PDF Page 1 of 24 6.0 COMMERCIAL NATURAL GAS 6.1 SUPPLY OVERVIEW Primary sources of gas supply for the Eastern Triangle are expected to be the Marcellus and Utica shale plays in the northeastern United States (US) and the Western Canada Sedimentary Basin (WCSB). Historically, the WCSB has been the major gas supplier to markets in Eastern Canada. The emergence of significant new gas supply from the Marcellus and Utica shale plays in the northeastern US has dramatically altered historical flow patterns established over decades. The rapid growth of gas supply in the northeastern US, an area that has historically been a key market area for TransCanada, is not only satisfying local area demand, but has displaced and is expected to continue to displace, traditional gas imports from areas such as the Gulf Coast and the WCSB as a result of its robust supply development economics and advantageous geographic proximity. TransCanada has developed updated supply forecasts since the original Application. Highlights of the changes are: Figure 6-2 US Resource Potential has been updated to include the most recent results from the 2015 US Potential Gas Committee assessment which adds the year 2014. Figure 6-3 Regional Shale Gas Resource Potential has been updated to include the most recent results from the 2015 US Potential Gas Committee assessment which adds the year 2014. Figure 6-5 Marcellus and Utica Supply Outlook has been updated pursuant to TransCanada s most recent supply forecast results in March 2015. The combined Utica Marcellus increased 67.3 % from 572.2 10 6 m 3 (20.2 Bcf/d) to 957.5 10 6 m 3 (33.8 Bcf/d) in the year 2025. Figure 6-7 WCSB Well Count and Production has been updated to include 2014 data. Figure 6-8 WCSB Remaining Recoverable Resource has been updated to 2014 to reflect a revision in Cordova Basin supply potential based upon a recent resource assessment study released in June 2015 entitled Resource Assessment of the Cordova Embayment authored by Akindele Balogun with the British Columbia Ministry of Natural Gas Development. Figure 6-9 WCSB Supply has been updated pursuant to TransCanada s most recent supply forecast results in March 2015. Forecasted supply has increased 6.5% from 524.1 10 6 m 3 (18.5 Bcf/d) to 558.1 10 6 m 3 (19.7 Bcf/d) in the year 2030. December 2015 Page 6-1
PDF Page 2 of 24 Section 5.1.3 Canadian Gas Supply St. Lawrence Lowlands, contained within the original Application, has been deleted as the Québec provincial government imposed an indefinite moratorium on shale gas development in 2011 which shows no sign of being rescinded. 6.1.1 North American Gas Supply Activity Historical North American gas supply and demand dynamics have changed because of the widespread application of innovative horizontal drilling and hydraulic fracturing technology. The new drilling and completion technologies, which were first pioneered in the Barnett shale play, allowed industry to move away from drilling for traditional discrete hydrocarbon accumulations or traps, which were becoming increasingly difficult and expensive to find. The industry is now focused on the successful exploitation of pervasively gas-charged systems, also known as continuous accumulations of unconventional shale-gas, and tight-gas resources across North America. Current and prospective North American shale plays are depicted in Figure 6-1. Figure 6-1: North American Shale Plays Page 6-2 December 2015
PDF Page 3 of 24 Initially, costs associated with horizontal drilling and multi-stage fracturing completions were very high. However, supply costs have steadily declined because of the implementation of pad drilling, built-for-purpose rigs and completion equipment coupled with assembly line development approaches and economies of scale. The North American oil and gas industry has recently been focused on the aggressive development of liquids-rich gas from ultra-low permeability gas-bearing formations that were technically not producible until a few years ago. In addition, the exploitation of tight oil plays, such as the Bakken and Eagle Ford, have contributed significant quantities of solution gas to the overall supply mix. These activities have led to a continent-wide surplus of gas in search of a market. Traditional flow patterns between supply sources and market demand areas have been disrupted from historical patterns. The growth in North American supply has been so dramatic that numerous liquefied natural gas (LNG) export projects, ranging from brownfield projects along the Gulf Coast to greenfield projects on British Columbia s (BC) coast, have been proposed in hopes of reaching new, more lucrative markets, particularly in Asia. 6.1.2 US Supply Potential The US is currently undergoing a natural gas supply renaissance brought about by the technology of long-reach horizontal drilling, in combination with sequentially staged hydraulic fracturing. Shale gas resource estimates have continued to rise along with expectations for production growth. Since 2004, estimates of US resource potential which are reported biennially by the Potential Gas Committee, have risen dramatically, and almost exclusively as a result of estimates involving shale plays. Its latest estimate pegs the US recoverable resource potential (see Figure 6-2) at approximately 71.24 10 12 m 3 (2,515 Tcf), which is more than double the estimates made in 2004. Almost all of the gains can be attributed to increases in the Atlantic region (see Figure 6-3) which is dominated by shale gas growth from the Marcellus and Utica plays (see Figure 6-4). The US, which currently produces about 2.07 10 9 m 3 /d (73 Bcf/d) 1 and represents approximately 79% of all North American gas production, is expected to increase its production to approximately 2.38 10 9 m 3 /d (84 Bcf/d) by 2020. Shale gas production has made the biggest contribution to supply growth. It has increased from approximately 59.5 106 m 3 /d (2.1 Bcf/d) in 2005 to 934.8 10 6 m 3 /d (33 Bcf/d), currently, and is expected to grow to 1.4 10 9 m 3 /d (48.5 Bcf/d) by 2020. The Appalachian sedimentary basin in the northeast US, which is home to the Marcellus and Utica plays, is responsible for 85% of all incremental U.S. shale gas production growth since the start of 2012. 2 The Marcellus play has grown from essentially zero 1 EIA (U.S. Energy Information Administration) July, 2015 Natural Gas Monthly Data to May, 2015. 2 EIA Drilling Productivity Report July, 2015. December 2015 Page 6-3
PDF Page 4 of 24 production to approximately 425 10 6 m 3 /d (15 Bcf/d) in six years. Production from the Utica plays continues on an upward trajectory having already reached approximately 56.7 10 6 m 3 (2 Bcf/d). The growth in the Marcellus play has been so rapid and unexpected that Marcellus gas supply now saturates the local US northeast market area. The influence of Marcellus gas supply is also being felt in Eastern Canada as Marcellus supply pushes its way northward into southern Ontario and Québec markets. 6.1.2.1 Marcellus Shale Play Figure 6-2: US Resource Potential (Rev.1) The Marcellus shale play (see Figure 6-4) ranks among the largest natural gas plays in the world based on area, resource and production. It is also proximal to the key Canadian gas markets of southern Ontario and Québec. The Marcellus is a Devonian shale gas play covering an area of about 12.1 million hectares (30 million acres) across four states including Pennsylvania, Ohio, New York and West Virginia, at depths ranging from 1,219 to 2,591 m (4,000 to 8,500 feet). In 2012, the U.S. Energy Information Administration (EIA) assessed the recoverable resource potential of the play at 3.99 10 12 m 3 (141 Tcf). Page 6-4 December 2015
PDF Page 5 of 24 Source: Potential Gas Committee Report April 2015 Figure 6-3: Regional Shale Gas Resource Potential (Rev.1) Figure 6-4: Marcellus and Utica Footprint December 2015 Page 6-5
PDF Page 6 of 24 The core of the play appears to be centered in Washington and Allegheny counties near the city of Pittsburgh. Marcellus production is expected to grow significantly to 2021 and level off towards 2025 (see Figure 6-5). Marcellus production has maintained steady rates of growth in spite of the fact that less than half the number of rigs are operating from an historical peak of 150. The increase in productivity per rig is attributed to the benefits of pad drilling, with 10 to 12 wells per pad, and assembly line operations. A typical well is drilled 1,829 m (6,000 feet) vertically, followed by a 1,524 m (5,000 foot) horizontal section with 22 fracturing stages. At the present time there are approximately 10,000 producing wells in the Marcellus play and about 60 drilling rigs working. (Source: TransCanada) 6.1.2.2 Utica Shale Play Figure 6-5: Marcellus and Utica Supply Outlook (Rev.1) The Utica play is a highly organic black Ordovician shale with an areal extent of approximately 6.1 million hectares (15 million acres) spreading across Pennsylvania, Ohio, West Virginia and New York. The play can be up to 213 m (700 feet) thick in SW Pennsylvania, but typically ranges from 46 to 91 m (150 to 300 feet). Current drilling activity is focused within a core area in eastern Ohio along the wet gas trend. The Utica play is geologically older than the Marcellus play and, thus, stratigraphically positioned approximately 457 to 610 m (1,500 to 2,000 feet) deeper, with considerable overlap between the two play trends. The development of the Utica Page 6-6 December 2015
PDF Page 7 of 24 lags several years behind the Marcellus with just under 500 producing wells and 20 active drilling rigs. Insufficient well data probably explains the relatively low estimate of 453 10 9 m 3 (16 Tcf) for recoverable resource potential assessed by the EIA in 2012, which will likely be upgraded as more wells are drilled and more acreage is fully evaluated. Currently, industry efforts are directed at delineating sweet spots, which have yielded some high volume tests. Current production is approximately 36.8 10 6 m 3 /d (1.3 Bcf/d), which is expected to climb as industry responds to strengthening gas prices by moving from the condensate window into higher productivity dry-gas zones. Utica shale drillers are outpacing midstream infrastructure to provide take-away capacity, but that is expected to change in the near future. 6.1.2.3 Other Appalachian Shale Potential In addition to the Marcellus and the Utica, the Appalachian Sedimentary Basin has several additional shale zones that remain either untested or have had some preliminary exploratory activity. These shales may have commercial value in the future. The untested or under-evaluated shales with economic potential include the Rhinestreet, Burket, Geneseo, Huron and Ohio Shale. 6.1.3 Canadian Gas Supply In a similar manner to the US experience, supply potential from various shale plays has also been identified in Canada, primarily in the west. 6.1.3.1 Western Canada Sedimentary Basin The WCSB has had a long history of gas production sourced from conventional reservoirs that were vertically drilled. However, over time, conventional gas discoveries were becoming harder to find, smaller in size and more expensive to develop, with lower initial production rates. This conventional paradigm shifted with the advent of coalbed methane production, which was followed closely by key developments in the Montney, Horn River, Cordova, Liard and Duvernay shale basins (see Figure 6-6). The shift from vertical drilling to horizontal drilling, in combination with hydraulic fracturing, is expected to facilitate WCSB supply growth in response to demand growth. In less than 10 years, horizontal drilling has increased from about 5% of total wells drilled to about 82%, currently, and is expected to increase to 90% within the next few years. Even though the annual well counts have declined from 16,000 to approximately 2,000 (see Figure 6-7), the WCSB has maintained a stable supply profile as a result of the early and rapid adoption of long-reach horizontal wells coupled with extensive hydraulic fracturing. December 2015 Page 6-7
PDF Page 8 of 24 Figure 6-6: Key WCSB Gas Plays The technically recoverable remaining resource estimate for the WCSB has increased fivefold from 4.8 10 12 m 3 (172 Tcf) in 2008 to 25.1 10 12 m 3 (886 Tcf) within six years (see Figure 6-8). The increase in recoverable resource estimates is the result of success in unconventional horizontally drilled shale and tight plays. While shale and tight gas plays are a significant new source of supply and represent the future of WCSB gas supply, conventional gas will continue to be an important supply source. There is approximately 4.4 10 12 m 3 (154 Tcf) of remaining conventional gas resource, primarily in low permeability reservoirs in the Deep Basin area that are close to established infrastructure. Page 6-8 December 2015
PDF Page 9 of 24 Figure 6-7: WCSB Well Count and Production (Rev.1) The WCSB currently produces approximately 396 10 6 m 3 (14 Bcf/d) (see Figure 6-9). Production from the basin is expected to remain at that approximate level for several years before increasing from about 2018 onwards. The increase in production will be driven by LNG export demand on BC s west coast at Kitimat and Prince Rupert. The supply contribution from conventional gas sources is expected to decline over time as contributions from unconventional supply sources increase. Source: TransCanada and various government agencies Figure 6-8: WCSB Remaining Recoverable Resource (Rev.1) December 2015 Page 6-9
PDF Page 10 of 24 Figure 6-9: WCSB Supply (Rev.1) 6.1.3.2 Montney Play The Montney is the WCSB s most active play, as well as its most mature unconventional play. The Montney trend represents one of the world s largest natural gas accumulations with a total technically recoverable and marketable resource assessment of 12.72 10 12 m 3 (449 Tcf). Although it is commonly referred to as a shale play, it is a hybrid combination of stacked and inter-bedded sequences of tight siltstones, sandstones and shales. 6.1.3.3 Horn River, Cordova and Liard Shale Basins Combined, these three Devonian shale basins encompass an area of approximately 4.9 million hectares (12 million acres) and contain an estimated 5.2 10 12 m 3 (182.8 Tcf) of technically recoverable gas. In contrast to the Montney play, these shale basins have experienced a significantly slower pace of development, which is a reflection of their remoteness and seasonal access, as well as a gas stream that is largely devoid of natural gas liquids and therefore provides no additional economic benefit over and above the price of dry gas. As future LNG projects are developed and as development costs decrease, significant growth is expected from these basins. 6.1.3.4 Duvernay Often referred to as the Eagle Ford of Canada, the Devonian-aged Duvernay ranks among the most recent and possibly most significant new WCSB supply source. The highly organic Duvernay shale encompasses an area of approximately Page 6-10 December 2015
PDF Page 11 of 24 10.1 million hectares (25 million acres) and is found at depths of 2,500 to 4,000 m (8,202 to 13,123 feet) with thicknesses up to 70 m (230 feet). Technically recoverable gas has been assessed at 2.55 10 12 m 3 (90 Tcf). 6.2 TRANSCANADA MAINLINE THROUGHPUT FORECAST TransCanada has developed a throughput forecast for this application to assess the utilization of the Mainline and for calculating fuel requirements subsequent to the Asset Transfer. The results of this throughput forecast are provided in Table 6-1: Western Canada Flow Balance and Table 6-2: WCSB Exports. The throughput forecast draws from analysis conducted within TransCanada and also benefits from the use of aggregate customer confidential information, public information as well as models and other assessments. The throughput forecast incorporates an outlook for the broader North American gas market (supply, demand and infrastructure assumptions) but focuses on the key factors that impact throughput on the Mainline system. Key factors include items such as WCSB supply, Marcellus and Utica supply, demands in Canadian markets, BC west coast LNG assumptions and flows on Canadian and related northern tier U.S. pipelines. For the flow balance for western Canada in terms of production, storage, demand and both pipeline and LNG exports from the region, see Table 6-1 and Figure 6-10. This figure also illustrates the portion of western Canadian demand that arises from the oil sands and the portion of western Canada (WC) exports anticipated in the form of LNG. As part of the Application Amendment, TransCanada is providing an update to the throughput forecast that was filed in the original Application. The following differences in key forecast assumptions are noted below: The inclusion of Tennessee Gas Transmission s Northeastern Energy Direct project (1.2 Bcf/d, starting in November 2018) into the Northeastern US market is expected to compete with TransCanada exports to the Boston market area resulting in less flows via East Hereford onto the Portland Natural Gas Transmission System (PNGTS). As in the Application, WCSB production is forecast to grow in response to LNG exports to the Pacific coast. Pre-LNG (2019) supply growth is slower relative to the 2014 Filing as start-up timing of the first terminal has been delayed a year. Post 2021 supply is expected to be higher than the 2014 Filing as the forecast of LNG exports are projected to be higher. December 2015 Page 6-11
PDF Page 12 of 24 Three LNG plants with a total of six 0.9 Bcf/d trains (total export capacity of 5.4 Bcf/d) are included in the updated throughput case. The 2014 Filing assumed the same number of plants (three) and trains (six) but less capacity for each train (0.8 Bcf/d) and total export capacity (4.8 Bcf/d). Forecasted Mainline Western Receipts are expected to decline in the next few years due to the switching of contracts from longhaul to shorthaul. Québec Utica shale is not anticipated in this forecast given the indefinite moratorium imposed by the Québec provincial government on shale gas development. In the 2014 Filing production levels from the Québec Utica shale were projected to reach 0.23 Bcf/d by 2023. Table 6-1: Western Canada Flow Balance (Annual Average Bcf/d) (Rev.1) Year WCSB Supply (Unconventional and Conventional) WCSB Net Storage Total Supply Western Canadian Demand 1 Western Canadian Exports 2000 16.3 0.2 16.5 4.2 12.4 2001 17.0-0.3 16.7 4.0 12.7 2002 16.8 0.1 16.9 4.1 12.9 2003 16.4 0.0 16.4 4.2 12.2 2004 16.6-0.1 16.5 4.3 12.2 2005 16.7 0.0 16.7 4.1 12.5 2006 16.8-0.3 16.5 4.3 12.1 2007 16.4 0.0 16.4 4.4 11.9 2008 15.7-0.1 15.6 4.6 11.0 2009 14.8-0.1 14.7 4.7 9.9 2010 14.2 0.0 14.3 4.7 9.6 2011 14.3-0.2 14.0 5.0 9.0 2012 13.6 0.0 13.7 5.2 8.5 2013 13.9 0.2 14.0 5.5 8.4 2014 14.4 0.2 14.6 5.6 9.0 2015 14.8 0.0 14.8 5.8 9.0 2016 14.4-0.2 14.2 6.1 8.1 2017 14.0-0.2 13.8 6.2 7.5 2018 14.2-0.1 14.1 6.5 7.7 2019 15.0 0.0 15.0 6.8 8.2 2020 16.1 0.0 16.0 7.2 8.8 2021 17.4 0.3 17.7 7.7 10.0 2022 18.1 0.3 18.4 8.0 10.3 2023 18.5 0.0 18.6 8.3 10.3 2024 18.9 0.0 18.9 8.5 10.4 2025 19.1 0.0 19.1 8.6 10.5 Page 6-12 December 2015
PDF Page 13 of 24 Table 6-1: Western Canada Flow Balance (Annual Average Bcf/d) (Rev.1) (cont'd) Year WCSB Supply (Unconventional and Conventional) WCSB Net Storage Total Supply Western Canadian Demand 1 Western Canadian Exports 2026 19.2-0.3 18.9 8.8 10.1 2027 19.3-0.3 19.1 9.0 10.1 2028 19.5 0.0 19.5 9.2 10.3 2029 19.6 0.0 19.6 9.4 10.2 2030 19.7 0.0 19.7 9.8 9.9 Note: 1. Includes pipeline fuel, and LNG fuel Numbers may not add due to rounding. Values may be converted to metric (10 6 m 3 /d) by dividing by 35.301 and multiplying by 1,000. Figure 6-10: Western Canada Volumes (Rev.1) For the forecast of exports from the WCSB, including western receipt flows for the Mainline, traditional pipeline export points and future expected LNG exports, see Table 6-2. This forecast is graphically presented in Figure 6-11. The LNG exports in this outlook assumes the initial start-up in 2019 of two trains at one LNG terminal each with a capacity of 26 10 6 m 3 /d (0.9 Bcf/d) for a total of 51 10 6 m 3 /d (1.8 Bcf/d). Second and third terminals are expected to come on-stream in 2020 and 2021 respectively. Each terminal is expected to have two trains which brings the total aggregate LNG plant capacity to 153 10 6 m 3 /d (5.4 Bcf/d) by the end of the time horizon in 2030. December 2015 Page 6-13
PDF Page 14 of 24 Table 6-2: WCSB Exports (Annual Average Bcf/d) (Rev.1) Northern Border - Monchy, SK Flows Mainline Western Receipts Flows West Coast LNG Exports Year Western Canadian Exports GTN - Kingsgate, BC Flows Alliance - Elmore, SK Flows NWP - Sumas, BC Flows 2000 12.4 2.2 2.3 0.2 0.9 6.8 2001 12.7 2.1 2.3 1.5 0.9 6.0 2002 12.9 2.1 2.0 1.5 0.9 6.4 2003 12.2 2.1 1.8 1.6 0.9 5.9 2004 12.2 2.1 2.0 1.6 0.9 5.7 2005 12.5 1.9 1.7 1.6 0.8 6.3 2006 12.1 1.9 1.9 1.6 0.7 6.1 2007 11.9 1.9 2.0 1.6 0.7 5.7 2008 11.0 1.6 1.8 1.6 0.8 5.2 2009 9.9 1.3 1.9 1.6 0.8 4.3 2010 9.6 1.9 1.9 1.6 0.8 3.4 2011 9.0 1.8 1.6 1.6 0.8 3.2 2012 8.5 2.0 1.7 1.5 0.8 2.3 2013 8.4 1.9 1.9 1.6 0.8 2.2 2014 9.0 1.4 1.7 1.6 0.9 3.4 2015 9.0 1.5 1.9 1.5 1.1 3.0 2016 8.1 1.4 1.9 1.6 1.1 2.2 2017 7.5 1.6 2.2 1.6 0.9 1.2 2018 7.7 1.7 2.2 1.6 0.9 1.2 2019 8.2 1.6 2.0 1.6 0.9 1.0 1.0 2020 8.8 1.5 1.8 1.5 0.9 0.9 2.1 2021 10.0 1.2 1.5 1.4 0.9 0.8 4.1 2022 10.3 1.0 1.4 1.4 0.9 0.8 4.8 2023 10.3 0.9 1.3 1.4 0.9 0.8 4.9 2024 10.4 1.0 1.3 1.4 0.9 0.8 4.9 2025 10.5 1.0 1.3 1.4 0.9 0.9 4.9 2026 10.1 0.8 1.3 1.4 0.9 0.9 4.9 2027 10.1 0.6 1.3 1.4 0.9 0.9 4.9 2028 10.3 0.8 1.3 1.4 0.9 1.0 4.9 2029 10.2 0.7 1.3 1.4 0.9 1.0 4.9 2030 9.9 0.4 1.2 1.4 0.9 1.0 4.9 Note: Numbers may not add due to rounding. Values may be converted to metric (10 6 m 3 /d) by dividing by 35.301 and multiplying by 1,000. Page 6-14 December 2015
PDF Page 15 of 24 Figure 6-11: Exports from WCSB and Mainline Western Receipts (Rev.1) 6.3 MARKETS OVERVIEW Although the Mainline serves markets across central and eastern Canada and the northern tier of the US, this overview will focus on the markets served by the proposed Eastern Mainline Project. The Eastern Mainline Project will serve existing markets in the eastern delivery areas (EDA) in Ontario and Québec, which are the domestic delivery areas in the Affected Area, as well as in the northeastern US via the export points in the Affected Area at Iroquois, Cornwall, Napierville, Philipsburg and East Hereford. Both domestic EDA and eastern export points together comprise the Affected Area. These markets are expected to remain relatively stable over time, with any growth in domestic demand offset by declining exports. TransCanada regularly evaluates these markets and updates its forecast of demand in these regions. 6.3.1 Eastern Delivery Area Markets The Mainline serves domestic markets in the EDA, which are located in eastern Ontario and in Québec. The market in these areas is expected to be relatively stable with growth expected in both power generation and industrial sectors. Table 6-3 reports historical consumption to 2014 and TransCanada s forecast of demand to 2030 (which incorporates market information provided by shippers) in these areas. As tabulated, demand within the EDA is forecast to grow from an average annual December 2015 Page 6-15
PDF Page 16 of 24 level of 24.6 10 6 m 3 /d (0.87 Bcf/d) in 2014 to 27.4 10 6 m 3 /d (0.97 Bcf/d) by 2020, and then to remain relatively flat to 2030. Table 6-3: EDA Market Demand Annual Averages (Rev.1) Residential Commercial Industrial Power Generation Total 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 2000 4.8 0.17 7.0 0.25 11.9 0.42 3.2 0.11 26.9 0.95 2001 4.3 0.15 6.4 0.23 10.3 0.36 3.5 0.12 24.5 0.87 2002 4.6 0.16 6.8 0.24 10.9 0.39 3.8 0.13 26.2 0.92 2003 5.0 0.18 7.2 0.25 10.1 0.35 2.9 0.10 25.1 0.89 2004 4.9 0.17 7.0 0.25 10.6 0.37 1.6 0.06 24.1 0.85 2005 4.7 0.17 6.8 0.24 9.6 0.34 2.1 0.07 23.2 0.82 2006 4.3 0.15 6.4 0.23 10.1 0.36 2.6 0.09 23.5 0.83 2007 4.7 0.17 6.9 0.24 10.5 0.37 4.6 0.16 26.6 0.94 2008 4.3 0.15 7.1 0.25 10.2 0.36 2.1 0.07 23.7 0.84 2009 4.7 0.17 8.1 0.29 8.1 0.29 2.1 0.07 23.0 0.81 2010 4.1 0.14 7.5 0.26 9.0 0.32 2.2 0.08 22.8 0.81 2011 4.3 0.15 7.6 0.27 9.4 0.33 2.3 0.08 23.5 0.83 2012 4.1 0.14 6.2 0.22 10.4 0.37 2.5 0.09 23.2 0.82 2013 4.5 0.16 6.3 0.322 11.8 0.342 1.8 0.06 24.4 0.86 2014 4.7 0.17 7.0 0.25 11.7 0.41 1.2 0.04 24.6 0.87 2015 5.0 0.17 7.1 0.25 12.3 0.44 0.7 0.02 25.1 0.89 2016 4.7 0.17 6.8 0.24 12.3 0.43 0.6 0.02 24.3 0.86 2017 4.7 0.17 6.8 0.24 12.7 0.45 0.5 0.02 24.7 0.87 2018 4.7 0.17 6.8 0.24 13.2 0.46 0.8 0.03 25.4 0.90 2019 4.7 0.17 6.8 0.24 13.7 0.48 2.0 0.07 27.2 0.96 2020 4.7 0.17 6.8 0.24 13.7 0.48 2.2 0.08 27.4 0.97 2021 4.7 0.16 6.8 0.24 13.6 0.48 2.8 0.10 27.8 0.98 2022 4.7 0.17 6.8 0.24 13.7 0.48 4.9 0.17 30.1 1.06 2023 4.7 0.16 6.8 0.24 13.7 0.48 5.0 0.18 30.1 1.06 2024 4.7 0.17 6.8 0.24 13.7 0.48 5.0 0.18 30.1 1.06 2025 4.7 0.16 6.8 0.24 13.7 0.48 5.0 0.18 30.1 1.06 2026 4.7 0.16 6.8 0.24 13.7 0.48 4.9 0.17 30.0 1.06 2027 4.7 0.17 6.9 0.24 13.9 0.49 3.2 0.11 28.7 1.01 2028 4.7 0.17 6.8 0.24 13.8 0.49 3.4 0.12 28.7 1.01 2029 4.7 0.16 6.8 0.24 13.7 0.48 3.4 0.12 28.5 1.01 2030 4.7 0.16 6.8 0.24 13.7 0.48 3.5 0.12 28.7 1.01 Page 6-16 December 2015
PDF Page 17 of 24 6.3.2 Northeastern US Markets The Mainline serves markets in the northeastern US through its export points at Iroquois, Cornwall, Napierville, Philipsburg and East Hereford. The volume of gas exported at these points in 2014 accounted for approximately 5-6% of the northeastern US demand and is forecast to decrease by 2030. Connecting to pipelines located in the northeastern US, these export points access markets within the Middle Atlantic and New England census regions. The market in these areas is expected to be relatively stable with growth expected in both commercial and power generation. Table 6-4 reports historical consumption and TransCanada s forecast of demand in these areas. As tabulated, demand within the northeastern US is forecast to grow from an average annual level of 303 10 6 m 3 /d (10.69 Bcf/d) in 2014 to 320 10 6 m 3 /d (11.28 Bcf/d) by 2020, and then continue to grow to 2030. Table 6-4: Northeastern US Market Demand Annual Averages (Rev.1) Residential Commercial Industrial Power Generation Total 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 2000 82.7 2.92 62.8 2.22 43.0 1.52 56.4 1.99 244.9 8.65 2001 78.1 2.76 58.1 2.05 39.1 1.38 60.2 2.13 235.5 8.31 2002 77.3 2.73 60.5 2.14 41.4 1.46 71.1 2.51 250.3 8.84 2003 87.1 3.08 60.6 2.14 34.3 1.21 60.1 2.12 242.1 8.55 2004 82.1 2.90 61.4 2.17 34.6 1.22 64.1 2.26 242.2 8.55 2005 83.6 2.95 55.4 1.96 33.4 1.18 67.1 2.37 239.5 8.46 2006 72.2 2.55 51.0 1.80 33.3 1.18 76.8 2.71 233.3 8.24 6.4 FLOW BALANCE FOR THE AFFECTED AREA Table 6-5 provides a flow balance for the Affected Area. It illustrates how natural gas volumes flow into this region, how they are consumed within the region and how they leave the region by the various export points. The column labelled TC Pipe Flow to Affected Area reports the volume sourced from the west. Specifically, this is the combined flow across both the North Bay Shortcut and the Montréal Line into the Affected Area, destined for the EDA and northeastern US markets. This flow will be transported by the pipeline capacity that remains on the North Bay Shortcut after the Asset Transfer and by the capacity on the Montréal Line, including capacity added as part of the Eastern Mainline Project. Québec supply, which is currently relatively small, is forecast to remain flat over the time horizon. The last four columns of Table 6-5 report the volumes at the Iroquois (Waddington) and Other Export Points (Cornwall, Napierville, Philipsburg and East Hereford), which serve, in part, the northeastern US markets shown in Table 6-4. December 2015 Page 6-17
PDF Page 18 of 24 6.4.1 Flows at the Export Points The export volumes at the Iroquois export point are forecast to decrease and eventually reverse in flow to become imports into Canada (see Table 6-5). The negative values in Table 6-5 imply imports. The primary reason for the decline and reversal of flows at Iroquois is the growth in Marcellus and Utica shale supplies within the northeastern US (as further described in Section 4.3.3). This growth in supply, combined with expected new pipeline infrastructure within the northeastern US region, is forecast to reduce the quantity of natural gas supplied to the markets in this region via TransCanada s Iroquois export point. Furthermore, these changes are expected to cause the Iroquois point to reverse flow such that natural gas is imported into Canada. The last two columns of values in Table 6-5 report the volumes to Other Export Points. As shown, TransCanada has historically exported volumes to these points and is forecasting that deliveries through these points will continue serving existing markets in the northeastern US. Table 6-5: Affected Area Flow Balance Annual Averages (Rev.1) TC Pipe Flow to Affected Area Québec Supply 1 EDA Demand 2 TC Export at Iroquois (Waddington) Other Export Points 3 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 2000 57.9 2.04-0.1 0.00 27.4 0.97 23.7 0.84 5.8 0.20 2001 54.1 1.91-0.1 0.00 25.1 0.88 22.6 0.80 5.6 0.20 2002 58.0 2.05-0.1 0.00 26.8 0.95 24.5 0.86 6.8 0.24 2003 57.1 2.02-0.1 0.00 25.7 0.91 24.2 0.85 6.4 0.23 2004 56.5 2.00 0.0 0.00 24.7 0.87 24.8 0.88 6.5 0.23 2005 59.9 2.11 0.0 0.00 23.9 0.84 28.1 0.99 7.6 0.27 2006 59.7 2.11 0.0 0.00 24.1 0.85 27.9 0.98 6.7 0.24 2007 62.9 2.22 0.1 0.00 27.2 0.96 28.1 0.99 7.2 0.25 2008 56.7 2.00 0.0 0.00 24.1 0.85 26.5 0.94 6.0 0.21 2009 49.4 1.74 0.1 0.00 23.3 0.82 21.8 0.77 4.6 0.16 2010 42.8 1.51 0.0 0.00 23.1 0.82 16.6 0.59 3.4 0.12 2011 40.7 1.44 0.1 0.00 23.8 0.84 14.2 0.50 3.2 0.11 2012 43.0 1.52 0.0 0.00 23.5 0.83 15.2 0.54 5.2 0.18 2013 44.9 1.58 0.0 0.00 24.7 0.87 15.3 0.54 6.6 0.23 2014 39.3 1.39 0.1 0.00 24.9 0.88 11.2 0.39 5.2 0.18 2015 44.1 1.56 0.1 0.00 25.0 0.88 13.5 0.48 7.1 0.25 2016 40.6 1.43 0.2 0.01 24.8 0.88 9.5 0.33 6.5 0.23 2017 31.7 1.12 0.1 0.01 25.0 0.88 0.6 0.02 6.2 0.22 2018 28.3 1.00 0.1 0.01 25.7 0.91-2.6-0.09 5.3 0.19 Page 6-18 December 2015
PDF Page 19 of 24 Table 6-5: Affected Area Flow Balance Annual Averages (Rev.1) (cont'd) TC Pipe Flow to Affected Area Québec Supply 1 EDA Demand 2 TC Export at Iroquois (Waddington) Other Export Points 3 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 10 6 m 3 /d Bcf/d 2019 21.3 0.75 0.1 0.01 27.6 0.97-11.7-0.41 5.5 0.20 2020 21.8 0.77 0.1 0.01 27.9 0.98-11.2-0.40 5.2 0.19 2021 21.6 0.76 0.1 0.01 28.1 0.99-11.6-0.41 5.3 0.19 2022 21.2 0.75 0.1 0.01 30.3 1.07-13.6-0.48 4.7 0.17 2023 20.0 0.71 0.1 0.01 30.1 1.06-14.9-0.53 4.9 0.17 2024 20.4 0.72 0.1 0.01 30.2 1.06-14.6-0.52 5.0 0.17 2025 22.3 0.79 0.1 0.01 30.4 1.07-13.4-0.47 5.5 0.19 2026 22.6 0.80 0.1 0.01 30.3 1.07-12.9-0.45 5.4 0.19 2027 22.2 0.78 0.1 0.01 29.0 1.02-12.0-0.42 5.4 0.19 2028 19.8 0.70 0.1 0.01 29.2 1.03-14.8-0.52 5.5 0.20 2029 19.8 0.70 0.1 0.01 28.9 1.02-14.3-0.51 5.4 0.19 2030 22.2 0.78 0.1 0.01 28.9 1.02-11.8-0.42 5.2 0.18 NOTE: 1. Includes net annual average storage withdrawals. 2. Includes pipeline fuel. 3. Includes Cornwall, Napierville, Philipsburg and East Hereford. 6.5 SYSTEM DESIGN FOR EASTERN MAINLINE PROJECT In Volume 2A, of the original Application outlined the considerations and approach that were applied in developing the scope of facilities required to meet the Design Requirements after the asset transfer. The system design for the Eastern Mainline Project has been updated to reflect the change in Design Requirements stemming from changes to timing, the 2017 new capacity open season (NCOS) and commercial processes and the LDC Agreement. The following evidence replaces the original evidence in Volume 2A, in its entirety. Section 4.4 of this volume has described the terms of the proposed Asset Transfer and its implications for the various segments of the Mainline, including the North Bay Shortcut. The purpose of this section is to outline the considerations and approach that were applied in developing the scope of facilities required to meet the Design Requirements after the transfer of the North Bay Shortcut to Energy East. In a separate, but related and concurrently filed application, TransCanada is applying for approval of the Eastern Mainline Project. Because the Eastern Mainline Project is integral to and interrelated with the transfer of Conversion Facilities, the system December 2015 Page 6-19
PDF Page 20 of 24 design for the Eastern Mainline Project is addressed in this Application. It should also be noted that a system design discussion is not provided in the Eastern Mainline Project Application, but a reference is provided in that application to this Asset Transfer application. Technical details of the facilities proposed can be found in the Eastern Mainline Project Application. The Eastern Mainline Project involves the construction of approximately 279 km of 914 mm (NPS 36), 6,450 kpa pipeline generally following the existing Montréal Line, plus the addition of nine 11 MW compressor units at five existing compressor stations. This section provides a general description of system design matters for the Eastern Mainline Project, including: the hydraulic design basis of the facility selection the process for selecting the applied-for facilities an evaluation of facility alternatives that were considered the capability of the applied-for facilities 6.5.1 Project Overall Hydraulic Design Basis TransCanada designs its Mainline system to meet firm transportation requirements for all days of the year. For the Eastern Triangle, the design condition is a peak winter day with a loss of the most critical unit in the area. 6.5.2 Facility Design Process The facility design process was carried out in three stages: 1. Determination of the preferred expansion option: TransCanada compared expansion options on the North Bay Shortcut (NBSC) and the Montréal Line. 2. Preliminary Facility Selection: TransCanada selected the pipeline and facilities required along the Montréal Line to meet the potential firm service requirements at the date of the proposed Asset Transfer. 3. Final Facility Selection: Once the precedent agreements resulting from the 2016 NCOS and the 2017 NCOS were executed along with the commercial processes completed (Term-Up Provisions, turnback process), TransCanada selected a subset of the preliminary facilities to meet the combined new and existing expected firm service requirements. 6.5.2.1 Stage 1: Determination of the Preferred Preliminary Expansion Option In early development of the Eastern Mainline Project, TransCanada compared the addition of facilities along the Montréal Line with facilities along the NBSC. To meet the firm service requirements to the Affected Area, TransCanada is proposing to add facilities along the Montréal Line since it is the shortest and most direct path for the Page 6-20 December 2015
PDF Page 21 of 24 service requests received in the 2016 NCOS and 2017 NCOS; it aligns emerging supply in the northeastern US with the major Eastern Triangle markets; and is therefore the most efficient location for expansion. 6.5.2.2 Stage 2: Preliminary Facility Selection Once the Montréal Line was determined to be the preferred path, the following design options were considered for facilities along the Montréal Line: alternative pipe sizes alternative compressor unit sizes Alternative Pipe Sizes The 914 mm (NPS 36) pipe size was selected as the most appropriate based on a comparison of the capabilities of 762 mm, 914 mm and 1067 mm (NPS 30, 36 and 42, respectively), once fully looped and compressed (see Table 6-6). The NPS 36 alternative with compression was selected because it would provide the capability to meet the firm service requirements after the Asset Transfer. Table 6-6: Capability of Alternative Pipe Sizes Maximum Pipe Size Length (km) Capability Increase (TJ/d) 762 mm (NPS 30) 370 700 914 mm (NPS 36) 370 1,200 1067 mm (NPS 42) 370 1,600 Alternative Compressor Unit Sizes An alternative compressor unit selection was considered that would have required slightly smaller unit additions, but this option would have required the continued operation of (and incurring increasing maintenance costs for) the existing Montréal Line units. TransCanada proposes to standardize the new gas-driven unit additions with a common 11 MW size. In addition, TransCanada will move towards retiring the existing electric-driven compressors installed from 1963 through 1972. The 7 MW unit at Station 134, which was installed in 2007, will remain in service. This standardization of new unit additions and retirement of existing units will result in: lower long-term cost of service, considering the impact of capital cost, fuel and maintenance: reduced maintenance and refurbishment of existing units December 2015 Page 6-21
PDF Page 22 of 24 reduced electrical power costs because existing electric units will not be operating capital cost benefits because of standardized unit selection and compressor station layout improved reliability and reduced maintenance costs for the new unit additions because of interchangeable parts 6.5.2.3 Stage 3: Final Facility Selection Once the Precedent Agreements arising from the 2016 and 2017 new capacity open seasons (2016, 2017 NCOS) were executed along with the completion of the commercial processes, the applied-for facilities were selected because these facilities: meet the Design Requirements which include the total firm service requirements and the Additional Capacity provide for future expandability in a cost-effective manner should the need materialize In selecting a subset of the preliminary facilities, pipe sections immediately downstream of compressors were preferred as they are the most hydraulically efficient method to provide the required capacity while minimizing fuel. The 914 mm (NPS 36) pipe remains the preferred pipe size to meet expected firm service requirements. As shown in the preliminary facility selection and Table 6-6, a 762 mm (NPS 30) pipe size would meet the expected requirements, however: it would require a greater length than 279 km to meet the same requirements it would result in increased land disturbance and stakeholder disruption as a result of the increased length the capital cost is approximately the same as the applied for facilities due to the additional pipeline length it would require additional compressor fuel it would limit future cost effective expandability, should the need materialize The maximum allowable operating pressure (MOP) of 6450 kpa was selected to match the MOP of the existing system. 6.5.3 Capability Impact of the Proposed Facilities The Capability Versus Requirements Table (CVRT) in Figure 6-12 shows the firm pipeline capacity after the proposed Asset Transfer, with and without the proposed facilities, based on the Design Requirement of 2,714 TJ/d. Without the Eastern Page 6-22 December 2015
PDF Page 23 of 24 Mainline Project, there would be a contractual firm capacity shortfall of approximately 708 TJ/d which includes the Additional Capacity. Figure 6-13 shows the flow schematics for the winter peak day design case (with facilities) shown in the CVRT. Canadian Mainline Eastern Ontario Triangle Capabilities vs. Requirements 1 Affected Area Peak Winter Loss of Unit Without Proposed Facilities With Proposed Facilities Peak Summer Loss of Unit Without Proposed Facilities With Proposed Facilities Average Winter (at 99% capability factor) Without Proposed Facilities With Proposed Facilities Average Summer (at 99% capability factor) Without Proposed Facilities With Proposed Facilities (TJ/d) (TJ/d) (TJ/d) (TJ/d) (TJ/d) (TJ/d) (TJ/d) (TJ/d) Affected Area Requirements 1. Cornwall 32 32 26 26 21 21 13 13 2. East Hereford 86 86 86 86 81 81 58 58 3. Enbridge EDA 611 611 530 530 363 363 117 117 4. GMIT EDA 948 948 726 726 444 444 242 242 5. Iroquois 545 545 545 545 415 415 120 120 6. KPUC EDA 23 23 12 12 17 17 7 7 7. Napierville 9 9 9 9 6 6 4 4 8. Philipsburg 85 85 65 65 34 34 19 19 9. Union EDA 325 325 299 299 198 198 95 95 10. Additional Capacity 50 50 50 50 50 50 50 50 11. Total Requirements 2714 2714 2347 2347 1629 1629 726 726 Affected Area Capability to Les Cedres 12. Flow-in Capability 2029 2767 2016 2650 2133 2653 1948 2030 13. Fuel at Capability 23 42 22 42 29 43 24 26 14. Design Capability (12-13) 2006 2725 1993 2608 2104 2610 1924 2005 Affected Area Available Capacity at Les Cedres 15. Available Capacity (14-11) -708 10-354 261 496 1007 1217 1299 1 Requirements of the Affected Area as of April 1, 2019 Figure 6-12: Capability vs Requirements (Rev.1) December 2015 Page 6-23
PDF Page 24 of 24 Figure 6-13: Eastern Triangle Flow Schematics (Rev.1) Page 6-24 December 2015