The refinery sits next to Valero’s existing Houston facility, which has a capacity of 205,000 barrels per day (b/d) and has run at essentially nameplate capacity in recent years. Both facilities (see blue arrows in figure below) are on the Houston Ship Channel, giving them a range of crude supply and logistics options. The LyondellBasell site was largely served by the Seaway Pipeline, co-owned by Enterprise and Enbridge, and by direct connections to Enterprise’s Houston Ship Channel terminal (Enterprise terminals in green arrows below). The facility also took crude from Energy Transfer’s HFOTCO assets (orange arrow) and has an indirect connection to the MarketLink and Keystone pipeline system (white arrow). Valero’s existing Houston refinery is largely served by ONEOK’s Houston distribution system, which ties into storage such as the Galena Park terminal and East Houston terminal (purple arrows). A Valero-owned last-mile pipeline connects all these systems to both refineries.

LyondellBasell’s refinery previously cited a capacity of roughly 265,000 b/d and ran mostly full, aside from several notable maintenance windows. Valero, however, expects to initially restart just 165,000 b/d of light sweet crude processing capacity by year-end 2027. That is a marked change for a facility where heavier crude appears to have made up more than 80% of the previous (2016-2025) inputs (see figure below).

Crude Oil Imports by Type - EIA

Much of the facility’s medium and heavy supply was imported from Colombia by vessel and Canada via Seaway Pipeline (see country mix below). Valero has left the door open to a return to these heavier grades in the future, saying the deal creates an opportunity to invest later in high-complexity, heavy sour crude processing.

Crude Oil Imports by Country - EIA

The transaction reinforces a theme we highlighted in September, when the White House was considering using the Defense Production Act to help boost fuel output. At the time, we identified refineries that could be restarted, in whole or in part, to increase capacity, including this LyondellBasell facility. While the initial restart would return only part of the plant’s former capacity, the deal shows that idled refining assets with strong logistics can still attract buyers.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 500 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

Phase 1 includes seven new storage tanks, a rail offloading system that can handle a 120-car unit train, and a new marine dock. A central focus appears to be giving the refinery a reliable way to receive waxy crude from Utah’s Uinta Basin, which moves by rail and must be kept heated to flow. The facility’s air permit includes six natural gas-fired boilers for railcar heating and two dedicated storage tanks for yellow wax crude, each holding about 110,000 barrels, which are likely among the Phase 1 tanks. The dock has received U.S. Coast Guard approval and is expected to be fully operational by the end of October (see photo below).

Image credit: Copernicus Sentinel data October 2026

Phase 2 is expected to begin construction in early 2027 and appears designed to support Chevron’s planned refinery expansion at Pascagoula. That project, approved by Mississippi regulators in March 2026, will raise the refinery’s crude capacity from 361,000 to 394,000 barrels per operating day by removing bottlenecks at its crude units, with startup targeted for the third quarter of 2027. BWC’s air permit covers 20 storage tanks totaling roughly 4.1 million barrels, which implies up to 13 additional tanks in Phase 2. The permit caps annual throughput of crude at 10 million barrels and yellow wax crude at 5.5 million barrels, or roughly 42,000 barrels per day combined. That is in line with the roughly 33,000 barrels per day of new refining capacity (see table below).

Refinery throughput data show Pascagoula running at or near full capacity, and in some months above nameplate (see below graph), so there is little spare room in the current system. Today, Pascagoula draws its crude from three main sources. The largest is Chevron’s wholly owned Cal-Ky pipeline system, which carries offshore Louisiana production through Chevron’s Empire terminal and on to Pascagoula via a subsea pipeline, moving around 165,000 barrels per day. The second is Chevron’s legacy marine terminal at the refinery, which handles roughly 100,000 barrels per day, mostly foreign imports. The third is Plains’ Mobile-to-Pascagoula pipeline, which brings ~85,000 barrels per day of crude imported through via a marine dock in Mobile, Alabama (see below). That route is likely used in part because marine import capacity at Pascagoula has been limited, a constraint the BWC dock could ease.

Taken together, the BWC terminal gives the Pascagoula refinery more flexibility in its crude supply, especially for Uinta waxy crude, and adds marine import capacity. In principle, that could shift some imports away from Mobile and reduce volumes moving through Plains’ Mobile terminal and Pascagoula pipeline. We think that is the less likely outcome. BWC terminal’s sizing, permit limits, and phasing all point to a project built mainly to feed the refinery’s 2027 expansion, with optionality as a secondary benefit, rather than one meant to displace existing supply routes.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 500 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

The timing of the increase roughly lines up with Trans Mountain’s drag reducing agent (DRA) expansion project, which is designed to add 90,000 barrels per day of new capacity (bringing the total to 980,000 bpd). Regulatory documents and past public comments from the company have pointed to an estimated in-service date of December 2026. However, filings also laid out a construction schedule showing work could be complete by the end of September (see schedule below). Adding to the case for an early start, the Canada Energy Regulator (CER) approved Trans Mountain’s firm service contracting application for the project at the end of September, which theoretically could allow those new contracts to begin this month.

Trans Mountain previously announced that the mainline would be in apportionment for October 2026, meaning shipper nominations exceeded available space and the pipeline would be running relatively full. Apportionment on its own does not explain the record volumes, though. The pipeline has been apportioned in prior months without dock volumes reaching anywhere near current levels. The combination of record throughput, a completed construction window, and fresh regulatory approval for new contracts suggests the DRA expansion capacity may now be in service.

Volumes on the system may move higher again in January 2027. No additional physical capacity is scheduled for that period beyond the DRA project, but Trans Mountain received approval at the end of September to raise its committed capacity cap from 80% to 90% (see table below). That change shifts a larger share of the pipeline’s space into firm, contracted service, which could support higher and more consistent utilization going forward.

Looking further out, the next major milestone is the Mainline Optimization Project, currently slated for late 2028. That expansion would add roughly 210,000 barrels per day of capacity to the system, including around 200,000 barrels per day of new incremental firm capacity (see table above). Taken together, the DRA expansion, the higher committed capacity cap, and the optimization project mark a steady build-out of Canada’s only direct crude export route to the West Coast, and October’s record shipments may be the first visible sign of that next phase.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 500 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

Looking ahead to 2027, calendar strip prices indicating West Texas Intermediate averaging around $85 per barrel will likely justify a material expansion in drilling activity. This projected increase in production threatens to push existing crude oil egress capacity from the Permian to the Gulf Coast to its limits by the end of 2027. Our current analysis indicates the basin has only 500,000 to 600,000 barrels per day of remaining capacity to the Gulf Coast through brownfield expansions and latent capacity before pipelines hit their limits (see graph and red arrow below).

When Gulf Coast routes approach full capacity, barrels will need to find alternative paths out of the basin, most likely utilizing pipelines heading north toward Cushing, Oklahoma. Three key pipeline systems would absorb this overflow: the Basin Pipeline, the Sunrise II Pipeline, and the Centurion Pipeline. Collectively, these routes feature approximately 600,000 barrels per day of open capacity (see graph below), positioning them to capture substantial volume if Permian bottlenecks intensify.

Beyond increased throughput volumes, certain systems possess distinct commercial advantages that amplify their revenue potential. Both the Basin and Sunrise II pipelines hold market-based rate authority with the Federal Energy Regulatory Commission, allowing them to increase rates uncapped as alternative Gulf Coast pathways fill. While full Gulf-bound pipelines would widen differentials and eventually incentivize the construction of a new greenfield pipeline, these Oklahoma bound pipeline assets could see a compelling short to medium term upside as early as late 2027.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 500 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

The most immediate operational impact centers on offshore crude oil production. Total Gulf output currently sits at approximately two million barrels per day, and we estimate roughly 500,000 barrels per day sit within the storm’s forecasted path. Key offshore infrastructure (shown in figure below) includes Shell-operated pipeline networks carrying around 300,000 barrels per day, alongside Williams’s Mountaineer pipeline and Chevron’s Breton Sound system, which together transport over 100,000 barrels per day from projects like Ballymore (shown in graph below). Crescent pipelines account for another 100,000 barrels per day. Facilities directly in the storm’s path face temporary shut-ins as a precaution, though swift recoveries remain typical provided physical infrastructure avoids heavy damage.

Beyond offshore extraction, onshore refining capabilities along the Gulf coast present a critical point of exposure. While high winds pose structural risks, storm surge and heavy flooding present the most severe operational challenges for onshore facilities. Chevron’s refinery in Pascagoula, Mississippi, represents the largest single facility in the path, processing roughly 350,000 barrels per day (see graph below). Capable of supplying approximately 2% of total U.S. diesel production, any prolonged disruption at Pascagoula would add immediate pressure to tight domestic and global fuel supplies. Smaller refining assets in the region, including Vertex’s facility in Mobile, Alabama, and Hunt Refining assets, also face potential impacts or operational pauses.

Regional energy supplies also rely heavily on maritime terminals and cross-regional supply chains. Critical import docks owned by Plains, Vertex, and Hunt located in Mobile Bay (see figure below) manage significant volumes of foreign imports and domestic barge/Jones Act traffic. These marine terminals feed key supply lines, which supply crucial crude inputs into regional refining facilities (see pipelines in figure below). Even if inland refineries escape a direct meteorological hit, localized flooding, power outages, or port closures around coastal terminals could choke off crude supply and throttle downstream production until marine transit safely resumes.

We will continue to monitor the track of the hurricane closely and provide further updates if the forecast shifts significantly to encompass additional infrastructure. Please reach out directly with any inquiries regarding specific asset-level data or localized impact analyses.

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For barrels originating at the Bryan Mound SPR facility, DOE-owned pipelines will route crude to either the Seaway export docks at Freeport (green arrow in below figure) or to refining and terminal assets in Texas City (purple arrow), including a second export-capable Seaway dock. Historical data (graph in figure below) from earlier SPR distributions in April and May 2026 showed immediate, dramatic spikes in export volumes across both Seaway marine terminals as operators moved crude into global markets. Jointly owned by Enbridge and Enterprise Products Partners, the Seaway system is positioned once again to capture incremental throughput fees as these fresh volumes hit the coast.

Simultaneously, the Big Hill SPR facility provides direct pipeline connectivity to refining and terminal complexes in the Nederland area. A DOE-owned pipeline (blue line in figure below) directly connects Big Hill to Energy Transfer’s Nederland terminal, which historically logged distinct export surges during the 2021–2023 SPR releases. While Big Hill remained inactive during earlier releases this year, the nearby West Hackberry SPR facility in Louisiana appears to have routed its releases to Nederland for export (see mid-2026 spike in graph below). With Big Hill set to supply throughput for the upcoming distribution, Energy Transfer stands to gain significant volume-based revenue across its Nederland marine terminal.

Critically, because the current program operates as an oil exchange rather than a permanent sale, the financial upside for both Energy Transfer and Seaway extends far beyond the initial distribution phase. As market participants return replacement barrels to government reserves in upcoming months and years, flow directions will flip. Both Energy Transfer’s Nederland terminal and Seaway’s marine locations will handle the incoming import ships, creating a rare two-way revenue cycle that maximizes terminal utilization on both egress and backfill.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 400 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

Despite these required premiums, current market conditions offer strong financial incentives for potential bidders. The crude oil forward curve is in steep backwardation, meaning near-term 2026 barrels trade at a substantial premium over later contracts post 2026 (see graph below). This price gap provides enough margin for bidders to sell expensive oil today and buy back cheaper replacement barrels later while keeping a solid profit, even after paying the required barrel premiums. The trade is especially attractive for 2029 returns. Although long-dated returns carry higher premium fees, 2029 oil prices are low enough to offset the cost. Furthermore, traders could invest the net cash proceeds from their late-2026 sales into risk-free government bonds, earning interest over the holding period before repurchasing the physical oil.

Barring a sudden flattening of forward oil prices before the bidding deadline or quality concerns of the remaining SPR crude, we expect this auction to be highly successful, with buyers taking all or nearly all of the 40 million barrels offered. This stands in clear contrast to a prior SPR tender earlier this year, where low participation occurred because narrowing price spreads wiped out trade margins during the submission window. Provided current market structure holds, strong buyer demand should clear most of the volume, bringing up to 40 million additional barrels onto the market in late 2026. Our SPR modeling (see graph below) currently assumes this latest SPR tranche is returned in the 2028-2029 window.

The Wrangler pipeline functions as an integrated entity constructed entirely from leased capacity across existing Enbridge assets. Specifically, it combines capacity on the Platte Pipeline with space on the southern leg of the Spearhead Pipeline, which spans from Key, Missouri, to the Cushing hub. By bundling these leased segments under a single operational umbrella, Enbridge provides shippers with a streamlined, single-entity committed service option to transport crude from Wyoming down to Cushing and additional Midwest refining centers. This new committed service structure is shown below and scheduled to take effect on October 1, 2026.

The 30,000 bpd offered under the Wrangler tariff matches the exact expansion volume Enbridge previously planned for the Express Platte system (blue and orange lines in figure below), as a key feeder component of its broader 2028 Southern Illinois Connector project (red lines). However, regulatory filings leave it unclear whether this 30,000 bpd represents existing unused capacity on the system or newly completed expansion capacity. While the new-build portion of the Southern Illinois Connector (Wood River to Patoka, Illinois) remains in permitting with a 2028 target online date, Enbridge management previously noted that the Platte expansion required only pump station upgrades and refurbishment. Because these pump station modifications could easily be finished ahead of schedule, the identical 30,000 bpd volume suggests, though does not confirm, that Enbridge may be bringing this expansion capacity online early via Wrangler.

If this does indeed represent early expansion capacity on Express Platte, it would immediately increase Canadian egress capacity heading into the winter, offering potential price support for Canadian crude pricing following recent seasonal weakness.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 400 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

With less crude being consumed in the Midwest, excess Canadian barrels must be pushed into storage or directed further south to U.S. Gulf Coast (PADD 3) refiners or export markets. Reaching Gulf Coast markets incurs significantly higher transport costs, naturally forcing the price differential wider. Furthermore, Canadian barrels arriving in the Gulf Coast face direct competition from other heavy crude imports, particularly heavy grades from Mexico and an increasing volume of Venezuelan crude entering the U.S. market. To successfully secure refinery space against these competing foreign heavy crudes, Canadian oil must offer deeper discounts.

Beyond demand-side constraints, temporary infrastructure outages may have added further friction to Canadian crude egress. Enbridge’s Line 5, which carries a capacity of 540,000 barrels per day and typically operates near full utilization (see graph below), experienced a temporary shutdown following a recent pipeline rupture. Although brief, this outage may have created bottlenecks for current monthly flows, further exacerbating downward pressure on WCS pricing.

Despite the near-term weakness in forward markets, the differential could narrow heading into the winter. Refinery operations at Joliet and Whiting should recover in short order, restoring baseline Midwest demand. On the logistics front, while egress is tight, we forecast capacity remains sufficient to handle anticipated volumes (see graph below), especially as the Trans Mountain pipeline expansion brings its drag-reducing agent (DRA) project online to add an estimated 90,000 barrels per day. Provided these pipeline capacity additions and refinery restarts proceed as expected, broader transport bottlenecks should be avoided, paving the way for a narrowing price gap.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 400 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

Beyond the gathering infrastructure, Plains also acquired Silver Creek’s 49% non-operating stake in the PRG pipeline system, which consists of the Powder River Express and Iron Horse short-haul transport lines. Because Enbridge acquired the other 51% controlling interest last week, the two midstream operators now find themselves joint owners of these crucial trunk lines. PRG moves barrels from PRCS gathering Pronghorn terminal to long-haul transmission pipelines in the Guernsey area, including Pony Express and Saddlehorn (in which Plains holds a 40% interest). By acquiring upstream infrastructure like PRCS, Plains may be able to exert greater influence over barrels near the wellhead, setting the stage for an increasingly competitive environment as both sides vie for volumes to feed their respective long-haul pipelines (see figure below).

Operationally, Plains has several options to optimize this new footprint and attract barrels over to its own systems. One potential play would be reversing flows on the PRCS Foxtail gathering line. This 8-inch line currently moves barrels from producing areas in Natrona County to the main PRCS trunklines, where barrels flow into PRG and down to Guernsey. Reversing this line would allow Plains to push barrels into its wholly owned Rocky Mountain North (a 12-inch line) and Bighorn Pipeline systems for delivery into Casper, Guernsey, or Fort Laramie where barrels could connect into Saddlehorn (see figure below). While Plains would forgo its share of pipeline tariffs on their 49% PRG ownership, capturing the full fee structure across its own pipelines could present a lucrative incentive to divert crude flows away from Enbridge-controlled routes.

Both the Foxtail and PRG routes also provide connectivity to Plains’ wholly owned Cheyenne pipeline in Guernsey, Wyoming. Utilizing this capacity with Plains' Cowboy Pipeline and their Saddlehorn interest downstream could allow barrels to also connect to the White Cliffs Pipeline in which Plains holds a 36% interest. This path offers yet another route to transport barrels to Cushing, Oklahoma, strictly on Plains-affiliated infrastructure.

This operational flexibility may sharpen the rivalry between Plains and Enbridge as both compete for market share in the Rockies. While Enbridge appears to hold the advantage in downstream egress optionality through its Pony Express and Platte pipelines, delivering into both Cushing, Oklahoma, and Wood River, Illinois, Plains now possesses critical leverage with upstream infrastructure close to the wellhead. With the Powder River Basin offering extensive untapped drilling inventory that becomes highly economical during periods of elevated oil prices, dealmaking and optimization projects are likely to continue across the region.

Debottlenecking Active Refineries

During the consultation, industry leaders reportedly emphasized that building new, large-scale refineries is an impractical fix. Instead, refiners advocated for targeted government investment in “debottlenecking” projects, which are incremental expansions designed to enhance existing operational efficiency. Historically, debottlenecking has quietly expanded U.S. processing capacity at numerous facilities. A prime example is Marathon’s Garyville refinery in Louisiana, which expanded its crude throughput from 539,000 barrels per day in 2016 to 617,000 barrels per day through steady, low-cost modifications (see red capacity line below). Federal backing under the DPA could accelerate similar quick-turnaround projects across numerous facilities, yielding a meaningful aggregate increase in fuel supply within 12 to 18 months.

^{Plainview’s map-based interactive crude oil platform (shown above with Garyville and below with Great Falls) has throughput or transactional data for ~100 North American refineries and ~400 pipelines/marine terminals. For a free trial email matthew.lewis@plainview-energy.com}

Restarting Idled Units or Converted Refineries

Beyond debottlenecking, refiners could evaluate the restart of idled or converted units of active facilities (shown in table below). Facilities like PBF Energy’s Paulsboro refinery in New Jersey brought several inactive units back online after the pandemic, yet approximately 35,000 barrels per day of capacity remain offline. Other operations, such as Calumet’s Great Falls facility (shown in figure below), previously converted hydrocracker units to produce renewable diesel. While reconverting these units back to crude oil processing is technically feasible, as demonstrated by CVR Refining and Vertex Refining, current strong margins for renewable diesel may make such shifts economically unappealing.

Similarly, fully converted renewable diesel facilities like HF Sinclair Cheyenne, Marathon Dickinson, and numerous California sites face high capital conversion costs, contractual delivery obligations, and favorable renewable margins, rendering near-term reconversions unlikely.

Restarting Cold-Stacked Refineries

The most capital and time-intensive path involves cold-starting major refineries that have been shut down for years (shown in table below). Lyondell’s Houston refinery, idled in early 2025, represents a significant prospective capacity source in a refinery-friendly state, though its current maintenance status and restart timeline remain uncertain. Other potential candidates include Par Pacific’s Kapolei West refinery in Hawaii, idle since late 2021, and Harvest Midstream’s Alliance Belle Chasse facility, which currently operates as a midstream terminal. However, facilities like Shell’s hurricane-damaged Convent refinery and several closed sites in California face steep technical, maintenance, and environmental permitting hurdles, making rapid restarts across those locations difficult to execute without substantial intervention.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 400 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

The true operational value of the acquisition may lie in future growth and integration including resolving historical “telescoping” bottlenecks along the Pony Express route. The system was originally assembled using distinct pipe segments: a 20-inch line from Guernsey to Northern Colorado, a 22-inch section from Northern Colorado to Northern Kansas, and a 24-inch new build finishing the run to Cushing, Oklahoma (see figure below). The initial 20-inch bottleneck was mitigated in 2021 by building a second line from Guernsey down into Northern Colorado. This bypass was made possible by leveraging leftover 24-inch pipe from the shelved Liberty Pipeline project. Following the project’s cancellation, thousands of unused 24-inch pipeline joints were left sitting in staging yards across Eastern Colorado, where vast stockpiles remain clearly visible alongside rail lines on satellite imagery to this day.

Today, the primary constraint on Pony has shifted downstream to the 22-inch segment running between Sterling, Colorado, and Natoma, Kansas. Public records, including minutes from a May 2026 Dundy County Commissioners meeting in Nebraska, reveal that Tallgrass planned to replace sections of the line with a new 24-inch pipeline in 2027. Paired with an Enbridge presentation detailing a planned 55,000-bpd expansion ("Pony Express Pipeline 2") for 2027, this suggests a possible strategy to utilize remaining Liberty pipe stockpiles to twin the critical Sterling-to-Natoma segment, debottlenecking mainline capacity.

Beyond the core Pony Express trunkline, Enbridge could benefit from integration with its broader midstream ecosystem. Assets like Enbridge’s Express Pipeline present potential future strategic optionality: while full at the Canadian U.S. border, Express offloads significant crude volumes to Montana refineries, leaving substantial latent capacity along the stretch between Billings and Casper. Future projects could utilize this latent capacity in order to move additional crude from Canada into U.S. markets.

Nile Midstream is a subsidiary of Blackbeard Operating, an exploration and production company focused on crude oil in the Central Basin Platform. That geologic area sits between the Delaware and Midland basins in the Permian (see figure below). Unlike those two growth engines, the platform has seen relatively little of the Permian’s decade-long production surge, with Blackbeard as the main exception after several years of focused horizontal development.

Crane County crude oil production shows Blackbeard as the major source of Central Basin Platform growth. Countywide output rose from about 20,000 barrels per day in 2021 to more than 50,000 barrels per day in 2026 (see graph below), and Blackbeard accounts for roughly 75 percent of total county volumes.

The Delta Express pipeline purchase expands Energy Transfer’s gathering presence on the Central Basin Platform and is likely intended to pull more barrels toward Midland rather than local Crane-area connections (Cactus I/II/III and Gray Oak) that typically feed Corpus Christi (see figure below). If a portion of Blackbeard’s volumes are redirected onto Permian Express or West Texas Gulf, barrels would shift away from Corpus Christi and toward Nederland and Houston.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 400 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

Trans Mountain last week filed an application with the Canada Energy Regulator for its Mainline Optimization Project, a proposal to raise throughput on the existing system by about 210,000 barrels per day. The work would add 11 new pump stations plus roughly 30 kilometres of new 36-inch pipe. The company has targeted a Q4 2028 in-service date. The filing put the estimated cost at $3.97 billion CAD. If tariffs stay in line with current Trans Mountain rates, the project shows a build multiple of about 5–7x EBITDA, pointing to relatively strong project economics.

The optimization sits on top of Trans Mountain’s Drag Reducing Agent (DRA) project, which has already reached a final investment decision. DRA is expected to add about 90,000 bpd and come online in late 2026. Together the two projects would lift system capacity by 300,000 bpd by the end of 2028, taking nominal throughput from roughly 890,000 bpd to as much as 1.19 million bpd. The Trans Mountain mainline moved ~840,000 bpd of crude and refined products in 2Q 2026 (see below).

The crude-flow platform used above is available as a separate product. For pricing, a walkthrough, or a free trial, email matthew.lewis@plainview-energy.com

Market interest in the additional capacity also looks robust. Trans Mountain recently disclosed to the CER that binding commitments for the 90,000 bpd DRA project approached 400,000 bpd, well above the capacity being added (see text below). That oversubscription is a useful signal that the larger 210,000 bpd Mainline Optimization project should also attract enough firm shipper support to be fully subscribed once a binding open season is held.

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Separately, Trans Mountain disclosed to the CER a new expansion project on the Puget Sound Pipeline, the U.S. offshoot that supplies Washington state refineries (see orange lines in below figure). The Sumas Terminal Efficiency Project involves limited upgrades at terminals and pump stations. The CER filing did not state a specific capacity increase, but earlier company disclosures indicated Puget Sound could rise from about 240,000 bpd to as much as 300,000 bpd. Extra light-oil deliveries into the U.S. would give Trans Mountain more flexibility between Washington refiners and export loadings at the Westridge Marine Terminal. Combined with the Second Narrows dredging project at the Port of Vancouver, slated for completion in 2027, the terminal work is intended to ensure the system can actually deliver the additional mainline volumes once they come online.

The crude-flow platform used above is available as a separate product. For pricing, a walkthrough, or a free trial, email matthew.lewis@plainview-energy.com

Sacagawea is a bidirectional Bakken crude system running from the Watford City area of McKenzie County, across the Missouri River / Lake Sakakawea and the Fort Berthold Reservation, and north toward Stanley (see figure below). It connects Bakken barrels to Dakota Access Pipeline at Johnson’s Corner, Enbridge’s North Dakota Pipeline near Stanley, and Palermo rail terminal. Recent data show Palermo railing Bakken crude west to Phillips 66’s Ferndale refinery, BP’s Cherry Point refinery, and Marathon Petroleum’s Anacortes refinery. In June, shipments from Palermo to those three destinations averaged ~46,000 bpd, or about 30% of typical Bakken rail shipments.

The tariff change looks like a competitive move: keep the Palermo rail route viable for Bakken barrels headed to Washington refineries and compete with other Bakken rail terminals for those same barrels. Diesel prices have risen in recent months, and those increases typically immediately flow through into crude-by-rail rates, weakening rail economics.

Bakken crude coming into Washington by rail competes with Canadian light oil flowing down Trans Mountain’s Puget Sound pipeline, which usually runs full (see below), and with light oil marine imports, typically from South America. Both of those alternatives have less direct exposure to diesel prices than crude-by-rail. Lower gathering and pipeline rates on systems such as Sacagawea can offset some of that rail-cost pressure, help Palermo hold its place against other Bakken loading terminals, and keep the Bakken-to-Washington rail path in the money.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 400 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

The Orla and Wink North systems together have recently moved roughly 90,000 barrels per day. Orla (western system) has handled around 30,000 barrels per day while Wink North (eastern system) has ramped to approximately 60,000 (see graphs below). Both the 12-inch Orla system and the 16-inch Wink North system have ample spare capacity. Key producers feeding the systems include Permian Resources, Devon, Civitas, and others on both sides of the state line.

The Delaware Crossing JV (purple line) has recently been transporting 55,000 to 60,000 barrels per day northward into the Wink area (see graph below). Its 16-inch trunkline also has ample spare capacity. Chevron, the 50 percent JV partner, is a major counterparty and operates a large gathering system (black lines) that feeds the line.

Financial data from Salt Creek’s FERC filings show the wholly owned gathering systems generated about $20 million in EBITDA in 2025. Recent financials for the Delaware Crossing JV are not available, although a 50 percent interest contributed $3 to $4 million in net income to Noble Midstream in 2020. Volumes on Delaware Crossing have increased materially since then, so the JV likely generates higher earnings today. Even so, back-of-the-envelope math still makes it hard to get below a double-digit EBITDA multiple for the acquisition. Enbridge undoubtedly plans to improve the economics by attracting additional system volumes and capturing other synergies.

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Enbridge has framed the purchase as completing a wellhead-to-water value chain. The company already holds a majority interest in Gray Oak Pipeline (pink line), a 30 percent stake in Cactus II (orange line), and full ownership of the large Enbridge Ingleside Energy Center export terminal (blue dot). Gray Oak and Cactus II are essentially full today, so the acquisition is unlikely to be driven by an immediate need to fill those lines. Ingleside, however, shows significant available export capacity (see graph below) when comparing flows to the facility’s nameplate export figures. Directing more barrels from the newly acquired gathering systems onto Enbridge-controlled routes could marginally help utilize that open terminal space.

The strategic logic of the acquisition may also be a longer-term play. Permian production continues to climb while pipeline capacity to the Gulf Coast is tightening. Plainview’s Permian Basin supply-and-demand balance shows only about 250,000 barrels per day of current open pipeline capacity to the Gulf Coast as of May 2026 (see graph below). While Plains’ Cactus III pipeline can expand by an additional roughly 200,000 barrels per day, Permian volumes could fill all Gulf egress capacity within the next couple of years if oil prices stay elevated. Owning wellhead connections will strengthen Enbridge’s position if it pursues building a new long-haul egress project, ultimately feeding additional volumes into already available export capacity at Ingleside and capturing more of the value chain from the well to the water. The acquisition therefore may be less like a short-term volume play and more like positioning for the next phase of potential Permian takeaway constraints.

The recent rebound follows a period of sharp swings driven by the Iran conflict, which has created major volatility in both prices and global crude flows over the past six months. U.S. exports peaked in April and May 2026 near 5.3 million barrels per day before falling sharply in June and July (see graph below). That decline coincided with a brief reopening of the Strait of Hormuz that allowed pent-up Middle Eastern supply to reach markets and reduced immediate demand for U.S. barrels.

Data from these individual terminals reflected the drop: Gibson’s volumes eased from around 800,000 barrels per day in the spring peak to under 600,000 in July; ONEOK’s Seabrook facility near Houston fell from just over 500,000 barrels per day to about 300,000; and Enterprise’s Houston Ship Channel terminal declined from roughly 1 million barrels per day to around 600,000 (see below).

The latest uptick in export volumes arrives as Strategic Petroleum Reserve releases conclude at the end of August, with no additional barrels scheduled unless the Department of Energy issues a new request for proposal. Earlier export strength largely reflected the evacuation of commercial and SPR storage rather than higher production from U.S. basins. With inventories now more constrained, any sustained global need for U.S. crude to offset lost Middle Eastern supply could place greater pressure on remaining storage and influence price dynamics in the weeks and months ahead.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 400 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

Canyon Crossing Pipeline (owned by Navigator Energy Services) last week submitted a tariff filing detailing significant rate increases for crude transportation service from Oklahoma into Perryton, Texas. Agreed upon by all active shippers, the new rate structure includes substantial baseline adjustments: standard base rates are rising between 18% and 60% (depending on route), while incentive rates see an even steeper increase ranging from 28% to 84%.

Moving roughly 40,000 barrels per day over the past year (see graph below), this northern leg of Canyon’s network feeds directly into Valero’s interconnecting infrastructure which moves those barrels farther into the Texas Panhandle to supply its McKee refinery. Based on current throughput levels, back-of-the-envelope calculations suggest the filing could generate $5-$10 million in additional annual revenue, assuming volumes remain constant.

Canyon Crossing also operates a separate southern leg that transports approximately 60,000 barrels per day (see graph below) from Oklahoma to the Borger Refinery under a 10-year minimum volume commitment, likely held by Phillips 66.

Using Plainview’s “Related Assets” feature for the McKee refinery on our interactive oil platform (see below figure) shows how Canyon Crossing and other pipelines give McKee exceptional crude-slate flexibility. In addition to Oklahoma and Cushing barrels delivered via Canyon Crossing (dark blue line below), McKee receives Permian Basin crude from West Texas through the Centurion (red line) and Sunrise II (orange line) pipelines, which deliver into Sunoco LP’s McKee (formerly NuStar) system (pink line). These Permian barrels supply a little more than 100,000 barrels per day into McKee (see graph below). By balancing these dual supply arteries, Valero can dynamically optimize its refinery feedstock, blending Cushing grades with Permian crude in response to shifting midstream economics and market differentials.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 400 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

While Enbridge’s precise motivation for creating the Wrangler Pipeline remains somewhat unclear, the move appears designed to optimize flow and offer more flexible shipping solutions. Structurally, this setup effectively divides the capacity of both the Platte and Spearhead systems into western and eastern sections (see figure below), with the western portions of the pipelines largely serving Wrangler and the eastern portions largely tied to the future Southern Illinois Connector leases which we deep dived last week.

In terms of market competition, Wrangler offers an alternative for moving barrels from Wyoming to Cushing, placing it in potential competition with systems like Pony Express and Saddlehorn. However, Wrangler’s initial tariff rates (uncommitted) to Cushing, posted at roughly $6 per barrel, are not currently competitive with the committed rates offered by those rivals. Enbridge could introduce committed tariff rates in the future to capture more volume, though historically the company has favored using Platte’s mainline capacity to move barrels to the Wood River area at higher rates rather than aggressively competing on price into the Cushing market via a Platte + Spearhead discounted joint tariff.

The launch of this service also carries interesting historical echoes. The “Wrangler Pipeline” name was originally used in 2011 for a proposed joint venture between Enbridge and Enterprise to construct a new pipeline from Cushing to the Houston Gulf Coast area. That original project was ultimately shelved and converted into the Seaway 2 expansion after Enbridge acquired a 50% interest in Seaway from ConocoPhillips. The revival of the Wrangler name is notable, if speculative, given recent industry rumors regarding potential plans for a new pipeline route connecting Cushing to Corpus Christi, Texas, a hub where Enbridge operates the largest crude oil export facility in the United States.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 400 assets with crude oil throughput or transactional data on our platform and continues to add more each week. Data for existing assets under coverage are posted as soon as they become available. Below are the assets that were updated this week or newly added to coverage.

To handle the 180,000 barrels per day (bpd) of incremental crude coming in under Mainline Optimization 1 (MLO1), Enbridge appears to be relying heavily on the Southern Illinois Connector project as a primary downstream solution. A 50-50 joint venture with Energy Transfer, this project has secured 100,000 bpd in commitments to route heavy barrels directly to the U.S. Gulf Coast. The initiative relies almost entirely on leased capacity across existing infrastructure, specifically Enbridge’s Spearhead Pipeline and the Platte system, paired with a short new-build connector between Wood River and Patoka, Illinois. From Patoka, barrels transfer to an additional lease on the Energy Transfer Crude Oil Pipeline (ETCOP) bound for Gulf Coast refineries in Nederland, Texas (dashed red line below), while the remaining ~80,000 bpd of MLO1 heavy crude will presumably head toward Cushing, Oklahoma, via an expanded Flanagan South Pipeline.

Looking ahead to Mainline Optimization 2 (MLO2), Enbridge has shifted focus by delaying the upstream component and prioritizing downstream infrastructure. Designed to unlock up to 250,000 bpd of additional Canadian crude egress, MLO2 involves complex flow rerouting. As we have outlined in previous videos, light crude will be redirected southward through pipeline reversals connecting to the Dakota Access Pipeline (DAPL) and the Chicap line. Downstream options for MLO2’s 250,000 bpd of incremental heavy crude appear to center on further expanding the Flanagan South system to the U.S. Gulf Coast and expanding the Southern Access Extension pipeline (see figure below). Expanding the Southern Access Extension creates an additional pathway into ETCOP or third-party assets such as the Capline system.