How do you sum up a year like 2021? It was good times for the economic health of producers and midstreamers alike. Prices were up, as were production and flows. But 2021 also brought along more than its share of chaos, including disruptive market events like Winter Storm Uri’s deep freeze and Europe’s natural gas crisis, along with general perplexity around all things clean, green, renewable, and certified. At RBN we take a different approach to assessing common industry themes. Namely, we examine the events and trends that the market considers the most important — crowd-sourced market intelligence, if you will. We can do that because every weekday we post a blog covering a single topic and blast it to almost 35,000 people, and we scrupulously monitor the website hit rate to see which blogs garner the most interest. Then, at the end of the year, we look back to see which topics rank at the top of the hit parade. That score reveals a lot about major market trends. So today we dive into our Top 10 blogs based on the number of rbnenergy.com website hits over the past year to see what we can learn about where things stand today and what’s up next.
Keystone XL
Late last month, the Canada Energy Regulator (CER) ruled against Enbridge’s proposal to convert as much as 90% of the capacity on its multi-pipeline, 3-MMb/d Mainline crude oil system to long-term contracts. The CER’s action leaves in place the Mainline’s current capacity-allocation process, under which every barrel-per-day of the pipeline system’s capacity is open to all shipping customers on a month-to-month basis. Although the rejection of Enbridge’s proposal is unlikely to change the volume of Western Canadian crude oil flowing on the Mainline over the next few months, the longer-term outlook for Mainline flows is less certain given that other, competing pipeline capacity out of Alberta will be coming into service by late 2022 or early 2023. In today’s RBN blog, we examine the decision to reject long-term contracting and what might be the next steps for Enbridge.
U.S. presidential transitions often bring policy changes, but few have been as dramatic and swift as the shift in energy policy that came with President Biden’s inauguration in January. Among his first acts after being sworn in was the signing of an executive order that revoked the Presidential Permit for TC Energy’s long-planned Keystone XL crude oil pipeline. Among other impacts, the move put on ice more than one-third of the Canadian midstream giant’s C$37 billion capital spending program for the 2021-24 period and unraveled TC Energy’s plan to balance its natural-gas-weighted pipeline portfolio with more crude oil pipes. So, what’s next for the midstreamer now that KXL is a no-go? In today’s blog, we’ll discuss highlights from our new Spotlight report on TC Energy which lays out how the company arrived at this juncture and where it goes from here.
Sure, there was at least some hope among Keystone XL’s supporters that President Biden might back away from his promise to kill the much-maligned crude oil pipeline project. After all, KXL developer TC Energy had done all it could to make the 1,210-mile project more palatable to the incoming administration by making Canadian First Nation groups partners in the project, reaching a favorable labor agreement with the four U.S. unions that would build the pipeline, and, most recently, committing to invest in renewable energy to power KXL’s pumps and other equipment. But it wasn’t enough, and now, with Biden’s decision to revoke the project’s Presidential Permit, it appears that the Alberta-to-Nebraska pipeline is all but dead, and that Western Canada will need to get by without its 830 Mb/d of southbound capacity. The looming question now is, what does that mean for Alberta’s producers — particularly those that have signed up for more than 500 Mb/d of space on KXL? Today, we discuss what’s ahead.
For most of the past few years, crude oil producers in Alberta have dealt with pipeline constraints that often forced them to sell their crude at steep discounts. While the constraints eased somewhat earlier this year as producers reduced their output due to cratering oil demand and oil prices, production more recently has been rebounding, resulting in the return of takeaway concerns. The big hope is that long-planned pipeline projects like the Trans Mountain Expansion (TMX) and Keystone XL will finally be built and commissioned, but they still face legal and regulatory hurdles before being completed. Lately, a different option has gained momentum focusing on a proposed rail line linking Alaska to the immense oil sands region of northern Alberta, potentially creating another corridor for the export of oil sands crude. Today, we describe recent developments in a bold plan to build a rail line from Alberta, across northern Canada, and into Alaska.
The demand destruction caused by COVID-19 hasn’t only hurt producers and refiners; it’s also slowed the development of a number of planned midstream projects. In fact, the only multibillion-dollar crude-related project to reach a final investment decision (FID) during the pandemic is TC Energy’s Keystone XL, which in late March won financial backing from Alberta’s provincial government. But Keystone XL soon hit another snag, this time in the form of U.S. district and appellate court rulings that vacated the project’s Nationwide Permit 12 for construction in and around hundreds of streams and wetlands along the U.S. portion of the pipeline’s route in the U.S. More important, the courts also put on ice — at least for now — the use of the general water-crossing permit for other new oil and natural gas pipelines as well. As we discuss in today’s blog, that could result in delays and legal challenges to dozens of projects that midstreamers and their counterparties have been counting on.
For most of the past three years, Western Canadian producers have had to deal with crude oil pipeline constraints — takeaway-capacity shortfalls serious enough to spur huge price discounts for the region’s benchmark Western Canadian Select (WCS) that are sufficient to support the higher cost of crude-by-rail alternatives. But things are changing, and fast. WCS prices are at or near historic lows — low enough to convince a number of producers to rein in their capital spending and production. Crude-by-rail use is down, and there’s even space available on the usually maxed-out Enbridge Mainline system, the region’s primary pipeline egress. And wouldn’t you know it, just as production is slipping and constraints are easing, real progress is being made on three big pipeline projects that had long been in limbo: the Line 3 Expansion, the Trans Mountain Expansion (TMX) and Keystone XL. Today, we provide an update on Western Canadian crude takeaway capacity and examine whether the region may — irony of ironies — end up with too much.
For more than six months now, the provincial government of energy-rich Alberta has been trying to mitigate the sometimes painful effects of having too little pipeline capacity to move crude oil to market. They’ve mandated production cuts by larger producers, contracted for crude-by-rail (CBR) services — then moved to undo those deals — and pressed the Canadian government to help advance long-delayed pipeline projects. Things appear to have reached a semi-happy medium for now: the price spread between Western Canadian Select (WCS) and West Texas Intermediate (WTI) has narrowed, but remains wide enough to justify sending crude out by train. Still, it’s clear that the big tranches of new pipeline capacity many had hoped would be built or at least under construction by now face more hurdles. How long will Alberta producers need to wait for unfettered pipeline access to the U.S. Midwest and Gulf Coast and to Canada’s West Coast? Today, we provide an update on WCS pricing, Alberta crude-by-rail, and the key pipeline projects that never seem to get finished.
The late-August decision by Canada’s Federal Court of Appeal to overturn the Canadian government’s approval of the Trans Mountain Expansion Project will delay the project’s completion to at least 2021 or 2022. And — who knows? — the unanimous ruling may ultimately lead to TMX’s undoing, despite the Canadian government’s acquisition of the existing Trans Mountain Pipeline and the expansion project and its commitment to get TMX built. As producers in the Western Canadian Sedimentary Basin (WCSB) know all too well, TMX’s 590 Mb/d of incremental pipeline capacity would help to resolve ever-worsening pipeline takeaway constraints out of the Alberta oil sands and other production areas in the WCSB. These constraints are having a major economic impact every day — as evidenced by price differentials wide enough to run a locomotive through. Speaking of trains, crude-by-rail exports out of Western Canada reached a record 205 Mb/d in June, an 86% increase from the same month last year, and with WCSB production rising as new oil sands capacity comes online and with only limited relief likely on the pipeline capacity front from the Enbridge Line 3 Replacement Project in late 2019, many producers will need to depend on rail shipments of crude well into the 2020s. Today, we discuss the recent court ruling and what it means for Western Canadian producers, price spreads and the future of crude-by-rail.
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.
On Friday, TransCanada finally secured a Presidential Permit for the U.S. portion of its Keystone XL pipeline, and the company committed to pursuing the state approvals it still needs to build the project. But three hard truths—crude oil prices below $50/bbl, the high cost of producing bitumen and moving it to market, and more attractive energy investments available elsewhere—have thrown a wet blanket on once-ambitious plans to significantly expand production in Western Canada’s oil sands, the primary source of the product that would flow through Keystone XL. Today we begin a series on stagnating production growth in the world’s premier crude bitumen area, the odds for and against a rebound any time soon, and the need (or lack thereof) for more pipelines.
Much of RBN’s forecast 1.4 MMb/d expansion in Canadian crude production between 2014 and 2019 is expected to come from oil sands bitumen in Western Canada. An increasing proportion of this crude has to find its way to refineries configured to process this type of crude on the Gulf Coast. But pipeline capacity on that route is in critically short supply. An important set of expansions to existing Enbridge and Enterprise pipelines between Canada and Texas, parts of which are set to come online soon, hopes to alleviate the situation. Today we wrap up a two part series describing these projects and their impact.
So far in 2013 around 645 Mb/d of new crude oil pipeline capacity has opened up to ship supplies to the Texas Gulf Coast. Early this month (December) line fill starts on the largest new capacity addition to date – the 700 Mb/d Keystone Gulf Coast Pipeline. The new pipeline runs from Cushing to Port Arthur and will carry mostly Canadian heavy crude. Today we wonder if all that crude will find a home.
The first episode in this series described 4 MMb/d of current and planned expansions to crude transportation capacity into the Texas Gulf Coast region (see Handling The Texas Gulf Coast Crude Flood). Our analysis showed that the new incoming light crude capacity will exceed Texas Gulf Coast demand by somewhere north of 0.5 MMb/d by the end of 2015. In episode two we described how some of these excess crude supplies would move east on the reversed Ho-Ho pipeline (see Gulf Coast Crude West to East Flows). In episode three we looked at how shippers could divert supplies away from Texas Gulf Coast congestion (see Texas Gulf Coast Bypass Options). This time we consider the impact of the Keystone Gulf Coast pipeline.
One of the more confusing features of the Keystone Gulf Coast Pipeline is what to call it – the name seems to change in real time. That is probably due to a desire to disassociate the southern Gulf Coast section of the pipeline from delays in permitting the Canada to US Keystone XL pipeline. Owner and operator TransCanada most recently set up a subsidiary to operate the pipeline called Marketlink LLC and it should now apparently more properly be called the Cushing Marketlink Pipeline so we will go with CMP as an abbreviation.
The 36-inch-diameter CMP runs 485 miles from Cushing, OK, to Nederland, TX (see green line on the map below). The line will have an initial capacity of 700 Mb/d with the option to expand to 830 Mb/d. It is almost ready to commence operations but before that can happen it has to be filled with oil – a process known as “line fill”. We described how line fill works and provided a formula to approximate the volume of oil required back in May 2012 (see A Time for Gas A Time For Crude – Part 2). According to that formula CMP requires 3.5 MMBbl of line fill. Marketlink LLC has said the first pipeline deliveries will be made before the end of 2013. The company is also constructing a 48-mile Houston Lateral pipeline (orange line on the map) that will run from the Liberty pumping station to East Houston and should be online by the end of 2014 with 130 Mb/d capacity.
Source: TransCanada Website and RBN Energy (Click to Enlarge)
The initial destination of the CMP is the Sunoco Logistics (part of Energy Transfer Partners) Nederland terminal. We have covered the Nederland terminal in two previous blog posts (see Nederland Crude Wonderland and Nederland Crude Volume Surges). The terminal is located on the Sabine-Neches waterway between Beaumont and Port Arthur, TX and has 22 MMBbl of storage capacity (see map below). The location is in the heart of Beaumont/Port Arthur refining country – home to four large refineries owned by ExxonMobil (Beaumont, 365 Mb/d), Valero (Port Arthur, 310 Mb/d), Total (Port Arthur, 174 Mb/d) and Shell/Saudi Aramco (Motiva 600 Mb/d). The Sabine Neches Waterway connects to the Gulf of Mexico, providing waterborne access to the entire Gulf Coast region. Nederland is about 100 miles East of Houston and 350 miles West of New Orleans.
This year (2013) Canadian regulators are expected to decide the fate of two West Coast crude oil pipeline projects. If one or both of these pipelines get the go-ahead then future expansion of Canadian production will be secure for a few more years and the export option to Asia will bring producers higher prices. The regulators face a single jeopardy – approve the pipelines or Canadian crude production expansion will decline. Producers face a double jeopardy if the pipelines are not built – lower production and lower prices. Today we discuss how critical the West Coast pipeline projects are to Canadian producers.
Yesterday the folks at Raymond James issued a great research piece titled “Hell Brent and Gulf Coast Bound, WTI Discount's Here to Stay”. Got to love those RJ titles. We won’t get into their numbers or the details of their analysis, but three of their points I’ll summarize here.