The rise in unconventional natural gas supplies in Western Canada has forced the region to again confront a dilemma that it faced in the 1990s and early 2000s: not enough export pipeline capacity to move all that gas to market. Although demand for natural gas has been growing in Alberta’s oil sands and power generation markets, it has not kept pace with provincial gas supply growth, leading to oversupply conditions and historically low gas prices. The need to export more of the gas to other parts of Canada and the U.S. is driving some pipeline expansions in the region. The question is, will they be enough? Today, we provide an update on the utilization of existing export routes, as well as the prospects (or lack thereof) for takeaway expansions, starting with Westcoast Energy Pipeline.
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Daily energy Posts
Any joint venture has its pros and cons for each party, and in an ideal world, everyone involved in a JV sees net benefits from pairing up with a partner. A quarter-century ago, state-owned Petróleos Mexicanos (Pemex) purchased a 50% stake in Shell’s Deer Park, TX, refinery. The JV partners also entered into a 30-year processing agreement under which each would purchase half of the refinery’s crude feedstock and own half the output. Separately, Pemex agreed to supply as much as 200 Mb/d of Mexico’s heavy sour Maya crude to Deer Park and Shell agreed to supply Pemex with 35-40 Mb/d of gasoline to help meet Mexico’s refined products deficit. The partners recently agreed to an early extension of the deal by 10 years from 2023 to 2033, while reducing the supply of Maya crude after 2023 to 70 Mb/d, to be sold at a fixed price. Today, we continue an analysis of the JV and the new changes to it.
Twenty-five years ago, in 1993, the Mexican national oil company — Petróleos Mexicanos, or Pemex — purchased a 50% stake in Shell’s Deer Park, TX, refinery. The joint-venture partners entered into a 30-year processing agreement under which each would purchase half of the refinery’s crude feedstock and own half the output. Separately, Pemex agreed to supply as much as 200 Mb/d of Mexico’s heavy sour Maya crude to Deer Park and Shell agreed to supply Pemex with 35-40 Mb/d of gasoline to help meet Mexico’s refined products deficit. The partners recently agreed to an early extension of the deal by 10 years from 2023 to 2033, while reducing the supply of Maya crude after 2023 to 70 Mb/d, to be sold at a fixed price. Today, we begin a two-part series on the joint venture with a look at how Pemex has benefitted.
It’s been a year since Hurricane Harvey made landfall and devastated the Texas Gulf Coast, and the Atlantic Basin is once again entering peak hurricane season. Among the widespread and prolonged effects of Harvey was the disruption of refinery and refined product pipeline capacity along the Gulf Coast, which then reverberated in downstream markets across Texas, and the U.S. East Coast and Midwest regions. As such, a closer look at Harvey’s timeline provides key insights into the importance of Gulf Coast refineries to the broader U.S. market. Today, we continue our series on Gulf Coast refining and pipeline infrastructure, and how a natural disaster along the coast can impact the rest of the country.
On August 25, 2017, Hurricane Harvey made landfall as a Category 4 hurricane near the popular Gulf Coast vacation town of Rockport, TX, just east of Corpus Christi. Harvey was the first major hurricane (Category 3 or higher) to make landfall along the U.S. Gulf Coast since the devastating 2005 hurricane season that included hurricanes Katrina, Rita, and Wilma, and is tied with Hurricane Katrina as the most expensive storm ever to hit the country. Harvey also highlighted just how important the Gulf Coast refining and refined product pipeline infrastructure is to the rest of the U.S. Today, we mark the one-year anniversary of the devastating storm with a three-part series on Gulf Coast refining and pipeline infrastructure, and how a natural disaster along the coast can impact the rest of the country.
The countdown clock to January 1, 2020 — Implementation Day for the IMO 2020 rule on low-sulfur marine fuel — is ticking, and while that date may still seem far away, it is decidedly not. The impending switch from 3.5%-sulfur fuel oil to marine fuel with sulfur content no higher than 0.5% will affect a broad swath of the energy sector worldwide, not to mention consumers of diesel and other low-sulfur distillates that will be in much higher demand by this time next year as the run-up to IMO 2020 kicks into high gear. Already, complex and simple refineries alike are evaluating changes to their crude slates and planning to add equipment that will enable them to produce more high-value distillate and less “bottom-of-the-barrel” residual fuel oil, the source of high-sulfur marine fuel. U.S. midstream companies are gearing up to export more light, sweet crude from the Permian and other shale and tight-oil plays to simple refineries that will no longer be able to get by refining heavy, sour crudes. Marine-fuel suppliers are testing various blends to see which might produce IMO 2020-compliant fuel at the lowest cost. As for ship owners, they’re preparing for topsy-turvy fuel prices in late 2019 and 2020 as this wrenching change plays out. Today, we consider key market participants’ latest thinking on the likely effects of the new rule for low-sulfur marine fuel.
The trade war between the U.S. and China continues to intensify — and now the rhetoric is shifting from steel and soybeans to oil and gas. What started as just an exchange of escalating bluster has developed into real tariffs that will be enacted beginning August 23 — which will include petroleum-based products like LPG and refined products. The commodities that would have the biggest impacts on global trade flows, liquefied natural gas and crude oil, were under tariff threat as well. LNG is still on a list of potential commodities to receive tariffs in the future, while crude has since been removed. But, keep in mind that today’s state of affairs could change tomorrow, so tariffs on those two commodities should be considered very much on the table. Today, we examine the potential trade war fallout for growing exports of U.S. LNG and crude oil.
While crude oil producers in the prolific Permian Basin are living out a Shale Revolution, the Midcontinent region of the U.S. is having a Refining Renaissance. Crude takeaway constraints, mainly due to insufficient pipeline capacity, are driving the prices of crude in Western Canada and West Texas to attractive lows against the WTI NYMEX benchmark for crude at the Cushing, OK, hub. Cheaper oil can contribute to bigger margins for refiners, who are supplying increasing volumes into a retail market that’s selling gasoline at the highest prices in four years. What will happen if the refiners don’t rein in their runs? Today, we’ll explore the implications of record-high run rates in the U.S. refining industry.
The Caribbean is strategically located at the crossroads of international trade routes between the Northern and Southern hemispheres, as well as the Atlantic and Pacific oceans. It has traditionally attracted oil trading, blending, and refining activity to meet the needs of local and international markets. Lately, the meltdown of Venezuelan national oil company Petróleos de Venezuela SA (PDVSA) — previously a dominant player in the region — has left refineries and storage terminals underutilized and starved of investment. U.S. Gulf Coast refineries have partially filled the gap by increasing product exports to the region, but an opportunity now exists for private investment to fill the refining and storage void left by PDVSA, and also to meet new demand for low-sulfur bunker fuel arising from stricter International Maritime Organization shipping regulations, which will come into effect in January 2020. Today, we review the impact of the PDVSA meltdown and new investment projects being pursued.
Back on March 15, the Federal Energy Regulatory Commission shook up master limited partnerships (MLPs) and their investors by deciding that income taxes would no longer be factored into the cost-of-service-based tariff rates of MLP-owned pipelines. We said then that there was no need to panic. In part, this was based on the view the FERC policy wouldn’t affect as much of the industry as some worried it would. But more importantly, our soothing message was tied to the fact it would take a long time for this to play out. It looks like we were right to have some confidence. Today, we explain why the commission’s July 18 vote on a topic as nerdy as “accumulated deferred income taxes” can warm the hearts of MLP investors.
Mexican demand for U.S.-sourced refined products continues to increase, but Mexico lacks the infrastructure required to efficiently import, store and distribute large volumes of gasoline and diesel. That has spurred the rapid build-out of new port and rail terminals, new pipelines and new storage capacity on both sides of the U.S.-Mexico border. At the same time, Mexico’s state-owned energy companies are gradually opening access to their existing refined-products pipeline and storage networks — which helps a little, but not enough. Today, we discuss the latest round of midstream projects tied to U.S. exports of motor and jet fuels to its southern neighbor.
The planned implementation of the International Maritime Organization’s rule slashing allowable sulfur-dioxide emissions from ocean-going ships on January 1, 2020, would create significant demand for 0.5%-sulfur marine fuel — a refined product that few refiners produce today. That could present a big challenge to the global refining sector, which will be called upon to produce marine fuel that complies with “IMO 2020,” as the rule is commonly known. But refiners have stepped up before, and if the IMO 2020 mandate proves to be unachievable and would put global commerce at risk, there could be ways to deal with it — including exemptions or implementation delays. In any case, the move toward much cleaner bunker fuel will be a boon to complex refineries along the U.S. Gulf Coast and elsewhere that can break down bottom-of-the-barrel “residual” fuel oil into feedstocks for gasoline, diesel and other high-value products. Today, we continue our analysis of IMO 2020 and its effects.
There has been a lot of acrimony and polarization among the natural gas industry, the environmental community, various consumer advocates, industrial energy users, organized power markets and renewables developers in recent years. However, the ongoing government efforts to prop up the power sector’s coal-fired and nuclear generators have succeeded in uniting all those disparate interests into a single voice saying a single word: No! Today, we discuss the history of the administration’s planned support of coal and nuclear, the unusually unified reaction to it from groups that are more often at odds with each other, and some underlying assumptions about natural gas that aren’t — well — how the gas industry says it works.
Drilling and completion activity in the Permian Basin doesn’t only produce vast quantities of energy, it consumes a lot of energy too, mostly in the form of diesel fuel to power the trucks, drilling rigs, fracturing pumps, compressors and other equipment needed to keep the oil patch humming. And while refineries within or near the Permian meet a portion of the region’s needs, rising demand for diesel there is spurring the development of new infrastructure — and the repurposing of existing assets — to bring additional fuel into the Permian from refineries along the Gulf Coast. Today, we discuss efforts to move more diesel to the oil fields of West Texas.
Two months ago, the Federal Energy Regulatory Commission shook up master limited partnerships (MLPs) and their investors by deciding that income taxes would no longer be factored into the cost-based tariff rates of MLP-owned pipelines. We said then that there was no need to panic — that all this will take time to play out, and that the end results may not be as widespread or dire as some feared. Today, we provide an update, dig into FERC’s other actions on changes in income taxes, and discuss the phenomenon known as “FERC Time.”
Shipowners and refiners are struggling with how to prepare for January 1, 2020, when all vessels involved in international trade will be required to meet significantly stricter limits on emissions of sulfur oxides (SOx), either by using fuel with a sulfur content of less than 0.5% or by “scrubbing” the exhaust of ship engines when using the much higher-sulfur bunker fuel that most ships now rely on. The International Maritime Organization’s (IMO) new sulfur rule isn’t a minor tweak. It’s a game changer that already is causing widening spreads on the futures market between 3.5%-sulfur heavy fuel oil (HFO) — the traditional global bunker fuel — and rule-compliant low-sulfur distillates. The rule also promises to be a boon to complex Gulf Coast and other refineries that can break down residual-based HFO into higher-value, lower-sulfur distillates. Today, we begin a new series on how shipowners, refiners and the markets for HFO and low-sulfur marine fuel are responding (or not) to the coming change in global bunker requirements.