SaskEnergy Second Quarter Report - September 30, 2018



The Management’s Discussion and Analysis (MD&A) highlights the primary factors that affected SaskEnergy’s consolidated financial condition and performance for the six months ended September 30, 2018. Using financial and operating results as its basis, the MD&A describes the Corporation’s past performance and future prospects, enabling readers to view SaskEnergy from the perspective of management. This MD&A is presented as at November 19, 2018 and should be read in conjunction with the Corporation’s condensed consolidated financial statements, which have been prepared in accordance with International Accounting Standard (IAS) 34 Interim Financial Reporting using accounting policies consistent with International Financial Reporting Standards (IFRS). For additional information related to the Corporation, refer to SaskEnergy’s 2017-18 Annual Report. The following discussion contains certain forward-looking statements that are subject to inherent uncertainties and risks, which are described in the Risk Management and Disclosure section of SaskEnergy’s 2017-18 Annual Report. All forward-looking statements reflect the Corporation’s best estimates and assumptions based on information available at the time the statements were made. However, actual results and events may vary significantly from those included in, contemplated by, or implied by such statements. The volume of natural gas delivered to customers is sensitive to variations in the weather, particularly through the prime heating season of November to March. Additionally, changes in market value adjustments may cause significant fluctuations in net income due to the volatility of natural gas prices. Therefore, the condensed consolidated financial results for the first six months of 2018-19 should not be taken as indicative of the performance to be expected for the full year. In order to compare financial performance from period to period, the Corporation uses the following measures: income before unrealized market value adjustments, realized margin on commodity sales, and realized margin on gas marketing sales. Each measure removes the impact of fair value adjustments on financial and derivative instruments and the revaluation of natural gas in storage to the lower of cost and net realizable value. These unrealized market value adjustments vary considerably with the market prices of natural gas, drive significant changes in the Corporation’s consolidated net income, and may obscure other business factors that are also important to understanding the Corporation’s financial results. The measures referred to above are non-IFRS measures, in that there is no standardized definition, and may not be comparable to similar measures presented by other entities.


Natural gas prices are set in an open market and are influenced by a number of factors including production, demand, natural gas storage levels, take-away capacity and economic conditions. Given the high demand for natural gas to heat homes and businesses during the cold winter months, and the demand for natural gas to produce electricity for air conditioning during the summer months, weather typically has the greatest impact on natural gas prices in the near term. Due to the high degree of uncertainty associated with weather and recent Alberta pipeline maintenance issues, natural gas prices in western Canada have been very volatile. Natural gas market fundamentals remain in a strong supply position relative to demand over the last number of years due to the advancements in shale gas production. The AECO 5A Spot price for natural gas in Western Canada, had a weighted average price of $1.10 CAD per GJ for the quarter ending September 30th 2018, with a settlement price on September 30th of $2.25 CAD per GJ. Daily and weekly changes in pipeline maintenance in Alberta caused volatility that facilitated the continued lower level pricing in the AECO natural gas market for the majority of the quarter. The end of September saw small amounts of increased pricing because of low storage levels in Alberta and cooler than normal temperatures. One year AECO pricing also continued encroaching extremely low levels at below $1.60 CAD per GJ. A transformational change occurred regarding natural gas transportation in the fall of 2017, when the National Energy Board approved a long-term fixed price contract from Empress (Alberta/Saskatchewan border) to Dawn (Ontario) on TransCanada's mainline. This event resulted in transportation capacity from Alberta to the Saskatchewan border becoming fully contracted. TransCanada Pipelines’ NGTL system in Alberta appears to need expansion of its export capacity in order to meet customer/industry requirements. Until more NGTL capacity is made available, some natural gas is effectively trapped in Alberta resulting in low AECO prices relative to the rest of the continent. Natural gas in Saskatchewan is priced at a differential to the AECO price and has historically traded between $0.05 per GJ and $0.20 per GJ higher than AECO. However, with the NGTL system constrained, the Saskatchewan price differential to AECO has been higher and more volatile, resulting in natural gas prices in Saskatchewan trading between $0.09 per GJ and $2.00 per GJ higher than the AECO price.



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