- We expect the commodity price shock will result in some demand destruction in Alberta, given the province's significant dependence on the energy sector. This should be mitigated by the large cogeneration component.
- Weakening demand, combined with lower power prices, will result in producers adjusting their dispatch along the power supply stack over the long term.
- Although we ultimately expect a balanced market with adequate supply, there remains some uncertainty as the market transitions.
- We expect increased cash flow volatility for TransAlta Corp. (TAC; BB+/Stable) and Capital Power Corp. (CPC; BBB-/Stable).We believe pricing discovery in 2021, and the ability to ratably hedge their economic generation, is a key credit factor for these companies.
As Alberta confronts the dual impact of the COVID-19 pandemic and the commodity price shock, S&P Global Economics forecasts that the province will experience an 11% decline in real GDP in 2020, before staging a modest recovery of about 4% in 2021. A decline of this magnitude in economic activity will affect the province's energy-only power market and Alberta's larger independent power producers (IPPs).
In this commentary, we present some of our key considerations when it comes to assessing potential risks for the companies that we rate.
History Of The Alberta Power Market
Alberta was initially set up as a competitive market, with the integrated utilities either investor- or municipal-owned, as opposed to provincially owned as they are in other parts of Canada. However, power generation in the province has always been concentrated among a few players. This concentration drove the government of Alberta to set up the first competitive exchange in Canada in 1995, with power prices set through hourly auctions.
However, large generators were exposed to the risk of low prices, and the government sought to mitigate that impact by auctioning off power purchase arrangements (PPAs). Through this mechanism, power generators would still recover their fixed and variable costs, and a rate of return, while transferring market risk to buyers. In effect, the buyers would have the right to offer the output from the volumes contracted under the PPA and could either make or lose money, depending on the difference between the prices obtained and the contracted payments owed to the power producers. The government also established the Balancing Pool to hold and manage any unsold PPAs.
The Severe Price Decline In 2016 Was Mostly The Result Of Supply Dynamics
The significant decline in power prices experienced in 2016, when they averaged just C$18 per megawatt hour (MWh), was the result of many factors, including the dynamic created with the Balancing Pool.
PPA buyers exercised their right to return the PPAs to the Balancing Pool, as they became less profitable due to lower power pool prices. This resulted in the Balancing Pool controlling a significantly higher market share.
The Balancing Pool could retain, sell, or terminate uneconomic PPAs, and had to manage the assets in a commercial manner. By failing to terminate unprofitable PPAs and offering power under a variable cost strategy, as later determined by the Market Surveillance Administrator, too much supply was put into the market.
As the last PPAs roll off in 2020, the Balancing Pool will no longer have as much influence on market prices. At that point, the right over the output will revert to the original owners.
The Industrial Nature Of Demand In Alberta Will Likely Result In Lower Load Over The Long Term
We expect there will be long-term impacts on power demand given its industrial nature. Having a higher industrial component with significant energy exposure makes demand for power more susceptible to macroeconomic shocks.
Even if the impact of social distancing measures were temporary, we believe that the pace of recovery in the energy sector will be key to long-term power demand. We anticipate a slow and uneven recovery, given the magnitude of the shock to Alberta's economy: S&P Global Economics estimates that a total of 43% of Alberta's GDP could be at risk, primarily driven by the resources sectors (26%) and social distancing measures (17%).
|S&P Global Ratings Selected Indicators|
|Alberta real GDP growth (%)||(11)||4|
|AECO Hub US$/mmBtu||2||2|
|Bbl--Barrel. WTI--West Texas Intermediate. MmBtu--Million British thermal units. AECO--Prices are rounded to the nearest $5/bbl and 25 cents/mmBtu.|
|Source: S&P Global Ratings.|
This is consistent with the conclusions drawn by the Alberta Electric System Operator (AESO) in its June 2020 report, An Update on the Impact of COVID-19 and Low Oil Prices on Alberta's Power System. Based on its slow-recovery scenario, which resembles our base-case scenario, the AESO forecasts a reduction of about 5% in 2021 from its pre-pandemic projected average internal load (AIL) or total demand (chart 1). The risk to this thesis is a K-shaped recovery, which could continue to impair demand in certain sectors of the economy for the long term, or even permanently.
The AIL is primarily composed of system load (approximately 70%), which is the demand without self-supply, and behind-the-fence (BTF) load (about 30%), which is typically served by cogeneration facilities. As most of the system load is driven by industrial demand (chart 2), we are expecting demand destruction.
However, the remaining BTF load could help mitigate the impact of this decline. Over the past 20 years, oil sands producers have built many cogeneration facilities, and they now represent about 35% of total installed capacity. As oil sands producers shut down their facilities to redeploy cash to their core operations, they will need additional power from the grid. This could mitigate the impact on demand for power producers as the load is redeployed to the system.
Lower-For-Longer Power Pool Prices, Spurred By Improved Efficiency, Will Affect Producers' Supply Decisions
Setting aside the lower demand component, power prices themselves are likely to fall, primarily because of technological changes. This is key to the profitability of power producers because, in an energy-only market, they must recover their costs through merchant prices set by the market.
The price of the marginal unit--the last unit that must be used to serve customer load--will be affected by two competing factors, the transition of the fleet from coal to natural gas and the increasing carbon tax. First, as the coal fleet transitions, the efficiency improvement will drive down power prices. Second, the carbon tax, which will rise to C$40 per tonne in 2021 from C$30 per tonne in 2020, will increase power prices to the extent there is a lot of coal-fired generation in 2021. Given that the marginal unit sets the market clearing price, as long as coal units are firing, they will set the marginal price. As a result, gas-fired units will benefit in terms of profitability.
Eventually, natural gas will displace coal as the baseload generation because coal-fired generation will be increasingly disadvantaged on the supply dispatch stack. Then, if no coal facility is firing, the marginal price will be set at the most inefficient gas facility. However, in periods where the coal units are required to meet demand, prices will rise, potentially resulting in much sharper pricing volatility given their higher marginal cost.
Overall, in the long term, we expect power prices will decline and they could be more volatile. The profitability of coal facilities will be stressed because they will dispatch less and operate at lower capacity. This, along with advancing environmental, social, and governance mandates and strategies at the companies, should incentivize IPPs to convert these units quickly to gas-fired generation.
Generators Should Be Able To Adjust Long-Term Supply To Match Forecast Conditions, Resulting In A Balanced Market
We expect that producers should be able to adjust their supply to lower power demand over the longer term. However, there is some uncertainty in the short term as supply is being adjusted to match prevailing market conditions. As noted, we see the cogeneration component as providing an important mitigating swing in supply. The decline in cogeneration electricity production, commensurate with the decline in electricity demand from oil sands producers, should help to balance the market in the short term.
Over the long term, we do not see an unbalanced market as the outcome. The market is very concentrated in terms of control: Power producers are incentivized and able to adjust their supply. As the output associated with existing long-term PPAs reverts to owners at the end of 2020 (approximately 15% of supply), the market will become even more concentrated.
The ongoing transition of coal facilities to natural gas also creates additional flexibility for producers. Facilities could be mothballed for longer or not returned to the grid. For example, TAC announced the retirement of the mothballed 368-megawatt (MW) Sundance 3. Furthermore, new projects could be delayed, such as Suncor Energy Inc.'s 800 MW cogeneration project, which has been delayed to 2025 from 2023.
The recently announced 900 MW combined-cycle power generation Cascade Power Project, scheduled to start commercial operations in 2023, is an interesting addition to the overall long-term supply dynamic, given its size and that it is backed by different players. Because of the small size of the market, oversupply can be very detrimental to profitability. We expect this project will be the exception rather than the rule, as we don't forecast a large wave of significant projects being announced. This is largely driven by our estimate that, to encourage new entry, power prices would need to be about C$55/MWh-C$60/MWh. Currently, the forward curve indicates prices in the low C$50/MWh area for 2022 and 2023.
As for the future of the supply mix, given the industrial nature of demand, firm baseload generation will remain crucial. This will likely be provided by natural gas facilities, due to the intermittent nature of renewable facilities. One interesting development for the goal of reducing emissions could be the transition to hydrogen-powered facilities. However, it is still early days, as the government is just creating its plan.
Changing Dynamics Highlight Risks For Companies
For the two IPPs that we rate, CPC and TAC, these changing dynamics could result in additional pressure on their credit metrics during our outlook horizon. While the market is undergoing this transition, both IPPs are seeing their merchant exposure to Alberta increase due to the expiry of their PPAs; it will represent their largest exposure and will be key to their credit quality. We believe the credit impact is negative even as both companies have diversified away from the province and improved their fuel diversity by expending their renewable portfolio over the past few years.
To some extent, higher merchant exposure risk can be mitigated by having in place a robust hedging program. However, the liquidity of Alberta's hedging market is limited, which makes it difficult for a producer to hedge well in advance. Therefore, although both companies are well hedged through 2020, they have limited hedging in place for 2021. This creates cash flow uncertainty. Therefore, while the impact of lower demand and declining prices has been fairly muted in 2020, we expect to see more volatility in 2021. We believe pricing discovery in 2021, and the ability to ratably hedge their economic generation, is a key credit factor for these companies.
Any increased volatility could be meaningful, as both IPPs are undertaking significant acquisitions and capital expenditures, which reduce cash flows available for deleveraging. Depending on how the projects are financed, this could result in limited room over their stated downside triggers until they start contributing to cash flows.
|Comparison Of Capital Power Corp. And TransAlta Corp.|
|Capital Power Corp.||TransAlta Corp.|
|Forward Alberta pool price as of third-quarter 2020 (C$/MWh)||2021: C$52||First-quarter 2021: C$62|
|2022: C$52||Balance of 2021: C$53|
|Hedging in place as of third-quarter 2020||2021: 13%||First-quarter 2021:44%|
|2022: 18%||Balance of 2021: 15%|
|Contracted prices as of third-quarter 2020 (C$/MWh)||2021: High-C$50||First-quarter 2021: C$60|
|2022: Low-C$50||Balance of 2021: C$55|
|Source: Capital Power Corp. third-quarter 2020 report and TransAlta Corp. third-quarter 2020 presentation.|
This report does not constitute a rating action.
|Primary Credit Analyst:||Viviane Gosselin, Toronto + 1 (416) 5072542;|
|Secondary Contact:||Aneesh Prabhu, CFA, FRM, New York + 1 (212) 438 1285;|
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: firstname.lastname@example.org.