Management Discussion and Analysis
OPERATING ENVIRONMENT SaskEnergy monitors a number of important factors that could influence financial performance. Energy Infrastructure Uncertainty
Another quarter into the global pandemic and the energy complex continues to look towards higher energy demand post-pandemic. Oil prices have fully recovered their 2020 losses and have moved up to levels not seen since late 2018. Price increases have not been limited to energy with many commodities (primarily grains) at multi-year highs; most notably, perhaps, lumber futures have finally began to fall after nearly quadrupling off of their 2020 lows. Regulatory uncertainty remains a significant concern as the Keystone XL pipeline project was cancelled in June after its presidential permit was rescinded five months earlier. The cancellation limits future export capacity for Alberta’s oil sands, but incremental capacity is still expected from the Trans Mountain expansion to the West Coast, whose construction has continued after a brief delay to mitigate potential damage to migratory bird populations. South of the border, the U.S. Army Corps of Engineers is expected to complete an environmental impact assessment on the Dakota Access Pipeline by 2022; this is notable as these assessments typically occur prior to construction, but the line has been active since 2017. Current court rulings allow the line to remain in-service awaiting the results of the assessment, though that status remains at risk due to pending legal challenges. Regulatory uncertainty is not confined to high-profile oil pipelines, as local gas projects are also affected. In a near identical situation as the NGTL 2021 Expansion delay that directly impacted SaskEnergy contracts, NGTL’s Edson Mainline project was approved by the federal government after an extended delay. SaskEnergy has no contractual association with this project, but benefits from facilities that balance supply and demand in Alberta. Impacts from the NGTL 2021 Expansion delay will finish in the second quarter with a curtailment expected in August. Natural Gas Demand The prior fiscal year ended with lower expectations for gas demand driven by customer de-contracting and lower utilization of remaining contracts. With the economy continuing to recover and an improved outlook for agri-business development, forecasted demand has now stabilized for the next few years. Local supply continues to trend toward increased dependence on associated gas, leaving local supply highly dependent on the volatile global oil market. With higher prices, rig activity in the province has improved, but not enough to expect gas supply increases. Natural Gas Prices After a moderate winter, summer had a relatively extreme start. Excessively high temperatures and exceptional drought conditions through much of the Southwest United States (US) resulted in high natural gas use for electricity generation. Further east, exports into Mexico increased year-on-year, and LNG takeaways from the Gulf coast to Europe and Asia were maximized. This incremental demand resulted in high natural gas prices and reduced injections into storage – compounding high prices with growing concern about storage balances moving into winter. Price levels increased to the point where there was switching from natural gas back to coal for power generation in Eastern US – even as coal-to- natural gas switching in Europe was contributing to the high demand for LNG. Some relief may come to demand for LNG as Russia’s Nord Stream 2 pipeline begins service to Europe and as hurricane season potentially limits tanker traffic in the Gulf. In Alberta, the extreme heat resulted in impacts to receipts more characteristic of a cold winter day and also caused unplanned outages at compressor stations. The resulting curtailments generally resulted in prices increasing with periods of extreme volatility. Looking forward, some Alberta curtailments are still expected through the remainder of summer as delayed projects are finally placed into service. Barring complications with storage injections, these curtailments should have minimal impact to SaskEnergy and its customers. The AECO daily index averaged $2.93 per GJ throughout the first quarter compared to $1.89 per GJ the year prior — the largest portion of the difference coming from prices increasing through the latter part of the quarter. The end of the quarter also saw extreme volatility with a single day range on June 28 of $3.77 to $4.90 as the market processed production uncertainty through the heat. Traditionally, most natural gas in Saskatchewan (TEP) is priced at a differential to the AECO price. This AECO to TEP differential for the quarter averaged $0.01 per GJ premium compared to flat the year prior. After years of volatility, the differential has found relative stability, but may see some volatility through the remaining summer as import curtailments take effect.
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