Alberta has a new set of recommendations to address the growing number of oil and gas production and infrastructure assets in the province that are nearing or have passed the end of their commercial lifespan.

Following a monthslong engagement process with nearly 100 stakeholders including representatives from provincial and municipal governments, technical experts, producing companies and the service sector,  the province released its Mature Asset Strategy (MAS) report earlier this year. 

Led by industry veteran David Yager, a special advisor to the Premier, the report presents a suite of 21 major recommendations aimed at driving economic growth while protecting the environment and ensuring long-term sustainability. 

The recommendations have not yet been formally accepted by the Alberta government. 

Broadly, they aim to address the growing issue of non-payment of municipal taxes and surface leases, ensure production facilities keep operating as long as it makes economic sense, repurpose aging oil and gas assets and infrastructure where possible to generate wealth, and accelerate closure activities. 

What is a mature asset? 

The MAS defines a mature asset as an oil and gas reservoir, field or well that has been producing for an extended period and rates are declining, making it uneconomic to continue operation now or in the near future. 

This includes associated surface equipment and pipelines.

According to the Alberta Energy Regulator (AER), the province has approximately 262,000 “non-reclaimed” wells that fit into the mature asset designation.  

This includes about 94,000 wells that are “decommissioned” (wellbore cut and capped, surface equipment removed but site reclamation incomplete), about 78,000 that are “inactive” (not on production but not decommissioned), and about 91,000 that are “marginal” (producing 10 barrels of oil equivalent or less per day). 

There are also approximately 23,000 surface production facilities that are either inactive or have been decommissioned but not reclaimed, and about 174,000 kilometres of flowlines and pipelines that are decommissioned or non-operating. 

How did we get here? 

Collapsed natural gas prices are a major driver of many of the challenges facing Alberta’s mature assets, the MAS says. 

In the first nine years of this century, a total of 84,635 new gas wells were drilled in Alberta, primarily shallow gas wells in central and southeast Alberta. In 2005 alone, the figure in this region exceeded 8,000.

Alberta’s AECO-C natural gas reference price during this period averaged $5.83 per gigajoule (GJ).

Then the North American shale gas revolution happened, natural gas prices plummeted and activity changed dramatically.

As the price of oil remained stable, new horizontal drilling and reservoir completion technology unlocked vast new unconventional energy resources in the U.S. and in Alberta. 

From 2016 to 2020, the AECO-C reference price averaged only $1.68/GJ, a 71 per cent decline.

In this seven-year period only 3,790 new gas wells were drilled, reflecting the dramatically deteriorating economics.

While there was some relief in gas prices following the outbreak of the war in Ukraine in 2022, the impact on gas prices was short-lived. Alberta’s natural gas reference price last year averaged only $1.17/GJ.

On a year-over-year basis from 2005 to 2023, gas drilling in central and southeast Alberta plunged by 99 per cent.

Today more than half of Alberta’s “marginal” wells – primarily producing natural gas – are located in the province’s southeast in Cypress County, Special Areas, Newell County, Wheatland County and Kneehill County.

“Many recent insolvencies have been linked to operators holding large amounts of these types of assets,” the MAS says. 

“The producers generating attractive returns on invested capital today are generally not the same producers that own many of the mature assets.” 

Although the oil and gas industry as a whole has returned to profitability, this is only true for certain segments, the report says.  

Alberta’s oil sands, conventional oil and “wet” natural gas plays that contain high value liquids like ethane, butane and propane are now profitable. 

Dry natural gas production, on the other hand, has struggled for years to remain profitable, falling short of covering all financial obligations for many producers. 

This includes unavoidable costs like municipal taxes and surface leases, rising expenses such as carbon taxes, AER and Orphan Well Association levies, and, ultimately, the cost of shutting down and reclaiming operations.

These economic considerations are key to consider before drawing conclusions about mature assets and liabilities in Alberta, the report says. 

Resolving unpaid municipal taxes

The MAS says that during consultations, representatives of rural municipalities and private surface lease owners repeatedly asserted that “trust has been broken.” 

This sentiment stems from unpaid or reduced payments for surface lease rental fees and municipal property taxes.

“Despite record oil and gas production, significant royalty and tax contributions and substantial job creation, some producers have struggled to meet financial obligations,” the report says. 

While recognizing the need to address this challenge, the MAS emphasizes the overall value that has flowed from oil and gas operators to Albertans.   

“While several hundred million dollars in unpaid municipal taxes over the past four years has made headlines, in 2022 alone the total municipal taxation levied on oil and gas assets in Alberta was $1.6 billion,” it says. 

In 2023, Alberta’s seven largest oil and gas producers contributed approximately $24 billion to various levels of government in taxes, royalties and fees. 

In addition to low natural gas prices, limited access to capital and increasing costs have complicated the issue, the report says. 

“These challenges forced many companies into bankruptcy or financial distress, prompting cost-saving measures including non-payment of surface leases and municipal taxes.”

The MAS recommends that the province, municipalities, the Rural Municipalities of Alberta and the AER work together to establish a rapid and transparent process for addressing late or non-payment of municipal taxes.  

It also recommends re-establishing a separate quasi-judicial and independent Surface Rights Board to address the complex concerns raised by rural municipalities and private surface lease owners.

Extending production

The MAS seeks to ensure Alberta’s mature oil and gas fields remain producing for as long as economically viable because it is ultimately beneficial for all stakeholders.  

“The continued operation of all producing assets supports the economy through taxes, royalties, wages, local support businesses, and maintenance contractors,” the report says. 

Economic adjustments to existing government programs could potentially extend the productive life of mature assets and sustain these benefits. 

The MAS cites several opportunities including changes to the Enhanced Hydrocarbon Recovery Program for deploying CO2-enhanced oil recovery projects, examining waterflood techniques in shale reservoirs, and pursuing elemental carbon recovery instead of carbon capture, utilization and storage (CCUS) from existing gas plants. 

New methods for conventional oil and bitumen extraction could also increase recovery and extend the life of mature assets, it says. 

New opportunities

High transportation costs and limited market access have long kept Alberta’s oil and gas prices low.

The MAS aims to reverse this by finding ways to bring the markets closer to the source.

Natural gas, in particular, is seen as a significant opportunity.

“Repurposing central and southeast Alberta’s legacy natural gas base could materially improve the outlook for tens of thousands of assets and multiple stakeholders,” the report says. 

“Given the current surplus of natural gas in North America, the most compelling opportunity is to add value…by utilizing more of it within Alberta, particularly by converting it into electricity.” 

This can sustain and stimulate local economies, reduce waste, finance future closure activities, and provide a reliable energy source for Alberta’s grid, it says.

Opportunities for stranded or undervalued natural gas include AI data centres, local power generation to support renewables, LNG for regional use, bitcoin mining, small-scale manufacturing, agricultural operations and Indigenous enterprises. 

Existing oil and gas assets can also be repurposed for new uses including subsurface heat for geothermal power, lithium extraction from brine water, and using surface locations for solar power generation instead of undergoing full reclamation.

Accelerating closure

While many mature assets in Alberta offer opportunities for value creation through life extension, others are nearing or at the point where closure and reclamation are the most appropriate steps.

The MAS says there is a clear need to make closure operations more efficient through better planning and collaboration. 

For example, it notes that by 2024 nearly 95,000 well sites had been decommissioned but their surface locations remain unreclaimed, mainly due to cost uncertainties and often delayed timelines between completing remediation and receiving a final reclamation certificate.

“Improved coordination with expert vendors and multi-level field operations cooperation could significantly reduce unit costs without compromising compliance,” the MAS says.

It highlights the opportunity to use spring breakup (the winter melting period between late March and late May, when traditional drilling operations are paused) to focus on closure work. 

This would serve the dual benefit of keeping workers employed while making closure activities happen faster.

Because time is money, the key to cost-effective closure operations is retaining skilled and experienced field service personnel, the report says.

The MAS also envisions enabling so-called “ClosureCo” and “HarvestCo” business models. 

For a fixed sum, a ClosureCo would assume responsibility for well closure and future liabilities from the current asset licensee, while a HarvestCo would use revenue from mature assets to fund its own closure activities.

“Special purpose, multi-discipline closure service entities in the U.S. provide a business model that could be replicated in Canada,” the report says.  

Innovative financial solutions

The MAS engagement process has underscored the need to develop flexible financial instruments that manage closure costs, it says. 

The report highlights proposals including legacy asset insurance funds and asset-attached closure financial products. 

“A new post-reclamation future environmental liability insurance fund – financed by contributions from licensees but managed by the province – could provide dedicated capital for managing liabilities tied to closed assets,” the MAS says. 

“This fund would offer certainty for surface rights owners and show licensees a path to remove closure obligations from balance sheets, which could provide another justification for accelerated closure activity.”

Meanwhile, asset-attached closure funding mechanisms on wells drilled in the future are envisioned as value tied to the individual wells or infrastructure, not the licensee. 

Dedicating a small portion of future cash flow from production to closure funds would ensure costs are planned for and covered throughout an asset’s lifecycle, the report says.

This would improve the balance sheets of licensees and enable smoother asset transfers to a greater number of potential buyers that would take on the well and its attached closure fund. 

A focus on collaboration

The MAS stresses that renewed commitment to collaborative efforts among all stakeholders is essential to address the scale of closure liabilities effectively. 

It highlights examples of successful collaboration including the AER’s Area-Based Closure (ABC) program.

This approach involves grouping well sites by location to concentrate closure efforts, allowing companies to utilize workers and equipment more efficiently to reduce costs.

From 2019 to 2023, the ABC program saved an estimated $1.7 billion through regulatory improvements and coordinated closure activities, the MAS says. 

“By leveraging innovation, collaboration, and tailored financial mechanisms, Alberta can reduce the burden of closure liabilities, enhance environmental stewardship, enhance economic growth, attract capital, and foster a resilient and competitive energy sector,” the MAS says. 

“These measures will not only address the challenges of today but also position Alberta as a leader in sustainable resource management for the future.”

The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.