When looking back on second-quarter energy-transaction statistics, Michael Collier, U.S. leader of the energy M&A practice at PricewaterhouseCoopers, says it’s the best quarter he’s seen in two years. “It feels like we’re back in business,” he says.

Three factors are necessary to fuel M&A: a reasonably stable stock market, commodity prices moving rationally, and a perception by buyers and sellers that values make sense.

“The last piece was the last shoe to drop,” says Collier. “We’ve clearly reached the point where buyers and sellers are comfortable with valuations, which is helping to drive the market and to ultimately get deals done.”

According to PricewaterhouseCoopers’ recently released M&A Outlook, the U.S. oil and gas sector—comprised of upstream, midstream, downstream and oilfield-equipment services—yielded 142 announced deals in the second quarter, the highest amount since the 190 posted in third-quarter 2008. Deal value totaled $36.9 billion, a 169% increase year over year.

And upstream asset-focused deals dominated deal activity, accounting for 67% of the total deal value and the largest deal volume, at 80%.

“Deal activity in the oil and gas sector rebounded significantly in the second quarter, and we expect the momentum to continue though the second half of the year,” says Collier.

Taking a global perspective, Ernst & Young’s Q3 Oil & Gas Outlook notes a similar trend. Global deal value increased 50%, to $135 billion, and 420 deals were announced in the first two quarters of 2010, compared with 334 during the same period in 2009.

“Energy M&A activity is starting to increase,” says E&Y’s Jon McCarter, transaction advisory services leader, Americas Oil & Gas Center. “We’ve seen a healthy increase in first-half 2010, and we expect that to carry through the second half.”

Deal-flow Dynamics

Deal flow is very active, according to Rob Bilger, managing director and head of U.S. A&D with Houston-based advisory firm and investment bank Macquarie Tristone. “I don’t think we’ve ever had a period when we’ve had more confidentiality agreements signed and data rooms per package than we have right now.”

The reason, he says, is a shortage of quality properties for sale—combined with greater capital availability.

Two kinds of deals are being marketed now, says Bilger. First, early-stage resource plays—with only a small amount of development work completed and a lot of upside—are getting done through outright sales or joint ventures.

Second, and at the opposite end of the spectrum, are conventional oil and gas assets, particularly oil-weighted and liquid-prone properties, which are commanding premium pricing. Yet not many conventional properties are on the market, “which has been a little disappointing for buyers.”

High-percentage PDP deals valued below $200 million garner a lot of attention, he says, while larger transactions have tended to involve early-stage resource plays.

“We’re just not seeing a lot of the large, high-percentage PDP (proved developed producing) packages come to market,” observes Bilger. Major exceptions are properties from Dallas-based Denbury Resources Inc., which has been rationalizing noncore assets from its purchase of Encore Acquisition Co., and ConocoPhillips, which is on a $10-billion global sell-down, including its U.S. E&P assets. “Other than those two companies, there haven’t been a lot of large property packages with high PDP.”

That’s because revived financial markets have allowed public companies to bolster their balance sheets this year, he says. “They’re not being pressured to sell assets to increase cash flow or to have capital available for their capital-expenditure programs.”

Logan Magruder, also managing director at Macquarie Tristone, says quality assets are beginning to surface. “Now we’re seeing companies make conscious decisions to reallocate capital within their portfolio. They are selling things of quality and value to redeploy capital into shale plays or some other program.”

Sellers in today’s marketplace consist of companies cleaning up portfolios, those seeking to reduce uncomfortable levels of debt, and private companies cashing in on having been first movers in resource plays. Buyers include international players, major oil companies, large independents and private capital.

Deal volume is increasing too, says Collier, but not due to the “headline-grabbing” deals, which he defines as $1.5 billion and up. Instead, it’s the smaller deals driving the numbers as companies make minor adjustments to their portfolios.

According to PricewaterhouseCoopers, upstream deals in the U.S. in second-quarter 2010 totaled 113 for nearly $25 billion, up from 87 in first-quarter 2009, and more than double in value from $12 billion. First-half 2010 deal value was up more than 400% over the previous year, on two-and-a-half times more deal flow.

Asset deals make up a high proportion of the E&P space—85% in the second quarter, according to the PwC M&A outlook—and were a major contributor to that quarter’s resurgence.

Capital Intensive

There is no shortage of capital for the E&P space, PwC’s Collier says, whether from equity capital, credit or private sources. “The amount of dry powder sitting on corporate balance sheets and in private-equity funds is at an all-time high. The numbers are astronomical.”

Capital markets have been strong, especially in comparison with the catastrophic financial events of two summers ago, when financing options disappeared, and one summer ago, when the markets remained tight and expensive. Today, debt is not only available, but at low cost. High-yield rates are down considerably. Equity markets are open.

“The money is out there,” agrees E&Y’s McCarter, but it is not only traditional bank debt spurring transactions. Private sources of capital are abundant as well, and have been sitting on the sidelines waiting for the right time to invest.

“More private-equity money is aimed at the space than we’ve ever seen,” he says.

He estimates $100 billion. About half of that is in energy-focused funds. The other half, he says, will come into the space from sources such as sovereign wealth funds and private-equity funds that invest across multiple industry sectors. “It’s a lot of money.”

This money will flow into minority-interest transactions, including equity, preferred stock and PIPE (private investment in public equities) funds. And while investors feel more urgency than a year ago, it’s because they finally see better opportunities. “These are disciplined investors,” says McCarter.

Macquarie Tristone’s Magruder sees private-equity sources “doubling down” in their E&P investments. “They are making certain their more proven management teams are well funded and are able to create significant critical mass and scale, which may have greater exit appeal.”

Yet while capital is abundant, it is more conservative, per Collier. Acquisition capital is chasing lower-risk deals “because of all the pain we’ve just gone through. Nobody’s in a hurry to do that again.” As confidence builds in a steadily growing economy, “that capital is there.”

As a result, deals done now are of a higher quality than those transacted in a boom, he says. “Buyers take their time to do their diligence and value the risks. When a lot of capital is on the sidelines and a conservative mindset is in place, you have high-quality deal flow.”

Shale Shakeout

The shale-gas situation is driving a lot of M&A. “We’ve seen a number of non-U.S. companies come into the shale-gas plays in a major way with major investments,” says Collier. “There will be plenty more of these.”

Two factors are at work. Foreign companies seek a major investment in what will be a fundamental change in the supply-and-demand equation in the world’s largest economy. Also, they want to apply the acquired knowledge in other shales around the world.

“There’s an expectation that unconventional gas resources are in plenty of places in the world, but you’ve got to have the know-how.”

PwC’s M&A Outlook reveals $13.4 billion in asset sales by non-U.S. entities taking positions in unconventional plays, with foreign buyers accounting for 25% of the transactions in the quarter, a 21.6% increase from the prior year.

Many of those transactions have been in the form of joint ventures, allowing producers to accelerate development and preserve leases by finding a partner instead of going to the bank.

“Joint ventures provide for an influx of capital,” Magruder says. “Developers get to preserve as much acreage as possible, increase drilling activity, and the market recognizes the acceleration of present value. Many companies have juiced shareholder value as a result of joint ventures.”

E&Y’s McCarter believes the impact of international players in the shales is significant, as they are the buyers getting deals done. Yet given the softness of natural gas prices and the lack of added demand in the equation, he questions the sustainability.

“I don’t think that deal activity can continue at that rapid of a pace for the long term. At some point all trends come to an end. So while the quantity of deals being done may slow, capital spending by past ventures and other E&P owners will probably continue at a rapid pace.”

Collier anticipates a new wave of joint-venture activity between operators and private-equity funds, especially if gas prices stay low. “We’re going to see operators tapping into private-equity companies’ desire to come into the space. It will create unique arrangements.”

Oil Rush

A movement is afoot to liquify portfolios. “Oil—or liquids—are getting a lot of interest,” says McCarter.

The trend toward oil and gas liquids is rooted in the unprecedented decoupling of commodity prices, with no sign of that abating. By historic standards, the differential between oil and gas prices is monumental, presently about a 20-to-1 ratio, and could widen as the economy improves and pulls with it demand for oil—while natural gas stays flat.

“Some independent companies are making a push for more oil in their portfolios, with the expectation that they will be rewarded for that,” Collier says. “We have seen a number of transactions that are all about having more oil.”

“There is no shortage of companies trying to balance that mix,” adds McCarter. “They are doing deals that are oil weighted or liquids heavy to balance their portfolio.”

The most popular: the oil and condensate windows of the Eagle Ford shale in South Texas. Here, in just six months’ time, values have ramped up from $500 per acre to $12,000. Likewise, the Bakken shale in North Dakota, the Wolfberry in the Permian Basin and the Granite Wash in the Texas Panhandle are garnering premium values.

Regarding the Granite Wash, Magruder says large and midcap companies just can’t get enough of it. And as for the Wolfberry, which benefits from multistage fracture stimulation without requiring high-cost horizontal drilling: “It’s one of the most attractive plays out there right now. All those plays have in common good drilling economics because they are high in liquid content.”

Conventional Gas Lives

Contrary to popular belief, however, conventional gas assets are still receiving a lot of attention, McCarter says. “It isn’t getting a lot of headlines. Plenty of companies are still investing in conventional gas.”

Conventional gas is less expensive to exploit, but the concern remains that the abundance of shale gas is going to continue to dampen gas pricing.

“It just feels like there’s less upside for conventional gas,” says Collier, “but I don’t see any evidence to suggest that conventional gas is over. We’re still seeing deals involving conventional gas.
“It’s not like it’s shale or nothing,” he says.

Bilger says high-percentage gas properties recently sold by Macquarie Tristone experienced active data rooms and bidding. “There’s still a buyer for all producing projects.”

Many companies with conventional gas assets, though, are not motivated to sell into current market conditions. “If they’re not under cash constraints, many companies are hoping gas prices will rebound before they do sell.”

Uncertainty Looms

If any factor is still dragging on M&A, it is the wild card of lingering uncertainty—about the global economy, regulation stemming from the oil spill offshore and hydraulic fracturing onshore, pending legislation impacting the tax regimen for operators, and commodity pricing, notably gas.

“Confidence is needed to get back to a robust transaction cycle,” says McCarter. “Knowing what the rules are is not going to hurt.”

Ernst & Young observed a significant pause in deals flowing into the pipeline though mid-summer, largely due to these factors and an anticipated improvement in the capital markets that failed to materialize.

“We saw a number of deals die,” says McCarter. “People are more cautious. They are less likely to get over issues that arise while doing a deal.”

The good news is the pipeline is filling up once again.

“We’re going to see a continued recovery. That trend has already shaped up in the first half, and overall that will continue.”

Collier believes that upstream M&A is a long way from a boom like that experienced at the end of the last cycle, but he thinks a long, gradual and measured ramp-up in deal flow is likely and better for the industry.

“We could be at the beginning of one of the longest, most comfortable M&A cycles any of us in the energy industry has seen.”