As Matt Badiali, geologist and editor of the Stansberry Resource Report, explains, it has only been in the last few decades  we have  learned how to release the potential of the massive oil and gas reservoirs in the U.S. Now we are learning how to tell if a shale project will be profitable. In this Energy Report article, he shares three names he is watching closely.

Geologist Matt Badiali compares a conventional oil field to a glass of iced tea. The ice cubes are the rocks, the tea is the oil and the cup is the reservoir (just imagine the whole thing upside down, so the cup is on top). The cup is a trap where oil and gas accumulate after migrating out of the source rocks.

A shale resource is not like that. It's the source of the oil. It is rock formed when much of Canada and the central U.S. was an oxygen-starved ocean bottom. These rocks are filled with carbon and if they are squeezed and heated in just the right way, the carbon becomes oil and gas.

However, the rocks don't produce oil and gas in the traditional way. You can't just drill into them and expect the well to gush, like a conventional field. In the late 1990s, George Mitchell, founder of Mitchell Energy & Development Corp., noticed something funny. When he drilled through the Barnett Shale, near Dallas, Texas, the hydrocarbon meter (oil detector) would light up as he cut through the shale layers. He envisioned shooting a water gun with grains of sand sideways into these thin layers to prop the sheets of rock open and allow the oil to escape.

He did it a few times and it worked. This was revolutionary. Everyone was talking about peak oil and predicting a shortage. George Mitchell ignored the conventional wisdom and unlocked a treasure trove of oil. Even after the geologists proved that it worked, however, the traditionalists pointed to all sorts of problems and said it would never last. They were wrong.

"The fact is that the amount of oil trapped in the source rock is enormous. In the history of the oil industry, we have only tapped a fraction of what is there," Badiali says.

"George Mitchell ignored the conventional wisdom and unlocked a treasure trove of oil."

The potential of fracking has left today's geologists searching for the most economic shale sources. He explains his research process this way: "When I'm evaluating a project, I look for rocks that are both 'porous' and 'permeable.' Porous means it has lots of space, lots of holes that can fill with oil. Permeable means those spaces are connected to one another. Shale is neither. That is why we have to artificially induce those things.

Ideally, we want the shale to be a combination of calcium carbonate (limestone) and silt, without a lot of clay. It has to be the right kind of rocks and it has to have lots of oil. We measure that as total organic carbon (TOC) by weight. A good shale holds between 1% or 2% TOC. The best shales hold over 5% TOC. Once we find that kind of rock, we drill sideways through it. Then we blow it up and make rubble to free the trapped oil and give it space to move around."

Since those early days, scientists have continued to refine the technique to increase the output and life of each well. "We have learned that using a lot more sand got a disproportionately large result. Now drillers are experimenting with larger bore holes. Remember, engineers have less than 10 years of experience getting oil out of shale. We have over 100 years of experience with conventional oil fields. This science is so new and the economics are improving rapidly," Badiali gushes.

There are limits to the new technology, however. "Almost no shale wells can profit at $45 a barrel ($45/bbl)," Badiali warns.

Offtake capacity is also important, according to Badiali. “You have to have a way to get it to market. Continental Resources Group Inc. went to North Dakota and started producing massive amounts of oil. But there were no pipes there and it is a long way from any refinery or market. Because the price of building a pipeline would be so high and the odds of getting it approved even worse, they turned to trains. The problem with trains is they are twice as expensive as pipelines. That means if you're producing oil for $60/bbl and you put it on a train for $20/bbl and sell it for $120/bbl, it's still a business. When you can only sell it for $50/bbl, it's a liability. That is a problem.

"The Eagle Ford is still my favorite basin. . .we have decades of drilling data so we know what is down there."

"The great thing about the oil industry in the United States is it is incredibly nimble," Badiali says. "When one area or commodity isn't economic anymore, they change. The problem is that the price of land in the established plays near infrastructure has skyrocketed. An acre that leased for less than $1,000 in the Eagle Ford in 2005 was $20,000 in 2011. The same thing happened in the Permian Basin and then the Tuscaloosa Marine Shale. It was a land grab and the well economics weren't a priority. Now those companies that overpaid for land are being hammered.” Badiali uses Chesapeake Energy Corp. (CHK:NYSE) as an example of a company that took on debt and had land in every shale in the U.S. "Today, they are in big trouble, just trying to pay the interest on their debt."

He points to Exxon Mobil Corp. (XOM:NYSE) as a major that took a different route. "Instead of overpaying for dirt and then learning the business through trial and error, they bought XTO Energy Inc. XTO, at that time, was the most profitable shale driller in the country. In one easy deal, Exxon acquired both excellent land positions and the best scientists in the industry."

Badiali warns that it may get worse before it gets better for producers. "I think that we're now on the cusp of bankruptcies galore because the marginal producers are struggling to make ends meet. That will benefit the ones who survive in the sweet spots because the cost of everything from the frack sand to the drillers and the pumpers has plummeted."

One of the great misunderstandings from outsiders looking into the oil industry is the role of debt, according to Badiali. "Oil isn't like mining. Drilling a well is a binary question. Either it produces oil or it doesn't. Traditionally, banks lent money based on production. The company locked in prices for oil production (called a hedge) and the bank used that future oil revenue as collateral. The problem was that everybody assumed an oil price of $100/bbl. And they were wrong. When the model is wrong by 50%, that can be a problem. When the hedges come off at the end of this year, the real trouble is going to start."

The drill count is already down dramatically. The rigs running today are running for one of two reasons, Badiali says. "They are either drilling oil wells that can make money at the current price or they have a work commitment. When companies acquire land, the deal says that if they don't do work on it, it will go back out for bid in a few years. Many of these companies spent a lot of money on that land. They can't afford to lose that acreage. In the oil industry, you either drill it or you lose it. So a lot of those wells are drilled, but not completed. Fracking is expensive. So we are in a situation where some 1,400 wells are simply waiting to be tapped as soon as the oil price gets a little higher."

When it comes to finding the survivors, Badiali looks at geography first. "The Eagle Ford is still my favorite basin because the rock quality is really high, but more importantly we have decades of drilling data so we know what is down there. Devon Energy Corp. (DVN:NYSE), EOG Resources Inc. (EOG:NYSE) and Pioneer Natural Resources Co. (PXD:NYSE) are doing a great job on the science right now. But I'm not buying them. Even the big players could feel some pain in the coming year and they are very bought up," he says. That is why, for now, he is watching and waiting.