Three major crude oil pipeline projects now under development would add nearly 1.8 MMb/d of much-needed takeaway capacity out of the Western Canadian Sedimentary Basin (WCSB), a region hit hard by pipeline constraints and widening price differentials. But each of the three projects — Kinder Morgan’s Trans Mountain Expansion (TMX), Enbridge’s Line 3 Replacement Project and TransCanada’s Keystone XL — continues to face regulatory challenges and it remains unclear how many of the projects will advance to construction and how soon the first of them might come online. It’s also possible that one or more may go the way of Northern Gateway and Energy East, two major pipeline projects that went belly-up after years of planning. Today, we continue our blog series on Western Canadian crude oil with a look at Keystone XL and its prospects.
Daily Energy Blog
Corpus Christi, TX, is quickly becoming a strategic hub for U.S. crude oil exports. Since the repeal of the crude oil export ban in December 2015, crude exports from the Sparkling City by the Sea have increased to nearly 500 Mb/d — and that may be just the beginning. Numerous pipeline and terminal projects have been announced to receive, store and ship out a lot more crude from the Permian and Eagle Ford shale plays, with an increasing share of those barrels destined for the international market. Today, we discuss recent developments in crude exports out of South Texas.
While the recently enacted federal tax cuts have been widely viewed as a boon to corporate America, including businesses in the energy sector, a new report by our friends at East Daley Capital finds a major drawback in the law for midstream companies. By slashing the corporate tax rate from 35% to 21% — and by allowing partnerships and “pass-through” entities to take a 20% deduction on their income pre-tax — the new law will increase the return on equity that midstreamers earn on their crude oil, NGL and natural gas pipelines. That may well lead the Federal Energy Regulatory Commission (FERC) to re-set its formula rates for at least some gas pipelines, and also is likely to heighten regulatory scrutiny of the rates charged by the owners of oil and NGL pipelines. Today, we continue our review of East Daley’s new “Dirty Little Secrets” report with a look at the tax law, the higher pipeline ROEs resulting from the tax cuts, and the midstream companies that may be affected most.
Mexico continues to open up its refined-products sector to competition, and refinery troubles at government-owned Pemex are providing U.S. refiners and motor-fuel marketers with a golden opportunity to export increasing volumes of gasoline and diesel south of the border. But transporting all those refined products to Mexican population centers and distributing them to thousands of service stations requires port and rail terminals, pipelines and storage, and Pemex has been slow in relinquishing control of its infrastructure. Today, we continue our series on efforts to facilitate the transportation of motor fuels from U.S. refineries to — and within — Mexico, this time looking at more port and rail-related projects and at existing and planned pipelines.
After a three-year hiatus, winter returned to the U.S. natural gas market this year in the form of a “Bomb Cyclone” and more than a week of frigid temperatures. The cold weather pushed Henry Hub prices above $6/MMBtu and East Coast prices higher than $100/MMBtu on some days. This winter, the pain wasn’t just confined to New England. Prices at Williams’ Transcontinental Gas Pipeline (Transco) Zone 5, which includes the Carolinas, Virginia and Maryland, hit all-time highs on January 5. Exports from Dominion’s Cove Point terminal in Maryland are only just getting started so it’s not liquefied natural gas (LNG) exports from the East Coast that are driving prices higher. Instead, it’s gas’s increasing role in winter power generation that has been putting pressure on East Coast gas pipeline deliverability. Today, we begin a series explaining why prices have been so high on very cold days this winter and why more price spikes may be ahead.
With Western Canadian crude oil production rising, available pipeline takeaway capacity shrinking and crude-by-rail volumes rebounding, midstream companies are ramping up their efforts to get long-planned pipeline projects built. But that’s no easy task. Virtually every plan to add new takeaway capacity out of Alberta — Canada’s #1 energy-producing province — continues to face regulatory hurdles, and it remains to be seen which of the pipeline projects will be completed, and when. We can’t just throw up our hands, though, and say, “Who knows?” With pipeline constraints out of Western Canada worsening by the month and having profound negative effects on the price of Western Canadian Select (WCS), there’s real value in reviewing in some detail what these pipeline projects are up against. Today, we discuss what’s being planned on the takeaway front and where these projects stand.
With ethane prices remaining below 30 c/gal, making it only slightly more valuable than natural gas at Henry Hub on a Btu equivalence, most natural gas processors/producers can earn a greater profit when ethane is sold with natural gas (rejected) than when it is extracted and sold with the NGLs. How much more money you may be wondering? The answer is — it depends. Are there downstream pipeline contracts and sunk costs impacting the decision making? Are the contracted volumes on an ethane-only pipeline or a raw mix pipeline? How far away is the producing basin from the Gulf Coast market? How do all these factors come together to determine whether ethane is produced or rejected and the value created? Today, we continue our discussion of the MQQV gas processing model — this time focusing on the Value principle. This is our final blog focusing on the MQQV model and, with it, we are making it available to all Backstage Pass holders should you want to run scenarios of your own.
Canada’s natural gas exports — which have been pushed out of the supply-rich U.S. Northeast in recent years — are also facing challenges in Western U.S. markets. Growing supply from North Dakota’s Bakken Shale is increasingly competing for capacity on the same transportation routes as imports and is targeting the same downstream markets. Meanwhile, the rise of renewable energy in the West region from wind and solar farms is limiting gas demand in those target markets. What does that mean for imports from Canada? Today, we look at how these factors are affecting Canada’s exports to the Western U.S.
2017 saw some tumultuous times for Asian butane. What started the year as a tight market, with butane trading at $120/ton over propane — a 25% premium — flipped to a surplus market in the second quarter, with the products trading about even, then reversed again later in the year. In the middle of it all was India, whose relationship with butane as a cooking fuel suffered a spring break-up before reconciling in the fall. It was a textbook example of how today’s energy markets are buffeted by changes in production trends, government intervention and the growing influence of U.S. exports, which are becoming a much bigger deal in the global butane trade. Today, we continue our discussion of the supply and demand dynamics that shaped Asian butane markets in 2017, and what these trends may mean for 2018.
Mexico’s natural gas market continues to evolve rapidly. New pipelines are being built to move increasing volumes of U.S.-sourced gas to Mexican power plants, industrial customers and other end users. Gas exports from the U.S. to Mexico already average 4.5 Bcf/d and those volumes are sure to rise as more pipelines and power plants come online. Just as important, the government of Mexico has been taking aggressive steps to undo what had been state-owned Petróleos Mexicanos’s (Pemex) near-monopoly on gas pipeline capacity and to encourage a large and diverse group of gas marketers to enter the fray. Today, we examine ongoing efforts to increase transparency, pipeline access and competition in the gas market south of the border, and look at how Comisión Federal de Electricidad’s (CFE) marketing affiliate, CFEnergía, is growing its gas marketing business within Mexico.
Permian crude oil production continues to march steadily upward, headed toward 3.0 MMb/d sometime in the next few months. Most of the recent growth responsible for pushing total U.S. output past 10 MMb/d has come from increases in Permian volumes. Pipeline capacity out of the super-hot play is on the ragged edge of maxing out, and a myriad of new projects to relieve capacity constraints are in the works. Why then has the price differential between Midland, TX, and the Gulf Coast dropped over the past few weeks? Why did the Brent vs. WTI/Cushing spread crater? And what does this all mean for Midland-to-Gulf Coast transport deals getting struck for $2.00/bbl or less? Today, we look at these developments, try to make sense out of the Permian/Midland crude oil market, and consider what the future might hold for West Texas barrels moving to the Gulf Coast.
The recent rise in crude oil prices to levels not seen since late 2014 certainly has captured everyone’s attention, and generally boosted the financial prospects for U.S. producers and midstreamers alike. But while it’s often said that a rising tide lifts all boats, the fact is that accurately assessing the relative value of — and prospects for — specific midstream energy companies requires a deep, detailed analysis. Where are their assets located? How do they complement each other? Do their contractual obligations help or hinder? Sure, things may be looking up in the midstream sector in a big-picture sense, but that hardly makes every midstream company a winner. Today, we review highlights from a new East Daley Capital report that shines a bright light on 28 U.S. midstream companies.
Producers in the Western Canadian Sedimentary Basin (WCSB) are in a bind. Crude oil output in the WCSB has risen by more than 50% over the past seven years to about 4 MMb/d and is expected to increase to 5 MMb/d by the mid-2020s. But there has been only a modest expansion of refinery capacity within the region and pipeline capacity out of the WCSB, and lately takeaway constraints have had a devastating effect on the price relationship between benchmark Western Canadian Select (WCS) and West Texas Intermediate (WTI). What’s ahead for WCSB producers and WCS prices? Today, we continue our series on Western Canadian crude and bitumen markets, this time focusing on WCSB refinery capacity and existing pipelines out of the region.
It was a wild ride for Asian butane in 2017, driven by a range of diverse market factors, including U.S. ethane and LPG exports, a government program in India to encourage switching from firewood to LPG, the OPEC/NOPEC crude oil production cuts and LPG contract pricing set by Saudi Arabia. It was a textbook example of how today’s energy markets are buffeted by changes in production trends, government intervention and the growing influence of exports. Today, we introduce a series on the supply and demand dynamics that shaped Asian butane markets in 2017, and that will drive LPG markets in Asia, Europe and the U.S. in coming years.
In 2017, the U.S. Northeast sent more natural gas to Canada than it received, making the region a net exporter for the first time on an annual average basis. That marks another milestone in the ongoing flow reversal happening in the Northeast, led by the growth of local gas supply from the Marcellus/Utica shales. For now, the region still relies on Canadian gas during the highest winter demand months, but imports from Canada in all the other months are increasingly unnecessary as Northeast gas production balloons further. Today, we look at evolving dynamics at the U.S.-Canadian border in the Northeast.
