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Weakening Commodity Prices And Demand Will Require Alberta Energy Producers To Adjust To A New Reality


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Weakening Commodity Prices And Demand Will Require Alberta Energy Producers To Adjust To A New Reality

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 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%).

Table 1

S&P Global Ratings Selected Indicators
2020f 2021f
Alberta real GDP growth (%) (11) 4
Brent US$/bbl 40 50
WTI US$/bbl 35 45
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.

Chart 1


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.

Chart 2


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.

Table 2

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
2023: C$51
Hedging in place as of third-quarter 2020 2021: 13% First-quarter 2021:44%
2022: 18% Balance of 2021: 15%
2023: 12%
Contracted prices as of third-quarter 2020 (C$/MWh) 2021: High-C$50 First-quarter 2021: C$60
2022: Low-C$50 Balance of 2021: C$55
2023: Low-C$50
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;

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