North America’s energy renaissance is going full tilt, but it could be shackled by a lack of personnel, more stringent regulations and even geology, IHS CERAWeek executives said in Houston last week.
In any given onshore U.S. play, only 3-9% of the acreage is producing profitable and productive wells, Raoul LeBlanc of IHS told the audience. He is managing director of onshore oil industry research.
Productive underground reserves are like nutrient-dense snacks that won’t stay in the cupboard forever.
“You have ‘PowerBars’ and popcorn in your pantry,” LeBlanc said. “Right now, we’re eating the PowerBars. At some point, the PowerBars will run out.”
Those nutrient-rich plays, like the Eagle Ford and Bakken shales, are only producing from the best-tested acreage. Eventually, development will slow while emerging fields, particularly from the rediscovered Permian Basin, become the unconventionals du jour.
“At some point, we’ll have to go to the ‘second best.’ It’s not a catastrophe. It’s not a disaster. It’s just not as good” as the easy to reach oil and natural gas, said the IHS executive. However, transitioning to more difficult plays and some emerging horizons may require higher, sustained oil and natural gas prices.
“We need a price…to go get it,” LeBlanc said. “As long as the price is there, I’m comfortable about the resource.”
One thing that’s becoming an increasing hurdle are project costs, said Woodside Energy CEO Peter Coleman, who oversees the Australian-based operator. Some higher ticket items, like liquefied natural gas (LNG) export terminals, are running into cost overruns overseas on labor and equipment shortages, something bound to affect North American developments as well.
Project costs could be reduced by as much as 40%, according to Coleman. It’s the only way to ensure an operator’s long-term profitability, he said.
In addition, as LNG becomes a more fungible commodity over the next 15 years or so, the relationship between buyers and sellers will change, Coleman said. By adopting an efficient business model now, operators may better align with expected revenues. It’s paramount to prevent over developing or stranding assets, said Coleman.
Today’s energy markets are so volatile and ambiguous that operators need to plan in three dimensions: geography, price and time, said GDF Suez Executive Vice President Jean-Marie Dauger.
Geographically, increasing interaction in the gas markets has allowed sources to expand their reach. However, all that new gas also is pressuring prices, and markets increasingly are moving to the same price, he said. Time, the third dimension, looms because the longer-term, high-priced investments are proposed at uncertain future gas prices, which increases the probability that disruptions may alter project economics.
“Individual excellence is not enough,” Dauger said. Gas players instead should consider sharing their visions and their strengths to succeed.
For many operators, labor and capital costs have become an increased burden, with costs doubling in the past decade, according to Chevron Corp. CEO John Watson. If there weren’t as many resources to develop, oilfield services wouldn’t have as much work to do. With all of the new technology and better efficiencies, it means more upfront costs, he said.
“All of us are facing new realities and pressures. The industry’s increasing demand for goods and services around the world caused significant escalation…So costs have caught up with energy prices,” he said.
To keep the development going at faster clip, the industry needs a sustained, triple-digit oil price and steady gas prices, Watson said.
Many of the mega-developments around the world are estimated to cost upward of $30-40 billion, with deepwater drilling and far-flung resources taking a big bite out of budgets.
ExxonMobil Corp.’s Rob Franklin, president of gas and power marketing, said the cost of big gas projects worldwide has quadrupled in just a few years. ExxonMobil has several mega developments, including new LNG projects, that are progressing.
The huge global developments no longer are the exclusive domain of the supermajors either, said ConocoPhillips’ Luc Messier, who heads project development and procurement. Today, there are more than 35 big deals on the drawing board, many by state-owned producers with money to burn. All of the operators are competing for the same oilfield services, personnel and equipment, he said.
Alberta Energy Minister Diane McQueen pointed to a lack of skilled workers and markets as holding back the opportunities for the Canadian oil and gas industry.
“That’s the challenge that we’re facing in order to keep the costs competitive,” she said. Alberta operators increasingly are working on ways to economically carry oilsands crude to markets and find new avenues for growing oil and natural gas resources.
For one thing, Alberta isn’t putting all of its energy eggs in TransCanada Corp.’s Keystone XL oil pipeline, which awaits approval by the U.S. State Department. A southern section of the pipeline is designed to transport crude supplies to Gulf Coast markets. But there are other options for the country’s reserves.
“It’s not one pipeline that we need,” McQueen said of Keystone. “We need them all…” Finding customers and exporting natural gas and/or oil to Asia-Pacific markets hold a particular allure. Finding those overseas customers makes it “really important to get to tidewaters to access markets,” McQueen said.
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