DALLAS—It has been a long, hard slog for oil and gas prices but stronger commodity markets are in the offing, according to a pair of trading experts.

Speaking at a S&P Global Platts forum entitled “Feast or Famine—A 360-Degree Oil & Gas Outlook” Sept. 28, Brian Milne, editor and project manager for DTN, discussed oil. Meanwhile, Ryan Ouwerkerk, senior pricing specialist for S&P Global Platts, focused on gas.

Milne noted that “after three years of oversupply, we’re beginning to see more demand for crude” as 2017 ends. As demand ticks up, the increase in supply seems to be leveling out too, he said. He said OPEC “is half way there” in its goal of cutting production 1% even as Libya and Nigeria—which were not part of the production cutback deal announced in late 2016—brought 600,000 bbl/d of production back on the market.

“They worked out deals with their militants and pretty much wiped out the Saudi cuts,” Milne added. He said to watch OPEC’s Nov. 30 meeting, which will include discussion about if, and how, to extend the production cut deal into 2018. He predicted the cartel will do so.

“OPEC is doing a good job, compared to their history” of enforcing cutbacks, Milne said. “But it’s important to watch occurs with cheating as prices go up.”

Saudi Arabia will continue to push hard to keep the cuts because the kingdom “needs for this to happen.” He explained that low prices have crimped its budget severely.

He pointed to three factors that are bringing crude prices out of the doldrums. In addition to OPEC’s cuts, U.S. production isn’t as robust as some projections have forecasted and worldwide crude demand is picking up.

In the U.S., output is close to the nation’s all-time peak of 10 MMbbl/d set in November 1970 but he noted the U.S. Energy Information Administration has already pulled back on its production forecast and said it’s likely the pull back further “when you go through their data.”

Milne noted cuts to domestic production primarily come from Alaska and the Gulf of Mexico, partially offset by a continuing rise in Lower 48 output from the shale plays. But recent rig counts are down and that indicates shale players are beginning to cut too.

Crude storage remains high and the U.S. Department of Energy has authorized sales from the Strategic Petroleum Reserve in response to Congress. Offsetting those negative impacts on crude prices, Milne noted “U.S. refinery demand was near a record high before the hurricane” and is returning rapidly to that high level. Exports also have been a significant positive, as well as petroleum product exports, thanks to those busy refineries.

Strong current crack spreads may induce some refiners to postpone seasonal turnarounds this fall so they can cash in for a while longer, Milne said.

He noted 26 countries have purchased U.S. crude this year “and that number should grow” as the nation builds a reputation as a dependable oil supplier. China has emerged as a major purchaser, Milne said. Stronger demand has pushed Brent to near the $60/bbl level while U.S. West Texas Intermediate (WTI) has crossed into the low 50s/bbl. But that WTI-Brent price spread could be a benefit to U.S. producers since the light, sweet crude typical of the domestic shales is popular with foreign refiners.

Gas Trends

Likewise, exports are a key driver for U.S. natural gas, Ouwerkerk said in his presentation. He termed the gas market “a roller coaster” in recent months as production has climbed while domestic demand has been weak. He noted prices had climbed to nearly $4/Mcf for the first time since 2014 in anticipation of the 2016-17 heating season, which turned out to be “the winter that wasn’t.”

New midstream infrastructure, “what I call Shale 2.0,” he said, is easing supply bottlenecks and turning the domestic gas market into a number of regional demand centers rather than a broad, national market. He mentioned specifically projects that help move gas out of Appalachia, including the Rockies Express Zone 3 repurposing that allowed the pipeline to move gas into the Midwest, and the Rover Pipeline Phase 1A that began moving gas into the Great Lakes region in September.

Another plus will come late this year when Dominion Resources brings its Cove Point LNG plant online, creating a 700 MMcf/d export for Marcellus and Utica gas.

“These expansions are no longer prospective, they’re happening. But we still have a wide range of constraints and domestic demand is anemic,” Ouwerkerk added.

But the focus of his presentation was Mexico. “It is the key trend in the North American gas market,” he emphasized. “Mexico is the next natural gas frontier.”

He noted new southbound pipeline capacity has received much publicity while 76% of Mexico’s LNG imports this year have been U.S.-produced gas via Cheniere’s Sabine Pass plant. The U.S. now provides 60% of Mexico’s natural gas, compared with only 10% as recently as 2010, Ouwerkerk said, adding Mexico has virtually no gas storage ability so gas supply must closely match demand.

Pipeline capacity out of the Permian has been a problem, he said, noting Permian gas currently can’t go very far due to Mexico’s limited pipeline grid. As a result, the bulk of pipeline-moved exports currently move under the river from South Texas. That will change as Mexico adds pipe. A major goal for Mexican authorities is to provide a Waha Hub-to-Guadalajara system that would feed Permian gas into the nation’s second-largest city, he said.

Ouwerkerk cautioned his audience to monitor closely Mexico’s 2018 presidential election because the energy reforms shepherded by President Enrique Peña Nieto will be a hot-button issue. Short term, there have been negative impacts, such as a 56% increase in power rates charged by the state-owned utility. That has made it difficult to gain public support for long-term benefits.

Peña Nieto cannot be re-elected under Mexico’s constitution.

One expected presidential candidate, populist Andrés Manuel López Obrador, has said he will put the nation’s energy reforms to a national referendum if he is elected president.