It seems as though the long slump in gas prices has gone on forever, but rising gas demand in the coming years may drive a third surge in shale investment. This is according to a recent report by Scott Gruber, senior analyst for Bernstein Research.

“We are often asked, in what inning of the upstream investment cycle does the industry currently stand? Our response for the North American market is we believe the market has entered a new ballgame,” he said.

The market has seen upcycles first in shale-gas production and then shale oil. Gruber said the next phase of shale development will create a different cycle. Growth in upstream investment could hit a modest 4% per year, but be more durable because of drivers in four sectors: declining shale-oil production, rising gas exports, gas-to-coal switching and industrial demand.

“In this long view, we assess the impact on North American oil service demand as the energy industry monetizes plentiful shale-gas reserves,” Gruber said.

Less than a decade ago, the industry was prepping for LNG imports. Today, exports are on the horizon. So far, four LNG export facilities have been approved by the federal government.

Gas exports to Mexico could also rise. Mexico imports about 1.8 Bcf per day, mostly from Texas, Arizona and California. The country plans to increase U.S. imports, though pipeline limitations have resulted in Mexico drawing additional gas from Africa and the Middle East. Pemex is commissioning a $3.3-billion pipeline project from Texas that would increase import capacity by 2.1 Bcf per day.

LNG exports have become contentious, however, because of environmental groups and the prospect of rising prices’ effect on manufacturing and other industries. The process of approving and constructing export facilities is complicated. Regulatory approval is needed from the Federal Energy Regulatory Commission (FERC) to construct terminals and the Department of Energy (DOE) to export.

Continued coal-to-gas switching is also expected as utilities announce the retirement of an additional 28 gigawatts (GW) of coal-fired plants through 2015. However, new coal-fired plants will reclaim 11 GW by 2015, limiting the net loss of coal-fired capacity.

If predicted coal-fired generation is offset by gas, U.S. gas consumption would have to increase by at least 3.1 Bcf per day from 2011 to 2015.

“All else being equal, this would imply a 5% increase in U.S. consumption of gas from 2011 levels,” Gruber said. Looking beyond to 2020, U.S. gas consumption would have to increase by 1.7 Bcf per day.

Ongoing efforts to build renewable generation are also likely to erode the impact on gas demand. Renewables are having a faster impact on energy demand than anticipated, Gruber said.

The government’s targets require renewable generation in the U.S. to expand by about 70 million megawatt hours (MWh) by 2015 and 200 million MWh in 2020. “Significantly, the U.S. is, in aggregate, on track to exceed these mandates,” Gruber said.

The renewable generation fleet should expand enough to increase by 90 million MWh by 2015 and 225 million MWh by 2020.

For industrial processes, fertilizers, plastics, oil refining and other uses should create greater demand. Industrial gas demand has expanded by 1.4% per year during the past five years. Extended over the next decade, Gruber’s base-case assumption is an industrial gas demand growth of 3 Bcf per day.

However, relatively few industries use oil and gas products as feedstock. “We would say low-cost gas has a minor impact on the chemicals industry as a whole,” Gruber said. “We estimate natural gas is about 16% and electricity is about 5% of U.S. chemicals industry costs.”

In contrast, gas-intensive processes like ethane cracking from gas constitutes more than 80% of costs.