Capital Expenditures


Updated March 2018

This section provides an overview for capital expenditures:

Figure 1.10

  • After two straight years of deep spending cuts, total capital expenditures in the oil and gas sector increased in 2017 despite a continued decline in oil sands spending.
  • Total capital expenditures increased by an estimated 26 per cent in 2017 to Cdn$33.6 billion as producers pursued efficiencies that increased the return per dollar of capital spent.
  • Capital expenditures are forecast to decline in the oil sands sector in 2017 as oil sands producers continue to defer new projects and expansions in the short term, focusing instead on maintenance and lowering costs.  
  • Capital expenditures in the conventional oil and gas sector are expected to increase throughout the forecast period as producers focus on shorter-cycle developments.
  • Consistent with our commodity price forecast, and with projected activity in the oil sands, conventional oil, and natural gas sectors, capital expenditures are not expected to return to the peak levels seen in 2014 over the forecast period.

Figure 1.10 [Tableau] shows historical and projected capital expenditures in Alberta’s conventional oil and gas and oil sands sectors. Capital expenditures for development of conventional oil and gas fell to an estimated Cdn$11.2 billion in 2016 from Cdn$16.3 billion in 2015. This contrasts with the sector’s strong growth from 2009 to 2014, when capital expenditures increased from Cdn$12.0 billion in 2009 to Cdn$26.7 billion in 2014.

Although exploration and production companies continued to cut costs in 2017, expenditures were driven by a significant increase in the number of wells drilled and associated completion costs, field equipment costs, and land sales.

Heading into 2017, the number of crude oil wells drilled in Alberta increased, with 245 wells drilled in January, an 88 per cent increase from December and up by 177 wells over January 2016. The strong trend in crude oil wells drilled continued throughout the year, with wells drilled in 2017 outpacing wells drilled in 2016. Natural gas wells drilled were also higher in 2017 than in 2016, with drilling up 43 per cent in January compared with December and 62 per cent higher than January 2016. In conjunction with drilling increasing in Alberta, equipment sales increased as oil and gas companies started to reinvest in machinery. Much of Alberta’s equipment is sold to the oil and gas industry, with oil and gas field equipment typically accounting for 40 to 60 per cent of overall sales. As activity started to increase in the oil and gas sector, economic activity in Alberta also started to pick up, with the Alberta Activity Index in the first eight months of 2017 up over last year’s levels by an estimated 5.6 per cent. As economic activity in Alberta picked up, inflation in Alberta also started to increase and was up 1.3 per cent year over year in October.

Land sales in conventional oil and gas also increased significantly compared with 2016, and sales in the first nine months of 2017 surpassed full-year land sales in 2015 and 2016. Land sales indicate that producers continue to invest in formations such as the Cardium and Lower Mannville for crude oil and the Montney and Upper Mannville for natural gas. These development areas typically generate positive returns with shorter payout periods.

Over the forecast period, capital expenditures are expected to continue to increase in line with the commodity price forecasts and the higher forecast for crude oil and natural gas wells placed on production.

Conversely, oil sands capital expenditures are forecast to decrease by 5 per cent from an estimated Cdn$15.4 billion in 2016 to Cdn$14.6 billion in 2017 and to Cdn$12.6 billion in 2018 as a result of companies capitalizing on various cost-saving opportunities, including modularizing and standardizing facilities, allowing for reduced well pad sizes and increased well lengths, and project deferrals. In addition, capital expenditures in 2018 are forecast to decrease by 14 per cent, mainly as a result of two major oil sands projects—Canadian Natural Resources Limited’s Horizon Phase 3 and Suncor Energy’s Fort Hills—that were previously under construction in the mining sector being completed in 2017, with no other major oil sands projects planned in the near future.

Over the forecast period, oil sands spending continues to decrease, reflecting the continued deferral of higher-cost projects; successful deployment of cost-reduction strategies; uncertainty around new regulations such as Alberta’s Oil Sands Emissions Limit Act, which will implement a 100 megatonne cap on oil sands emissions; and uncertainty over export pipeline development projects. Expenditures in the oil sands are expected to be invested in new thermal projects or primarily aimed at sustaining capital and expanding existing projects.

Total expenditures are forecast to remain relatively flat until 2021, with an increase in conventional oil and gas sector spending offset by a decline in capital expenditures in the oil sands sector. For the remainder of the forecast period, capital expenditures are projected to moderately increase, again with more capital expenditures assumed to be directed to the conventional oil and gas sector.

Details about how the forecast was developed can be found in the Methodology section.

Value of Production

Figure 1.11

  • In 2017, the total value of production increased by 35 per cent from 2016 primarily as a result of oil sands production returning to levels seen before the Fort McMurray wildfires and partly due to higher prices.
  • Combined upgraded and nonupgraded bitumen revenues, at roughly Cdn$45.6 billion dollars, were 64 per cent of the total revenue in 2017, 46 per cent higher than in 2016.

Table 1.10

The value of production of Alberta’s energy resources from 2013 to 2017 is shown in Figure 1.11 [Tableau]. Table 1.7 [HTML] provides the value of Alberta’s energy resource production for 2017 and forecast values to 2027. In the future, revenues from upgraded and nonupgraded bitumen are expected to continue to account for most of the value of production in Alberta given the size of the resource.