Natural gas production from the Marcellus and Utica shales should double over the next five years, surpassing Rockies output levels from 2012 and accounting for “over a quarter of U.S. Lower 48 gas production,” Wood Mackenzie upstream analysts are forecasting.

Northeast production also is seen exceeding by 2015 gas output from the Western Canadian Sedimentary Basin (WCSB), said analysts late last month.

The UK-based team recently hosted a conference call about North American onshore trends led by upstream analysts Callan McMahon and Mark Oberstoetter, who dissected the plays that matter and their potential and implications on other production areas. Senior analyst Eric Kuhle also weighed in on the firm’s long-term North American gas supply themes.

Most U.S. natural gas drilling in the Lower 48 states is economic today at prices above $4.00/MMBtu, but in the years to come, the Marcellus and Utica shales increasingly will lead North American gas market dynamics, analysts said.

With a compound annual growth rate in the Marcellus at about 2.4%, the Northeast growth and an operator-focus on tight oil is putting “pressure” on the Rockies basins and in the WCSB over the medium-term, said Kuhle. However, “demand growth and improved gas prices lead to a gas production rebound in the Rockies and WCSB beyond 2015.”

Over the next 20 years, the Marcellus by itself should lay claim to 14 Bcf/d by 2020, more than 10 times what it is estimated at today, analysts said. Utica gas production rates also “have been very encouraging,” with initial production rates improving.

There’s been a “significant increase in drilling” into the Marcellus formations, as well as “superior well performance…where wells are expected to produce as much as 6-10 Bcf,” which would “support continued production growth over the next two decades,” analysts noted.

Drier gas plays, like the Haynesville and Barnett shales, have seen drilling and production decline as producers ventured into wetter areas, but that’s not true of the Marcellus or the emerging Utica, which has tended to be more dry than wet. On the backs of those two plays alone, Northeast gas production is expected to lead the charge for the next two decades.

The reason: location, location, location.

“Being in the right location within a play is vital as multiple sub-areas that exist where well results and economics vary dramatically,” said analysts.

“Given low domestic gas prices, operators have continued to shift capital from peripheral and noncore gas areas to liquids-rich and tight oil plays,” said the analysts. “Of the US$150 billion forecast to be spent on onshore North American developments in 2013, over 40% will be directed to tight oil plays. Shale gas and Canada’s oilsands makes up much of the remainder, as unconventional themes now dominate the continent’s upstream sector.”

The Northeast hasn’t experienced sharp gas drilling reductions because of the “low-cost of development and benefit of natural gas liquids [NGL] in some areas,” analysts said. There’s been a continuing decline in “lean gas well costs.” Declining well completion costs — and lower-cost multi-pad drilling — also have been a big point of discussion in recent earnings/operations reports.

“In July, 87% of active gas rigs had a 10%-plus return on strip pricing, up from 40% in June 2012,” McMahon noted. “Low gas drilling levels have led to a 20% cost reduction in lean-gas areas.”

Although the Northeast gas output may surpass the Rockies, the legendary outpost still offers compelling gas growth, with production by 2020 “38% higher than current levels,” said analysts. Rockies growth will come from more than just drilling gas wells. Associated gas from tight oil development should continue to grow, particularly in the Bakken Shale, with gas production reaching 2.1 Bcf/d by 2020. Also, rig productivity improvements and increased activity are supporting a “Piceance revival.”

There’s also plenty of gas still to be captured in the WCSB from low-cost unconventional gas drilling, which has contributed to a production “rebound.” High on the radar is the still-emerging Montney Shale in British Columbia (BC), where production is forecast to double from current levels to reach 5.1 Bcf/d by 2018.

Less strong are growth signals in the wetter Duvernay Shale, where “costs still remain high due to drilling challenges.” However, the Duvernay should contribute to production growth “beyond 2015,” reaching 2.1 Bcf/d by 2020. The gassy Horn River Shale in BC likewise won’t contribute much to the numbers until after 2020.

In any case, Wood Mackenzie’s team thinks NGL production and “liquids support” are the “key to supporting near-term gas drilling levels” in the Canadian unconventionals.