What I Was Watching in February: Gas, Geopolitics, and What It Means for Oil and Gas Investors

Every month I put out the ONG Report, a short weekly brief covering the energy news I think matters most to investors watching the oil and gas space. I keep it tight on purpose. The goal is to cut through the noise and give you the signal.

But at the end of each month, I want to do something a little different. I want to pull back, look at everything we covered, and connect the dots. Individual headlines can be interesting. Patterns are where the real picture lives.

February 2026 gave us a lot to work with. Seven reports. Seven weeks of market signals. And when I lay them all out together, they tell one clear story: natural gas is no longer just an energy source. It is becoming the backbone of the American economy's next era, and the gap between what is being demanded and what can actually be delivered is widening fast.

Here is what I was watching, what it means, and why I think it matters if you are considering direct participation in domestic oil and gas.

The AI Energy Demand Story Is No Longer Hypothetical

I led off the month with a story that I think a lot of people in the investment world are still underestimating.

Texas just approved the largest gas power project in US history. Pacifico Energy's 7.65 gigawatt GW Ranch in Pecos County received its air permit, and it is not alone. During 2025, Texas added nearly 58 gigawatts of gas generation capacity to its development pipeline. To put that in perspective, that is more than the entire peak power demand of the state of California.

If fully built, the GW Ranch alone could consume up to 2 billion cubic feet of gas per day, equivalent to 7% of total daily Permian Basin production in 2025.

That is not a rounding error. That is a structural demand shift.

The driver behind all of it is AI. Data centers need power that does not blink. Wind goes calm. Solar goes dark. Natural gas runs 24 hours a day, 7 days a week. That is why, when I covered the turbine shortage story on February 5th, the numbers hit differently than I expected.

Lead times for gas turbines have stretched to five years, up from three and a half just two years ago. Costs have surged 49%. The US had over 159 gigawatts of gas power in pre-construction as of January 2026, but turbine manufacturers physically cannot keep up. GE Vernova ended 2025 with 83 gigawatts under contract. They started the year with 46. They expect to hit 100 gigawatts by the end of 2026. Delivery on most of those orders will not begin until 2027 and beyond.

Then, right here in Oklahoma, the Sand Springs City Council voted 6-1 to approve Google's 827-acre data center near Tulsa. Local opposition. Active lawsuit. Neither one stopped it. The project moved forward. That tells you something about how much demand pressure is sitting behind these builds.

By February 23rd, the story had grown further. Even dedicated renewable energy companies, including NextEra and Clearway, are now building gas-fired capacity to serve hyperscale data centers. About 75% of planned data center generation equipment is for natural gas. These are companies that built their entire identity around wind and solar. They are adding gas because there is simply no other way to deliver 24/7 power at the scale AI requires.

Supply Shock: When the Market Got a Wake-Up Call

Then Winter Storm Fern hit, and the numbers that came out of that week stopped me in my tracks.

In the week ending January 30th, natural gas storage in the Lower 48 fell by 360 billion cubic feet. That is the largest single-week storage withdrawal in the entire history of the Weekly Natural Gas Storage Report. The draw exceeded the five-year average for the same week by 89%.

Henry Hub hit $9.03 per MMBtu on January 28th, a 45% spike in seven days. Storage levels fell below the five-year average. Freeze-offs and shut-ins cut production along the Gulf Coast at the same time that residential and commercial heating demand ran 29% above the five-year average.

Every $1 increase in Henry Hub gas prices costs US consumers and manufacturers approximately $54 billion annually, split between $34 billion in direct gas costs and $20 billion in electricity bills.

I come back to that statistic often because I want investors to understand the scale of what we are dealing with. Natural gas is not a niche commodity. It runs the country. When supply tightens, whether from a weather event, from export demand, or from production disruptions, the economic consequences are enormous and immediate.

The LNG export side of this story adds another layer. US LNG exports hit a record 111 million tons in 2025. Export capacity is set to more than double by 2029, with projects like Plaquemines LNG Phase 1, Corpus Christi Stage 3, Delta LNG, and CP2 LNG all coming online. European industrial gas costs are projected to fall nearly 50% by 2030 as a result, saving European industry roughly $46 billion annually.

But here is the other side of that picture: domestic US gas prices are expected to rise nearly 50% between 2030 and 2035 as export-linked demand tightens supply. The US is becoming more of a global market participant and less of an insulated domestic one. For investors in producing assets, that long-term price trajectory matters a great deal.

Geopolitics Is Redrawing the Global Oil Map

The geopolitical moves this month were worth paying close attention to, because they affect where global crude flows, and that eventually touches everyone in this business.

On February 2nd, President Trump announced that India would begin buying Venezuelan oil instead of Iranian oil. The US lifted additional tariffs on Indian goods in response, tariffs that had been imposed specifically to pressure New Delhi away from Russian crude. By February 9th, major Indian refiners including Indian Oil, Bharat Petroleum, and Reliance Industries had already stopped signing new deals for Russian oil deliveries.

This is a meaningful realignment. Russian barrels are being pushed further toward isolation in global markets. Venezuelan oil, moving under US-facilitated terms, is filling part of that gap. And the US is using energy trade as a direct diplomatic lever in ways that are reshaping crude flows across the entire Atlantic basin.

Meanwhile, US-Iran tensions kept oil traders on edge throughout February. WTI climbed above $65 on February 5th as conflicting reports on nuclear talks and rising military rhetoric pushed geopolitical risk premiums higher. An Iranian drone was shot down near a US carrier. Oil tanker threats resurfaced in the Strait of Hormuz.

The Strait of Hormuz handles roughly 20 million barrels of oil per day, about one-fifth of global petroleum liquids consumption. It is the single most critical chokepoint in global energy trade.

By February 23rd, analysts were openly discussing $90 to $100 crude scenarios if US-Iran tensions escalated to conflict. Some experienced energy analysts believe the market may be underpricing the potential scale of retaliation, including the possibility of Iranian strikes on Gulf production facilities or an attempt to close Hormuz.

I am not in the business of predicting geopolitical outcomes. Nobody is. But I do pay attention to risk premiums, and February made clear that the risk premium on crude is returning to the market in a real way. For domestic producers in stable US jurisdictions, that backdrop is worth understanding.

The Majors Are Drilling Again. Here Is Why That Matters.

One story that did not get enough attention this month was what the super majors quietly announced about their 2026 drilling budgets.

After years of prioritizing share buybacks over capital investment, the largest oil companies in the world are rotating back toward upstream growth. One US major announced 2026 capital spending of $27 to $29 billion. Another outlined $18 to $19 billion, heavily weighted to oil and gas. A third guided $20 to $22 billion in cash capex.

That is not incremental. That is a signal. These companies have massive research departments, enormous geological databases, and the ability to allocate capital virtually anywhere on earth. When they shift back to drilling, they are telling you something about where they see value in the cycle.

For investors watching the broader energy market, rising major upstream capex means service demand increases, deal flow improves, and long-term supply discipline strengthens across the industry. It is a constructive backdrop for conventional operators who have stayed disciplined through the leaner years, and it supports the economics of the kinds of projects we run at BassEXP.

What Oklahoma's Rig Count Is Telling Us

Closer to home, the number I watch most closely every week, Oklahoma's rig count told an interesting story in February.

Oklahoma hit 46 active rigs in the Baker Hughes count released February 2nd. That is a rise of three rigs in a single week and a recent high for the state. For context, Oklahoma had 45 rigs active at the same point last year.

Nationally, the picture is more mixed. The US total stood at 546 rigs, still 36 below where we were this time last year. The decline from last year has been concentrated in oil rigs, down 68 year over year. Gas rigs, on the other hand, are up 27, and that growth is where Oklahoma is participating.

What I take from this is that conventional Oklahoma fields are holding their own. While the national rig count reflects the broader pressures of price cycles and capital discipline among larger operators, Oklahoma's steady and slightly rising activity tells me that operators working proven legacy fields with strong geological understanding are finding the economics workable. That is exactly the environment we operate in.

The fields we work, conventional stacked-pay formations in legacy Oklahoma producing areas, do not require $80 oil to make sense. They require disciplined geology, cost control, and a multi-zone approach that gives you multiple shots at commercial success in every wellbore. February's rig count data reinforces that the ground we are standing on is sound.

What I Keep Coming Back To

When I look at everything February put on the table, a few things stand out clearly.

First, the structural demand case for natural gas has never been stronger. AI data centers, LNG exports, industrial electrification, and heating demand are all pulling from the same resource. Supply is constrained by weather events, by turbine shortages that delay new power generation capacity, by geopolitical disruptions, and by a national rig count still running below last year's pace. Demand up, supply constrained. That is the fundamental setup.

Second, global crude flows are being redrawn in real time. Russia's market access is narrowing. Geopolitical risk is pricing back into crude at a meaningful level. Domestic US production in stable, proven jurisdictions carries a growing premium in that environment, for commodity pricing reasons and for investor confidence reasons alike.

Third, the super majors returning to aggressive upstream drilling is a signal worth taking seriously. These are not impulsive decisions. They reflect a view that reserves matter, that production durability matters, and that the cycle has turned constructive for disciplined operators.

And fourth, the number I keep coming back to: Oklahoma held at 46 rigs. Steady, responsible drilling in proven fields. That is what we do. That is what this environment rewards.

At BassEXP, we do not just follow the news. We put it to work.

If you are a high-income investor looking at oil and gas for the first time, or coming back to the space after a difficult experience with another operator, I would encourage you to look past the headlines and ask the deeper question: who is actually operating in the ground? What is their track record? How do they communicate with investors? Do they abandon wells early, or do they see every viable pay zone through?

Those are the questions that separate a good investment experience from a bad one in this industry. They are the questions we have built BassEXP to answer clearly.

Looking Ahead Into March

Going into March, I will be watching the US-Iran situation closely. Any disruption in the Strait of Hormuz would move crude markets fast and significantly. I will also be tracking Oklahoma's rig count to see whether February's strength holds as the market processes OPEC's production decisions and domestic price signals.

And I will keep putting out the ONG Report every week, because staying informed is the foundation of making good decisions.

If you want to go deeper on what direct participation in oil and gas looks like, including the tax structure, the economics, and how working-interest ownership actually functions, I would invite you to download our Investor Guide or reach out directly. No pressure. Just a conversation.

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