Famed New York Yankee catcher Yogi Berra once quipped that “It’s tough to make predictions, especially about the future.” This Yogi-ism is a pretty apt description of the situation surrounding the oil and gas industry in Colorado. The exact outlook for the region in terms of oil and gas production is cloudy, but none of it looks very good.

Producers and midstream operators have been investing heavily in the D-J Basin for the past 18 years. This level of activity has seen Colorado become the sixth-largest oil producer in the country, hitting a record 450,000 barrels per day (bbl/d) in April 2018. The state is also the eighth-largest natural gas producer in the U.S.

However, the region is facing several headwinds when it comes to maintaining this growth. The first of these is the increasing likelihood that SB19-181 passes and the other is the strength of other domestic oil and gas plays.

The Colorado State Senate’s passage of SB19-181 will make it more difficult to produce oil and gas as this bill gives the state government more oversight and power over the industry. These include providing more direct authority by local agencies over land use and permitting, well siting, as well as reviewing air quality and emission regulations.

Considering the wide-ranging authority that this bill will give to the state, it creates a great deal of uncertainty for producers. Even before this bill’s passage, production out of the Rockies was expected to decrease with Stratas Advisors (a Hart Energy company) forecasting a large overbuild in the region as producers look to other regions with better economics.

“Simply put, we believe oily producing regions other than the Rockies will capture increasing more drilling and completion capital expenditures due to the other plays having more attractive economics underpinned by relatively lower costs, juicier and more extensive producing field pay zones, greater recovery, and closer and less costly access to domestic and global refining markets,” the company said in a recent research report, “Overbuild Underway in Rocky Regional Crude Outbound Capacity?”

According to Greg Haas, director, integrated oil and gas, at Stratas Advisors, some other plays are more attractive because of a combination of lower drilling/completion costs and higher productivity and/or greater proximity to in-region demand or direct access to export infrastructure.

Since local demand doesn’t match production coming out of the region, it’s likely that Rockies production will be moved to other regions. “The resource is beyond the demand and needs of the Rocky Mountain region. Monetizing such great resources means moving the regional production to other domestic or even export markets,” Haas told Hart Energy.

According to the report, crude and condensate production out of the Rockies is expected to peak in fourth-quarter 2021 at 566,000 bbl/d. This will be well under the potential total crude takeaway pipeline capacity of 2.2 million bbl/d that includes existing capacity and capacity under development on open season.

“It’s not a foregone conclusion that there is or will be an overbuild. What is clear to us is that there are too many project announcements that are being bantered about in the press. The reported number of takeaway projects is too great given the growth in actual production we expect. The potential overbuild we see could be avoided this week or next if the overhang of projects in the press log is reduced by cancellation, delay, or a combination of both,” Haas said.

He added that some liquids pipelines in the region will be able to be repurposed for other hydrocarbon liquids, such as how SemGroup Corp. is converting a portion of the White Cliffs Pipeline from crude oil to NGL service.

“There will be more storage built at existing hubs to handle new in-region production as well as flow-through volumes such as those coming from Canada or the Bakken as they enter the Rocky Mountain region and leave bound for Cushing or the Southwest,” Haas said.

The increased oversight by the state may result in a further dichotomy between production and takeaway capacity with the greater uncertainty over investments. “It looks like this legislative torpedo to the industry could sink our forecasts and could be the trigger for not only upstream industry contraction in the region, but also midstream industry contraction and press log project cancellations,” Haas said.

“The midstream industry over the last five to seven years or so participated in the greatest U.S. boom in new production of all hydrocarbon classes. From oil to gas to NGLs, the resources are now known to be here on U.S. soil and midstream developers are seeking to connect supply with demand. The problem for the Rockies is that this region has relatively limited regional in-market demand growth and the broader market in the Midwest or Gulf Coast is being targeted by other hydrocarbon rich plays with greater proximity or lower development costs,” Haas added.

Stratas Advisors also thinks that the Rocky Mountain region may see an influx of new exports of Canadian crude over the next three years arriving from Canada, sent under the three-year crude by rail marketing program now being kicked off by the Government of Alberta. At its peak, the program intends to move 120,000 bbl/d out of Alberta by rail.

Haas added, “We think the Rocky Mountain refining network or close-by refineries of the neighboring states down to the Panhandle region of Texas and Oklahoma could develop into an attractive and relatively short-haul destination market for these Alberta crude-by-rail runs. If that happens, the rail movements could free up space for crude to move in existing pipelines. So even rail is competing with Rocky Mountain pipeline utilization at present. The shorter the crude-by-rail haul is, the shorter the cycle time for the run. And that means better rail economics. That puts the Rockies refiners in the first bullseye to the south for Alberta’s rail program.”