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.

Enterprise Gets Aggressive with Permian Crude Volume Surge

Enterprise Products Partners appears to have rapidly intensified competition for Permian Basin crude by reconverting its Midland-to-Echo 2 (ME2) pipeline back to crude service in early 2026. This move followed the startup of the company’s Bahia NGL pipeline, which allowed ME2 to shift back away from natural gas liquids. Since the conversion, Enterprise appears to have aggressively marketed capacity, causing combined volumes on its Midland-to-E1 and ME2 pipelines to spike dramatically. In March, flows across the joint system approached 815,000 barrels per day (see figure below), pushing the lines remarkably close to their estimated nameplate capacity of 840,000 barrels per day.

Because total Permian Basin production has not grown significantly during the first half of 2026, Enterprise is almost certainly pulling these massive volumes away from rival operators. The impact appears widespread across the region, as data does not yet show an obvious single, severe drop on any individual competitor line, suggesting Enterprise may be capturing market share incrementally from multiple pipelines. Meanwhile, the company’s separate Midland-to-E3 pipeline, which holds an undivided joint interest in the Wink-to-Webster system, continues to run completely full, consistently moving about 450,000 barrels per day as it has since late 2021.

Phillips 66 Sweeny Refinery’s Shifting Crude Oil Supply

The Phillips 66 Sweeny Refinery, which operates at a daily crude oil capacity of approximately 265,000 barrels, has recently experienced a notable shift in its crude oil supply. Historically, the facility has relied on three major pipeline sources: the Sweeny, Gray Oak, and KMCC pipelines. Phillips 66’s wholly owned Sweeny pipeline (the orange line in the figure below) remains the refinery’s primary anchor, consistently delivering about 150,000 barrels per day of combined waterborne imports from the Freeport marine terminal and Canadian crude coming off the Seaway Pipeline. However, the balance of the refinery’s supply is undergoing a reallocation between the other two competing pipelines.

In recent months, volumes from the Gray Oak pipeline (green lines in figure below) dropped significantly from just under 100,000 barrels per day to around 40,000 barrels per day. This missing volume has shifted over to Kinder Morgan’s KMCC pipeline (red lines in figure below), boosting its crude deliveries into Sweeny to over 60,000 barrels per day. This reversal is surprising because Phillips 66 holds a 6.5 percent ownership stake in Gray Oak but owns no part of KMCC. The shift could be driven by highly competitive tariff rates offered by KMCC or a strategic desire for more Eagle Ford barrels, although Gray Oak can also source Eagle Ford barrels. The lower usage on Gray Oak is particularly interesting as it comes at a time when some investors have pressured Phillips 66 regarding the potential sale of some of their midstream pipeline assets.

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 (DOE) has issued what may be its final Request for Proposal (RFP) for crude oil exchanges from the Strategic Petroleum Reserve (SPR) this year, offering an additional 40 million barrels. If fully awarded, this would exhaust the previously announced 172-million-barrel maximum allocation. The withdrawal timeline spans from July through September, with crude drawn directly from two primary Gulf Coast sites: 15 million barrels from Bryan Mound, which is the largest SPR location, and 25 million barrels from Big Hill.

The physical barrels from this new tranche will exit the underground caverns during the summer months, with the replacement barrels scheduled to return primarily throughout 2027, stretching into the first quarter of 2028. This temporary drawdown creates a projected logistical “bottom point” for SPR inventory levels in September (see below graph). Crucially, the return structure requires that the oil be replenished at an 8% to 10% premium, which ultimately ensures a higher total volume of crude returns to the reserve than would have existed under standard, non-exchange congressional sales.

Infrastructure Deep Dive: Big Hill and West Hackberry

Like all the SPR sites, the logistics networks serving the West Hackberry facility in Louisiana and the Big Hill site in Texas utilize DOE-owned pipelines.

For the Big Hill facility, which boasts a total storage capacity of 170 million barrels across its subterranean salt caverns, crude oil distribution funnels primarily northward through a single proprietary bi-directional pipeline. This dedicated line terminates directly into Energy Transfer’s Nederland Terminal (see figure below). From this specific nexus point, the crude oil can be seamlessly directed across marine export docks to global markets or routed via third-party networks to local refineries, including Exxon Beaumont, Total Port Arthur, Motiva, and Valero Port Arthur.

Further east, the West Hackberry site holds a 221 million-barrel capacity, storing a strategic mixture of both sweet and sour crude. West Hackberry is uniquely supported by two independent, bi-directional DOE pipelines that afford it dual-routing flexibility. Barrels can flow directly west to tie into the same Energy Transfer Nederland Terminal or migrate north into the Lake Charles refining hub to supply major refineries operated by CITGO and Phillips 66. Additionally, West Hackberry features a key interconnect with the Zydeco pipeline network, allowing operators to push crude deeper into the broader Louisiana refining matrix.

Global energy markets experienced a dramatic shift this spring as regional crude oil price spreads between U.S. and international markets widened significantly, peaking in early May. Driven by the Iran conflict, the Brent to WTI Cushing spread neared $13 per barrel for front-month delivery, while domestic U.S. spreads also spiked. Patoka crude commanded an $11 premium over WTI Cushing, and Houston pricing surged to a premium of over $4. This massive pricing dislocation incentivized a heavy volume of crude oil to drain from both commercial and SPR stockpiles to the international markets. Consequently, the surge in supply has notably normalized prices and narrowed regional spreads. By early June, the Brent/WTI spread has collapsed to around $5, the Patoka premium was cut in half, and Houston pricing reverted to its historical baseline of about $1 over Cushing.

While this storage-driven export boom provided a highly profitable short-term volume bump for U.S. pipelines and terminals, the upside faces a likely expiration date as storage inventories dwindle. Pipeline flows should slowly normalize back to pre-conflict levels in the short-term. However, we view the midstream outlook optimistically longer-term. The rapid depletion of global storage combined with ongoing geopolitical risk should support higher long-term crude prices. Higher sustained prices will inevitably incentivize increased U.S. production, creating a tailwind for healthy, sustainable growth environment for U.S. infrastructure. As long-term production volumes rise, midstream companies can look forward to growing base flows and the distinct potential for future pipeline capacity expansions once existing networks fill back up.

Gibson Energy’s Gateway Terminal Eyes 1M BPD Export Surge After March Slump

Gibson Energy’s Q1 earnings call highlighted a turbulent start to the year for its flagship Gateway terminal, which faced abrupt export disruptions in March due to shipping bottlenecks and heightened market uncertainty. This operational speedbump was directly reflected in the terminal’s incoming pipeline deliveries, which experienced a sharp contraction, plummeting from a robust average of over 850,000 barrels per day (bpd) in February to just under 600,000 bpd in March (see below). Despite the temporary March drawdown, Gibson Energy projected a rapid recovery for the terminal heading into the latter half of Q2 2026. Management noted on their Q1 earnings call that export volumes are on track to potentially cross the milestone of 1 million bpd, spurred by shifting global logistics and geopolitical tailwinds due to the ongoing Iran conflict.

The Gateway terminal relies on a network of four primary feeder lines: the Eagle Ford-sourced Arrowhead South Texas pipeline managed by Harvest Midstream, and three major Permian baselines, Cactus II, Cactus III, and Gray Oak. The latter two serve as Gibson’s primary volume drivers, with Gray Oak delivering approximately 350,000 bpd and Cactus III contributing around 250,000 bpd based on 2025 baselines (see Gray Oak deliveries to Gibson in 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 Strategic Petroleum Reserve (SPR) relies on a complex network of underground salt caverns rather than traditional above-ground storage tanks to secure America’s emergency oil supply. Located southwest of Houston in the Freeport, Texas area, the Bryan Mound facility stands as the largest site within this system, boasting a storage capacity of 247 million barrels. Utilizing 19 active underground caverns, Bryan Mound can draw down up to 1.5 million barrels per day (bpd) during emergency releases, though refilling the caverns is a notably slower process, capped at a daily rate of 225,000 barrels.

At the heart of Bryan Mound’s distribution network are pipelines owned directly by the U.S. Department of Energy (DOE). In a unique public-private arrangement, Exxon holds a long-term lease on these pipelines extending through 2030, integrating them into its onshore Hoover pipeline system (HOOPS) to transport offshore oil to Texas City and Jones Creek. However, this lease includes a critical caveat: during an official SPR drawdown, the DOE receives absolute priority service, reclaiming use of the infrastructure to distribute emergency crude to the market.

When oil is released from Bryan Mound, it primarily moves through three major midstream corridors:

• The Seaway Freeport Dock (yellow arrow below): A 50-50 joint venture between Enbridge and Enterprise, this terminal facilitates direct exports to international markets or domestic U.S. ports via tankers.

• Texas City (white arrow below): A 40-inch pipeline carries barrels north directly to major refining hubs, including Marathon’s Galveston Bay refinery and Valero’s Texas City refinery, as well as additional Seaway’s Texas City export docks and Genesis Energy terminals.

• Jones Creek Storage Facility (red arrow below): This route connects to tanks owned by Phillips 66 and Seaway at Jones Creek. After being offline due to damage from Hurricane Harvey in 2017, this critical line was refurbished by Exxon and returned to service. This connection allows crude to access Phillips 66’s Sweeney refinery via a connecting pipeline or flow north toward Enterprise’s Echo Terminal via Seaway to reach the broader Houston refining complex.

In what will be an ongoing theme in this deep dive series, the shifting dynamics of North American energy production have fundamentally altered how the SPR interacts with the broader grid. Before the domestic shale boom and the surge in Canadian crude imports, Bryan Mound had direct access to Midcontinent refineries via pipelines like Seaway, which originally flowed north (see below). Today, those infrastructure pathways have been reversed to bring a continuous surplus of oil south to the Gulf. While this reversal technically limits the SPR’s flexibility to physically pump oil north, the modern energy market handles disruptions through displacement, releasing SPR barrels along the Gulf to satisfy local demand, which in turn allows northern supplies from Canada and PADD 4 to remain in the Midwest in the time of supply disruptions.

Ultimately, whenever the federal government mandates an SPR release, such as the historic drawdowns under the Biden administration or structural exchange programs, midstream operators stand to see significant volume upside. In the case of withdrawals or refills at Bryan Mound, companies like Enterprise and Enbridge via the Seaway network, along with Exxon collecting midstream fees, are positioned to benefit.

South Bow Corporation announced a major milestone for its proposed Prairie Connector project on Friday as the company successfully closed its open season after securing binding, 20-year transportation commitments from shippers. Despite the commercial momentum, South Bow outlined a surprisingly long timeline targeting a Final Investment Decision (FID) by mid-2027. South Bow CEO Bevin Wirzba emphasized at a conference earlier last week that the company will not deploy capital until it secures “complete durability” of its U.S. cross-border permit.

The original Keystone XL project collapsed when President Joe Biden unilaterally revoked the presidential permit previously granted by President Donald Trump. Because international oil pipelines currently operate under the implied Article II constitutional powers of the executive branch rather than explicit statutory laws, their permits exist entirely at the political whim of whoever occupies the White House.

To establish a truly durable route forward, the pipeline’s regulatory framework may need to shift out of this constitutional “gray zone” and into explicit statutory law. Under Article I of the Constitution, Congress holds the absolute right to regulate foreign commerce, which federal courts historically rule overrides vague executive foreign affairs claims. If Congress exercises this authority by passing a legislative statute for oil pipelines, the power to grant and revoke cross-border permits could permanently transfer to a legislative framework, protecting multi-billion-dollar energy corridors from being canceled by the stroke of a future president’s pen.

Bakken and U.S. Oil Rig Count Climbs as Producers Respond to Higher Prices

North Dakota’s active drilling rig count increased by five over the past week, reaching 30 rigs statewide. This marks a notable rebound, up eight rigs from the three-year low of 22 recorded just two weeks ago. According to the North Dakota Department of Mineral Resources, the latest gains were led by Devon Energy, which added two rigs, while Burlington Resources, Phoenix Operating, and Hunt Oil each added one. The prior week also saw additions from Formentera, Silver Hill, and SOGC, signaling renewed momentum in the state’s oil patch following a period of subdued activity.

The Bakken uptick comes shortly after Q1 earnings reports from exploration and production (E&P) and midstream companies, which highlighted limited new drilling across the U.S. despite a sharp rise in oil prices triggered by the Iran conflict. While producers continue to emphasize capital discipline, supported by extreme backwardation in the futures curve, U.S. onshore oil rigs have notably increased in recent weeks (see graph below). Although E&Ps are more financially disciplined than in previous cycles, the incentive to maximize production from existing acreage during periods of elevated prices remains strong, potentially driving continued activity if the forward curve stays above $70/bbl.

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.

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The U.S. Strategic Petroleum Reserve (SPR) consists of over 700 million barrels of crude oil storage capacity in four major underground storage facilities along the Gulf Coast, providing critical emergency crude oil supplies. The largest is Bryan Mound near Freeport, Texas, with 247 million barrels capacity and a maximum drawdown rate of about 1.5 million barrels per day. West Hackberry in Louisiana holds 221 million barrels, Big Hill offers 170 million, and the smaller Bayou Choctaw near Baton Rouge has 76 million barrels capacity. These sites primarily store a mix of sweet and sour crude in massive underground salt dome caverns located 2,000 to 4,000 feet below the surface, rather than conventional above-ground tanks.

Historically, the SPR reached near-full capacity of approximately 700 million barrels about a decade ago. Levels have declined steadily due to congressionally mandated sales attached to various budget and infrastructure bills across multiple administrations (see table below).

These sales effectively turned the SPR into a budgetary tool to help offset spending or tax measures. A significant acceleration occurred in 2021-2022 during the Biden administration, when emergency sales in response to the Russia-Ukraine war reduced inventories sharply from over 600 million to below 400 million barrels. Some of these sales were pulled forward from previously scheduled mandates (black line on graph below), and the administration later conducted some buybacks at lower prices, generating a profit for the U.S. Treasury.

In response to the Iran conflict in 2026, the Trump administration launched an oil exchange program rather than outright sales. Through multiple Requests for Proposals (RFPs), the Department of Energy is releasing over 170 million barrels for delivery primarily during the summer driving season (April-August 2026). In return, market participants must repay the oil from late 2026-2029 with a 18-24% premium in kind. This structure leverages market backwardation to increase SPR inventories beyond the congressionally mandated baseline levels (black line vs. yellow bars in graph below).

The current drawdown is helping mitigate oil price spikes amid global supply concerns, but it will leave the reserve at relatively low levels by late 2026. Refills starting in November of that year could provide supportive buying pressure in the physical market as participants purchase oil to meet their repayment obligations. While the exchange approach offers a mechanism to rebuild stocks higher than pure congressionally mandated drawdowns would allow, sustained low SPR levels still carry energy security risks if new disruptions emerge before full replenishment. Market participants should closely monitor the cadence of both the sales and subsequent returns under the exchange program, as it could have significant impacts on commodity and equity prices as well as U.S. and foreign geopolitical strategy.

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Capline Pipeline Southbound Flows Near Capacity in April Amid Global Oil Supply Shortages

New reported data from the state of Louisiana provides the first look at southbound pipeline flows since the Iran conflict began in March. Capline Pipeline flows from Patoka, Illinois, into Louisiana exceeded 300,000 barrels per day (bpd) in April, operating near the pipeline’s estimated capacity for a typical light-heavy crude mix (see figure below). The line’s rated capacity ranges from 250,000 to 417,000 bpd depending on the crude slate. Recent wide price spreads between Midcontinent and Gulf Coast markets indicate that major southbound pipelines are running full, as global buyers pull U.S. crude to export terminals to offset international supply shortages.

This strong April data point is encouraging for other key southbound pipelines, including ETCOP JV system moving barrels from Patoka to Nederland, Texas, as well as Seaway and Marketlink lines from Cushing to the Texas coast. The elevated Gulf Coast deliveries have been supported primarily by commercial storage withdrawals and releases from the Strategic Petroleum Reserve (SPR) rather than new production growth. As noted in prior analysis, these high flow levels are likely temporary and will be difficult to sustain long-term without significant production increases across major U.S. basins.

Plains Ramps Up Cactus III Pipeline Throughput as Throughput Again Nears Capacity

Since acquiring control of the Cactus III pipeline (formerly the EPIC) in November 2025, Plains has significantly increased the system throughputs. Permian egress volumes on the system have risen from approximately 500,000 barrels per day in late 2025 to nearly 600,000 barrels per day in March 2026, approaching the pipeline’s full capacity of 625,000 bpd (see figure below). Plains has also doubled flows on its Northern Eagle Ford line serving the Hobson area, growing from 20,000 bpd to nearly 40,000 bpd over the same period. This growth is likely partly supported by marketing volumes moving through the recently acquired Ironwood Karnes System, which delivers barrels into Cactus III at the Hobson interconnect.

The recent incremental volume growth has been directed to Corpus Christi rather than Ingleside, as Plains utilizes its wholly owned EPIC Grain Export Terminal in the Inner Harbor, an economically attractive option compared to paying third-party fees at Ingleside (see figure below). With the Iran conflict ongoing and oil prices remaining elevated, Permian production is likely to rise further toward year-end. Cactus III is well positioned to capture additional upside through low-capital-cost expansion projects, including pump station additions and system optimizations that offer strong economics for incremental barrel growth.

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.

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Record U.S. Condensate Exports Surge to Canada in Early 2026

Statistics Canada has reported record imports of U.S. condensate with volumes exceeding 340,000 barrels per day (bpd) in January and surpassing 350,000 bpd in February, the highest monthly levels ever recorded. Supporting pipeline specific figures from the Canada Energy Regulator (CER) show Pembina’s Cochin pipeline achieving record Q1 volumes above 115,000 bpd. The Cochin and StatsCan numbers also imply that Enbridge’s Southern Lights pipeline also hit new highs, eclipsing 230,000 bpd in the first two months of the year, well above the pipeline’s 198,000 bpd nameplate capacity following its recent expansion (see figure below).

The sharp increase in condensate imports reflects growing Canadian heavy oil and bitumen production, which relies on diluent blending to meet pipeline specifications for export to the U.S. and other markets. Seasonal factors likely amplified demand as lower imports in Q3 2025 (particularly on Cochin) appear to have drawn down storage inventories heading into winter, when colder temperatures require higher condensate ratios to maintain flowability.

U.S. Crude Exports Remain Elevated - Several Houston Terminals Slated for Upside

U.S. crude exports continue to run well above normal levels as global demand pulls barrels amid the Iran conflict and the resulting disruption of supply through the Strait of Hormuz. Two major Houston-area facilities are playing a key role in meeting this demand. Enterprise Products’ EHT Terminal in the Houston Ship Channel, one of the largest U.S. crude export facilities, has significant storage and dock capacity and previously achieved nearly 1 million barrels per day of exports in a single month (see figure below). In its Q1 earnings call, the company highlighted rising exports driven by the conflict and expects additional upside in Q2.

Nearby, Seabrook Logistics, co-owned by LBC Terminals and ONEOK, has recently recorded rates ~400,000 barrels per day (see figure below) and is also benefiting from the tightened global supply picture. The current export strength is viewed by Plainview as a short-term event as much of the incremental volume is being pulled from commercial storage and Strategic Petroleum Reserve (SPR) inventories rather than new production. As a result, the upside from these elevated exports is expected to moderate in the second half of 2026 once SPR drawdowns conclude toward the end of the year, unless domestic U.S. crude production increases significantly to sustain the higher export pace.

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.

Reuters reported last week that shippers have committed to move at least 400,000 barrels per day (of the initial 550,000 bpd capacity) on South Bow and Bridger’s major new pipeline project from Alberta to Guernsey, Wyoming. Committed shippers include Cenovus Energy, Canadian Natural Resources, and others according to the report. Bridger has targeted approximately 450,000 bpd of committed volumes to proceed with the project, and current interest suggests the expansion is on track to advance. Bridger’s newly created expansion page indicates permitting and regulatory reviews are expected to run through 2027, with construction planned from fall 2027 and an in-service target of late 2028 or early 2029 (see figure below).

While commitments for the Alberta-to-Guernsey segment are solidifying, significant uncertainty remains around what will happen to these barrels once delivered to Wyoming. As we noted in our co-authored PADD 4 crude study with RBN Energy, PADD 4 already faces relatively tight takeaway capacity (see PADD 4 to Cushing graph below), and 450,000+ bpd of incremental heavy oil supply will almost certainly require the addition of a new egress pipeline. A February 2026 joint open season between Tallgrass and Bridger points to potential use of the Pony Express Pipeline corridor, possibly through a new twin line or rights-of-way acquired from the cancelled Phillips 66 Liberty Pipeline (which were purchased by Bridger/Tallgrass). Both of these routes would deliver volumes to Cushing, Oklahoma, with further access to the Gulf Coast via South Bow’s Marketlink system.

Energy Transfer to Expand Bayou Bridge Pipeline to 600,000 BPD, Backed by Increased Commitment

Energy Transfer announced last week that it has approved an expansion of its Bayou Bridge Pipeline joint venture, boosting capacity to approximately 600,000 barrels per day (vs. ~480,000 bpd previously). The new project is supported by a 10-year contract extension and increased volume commitment from a key demand-pull customer, with the expanded capacity expected to come online in the first quarter of 2027. Phillips 66, which owns 40% of the pipeline and serves as a major shipper alongside CITGO, is viewed by Plainview as the anchor customer driving the expansion. The timing aligns with the expiration of the original 10-year anchor contract, replacing a 130,000 bpd commitment with a new 175,000 bpd contract at slightly lower rates.

The Bayou Bridge Pipeline currently supplies about 150,000 bpd to Phillips 66’s Lake Charles refinery, accounting for the majority of the refinery’s 225,000 bpd throughput in 2025, with the balance coming from Shell’s Zydeco Pipeline and waterborne sources. The higher new commitment could displace some volumes from those secondary sources or support increased refinery utilization, given Lake Charles’s nameplate capacity of around 260,000 bpd. The expansion will also loosen an upstream bottleneck on Bayou Bridge, allowing it to deliver additional volumes past Lake Charles to St. James, a segment of the pipeline that has been significantly underutilized (see graph below) since it was completed in 2019.

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 U.S. Energy Information Administration (EIA) reported a staggering 6.4 million barrels of crude oil exports for the week ending April 24, marking the highest weekly figure ever recorded. Even when smoothing the data with a three-week average to account for typical weekly volatility, the export surge remains the strongest on record (see graph below). This unprecedented outflow comes as global oil markets face a major supply shock from the effective closure of the Strait of Hormuz. The resulting supply gap has triggered a strong “call” on American barrels, driving significantly higher volumes from U.S. storage hubs (including the Strategic Petroleum Reserve) to Gulf Coast export terminals.

Despite the substantial rise in export volumes, U.S. marine terminals appear well-positioned to handle additional flow. Corpus Christi’s nameplate export capacity, for instance, is approximately 5 million barrels per day, nearly double its recent throughput (see graph below). Nevertheless, upstream pipeline bottlenecks remain a risk, potentially capping the upside for certain facilities. Pipeline capacity into Ingleside was already near its limit prior to the recent throughput growth and is likely facing significant constraints at present.

Current U.S. Petroleum Export Boom Powered by Storage, Not Supply Growth

The headline U.S. crude export numbers are impressive, yet a closer look reveals the true story behind the surge. In the two months since the Iran conflict escalated, U.S. crude oil production has likely not materially changed. At the same time, domestic refinery throughput is running marginally higher than the two-year average, reducing available crude oil supply (see graph below). This means the rapid climb in exports has been almost entirely enabled by large-scale storage drawdowns, both from the Strategic Petroleum Reserve and commercial inventories across the country.

Short-term, these inventory releases are providing a welcome boost to throughput across U.S. pipelines and export terminals. However, storage drawdowns cannot continue indefinitely. For the U.S. to sustain elevated throughput volumes over the longer term, either domestic production growth or meaningful cuts in refinery runs will be required. Ultimately, global and domestic markets must balance. With a steeply backwardated forward curve currently discouraging new drilling, either higher prices or a swift resolution to the Iran conflict will be needed to rebalance the market.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 350 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.

Iran Conflict Driving Large U.S. Light Sweet Crude Premiums

The ongoing conflict in Iran and the resulting threat of a Strait of Hormuz closure continue to inject sharp volatility into global oil markets, tightening supply from the Middle East and pulling U.S. barrels strongly toward export. As previously noted, this global shortage has already widened spreads between Cushing and the Gulf Coast. Now the pressure has moved inland, creating unusual price dislocations across domestic light sweet crude grades for June delivery. Bakken crude at Dakota Access Pipeline receipt points is currently trading at a $5.60 premium to Cushing WTI, while the same grade in Guernsey trades at a more modest $3.30 premium. The standout anomaly is in Patoka, Illinois, where Bakken light sweet crude commands a staggering $9.50 premium to Cushing WTI.

The massive premium at Patoka likely stems from Midwest (PADD 2) refineries aggressively bidding up these light sweet barrels to secure domestic supply and avoid losing them to export markets, where international benchmarks such as Brent are already trading more than $11 above Cushing. This localized scramble is likely to shift some crude away from lower priced markets (Guernsey, Cushing) and toward Patoka in the near term, delivering short-term upside potential for pipelines like Dakota Access that deliver into the Patoka area.

North Dakota Oil Sees 13% Workover Rig Surge on Price Spike, But New Drilling Remains Tepid Amid Steep Backwardation

The North Dakota Department of Mineral Resources’ latest monthly Director’s Cut highlighted a notable uptick in producer activity following the recent oil price spike triggered by the Iran conflict. Workover rig counts in the state have risen approximately 13%, as operators focus on optimizing existing wells to bring incremental production online quickly. Workover rigs provide a faster and lower-capital route to incremental barrels compared to new drilling, allowing producers to capitalize on elevated near-term prices without committing to large-scale development programs.

However, new horizontal rig additions remain tepid due to the steeply backwardated WTI forward curve, with 2027 prices hovering just above $70 per barrel. While it is reported that one Bakken operator has committed to picking up a rig and frac crew for July, and another is considering a similar move, broader capital spending discipline persists across North Dakota and the wider U.S. shale patch. This market structure signals that even if Middle East supply disruptions persist, U.S. production growth is likely to remain muted in the medium term, as producers remain wary of locking in incremental capital at today’s uncertain longer-dated prices.

Flow/Transaction Updates and New Assets Under Coverage

Plainview has over 300 assets with crude oil flow 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.