The utilization rate of central gas processing fractionators in Alberta should improve from now until 2010. This rate of central fractionation capacity dipped in 2001, coinciding with start-up of the Alliance Pipeline.
Central fractionation utilization will increase to 93% in 2010 from approximately 76% in 2000. Conversely, the proportion of Alberta propane recovered at on site fractionators will decline to approximately 20% in 2010 from 25% in 2000.
Over the past 15 years, the importance of on site fractionators in Alberta has diminished and several have shut down.
The evolution of the Canadian gas processing industry is similar to that of the US. There are important differences, however, when one forecasts utilization of fractionation capacity in Alberta, valuation of Alberta fractionation capacity and other midstream assets, and the availability of specification products in Western Canada.
One of the major developments in Canadian gas processing in the late 1990s was the extension of NGL pipeline infrastructure from Alberta into Northeast British Columbia (NEBC).
To exploit this pipeline infrastructure, Taylor NGL LP commissioned a deep-cut facility at its Younger plant near Fort St. John to recover an ethane plus (C2+) mix. This NGL mix feeds the Williams Energy Canada Inc. fractionator at Redwater, north of Edmonton.
The Redwater fractionator was completed in 1998 and represented a significant expansion of central fractionation capacity in the Edmonton-Fort Saskatchewan-Redwater area.
Williams acquired the Redwater fractionator and other gas processing assets from TransCanada Pipelines Ltd. On July 25, 2002, Williams announced the possible sale of its Canadian midstream assets (OGJ Online, July 30, 2002) including the Redwater fractionation plant.1
Historical perspective
Some Alberta gas plants, particularly the large ones, may have a fractionator on site. Over the last 30 years, Canadian gas producers recognized that constructing fractionation facilities at central locations would achieve economies of scale.
Since 1970, most new Canadian NGL fractionation capacity has been built at central locations, specifically near Edmonton (including Fort Saskatchewan and Redwater) and at Sarnia, Ont.
To some extent, the circumstances in Canada parallel the evolution of the US NGL industry where central fractionation facilities were installed on the Gulf Coast (Texas and Louisiana), and in the Midcontinent (Kansas and Oklahoma).
There is one significant difference in Canada: The fractionation facility at Sarnia lies within the market region. In the US, the Gulf Coast and Midcontinent fractionators are in producing regions.
The presence of underground salt formations, in which caverns can be created to provide economical underground storage for NGL, have dictated the locations of major fractionation facilities.
The original developer of the Sarnia fractionation plant, Dome Petroleum Ltd., also perceived an opportunity to exploit economies of scale by moving unfractionated NGL as batches in a crude oil pipeline.
Central fractionation facilities constructed in Canada in the 1970s and 1980s were designed to handle propane plus (C3+) mixes. These circumstances differed from those in the US where most of the central fractionators handle C2+ streams.
Although the Canadian NGL industry started down a different path than the US NGL industry in terms of fractionation, the logic and fundamental economics of the US model ultimately prevailed.
In the 1990s, two new central fractionators were constructed in Alberta: Dow Chemical Canada Inc.'s Fort Saskatchewan facility (DFS) and Williams' Redwater facility.
Both of these handle C2+ streams. Dow generally purchases the ethane from DFS and Nova Chemical Corp. usually purchases the ethane from Redwater.
In 1988, there were 28 Alberta gas plants with on site fractionation. These gas plants included the Petro-Canada (now Conoco Inc.) Empress straddle plant, Shell Canada Ltd.'s Waterton and Jumping Pound plants, Gulf Canada Ltd.'s (now KeySpan Energy Canada Inc.) Rimbey plant, Imperial Oil Ltd.'s Bonnie Glen plant, and Petrogas Marketing Ltd.'s Balzac plant.
Most of these plants are in central or southern Alberta and were originally constructed before 1970. In 2000, the number of Alberta gas plants with operating on site fractionation capacity declined to 19.
Competitive situation
Central fractionators compete with each other and with on site fractionators at various gas plants. The Sarnia or eastern Canadian market generally provides a price upgrade for propane.
Fig. 1 shows the propane price differential at Sarnia vs. Edmonton. The circumstances, including underutilized fractionation capacity in Alberta, ensure a competitive market for fractionation services and the acquisition of NGL mix in the Edmonton-Fort Saskatchewan-Redwater area.
Because there is generally a strong market for propane and butane in Ontario and adjacent US states, there is generally a significant upgrade in moving propane and butane from Alberta to Ontario.
In contrast, the value of the C5+ is often significantly higher in Alberta because C5+ is used as a diluent for the pipeline transportation of heavy crude oil and bitumen from Western Canada.
Outlook for NGL fractionation
Fig. 2 shows that the Alberta propane recovered at on site fractionators was approximately 33% of the Alberta gas plant propane in 1990.
While the total propane recovered in 2000 at the on site fractionators was higher than in 1990, the 2000 proportion of propane volume from on site fractionation was only 25% of the total Alberta gas plant propane.
By 2010, the proportion of Alberta propane recovered at the on site fractionators will decline to approximately 20%.
The drop in Alberta propane recovery to 168,900 b/d in 2001 from 183,300 b/d in 2000 corresponds to the start-up of the Alliance Pipeline.2
Fig. 3 shows a forecast of the utilization of central fractionation capacity. It will increase to 93% in 2010 from approximately 76% in 2000. A modest increase in Alberta gas production is a key assumption.
Improved utilization also results from less use of on site fractionators (Fig. 2), raw gas moved from NEBC to Alberta for processing, and the pipeline transfer of NGL mix from Taylor, BC, to Redwater. In the longer term, there may be some NGL recovered from Mackenzie Delta gas, which could also contribute to improved utilization of Alberta NGL fractionation.
Fractionation operation
Table 1 lists the central fractionation facilities near Edmonton. Although there are five fractionation facilities listed in Table 1, companies that are not major gas producers in Canada operate two of the facilities—DFS and Williams Redwater.
These operators are essentially offering a merchant service and will compete for available NGL.
The completion of a third ethylene plant at Joffre has resulted in insufficient ethane to meet feedstock requirements of all the Alberta ethylene plants. These additional ethane investments are, therefore, on hold; increased ethane recovery should mitigate the Alberta ethane supply shortfall:2
Taylor NGL is building a new gas plant at Joffre to process natural gas consumed as fuel and for on site electrical power generation at the Nova Joffre petrochemical complex.
EnCana Corp. is installing a deep-cut ethane recovery unit at its Empress straddle plant.
EnCana may also rationalize some ethane recovery capacity at Empress. This rationalization may focus on processing available gas in more-efficient facilities, which generally means modern plants with higher ethane-recovery levels.
Gross margins
As the gas and NGL industry in Alberta has matured, gas producers are now more aware of gas processing economics and specifically of the margins on ethane and propane recovery.
The gross margin is one way to measure the economics of NGL recovery. It is the market price for a product (ethane and propane) less the value of shrinkage (i.e., the heating value of gaseous ethane and propane) and transportation and fractionation (T&F) costs.
Recovery of ethane and full recovery of propane are sometimes economic decisions. Fig. 4 shows the gross margin for propane recovery at a typical Alberta straddle plant assuming typical T&F costs. Since 1987, the economics of propane recovery have generally been positive, even lucrative in some months.
High margins in late 1996 and early 1997 (Fig. 4) were largely attributable to the tight capacity situation in gas pipelines exiting the Western Canadian Sedimentary Basin (WCSB). The Northern Border Pipeline expansion and extension in late 1998 increased the gas pipeline capacity from the WCSB.
Apparent margins in certain months were negative (Fig. 4); in these months economics may have favored a reduction in ethane and propane recovery.
Because fractionation costs are deductions in the gross margin calculation, gas producers are sensitive to these costs. Fuel and power are variable costs at fractionation plants; they were substantially higher in recent years as a result of electrical deregulation and higher gas prices.
The gross margin in specific situations can be different than depicted in Fig. 4 depending on whether the fees for fractionation tracked actual costs or were based on historical costs.
Fig. 3 shows that the volume of NGL available for fractionation in Alberta may increase. Fractionation profitability also depends on the fees for this service. Excess capacity and competition from Sarnia have constrained the fee level for Alberta fractionation.
There are several factors that may affect the future outlook for fractionation fee, including the expansion of NGL supply in market areas served by Sarnia. The Aux Sable plant in Illinois will enhance propane supply in the Midwest, and the Point Tupper propane supply recovered from offshore Nova Scotia will capture markets in eastern Canada and the US Northeast.
Both these factors could reduce the volume of propane and butane required at Sarnia. These circumstances and the premium value for C5+ in Alberta could favor increased use of Alberta central fractionators.
References
- "Williams Considers Selling its Western Canada Assets," Williams Co. press release, July 25, 2002.
- "LPG Outlook 2002," Hawkins Gas Consultants multiclient study, July 2002.
The author
David J. Hawkins is president of Hawkins Gas Consultants Ltd., Calgary. He joined the Canadian affiliate of Purvin & Gertz Inc. in 1976 where he worked until 1997. From 1972 to 1976, he worked in the energy studies section of TransCanada PipeLines, Toronto. Hawkins has a BASc in engineering science and an MASc in chemical engineering from the University of Toronto and a doctorate in control systems from the Victoria University of Manchester, UK. He is a member of the Canadian Society for Chemical Engineering and is a registered professional engineer in Alberta and Ontario.
