Home Business of Energy Time For A Fresh New Look At Alberta’s Oil & Gas Future

Time For A Fresh New Look At Alberta’s Oil & Gas Future

David Yager

With common sense finally returning to the future of fossil fuels, Alberta has a remarkable opportunity to switch from defense to offense.

Instead of reacting to external event as we’ve done for years, we should again become masters of our own destiny.

Fifteen years ago, there was talk about increasing oil sands output to five million barrels per day and beyond. But this was eclipsed by the oil price collapse, pipeline obstruction, climate concerns and the declaration of war on fossil fuels by too many western governments.

This century started with natural gas paying the rent for Alberta. But because of huge quantities of new supplies of methane from shale gas plays across North America, the gas business tanked. There were great plans for LNG exports, but with the exception of one project, this opportunity has gone nowhere.

Frequently discussed but never fully understood is what it means to be in the oil and gas business for over 100 years and accumulate several hundred thousand separate producing assets of all shapes and sizes that at some point must be properly decommissioned. Alberta has never before been in cleanup mode on this scale.

Within Alberta there has been a major geographical shift in activity from the central and southeast regions to the oil sands and light tight oil and natural gas liquids plays in western and northwestern regions of the province.

This has dramatically changed the economic and taxation landscape for half the province. What we hear most on this file is how producers are delinquent on their property taxes and surface rights leases. The collateral damage of lost jobs, taxes and the complete retooling of the oil service industry has not been properly framed.

Alberta likes to blame losing control of its hydrocarbon destiny on external forces in Canada, the U.S. and internationally. There is massive evidence that this is indeed the case. The thesis of the “energy transition” is that that the sooner Alberta is out of the oil and gas business, the better the world will be.

But some of our problems are home grown. The first oil sands emissions cap regrettably originated in Alberta in 2015 courtesy of NDP Premier Rachel Notley. It is now the federal law of the land.

There are many other issues within Alberta that have made the oil and gas industry less successful than it could be otherwise.

Things changed big time for Alberta in 2022. The Great Reset as proposed by the World Economic Forum in 2020 has been replaced by the Great Reality Check. That’s when the invisible hand of Adam Smith slapped the world in the head and reminded consumers and policy makers that energy price, supply and demand still matter.

As a result, in 2023 the major issue with energy is cost and supply, not carbon content. Despite the continued chorus from climate alarmists that the world is doomed unless we immediately do what they say, there is growing acknowledgement that fossil fuels are going to be around a lot longer than hoped or planned.

A great analysis from Goldman Sachs energy guru Jeff Currie last October summed it up. He noted that in 2012 fossil fuels provided 82 per cent of the world’s primary energy. Ten years later, and after investing US$3.8 trillion in replacement renewable energy sources, the figure was reduced to 81 per cent.

Whatever you’ve heard and been told – and whether or not this should be the case – Alberta is going to be in the oil and gas business for a long time.

It will be different of course because of an evolving resource base, technologies and society’s expectations of what a responsible environmental footprint looks like in the 21 century.

But as a province, we should review all aspects of the industry to find the areas where we can improve operations and opportunities without asking anybody for permission.

This hasn’t been done for a long time.

Alberta’s oil and gas business has changed much more than how it is managed and regulated.

Many government departments like finance, education and transportation have been doing essentially the same thing the same way for a long time.

Energy is different because it changes continuously. Today, Alberta is trying to run a 100-year-old business with a patchwork of overlapping and conflicting regulations from multiple sources. This hampers competitiveness and impairs growth.

What energy consumers want to know now is what Alberta can deliver in terms of increased hydrocarbon output produced in the most environmentally responsible way possible.

How can we do everything better?

The oil sands producers are ahead of the curve. Perhaps that’s because they have been criticized the most and have the greatest production volumes at stake. The Pathways Alliance has developed an ambitious but expensive plan to materially reduce production emissions through a combination of CCUS and possibly lower carbon heat from Small Modular Nuclear Reactors.

Natural gas is more challenging. What is not well known is that in 2020, 6.4 bcf/day, or 54 per cent of all gas consumed in Canada, was used in Alberta. Of that, 84 per cent was “industrial” as heat for oil sands recovery, petrochemical feedstock and electricity generation.

But supply has shifted. With prices down and operating costs up, the traditional areas of development in central and southeast Alberta have been all but abandoned for new supplies from the massive light tight gas and liquids reservoirs like the Montney and Duvernay in northwest Alberta.

This has caused a myriad of problems that were not anticipated. Big new gas volumes from the opposite end of the province have exposed the shortcomings in the Nova Gas Transmission Ltd. gathering system. This has collapsed spot gas prices to previously unimaginably low levels in the past three years. That caused significant financial pain on many fronts.

The lack of new drilling and the maturity of the gas producing assets is affecting municipalities in central and southeast Alberta. In 2005 there were 8,801 new gas wells drilled in this region. In 2021 the figure was only 52. The oil services sector in Medicine Hat, Brooks, Taber and Drumheller has been clobbered resulting in lost jobs and commercial activity.

Fewer wells and the amount of new land required for development has squeezed municipal property taxes and surface rights payments on private lands. Back in the day this was a reliable source of non-voter tax revenues, and a welcome income supplement for agricultural producers.

But the gas crash created new issues like unpaid municipal taxes and access payments. With production volumes down and prices still not what they were when many of the wells were drilled, these costs impair the industry’s competitiveness.

Decommissioning Alberta’s legacy production asset base is a source of regular study and concern, but the subject is much more complex that reciting “polluter must pay.”

In 2021 there were over 360,000 individual producing assets including over 300,000 wellbores and surface locations (oil, gas, bitumen, inactive, partially reclaimed), 47,000 gas and oil processing facilities, eight oil sands mines, 25 in-situ bitumen projects, and eight heavy oil upgraders.

As the number of assets has increased, so has the regulatory complexity and cost of what is expected for satisfactory decommissioning. As cash flow from existing production declines, more producing assets are rendered uneconomic thus increasing the mature asset reclamation base.

This is a death spiral that nobody has thought through. As available funds for decommissioning liabilities falls as the industry contracts – as per the master energy transition plan away from fossil fuel – the number of assets requiring decommissioning rises.

Miraculously, oil and gas is supposed to go out of business and leave nothing unreclaimed behind. No industry in world history has ever done this.

The most obvious solution is a fiscal and regulatory regime to keep as many of these assets commercially viable as long as possible. The rest need further study to ensure costs and expectations are reasonable.

The last big issue is competitiveness. The 2022 Fraser Institute’s North American oil and gas competitiveness report put Alberta 12th among 15 U.S. states and Canadian provinces. This is a measure of operating costs, regulatory complexity and returns on invested capital.

Alberta ranks above only Alaska, Colorado and B.C., three jurisdictions well known for their environmental protection zealotry.

Saskatchewan ranks number six behind Wyoming, Texas, Oklahoma, Kansas and North Dakota. It operates under the external parameters as Alberta.

When Premier Ed Stelmach’s disastrous 2007 New Royalty Framework was replaced in 2010, government and industry conducted a comprehensive competitiveness review to ensure Alberta continued to be an attractive destination for oil and gas investment capital.

Revisiting this after 12 years is hardly a radical idea.

With a provincial election coming, the future of the oilpatch should become a major economic policy issue.

Former Premier and NDP leader Rachel Notley is now pledging “stability” after doing the exact opposite in 2015.

Based on the foregoing, more of the same is hardly an attractive option.

Reviewing everything and charting a new future for Alberta’s oil and gas industry is a much better idea.

David Yager is a Calgary oil service executive, energy policy analyst, writer and author. He is President and CEO of Winterhawk Casing Expansion which is commercializing a new methane emission reduction technology. His 2019 book From Miracle to Menace – Alberta, A Carbon Story is available at www.miracletomenace.ca.