As Mexico pushes forward with energy reform intended to attract foreign investors and lift sagging production levels—ultimately boosting the economy—panelists at a forum this week pointed out that both challenges and opportunities await the country.

“There are opportunities in all of the key provinces. You have opportunities for unconventionals in the north. You have deepwater. You have shallow water. You have mature [fields] toward the south. You’ll have some of the heavy oil opportunities also,” Joe Amador of Tudor, Pickering, Holt & Co., said during King & Spalding’s Mexico energy reform forum. “There is something there for everybody. … All of this does pose challenges and opportunities in all areas of the energy chain. It will require significant investment.”

Historic constitutional changes have opened the upstream among other sectors to private investors, ending Pemex’s decades-old monopoly. Types of E&P contracts available will include license, production-sharing and profit-sharing contracts, with the ultimate goal of maximizing the nation’s revenues. Local content requirements for E&P companies doing business in Mexico will gradually rise from 25% next year to 35% by 2025.

Now that Round Zero has been complete, with Pemex learning which assets it will be allowed to keep, the energy ministry is preparing for the first round of open bidding, scheduled for first-quarter 2015.

Rogelio Lopez, a partner with the Velarde, Lopez, Velarde, Heftye y Soria law firm, said 169 blocks (109 exploration blocks and 60 producing fields) will be offered during Round 1, which will be launched in February or March 2015.

But before this happens, Lopez highlighted the hefty workload that remains and issues to be resolved. In October and November, plans are for secondary legislation and related regulations to be published for comments, and there will be announcements on the process for farm-outs of the 11 allocations Pemex kept in Round Zero that will be subject to joint ventures. The farm-outs must be approved by Mexico’s national hydrocarbons commission, CNH. Existing service contracts will also have to be converted.

“The timeline is extremely short to organize activity of such a magnitude,” Lopez said. He later pointed out other concerns raised and other possibly contentious areas such as data room quality and that all of the geological information is kept by Pemex; surface rights, considering operators will have to obtain their own surface rights and negotiate with surface owners; the need for technical standards for safety; and local content issues, specifically whether the local content requirement violates the North American Free Trade Agreement and whether locals have the expertise to do the job. Local content exceptions have already been made for deepwater.

More than 100 regulations need to be adopted, he added, saying, “That is significant.”

“Everybody has high expectations, not only politicians, this government, us the public, investors. That can be a concern,” Lopez continued. “When you have high expectations you have to manage those expectations. … . We see a lot of changes, but that’s going to take a lot of time. Hopefully, the system has been developed in a way that [allows adjustments]. Many of the regulations are very critical.”

Opportunities exist

Although the reform effort is still ongoing, some oil and gas companies have already realized the possibilities and have expressed interest in working in Mexico.

Comparing oil and gas development in the U.S. GoM and shale plays in Texas, Amador spoke about the level of development that will be required in Mexico. Looking at well density alone in the Eagle Ford Shale, which is believed to extend into Mexico, there have been more than 7,000 wells drilled in the U.S. Eagle Ford vs. about 20 in the Mexico Eagle Ford in the Burgos Basin.

“The Eagle Ford Shale has increased production by about 1½ [million] to 2 million barrels a day. That can more than offset the decline in Cantarell,” Amador said.

Basins believed to hold shale resources line the country’s northeastern and eastern parts. Basins include the Chihuahua, Sabinas, Burro-Picachos, Tampico-Misantla, Veracruz and the Burgos, which could be the most promising because of its proven resources and continuation of the prolific Eagle Ford Shale play across the border in Texas.

In an investor presentation, Pemex said the Woodford also has continuity across the border, and the Bakken and Haynesville shale plays are analogues of plays in Mexico. The Tampico-Misantla Basin possibly holds 34.8 Bboe in prospective unconventional resources, with the Burgos holding about 15 Bboe, Sabinas with 9.8 Bboe and the Veracruz with 0.6 Bboe in prospective unconventional resources.

Additional resource potential exists onshore and offshore in both shallow water and deepwater.

“Deepwater offers quite a bit of opportunity, primarily in the northern part just across the border. Keep in mind geology does change quite a bit as you head south across the Gulf of Mexico,” he cautioned.

Some operators and service companies are already present in Mexico. These include London-based Andes Energia, Lewis Energy of San Antonio, Argentina’s Tecpetrol, Petrobras, Petrofac and Weatherford. To attract more investors, Mexico will need to be competitive.

“You have companies that are doing extremely well operating and drilling in the Permian, the Eagle Ford and the Marcellus. … Oilfield service companies that can’t find enough horsepower to fulfill all the frack requirements,” Amador continued. “It’s going to take an incentive to get companies to move down to Mexico. That is very important to keep in mind, and obviously, implementation is going to be key. We’re very, very focused today on the migration and the joint ventures and the licensing rounds. But in order to drill your first well you have to get permits, environmental permits. There are going to be social issues you need to resolve.”

Hopefully, Mexico will learn from other countries as it works to implement some of these laws, he said.

Reserves, production

Falling production levels show the consequence of underinvestment. Amador mentioned how the Golden Lane Field discovery boosted oil production in Mexico to 500,000 bbl/d in the early 1900s—enough to classify Mexico as the second largest oil producer. But output quickly declined due to underinvestment, before nationalization occurred in 1938. Oil production took off in the late ‘70s, mainly due to the Cantarell discovery, benefiting the country’s economy as the world faced oil price hikes due to conflict in the Middle East.

“The production in Mexico has very much been a function of the Cantarell production, and you see it most recently since 2008 to 2009 that that field has been on a decline, a very steep decline,” Amador continued.

More than half of Mexico’s oil production comes from the Cantarell and Ku-Maloob-Zaap (KMZ) fields in the Bay of Campeche. However, falling reservoir pressure at the Cantarell has resulted in the KMZ becoming the country’s most prolific field, according to the U.S. Energy Information Administration (EIA). Despite attempts to boost production, including by injecting nitrogen to maintain pressure in the reservoir, Cantarell’s production has continued to decline, plummeting from a high of 2.1 MMbbl/d in 2004 to about 440,000 bbl/d in 2013, EIA figures showed.

While oil production overall has dropped in Mexico, going from just less than 4 MMbbl/d in 2004 to less than 3 MMbbl/d today, after a dramatic fall of 22% from 2004 to 2009, gas production figures have not been as bleak.

“Natural gas has been on the uptick. That’s the bit of good news, a lot of it the function of multiple service contracts that Mexico began offering back in 2003 to 2004,” Amador said.

In its latest outlook on Mexico, the EIA projected that the reform could increase the country’s long-term oil production by 75%, rising from 2.9 MMbbl/d in 2020 to 3.7 MMbbl/d by 2040.

Currently, Mexico has about 12Bboe to 13Bboe, including natural gas, in reserves, down from a reserve base of 70 Bboe in 1982. The reserve-to-production ratio has stabilized at about 10 years, according to Amador.

“What you see is a significant amount of resource base opportunity to go drill up those large volumes that are there. They are there. It is just a matter of drilling them and getting production volumes up,” Amador said. “If you do a little math and use the 70 billion barrel reserve base that Mexico used to have at a 10-year reserve-production ratio, that is close to 20 million barrels a day of production. That’s quite a staggering number, particularly compared to the production volumes of Mexico today.”

Contact the author, Velda Addison, at vaddison@hartenergy.com.