Bass Energy & Exploration is independently owned and operated by the Bass family.
Bass Energy & Exploration
7 NE 6th Street
Oklahoma City, OK 73104
Pivot: Canada is moving to break its 90% export reliance on the United States by approving a framework for a privately financed pipeline to Asia. This represents a significant policy U-turn by Prime Minister Mark Carney, prioritizing economic resilience and "energy independence" over the previous government's aggressive decarbonization agenda in response to rising US tariff tensions.
The proposed route through British Columbia faces severe legal and political obstacles, specifically the 2019 tanker moratorium on the northern coast. While national polling shows 56% public support due to economic anxiety, the project is a "non-starter" for BC Premier David Eby and faces non-negotiable opposition from coastal First Nations, setting up a constitutional clash between federal trade goals and local sovereignty.
BP has successfully brought the Atlantis Drill Center 1 expansion online in the "Gulf of America" (formerly Gulf of Mexico) two months ahead of schedule. Adding 15,000 barrels of oil equivalent per day (boe/d), this project demonstrates the operational efficiency of subsea tie-backs and reinforces the Gulf's status as a critical, high-margin supply basin.
The Atlantis startup is a key milestone in BP’s strategy to grow its US production to 1 million boe/d by 2030. By investing heavily in legacy assets like Atlantis (producing for 20 years), BP is signaling that brownfield expansion in stable jurisdictions is the most effective route to capital-efficient growth.
The energy landscape in Oklahoma is being reshaped by at least 18 new data center projects. Utilities like OG&E and PSO are responding by proposing new natural gas generation units and transmission upgrades, confirming that the rapid expansion of AI and digital infrastructure is directly driving demand for firm, fossil-fuel baseload power.
The surge in infrastructure spending has triggered a debate over cost allocation. With utilities seeking to pass the costs of new transmission lines and power plants onto the customer base, consumer advocates warn that everyday Oklahomans could face higher monthly bills to subsidize the energy-intensive operations of global tech giants.
Canada’s long-standing oil relationship with the United States is showing signs of strain. In November 2025, Prime Minister Mark Carney unveiled a sweeping federal-provincial agreement to support a new pipeline carrying Alberta’s oil sands crude to the Pacific coast. This marks a dramatic reversal of Canada’s recent climate-focused energy policy. Just four years ago, the cross-border Keystone XL project was cancelled on environmental and human rights grounds. Now, facing aggressive U.S. tariffs and trade uncertainty, Ottawa’s priority has shifted to economic resilience over rapid decarbonization.
Carney’s rationale is clear: Canada must diversify its export markets. The U.S. currently buys over 90% of Canadian crude exports, effectively making America a near-monopsony (single dominant buyer) for Canadian oil. Such dependence gives U.S. policymakers leverage over Canada’s economy. Carney has explicitly stated that a pipeline to Asia would make Canada “stronger, more independent, more resilient” in the face of U.S. trade actions. The goal is to double non-U.S. exports within the next decade, reducing vulnerability to U.S. tariffs or demand swings. Alberta’s Premier Danielle Smith applauded the deal as the end of “dark times” for her oil-dependent province.
Strategically, the proposed pipeline would be massive – designed for at least 1 million barrels per day of heavy crude flow to Asian markets. This volume could significantly alter global crude trade patterns, giving Asian refiners a stable alternative supply of bitumen-rich oil. However, the project hinges on private financing and commercial interest. Notably, the agreement stipulates the pipeline must be privately funded; no specific company has yet stepped up. One challenge is that Alberta’s oil sands crude is a dense, high-sulfur grade that many refineries cannot easily process without costly upgrades. Industry analysts note limited enthusiasm among energy companies for new heavy-crude pipelines given these refining hurdles. Alberta’s government has tried to jump-start interest by pledging $10 million for early project development, essentially seed money to attract a private consortium. Still, without a committed builder and clear economics, the pipeline’s future is uncertain.
Geography presents a major obstacle to Carney’s grand plan. To reach Asia, Alberta’s oil must traverse British Columbia (B.C.) to a port on the Pacific – but Canada has a 2019 oil tanker moratorium along B.C.’s northern coast. This “Great Bear Rainforest” tanker ban was enacted to protect a fragile marine ecosystem renowned for its stormy seas, hazardous navigation channels, and rich biodiversity. It was also a political victory for environmental groups and Indigenous communities, effectively blocking any Northern Gateway pipeline project in the past. Lifting or adjusting this ban is widely seen as a prerequisite for the new pipeline, since the crude would otherwise have no route to tankers bound for Asia.
Ottawa’s indication that it might relax the tanker ban has provoked fierce resistance. Coastal First Nations leaders have declared the ban non-negotiable, citing the grave risk of oil spills in their traditional waters. Chiefs representing over 600 Indigenous communities have called on Ottawa to keep the moratorium in place and even withdraw support for the Alberta pipeline agreement. B.C. Premier David Eby has likewise warned that any pipeline requiring an end to the tanker ban is a “non-starter” for his government. Local opposition is rooted in both environmental and legal grounds – coastal tribes have rights and title that could lead to court challenges, and B.C.’s populace remains wary of oil tankers in these sensitive inner channels.
Environmental advocates add that no amount of wishful thinking can erase the physical dangers. Green Party leader Elizabeth May bluntly stated there is “no chance on God’s green Earth” an oil tanker could safely navigate the turbulent waters between Haida Gwaii and B.C.’s north coast without incident. Citing scientific assessments of the region, she argues that a major spill is almost inevitable if large crude carriers are allowed in these waters. This impasse sets up a potential federal-provincial showdown: to fulfill Carney’s export vision, Ottawa may have to override B.C.’s tanker ban – a move that would ignite political and legal battles over environmental sovereignty and Indigenous rights.
Despite the controversy, Canada’s political calculus is being altered by shifting public opinion. Economic anxiety and job security have become top-of-mind, even if it means compromising on climate goals. A new Nanos Research poll indicates that 56% of Canadians support (or somewhat support) building a new Alberta-to-Coast oil pipeline, and 55% support lifting the B.C. oil tanker ban to enable it. Only about 37% flatly oppose these ideas. This slim majority in favor represents a notable change in attitude from a few years ago, when pipeline projects were lightning rods for public protest. It suggests that concerns over trade uncertainty with the U.S. and broader economic stress (e.g. inflation and jobs) are outweighing environmental worries for many Canadians. As pollster Nik Nanos observed, people are worried about their livelihoods and are “trying to figure out how projects can happen” in the face of U.S. trade uncertainty.
This emerging public mandate gives the federal government some cover to pursue “energy realism.” Even within the typically climate-conscious Liberal cabinet, Carney’s pivot has gained traction as a national interest issue. Still, the move is a U-turn on Canada’s recent climate commitments. Canada’s oil and gas industry is the country’s largest emitter – accounting for roughly 31% of national greenhouse gases, with oil sands operations making up about 36% of the sector’s emissions. Approving a major new pipeline to boost oil sands output directly contradicts Canada’s pledges to cut emissions under global climate agreements. This puts Ottawa in a bind: how to reconcile a leap in fossil fuel infrastructure with its decarbonization agenda. The likely approach will be to emphasize parallel efforts in emission mitigation – for instance, touting carbon capture projects or stricter regulations on producers – even as oil exports ramp up. But the overall signal is that when forced to choose, Canada’s leadership is prioritizing energy security and trade diversification over aggressive climate action, at least in the near term.
Even as onshore shale drilling faces headwinds, the offshore Gulf of Mexico (rebranded by some as the “Gulf of America” for its strategic importance) is proving its resilience. A prime example is BP’s latest success in the deepwater Atlantis field. In December 2025, BP announced first oil from the Atlantis Phase 3 expansion – known as Atlantis Drill Center 1 – which was brought online two months ahead of schedule. This subsea tie-back project connects two new production wells to the existing Atlantis platform via new pipelines, adding roughly 15,000 barrels of oil equivalent per day (boe/d) of capacity to one of BP’s flagship Gulf developments.
The operational feat is noteworthy in an industry where mega-project delays are common. BP credited the early startup to leveraging existing infrastructure and inventory, drilling wells more efficiently, and streamlining offshore installation plans. Essentially, by expanding via tie-backs to an established hub, BP minimized complexity and cost. Atlantis itself is a mature asset – discovered in 1998 and producing for nearly 20 years – yet it remains a prolific and strategic one. The field hosts BP’s deepest moored floating platform (operating in over 7,000 feet of water) and had been producing up to 200,000 barrels of oil and 180 million cubic feet of gas per day at peak rates. Incremental projects like Drill Center 1 tap into remaining pockets of oil tied to the platform’s existing network, delivering high-margin barrels without the expense of a brand-new facility.
According to BP, the Atlantis expansion is the company’s seventh upstream project start-up in 2025 – capping an exceptionally busy year. It’s part of a broader portfolio push to grow BP’s U.S. production to ~1 million boe/d by 2030. “Atlantis Drill Center 1 caps off an excellent year of seven major project start-ups for BP. This project supports our plans to safely grow our upstream business, which includes increasing U.S. production to around one million barrels… per day by 2030,” said Gordon Birrell, BP’s Executive VP for Production & Operations. In other words, the Gulf of Mexico is central to BP’s long-term growth strategy, even as the company talks up renewable investments elsewhere. The economics of these deepwater projects remain attractive – large scale, relatively stable operating costs, and decades-long production profiles in a politically stable region.
BP’s Gulf activity reflects a wider confidence among producers in the value of offshore oil. The Atlantis Drill Center 1 expansion is one of three major Gulf of Mexico projects that BP has slated for completion by 2027 (among 10 big projects globally). Earlier in the year, BP also started up the Argos platform’s Southwest Extension in the Gulf, which added another 20,000 barrels per day of capacity. The next planned milestone is an Atlantis Major Facility Expansion that will involve water injection to boost reservoir pressure and output in the field. In total, these efforts underscore that the Gulf remains a growth arena, not just a legacy asset base.
Policy support has bolstered this outlook. The U.S. federal stance in recent years – spanning from the prior administration’s “energy dominance” agenda to current initiatives – has kept Gulf lease opportunities open and signaled a favorable regulatory environment for offshore drilling. Large lease sales have been back on the calendar, and permitting, while still thorough, hasn’t seen the kind of clampdown some feared after 2020. This stability gives oil companies the confidence that multi-billion dollar projects started now will not be stranded by policy shifts. It’s a stark contrast to some other regions where fiscal terms or political support for oil development are in flux.
From a strategic perspective, deepwater Gulf projects are attractive because they deliver long-lived, high-volume production with a relatively lower carbon intensity per barrel than many onshore plays (due to economies of scale and modern efficiencies). They act as “anchor” supply – baseline oil flows that can sustain refineries and export commitments for decades. BP’s commitment to invest in these projects – alongside partners like Woodside Energy, which holds a 44% stake in Atlantis – indicates that Big Oil sees Gulf barrels as crucial to future supply security. As Andy Krieger, BP’s SVP for the Gulf and Canada, put it: “We are committed to investing in America as we firmly believe this region will continue to play a critical role in delivering secure and reliable energy to the world today and tomorrow”. In essence, the U.S. Gulf is being treated as a strategic reserve of sorts, one that can be expanded methodically to meet rising demand or offset declines elsewhere.
The timing of the Gulf’s renaissance aligns with a renewed emphasis on energy security in U.S. policy circles. Geopolitical tensions and higher oil price volatility in recent years have underscored the importance of domestic production. The Gulf of Mexico, with its existing pipeline and refinery connections, offers a dependable source of crude that is less susceptible to international disruption. Recognizing this, U.S. policymakers have been supportive – for instance, designating the Gulf as critical infrastructure and streamlining certain permitting processes. While environmental regulations (like robust safety rules after Deepwater Horizon) remain in place, there’s a concerted effort to avoid unnecessary delays for projects that bolster domestic supply.
This supportive backdrop has tangible effects. Companies like BP can justify fast-tracking investments because they anticipate fewer regulatory holdups and a favorable market for the oil. The Atlantis expansion coming online ahead of schedule demonstrates the efficiencies gained when government and industry goals align. In 2025 alone, BP achieved first production from major projects not just in the Gulf but also in places like Egypt, West Africa (Mauritania/Senegal), Trinidad, and the North Sea. That global sweep of start-ups indicates a race to bring resources to market while demand is strong and before any long-term peak oil demand scenario. For the Gulf of Mexico, the window looks especially good: it has the reserves, infrastructure, and political backing to continue as a cornerstone of North American energy for years to come.
On the U.S. mainland, a very different energy challenge is emerging. Oklahoma, a state traditionally known for oil and gas production, now finds itself contending with the power demands of the 21st-century digital economy. Over the past two years, tech giants and data hosting firms have been scouting and announcing projects across Oklahoma to build massive data centers – the server farms that run the cloud and artificial intelligence services. According to an investigation by The Frontier, at least 18 data center projects are either under construction or awaiting approval across the state. This is an astonishing number in such a short time, and it’s turning into a major stress test for the region’s electric utilities and infrastructure.
Several factors make Oklahoma attractive for these energy-hungry facilities: abundant land, relatively low electricity rates, tax incentives, and a business-friendly regulatory climate. Companies like Google and Microsoft have already established big data centers in the state in recent years, and more are looking to follow. But each large data center can draw tens of megawatts of power – on par with a small city’s consumption. The surge of 18 new centers would create extraordinary new demand on the grid, essentially equivalent to dropping multiple new cities’ worth of load onto Oklahoma’s system. This raises a critical question: How will Oklahoma generate enough electricity to power these facilities, and what will that mean for everyday consumers?
To brace for the coming wave of demand, Oklahoma’s major utilities are pivoting quickly to boost capacity. The state’s two largest electric companies – Oklahoma Gas & Electric (OG&E) and Public Service Company of Oklahoma (PSO) – are already charting plans for substantial expansions of generation and transmission. Renewable energy alone cannot reliably cover the huge, continuous power draw of data centers (which require near 100% uptime, something solar and wind cannot guarantee without massive storage). As a result, the utilities’ expansion plans are centered on fossil fuel power and grid upgrades, effectively re-carbonizing some of the electricity mix to ensure reliability.
According to The Frontier report, the utilities are proposing a slate of measures:
State regulators are acknowledging the scale of this challenge. The Oklahoma Corporation Commission (which oversees utilities) voted recently to pre-approve OG&E’s expansion plans – including new power purchase deals and infrastructure projects in eastern Oklahoma County, Pittsburg County, and the Kiamichi region. These areas are presumably where either new generators will be sited or where large transmission improvements will occur. The pre-approval indicates regulators see the writing on the wall: if the data center boom proceeds, the power must be ready in time, and that likely means green-lighting utility investments now.
Behind this flurry of activity is a hard truth: the digital economy’s growth is outpacing the green energy transition. Data centers operate 24/7 and demand rock-solid power availability. While Oklahoma has invested in wind energy and some solar, those resources are intermittent and often located far from load centers. Batteries at the scale needed to back up entire data centers are still prohibitively expensive. Consequently, the practical solution being adopted is to fall back on natural gas – a fossil fuel – for dependable baseload and peaking power. Industry estimates indicate that a large majority of new data center capacity nationwide still relies on gas or other fossil-generated electricity for its primary power or backup. Oklahoma’s case exemplifies this trend: despite hopes to decarbonize, the immediate need for reliable electricity is causing a “re-carbonization” effect, at least in the short term, as gas plants and infrastructure expand.
The rapid build-out of power infrastructure for data centers is not without controversy. A growing point of tension is who will bear the cost of these new investments. Constructing power plants and transmission lines is expensive, and utilities generally recover those costs through rates charged to customers. The Frontier uncovered that the utilities intend to pass on the costs of new grid upgrades and generation to all their customers – not just the tech companies – meaning residential and small business ratepayers could see higher electric bills. As the report put it, “The utilities are already looking to pass the cost of new transmission lines and power generation on to all customers, including residential users.”
This prospect has consumer advocates on high alert. Oklahomans have enjoyed relatively low electricity rates historically, and a sudden jump in rates to subsidize huge data centers owned by some of the world’s richest companies is a tough sell. Local community meetings about proposed data centers have increasingly featured residents questioning whether the promised economic benefits (like jobs and tax base increases) are worth the likely rate hikes. They argue that Big Tech should pay its fair share – for example, funding the necessary power infrastructure through special agreements – rather than offloading the expense onto ordinary households.
The debate is quickly becoming a statewide issue. Oklahoma’s leaders must balance the allure of high-tech investment against the risk of burdening citizens with higher utility costs. How much should Oklahoma invest in powering data centers – and who should shoulder the cost? is the question now echoing from regulatory hearing rooms to local town halls. In some cases, concessions are being discussed, such as requiring data center operators to curtail usage during grid peaks or to invest in on-site generation. However, those measures can only go so far for facilities that require constant power. If not carefully managed, the situation could breed public resentment, framing it as everyday people subsidizing corporate data hubs. On the other hand, if Oklahoma manages to expand its grid smartly, it could become a magnet for even more digital industry, creating jobs and tax revenues that, proponents argue, will ultimately benefit everyone. For now, though, the immediate reality is that electricity bills are poised to rise, and the state is grappling with how to equitably distribute the costs of its rapid tech-driven growth.
Across these three storylines – Canada’s pipeline push, the Gulf’s oil surge, and Oklahoma’s power scramble – a common theme emerges: physical energy needs are trumping ideological goals. In each case, hard realities are forcing a shift in strategy:
In short, pragmatism is back in vogue. The lofty rhetoric of an imminent fossil-free era has been tempered by the immediate demands of geopolitics and gigawatts. Leaders are effectively saying: we cannot let idealism about the future undermine the energy security of today. This doesn’t mean climate concerns are gone – but it does mean they are being balanced more evenly against economic and security factors.
Another consequence of this new pragmatism is a potential fragmentation of what was once a highly integrated North American energy system. If Canada proceeds with an Asia-focused pipeline, it will start to loosen the tight knot that has bound Canadian oil to U.S. refiners. American Gulf Coast and Midwest refineries have long enjoyed a captive supply of discounted Canadian crude, especially heavier grades. This arrangement benefited both sides when relations were stable: Canada had a guaranteed buyer, and U.S. refiners had steady feedstock at a bargain. However, with Canada seeking alternative buyers in Asia, U.S. refiners could lose their privileged access to cheap Alberta oil. They would have to compete on the global market for heavy crude, likely raising their input costs. In the long run, this could lead to higher fuel prices in the U.S. or costly refinery adaptations to process different crudes.
The tariff-driven rift also hints at broader decoupling. Energy trade that once flowed freely under NAFTA/USMCA is now subject to strategic recalculations. Mexico, for instance, will be watching how U.S.-Canada energy dynamics change, as it too has energy links to both countries. If North America’s energy market becomes more segmented – each country ensuring its own resilience even at the expense of integration – the continent might lose some of the efficiencies it once enjoyed. There is a security argument for each nation controlling its own destiny, but there’s also a cost if cooperation diminishes. In essence, a Canada–Asia oil pipeline could be the first major crack in the concept of North American energy independence as a unified bloc.
For investors, the takeaway from late 2025’s developments is that hard assets are king once again. Projects and companies that deliver tangible solutions to physical constraints are gaining value. Whether it’s a pipeline that can reroute oil flows to higher-priced markets, an offshore platform that reliably pumps out hydrocarbons, or a power plant that keeps a data center online, the market is rewarding the builders and operators of critical infrastructure. We are entering an era of what might be called “infrastructure realism” – a recognition that modern societies still run on steel in the ground and electrons on wires, not just ideas and promises.
This doesn’t mean sustainability is off the table. It means that the path to a cleaner future will likely be gradual and built atop a foundation of energy security investments. We’re seeing a recalibration: instead of betting on distant technological breakthroughs or sweeping policy shifts, many stakeholders are doubling down on the assets that can bridge today’s needs with tomorrow’s aspirations. For example, Canada may justify its pipeline by pairing it with carbon capture in the oil sands, aiming for both economic gain and emissions mitigation. Oklahoma might use the revenue from data center growth to invest in grid improvements or renewable projects down the road. The Gulf of Mexico oil boom could bankroll companies’ diversification into low-carbon ventures.
In the here and now, though, the signal is clear. Nations and companies are securing their options: pipeline corridors, drilling rights, power plants – these provide optionality and leverage in an uncertain world. The free-flowing trade and “just-in-time” energy supply mindset of the past decades is giving way to a more hardened approach. Energy infrastructure is becoming a form of geopolitical insurance. The era of frictionless globalization in energy is ebbing, and a new era of strategic infrastructure investment has begun. Investors should adjust their strategies to this reality, focusing on ventures that can survive and thrive on the strength of their physical assets and operational resilience in a world that values security and reliability above all.
Bass Energy & Exploration is independently owned and operated by the Bass family.
Bass Energy & Exploration
7 NE 6th Street
Oklahoma City, OK 73104