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, 2017. 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 14, 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 2016-17 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 2016-17 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 2017-18 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.
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, takeaway 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, weather typically has the greatest impact on natural gas prices in the near term. Due to the high degree of uncertainty associated wi th weather, natural gas prices can be 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 monthly index, the benchmark price for natural gas in Western Canada, settled at $2.04 per gigajoule (GJ) for the month of December 2017. Throughout the nine months ended December 31, 2017, market prices fluctuated greatly. During the summer pipeline maintenance in Alberta limited transportation available from AECO to the Saskatchewan border. However, a transformational change occurred in the fall, 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 any excess transportation capacity in Alberta to the Saskatchewan border quickly being fully contracted. Essentially, TransCanada Pipelines NGTL system in Alberta needs to expand its system capacity in order for more natural gas leave Alberta. Until more NGTL capacity is made available, large volumes of natural gas may be trapped in Alberta. The index declined from $3.07 per GJ at the end of March 2017 to $2.04 per GJ at the end of December 2017. Although this was only a 34% per cent decline in the nine month period as noted in the AECO Monthly Index Historical Prices chart, within this time frame AECO prices were extremely volatile, with prices trading negative (less than $0.00/GJ) on a few days. Traditionally most natural gas in Saskatchewan had been priced at a differential to the AECO price and typically traded between $0.05 per GJ and $0.20 per GJ higher than AECO. However, with the NGTL system constrained, AECO – TEP differentials were much higher and volatile, resulting in TEP natural gas trading anywhere between $0.60/GJ and more than $10/GJ higher than AECO prices on rare occasions this winter.
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2017-18 THIRD QUARTER REPORT
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