BP Prudhoe Bay Royalty Trust (BPT): PESTLE Analysis [Nov-2025 Updated]

If you own BP Prudhoe Bay Royalty Trust (BPT), you know your cash flow is a hostage to external forces-you're not investing in an operating company, but a royalty stream from a mature oil field. As of 2025, BPT's future hinges on three things: the volatility of WTI crude prices, the success of enhanced oil recovery (EOR) techniques to fight the natural production decline, and the constant political tug-of-war over Alaskan oil taxes. Let's cut through the noise and map out the Political, Economic, Sociological, Technological, Legal, and Environmental (PESTLE) factors that will defintely drive the next distribution cycle.

BP Prudhoe Bay Royalty Trust (BPT) - PESTLE Analysis: Political factors

You need to understand that political decisions in Washington D.C. and Juneau are the single biggest non-geological risk factor for BP Prudhoe Bay Royalty Trust (BPT) unitholders. The Trust's income is a direct function of the West Texas Intermediate (WTI) price minus a complex formula of costs and taxes, so any shift in tax structure or federal drilling policy immediately impacts the royalty calculation, even as the Trust winds down its affairs in 2025.

Alaska state legislature constantly debates oil tax structure.

The state's fiscal health is deeply tied to North Slope oil, and with BPT's royalty payment already at $0.00 for the first two quarters of 2025, the legislative debate on oil taxes is a clear risk to the underlying operator, Hilcorp North Slope, LLC, and thus to the field's long-term economics. Alaska Senate leaders were actively debating tax reform in early 2025 to close an estimated half-billion-dollar deficit, specifically a projected $536 million deficit between this year and the next.

One proposal in February 2025 aimed to reduce a North Slope oil production tax credit by $3 per barrel and prevent producers from claiming more in tax credits than they spend on capital investment in a given year. Here's the quick math: for the Trust's Q2 2025 calculation, the Average Production Taxes were already $2.15 per barrel. An increase in this tax, or a reduction in credits for the operator, directly pressures the economic viability of the field, which is critical since the Department of Revenue's Spring 2025 forecast projects total unrestricted petroleum revenue to decline by over 25% from the FY 2024 baseline of $2.47 billion, even with a projected 44% rise in production volume.

The state's net-profit tax system is fundamentally flawed for revenue generation right now. In May 2025, the Governor vetoed a bill (Senate Bill 183) intended to increase transparency in the state's handling of oil and gas tax payments, which critics argued benefits the industry at the state's expense. That lack of transparency just makes it defintely harder to model future state revenue policy.

Federal administration policy shifts on Arctic drilling permits.

The federal administration's policy has seen a dramatic, pro-development shift in 2025, reversing prior restrictions and expanding the potential for new drilling near Prudhoe Bay. This is a positive signal for the long-term life of the North Slope oil infrastructure, which is vital to the Trust's royalty interest. In November 2025, the administration finalized plans to reopen the entire 1.56 million-acre Coastal Plain of the Arctic National Wildlife Refuge (ANWR) to oil and gas leasing.

Also, the administration lifted Biden-era restrictions in the National Petroleum Reserve-Alaska (NPR-A), opening approximately 82% of the 23 million-acre reserve to leasing. This is a major policy reversal that reinstates the 2020 Record of Decision, streamlining approvals for energy projects. The Interior Department is also working to reinstate leases in ANWR that were canceled by the previous administration. More drilling is coming, so that's a good thing for the region's longevity.

Geopolitical stability affects global crude oil price benchmarks.

Geopolitical instability continues to inject volatility into crude oil prices, but the dominant trend in late 2025 is a bearish one driven by fundamentals. The Trust's royalty calculation is based on the WTI price, and that price has been under pressure. In October 2025, WTI crude was trading around $61-$62 per barrel, hitting a four-month low, with Brent crude around $64-$65 per barrel.

The U.S. Energy Information Administration (EIA) forecasts a further decline, predicting WTI could fall to an average of $58 per barrel in Q4 2025. This downward pressure is driven by robust global supply from non-OPEC+ nations, including the United States, plus moderating global demand. This is a critical factor because the Trust's royalty interest is highly sensitive to the WTI price, as illustrated by the Q2 2025 results:

When the WTI price is below the 'break-even' price (which was over $100 in Q2 2025), the royalty payment is zero, which is exactly what happened.

Potential for new federal lease sales or restrictions near Prudhoe Bay.

The political environment in late 2025 is mandating new lease sales, which signals a clear intent to maximize North Slope oil production, directly impacting the long-term supply and infrastructure supporting Prudhoe Bay. The new federal policy mandates a significant increase in leasing activity in the Arctic regions adjacent to Prudhoe Bay.

The budget reconciliation bill mandates multiple new lease sales over the next decade:

• Four lease sales in the Arctic National Wildlife Refuge (ANWR), each offering a minimum of 400,000 acres.
• Five lease sales in the Western Arctic (NPR-A), each offering a minimum of 4 million acres.

Specifically, a lease sale in the NPR-A is already planned for Winter 2025-26, which will be the first sale in that reserve since 2019. This push for new acreage, plus the proposal to add a 'High Arctic' planning area to the federal offshore leasing program, shows a strong government commitment to Arctic oil. The key action here is watching the industry's actual bid interest in the Winter 2025-26 NPR-A sale; low interest, like the prior ANWR sale that raised only about $14.4 million in bids, would signal that the political opportunity is still constrained by economics and logistics.

BP Prudhoe Bay Royalty Trust (BPT) - PESTLE Analysis: Economic factors

Royalty is highly sensitive to WTI crude oil price fluctuations.

The entire economic viability of the BP Prudhoe Bay Royalty Trust (BPT) is directly tied to the daily price of West Texas Intermediate (WTI) crude oil, making it an extremely high-leverage bet on energy prices. The royalty payment formula takes the WTI price and subtracts various costs and taxes to arrive at the 'Per Barrel Royalty.'

In 2025, this relationship has been fatal. For the first half of the year, the average WTI price was far below the effective 'break-even' price required for a positive royalty payment. While the U.S. Energy Information Administration (EIA) forecasts the WTI spot average price to be around $65.15 per barrel in 2025, and J.P. Morgan projects an average of $62 per barrel, these levels were insufficient to cover the escalating costs.

Honestly, the price volatility is the only factor that matters, but the cost structure is what kills it.

Here's the quick math for the first two quarters of 2025, showing why price is the primary risk:

Since the Per Barrel Royalty cannot be less than zero, the Trust received no revenue for either quarter.

The Trust's royalty interest is subject to termination based on low price thresholds.

This isn't a near-term risk; it's a realized event. The Trust's governing agreement stipulated that it would terminate if the net revenues from the Royalty Interest were less than $1,000,000 per year for two successive years. Because the Trust received zero revenues for all four quarters of 2023 and all four quarters of 2024, the termination condition was met.

The Trust terminated at 11:59 PM on December 31, 2024, and the winding-up process commenced in January 2025. What this estimate hides is that the economic model simply ceased to function at prevailing oil prices and costs, making the termination an economic certainty, not a legal technicality.

Operating costs for the Alaska North Slope are structurally high.

The structural cost burden is the real long-term problem for the royalty calculation. The operator, Hilcorp North Slope, LLC (HNS), is permitted to deduct 'Chargeable Costs,' which are fixed amounts specified in the original conveyance and then multiplied by a Cost Adjustment Factor (CAF) tied to inflation, plus Production Taxes. These costs are not HNS's actual operating costs, but they act as a fixed, escalating hurdle for the Trust's revenue.

The Adjusted Chargeable Costs have become the dominant economic headwind, consistently pushing the royalty's break-even WTI price well above market rates in 2025:

• Q1 2025 Adjusted Chargeable Costs: $98.89 per barrel
• Q2 2025 Adjusted Chargeable Costs: $99.63 per barrel

For the Trust to have made a payment in Q2 2025, the WTI price would have needed to exceed $101.78 per barrel (Adjusted Chargeable Costs plus Production Taxes).

Inflationary pressure increases costs for maintenance and labor.

The Cost Adjustment Factor (CAF) is explicitly linked to the U.S. Consumer Price Index (CPI). This means that general inflation, even outside the oil industry, directly and automatically increases the deductible Chargeable Costs in the royalty formula, regardless of the operator's actual spending on maintenance and labor in Alaska.

The effect is clear in the 2025 data, where the average Adjusted Chargeable Costs increased by $0.74 per barrel from Q1 to Q2 2025, rising from $98.89 to $99.63. This structural inflation mechanism is a defintely a one-way street, constantly raising the break-even price and accelerating the Trust's demise.

Prudhoe Bay production volume continues its natural long-term decline.

The royalty is capped at a percentage of the first 90,000 barrels of average daily net production from specific leases. The Prudhoe Bay field is a mature asset, and while new North Slope projects may boost overall Alaska production in 2026, the specific leases tied to the Trust continue their natural decline curve.

The actual production volumes used in the royalty calculation for the first half of 2025 were significantly below the cap, reflecting this long-term trend:

• Q1 2025 Average Net Production: 65.6 thousand barrels per day (mb/d)
• Q2 2025 Average Net Production: 63.3 thousand barrels per day (mb/d)

This decline reduces the total volume of oil eligible for the royalty, compounding the negative impact of the high per-barrel costs and low WTI prices. The Trust's royalty is already limited by a physical cap, and the natural decline is pushing it further away from that maximum potential revenue.

BP Prudhoe Bay Royalty Trust (BPT) - PESTLE Analysis: Social factors

You're looking at BP Prudhoe Bay Royalty Trust (BPT) and seeing a royalty stream tied to one of the most mature, and socially complex, oil fields in the world. The social factors here are not abstract; they translate directly into operational costs, regulatory risk, and investor flight. The core dynamic is a conflict between global anti-fossil fuel sentiment and the local economic reliance on oil, which creates a high-cost, high-scrutiny environment for the operator, Hilcorp North Slope, LLC.

Public and investor sentiment against fossil fuels, especially Arctic drilling.

Investor sentiment has turned sharply negative, moving beyond mere Environmental, Social, and Governance (ESG) concerns to a fundamental view of Arctic oil as a stranded asset. This shift is a major factor in the Trust's current state. The Trust formally entered dissolution on December 31, 2024, due to not meeting revenue thresholds, and announced a $0.00 dividend payment for both the quarter ended March 31, 2025, and the quarter ended June 30, 2025. That's a clear signal.

The Trust's units were delisted from the NYSE on June 30, 2025, and moved to the illiquid OTC Pink market under the symbol BPPTU. This move depresses liquidity and further pressures the trading price, which was around $0.51 per unit as of November 2025. For context, a July 2025 poll showed that 57% of swing district voters support policies to protect the Arctic from new oil and gas development, citing the risk to Alaska's $3 billion outdoor recreation economy.

Labor availability and high cost for specialized North Slope workers.

The North Slope is one of the most expensive operating environments globally, and labor is a primary driver. The specialized workforce required for Arctic conditions is scarce, driving up wages and overall project costs. This isn't just a general cost; it's a direct financial headwind for the Trust's royalty calculation.

Here's the quick math: the royalty payment is calculated after subtracting Chargeable Costs. For the quarter ended June 30, 2025, the Average Adjusted Chargeable Costs were an astronomical $99.63 per barrel, far exceeding the average WTI Price of $63.95 per barrel for that same period. This cost structure, heavily influenced by high labor and logistics, is the single biggest threat to the Trust's viability. Also, job numbers in the North Slope and Northwest Arctic regions jumped by 7% in the past year (as of April 2025), indicating intense labor demand as new projects like Willow and Pikka ramp up, making it defintely harder to find and retain staff.

Increased focus on corporate social responsibility (CSR) from operators.

Hilcorp North Slope, LLC, as the operator, is under pressure to demonstrate strong corporate social responsibility (CSR) to manage reputational risk and maintain its license to operate. This focus translates into non-production-related capital expenditures that reduce overall profitability, but are mandatory for social acceptance.

Key CSR and environmental commitments include:

• Commitment of $10 million for a pilot project at Prudhoe Bay aimed at capturing CO2 from the fuel gas stream.
• Potential to capture over 600,000 metric tons of CO2 per year from the pilot project.
• Reported 77% reduction in absolute methane emissions since 2020.
• Over $32 million in community giving in Alaska since 2020.

This is a cost of doing business in the Arctic, and it's a permanent feature of the operating model. The operator must invest heavily in social capital just to keep the field running.

Alaskan Indigenous groups' influence on resource development decisions.

The influence of Alaskan Indigenous groups, particularly the Iñupiat people, is a complex, dual-sided social factor. On one hand, oil development provides critical economic support; on the other, it threatens the traditional subsistence way of life.

The Alaska Native Claims Settlement Act (ANCSA) created for-profit corporations like the Arctic Slope Regional Corporation (ASRC), which is a powerful advocate for resource development. ASRC has distributed more than $1.8 billion to other Alaska Native corporations across the state since first oil on ASRC lands in 2000. This massive economic benefit aligns some local leadership with industry goals.

Still, other Indigenous communities fear the impact of infrastructure on caribou migration and subsistence hunting, which are vital to their cultural identity and food security. This tension is managed through formal consultation, such as the Bureau of Land Management's outreach to 33 Alaska Native organizations in 2025 regarding policy changes in the National Petroleum Reserve-Alaska (NPR-A). The operator must navigate this split, ensuring that infrastructure respects subsistence practices, like maintaining pipeline heights of at least seven feet to allow caribou herds to pass underneath. The social risk here is not a complete shutdown, but the potential for costly delays and injunctions from litigation over environmental and subsistence impacts.

BP Prudhoe Bay Royalty Trust (BPT) - PESTLE Analysis: Technological factors

Success of Enhanced Oil Recovery (EOR) techniques is crucial for production stability.

The Prudhoe Bay field is a mature asset, having produced over 13 billion barrels of oil since its discovery. For the BP Prudhoe Bay Royalty Trust's royalty interest to remain valuable, the operator, Hilcorp North Slope, LLC, must defintely invest in advanced Enhanced Oil Recovery (EOR) techniques. EOR is essentially the technological lifeline for a super-giant field like this, pushing production past the limits of conventional methods.

The success of these techniques is reflected in the field's surprisingly low decline rate. Hilcorp's continued investment is supporting a projected Proved Developed Producing (PDP) and Proved Undeveloped (PUD) decline rate of just 2% annually over the next five years. That's a strong technical performance for a field this old. The average net production for the quarter ended March 31, 2025, stood at 65.6 thousand barrels per day (mb/d), a number that would fall much faster without aggressive EOR.

Here's the quick math: keeping the decline rate at a mere 2% requires constant, high-tech work-mostly through miscible gas injection and waterflooding, which physically push more oil out of the reservoir rock.

Advancements in drilling technology can slow the field's decline rate.

New drilling technology is the other half of the equation, allowing the operator to access pockets of oil that were previously uneconomical or unreachable. Hilcorp is actively pursuing this strategy, targeting a 5% production increase in 2025 through continued investment. This kind of growth target is only possible with modern, high-efficiency drilling.

The operator is running a significant program, utilizing five active rigs in the field. This level of activity, focused on infill drilling and sidetracks, is designed to maximize recovery from the existing infrastructure. We are also seeing the impact of technological improvements in well productivity across the North Slope. For example, new project wells are demonstrating a 20% productivity advantage over older wells, a clear indicator of superior well design and completion techniques, even in the harsh Arctic environment.

• Run five active rigs to maximize infill drilling.
• Achieve a 20% productivity advantage in new wells.
• Target a 5% production increase for the 2025 fiscal year.

Integrity and maintenance of the aging Trans-Alaska Pipeline System (TAPS).

The Trans-Alaska Pipeline System (TAPS) is the sole artery for Prudhoe Bay's oil, and its integrity is a massive technological and logistical challenge. Built between 1975 and 1977, the 800-mile-long pipeline is showing its age, plus it faces new risks from climate change.

The biggest technological risk is the thawing permafrost (permanently frozen ground), which is jeopardizing the structural integrity of the vertical supports holding up the above-ground sections. Also, the declining North Slope production means lower throughput, which changes the oil's temperature and flow dynamics.

The average daily throughput in 2024 was approximately 464,784 barrels a day. This lower flow rate means the crude oil takes longer-about two weeks-to reach the Valdez Marine Terminal, arriving colder. This necessitates specific technological solutions by the operator, Alyeska Pipeline Service Company, to manage wax accumulation and maintain flow:

Digitalization efforts to optimize field operations and reduce costs.

Digitalization, or the use of advanced data analytics, sensors, and remote monitoring, is critical for maximizing efficiency in a high-cost, remote environment like Prudhoe Bay. The goal is to optimize every barrel and reduce the chargeable costs that directly impact the Trust's royalty calculation.

While specific 2025 cost-saving figures from a new Digital Twin (a virtual replica of the field) aren't public, the operator's actions point to a clear focus on data-driven efficiency. Hilcorp completed a major Turnaround (TAR) at Prudhoe Bay in the summer of 2025, a massive, coordinated maintenance effort that relies on sophisticated planning software to minimize downtime and costs.

Furthermore, new infrastructure projects are being built with a digital backbone. For instance, a nearby development is constructing an 80-foot telecommunications tower to support the Nanushuk Processing Facility tie-in. This investment in high-bandwidth connectivity is the foundation for future digitalization, enabling real-time data collection from intelligent wellheads and sensors across the field. This shift is how a mature field stays competitive.

BP Prudhoe Bay Royalty Trust (BPT) - PESTLE Analysis: Legal factors

Royalty Calculation is Governed by a Complex 1989 Agreement

The entire legal basis for BP Prudhoe Bay Royalty Trust's existence and its revenue stream is the BP Prudhoe Bay Royalty Trust Agreement dated February 28, 1989. To be defintely clear, this is not a typical corporate structure; it's a passive entity, and its termination is hard-wired into this founding legal document.

The Trust Agreement stipulates that the Trust terminates when the net revenues from the Royalty Interest are less than $1.0 million for two successive years. Honestly, the most significant legal factor for the Trust in 2025 is that this condition was met: the Trust did not receive any revenues attributable to any of the four quarters of 2023 or 2024. So, the Trust terminated at 11:59 PM on December 31, 2024, and the Trustee, The Bank of New York Mellon Trust Company, N.A., has commenced the winding-up process.

The complexity of the royalty calculation formula itself, which is central to the agreement, is what drove the termination. The formula is designed to cut off payments to the Trust when the oil price is too low relative to the operator's (Hilcorp North Slope, LLC) costs. Here's the quick math for the most recent quarter:

Because the resulting Average Per Barrel Royalty for the quarter ended June 30, 2025, was a negative ($37.83), the Trust received no payment for the quarter, as the agreement states the payment cannot be less than zero.

Litigation Risk Related to Environmental Compliance and Permitting

Even in a wind-up scenario, the underlying Prudhoe Bay field operator, Hilcorp North Slope, LLC, faces continuous and escalating litigation risk, which affects the value of the Royalty Interest during the final disposition. The history here is important: a prior operator, BP Exploration (Alaska) Inc., settled claims over reduced royalty payments following oil spills and a temporary shutdown at Prudhoe Bay. That settlement amount was $29,469,080.92, paid to the Trust for claims related to 2006, 2007, and 2008.

Today, the major litigation risk centers on environmental permitting, particularly the federal government's push to expand drilling. The general trend in 2025 climate litigation shows that approximately 20% of climate cases filed in 2024 targeted companies or their directors and senior officers, and ESG (Environmental, Social, and Governance) and environmental claims saw a jump in class and mass action activity. The key legal risks for the operator are:

• Environmental Lawsuits: Opposing groups are expected to file legal challenges against the Trump administration's June 2025 plan to repeal Biden-era restrictions and open approximately 82% of the National Petroleum Reserve-Alaska (NPR-A) to leasing.
• Pipeline Safety: The Trans-Alaska Pipeline System (TAPS), which runs for 800 miles, remains a critical and aging piece of infrastructure. Any incident could trigger massive litigation and operational shutdowns, similar to the 2006-2008 events.

Complex Federal and State Permitting Processes for New Drilling Activity

The regulatory environment for new oil activity on the North Slope, including the area surrounding Prudhoe Bay, is highly volatile in 2025. The complexity of permitting is not just bureaucratic; it's political and subject to immediate judicial review.

The Trump administration's June 2025 announcement to reverse restrictions and expedite development aims to simplify the process, but this immediately introduces a new layer of legal uncertainty. The path from policy to oil flowing is lengthy, involving regulatory finalization, environmental impact statements, and, critically, the inevitable legal challenges that will likely extend the regulatory finalization timeline into early 2026 or later.

What this estimate hides is the power of judicial injunctions. A single successful lawsuit by an environmental group could halt a major project, regardless of the administration's stated policy goal to unlock an estimated 2.7 to 10 billion barrels of recoverable oil in the region.

Changes to Federal Tax Code Regarding Royalty Trusts and Pass-Through Entities

While the Trust is in wind-up, the tax landscape for royalty trusts and their unitholders is still relevant for final distributions and future pass-through energy entities. The One Big Beautiful Bill Act (OBBBA), signed in July 2025, provides some clarity and stability for the tax structure of trusts and oil operators.

The new law makes permanent the individual income tax rate schedules enacted by the Tax Cuts and Jobs Act (TCJA). For estates and trusts, the existing four tax rates of 10%, 24%, 35%, and 37% remain in effect, preventing a revert to the higher pre-TCJA rates. Also, the operator, Hilcorp North Slope, LLC, benefits from a provision allowing oil and gas companies to exempt intangible drilling and development costs when calculating their corporate alternative minimum tax (AMT), which improves the operator's financial position, though it does not change the Trust's termination.

BP Prudhoe Bay Royalty Trust (BPT) - PESTLE Analysis: Environmental factors

Strict federal and state regulations on Arctic ecosystem protection.

You need to understand that the regulatory environment in the Arctic is a political pendulum, which directly impacts the operating costs for Hilcorp North Slope, LLC (HNS), the current operator of the Prudhoe Bay Unit. While the area is ecologically sensitive, the near-term federal policy shift is moving toward less restriction.

In November 2025, the Trump administration announced the final rule to rescind previous federal protections that restricted future oil and gas leasing in vast swaths of the National Petroleum Reserve-Alaska (NPR-A). This reversal, which overturns protections for areas like Teshekpuk Lake, signals a less stringent federal approach to new Arctic development. Still, the existing Prudhoe Bay operation remains subject to stringent state and federal permitting, especially concerning water quality and wildlife impact, plus the ongoing requirements from past legal settlements.

The core compliance burden remains high because the operator must maintain a comprehensive Integrity Management Program (IMP) for the over 1,600 miles of pipeline on the North Slope, a requirement stemming from a 2011 Clean Water Act settlement. That's a huge, defintely non-negotiable fixed cost for the operator.

Climate change impacts like permafrost thaw threaten infrastructure integrity.

The most immediate, non-negotiable environmental risk is the physical threat of climate change to the infrastructure itself. The Arctic is warming nearly three times faster than the global average, and this is causing permafrost (perennially frozen ground) to thaw, which directly undermines the stability of roads, pipelines, and drilling pads.

This isn't a future problem; it's a current engineering challenge that adds significant cost. Research shows that infrastructure deterioration is accelerating faster than expected because the structures themselves hasten the thaw in adjacent permafrost. Engineers must account for the formation of 'taliks' (areas of year-round unfrozen ground) under infrastructure, which can cause failure within a structure's service lifetime of about 30 years. This forces the operator to spend heavily on mitigation and maintenance, which is baked into the 'Chargeable Costs' that reduce the royalty payment to the Trust.

• Permafrost thaw causes ground subsidence, threatening pipelines and well cellars.
• The thaw creates pathways for contaminants to migrate into the environment.
• Infrastructure failure due to thawing ice-rich soils is a major risk.

Methane emissions and carbon capture requirements add operating cost pressure.

The global push to decarbonize is hitting the North Slope, even if federal policy is currently relaxed. Financial institutions are increasingly requiring companies to have a plan for reducing their carbon footprint, which means the operator, HNS, must consider Carbon Capture and Storage (CCS).

Alaska is actively developing a framework for CCS, with the state aiming to gain primacy over the federal Class 6 well program for CO2 sequestration. The state has an estimated storage capacity of 50 gigatons of carbon. However, the sheer capital cost for a large-scale project is staggering. For an Alaska Gas Treatment Plant (GTP) project, the estimated capital cost for a post-combustion carbon capture system was more than $3 billion (based on a 2016 escalation). Even a small fraction of that cost, or the cost of compliance with new methane emission rules, would increase the 'Chargeable Costs' further, directly eroding the Trust's royalty revenue.

Risk of oil spills and associated cleanup liability in a sensitive environment.

The high-profile risk of an oil spill in the sensitive Arctic environment remains a major financial liability. Past events highlight the potential cost: the 2006 spill of approximately 5,053.6 barrels resulted in a $25 million civil penalty, the largest per-barrel penalty at the time. This is a clear indicator of the massive financial risk associated with any operational failure.

The cost of this constant environmental vigilance is already reflected in the Trust's financial performance. For the second quarter of 2025, the Average Adjusted Chargeable Costs (which include operating expenses, maintenance, and environmental compliance) were $99.63 per barrel. This high-cost structure is why the Trust terminated on December 31, 2024, because the net revenues were below the $1.0 million threshold for two successive years.

Here's the quick math on the Q2 2025 non-payment, showing the pressure of costs like environmental compliance:

When the all-in cost of production, heavily influenced by the high cost of operating safely in a fragile, thawing Arctic, exceeds the oil price, the royalty payment is zero. That's the bottom line on environmental risk for the Trust.