MANAGEMENT’S DISCUSSION & ANALYSIS
INTRODUCTION
The Management’s Discussion and Analysis (MD&A) highlights the primary factors that affected SaskEnergy’s consolidated financial condition and performance for the nine months ended December 31, 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 February 13, 2019 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 nine 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 asset optimization 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.
INDUSTRY OVERVIEW
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 price in the near term. Due to the high degree of uncertainty associated with weather and Alberta pipeline maintenance issues, natural gas prices in both Alberta and Saskatchewan 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 average natural gas settlement price in Western Canada, was $1.24 per gigajoule (GJ) throughout the nine months ended December 31, 2018 compared to $1.88 per GJ for the same nine months in 2017. Throughout the nine month period, pipeline maintenance in Alberta limited transportation available from AECO (Alberta) to the Saskatchewan border. This Alberta infrastructure shortage is evident by the decreased average daily settlement prices at AECO and elevated prices at TEP (Saskatchewan) and Empress (Alberta - Saskatchewan border). Multiple days of negative prices occurred in 2018 at AECO and this low priced AECO gas environment is expected to continue until at least November of 2020 when infrastructure is scheduled to start coming online, at which time a slow reversion to a higher normalized AECO price is expected provided take-away capacity improves. Traditionally, most natural gas in Saskatchewan is priced at a differential to the AECO price. This AECO to TEP differential for the nine months ended December 31 2018 averaged $1.55 per GJ compared to $0.67 per GJ for the same period the year prior creating fixed prices of $2.79 per GJ at TEP versus $2.55 per GJ. With the NGTL system constrained, cold temperatures in eastern markets, and low levels of North American storage, TEP incurred fixed settlement prices greater than $5.00 per GJ in November 2018. Conversely, warmer weather in December 2018 combined with high levels of interruptible Alberta Eastgate gas service saw a December 31 price at TEP of $2.61 per GJ.
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2018-19 THIRD QUARTER REPORT
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