Exploring the regulatory maze (Part 2): Mine Financial Security Program

On 6 May the Minister of Environment and Parks, Jason Nixon announced a program review on the Mine Financial Security program (MFSP).  According to the news release, “(A)s of June 30, 2020, $1.48 billion was being held in security under the MFSP. Oilsands mines account for just under $1 billion of this total.” The program “helps manage coal and oilsands liabilities by collecting financial security from mine owners and protects the public from paying for project closure costs” (emphasis added). In addition to security deposits, the oilsands producers “use their reserves as collateral for financial security.”

This promise from Nixon to protect the taxpayers was backed up by Laurie Pushor, the new CEO of the Alberta Energy Regulator. In a one-year on the job interview with The Canadian Press’s Bob Weber , Pushor stressed  oil and gas wells will be cleaned up despite the backlog. Pushor did acknowledge past problems saying the regulator had watched company failures which had positive ratings. “We think there will be an opportunity for us to be more diligent in protecting the interests of Albertans if a company is in failure.”

We’ll be taking a look at the claim that the program protects the public from paying for “closure costs” and whether producer reserves are indeed adequate to ensure the public does not pay.  

Program Review

Ostensibly the program review is to ensure that “appropriate funds are being collected to cover reclamation liabilities and ensure continuous program improvement.” The review focusses on the calculation for the security, including feedback from the Auditor General and the impact of “extremely low oil prices in 2020.” The one-page description cites the concerns of the Auditor General and in apparent deference to industry pressure is 

“making a change in the interim to the calculation while the review is underway,” Details on program consultations with stakeholders and indigenous peoples are to be released in the coming weeks. 

Auditor General’s concerns

This program review stems from a July 2015 report of the Auditor General which outlined, according to the Alberta Energy Regulator (AER which currently administers the program), five concerns.  These concerns are characterized by the AER as:

• Reserves estimate treats proven and probable reserves as equally valuable
• The resource asset valuation calculation applies a forward price factor to the average netback for the last three years, which assumes that oil prices and operating costs move proportionally
• The resource asset valuation calculation does not reflect risks associated with the future economic value of the reserves
• Some oil sands mine operators include in–situ (non–mining) production areas in their asset calculations
• Oil sands mine operators are able to amend the areas covered by their mine approvals or combine multiple mines into one potentially extending reserve life and size.

These are substantive issues that have waited 6 years and two governments to address.  It is curious that suddenly this program review surfaces at a time when oil prices have recovered strongly and yet there is concern that the 2021 payment will skew unreasonably the calculation for the oilsands security requirement.

Auditor General’s (OAG) Report

The summary best conveys the difference in tone between AER’s take on the issue and the OAG’s. 

What we found:

There is a significant risk that asset values calculated by the department are overstated within the MFSP asset calculation, which could result in security amounts inconsistent with the MFSP objectives. The MFSP asset calculations do not incorporate a discount factor to reflect risk, use a forward price factor that underestimates the impact of future price declines, and treat proven and probable reserves as equally valuable.

Why this is important to Albertans

From the detailed OAG report is the observation:

The MFSP is not designed to respond quickly to sudden fluctuations in the price of oil. This was a deliberate decision made by the department to avoid potentially widely fluctuating security amounts from year to year. If an abrupt financial and operational decline were to occur in the oil sands sector it would likely be difficult for an oil sands mine operator to provide this security even if the need for the security was identified through the program. It is important to recognize that the department has accepted the risk of not protecting against a broad based and rapid structural decline in the oil sands sector, having designed the program with the intent of capturing what they believe are a reasonable range of economic conditions. (Emphasis added)

Below we highlight many of the detailed concerns that were pointed out by then Auditor General Merwan Saher. 

Current MFSP System

The intent of the program is to protect both Alberta taxpayers and the environment. The history of the program goes back to 2011, about a decade after the massive expansion of the oilsands began.  This timeframe roughly corresponds with the completion or near completion of major oilsands developments such as Imperial Oil-Exxon’s Kearl Lake project and Shell’s Albian Sands operations. While Environment initiated the program, the administration of the program was transferred from that department to the AER in March 2014.

The program falls under the Environmental Protection and Enhancement Act. According to the AER’s website, the total deposit amount as of 30 September 2020 was $939 million for oilsands producers and $547 million for coal producers. These security deposits are either in the form of cash or letter of credit guarantees. A letter of credit is a financial instrument issued by a bank or other financial institution which is an irrevocable promise to pay when the holder wishes to claim the security deposit. This would typically be when the operator stops operations and/or goes bankrupt leaving the security to pay the reclamation costs. The letter of credit is backed by the promise of the obligor (oilsands company) to make good on the ultimate cash payment. For the bank’s guarantee of ultimate payment to the government the bank collects a guarantee fee, usually a small percentage of the letter of credit or guarantee.

There are four types of security deposits: 1) base security deposit “used to maintain the security and safety of the site until another operator assumes responsibility for the project or until all infrastructure is removed and the site is reclaimed;” 2) operating life deposit to cover risks which coincide with the end of a mine’s operation.  This is triggered when there are less than 15 years of reserves remaining; 3)  asset safety factor deposit is triggered when a project’s asset to liability ratio falls below 3.0; and 4) outstanding reclamation deposit when a company fails to meet an approved reclamation plan target.

Assets to Liability Ratio

Central to the MFSP is the assets to liability ratio. To understand this ratio, one must understand what is defined as an asset and a liability.  This may sound simple but it is not. There is a 72-page Guide to the Mine Financial Security Program which was just updated. Appendix 2 is a definitional section that is 10 pages long. Appendix 3 called “Principles Guiding Development of the MFSP,” is a list of “shoulds” which purportedly will “guide the behaviour of government and the industry” and includes both assertions or assumptions. Every one of these statements could be interpreted by officials, courts, or industry is any variety of ways. A typical example of a “should””

The MFSP should provide appropriate liability protection for the public at a reasonable cost to industry.

A typical assumption is:

Resources under development represent an asset of the approval holder (generating net revenues) and an asset of the province (generating tax and royalty revenues), and should be considered as such when assessing the extent to which outstanding reclamation liabilities should be secured by deposits.

Definition of Assets and Liabilities

According to the Guide, assets represent the “estimated financial capability of an approval holder’s (e.g. operating company) project to address its future obligations.” The asset amounts “should be derived from each approval holder’s publicly filed annual financial reports.” Assets include the project’s gross proven and provable or probable reserves by the three-year average annual netback and then multiplying the result by a factor that is based on the projected future commodity price. Reserves and provable reserves must be prepared by a qualified reserves auditor or evaluator. The calculation must be done in accordance with Canadian and U.S. securities laws. Reserves may be calculated using constant dollar or forecasted prices. Reserves also include in-situ bitumen operations. This designation was questioned

In spite of the OAG’s reservations about using probable reserves 6 years ago, this practice continues. Nor is discounting of future estimated cash flow required. This status quo approach is labelled conservative in spite of project operator’s reduced ability to attract capital necessary to further develop projects. Developing projects whether conventional or unconventional has been the lifeblood of the oil and gas industry for a century. With ESG investing in ascendance, this system of setting security requirements is outmoded.

Netback is gross revenues minus operating costs of the project divided by the annual sales for the project excluding gains or losses from hedging activities.  Operating costs exclude transportation costs, depreciation, exploration costs but include royalties and production costs.

The central formula for MFSP assets is N × R × F where N is the netback, R the reserves, and F the forward price factor. The greater the netback and reserves the larger the assets and therefore the lower likelihood that further security needs to be pledged.

The forward price factor is a key determinant in the determination of the project’s financial capability. For oilsands projects the factor is based on NYMEX’s WTI average price.  The factor is posted on the AER’s website at the beginning of each calendar year. The most recent factor is 0.87. The asset calculation must be certified by the approval holder’s CEO or CEO or designated representative.

Implications for oilsands operators

There are now major caveats about oilsands development peppered through securities filings and investor presentations which raise concerns about stranded assets and whether the large oilsands operators will remain “going concerns.” This question should be on the forefront of AER regulators whose mandate is to ensure the reclamation liabilities are not socialized on the backs of Alberta taxpayers. This concern is particularly important given the fact of the exit of large energy companies from the oilsands in the past five years. Exits include Shell, Total, and Chevron. Industry consolidation is down to four corporations: Suncor, Imperial Oil, Cenovus (merging with Husky), and CNRL. Below we examine the last filing of the four major players for the MFSP and other financial regulatory filings.

2020 Filings

AER reported on its website six corporate filings and eight oilsands projects reported with total security of $939.3 million.  

In the case of Suncor, “Beginning in 2020, due to increasing integration of the company’s assets, the company revised the presentation of its operating netbacks from an individual asset view to an aggregate product view of Bitumen, and SCO and diesel to better reflect the integration among the company’s assets.” For fiscal year 2020, Suncor’s operating netback was $11.37 and varied quarterly from -$4.24 to $17.89. This compared to a netback of $33.35 in 2019. Suncor did not report its reserves in its annual financial report rather deferring to its filings to securities regulators. In  the company’s 2020 Annual Information Form. Suncor reported 1.377 billion in proven mining and in-situ bitumen reserves and 773 million in provable reserves.

For CNRL, the company did not disclose information on netbacks for bitumen for the Horizon and AOSP sites. In the case of Cenovus, netback was separately disclosed for Foster Creek and Christina Lake sites.  Foster Creek’s 2020 netback fell to $8.93 in 2020 down from $27.93 in 2019 and $19.07 in 2018. For Christina Lake the 2020 number fell to $10.40 from $27.52 in 2019 and $20.20 in 2018.

 

 

 

 

Imperial Oil does not report netbacks. Most relevant to the calculation of financial capability is the reserves figures. in its earnings release for the 2020 fiscal year reported

Under the SEC definition of proved reserves, certain quantities that qualified as proved reserves at year-end 2019, primarily proved bitumen reserves at Kearl and Cold Lake, will not qualify as proved reserves at year-end 2020 (approximately 2.2 billion barrels of bitumen at Kearl and approximately 0.6 billion barrels at Cold Lake)…The company does not expect the operation of the underlying projects or its outlook for future production volumes to be affected by a downward revision of reported proved reserves under the SEC definition. In the SEC disclosure document, Imperial Oil dropped its reserve estimates massively as the following paragraphs indicate.

Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors, including completion and optimization of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, changes in the amount and timing of capital investments, royalty frameworks and significant changes in oil and gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the company’s capital spending and also impact its partners’ capacity to fund their share of joint projects.

As a result of low prices during 2020, under the U.S. Securities and Exchange Commission definition of proved reserves, certain quantities of bitumen that qualified as proved reserves in prior years did not qualify as proved reserves at year-end 2020. Amounts no longer qualifying as proved reserves include 2.2 billion barrels of bitumen at Kearl and 0.6 billion barrels of bitumen at Cold Lake. Among the factors that could result in portions of these amounts being recognized again as proved reserves at some point in the future are a recovery in the SEC price basis, a further decline in costs, and / or operating efficiencies.

These numbers seem to be contradicted by a CBC News report of 25 February 2021 which stated that Imperial was cutting one billion barrels from its inventory of oilsands bitumen. The discrepancy appears to be related to Imperial and Exxon’s reporting for the Securities and Exchange Commission when Exxon simultaneously “where reserves were all but eliminated, dropping from 3.86 billion barrels to just 81 million barrels.”  

Given these disclosures one has to question whether the AER is indeed being conservative in permitting probable or proved reserves should be included in the calculations. In the case of Imperial Oil, 2.8 billion of proved reserves have been removed.

Great Uncertainty

There is great uncertainty now in the oilsands business and fossil fuel industry in general.  This week saw several notable events at oil majors. Engine 1 an American hedge fund management was able to humble giant EXXON-Mobil getting two directors appointed to the board of directors.  In the Netherlands, in a lower court ruling Royal Dutch Shell was told to change its meagre net-zero plans to conform with the Paris commitments.  Chevron was also impacted with a shareholder vote to cut emissions from its oil and gas products. Additionally, there are about 1400 lawsuits in the United States seeking justice from polluters, including suits launched by state and local governments.

This uncertainty will continue. Below is an excerpt from the PWC audit report to Cenovus shareholders.

The principal considerations for our determination that performing procedures relating to the impact of reserves and resource estimates on the recoverable amounts of the Oil Sands and Conventional CGUs and on DD&A expense for the Oil Sands and Conventional segments is a critical audit matter are (i) the significant amount of judgment required by Management, including the use of Management’s specialists, when developing the estimates of reserves and resources and the recoverable amounts; (ii) there was a high degree of auditor judgment, subjectivity, and effort in performing procedures relating to the significant assumptions used in developing these estimates including forward commodity prices, expected production volumes, quantity of reserves and resources, future development and operating expenses, as well as discount rates; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.(Emphasis added.)

Regulatory Filings- Alberta Energy Regulator
Company/Project	Financial Security ($millions)	Asset safety factor	Planned Reclamation	Completed Reclamation
CNRL-Horizon	61.2	47.4	0	121
CNRL-Joslyn North	26.4	N/A	N/A	N/A
Canadian Natural Upgrading-Jackpine	72.4	30.93	4.9	90.8
Canadian Natural Upgrading-Muskeg River	111.3	23.18	28.7	64.5
Fort Hills Energy Corporation (Cenovus)	39	4.6	0	0
Imperial Oil Resources Ventures-Kearl Lake	64.7	5.97	11	0
Suncor Energy Inc.-Base Operations	359	12.7	68	83.4
Syncrude Canada Ltd.- Mildred Lake-Aurora North*	205.3	4.06	200	341
Totals	939.3		312.6	700.7
Syncrude Canada is 58.7 % owned by Suncor, 25 %  owned by Imperial Oil, 9/03 % by Sinopec and 7,23 % by CNOOC.
Source: https://static.aer.ca/prd/documents/liability/AnnualMFSPSubmissions.pdf Accessed 24 May 2021.

 

From the above table we see that the oilsands industry has spent roughly $1.6 billion in pledged security and reclamation expenditures against a liability officially estimated by AER of about $32 billion. Future spending on reclamation activity is $312 million. A 2018 internal estimate by Wadsworth for oilsands-related reclamation was about $120 billion. The question becomes: is it realistic for the government, and Alberta taxpayers, to expect that Suncor (Baa3), CNRL (Baa2) and Cenovus (Baa3) all with low investment grade ratings to pay for the massive reclamation liabilities of oilsands mines, upgraders and facilities?

Below we examine the fiscal capacity of these three large Canadian producers by examining their balance sheets to determine under a most probable reclamation scenario whether the AER, on behalf of the Alberta taxpayer, will be adequately secured if in a worst case scenario the company goes bankrupt, that is a stranded asset scenario.

 

Financial Capacity of Canadian Oilsands Producers
Company	Current assets- Current liabilities ($millions)	Property Plant and Equipment (Oil &Gas)  ($millions)	Long-term Debt  ($millions)	Asset Retirement Obligations  ($millions)	ARO- undiscounted  ($millions)	Deferred Income Taxes  ($millions)	Current market Capitalization ($millions)
Cenovus	617	25,411 (21,465)	7,441	1,248	n/a	3,234	19,790
CNRL	-717	65,752 (45,710)	20,110	5,861	n/a	10,144	49,590
Suncor	-1,163	68,130 (42,709)	13,812	9,794	14,100	8,967	42,030
Sources: Audited financial statements for year ended 31 December 2020.
Cenovus- As at December 31, 2020, the undiscounted amount of estimated future cash flows required to settle the obligation is $4,953 million (2019 – $5,173 million), which has been discounted using a credit-adjusted risk-free rate of 5.0 percent (2019 – 4.9 percent) and an inflation rate of two percent (2019 – two percent). Most of these obligations are not expected to be paid for several years, or decades, and are expected to be funded from general resources at that time.
CNRL-The Company’s asset retirement obligations are expected to be settled on an ongoing basis over a period of approximately 60 years and discounted using a weighted average discount rate of 3.7%
Suncor- A weighted average credit-adjusted risk-free interest rate of 3.10% was used to discount the provision recognized at December 31, 2020 (December 31, 2019 – 3.30%). The credit-adjusted risk-free interest rate used reflects the expected time frame of the provisions. Payments to settle the decommissioning and restoration provisions occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 50 years.

 

What is notable about this table is the similarity between the market capitalization of these producers and the estimated value of their oil and gas reserves (highlighted). From the audited statements point of view and the official AER liability of $32 billion which includes Imperial Oil’s liability, there appears to be adequate security. Is the audited number for decommissioning expense of asset-retirement obligations a reasonable number?  Given the long-term nature of the production reserves which are expected to be productive for another 30-60 years, the AER has accepted the company’s version and assumptions.

But are the assumptions credible and are they available to the public to scrutinize? The degree of detail from the regulator and company is lacking.  Critical assumptions would include the cost of future capital programs; demand for oil; commodity prices; future production; and discount rates.

How long will be production continue to operate profitably?

How are the asset retirement obligations arrived at for the purposes of the audited financial statements? This statement in Cenovus’s is hardly revealing:

Provisions are recorded for the future decommissioning and restoration of the Company’s upstream assets, refining assets and crude-by-rail terminal at the end of their economic lives. Management uses judgment to assess the existence and to estimate the future liability. The actual cost of decommissioning and restoration is uncertain and cost estimates may change in response to numerous factors including changes in legal requirements, technological advances, inflation and the timing of expected decommissioning and restoration. In addition, Management determines the appropriate discount rate at the end of each reporting period. This discount rate, which is credit adjusted, is used to determine the present value of the estimated future cash outflows required to settle the obligation and may change in response to numerous market factors. (Emphasis added.)

• What are the assumptions used for determining the AER’s official number?
• Are these estimates available by project?
• Why aren’t regulatory filings required under the MFSP not made public?

There remain many more questions to be asked and answered to give Alberta taxpayers assurance that oilsands tailings ponds, mines, and facilities will be decommissioned properly and the land restored to its pre-extraction state. The timing to give the large oil sands producers a break because of low oil prices flies in the face of the regulator’s position of using a three-year average to smooth payments. It has been nearly six-years since the Auditor General issued his report with his critical findings. It is important for the government and regulator to begin to restore confidence in the liability rating system (both oil and gas and MFSP) and the adequacy of the financial security. Given the tremendous uncertainty over the medium- and long-term financial viability of the fossil fuel industry, it is no longer acceptable for Alberta taxpayers to trust the word of governments, government regulators and companies in the absence of better disclosure.

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