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 2027. 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.

Despite its immense physical footprint, Capline faces formidable strategic challenges, primarily stemming from its lack of direct connections to growing production basins. The massive growth in Canadian and U.S. production over the last 15 years has largely bypassed Capline, with expanding Canadian, Rockies, and Permian volumes being routed through corridors outside Capline’s reach (see figure below). Furthermore, near-term Canadian growth may also slip away from the pipeline. Enbridge appears positioned to utilize its ETCOP joint venture pipeline for its incremental volumes, while the proposed South Bow and Bridger project aims to transport Western Canadian crude through the Rockies directly to Cushing, Oklahoma, entirely bypassing the Midwest and Capline’s intake point.

Nevertheless, these commercial barriers may not be insurmountable. Executives at majority-owner Plains All American have repeatedly emphasized on earnings calls that Capline remains a primary long-term focus, noting that its vast unutilized capacity is well-positioned to solve regional egress issues for heavy Canadian crude seeking Gulf Coast refiners and global export markets.

To capture this demand, several indirect catalysts could unlock Capline’s potential. Increased crude volumes flowing into Cushing from projects like South Bow and Bridger could displace legacy barrels on TC Energy’s Keystone system, nudging those flows eastward along Keystone’s Illinois leg into Patoka and onto Capline. Furthermore, Plains holds a stake in the Diamond Pipeline connecting Cushing to Memphis, Tennessee. While a connection from Diamond into Capline was shelved during the COVID-19 pandemic, reviving this link, alongside securing long-term contracts across complementary assets like Plains’ Mississippi/Alabama system, remains a viable strategic option if Cushing requires additional egress (see below).

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 Cherokee is a liquids-rich unconventional oil play in Western Oklahoma, broadly known as part of the Granite Wash. After reaching its initial peak during the onset of the shale boom around 2013, production across the area gradually slowed as operators shifted capital toward more economically favorable plays across the U.S. However, recent drilling results have catalyzed a major resurgence in the Cherokee region, turning a quiet legacy play back into one of the country’s most dynamic production hubs.

This unexpected boom is heavily concentrated in Western Oklahoma, specifically within Roger Mills and Custer counties (see figure below).

Between January 2024 and April 2026, the horizontal oil rig count in these two counties surged from 2 rigs to 17. Driven by this focused operator activity, crude oil output has tripled since early 2025, climbing from 15,000 barrels per day (bpd) to over 45,000 bpd (see figure below). Experiencing this degree of sustained growth in such a short window is exceedingly rare in today’s mature onshore environment.

With this rapid volume growth, the region may present compelling infrastructure opportunities. Because the 2013 development phase was centered in different counties across the Granite Wash, Roger Mills and Custer counties remain relatively devoid of large-scale crude oil gathering systems. Operators in the area still likely rely on small-diameter pipeline networks or heavy truck hauling to transport crude to nearby terminals, creating a significant operational challenge.

Despite the localized gap in gathering infrastructure, several key midstream systems exist near the activity center (boxed in gray in figure below) and stand to benefit from the continued surge in crude output:

• Plains All American Midcon System (green lines in figure below): One of its lines runs through the heart of Roger Mills County, this pipeline offers an ideal midstream route to collect local production and potentially deliver volumes to Cushing or connect with third-party lines at the Cashion terminal near Oklahoma City.

• Energy Transfer Granite Wash Extension (yellow line in Western Oklahoma): Completed in 2013, this line moves volumes south toward Ringgold, Texas, where crude can connect to the Permian Express system for transport to Gulf Coast refining hubs in Nederland.

• Phillips 66 Line O (red line): A 10-inch pipeline that previously moved crude from Cushing to the Borger Refinery in the Texas Panhandle. With deliveries to Borger transitioned to the third-party Canyon Crossing pipeline, the now unused Line O may present as a prime candidate for asset re-evaluation or pipeline reversal.

For energy market participants, tracking rapid, under-the-radar growth in regions like Western Oklahoma is vital. As production outpaces localized gathering capacity, significant financial and strategic upside exists for upstream producers, midstream operators, and downstream marketers capable of capitalizing on early-stage infrastructure bottlenecks before the market fully catches up.

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 Port of Corpus Christi, the largest crude oil export hub in the U.S. and home to almost a million barrels per day of refining capacity, noted in an interview last week that companies are exploring a new pipeline to connect Corpus Christi with Cushing, Oklahoma. The port currently lacks a direct or even indirect pipeline connection to Cushing, relying almost exclusively on production from the Permian and Eagle Ford basins. A dedicated pipeline from Cushing would significantly diversify the area’s supply slate, granting access to Canadian, Bakken, and other Midcontinent crude grades. This initiative somewhat echoes the ill-fated Red Oak pipeline (see image below), a joint venture between Phillips 66 and Plains All American, which was canceled in 2021 due to COVID-19.

Incremental Supply Headed Toward Cushing

The likely primary driver for this renewed interest is a perceived supply-demand mismatch at Cushing over the coming years. Various midstream projects, most notably Enbridge’s Mainline Optimization phases and the new pipeline planned by South Bow and Bridger, could introduce up to 900,000 barrels per day (bpd) of new Canadian supply capacity into Cushing by late 2028. When measured against the current available egress capacity from Cushing to the Gulf Coast, estimated at roughly 400,000 bpd (based on 2025 average throughputs), a significant capacity constraint appears possible, theoretically justifying the construction of a new greenfield pipeline to move these barrels south (see figures and tables below).

Potential Brownfield Pipeline Expansions

However, a closer examination suggests that a brand-new pipeline may be unnecessary. The industry possesses several brownfield alternatives, or expansions on existing infrastructure, that would likely prove more cost-effective than building a new corridor from scratch. We estimate operators could potentially unlock ~1,000,000 bpd of incremental capacity by utilizing the Seaway, Marketlink, Capline, and Diamond pipelines. These projects (outlined and illustrated in detail below), would rely on drag-reducing agents (DRAs) and additional pump stations, and likely offer a more capital-efficient path to market than new construction.

Seaway Expansion: Made up of two 30-inch pipelines, the legacy 30-inch Seaway I pipeline currently operates at only 350,000 bpd, well below the typical capacity for a pipe of this diameter. While the legacy pipeline’s age may impose constraints, we estimate an additional 175,000 bpd of capacity could be realized across the twin-pipeline system.

Marketlink Expansion: Regulatory filings indicate the pipeline has the potential to expand to nearly 1,000,000 bpd, which would add approximately 175,000 bpd to current capacity.

Keystone Displacement to Illinois + Capline Expansion: We estimate up to 400,000 bpd of legacy volumes on the Keystone system could be shifted toward Illinois to utilize expanded southbound capacity on the Capline pipeline.

Diamond/Capline Expansion: An expansion of the Diamond pipeline with a direct connection into Capline could add another 250,000 bpd of capacity to the Gulf Coast.

Despite typically being more cost-effective, there may be hurdles for some of these brownfield expansions. Contractual obligations, such as “most favored nations” clauses on pipelines like Diamond and Capline, may limit the ability of operators to offer the competitive tariffs required to attract shippers. Ultimately, while Port of Corpus Christi views a direct Cushing connection as a strategic proactive measure, we believe a new greenfield pipeline has longer odds compared to incremental system expansions on existing infrastructure.

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.

Recent joint venture announcements from South Bow and Bridger Pipeline have answered a major midstream question: how Canadian crude oil from the newly proposed Prairie Connector and Bridger Expansion will find its way from Wyoming to Cushing, Oklahoma. By acquiring rights-of-way from the canceled Liberty Pipeline project, the partners plan to modify existing permits to build a larger 36-inch crude oil pipeline. This third leg of their broader network effectively solves the bottleneck, ensuring that up to 550,000 barrels per day of Canadian and Bakken crude can flow to Midcontinent with connectivity to Gulf Coast markets (see figure below).

However, this crude oil solution raises a fascinating secondary question regarding the physical remnants of the canceled Liberty project. Prior to its cancellation in 2021, the developers took delivery of a significant amount of 24-inch pipe. While some was used by Pony Express to bypass a local bottleneck from Guernsey, Wyoming, to Northern Colorado, thousands of joints of unused 24-inch pipe have been sitting in storage yards in places like Stratton, Colorado, since 2021 (see satellite and street view photos below). Local residents reported to Plainview that project representatives have discussed possible plans to lay two pipelines in the Liberty right-of-way: the new 36-inch crude line and a secondary project utilizing the idle 24-inch pipe for a completely different commodity.

Because crude oil supply dynamics do not justify two parallel oil pipelines from this area, the second line could carry another commodity like Natural Gas Liquids (NGLs). The timing aligns well with one recent NGL pipeline conversion: in early 2026, Kinder Morgan’s Hiland Express (formerly the Double H oil pipeline) was converted to NGL service, with the ability to flow approximately 100,000 barrels per day south from the Bakken. Currently, throughput on Hiland Express is likely a small fraction of this capacity because NGL egress options out of the Guernsey, Wyoming area are highly limited. Indeed, tariff information indicates Hiland Express currently relies on Phillips 66’s small, 16,000-barrel-per-day Powder River NGL pipeline to reach NGL egress lines in Colorado.

Kinder Morgan continues to hint in investor calls at expanding the scope of Hiland Express to bring even more NGL volumes south. Our analysis indicates they would need a higher-capacity egress solution out of the Wyoming area to achieve any meaningful volume increase. The idle 24-inch Liberty pipe could be deployed to bridge this gap. An NGL pipeline of this scale would allow Kinder Morgan to bypass the Wyoming bottleneck, link directly into expandable networks like Phillips 66’s Southern Hills pipeline in Oklahoma, and efficiently transport Rockies and Bakken NGLs straight to the Gulf Coast. While a joint venture between Kinder Morgan, Phillips 66, and whoever still owns the 24-inch Liberty pipeline remnants remains speculative, utilizing the leftover Liberty pipeline assets is a highly logical, market-moving play that could soon reshape NGL dynamics in Bakken and Rockies markets.

The Canadian government recently unveiled two major state-sponsored crude oil pipeline egress projects. An eastbound proposal, named the Northern Shield Pipeline (blue line in figure below), aims to move 500,000 barrels per day (expandable to 800,000 bpd) of crude from Hardisty, Alberta, to Sarnia, Ontario, to supply eastern refineries domestically. A separate proposal is a massive westbound project that plans to leverage the existing Trans Mountain corridor, carrying approximately 1,000,000 bpd of new crude to the West Coast (pink line). While both projects are designed to secure and diversify Canada's energy transport network, they come with substantial logistical, political, and financial complexities that raise critical questions regarding their commercial viability.

Northern Shield Pipeline

The Northern Shield Pipeline is engineered to directly feed the 300,000 bpd of refining capacity in the Sarnia area (see figure below). The pipeline has the added potential to indirectly serve an additional 500,000 bpd to refineries in Nanticoke, Montreal, and Quebec via third party pipelines and ship traffic up the St. Lawrence River. A potential strategic advantage of Northern Shield is its entirely domestic route. By keeping the pipeline completely within Canadian borders, the government avoids the complex cross-border tariffs and regulatory risks that have recently arisen with energy infrastructure traversing through the United States.

However, outside of its utility as a geopolitical safety net, the commercial viability of Northern Shield is a significant long shot. Assuming it requires entirely new pipeline construction, the project will likely carry an exorbitant price tag just to serve the same Ontario refineries already economically fed by Enbridge pipelines. Furthermore, the project lacks a robust, direct export option to diversify demand beyond these local refineries. While the government has vaguely mentioned possible future northern laterals to Hudson Bay or James Bay (pictured below), analysis indicates these routes would be prohibitively expensive and likely impractical. Without them, Northern Shield will struggle to secure long-term commitments from refiners who can already source crude competitively.

The Trans Mountain Triplet

In contrast, the new westbound Trans Mountain corridor project focuses heavily on global export diversification by routing barrels to the Pacific coast. While it largely follows the existing Trans Mountain right-of-way, it introduces a critical structural improvement: terminating further southwest at Roberts Bank. By extending past the shallow-water bottleneck points that limit the existing Westridge export facility (see below), this new terminal would possess the deep-water capacity to load Very Large Crude Carriers (VLCCs). This gives the project a distinct advantage over the existing Trans Mountain route, unlocking higher-volume maritime access to premium Asian and global markets that were previously restricted to smaller, less economic vessels.

Despite this logistical advantage, the project’s financial outlook is highly precarious, with preliminary costs estimated around $30 billion USD. Even under optimistic assumptions regarding contracting, budget management, and competitive tariff rates, back-of-the-envelope calculations indicate weak economics. Cost-to-EBITDA multiples sit in the mid-teens (see below), metrics that would deter almost any private corporation. Furthermore, securing commercial commitments from shippers will be a steep uphill battle. Given the Canadian government’s track record with severe overruns, shippers will resist signing cost-escalation agreements that could drive up their long-term tariff rates.

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.

U.S. Regional Crude Prices and Spreads Fall as Hormuz Supply Rebounds

Regional U.S. crude oil prices and pricing spreads to Cushing have narrowed significantly over the last few weeks due to a surge in oil supply escaping the Strait of Hormuz. This massive influx of global crude is flooding an international market already well-supplied for July and August, heavily depressing domestic regional prices. Bakken crude has slipped to a notable $2.58 discount to August WTI Cushing, while light oil at Guernsey flipped to a $1.65 discount for the first time in several months. West Texas Intermediate (WTI) Midland has similarly dropped to a 15-cent discount to Cushing. Crucially, the spread between Cushing and Houston has withered to just 5 cents per barrel, rendering spot market shipments completely uneconomic and challenging the financial viability of even contracted pipeline volumes.

This domestic price slump stems strictly from a drop in export demand rather than a slowdown at domestic refineries, which maintain high utilization rates to combat global refined product shortages. Essentially, the unleashing of trapped Middle Eastern supply is pricing American barrels to stay inland. Early July ship-tracking data from Plainview confirms this drop, showing key U.S. hubs averaging just 3.7 million barrels per day (bpd) in exports during the first five days of the month, down from our 5.6 million bpd estimate for the first five days of June (see table below). While exports can be lumpy and could moderate higher over the course of the month, current prices indicate July export numbers will be materially lower than June.

South Bow and Bridger to Revive Liberty Pipeline Route for New Guernsey to Cushing Project

A recent Reuters report indicates that South Bow and Bridger are planning to jointly develop a new oil pipeline from Guernsey, Wyoming, to Cushing, Oklahoma. The story indicates that according to a JP Morgan research report, the joint venture acquired the rights of way for the project from Tallgrass Energy. These rights originally belonged to the Liberty Pipeline, a pre-COVID pipeline project spearheaded by Phillips 66 and Bridger that was ultimately canceled due to the pandemic. This new development successfully answers questions regarding the “third leg” (orange line in figure below) which will be the final leg to connect South Bow’s previously announced Prairie Connector (yellow line) and Bridger expansion (blue lines) projects to Cushing, Oklahoma.

Historical materials from Phillips 66 highlight that this contemplated pathway follows a distinct route separate from Tallgrass Energy’s existing Pony Express pipeline (pink lines in figure above) asset. Local outreach by Plainview further supports the continuity of this route; interviews with two residents living near the Liberty Pipeline right of way in Eastern Colorado and Western Kansas revealed that the existing land corridors in those areas remain significantly unchanged. Consequently, the new South Bow and Bridger joint venture is highly likely to utilize the same landowners and pre-established right of way agreements originally outlined in 2019 and 2020.

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.

Solving the Current Draft Restrictions

Currently, Trans Mountain’s volumes are not restricted by pipeline or terminal capacity. Over the past year, the pipeline has consistently moved around 750,000 barrels per day (bpd), of which about 450,000 bpd exits through the Westridge Marine Terminal. The recent Iran conflict has pulled more volumes to Westridge with June 2026 loadings trending at a record pace of over 550,000 bpd based on Plainview’s ship tracking analysis (see image below). While this remains under Westridge’s current physical limit of 630,000 bpd, the terminal faces a strict regulatory cap of 34 Aframax vessel loadings per month.

Because shallow water depths create strict draft restrictions, these Aframax vessels currently only load around 600,000 barrels of oil, representing roughly 75% of their full 800,000-barrel capacity. Deepening the channel may allow these 34 monthly ships to load to full capacity, effectively expanding the terminal’s throughput without increasing vessel traffic.

Phase 1: Aligning with the 2027 DRA Expansion

The timing of the dredging project aligns well with Trans Mountain’s upcoming Drag Reducing Agent (DRA) expansion. Scheduled to come online in January 2027, the DRA initiative will boost the pipeline’s current nameplate capacity by 10%, adding roughly 90,000 bpd to bring total system capacity to 980,000 bpd.

Currently, Trans Mountain utilizes three delivery points that sum to a combined delivery capacity of 925,000 bpd (see image below):

• Westridge Marine Terminal: 630,000 bpd

• Puget Sound Pipeline (U.S.): 240,000 bpd

• Burnaby Refinery: 55,000 bpd

Because existing delivery options barely exceed the current 890,000 bpd pipeline capacity, Trans Mountain will rely heavily on the newly dredged port to efficiently clear the additional 2027 DRA volumes without causing a bottleneck at the dock.

Phase 2: The Foundation for 1.19 Million bpd

Looking toward the end of the decade, the port upgrade serves as the foundation for an even larger vision. Trans Mountain is contemplating a larger-scale pump station and mainline optimization project that could supercharge pipeline capacity up to 1.19 million bpd by 2028–2029.

To handle that future volume, any material expansion beyond the current configuration will require Westridge to handle a peak export capacity of 895,000 bpd (see image below). Assuming the regulatory cap remains at 34 tankers per month, those ships must be fully loaded at 800,000 barrels each to achieve this target. Combined with steady regional demand from the Puget Sound pipeline (240,000 bpd) and the Burnaby refinery (55,000 bpd), a deeper Burrard Inlet is the final, critical link required to fully maximize the delivery side of the Trans Mountain system.

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 Department of Energy’s (DOE) June 10, 2026, Request for Proposal (RFP), which offered 40 million barrels of crude oil from the Strategic Petroleum Reserve (SPR) sites at Bryan Mound and Big Hill, saw an incredibly weak market response. When the awards were finalized, only 0.5 million barrels of the 40 million offered were actually awarded to market participants. The current exchange program relies on a structure tailored heavily toward crude oil marketers, who borrow near-term barrels and agree to return them at a later date, along with an additional premium, essentially acting as interest paid in additional oil.

The extreme shortfall in awards for the June 10th RFP was not an administrative failure, but rather a direct result of rapid shifts in the global crude forward price curves. When the RFP launched on June 10, near-term August oil contracts traded at $90 per barrel, while mid-2027 contracts sat around $78, creating an attractive $5 per barrel net profit margin for marketers even after factoring in the 9% return premium (see table below).

However, by the time bids were due on June 15, near-term crude prices collapsed to $80 per barrel while back-end prices held firmer (see graph below). This severe flattening of the curve completely erased the financial spread, leaving marketers with no financial incentive to participate in the exchange (see table below).

Bayou Choctaw SPR Infrastructure: Mapping Louisiana’s Deep Crude Connectivity

As the smallest of the primary Strategic Petroleum Reserve facilities, the Bayou Choctaw storage site in Louisiana holds a capacity of 76 million barrels. Situated southwest of Baton Rouge, its geographic layout offers exceptional distribution capabilities across the Gulf Coast and global markets.

The backbone of Bayou Choctaw’s immediate infrastructure is the DOE-owned, 36-inch bi-directional Red Stick Pipeline. Currently under a 20-year lease to Exxon running through 2040, this pipeline serves a dual purpose, moving commercial barrels up to Placid and Exxon’s Baton Rouge area refineries during standard operations and serving as the primary highway to draw down or replenish SPR reserves during releases/buybacks.

When the DOE mandates an SPR drawdown from Bayou Choctaw, crude flows south via the Red Stick Pipeline directly into the massive St. James Storage Hub along the Mississippi River (light green line in figure below). DOE infrastructure at St. James features two dedicated marine docks managed under the Exxon lease, giving the government direct access to load marine vessels or export crude globally via ocean-going tankers. Furthermore, Bayou Choctaw directly connects to the north via Placid’s one-way Bourre’ pipeline which provides access to Baton Rouge refineries (red line). For broader domestic distribution, the St. James hub links directly into major third-party systems like the LOCAP (dark blue line) and LOOP (orange line - Louisiana Offshore Oil Port) pipelines, allowing Bayou Choctaw reserves to directly or indirectly tie into nearly every refinery in Louisiana or load onto Very Large Crude Carriers (VLCCs) at LOOP’s deepwater terminal.

As arguably the most well-plumbed inland storage hub in the world, Cushing is connected to numerous U.S. oil hubs and the Gulf Coast via more than two dozen pipelines. Plainview’s crude oil platform monitors flows and capacities on 28 pipelines in and out of Oklahoma, throughputs in the state’s five refineries, storage balances, and in-state oil production to form our “Oklahoma Balance” which is updated monthly (see figure below). This extensive infrastructure allows the Cushing hub to seamlessly balance its own market dynamics. During periods of oversupply, excess crude is pushed out to Gulf export facilities, while in times of relative undersupply, those same pipelines simply reduce the volume of barrels leaving the hub to stabilize local inventory.

Because of this built-in flexibility, tight inventory is primarily impacting price spreads between major U.S. hubs rather than driving outright WTI crude prices higher. The spread between Cushing and Houston, which peaked above $4.00 in early May as barrels rushed to the Gulf Coast for export, has narrowed drastically to under $0.70 a barrel. At this sub-$0.70 level, it is no longer economically viable to ship uncommitted barrels from Cushing to the Gulf Coast on pipelines like Seaway or Marketlink (see graph below). This narrowing spread indicates that Cushing is already successfully pricing its crude to retain barrels locally, likely bringing an end to the heavy inventory draws seen throughout May and the first half of June. While major geopolitical events can always trigger much higher worldwide prices, a tight Cushing market simply prices itself to trade near historically stronger benchmarks like Houston and Brent to keep its barrels from leaving, rather than massively lifting the entire global complex.

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.