S&P Global Ratings considers the regulatory frameworks for electricity and natural gas transmission facility owners (TFOs) and distribution facility owners (DFOs) in Canada’s Alberta province to be predictable and stable. This results in our assessment of Alberta regulation–which is administered largely by the Alberta Utilities Commission (AUC), the key source of our information–as highly credit supportive (strong/adequate). We evaluate jurisdictions by the qualitative and quantitative factors that affect the regulatory advantage for the utilities we rate. We view the regulatory assessment as the single most important factor in assessing a regulated utility’s competitive position (see “Key Credit Factors For The Regulated Utilities Industry,” Nov. 19, 2013).
|Key Factors Of The Alberta Regulatory Framework (Electricity And Gas)|
|Regulation under the AUC has been in place since 2008, with the performance-based regulation (PBR) framework used for DFOs since 2013 and a cost-of-service (COS) framework for TFOs.|
|Predictable and mostly transparent framework; DFOs are on their second generation of PBR, with well-defined parameters.|
|Tariff-setting procedures and design|
|The tariff structure is stable and aims for fair returns for utilities.|
|Renumeration for TFOs and DFOs allows for investment recovery, financial renumeration, and ongoing operational expense recovery, with minimal exposure to commodity risks.|
|Utilities can recover most costs.|
|Regulatory independence and insulation|
|The AUC is a regulatory body independent from the government, with no indications of material political interference.|
The AUC is an independent, quasi-judicial tribunal that regulates the province of Alberta’s utility sector, including electricity, natural gas, and water. It is also responsible for setting and approving rates charged by utilities as well as ensuring utilities deliver safe and reliable services. The AUC was established in 2008, following the passage of the Alberta Utilities Commission Act.
Other supervisory bodies.
The Office of the Utilities Consumer Advocate (UCA) was established in 2003 by the Alberta government to represent utility consumers in the regulatory rate proceedings. UCA represents the collective interests of Alberta’s small business, farm, and residential electricity, natural gas, and water consumers. One collective representative for these consumers makes the regulatory process more efficient.
Alberta Electric System Operator (AESO).
Established in 2003 via the Electric Utilities Act, AESO’s core responsibilities include developing and operating the wholesale energy market, developing the electricity transmission system, overseeing access of the transmission system for both generation and load customers, and operating the power grid. AESO is governed by an independent board, which is appointed by the Minister of Energy, and regulated by the AUC.
Transmission facility owners.
Electric TFOs are responsible for transferring electricity from generation facilities across high-voltage power lines to the distribution network. The AUC regulates the TFO tariffs, while the AESO is responsible for the planning of new transmission infrastructure. In Alberta, about 26,000 kilometers of transmission lines bring power to over 4 million people. The major TFOs in Alberta are AltaLink L.P., ATCO Electric Ltd., ENMAX Power Corp., and EPCOR Utilities Inc. AltaLink L.P. serves 85% of Alberta residents and owns more than half of the provincial transmission system.
Gas TFOs own the transmission pipelines that transport natural gas from gas processing facilities to the distribution systems. The major regulated natural gas TFOs in Alberta are ATCO Gas & Pipelines Ltd. and Apex Utilities (formerly known as AltaGas Utilities Inc.), and these are regulated by the AUC.
The AUC regulates many aspects of gas utility pipelines, including approving new pipeline construction, setting the gas transportation rate, and establishing regulations for the design, construction, operation, and retirement of gas utility pipelines. The AUC only regulates intra-provincial gas utility pipelines operating within Alberta. The Canada Energy Regulator (which replaced the previous regulatory body known as the National Energy Board) regulates any interprovincial or international pipelines.
Distribution facility owners.
Electric DFOs are responsible for maintaining and operating the local distribution network. Electricity from the high-voltage power lines are transformed to a lower voltage and passed through the distribution lines before reaching customers. The AUC regulates the DFO tariffs. The major DFOs in Alberta are ATCO Electric Ltd., FortisAlberta Inc., ENMAX Power Corp., and EPCOR Utilities Inc.
Gas DFOs own the gas distribution network that delivers gas to the end users. They are responsible for operating and maintaining the distribution network as well as building new distribution infrastructure where required. Gas DFOs tariffs in Alberta are also regulated by the AUC. Major gas DFO players in Alberta include ATCO Gas and Apex Utilities.
As Alberta has a deregulated electric and natural gas market, most consumers can choose which utility is their energy provider. If consumers don’t want to sign up with any competitive retailers, they can always stay with the default regulated rate option (RRO) that is provided by the electric distribution utility servicing the customer’s respective area. As a result, electric distribution utilities are the default RRO provider for their respective service area. However, they have the option to outsource or divest this retail operation to another energy retailer if they want to, and some utilities in Alberta have done so. The equivalent of the RRO for natural gas is the default rate tariff (DRT).
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).
|Alberta’s Regulatory Frameworks|
|Regulated entity||Rated entity||Operations||
|AltaLink L.P.||AltaLink L.P.||Transmission||COS|
|ATCO Electric Ltd.||CU Inc.||Distribution||PBR|
|ATCO Electric Ltd.||CU Inc.||Transmission||COS|
|FortisAlberta Inc.||FortisAlberta Inc.||Distribution||PBR|
|ENMAX Power Corporation||ENMAX Corp.||Distribution||PBR|
|ENMAX Power Corporation||ENMAX Corp.||Transmission||COS|
|EPCOR Distribution and Transmission||EPCOR Utilities Inc.||Distribution||PBR|
|EPCOR Distribution and Transmission||EPCOR Utilities Inc.||Transmission||COS|
|ATCO Gas and Pipelines Ltd.||CU Inc.||Distribution||PBR|
|ATCO Gas and Pipelines Ltd.||CU Inc.||Transmission||COS|
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.
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.
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.
|Major RRO Providers In Alberta|
|Regulated entity||Rated entity||RRO provider|
|ATCO Electric Ltd.||CU Inc.||Direct Energy Regulated Services|
|FortisAlberta Inc.||FortisAlberta Inc.||EPCOR Energy Alberta GP Inc.|
|ENMAX Power Corp.||ENMAX Corp.||ENMAX Energy Corp.|
|EPCOR Distribution and Transmission||EPCOR Utilities Inc.||EPCOR Energy Alberta GP Inc.|
|ATCO Gas and Pipelines Ltd.||CU Inc.||Direct Energy Regulated Services|
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.
Related Criteria And Research
This report does not constitute a rating action.
No content (including ratings, credit-related analyses and data, valuations, model, software or other application or output therefrom) or any part thereof (Content) may be modified, reverse engineered, reproduced or distributed in any form by any means, or stored in a database or retrieval system, without the prior written permission of Standard & Poor’s Financial Services LLC or its affiliates (collectively, S&P). The Content shall not be used for any unlawful or unauthorized purposes. S&P and any third-party providers, as well as their directors, officers, shareholders, employees or agents (collectively S&P Parties) do not guarantee the accuracy, completeness, timeliness or availability of the Content. S&P Parties are not responsible for any errors or omissions (negligent or otherwise), regardless of the cause, for the results obtained from the use of the Content, or for the security or maintenance of any data input by the user. The Content is provided on an “as is” basis. S&P PARTIES DISCLAIM ANY AND ALL EXPRESS OR IMPLIED WARRANTIES, INCLUDING, BUT NOT LIMITED TO, ANY WARRANTIES OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE OR USE, FREEDOM FROM BUGS, SOFTWARE ERRORS OR DEFECTS, THAT THE CONTENT’S FUNCTIONING WILL BE UNINTERRUPTED OR THAT THE CONTENT WILL OPERATE WITH ANY SOFTWARE OR HARDWARE CONFIGURATION. In no event shall S&P Parties be liable to any party for any direct, indirect, incidental, exemplary, compensatory, punitive, special or consequential damages, costs, expenses, legal fees, or losses (including, without limitation, lost income or lost profits and opportunity costs or losses caused by negligence) in connection with any use of the Content even if advised of the possibility of such damages.
Credit-related and other analyses, including ratings, and statements in the Content are statements of opinion as of the date they are expressed and not statements of fact. S&P’s opinions, analyses and rating acknowledgment decisions (described below) are not recommendations to purchase, hold, or sell any securities or to make any investment decisions, and do not address the suitability of any security. S&P assumes no obligation to update the Content following publication in any form or format. The Content should not be relied on and is not a substitute for the skill, judgment and experience of the user, its management, employees, advisors and/or clients when making investment and other business decisions. S&P does not act as a fiduciary or an investment advisor except where registered as such. While S&P has obtained information from sources it believes to be reliable, S&P does not perform an audit and undertakes no duty of due diligence or independent verification of any information it receives. Rating-related publications may be published for a variety of reasons that are not necessarily dependent on action by rating committees, including, but not limited to, the publication of a periodic update on a credit rating and related analyses.
To the extent that regulatory authorities allow a rating agency to acknowledge in one jurisdiction a rating issued in another jurisdiction for certain regulatory purposes, S&P reserves the right to assign, withdraw or suspend such acknowledgment at any time and in its sole discretion. S&P Parties disclaim any duty whatsoever arising out of the assignment, withdrawal or suspension of an acknowledgment as well as any liability for any damage alleged to have been suffered on account thereof.
S&P keeps certain activities of its business units separate from each other in order to preserve the independence and objectivity of their respective activities. As a result, certain business units of S&P may have information that is not available to other S&P business units. S&P has established policies and procedures to maintain the confidentiality of certain non-public information received in connection with each analytical process.
S&P may receive compensation for its ratings and certain analyses, normally from issuers or underwriters of securities or from obligors. S&P reserves the right to disseminate its opinions and analyses. S&P’s public ratings and analyses are made available on its Web sites, www.standardandpoors.com (free of charge), and www.ratingsdirect.com and www.globalcreditportal.com (subscription), and may be distributed through other means, including via S&P publications and third-party redistributors. Additional information about our ratings fees is available at www.standardandpoors.com/usratingsfees.
Any Passwords/user IDs issued by S&P to users are single user-dedicated and may ONLY be used by the individual to whom they have been assigned. No sharing of passwords/user IDs and no simultaneous access via the same password/user ID is permitted. To reprint, translate, or use the data or information other than as provided herein, contact S&P Global Ratings, Client Services, 55 Water Street, New York, NY 10041; (1) 212-438-7280 or by e-mail to: [email protected]