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.
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, and specifically how the Marcellus and Utica shales will shape future growth across Canada and the western United States.
“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.”
Nearly all current domestic gas drilling is economic at prices above $4.00/MMBtu, said Kuhle. With the 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 and WCSB over the medium-term. But demand growth and improved gas prices lead to a gas production rebound in the Rockies and WCSB beyond 2015.”
Marcellus gas well performance by itself should lay claim to 14 Bcf/d by 2020, more than 10 times what it is estimated at today. The Utica gas production rates also “have been very encouraging,” with initial production rates improving, said analysts. Drier gas plays, like the Haynesville and Barnett shales, have seen drilling and production decline as producers ventured into wetter plays, 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. Why? 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. Changing North American oil and gas market dynamics today center on geographic location, which has become “a key determinant for operator’s netbacks, alongside geology and supply costs.”
The northeastern unconventionals have not experienced sharp gas drilling reductions because of the “low-cost of development and benefit of natural gas liquids [NGL] in some areas,” they said. A key trend since 2011 has been the continuing decline in “lean gas well costs.” Declining well completion costs — and lower-cost multi-pad drilling — 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 soon may surpass Rockies gas output, the legendary western region still offers compelling gas growth through the end of the decade, with output by 2020 “38% higher than current levels,” said analysts. And the 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 output 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,” said analysts.
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. The gains in part are attributed to producers gearing up for potential liquefied natural gas exports from the BC coast. Less strong is output 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.
On the oil and liquids side, Wood Mackenzie expects tight oil growth to continue, “but we have found it extremely important to differentiate between different sub-play areas,” with well results and economics varying “dramatically,” said analysts. “Market access has become a major concern for many operators as supply growth from inland basins contends with infrastructure bottlenecks. Pipeline projects are underway to help clear new volumes to more attractive coastal markets, but these will not keep pace with supply growth. As a result, pricing discounts for inland crudes have materialized and demonstrated wide volatility.”
These volatile discounts for inland crudes have impacted returns and resulted in the use of higher-cost modes of transport, including barge, truck and rail, said analysts. More than half of North Dakota Bakken barrels are now transported via rail, but pipelines will remain the “favored mode of transportation” for many areas. Tight oil “accounts for over 40% of the US$150 billion we forecast will be spent on North America onshore developments in 2013,” said the analysts. “We expect tight oil production volumes will exceed 5 million b/d by 2019.”
Just two plays, the Bakken and Eagle Ford shales, account for more than half of the new production.
The Bakken Shale has 10 sub-plays, according to analysts, with most producer focus on the Parshall, Sanish and West Nesson/Nesson Anticline South. Those plays together are 54% of current production and “the foundation of our production outlook. Those same three sub-areas make up 70% of the remaining value modeled in the Bakken. Breakevens in the best core area of Parshall/Sanish are US$49/bbl, while some noncore area breakevens exceed US$80/bbl.”
Eagle Ford production this year should jump by 50% from 2012 to average 844,000 b/d, said analysts, who have identified nine sub-plays, led by the Karnes Trough condensate window, which “tops value and activity.” Those wells have “an oil breakeven price of US$46/bbl, the lowest of any North American resource play covered.”
Meanwhile, the rebirth of the Permian Basin, and in particular the Wolfcamp/Cline formation, remains one of the “fastest growing” tight oil regions, but it still “lacks the world-class scale of the Bakken and Eagle Ford,” said analysts. Canadian tight oil plays “offer attractive returns to the right operator,” but too “generally lack the scalability of the larger U.S. counterparts.”
For the Permian Basin to show off its incredible potential, the Wolfcamp/Cline “is a key factor in the wider growth of the Permian region,” said analysts. Production there is expected to grow over the next five years to 195,000 b/d from today’s 111,000 b/d. The play by itself now accounts for about 7% of all Permian production, but it is expected to double to 14% by 2018.
Also under the West Texas/New Mexico microscope is the Permian’s Ozona sub-play in the southern Midland Basin, and the Glasscock Nose sub-play area in the central Midland Basin, which constitute about 90% of output from the area. “Considerable upside exists as this play consists of multiple benches with much of the early activity only focusing on the B-bench.”
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