Amid the industry optimism, positive post-reform thoughts and good vibes emanating from the deepwater oil and gas potentially lurking offshore Mexico, Stan Franklin couldn’t resist the elephant in the room.

“A lot of projects are struggling,” said Franklin, general manager for frontier exploration and appraisal for Chevron Africa and Latin America Exploration and Production Co. “Deepwater has some headwinds in front of it. The breakeven prices are very difficult.”

However, the industry—along with its long-cycle projects—will get past this phase, he added.

Offshore breakevens need to be at least $50 per barrel to compete for spending with onshore and shallow-water opportunities, according to Helge Haldorsen, general director of Statoil Mexico. Getting there will “take a village,” he said, adding that this includes not just operators, service companies and suppliers but also the administration, regulators and the treasury.

Mexico could be an attractive piece of the offshore picture as the industry emerges from one of its worst downturns, oil prices stabilize and companies prepare to meet an expected rise in global demand.

Since opening its doors to foreign investors in December 2013, interest has grown off-shore Mexico with eight of 10 blocks receiving bids during the country’s first deepwater auction in 2016. Another deepwater auction is set for this year.

Some of the world’s biggest players are already gearing up for the dive in hopes of striking hydrocarbon riches. Mexico’s newest deepwater players, including Chevron and Statoil, took the stage at this year’s Offshore Technology Conference (OTC) in Houston to talk about why they decided to enter the region, even as low-commodity prices ate into companies’ profits, prompting spending and activity slowdowns.

“Will [Mexico’s] deepwater trigger a renaissance?” Franklin asked. To help answer the question, he created a scorecard that assessed six areas: a proven petroleum sys-tem, attractive acreage and predictable bid rounds, a stable fiscal and regulatory regime, 3-D seismic data, well and impact discoveries, and infrastructure.

Mexico fared well in some areas, but others needed improvement. A positive is that “we know it has excellent source rocks,” he said.

Making the grade

While production on Mexico’s side of the Gulf of Mexico (GoM) pales in contrast to the U.S. side, Haldorsen pointed out reserves and production, including from Mexico’s Cantarell Field, have fallen.

But, Pemex has made a “string of discoveries extending that Perdido trend. That’s how it all begins,” said Franklin.

Mexico had about 9.7 billion barrels of proved oil reserves at year-end 2015, mostly located offshore, according to the U.S. Energy Information Administration (EIA).

Data from the EIA also show that roughly half of Mexico’s oil production comes from two offshore fields in the Bay of Campeche region—the Ku-Maloob-Zaap and Cantarell, which was once the second-largest field in the world following Saudi Arabia’s Ghawar.

Production has fallen. But active source rock is present, Franklin said.

“There is a huge diversity … of traps perforated by salt,” Franklin said. “And we’ve got a wide range of play types … from the youngest, Pliocene, all the way back to Jurassic. That’s good news.”

However, there are some differences between the two regions. The biggest is, perhaps, the sediment supply, Franklin said. For the U.S., multicyclic sediment flows into the GoM from the Mississippi River Delta. It’s been recycled a few times to create clean sandstones, buried deeper and preserving reservoir quality.

Meanwhile, along the Mexican coast, there is tectonic activity, which creates more “dirty-type rock fragments” that reduce per-meability when buried deep.

It could create some challenges, but Franklin gave Mexico’s petroleum system a check on the scorecard, given its potential. Plus, Mexico has made plenty of acreage available and has provided a transparent path for investors in bid rounds and terms. The regulatory process continues to improve, he said.

“There is plenty of play-trend running room to go,” which is needed for companies like Chevron to establish business. Also, Mexico is “off to a very strong start” for providing 3-D seismic, which is key to finding and unlocking resources, but it “still has a ways to go.”

Of the areas assessed by Franklin, one clearly stood out as weak: infrastructure. There are about 3,000 deepwater wells in the U.S. GoM with a vast network of infrastructure and tiebacks, compared with fewer than 60 on Mexico’s side with little infrastructure.

“We’re going to need a couple of major discoveries, and that will bring the initial infrastructure,” Franklin said. Satellite fields will follow.

But Mexico will need to see a lot more drilling, he said.

Reaching goals

The International Energy Agency’s (IEA) Mexico Energy Outlook to 2040 projects Mexico’s crude oil output will bottom out at fewer than 2 million barrels per day (MMbbl/d) toward 2020. But efforts from the reform have the potential to lift production as deepwater developments begin operations. Output is expected to rise to 2.4 MMbbl/d by 2040. Adding tight oil and NGL to the mix, output could hit 3.4 MMbbl/d.

But the IEA pointed out that “Mexico’s long-standing position as one of the world’s major producers and exporters has been weakened in recent years, with investment by Pemex insufficient to arrest an output decline by more than 1 million barrels per day since 2004.” A turnaround of the country’s oil and gas sector rests on three pillars: development of onshore unconventionals, shallow-water fields and deepwater fields. The lattermost could make up about half of the Mexico projected offshore oil output by 2040, the IEA said.

Haldorsen referenced the report during his OTC presentation, saying that, without denationalization, Mexico would lose the opportunity for $1 trillion of GDP, nearly $750 billion in oil and about $250 billion in investment.

Looking at the good that is possible, Hal-dorsen asked, “How can anyone be against this happening for the country?” Then, he turned to something the report didn’t cover—what it’ll take to get to 3.4 MMbbl/d.

In his opinion, Mexico will need about 20 wildcats a year. “This is possible,” considering Norway and the U.S. have achieved that and more. He also estimated that as much as $30 billion in investment may be needed annually.

Still, other factors could derail hopes.

“Potential is still the bird on the roof. It [oil] might not be there,” Haldorsen said, adding that he hopes this is not the case. “Oil prices could be so low that the breakevens are too high, so you don’t get investments com-ing in. Maybe the breakevens in Mexico are too high because of the fiscal models. Maybe there are too few actors.”

Politics could be at play. Activity levels could drop further.

Yet, there are levers Mexico can pull, he added.

“Clearly, they can offer globally competitive terms and conditions. They can even offer the best terms and conditions. They can offer predictability and long-term investment security; many of these things, they are doing,” Haldorsen said.

But Mexico could do more. He suggested Mexico could lift a page from Norway’s play-book and offer free legacy seismic data.

It could also change the specified minimum royalties and work programs used during bid-ding. From the deepwater blocks awarded in December 2016, initial royalties are not pay-able until 2025.

“The first royalty will come to Mexico once the well starts producing. Let’s say it takes seven years between finding it and first oil, then you get the cash flow in 2025 discounted back to today,” Haldorsen explained. “It’s not that much.”

Compare that cash flow with drilling a well during the first year of an exploration pro-gram, he said. “Any well that you drill can turn into a discovery.” By starting exploration and development work early, revenue could be generated sooner to stimulate the economy.

“You’re investing, employing people. Stuff is happening and you start producing. This is what Mexico needs more than anything else.”

Activity is important to make reform a success, he said.

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