The Canadian well drilling forecasts are in and 2018 appears to be shaping up as a modest improvement over 2017, with oil prices expected to continue to hover in the mid-$50 range and natural gas to remain under $3. But the industry is upping the pressure on governments and regulators to lower regulatory compliance costs, help boost investor confidence and improve market access (read, hurry up and get pipelines built).

First up is the Petroleum Services Association of Canada, which reported late in October, predicting a total of 7,900 wells (rig releases) to be drilled in Canada in 2018 up from 2016’s revised forecast of 7,550 wells.

“The small uptick in activity we realized in the first-quarter of 2017 has carried on through the year. Budgets set with initial optimism for a gradual climb in prices by year-end continue with their plans as drilling and completion efficiencies improve,” Mark Salkeld, president, said, which expects that growing interest in the huge liquids-rich natural gas fields in Alberta and British Columbia should support a 4% to 5% increase in oilfield activity.

The Canadian Association of Oilwell Drilling Contractors (CAODC) isn’t nearly as confident, forecasting a small increase in wells drilled to 6,138 (an increase of 107 from 2017), 70,587 more operating days (an increase of 1,234), while the rig fleet is expected to decrease by 19 totaling 615.

CAODC said operating days are a key economic indicator for the industry and the expected uptick for 2018 bodes well for companies hit hard by almost three years of downturn; increases for rig day rates are still hard to come by.

“Right now our members are offering a premium product for discounted rates just to survive,” Mark Scholz, association president, said, adding that “a sustained period of low to no cash flow” has made it difficult for drillers to access the capital they need to maintain equipment and buy new rigs.

Splitting the baby more or less in the middle is the Canadian Association of Petroleum Producers (CAPP), which is forecasting 6,800 wells drilled in Western Canada in 2018. The big story for CAPP is the drop in upstream capital spending, from a peak of $81 billion 2014, bottoming out in 2016 at $38 billion before rising 19% in 2017 and expected to plateau in 2018.

While prospects in the oil patch have improved, they’re not great and fingers are being pointed at government pipeline policy and environmental regulations as factors that increase industry costs—affecting its competitiveness.

“What we need most is the optimism a strong investment climate will create,” Scholz said. “Market access and a predictable regulatory environment are the most significant factors in creating an environment that will allow our industry to deliver stronger results in the coming years.”

Energy economist Blake Shaffer thinks the drillers association’s argument is half right. He recently refereed an upcoming CD Howe Institute paper that compared the cost of regulation and policy across a variety of North American jurisdictions, if they were applied to a representative well in the Montney Basin in northwestern Alberta.

The study found that capital taxes and royalties are uniform across the jurisdictions, even though they’re implemented differently in Canada and the U.S.

“As a result of Alberta’s royalty review, the policy costs of our royalties, at least for the marginal well, the one that we’re concerned about for investment, dropped significantly. Our average take is staying constant, but the marginal effects of the tax rate [are] dropping,” Shaffer said.

Municipal property taxes, on the other hand, have a much bigger impact than what is commonly understood.

“Property taxes fly under the radar. It’s not the first thing we think about when we think of taxes on oil and gas, but it’s a significant component,” Shaffer said, noting that the property tax system within Alberta is very complex.

“The amount of tax at the municipal level for linear infrastructure and other facilities varies greatly. What’s considered linear infrastructure [pipelines] versus a facility? There’s definitely scope for improvement to our competitiveness just on making that a lot more uniform.”

A favorite target of the Alberta-based industry is the provincial carbon tax, but the study found the effect of environmental levies to be negligible.

“Environmental taxes are often cited as a big impediment to Alberta, but what this report finds is that, compared to all these other policy costs, it’s relatively trivial. It’s a very small component of overall policy costs,” Shaffer said.

The study estimates the cost to oil sands producers at about $0.30 a barrel (bbl) and $1/bbl to $2/bbl for conventional oil and gas depending upon emission intensity.

“Compared to the cost of capital taxes/royalties or property taxes, environmental taxes are certainly the smallest of the three,” Shaffer said.

Both the industry associations and the economist agree that growing production coupled with an already constrained pipeline system is a major problem. Shipping crude oil by rail to U.S. markets can add $5/bbl to $10/bbl to a product that is already heavily discounted against West Texas Intermediate.

“The cancellation of TransCanada’s Energy East pipeline is another blow to investor confidence in Canada,” Salkeld said. Pointing to delays faced by Kinder Morgan’s (NYSE: KMI) 525,000 barrel per day Trans Mountain Expansion project from Alberta to the west coast,.

“The cancellations of key energy infrastructure projects, and further delays to those already approved, send a message to potential investors that Canada’s rules and regulations around these projects are subject to continuous change at a moment’s notice,” Scholz argued.

The watchword for 2018 appears to be uncertainty—in markets, with pipeline projects, surrounding provincial and federal policy and regulation—that combined will mute growth in the Canadian oil and gas industry.

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