Bass Energy & Exploration is independently owned and operated by the Bass family.
Bass Energy & Exploration
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Oklahoma City, OK 73104
Artificial intelligence infrastructure demand and U.S. foreign energy policy are reshaping global oil and power markets in tandem. On one side, Washington has facilitated the first sanctioned sale of Venezuelan crude in years, a landmark $500 million deal that signals a new approach to managing Venezuela’s oil riches. On the other side, surging electricity needs from data centers and AI computing are driving the strongest U.S. power demand growth in a quarter century, forcing grid planners and developers to adapt. These two narratives – unlocking sanctioned oil supplies and a digital-driven power boom – are two sides of a global energy reallocation. In the following sections, we examine how the U.S. monetization of Venezuelan oil is unfolding (and what it means for oil diplomacy and PDVSA’s role), how AI-driven demand is straining power systems in the U.S. and UK, why developers are increasingly bringing their own generation to projects, and what these shifts mean for the energy market outlook.
The U.S. has completed its first sale of Venezuelan crude oil, netting about $500 million as part of a new $2 billion export deal with Caracas. This inaugural tranche was enabled by a breakthrough agreement in early January under which Venezuela will “turn over” 30–50 million barrels of oil to the U.S. for marketing. No details have been disclosed on the exact volumes sold or buyers, but President Trump’s administration authorized global traders Trafigura and Vitol to market the cargoes as a way to bypass Venezuela’s state oil company, PDVSA. The oil – mainly Merey heavy crude – had been stuck in floating and onshore storage due to a U.S. export blockade imposed in mid-December amid escalating pressure on the Maduro regime. By taking custody of these barrels and redirecting them (reportedly from Asian-bound routes to U.S. refiners), Washington aims to avert further production shut-ins in Venezuela while depriving the Maduro government of direct control over the revenue.
A court-approved trusteeship structure is underpinning the sales to keep proceeds out of contested hands. According to U.S. officials, all revenues from the oil are being held in accounts controlled by the U.S. Treasury – including a main account in Qatar – rather than funneled to PDVSA. An executive order signed by President Trump has explicitly shielded these funds from any creditor claims or seizure attempts in U.S. courts. This legal arrangement effectively creates a financial trust for Venezuela’s oil wealth, to be managed under U.S. oversight until a legitimate government can be established. “President Trump brokered a historic energy deal with Venezuela… that will benefit the American and Venezuelan people,” a White House spokesperson said, underscoring that Washington will “oversee the sale of the oil” and ensure proceeds are safeguarded. The interim president recognized by the U.S., Delcy Rodríguez, has been in direct contact with Trump and welcomed the cooperation “within a framework of mutual respect”. (Rodríguez, formerly a vice-president under Maduro, was sworn in as acting president on January 5 after U.S. forces captured Nicolás Maduro in an unprecedented raid.)
Trump’s oil diplomacy marks a dramatic intervention in Venezuela’s energy sector, blending hard power and deal-making. In the span of two weeks, the U.S. has moved from strict sanctions to orchestrating exports of Venezuelan crude. The President has declared that “this oil will be sold at market price, and that money will be controlled by me, as President… to ensure it is used to benefit the people of Venezuela and the United States”. U.S. Energy Secretary Chris Wright is leading execution of the plan, which initially involves unloading oil from Venezuelan tankers and sending it directly to U.S. Gulf Coast refineries. The strategic intent is twofold: redirect Venezuelan supply away from China (its main buyer in recent years) toward American buyers, and leverage Venezuela’s vast reserves (303 billion barrels, the world’s largest) for mutual gain under U.S. stewardship. Washington has tied this energy détente to political aims – notably a transition in Caracas. Trump has bluntly stated he needs “total access to the oil and other things in their country” during the transition, and has urged U.S. companies to invest $100 billion to rebuild Venezuela’s gutted oil infrastructure. This muscular approach – including the capture of a head of state – is virtually without modern precedent, and it has rattled other stakeholders like China (a key Venezuelan creditor and oil customer).
Major oil companies are intrigued but wary – epitomizing Exxon’s hesitancy. At a recent White House meeting, the CEO of ExxonMobil cautiously told President Trump that Venezuela would need to overhaul its laws and enforce contract protections before Exxon would consider re-entry. Exxon and ConocoPhillips were expropriated in the 2000s and are still owed over $13 billion from arbitration awards. Their guarded stance prompted an irritated response from Trump, who remarked he “didn’t like Exxon’s response” and floated the idea of barring Exxon from Venezuela’s reopening if it won’t commit enthusiastically. Industry experts note that Chevron – currently the only U.S. major still operating in Venezuela – has a leg up, as it can incrementally invest in existing projects to boost output. By contrast, Exxon and others face a long road to rebuild trust and infrastructure in-country. The legal and operational challenges remain sobering: U.S. oil executives say security guarantees, contract sanctity, and resolution of past debts are prerequisites for any large investment. As one analyst put it, “Exxon isn’t going to break a sweat if they’re not first in line… big projects take years, and Trump’s comments won’t dictate long-term plans”. In short, the door to Venezuela’s oil patch is open, but cautious corporate partners will insist on stable ground rules before rushing in.
By design, the new sales bypass PDVSA and could render the state oil company increasingly peripheral. PDVSA’s role has effectively been reduced to pumping the oil that others will market. Sanctions have locked PDVSA out of the global financial system – its bank accounts are frozen and dollar transactions barred – necessitating this trustee arrangement. U.S. officials have discussed auctioning Venezuelan crude directly to U.S. buyers or issuing licenses to joint-venture partners to handle exports, thereby routing oil flows around PDVSA’s central sales unit. Indeed, since late 2025, Chevron has essentially controlled all Venezuelan oil exports to the U.S., averaging 100–150 kbpd under a sanctions waiver. Now, with third-party traders authorized and potentially more companies to follow, PDVSA’s traditional marketing arm is being sidestepped. The Trump administration has even signaled plans to sell not only the ~50 million barrels in storage but “all of [Venezuela’s] future production” through U.S.-approved channels. Such a sweeping move would effectively strip PDVSA of its autonomy in exporting its crude, at least for the time being. The upside is potential investment: U.S. officials claim “ongoing discussions with oil companies ready to make unprecedented investments to restore Venezuela’s oil infrastructure”. If those materialize, Venezuela’s output could grow with outside capital – but under mechanisms where revenues flow to escrow accounts rather than the Maduro-aligned establishment. The coming weeks will test how much oil can realistically be monetized this way. Additional cargo sales are expected in days and weeks ahead, and U.S. oil executives are reportedly heading to Washington to coordinate on reviving Venezuelan production. For investors and traders, a key question is how quickly this policy translates into tangible extra barrels on the market – and whether legal challenges or political shifts could disrupt the experiment. For now, the market is tentatively pricing in higher Venezuelan supply, as seen by a dip in oil prices after Trump’s announcement (Brent fell ~1.5% on the news). Venezuela’s long-isolated oil sector is being re-integrated, albeit via a U.S.-controlled detour.
America is on track for its fastest four-year electricity demand growth since 2000, with data centers and AI computing driving the surge. The U.S. Energy Information Administration’s latest outlook (January 2026) projects that power demand will rise in 2026 and 2027 by 1% and 3%, respectively – marking the first time since 2007 of four consecutive annual increases, and the strongest growth run in over two decades. This is a striking departure from the slow or stagnant electricity usage trend of the 2010s. **The primary catalyst is the proliferation of large-scale computing facilities – from cloud data centers to AI “factory” clusters – which are imposing a new kind of load growth on the grid. In essence, we are witnessing the first major “digital-to-physical” demand shock: surging digital activity (AI model training, cloud services, streaming) translating into very physical needs for power, land, and cooling. The EIA explicitly cites “increasing demand from large computing facilities, including data centers” as the core driver behind the upward revision in U.S. electricity sales. This signals to utilities and investors that the AI revolution, often thought of in virtual terms, has concrete infrastructure implications – namely, a historic bump in energy consumption.
By the numbers, the growth is concentrated in the commercial sector and in key tech-heavy regions. EIA expects U.S. commercial sector electricity sales to jump 2.4% in 2026 and 4.3% in 2027 (after already rising 2.4% in 2025). These rates are extraordinary for a sector that had been relatively flat for years. The agency attributes this largely to power-hungry data centers expanding across the country【15†L179-L187}. The geography of demand is telling: about half of the commercial growth in 2026–27 comes from the West South Central region (chiefly Texas) – an increase of 10 billion kWh in 2026 and 33 billion in 2027 in that region alone【15†L199-L207】. Texas’s mix of cheap land, available gas-fired power, and friendly regulations has made it a magnet for new server farms and AI computing hubs. Other hot spots include the South Atlantic (e.g. Virginia and Georgia) and East North Central (e.g. Ohio) regions, which together account for much of the remaining growth. Notably, northern Virginia’s data center corridor (Ashburn and beyond) – already the world’s densest cluster of servers – continues to expand, joined by emerging AI cloud campuses in places like Georgia and Ohio, where tech firms are investing heavily. EIA points out that Virginia, Georgia, and Ohio are standouts for data center-driven load growth in their regions. In short, the map of U.S. power demand growth is increasingly the map of major data center deployments.
Traditional industry is also adding to demand, but at a slower clip, and often linked indirectly to the tech boom. After decades of flat consumption, industrial sector electricity use is forecast to rise ~1.6% in 2026 and 3.4% in 2027 (following ~1.7% growth in 2025). A significant portion of this is in the West South Central (WSC) region, which could contribute 40%–70% of the nationwide industrial sales increase in those years. What’s driving that? EIA notes rising power use for oil & gas extraction, petroleum refining, and LNG export facilities in Texas and Louisiana. In effect, the ongoing shale and LNG expansion in the Gulf Coast is itself a big electricity consumer (pumping, liquefaction, etc.). There’s a broader narrative here: cheap natural gas and the push for U.S. energy exports (like LNG) are stimulating industrial electricity usage, even as digital economy growth fuels commercial usage. Both trends rely on abundant power. In fact, EIA’s Administrator Tristan Abbey highlighted that robust natural gas production (expected to hit 109 Bcf/d in 2026) is “critical” to meeting both rising LNG exports and the power needs of data centers through 2027. Gas-fired generation will carry much of the burden of this new demand wave, given its flexibility and availability. Abbey’s comments underscore that the fates of the tech sector and the energy sector are interlinked: record gas output is enabling AI’s rise by keeping electricity reliable and affordable, while AI-driven demand is in turn providing a new market for gas and power producers.
The bottom line: U.S. power consumption growth is accelerating to levels not seen since the internet boom of the late 1990s, but the composition of demand is very 2020s – data centers, cloud computing, and industrial energy for hydrocarbons and exports. For investors in utilities and generation, this is a bullish signal for demand (after years of anemic growth), but it also raises questions. Are grid infrastructure and generation capacity keeping pace? Can renewable build-outs catch up with this load, or will gas plants see extended life to ensure reliability? Thus far, the data center boom has been a boon for regions that can accommodate it (plentiful power, supportive policy) and a constraint for those that cannot. It’s no coincidence that power-short markets like California and New York have seen slower data center expansion, while Virginia and Texas flourish. This divergence may widen as companies seek out “energy-rich” locations. Moreover, with the AI arms race heating up, some analysts warn that today’s high-density computing labs can require up to 10× the power of traditional data centers, altering how new projects are designed. In sum, the U.S. grid is entering uncharted territory where digital demand growth becomes a macro driver – an important trend for energy investors to monitor alongside the usual economic and weather-related factors.
The UK is experiencing a data center land rush, with new site applications up 63% in 2025 as investors chase the AI infrastructure boom. According to an analysis by City A.M., over 60 new data center planning applications were filed in England and Wales during 2025 – an all-time high, and a sharp increase from the previous year. (This count even excluded extensions of existing facilities, so the true scope of planned capacity is larger.) The flurry of proposals lays bare the surging demand for server space and compute power in the wake of generative AI’s takeoff. Large Language Models and other AI workloads require enormous computing resources, which in turn demand significant power and real estate. Property developers traditionally outside the tech sphere are rushing to reposition as data center players to capitalize on sky-high valuations for “powered land”. “Everyone’s trying to get a piece of the pie, and that creates a bunch of fizziness,” observes Dame Dawn Childs, CEO of Pure Data Centres. She describes an almost gold-rush mentality: unknown players hawking plots “in the middle of nowhere” advertised as future “AI gigafactories” for eye-watering prices. This speculative fervor – the “AI bubble” in infrastructure – has driven up land values and spawned some questionable projects, hence the “fizzy” (frothy) characterization. The lion’s share of demand is coming from the big cloud and tech firms (the “Magnificent 7”) rolling out AI capacity, Childs notes, but even absent AI, broader cloud adoption in Britain would have elevated data center growth anyway. In other words, AI is pouring fuel on an already strong fire.
Developers are getting creative with locations as traditional sites saturate. Roughly half of 2025’s data center applications were in Greater London and the South East – the UK’s established hub for server farms – but activity is spreading geographically. Notably, seven projects were filed in Wales, seven in the East Midlands, four in the North West, and four in Yorkshire over the year. This indicates that regions beyond the M25 corridor are now on the map for digital infrastructure, possibly due to cheaper land or newly available grid connections. Furthermore, non-traditional sites are being targeted in the scramble to secure planning approval. Examples include: an abandoned Mercure hotel in Watford earmarked for conversion to a data center; the historic Truman Brewery in East London’s Hackney slated to become a server facility; a shuttered coal mine in Nottinghamshire proposed for revival as a data center; and a former landfill in Chesterfield pitched as an “AI content” hub. These unconventional site choices underscore two things: suitable land with sufficient power is scarce, and local councils are more receptive to redeveloping derelict properties. Technological advances in networking also allow data centers to be a bit further afield from core fiber routes than before (hyperscalers have widened the radius within which a satellite data center can connect back to a main region). Still, proximity to power and end-users remains key, so even these novel sites are generally within reach of major metros or grid infrastructure.
However, the UK’s ambitious data center plans face a hard constraint: the electric grid. Industry insiders warn that power availability and grid constraints will likely limit how many of these approved projects can actually be built. Getting planning permission is just one hurdle; securing megawatts of supply from regional network operators has become the taller barrier. London famously hit a capacity crunch where new data center connections in some areas were paused due to grid strain. Even outside London, delays are common. For instance, Google’s first UK-owned mega data center (in Broxbourne) encountered serious infrastructure hurdles: the initial planning app in 2018 drew a warning from the water utility that local supply couldn’t meet the cooling needs, and a utilities report found the local power network was inadequate, requiring a new 6 km cable run (including drilling under the M25 motorway) to hook into a distant substation. These kinds of costly, time-consuming grid upgrades can make projects infeasible or slow them by years. It’s a scenario playing out repeatedly: dozens of proposed data centers chasing a finite pool of available grid capacity. Some of the 2025 proposals will inevitably fall by the wayside unless creative solutions are found.
One solution gaining traction is “bring your own power.” The constraints are spurring developers to consider on-site or privately supplied energy sources to power data centers, rather than relying solely on the public grid. This could involve partnering with energy companies to build dedicated generation (like gas turbines or large fuel cells) or tapping into nearby renewable projects via private wire. Childs notes that as a result of grid bottlenecks, the BYOP model is “being seen more and more,” with data center firms directly funding power infrastructure to meet their needs. In the UK and Europe, that might mean a data center campus comes with its own gas gensets or solar farm plus batteries. The government’s designation of “AI Growth Zones” – areas promoted for AI infrastructure investment – may help by focusing grid upgrades in certain locations, but that program is nascent (200+ zone proposals have been submitted by local authorities). In the interim, many projects must either scale down, delay, or bring power with them. For investors, the UK story is a microcosm of a global trend: tremendous demand for digital infrastructure colliding with slow-moving physical infrastructure. It creates opportunity (for those who can build or supply power to new sites) and risk (projects stranded by lack of electricity). The frothiness (“fizziness”) in valuations for powered sites suggests some investors anticipate future winners and losers depending on who can solve the power puzzle. Those backing data centers in power-constrained areas must either budget for expensive grid upgrades or pivot to self-generation solutions – themes we explore next.
Widespread grid constraints are giving rise to “bring your own power” strategies, where data center developers pair on-site generation with compute demand – a trend that heavily favors natural gas over waiting for new transmission. In both the U.S. and UK (and other hot markets like Dublin), big new loads are finding that the traditional model – simply plugging into the existing grid – is too slow or uncertain. Average lead times for grid connections now exceed four years in top data center markets, and some regions are essentially saying no to new load unless it’s self-supplied. As a result, tech firms and colo providers are increasingly funding their own power plants to guarantee energy availability. In Ireland’s Dublin area, for example, authorities have imposed de facto requirements that new data centers secure dedicated power sources due to local grid limitations. In Texas (especially in fast-growing corridors around Dallas and Austin), a similar BYOP mentality has taken hold – ironically in a state known for energy abundance, the speed of large AI project deployments is still outpacing transmission build-out. The data center industry’s 2026 outlook by JLL observes that several markets have implemented “‘bring your own power’ mandates” in practice. This is a fundamental shift: the responsibility (and opportunity) for power generation is moving from utilities to the data center operators and their partners.
Natural gas is emerging as the workhorse solution for BYOP, at least in the near term, given its scalability and dispatchability. The JLL report explicitly projects that gas-fired generation will play a “major role” in alleviating U.S. grid constraints – both as a bridge and for permanent on-site power at data centers. We are already seeing this happen. Many of the new huge “AI compute” campuses are designing in on-site gas turbines or engines from day one. For instance, in West Texas and North Dakota, several hyperscale data centers have integrated gas generator farms – often tapping local gas supplies or even flare gas – to power AI workloads without waiting for grid upgrades. One headline project is in Alberta, Canada: an 8 GW (!) data center cluster announced in 2024 plans to run entirely on dedicated natural gas generation, with the first 1.5 GW phase due by 2027. Similarly, in Utah, a 4 GW data center campus under development will center around a fleet of Caterpillar gas gensets (2.5 MW each) and large battery storage, essentially creating a private gas-fired power plant for the servers. The appeal of gas gen is multifaceted: it offers speed to power (modular gas engines can be installed much faster than building new utility-scale plants or lines), high reliability for mission-critical loads, and relatively lower emissions than diesel backup. Suppliers of gas generator units report booming business – one manufacturer noted a massive ramp-up in production as data center orders pour in. In effect, a portion of what would have been central utility investment is shifting to these private micro-grids, with gas as the backbone fuel. Even tech giants known for green energy commitments are recognizing the need for gas: Google, for example, inked a deal to develop a dedicated gas-fired plant (with carbon capture) for its data centers in Ohio, acknowledging that 24/7 reliability can’t yet be met purely with renewables and batteries in all cases.
Bringing your own power is not limited to fossil fuels – but practical limitations make gas king for now. Some data center operators are exploring fuel cells (often running on natural gas or hydrogen blends) and greater use of on-site solar plus storage. In Europe, a few projects are tying directly into offshore wind farms via private wires, and operators can claim up to 40% power cost savings by bypassing the public grid tariffs. Battery energy storage systems (BESS) are also on the rise as a complement: they help data centers ride through short outages or even provide grid services to speed up interconnections. Long term, there is even talk of small modular nuclear reactors as a future option to provide carbon-free, high-uptime power for data centers – though nothing like that will be deployed at scale before the 2030s. In the immediate term, natural gas offers the best combination of scalability, cost, and readiness to meet AI’s voracious power appetite. It’s telling that in the U.S., data center energy strategies are pivoting to include gas not just as backup, but as primary power: a notable cultural shift for an industry that, until recently, preferred to buy from the grid and match consumption with off-site renewables. Now, with grid bottlenecks, speed-to-power is the top site selection criterion, even above location or tax factors. This was unheard of a few years ago. For investors in energy, this translates to new demand for distributed generation assets and natural gas fuel sales, while potentially reducing demand growth for traditional utility-delivered power in certain regions. Midstream gas companies and equipment makers could be surprise beneficiaries of the AI boom (e.g. supplying gas hookups or micro LNG to data center sites). Indeed, midstream analysts have flagged the “AI data center boom” as a bullish demand factor for natural gas pipelines and generation equipment.
As an example of how far operators will go, consider an iconic power asset being repurposed: Microsoft has plans to reopen the long-mothballed Three Mile Island nuclear plant in Pennsylvania specifically to power new AI data centers. This development – a tech company breathing life into a shut nuclear facility – underscores the lengths being taken to secure reliable electricity for computing. While nuclear is a special case, it demonstrates that the energy sourcing for data centers is now a strategic battleground. The “bring your own power” era means data center developers must essentially become energy developers too, or partner closely with them. Investor takeaway: expect capital expenditures for major computing projects to increasingly include generation and grid infrastructure alongside servers. Companies that can deliver turnkey power solutions (especially gas-fired) stand to gain. Conversely, utilities facing this bypass could see lower long-term load growth from large customers unless they innovate on delivery speed. Policy-wise, it raises interesting questions: Will regulators adapt to encourage faster grid connections, or will private microgrids proliferate, potentially fragmenting the power system? For now, BYOP is a pragmatic response to an urgent need – and it is bridging the gap with natural gas, even as renewables and storage scale up in the background.
Oil prices are forecast to soften significantly in the next two years despite rampant geopolitical volatility – a disconnect driven by oversupply and resilient production. The U.S. EIA’s latest Short-Term Energy Outlook (STEO) anticipates Brent crude will average around $69 per barrel in 2025, then fall to just $55 in 2026. That implies a 19% price drop and a return to price levels not seen since the pandemic aftermath. The bearish outlook stems from expectations of global supply growth outpacing demand growth, leading to inventory builds. In fact, both OPEC and non-OPEC producers ramped output through 2024–25: one analysis noted OPEC supply rose ~1.6 mb/d and non-OPEC by ~2.4 mb/d between Q4 2024 and Q4 2025. They enter 2026 pumping at high levels, just as demand growth is cooling (2025 demand growth was ~0.9 mb/d, below the historical norm of 1.2 mb/d). This combination sets the stage for a potential surplus of up to 3 mb/d in the first half of 2026, according to Morgan Stanley. EIA accordingly sees continued stock builds putting downward pressure on prices. In short, the fundamental picture suggests an oil market moving from tightness to glut, even as news headlines teem with conflict and upheaval.
This apparent divergence – “geopolitical chaos vs. supply-driven pricing” – is top of mind for investors. Consider the events of recent months: war scares in the Middle East, Russia’s export maneuvers, and the U.S.’s own intervention in Venezuela (literally capturing a president and seizing oil flows). Ordinarily, such events might inject a hefty risk premium into oil. Yet the market’s reaction has been muted because physical supply is ample. After Trump announced the Venezuela oil deal, instead of spiking, Brent actually ticked down on anticipation of more barrels hitting the Gulf Coast. Similarly, worries about conflict-driven outages (Iran, etc.) are being offset by robust U.S. production and higher output from places like Guyana and Brazil. The EIA expects U.S. crude production to hold near record highs (~13.6 mb/d in 2025–26), and other non-OPEC gains to continue. Even sanctioned producers are adding volume: Iran’s exports rose in late 2024, and now Venezuela could add significant exports under U.S. stewardship. On the demand side, a potential economic slowdown and efficiency gains are capping growth. All of this creates a bearish tilt. One energy desk summarized: “As the evolving global oil surplus becomes more transparent, the stage for a renewed downturn will be set”. It’s a reminder that supply-demand fundamentals ultimately dominate sustained price direction, even if political events cause short-term gyrations.
That said, volatility hasn’t vanished – it’s just more two-sided. Analysts caution that geopolitical risks could yet “inject volatility and slow the price slide”. A prime example: Russia’s oil sanctions. If enforcement tightens or Moscow retaliates (for instance by cutting output), the supply picture could shift. The uncertainty around Venezuela’s ramp-up is also notable – while the U.S. deal suggests more exports, the country’s production base is dilapidated, and any misstep in the delicate U.S.-Venezuela arrangement could swing sentiment. Weather and unforeseen outages (hurricanes affecting U.S. Gulf production, for instance) are wildcards too. Macquarie’s commodity team, which largely agrees on an oversupply outlook, nonetheless forecasts a slightly higher price than EIA ($57 WTI in 2026 vs $51) because they see OPEC+ responding. By late 2026, if inventories truly balloon and Brent sinks into the $50s, most analysts expect OPEC+ would intervene with production cuts to shore up the market. In other words, the floor under prices may eventually firm if Saudi Arabia and allies reduce output to prevent a freefall. This dynamic suggests a trading range environment: ample supply putting a cap on rallies, but coordinated producer action (or disruption) putting a floor on severe declines. For investors, it means bracing for moderate prices with periodic volatility around events.
Meanwhile, natural gas looks to follow a different trajectory, with prices rising moderately on structural demand growth. EIA’s STEO sees U.S. Henry Hub natgas averaging ~$4.00 per MMBtu in 2026, up from ~$3.50 in 2025 and just $2.20 in 2024. That’s a sizable rebound, driven by factors like expanding LNG exports (U.S. LNG export volumes are set to hit 16 Bcf/d in 2026, up from 12 Bcf in 2024) and increased domestic heating and power use. Even with robust U.S. gas production, winter demand and new export facilities are tightening the gas balance. Macquarie concurs that gas prices are on an upswing, though they think U.S. output could surprise to the upside and keep prices from spiking too high. Still, the contrast is clear: oil is expected to cheapen over the next 1–2 years, while gas is forecast to become dearer. This feeds into the earlier discussion – data center growth and “bring your own power” trends imply more gas consumption, potentially reinforcing gas market strength.
Preston Bass is the founder of Bass Energy Exploration (BassEXP) and an experienced operator in the private oil and gas sector. He helps accredited investors evaluate working-interest energy projects with a focus on disciplined execution, cost control, and transparent reporting. Preston also hosts the ONG Report (Oil & Natural Gas Report), where he breaks down complex oil and gas investing topics—including tax considerations and deal structure—into clear, practical insights.
Read Full BioBass Energy & Exploration is independently owned and operated by the Bass family.
Bass Energy & Exploration
7 NE 6th Street
Oklahoma City, OK 73104