, has been the workhorse behind Canada’s ascent to near the top of oil-producing nations. However, it is impossible to get raw, near-solid bitumen to refiners by pipeline without either upgrading it to a flowable crude oil or blending it with lighter hydrocarbon liquids, a.k.a. diluents, to form the more diluted version of the product, referred to as “dilbit.” As for moving bitumen by rail, there are two main options: using heated tank cars or blending it with diluent to form “railbit.” The rapid rise in bitumen production in the past decade — interrupted only by wildfires and the recent price crash — has generated a large parallel market for diluents, whose fortunes are closely tied to the oil sands. U.S.-sourced diluent currently meets a substantial portion of the demand. But with Alberta oil sands development poised for renewed growth and in-province condensate production rising, the Canadian diluent market could be in for some big shifts. Today, we start a blog series considering the unique role that this special form of hydrocarbon plays in the oil sands.
365手机登录网页In the first eight months of last year, the Corpus Christi area ranked third among its Gulf Coast brethren in crude oil export volumes — Houston was consistently #1 then, and Beaumont was the regular runner-up. Since September 2019, though, Corpus has been out front, often by a wide margin, and there’s good reason to believe it will stay ahead of the pack, at least for a while. What’s driving the South Texas port’s export-volume growth? First, there are three big new pipelines now moving crude from the Permian to Corpus: Cactus II, EPIC Crude and Gray Oak. Second, Corpus Christi and nearby Ingleside, TX, have a lot of existing storage and marine-dock capacity, and more is being developed. Today, we continue our review of crude export facilities with a look at three terminals along Corpus’s Inner Harbor.
Though crude oil prices have been rebounding lately, this spring’s price crash sent shockwaves through the U.S. midstream industry, which had just emerged from a decade of massive infrastructure investment in response to unprecedented upstream production growth. Just as midstreamers were looking forward to steady earnings growth, waves of huge capex cuts and well shut-ins by producers shattered forecasts and shifted strategic instincts toward survival instead of growth. Every 365手机登录网页 is different, of course, but a lot can be learned by examining a single firm in detail to see how it will fare in the current market environment, given its particular set of assets and arrangements. Take Targa Resources. An analysis of its performance provides insights into the outlook for integrated natural gas and NGL assets, especially in the Permian Basin, as well as the value of forming joint ventures. Today, we preview our new Spotlight report on Targa.
Mexican demand for motor gasoline and diesel has plummeted this spring due to COVID-19 — so has demand for LPG. So far, Pemex — Mexico’s state-owned energy 365手机登录网页 and by far the country’s largest supplier of these commodities — has responded by slashing how much gasoline, diesel and LPG it is importing from the U.S. and holding its own production steady, despite the fact that Pemex’s refining margins are now deep in negative territory. What does Pemex’s focus on money-losing refining mean for U.S. exports to Mexico going forward? Today, we begin a short series on the ongoing competition between U.S. refiners and Pemex for market share south of the border.
Up in Canada, there is finally a regulatory timeline for reviewing Enbridge’s long-standing proposal to revamp how it allocates space — and charges for 365手机登录网页 — on the 365手机登录网页’s 2.9-MMb/d Mainline. But the plan to convert the largest crude oil pipeline system out of Western Canada from one whose space is 100% uncommitted and allocated every month to one with 90% of its capacity locked in via long-term contracts remains controversial, especially among producers. Plus, the world has changed in the past few months. Oil sands and other production in Alberta and its provincial neighbors is off sharply in response to pandemic-related demand destruction and low oil prices, and the always-full Mainline has been running at well under 90% of its capacity lately. Further, the Trans Mountain Expansion and Keystone XL projects — competitors to the Mainline in a way — have progressed this year, making shippers wonder whether to lock in capacity on the Mainline if TMX and KXL’s completion may be imminent. Today, we begin a short series on the prospective shift to a contract-carriage approach on the primary conduit for heavy and light crudes from Western Canada to U.S. crude hubs and refineries.
Energy markets balance — eventually. In the midst of the turmoil we’ve experienced this year, there have been periods when it seemed like markets were going to hit the wall. But even with the historic WTI oil price glitch on April 20, the physical crude oil markets continued to function. That’s the way it is supposed to work, and it’s good news. The bad news is that figuring out how these markets are balancing in these volatile conditions can be challenging if not downright perplexing. Nowhere is that more true than the market for U.S. propane. Production is down, but so is demand. Inventories are up, and so are prices. Propane continues to be exported, even though global demand has been whacked by COVID. In today’s blog, we explore these developments and put the spotlight on RBN’s NGL Voyager365手机登录网页, our subscriber report and data 365手机登录网页 that we have just reformatted, upgraded and generally reconstructed to meet the information needs of today’s NGL marketplace.