In an era dominated by the chase for more liquids in the portfolio, a recent industry discussion on the dynamics of M&A in today’s marketplace was weighted toward natural gas—and the wisdom of owning it. Despite two years of depressed gas prices and a similarly representative forward curve, panelists at M&A intelligence firm Mergermarket’s Energy M&A Forum in Houston were nonetheless focused on the near-term challenges and opportunities posed by gas.

As winter storms gripped the nation and natural gas prices barely blinked above $4 per thousand cubic feet (Mcf), Frank Verducci, director of structured products for BP Corp. North America Inc., posed the question, “Is this the death of natural gas?”

Verducci, who handles structured commodity and credit transactions with financial sponsors for BP, says the majority of deals in the past year have been on the oil side.

?“Until we have a large shift…you’re going to see depressed levels,” says Frank Verducci, BP Corp. North America Inc.

“Private-equity firms, mezzanine-debt providers and hedge funds like the space because of the crude-oil shortage,” he said. “They think the value is there in finding proved reserves that can be sold off to majors as they get larger.”

These financial players think gas may remain depressed for an extended period. “They are not concentrating their capital in gas at this time. There is some, but the majority is oil.”

However, the tide may be turning for gas assets in the M&A marketplace, said Wells Fargo Securities’ Hugh Babowal. “We have seen a fair number of financial sponsors in the last three to four months start to explore the conventional-gas side of the business,” he said.

Babowal, who heads Wells Fargo’s energy and power M&A practice, points to recent transactions, including Occidental Petroleum’s acquisition of conventional-gas assets in South Texas from Royal Dutch Shell for $1.8 billion. Given the economics of conventional gas versus unconventional gas, that package sold for a hefty premium, he said, noting there was a lot of interest. Other conventional-gas packages are currently on the market—some fairly sizeable—that too are garnering healthy interest.

And capital is abundant, particularly private equity. “People are starting to ask how long will (gas) stay depressed?”

?The tide may be turning for gas assets in the M&A marketplace, says Wells Fargo Securities’ Hugh Babowal.

Since the Mergermarket event, privately held, Houston-based Legend Natural Gas LP, backed by Riverstone/Carlyle, planted a $1-billion flag in gas assets in the Barnett shale and far South Texas, picking up assets from two sellers.

“We’re seeing enough buyer interest that it’s putting a floor on the value of those assets. We’re starting to see an uptick in valuations for conventional-gas assets,” Babowal said. “We’re at the bottom and now is the time to be looking at buying some of those assets.

“We’re at the inflection point on conventional gas.”

Betting on the arbitrage

The lure of gas assets may be the arbitrage opportunity resulting from the ongoing disconnected oil-to-gas ratio. Hovering around 20:1 now and two years into the forward curve—a far cry from the traditional 6:1 parity based on Btu content—does the spread create an opportunity for buyers?

Maynard Holt, co-president and head of E&P investment banking, Tudor, Pickering, Holt & Co., thinks so. Holt admitted, however, that it remains difficult to persuade producers of that argument.

“Companies feel confident around oil now. Even gassy companies talk about their oil and their liquids, because that’s what investors want.” And while companies could trade barrels into gas, “they more often decide that it’s safer not to.”

He harkens back to 2007, when gas prices were strong and gas was the long-favored commodity. “If a gassy wonder child had said, ‘You know, this gas thing is getting a little ahead of itself, we’re going to swap into oil,’ that would have been the same kind of difficult trade (as today with gas). But it obviously would have been a pretty good one.”

Instead, he said, more diversified and bigger companies that have the capacity to plan portfolios five to 15 years out are positioning for the arbitrage opportunity.

“Those companies are not swapping oil into gas, but they are buying gas, which just makes sense. As gas captures market share there will be a demand for it.”

?Diversified and bigger companies that have the capacity to plan portfolios five to 15 years out are positioning for the arbitrage opportunity in gas, says Maynard Holt, co-president and head of E&P investment banking, Tudor, Pickering, Holt & Co.

The main reason ratios have gone through the roof is simple, according to Verducci: producers have gotten too good at finding gas. A great deal of capital has been spent acquiring leases in recent years, and to protect that investment they continue to drill through low gas prices even though it is uneconomic.

“You may see that persist for another year or two. We are not laying rigs down in the industry. Until we have a large shift to where we export gas or manufacturing capacity comes online substantially more, you’re going to see depressed levels.”

Further, Babowal views the 6:1 ratio as outdated. The reason: almost no electrical generation in the U.S. is driven by crude-based feedstocks, as it was 30 years ago by bunker fuel oils. “That’s just gone today. We’ve seen the permanent detachment of that ratio. How long it lasts is anyone’s guess.”

Displacing coal

Though natural gas supporters anticipate the commodity making inroads to coal’s dominance for electric power generation, thus bolstering prices, Babowal suggested such hopes may be wishful thinking. “In the near or mid-term, I don’t think you’re going to see a meaningful move away from coal in the U.S.”

Massive bases of coal-fired power plants dominate in the Northeast, Midwest and Southeast, mega plants that are 1,000 to 2,000 megawatts and are very cost effective for utilities. “It’s difficult to just turn those off overnight and switch to natural gas.”

Too, utilities have a mindset of gas-price wariness. Even though all signs point to low prices for a long period of time in the U.S., utility executives look at past volatility of natural gas and ask, “Do I really want to get caught with that in front of my regulator?”

The hesitation stems from a lack of historical data for shale-play production. Utilities desire 10 to 20 years of data, instead of the three to four years of meaningful production from shale-gas plays.

“We don’t have two decades of decline-curve histories on these wells,” Babowal said. “That’s what utility CEOs think about. They want long-term proof that gas is going to be sustainable at this level for a long time, before seeing meaningful moves from coal to gas for electricity generation in the U.S.”

Instead, he said, expect to see smaller, less efficient plants shut down in the near and midterm, representing about 50 gigawatts of capacity, according to a Wells Fargo analysis. “We think that is 3- to 4 billion cubic feet (Bcf) per day of incremental natural gas demand, versus 20 Bcf per day of what’s going into the power-gen complex overall. It’s not huge, but it’s not insignificant.”

Holt predicts public sentiment in time will sway such inertia. “If you look at the tea leaves and ask yourself, ‘What’s the right fuel?’ natural gas feels like a hard fuel to bet against, both domestically and internationally.

“Somebody is going to eventually stand up and say that coal doesn’t seem like the fuel of the future. And when one person says it, 40 people will, and suddenly you will get a sea-change moment. The trend is in place.”

Outgoing LNG?

With the advent of shale-gas production, the conversation about liquefied natural gas (LNG) has been muted. A decade ago some 30 to 40 regasification facilities were planned in the U.S. to supplement a limited supply. Now industry is discussing liquefaction-export plants.

“Five years ago the thought of building energy policy around natural gas in the U.S. felt irresponsible,” said Holt. But beginning early last decade, producers plowed into natural gas and did so year after year on the premise that the commodity was in short supply. “And look what happened; we found a ton.”

That same dynamic is happening in oil now, he believes, as new technologies developed in U.S. shales are being deployed worldwide.

“I’m a little suspicious that oil is going to be $90-plus forever. People ought to be thinking about this and what happened with gas.”

Giant investments by international companies in North America shale plays are rewriting international relations, Holt suggested. “That will have a massive impact on investment and technology. You have to have that type of buy-in for the potential of natural gas export.”

Yet despite hungry gas markets in Asia and Europe, where pricing is three times that of the U.S., LNG export remains a midterm hope at best. Lenders, as confirmed by Wells Fargo’s Babowal, are not yet embracing multibillion-dollar liquefaction projects. “That’s a little tougher,” Babowal said.

Rather, gas producers must find “the thin edge of the wedge” to push natural gas as a more prevalent fuel in the U.S., he said, be it compressed natural gas used by fleet trucks such as FedEx or UPS, or long-haul trucking.

“A small step can open big doors,” he said. “We need to figure out what pushes natural gas to the forefront of the energy discussion.”

Companies with the best view of the future, such as ExxonMobil Corp., have clearly been buying onshore U.S. gas, said Holt. “That’s a company with some of the best returns in the industry, so they probably don’t buy stuff they think is going to be $4 forever. When you add this up, it’s a question of when—not if—those dominoes will fall.”

Babowal agreed. “When majors are buying, something’s up. That’s a sign it’s a great time to be buying U.S. onshore gas reserves.