More U.S. shale-gas joint ventures will produce headlines in coming months, but deals will be smaller, and partnerships in non-shale plays are also under way, says Ward Polzin, managing director and head of A&D for Tudor, Pickering, Holt & Co. Securities Inc.

“It’s just a process; it doesn’t have to happen just in shale acreage,” Polzin says. As for shales, “there are still a few billion-dollar JVs to be done, but most of those have been done. You’re going to see more JVs, no doubt, but they’re going to be a bit smaller.”

Polzin addressed attendees at the ninth annual A&D Strategies and Opportunities conference in Dallas, presented by Oil and Gas Investor and A&D Watch.

Deal values in the second quarter for access to the Marcellus and Haynesville plays pushed to roughly $14,000 an acre, where the potential has been established and prospective partners can believe in the upside. In the condensate window of the Eagle Ford play, the most recent high deal value is some $12,000 an acre, Polzin says.

In the more nascent Eagle Ford oil window, the highest recent price is about $5,000 an acre; in the Niobrara, just under $4,000.

In the midst of these is the Bakken, at just under $8,000. “In the middle is where I put the Bakken today,” Polzin says. While the play is being proven, the upside potential is growing. “Any Bakken well drilled three years ago is irrelevant to any Bakken well drilled today, with longer laterals and 40 or more frac stages at times. I think we’re still trying to figure out in the industry what the new Bakken looks like.”

Plus, owners of the oil-rich Bakken are less strapped for cash for reinvestment, as oil is fetching $75 a barrel or more, compared with dry-gas-rich plays making $4 a million Btu.

“This big spate of JVs we’re seeing right now reflects the reality of the capital markets today,” Polzin says. “The high-yield market is open, but the equity market isn’t these days.” Stock can be sold, but many E&P issuers would be selling shares below net asset value. “You don’t want to do that if you don’t have to.”

What to bring

At the JV deal table, “you’ll have tons of things to negotiate, but there are five major areas.”

• How much ownership is sold? Deals have ranged between 25% and 50%.

• How much is cash, upfront? “Today, the cash component is between 25% and 50%. In the past couple of years, it was 50%, then it moved down to 25% and now it’s back to 50%.”

• How much of drilling costs is the buyer going to carry? This has ranged between 50% and 75%. “Today, 75% is, give or take, the average.”

• How long does the carry exist? “About two to four years. We’ve seen five; we’ve seen 18 months. But two to four years seems to be the time frame.” Longer terms increase risk, and for both parties.

“Lots of things can happen after the third or fourth year; lots of things can happen in three or four months in terms of commodity prices…The longer the partner is exposed to a changing gas-price environment, the more difficult the deal.”

• What is the operatorship option? In earlier deals, JV takers waived options on other acreage or on upside from other formations under the target acreage. For example, is the JV limited to the Marcellus or may the partner participate in targeting the Utica too? Is there adjacent acreage the partner can drill exclusively?

“Now, in some (deals) the partner can operate a piece. That’s something that has changed in a few JVs in the past six or eight months.”

It’s Complicated

The JV deal is similar to, but very different from, a traditional divestment or acquisition. “The seller is not going home when this deal is over, and the buyer is not taking over. This really is a marriage.” Trust, creativity, flexibility, transparency, patience, credibility—“All of this is going to be tested.

“You don’t have to love your partner, but you do have to have a lot of mutual respect.” A pre-nup is necessary, and the terms must be reasonable for both parties. “It really is complicated, but it’s where the rubber meets the road. Make sure you’re on the same page on these key issues.”

• First, the property owner needs to be transparent about what it needs: capital to accelerate drilling, hold acreage and build economy of scale, and to diversify risk via a partial monetization, while maintaining control and enjoying upside. The partner usually seeks shale expertise, access to a specific play, a large-scale portfolio-building opportunity, a pay-as-you-go acquisition opportunity, accelerated learning and participation in a broader value chain.

• Before putting a JV on the market, substantiate the geologic model. “It starts with the rock. You have to have a strong technical reason for where your acreage is—why you’re in this county and not that county, why you bought this rock and not that rock.”

• Also, have a detailed development plan for the entire acreage position that will be in the JV. “The partner is going to ask, ‘How are you dealing with your expiring?’”

• The type curve must be fully supported, and single-well and full-development economics demonstrated. “You need to prove that each well can stand up in a lower gas-price environment.”

• Vertical wells and at least some horizontal wells in the acreage must already have been drilled to derisk the prospective JV area. And, an ability to operate in the shale must be proven. “It might not be a track record in that shale, that play, but you need to show you can do high-tech completions, that you can do horizontal drilling without mistakes.”

• Take-away must be arranged too. “You need to deliver a midstream solution. You’ll get paid for it if you can.” If take-away will be built or bought, most JV partners will want to participate in that venture too.

JVs take longer to negotiate and close, he adds. “There is no unique solution; there are many moving parts.”

Partners, BYO$

The partner brings the money, and it must be the right money. “What do we mean by the right capital? First, it begins with size. Generally, even if it is a small JV, the partnering company is larger than the seller. The partner needs to make a relatively large commitment. It has to be large enough that the JV is important to the company, but small enough that there are no funding concerns.”

Of 31 JV deals Polzin reviewed, all but three involve a smaller-cap E&P or capital source partnering with a larger company, ranging from supermajors to private-equity providers. The exceptions are the Chesapeake Energy Corp. deal with Plains Exploration & Production Co. in the Haynesville; Carrizo Oil & Gas Inc. and Avista Capital Partners in the Marcellus; and PDC Energy and Lime Rock Partners in the Marcellus.

The partner’s money is for accelerating drilling and holding acreage. “Many of these existing players have large acreage positions.” Drilling inventory may span 10 or 15 years at the current spend level. Operators are also seeking to reduce costs by increasing scale, keeping more rigs and frac crews at work. “You want to get bigger. The JV helps to do that. There’s nothing wrong with taking some money off the table. The JV also diversifies your risk.”

Many prospective partners are seeking expertise and diversification. “They want to participate in the value chain.” Statoil ASA was an early U.S. shale-play entrant via a JV with Chesapeake Energy Corp. in the Marcellus. BG Plc came in via JVs with Exco Resources Inc. in the Marcellus and Haynesville.

“Why are they here? The reality is that they both have large LNG positions and trade gas in the U.S. Adding an upstream gas component gives them the full suite of the value chain. It lets them spread their value around and gain greater consistency in many types of price environments.”

About a third of all shale deals lately are JVs, rather than acquisitions, Polzin notes. “It’s a very significant part of the market.”

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