TD Alberta Power: Jan-Feb Dispatch & Realized Pricing Review
Event
This flash note reviews January-February activity in Alberta's wholesale electricity
market. Wholesale prices averaged $118/MWh over the first two months of
Q1/24. This represents a 6% decrease compared with the same period in Q1/23.
Impact: NEUTRAL
We view YTD power prices and spark spreads as solid given Q1/24's relatively
warm weather, while unit output has generally been strong. TransAlta's hydro
assets have shown robust generation and pricing thus far in 2024, but investors
should bear in mind that Alberta is expected to face drought-like conditions over 2024
(potentially tempering full year hydro output relative to LTA). Q1/24 average pricing
currently looks likely to be consistent with our expectations (we assume $105/MWh
in Q1/24, before hedging). Cascade remains in commissioning but has yet to export
large volumes to the grid; we anticipate it will be into Q2/24 before it begins to have
a meaningful impact on market dynamics.
Details
Spark spreads declined 3% y/y in January-February 2024, to $98/MWh.
Realized power prices QTD, combined with recent forward pricing, would imply
a Q1/24 average price of ~$105/MWh (26% below the arguably robust Q1/23
average of $142/MWh).
Read-throughs for Capital Power. Genesee 1-3 achieved capacity factors
of 81-97% in January-February 2024 (91% overall); G1+G2 are Alberta's only
remaining coal-fired generators. We estimate that revenues from the Clover Bar
peakers (typically unhedged) increased 1% vs. the same period in Q1/24 (higher
pricing mitigating lower dispatch).
Read-throughs for TransAlta. AESO data indicates TA's Alberta hydro energy
output rose 21% y/y in January-February; we estimate energy market revenues
for TA's hydro assets increased $13 million (higher volume and realized prices).
We calculate a capacity factor for TransAlta's coal-to-gas (CTG) fleet of 62% vs.
60% in January-February 2023.
Cascade update. The revised schedule for the 900 MW Cascade combined-cycle
gas plant targets an April 30 COD; it remains in commissioning (sporadic output).
Exhibit 1 presents estimated generation and price realizations for select
Alberta units. These are estimated utilizing AESO metered volumes and pricing
data. These estimates do not include ancillary revenues (particularly relevant for
hydro units) and do not capture the impact of hedges on revenues.