Why We See Alberta’s Electricity And Gas Regulatory Framework As Highly Credit Supportive

Regulatory Stability

When assessing regulatory stability, we review the transparency of the key components of rate setting, the predictability of the framework, and the consistency of the framework over time. The AUC publishes details of all hearings and rationales, and it works with consultants if there are any potential regulatory changes, providing transparency in the process. This was evident with the transition to a performance-based regulation (PBR) framework for DFOs in 2013 as well as the AUC’s current efforts to improve regulatory and administrative efficiencies.

From a predictability standpoint, the AUC switched to a PBR framework in 2013 for DFOs and has been operating under it ever since. For TFOs, the utilities have been operating under a COS framework for more than a decade, providing a track record of stability and predictability in the tariff framework.

Other important rate-making parameters–such as the deemed capital structure and return on equity (ROE)–have been consistent across the electric and natural gas TFOs and DFOs, with a 37% equity layer and an 8.5% ROE for 2021. For Apex Utility, the deemed capital structure is slightly higher at a 39% equity layer. The AUC does not use a formulaic approach to devise these parameters, it instead determines them through generic cost of capital (GCOC) proceedings. In the GCOC proceedings, utilities and the UCA present the AUC evidence based on many influencing factors, including utilities’ finances and credit ratings, credit markets, and macroeconomic aspects, which provides some degree of predictability and transparency. Furthermore, the authorized ROE and capital structure have not changed materially over the past years. Throughout the years, the equity thickness has fluctuated within about 350 basis points (bps), and the ROE has varied by 45 bps.

Tariff-Setting Procedures And Design

When assessing the tariff-setting procedures and design of a regulatory framework, we analyze whether all operating and capital costs are fully recoverable in a timely manner, the balance of interests and concerns of all stakeholders affected, and whether incentives are achieved and contained.

Design of regulatory frameworks. 
In Alberta, utility rates are typically set under the COS or the PBR frameworks. Rates for electric and gas TFOs are set under a COS framework. For DFOs, the rate-setting framework transitioned to a PBR framework from COS in 2013 (see Table 2).

COS framework. 
In our view, the COS regulatory approach provides a stable regulatory framework and very stable cash flow for utilities. Under this approach, the utilities can recover most of their costs, earn a modest return on capital, and recover capital deployed. Companies typically provide their forecasted revenue requirements for a two-year period. The regulator will test them for reasonableness, thereby allowing utilities to recover reasonable expenses. If a utility’s performance deviates from the forecast, the subsequent forecasted period will reflect the under- or overperformance. Companies that use the COS framework will typically be able to seek rate relief for unexpected costs from the regulator.

PBR framework. 
The PBR framework is currently in its second period, a five-year rate plan for the duration of 2018-2022, which is largely similar to the first period. Under this framework, DFO utilities are subject to an annual rate adjustment intended to account for inflation and some costs beyond management control (see Chart 5).

The PBR framework also includes a re-opener provision that allows utilities to reset the base rates if they are under or over the authorized threshold, eliminating large swings. The current threshold for re-opener is +/- 300 bps of the approved ROE for two consecutive years or +/- 500 bps of the approved ROE for any single year. In addition, there is an efficiency carryover mechanism that provides up to 0.5% additional ROE carrying over into the subsequent PBR term. This encourages utilities to continue to make cost-saving investments near the end of the term.

The PBR framework–and more specifically its formulaic annual rate adjustment mechanism–provides both transparency and predictability to returns on investment (ROI) as well as reduces utilities’ exposure to regulatory lag.

Although Alberta has some of the lowest authorized ROEs and equity ratios among North American jurisdictions, most utilities in the province have been able to at least earn the authorized ROE.

We believe the AUC’s mandate continues to balance the interests of both customers and the regulated service providers. Overall, we consider Alberta’s tariff frameworks as highly credit supportive. The frameworks allow a utility to recover their prudently incurred operating and capital costs as well as earn the authorized returns on investment.

Financial Stability

When assessing the financial stability of a regulatory framework, we look at the timeliness of cost recovery and cash-flow volatility, how much flexibility there is in the framework to allow the recovery of unexpected costs, the attractiveness of the framework to long-term capital, and capital support during periods of heavy investments.

Commodity cost recovery and cash-flow volatility. 
One of the largest expenses to utilities is commodity costs. Under the RRO regulation for electric DFOs, the regulator sets a new RRO rate each month based on a month-forward electricity price. This leaves RRO providers susceptible to both price and volume risks, specifically differences in forward prices and forecasted consumption and the actual price and consumption. The AUC does not allow the use of adjustment mechanisms such as true-ups, rate riders, or deferral accounts to reconcile the costs for electricity purchases with the revenues collected from customers. Instead, RRO providers may include a risk margin that offsets potential volume, price, and credit risks. Historically, they have been able to recover the electricity costs with minimal impact on cash-flow volatility.

Similar to the RRO rate for electricity, for natural gas DFOs, there is the DRT for consumers who do not want to sign up with a competitive gas retailer. However, unlike electric DFOs, natural gas DFOs can true-up or use deferral accounts to reconcile price and volume differences, minimizing exposure to price and volume risks.

In terms of the base rates, electric DFOs have a portion exposed to volume-metric risk, but this is partially mitigated by a fixed component that does not vary month-to-month. By contrast, electric TFOs have the revenue requirement set by AESO and are paid in 12 equal installments each year with annual true-ups.

Although the tariff framework is generally supportive of cash flow, utilities in Alberta are exposed to the risk of absorbing the undepreciated capital cost of stranded assets due to extraordinary retirements, commonly known as the utility asset disposition (UAD) issue. While this issue remains ongoing and there have not been material disallowances, it does suggest the risk that prudently incurred capital costs by utilities might not always be fully recovered in rates.

Recovery of unexpected costs. 
In terms of ability to recover unexpected costs, the PBR model includes a Z-Factor that allows utilities to recover prudently incurred unexpected costs, subject to a materiality threshold that is greater than the dollar value of a 40-basis point change in ROE. Utilities that operate under a COS model would typically be able to seek relief for unexpected costs.

Cash-flow support during heavy construction periods. 
The Alberta regulator has shown willingness in the past to provide cash flow support to utilities during construction to alleviate funding and cash flow pressure during periods of heavy investments. This was noticeable from 2012 through 2015, also known as the Big Build period in Alberta, when some utilities were allowed to earn a return on construction work in progress in rate base, boosting operating cash flow.

Regulatory Independence And Insulation

When assessing regulatory independence and insulation, we look at the market framework, how the law preserves and separates the regulator’s powers, as well as any risks of political intervention. In many jurisdictions, the role of the regulator is to set and regulate rates and service standards with due regard to all stakeholders including customers, utility operators, investors, and other constituents as well. How politics could influence regulation helps us evaluate a regulatory environment around political and economic risks.

Since 2008 when the AUC formed, there have been several shifts in political power in Alberta, and each ruling government has had its own energy policies and objectives. However, in each instance, we have not observed noticeable evidence of government interference in the rate-setting process.

The AUC’s structure consists of commissioners, including a chair, that are all appointed by the Alberta government through an order in council. The chief executive of the AUC, appointed by its chair, is responsible for leading the implementation of overall organizational strategy and day-to-day operations of the AUC. We view the separation of duties between the chief executive and commissioners as generally supportive because it allows the commissioners to focus on adjudicating applications. Furthermore, we generally consider government-appointed commissioners subject to legislative approval as generally more supportive of credit quality than commissioners that are directly elected by voters paying utility bills.

Regulatory Impact On Utilities’ Credit Quality

The four pillars of regulatory advantage– regulatory stability, tariff-setting procedures, financial stability, and regulatory independence–are the key elements in Alberta’s natural gas and electricity regulatory environment. We view the Alberta regulatory environment overall as highly credit supportive to utility operators. This has been evident over the past several years, when many utility operators have established track records of recovering their operating and capital costs and have earned close to or above authorized ROEs.

Nonetheless, there are some shortcomings to the regulatory environment in Alberta. The UAD and asset utilization issues can affect predictability of rate recovery of capital investments. This can create friction between the AUC and Alberta utilities. The very low authorized ROEs and equity ratios as compared to other jurisdictions across North America may not justify the risks Alberta utilities face and hinders the attractiveness of long-term capital to the sector. Furthermore, delays in some AUC decisions have increased regulatory lag, slowing rate recovery and cash flow predictability.

We could review our regulatory assessment on Alberta for multiple reasons including:

• The AUC improves and establishes a track record of rendering decisions in a timely manner, reducing regulatory lag.
• The AUC addresses the UAD issue such that there’s more certainty on the recovery of prudently incurred capital spending.
• There is a loss of regulatory independence or instances of political interference in the framework.
• Any material changes in regulation likely to decrease transparency, consistency, and timely recovery of costs.
• Material increases in provincial or sovereign risk factors that could negatively affect the utility’s financial compensation.

However, there are signs that the regulatory environment could stabilize or improve. The AUC is the middle of a transformation and has recently accepted all but one recommendation to address regulatory lag made in a report by an independent expert. In addition, since the appointment of a new chair in June 2020, key regulatory decisions (such as the GCOC proceeding for 2021) have been made more quickly than previous decisions. We will continue to monitor AUC developments on the proposed action plan to improve efficiency and reduce regulatory and administrative burden as well as other changes in Alberta regulation.

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