M&A activity went on a hiatus in first-half 2013, with overall deal value dropping by more than half by one count when compared with the year-ago period. Players devoted the break to digesting acreage and acquisitions accumulated over the past couple of years. But the lull won’t last. Trading—both asset and corporate deals—is expected to rebound through the fall.

Doug Reynolds, head of U.S. business for Scotia Waterous, says buyers continue to favor the core areas of the Eagle Ford, Permian, Gulf of Mexico and Bakken, where annual production has grown significantly in recent years. “You’re either playing in the core oil basins in the U.S. or you’re being left behind,” he says.

Skilled people and management teams are in short supply and command a premium in deals. “With the organic growth in the industry, there are some huge successes out there,” Reynolds says. “As with any technology revolution, we have also seen many traditional leaders left behind. There are large companies that have not participated and need to restructure, and the winners will always look to extend their streak.”

This year, Reynolds has seen plentiful capital funneled into drilling new plays, which in turn has drained some investment dollars away from M&A. Many operators are focusing on organic drilling and boosting production volumes, without an appetite for acquisitions. As production ramps up, there is a renewed interest in quality acreage.

“The industry has realized that not all 12 million acres of the Eagle Ford, for example, are top quality,” he says. “Folks want to be in the core. People want to buy in the equivalent of River Oaks and Beverly Hills. Sellers of Tier 2 and 3 acreage have had a rough time coming to terms with the price implications of this flight to quality.”

The market is focused on estimated ultimate recoveries (EURs) and the margins available in oil and liquids-rich plays. “Those barrels are hugely attractive,” he says.

What could drive a resurgence in deals? With rising production, many companies will have stronger cash flows, providing capital for M&A activity in areas that are not considered top quality.

M&A drivers

Operators placed a big bet on a rebound in natural gas prices but lost a lot of money when that rebound did not occur. Many took reserve writedowns and repositioned to oil, and those barrels are now coming online. Production in the Eagle Ford, for example, has surged to more than 600,000 barrels per day from near zero three years ago. “At $100 plus per barrel, that’s a ton of cash flow,” Reynolds says.

Drilling times for rigs are down significantly, leading to greater efficiencies in the Bakken, Eagle Ford and the Permian and making less-attractive properties look more alluring. “The Tier 2 and Tier 3 look a lot better as technology improves and the core is developed,” Reynolds says.

One area where more activity is expected is natural gas. In 2012, gas prices collapsed and expected liquefied natural gas (LNG) export approvals were delayed. Today, prices have stabilized, non-Free Trade Agreement approvals are starting to flow, and there is a steady stream of announced petrochemical and other gas-fed projects.

“We expect gas demand in the U.S. to double in the next three to five years, and this will be met largely with already identified resources. This should provide price stability as well as a constructive deal environment,” Reynolds says.

U.S. majors and larger independents are looking at U.S. basins with renewed interest. The bigger U.S. oil basins onshore and in the Gulf of Mexico currently offer some of the best returns in the world. Foreign buyers are keeping a close eye on the U.S. shales, either to apply the technology to their own unconventional resources or to lock in reserves for domestic consumption.

That said, many potential foreign players have become more sophisticated and thoughtful about how they plan to invest. The influx of foreign partners has led to some successful partnerships as well as some less successful arrangements.

The low cost of capital, meanwhile, enables potential buyers to be more aggressive toward cash-flow-producing properties. Interest rates have begun creeping up, but even with recent increases, the cost of capital remains near record lows. “There are some extremely good bids available today for properties that produce cash flow,” Reynolds says.

The fascination with unconventional properties, primarily shales, has not faded. Several years ago, while there was a lot of interest in shales, there was also a lot of skepticism about the ultimate return on those assets. Today, the assets have proven their potential. “We have a much better idea now about the ultimate recovery on these plays and the variations in performance across basins. That allows acquisition decisions to be more informed,” Reynolds says.

In fact, the results in many of these plays in or near core areas have generally exceeded expectations. “I would think that, quite frankly, that will encourage M&A activity,” he says.

Scotia is in touch with mainstream oil and gas companies that remain interested in acquiring additional unconventional resources. “These are household-name companies that have good inventory positions, but they have to think down the road and wonder where their next big play or growth driver is,” he says. With the current surplus of supply in the A&D market, acquisition prices are more attractive than in recent memory.

While there remain compelling opportunities for multinationals internationally, U.S. resources are exerting a strong pull. Marathon Oil, for example, announced recently it would sell assets in Angola. Hess Corp. has sold assets in the North Sea. Anadarko Petroleum and Newfield Exploration have also stated they will sell assets outside the U.S.

“It seems to be a consistent trend of multinationals looking at investment on a global basis and increasing their focus on U.S. basins, for the first time in 30 years. This is an historic time in the U.S. upstream industry,” Reynolds says.

Bruce Cox, managing director and head of A&D at Credit Suisse in Houston, says that while deal flow fell materially in first-quarter 2013, the drop in deal value was perhaps lower than expected. Also, the decline was a relic of the large number of transactions accelerated into the end of 2012 by fiscal cliff issues.

Cox says for deals worth more than $25 million, the number of transactions during first-half 2013 is actually slightly higher than the year-ago period, but the overall deal value and average deal size is generally lower. In the second quarter, total deal value leveled out and was on track with historical averages, but again, with lower average deal size.

“The number of deals below $100 million actually increased and principally compensated for the loss of the larger deals in the first half of the year,” he says. Some perceived deal quality to be less strong than in the year-ago period; also, seller expectations and buyer perceptions of value were not as in sync.

Independent public E&Ps, meanwhile, are “becoming much more cautious and selective when looking at adding acreage and incremental opportunity sets, because they are so long on inventory,” Cox says.

Some asset deals brought to market have been pulled for further de-risking through development drilling, or delayed. Cox expects buyer attention to remain focused on oil and liquids-producing properties. “With general agreement as to the long-term oil price outlook and the overall higher margins associated with opportunities, it’s not surprising that oil and liquids are greatly preferred,” he says.

The market still lacks consensus as to when natural gas prices will turn upward, and this will continue to hamper activity. Gas-weighted deals will probably be smaller and more nonoperated, with seller value expectations not as high. However, the first half demonstrated that larger opportunities will command a premium and be available sporadically as companies reposition.

Cox concurs that buyers will continue to seek unconventional resources, whether shale or tight formations. “Buyers are looking and testing anywhere you can apply the ongoing advances in horizontal drilling or fracture-stimulation technologies and methods,” he says. The Permian Basin is currently being re-rated as a result of these advances and its abundant multiple horizon and sub-horizon opportunity set, he adds.

The Credit Suisse A&D specialist says corporate activity will likely pick up in the latter half of the year as companies reassess their positions closer to year-end. Shareholder activists or even the threat of activism have forced companies to be more inclined to pull the trigger on repositioning efforts and associated divestitures. Assets up for sale in the Gulf of Mexico, Texas Panhandle, Anadarko Basin and across some of the major unconventional plays reflect a trend that will continue.

While additional E&P corporate deals are likely, Cox sees two near-term parallel trends unfolding. First, takeover premiums can be more difficult to justify with many targets viewed favorably in the public markets and trading at healthy metrics. In addition, acquisition targets are reluctant to take too high a payment in the form of stock that could turn down or at best delay an agreement.

“They seek more near-term value certainty, which translates into asking for higher proportions of cash,” he says of acquisition targets. Meanwhile, many potential buyers might be leveraged and have their available cash tied up in long-term drilling and growth programs.

Many analysts believe the majors will play a larger role in the ongoing development of unconventional resource plays. Corporations seek a transaction similar in scale to the ExxonMobil/XTO deal, or as a bridge into a pure play, like the Statoil/Brigham Exploration agreement. While the smaller-cap independents have been active in first-half 2013 deals, the expectation is that the majors will ultimately enter the market looking for significant reserve replacement and growth options.

A market in transition

Lance Dardis, managing director of oil and gas acquisition and divestitures at Evercore Partners, Houston, says the A&D market is in transition. In the past couple of years, buyers have rushed into shale formations with a relatively low component of producing reserves. This year, as the market matures, there is less desire to grab undeveloped land in hopes of a quick flip. And, there is a shift on the demand side of the equation away from large-scale acreage transactions. “People are looking for further developed assets rather than raw acreage,” he says.

Another recent trend is the increasing number and appetite of master limited partnerships (MLPs) and other yield-oriented buyers. These buyers tend to seek assets that have a higher yield and a higher percentage of producing re- serves. Also in the mix are private-equity-backed companies, which have historically represented a buyer group with a relatively short investment horizon. They haven’t typically competed with yield buyers for the same assets, but they, too, are shifting their acquisition efforts toward more developed assets and, in some cases, setting up their own yield vehicles to compete with the MLPs.

A case in point is Atlas Resource Partners’ recent agreement to buy 446 billion cubic feet (Bcf) of proven natural gas reserves from EP Energy E&P Co. LP. The deal is expected to close in the third quarter. Evercore advised on the transaction, along with the sale of EP Energy’s ArkLaTex assets.

The key factor for the MLP is yield, not commodity or upside potential. “The competition for MLP type assets is stronger than it’s ever been,” he says. “This trend will likely continue as they need to make accretive acquisitions to perpetuate their model.”

What Dardis expects to change is the number of assets available for sale. A renewed interest in assets with a high percentage of producing reserves will likely bring more of those types of assets to the market.

Most agree the rush for raw shale acreage is over. “The universe of buyers for early stage assets is a lot smaller than two years ago,” Dardis says.

Any asset with zero to 10% developed reserves is going to be hard to sell. Yet, a lot of private-equity-backed companies have put together positions that fall into this category. These companies are fundamentally disadvantaged because of their shorter investment horizon. When the buyer of immature assets disappears, it makes it harder for companies with early-stage assets to find an exit within the typical three- to five-year time frame for most private-equity-backed companies, although some with attractive positions in liquids-rich resource plays are looking to the public markets (IPOs) as an alternative means to an exit.

Foreign buyers entered the U.S. market in strength about two years ago and they continue to show interest, although their appetite is not as strong as it was two years ago, Dardis says. But the demand is still there. For example, Quicksilver Resources Inc. sold an undivided 25% interest in its Barnett shale assets for $485 million to TG Barnett Resources LP, a wholly owned U.S. subsidiary of Tokyo Gas Co. Ltd. In addition, Woodbine Acquisition LLC announced it will sell the majority of its assets to Meidu Holding Co., a publicly traded Chinese conglomerate, in a transaction valued at $535 million.

Deals like those will continue, but they will be less common and smaller than before. The days of several-billion-dollar deals to Asian national oil companies may have passed. But other factors may offset the trend—the commodities market has entered a period of relative price stability, for example, which could increase the number of asset deals.

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