New study reveals property taxes, pipeline capacity biggest challenges to oil and gas industry, not “regulatory uncertainty” or environmental levies
The Canadian well drillers have released their 2018 drilling forecast, which reflects a steady as she goes state of affairs while prices hover around $50 WTI and the oil patch slowly gets back to work after two or three pretty horrific years. But you can tell elections are coming in 2019 because the industry’s notoriously conservative politics are on full display as association president Mark Sholz takes aim at the Alberta and Canadian governments. A few of those criticisms are on the mark, but a forthcoming study shows that many of them miss the target by a wide margin.
Let’s start with the numbers. The Canadian Association of Oilwell Drilling Contractors expects that next year will see 6,138 wells drilled (an increase of 107), operating days of 70,587 (an increase of 1,234), and a decrease in the drilling rig fleet from 634 to 615.
The association says operating days are a “key economic indicator of the health of the sector” and it appears from the mild uptick in that category that the drilling and service rig market has bottomed out.
But many drillers are coming back from a long way down. When oil prices nosedived in late 2014, the first thing producers did was call in their service companies and hammer them for discounts.
Odin Waldal is the owner of Calgary-based Lonestar Drilling, which has a combined workforce of about 60 staff and consultants. When the downturn hit, there was plenty of supply and much less demand: “The pricing was very aggressive ,so obviously we had to drive down pricing. The field staff, which probably took the biggest cut of anybody, some of those guys are working for half of what they did previously.”
But because he had managed prudently during the good times not taking on too much debt to buy new equipment, Waldal says he was able to maintain a 5o per cent utilization rate and generate enough cash flow to make ends meet during the downturn.
“Right now our members are offering a premium product for discounted rates just to survive,” says Scholz. “The combination of low commodity pricing and the cumulative costs of government policy have been detrimental to say the least.”
Alberta has no control over global oil prices, but the cost of regulations – especially carbon taxes and other climate mitigation policy – has been a sore point for industry.
The Canadian Association of Petroleum Producers released a study in July that claimed “industry continues to face mounting costs and barriers to growth due to changes in provincial and federal government policies and regulations such as methane emissions, carbon pricing, municipal and corporate tax increases, wetland policy, well liability and closure, and caribou management, among others.”
“The upstream oil and natural gas industry provides many benefits to Albertans but continues to face challenges and barriers to growth and success, including policy and regulatory challenges at both the provincial and federal levels,” said Tim McMillan, CAPP president.
Shaffer 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 came to three surprising conclusions.
The first is that the largest financial burden, corporate (or capital) taxes and royalties, are pretty uniform across the jurisdictions. Even though they’re implemented differently in Canada (by the Crown) and the United States (private landowners), the costs don’t vary much.
“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 is dropping,” said Shaffer.
The second conclusion of the study is that municipal property taxes have a much bigger impact than 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,” said Shaffer, who notes 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.”
The third conclusion is that environmental levies, such as the Alberta carbon tax, are “trivial.”
“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,” he said.
The study estimates the cost to oil sands producers at about $0.30 a barrel and $1 to $2 per barrel 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.
But the biggest cost burden for Alberta producers, the one that dwarfs all others, is the lack of pipeline capacity, which the study calculates can add $5 to $10 a barrel if crude oil has to be shipped by rail.
This was certainly a focus for the drillers association, which called it one of the “biggest hurdles” facing industry.
“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,” said Scholz, who said he is disappointed with the “current approach of some policymakers.”
Scholz certainly has a legitimate gripe about the Trudeau Government’s haphazard “modernization” of the National Energy Board and the last minute decision to include the assessment of downstream greenhouse gases in the 1.1 million b/d Energy East review.
Readers will recall my columns pointing out that this fall Ottawa stacked the deck against the Trans Canada project because with the 830,000 b/d Keystone XL – an alternate route was recently approved in Nebraska – back on the table thanks to the Trump Administration, the Liberals did not want to fight a 2019 election in Quebec in the midst of an unpopular pipeline project review.
But his complaints about minor delays to construction of the 530,000 b/d Trans Mountain Expansion from BC municipalities refusing to issue permits and legal challenges from the BC government and First Nations are just posturing.
No reasonable observer of the Kinder Morgan project expected construction to proceed without a hitch given the widespread opposition in the lower mainland of BC.
And let’s not forget the federal approval of the 390,000 b/d upgrade to Enbridge’s Line 3, which is facing delays from Minnesota regulators that has nothing to do with Canada.
The three pipeline projects total 1.65 million b/d of crude oil shipping capacity, enough to accommodate existing production and expansion of the Alberta oil sands to 2030. All three are being vigorously supported by the Canadian and Alberta governments.
We certainly understand the well drillers’ frustrations.
Scholz’s members have taken it on the chin over the past three years, with low to no cash flow and capital to maintain equipment and re-invest in their businesses hard to come by.
But as energy economist Blake Shaffer has explained, the association president has mixed up the real causes of his industry’s woes. Oh, and low oil and gas prices, which are the real cause of Alberta’s problems over the past three years, get only a passing mention.
Perhaps Scholz and his organization would be better served focusing on the real pressing issues, like property taxes, which would provide support to those members like Waldal who have survived the worst of the downturn and are hoping to prosper if good times are around the corner.