Evolving economics drive the life cycle of an oil and gas play.
By Paul Wiseman
In the wild west days of the oil patch’s infancy, gritty men in jeans and overalls prowled the prairies armed with dreams, a bit of geology, and some kind of luck. The opportunities were as varied and wide as those prairies, and one’s luck generally swirled madly around in all directions at the whim of the prairie wind.
Fortunes were quickly gained and quickly lost. The black liquid riches were as uncharted as were the draws and playas of the surface. For the wildcatter, everything revolved around getting investors to believe in your plans enough to add their dreams to your own.
As much as today’s oil field has changed on the front side—overalls replaced with FR clothing, wildcatters obsoleted by seismic maps and computer models, and punchy cable tool rigs overtaken by deftly-steered horizontal drilling—the back side has stayed the same.
Follow the money.
The biggest money follows the biggest growth.
For decades the life of an oil and gas play followed a predictable pattern of phases: exploration led to development, which graduated to slowly declining production. With decades of exploration under its belt, the very mature Permian Basin no longer really invites a lot of exploration, said Cary Brown, principal of the Moriah Group, a Midland-based oil and gas-related holding company.
Brown said that, historically, an exploration company would have an idea where they might find oil. They would drill some exploratory or “wildcat” wells to test their theory and their geology. If they were right, oil was really there, the majors would come in and buy up leases for miles around those exploratory wells, expecting to develop that play into millions of barrels of produced oil.
After the majors had fully developed the field, with no more growth possible, they would sell the play to a smaller company that would simply continue to produce the existing play. The production phase was perfect for less-capitalized companies. It’s somewhat like putting money in a savings account instead of investing in the stock market. Development has greater growth upside but production has fewer risks.
Today, these acres have been prowled thoroughly by wildcatters, seismic teams, and geologists to the extent that there are few unproven reserves left, so even the development mode has fewer risks than in the old days. “The exploration phase today looks more like the development phase,” Brown said.
For example, one of today’s hottest plays is the Delaware Basin. “We knew there was oil there,” he noted, adding that the technology and the price made it economical to produce that area in the last few years.
When the capital markets felt confident that they could make a significant return in the Delaware and other basins in the Permian, the cash began to flow and the rigs began to drill. No one had to really explore anything.
While the downturn slowed things down, it also made operators more efficient, which kept the bits turning even at lower prices. The technology and the uncertain economics make the life cycle of today’s “hot” basins less clear than in previous decades.
“We don’t really know what the life cycle of the new production is going to be,” Brown said. Horizontal drilling, fracturing, and other technological advances have extended the life of plays formerly thought to be irrevocably in production mode. And the complexities of today’s capital markets no longer make it a given that production-mode properties get sold to a production-only company. So what drives buying and selling today?
Follow the money, part deux.
For almost every public company today, there has to be some avenue for growth for Wall Street to make capital available to them. Brown explains it as follows: “Wall Street values growth. So when you get to a spot where you can’t grow, you need to shrink so you can grow again. You [sell off assets] and you take that cash and put it in something you can grow again and then Wall Street rewards you again.”
This model is one of the main reasons the U.S. majors began to look overseas in the 60s and 70s. “It was the only place they could grow their assets,” he said.
Once one zone has been developed as far as is possible, there are two main options. The operator can sell the property to a production mode company and use the proceeds to buy into a newer play.
Or it can keep the property and use the ongoing cash flow to fund smaller drilling and development projects.
A subset of the second option is that the company can use the producing assets to lure investment dollars from Wall Street. “If my stock price is valued on my acreage position and Wall Street is going to value me at $60,000 an acre or $50,000 an acre, and I can go pay $30,000 an acre and then go issue equity,” Brown said. “I can buy it at 38 and sell it for 50 and everybody’s a winner. Now they’re not going to be able to sell it for 50 if there’s not a story about how you’re going to grow production. All of these things have to line up.”
While the particular economics in each case are varied and complex, what a company does with its production-mode assets boils down to this: “If I can take that money and go drill wells at a 30 percent rate of return, I’m better off to sell that, get a lump sum cash flow, and then go put that to work. Somebody else will go harvest that and get the cash flow and I’ll drill.”
The old wildcatters wouldn’t have liked the risk-reward-reducing computer models of today. They wouldn’t have liked FR clothing, either.