ERICA HAMILTON COMMISSION SECRETARY Commission.Secretary@bcuc.com web site: http://www.bcuc.com
LETTER L-43-13
SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, BC CANADA V6Z 2N3 TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385 FACSIMILE: (604) 660-1102
Log No. 43967, 40018
VIA EMAIL gas.regulatory.affairs@fortisbc.com
July 11, 2013
Ms. Diane Roy Director, Regulatory Affairs FortisBC Energy Inc. 16705 Fraser Highway Surrey, BC V4N 0E8
Dear Ms. Roy:
Re: FortisBC Energy Inc. 2013/14 Annual Contracting Plan (November 2013 – October 2014)
On May 1, 2013, FortisBC Energy Inc. (FEI) filed on a confidential basis its 2013/14 Annual Contracting Plan (2013/14 ACP). The British Columbia Utilities Commission (Commission) generally accepts the FEI 2013/14 ACP and items as set out on pages 6 to 7. The major portfolio changes affecting the FEI 2013/14 ACP are as follows:
1. Forecast Design Peak Day Demand: FEI recommends a peak day value for 2013/14 of 1,218 TJ/day, a decrease of 6 TJ/day or 0.5% from the 2012/13 value of 1,224 TJ/day. The reduction in the design peak day is mainly attributable to a drop in the actual use per customer combined with a slightly lower forecast customer growth rate.
2. Annual Normal Demand: annual normal demand for 2013/14 is projected at approximately 117.3 PJ resulting in an average daily normal load of 321 TJ/d. In 2012/13, the total annual normal demand was forecast to be 113.8 PJ that resulted in a daily normal load of 312 TJ/d. The increase of 9 TJ/d in 2013/14 in the annual normal load is mainly attributable to an increase in commercial and small industrial volumes.
3. Commodity Portfolio: change the baseload supply receipt point allocation, effective November 1, 2013, by increasing Station 2 from 70% to 75%, decreasing Huntingdon from 15% to 0%, and increasing AECO/NIT from 15% to 25% in 2013/14 compared to previous years’ allocations.
4. Commodity Portfolio: Commodity Providers’ fuel requirements for gas delivery on November 1, 2013 will be evaluated and communicated before October 2013. For the period November 1, 2012 to October 31, 2013, the fuel percentages are 3.1% at Station 2 and 1.0% at AECO.
5. Commodity Portfolio: FEI recommends continuing with a balanced mix of daily and monthly priced supply to mitigate adverse price movements and provide operating flexibility.
6. Commodity Portfolio: FEI recommends consideration of longer term supply contracts with British Columbia gas producers, up to ten years in length, in the interest of supply security at the Station 2 market hub.
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7. Midstream Portfolio: contract for transportation service capacity, effective November 1, 2013, to support the changes in the Commodity baseload supply receipt point allocation percentages.
8. Midstream Portfolio: adjust seasonal supply to account for the changes in market conditions, decrease in forecast peak day demand, and in the interest of meeting the objectives of the ACP.
The Commission requests FEI file its 2014/15 ACP by May 1, 2014. In addition to the items in section 2.3.1 of the 2013/14 ACP entitled “Actions for FEI Prior to Submitting the FEI 2014/15 ACP” the Commission requests FEI include the following analyses:
An update to the Northeastern BC market study with the scope and detail of the update to be determined by FEI.
An update on the efforts to establish key relationships with producers who plan to develop supply in the Horn River, Montney and other producing regions of British Columbia over the long term.
A review and analysis of the experience with Mt. Hayes and Tilbury LNG peaking resources for the 2013/14 contract year, including an analysis of the impact of Rate Schedule 16 service on the availability of these peaking resources for the core natural gas customers.
A review of the storage and transportation alternatives for the 2014/15 and 2015/16 contract years and an analysis to optimize the amounts of transportation and storage to be contracted in future years taking into account the regional infrastructure and market developments currently in place and anticipated to be in place in the future.
Exclusive of the non-confidential Executive Summary (attached), the Commission agrees to hold the 2013/14 Annual Contracting Plan confidential as it contains market sensitive information.
CMM/cms Attachment
Yours truly, Erica Hamilton
Orders/L-43-13_FEI 2013-14 Annual Contracting Plan
FORTISBC ENERGY INC. AND FORTISBC (VANCOUVER ISLAND) INC. 2013/2014 ANNUAL CONTRACTING PLANS EXECUTIVE SUMMARY
EXECUTIVE SUMMARY 1 INTRODUCTION The Annual Contracting Plan (ACP) is a short term gas supply planning document filed with the Commission in the spring of each year. The ACP sets out the anticipated demand for natural gas by core customers and outlines the Companies’ strategy to contract for gas commodity, storage, and pipeline transportation resources to meet demand for the upcoming gas contract year. The ACP also includes a review of regional marketplace developments that provides context for the overall portfolio strategy.
This submission outlines the proposed ACPs to meet the respective natural gas requirements of FortisBC Energy Inc. (FEI) and FortisBC Energy (Vancouver Island) Inc. (FEVI) for the upcoming gas year, commencing on November 1, 2013 and ending on October 31, 2014. The Annual Contracting Plan for FEI also incorporates the natural gas requirements for FortisBC Energy (Whistler) Inc. (FEW). FEI, FEW, and FEVI are collectively known as the “FortisBC Energy Utilities” or the “FEU” or the “Companies”. This submission incorporates the FEI and FEVI Annual Contracting Plans into a single filing. The content of this submission is consistent with previous years’ filings, including topics of special interest as directed by the Commission in the acceptance letters of the 2012/13 ACPs 1 .
Within the FEU’s Common Rates, Amalgamation and Rate Design Application submitted to the Commission on April 11, 2012, the FEU sought approval for amalgamating FEI, FEVI, and FEW in order to implement “postage stamp” or harmonized rate structures across the entire FEU service area. Accordingly, in the FEU’s submission on May 1, 2012, incorporating the FEI and FEVI’s 2012/13 ACPs, the FEU assessed the requirements to implement a single gas portfolio following amalgamation. On February 25, 2013, the Commission issued its decision denying the proposal for amalgamation. As such, as provided in this document, FEI and FEVI will continue to maintain separate gas supply portfolios and develop separate price risk management strategies. Maintaining separate gas supply portfolios and price risk management strategies will enable FEVI to address and mitigate its unique challenges. While the FEI and FEVI ACPs will remain separate for 2013/14, both continue to take into consideration regional market developments that impact both utilities.
1.1 Objectives of the FEU 2013/14 ACPs The objectives for the 2013/14 ACPs are consistent with those of the 2012/13 ACPs that were accepted by the Commission. They continue to be appropriate and are as follows:
1
Commission Order No. L-45-12 dated August 2, 2012 for FEI and Commission Order No. L-46-12 dated August 9, 2012 for FEVI.
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1. To contract for resources which ensure an appropriate balance of cost minimization, security, diversity and reliability of gas supply in order to meet the core customer design peak day and annual requirements.
2. To develop a portfolio mix that incorporates flexibility in the contracting of resources based on short term and long term planning, and evolving market dynamics.
The ACPs have been successful in meeting these objectives in the past and the proposed 2013/14 ACP will continue to enable the FEU to meet these objectives for the upcoming gas year and beyond.
1.2 Follow up from the Filing of the 2012/13 ACPs The Commission accepted the recommendations outlined in the FEI 2012/13 ACP in Commission Letter No. L-45-12 dated August 2, 2012 and in the FEVI 2012/13 ACP in Commission Letter No. L-46-12 dated August 9, 2012. Included in these Letters, the Commission directed FEI and FEVI to provide the following information as part of their 2013/14 ACP:
An update to the Northeastern BC study with the scope and detail of the update to be determined by FEI.
A review and analysis of the experience with the Mt. Hayes and Tilbury LNG peaking resources for the 2012/13 contract year, including an analysis of the impact of Rate Schedule 16 service on the availability of those peaking resources for providing peaking supply for core natural gas customers.
A review of the storage and transportation alternatives for the 2013/14 and 2014/15 contract years and an analysis to optimize the amounts of pipeline and storage to be contracted in future years, taking into account the regional infrastructure and market developments currently in place and anticipated to be in place in the future.
The Appendices included in this submission provide additional information describing regional market developments of significance for the FEU, considerations for resource contracting, and portfolio optimization outlooks.
The FEU trust that the information included in this filing helps to provide insight into contracting considerations that were taken into account in the development of this ACP, as well as providing an update on significant developments that affect the regional marketplace. These developments do not significantly impact the recommended portfolios for the coming winter 2013/14, but are important to monitor because they could affect the portfolio strategy in the future.
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2 FEI 2013/14 ACP This section provides an overview of significant topics that are discussed in detail in the FEI 2013/14 ACP, including the forecast design peak day and annual normal loads, changes in contracting for resources from the previous year, operational and long term planning considerations. Key elements of FEI’s porfiolio include:
Forecast Design Peak Day Demand for 2013/14 Forecast at 1,218 TJ/d for 2013/14, which represents a net decrease of 0.5 percent or 6 TJ/d from 1,224 TJ/d in 2012/13. The reduction in the design peak day is mainly attributable to a drop in the actual use per customer combined with a slightly lower forecast customer growth rate.
Annual Normal Demand for 2013/14 Forecast at 117.3 PJ for 2013/14, resulting in an average daily normal load of 321 TJ/d. In 2012/13 the total annual normal demand was forecast at 113.8 PJ, which had resulted in a daily normal load of 312 TJ/d. The increase of 9 TJ/d in 2013/14 for the annual normal load is mainly attributable to an increase in commercial and small industrial volumes.
Commodity Portfolio For 2013/14 FEI proposes to change the baseload supply receipt point allocation by increasing Station 2 from 70 percent to 75 percent, decreasing Huntingdon from 15 percent to 0 percent, and increasing AECO/NIT from 15 percent to 25 percent in 2013/14 compared to previous years’ allocations (see Appendix C for details). This change is primarily due to the concerns with future Huntingdon supply reliability given the significant amount of decontracting of Westcoast firm T-South capacity by shippers.
FEI recommends continuing with a balanced mix of daily and monthly priced commodity supply in the portfolio to mitigate adverse price movements and provide operating flexibility.
FEI also recommends consideration of longer term supply contracts with BC gas producers, up to ten years in length, in the interests of supply security at the Station 2 market hub.
Midstream Portfolio Due to the changes in the Commodity baseload supply receipt point allocation percentages, FEI will be required to contract for incremental T-South and NGTL and Foothills capacity effective November 1, 2013. FEI has also made changes to its seasonal supply within the Midstream portfolio to account for the changes in market conditions and in the interests of meeting the objectives.
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2.1 Resource Contracting in the FEI 2013/14 ACP FEI must not only meet forecast design peak day demand 2 , but also manage loads rising well above normal over extended periods of colder weather and mitigate interruptions in delivery capacity related to both transportation and storage. Conversely, FEI also must manage load swings and resources requirements during spells of warmer than normal weather in the winter months. FEI strives to procure and deliver natural gas in the most reliable manner possible. This responsibility includes the need to to identify, monitor, and mitigate potential operational and market-related risks. In addition, the minimization of costs related to the annual portfolio, while ensuring the delivery of gas each day, is an important key objective. Balancing the need for cost minimization while meeting reliability, diversity, and flexibility objectives do not necessarily always result in the selection of the least cost alternative for inclusion in the portfolio.
The recommended portfolio is based on a balance of resources that meets the objectives of the plan. The portfolio selected each year is based on the objectives of the ACP that take into account the market data available to FEI at that time. However, it must be recognised that due to the many factors influencing natural gas supply and demand, the market for natural gas is always changing. Not only are there absolute price changes, but also changes in market factors (premiums or discounts) for securing physical supply. These changes are driven by the relationship between pricing points and the availability of resources.
The contracting strategy for the FEI’s Commodity and Midstream portfolios include a combination of monthly and daily priced supply for price diversification, in addition to contracting at multiple storage facilities and associated transportation resources. Daily priced supply can be resold in the market at the same price as it is bought and, therefore, remove any price exposure compared to monthly priced supply. This strategy helps FEI to remain cost neutral when reselling gas on the day. Monthly priced supply helps reduce exposure to market price volatility during the winter months.
FEI takes a longer term outlook when contracting for some resources, like transportation and storage assets, and may be restricted to some degree in changing these particular resources in the portfolio in a particular year. However, customers realize any benefit associated with such resources since they provide security of supply and increased portfolio diversity. Gas from various storage facilities in the winter provides the portfolio with diversity and intraday flexibility, as well as summer-priced supply.
Further details about these consideration are provided in the confidential components of the 2013/14 ACP.
2
The total system demand based on the usage from the total forecast number of accounts on the system on the coldest day expected to occur.
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2.2 Demand Forecast (Design Peak Day and Normal Load) The forecast of design peak day demand for the 2013/14 contract year is 1,218 TJ/d, which represents a decrease of 0.5 percent or 6 TJ/d over the 2012/13 contract year. Table 1 sets out the forecast design peak day and normal loads during the winter and summer season projected for the next five years. This table also sets out the forecast 2012/13 design peak day and normal loads that were used in the 2012/13 ACP.
Table 1: Forecast Design Peak Day and Normal Volumes by Service Region Contract Year 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 (TJ/d) (TJ/d) (TJ/d) (TJ/d) (TJ/d) (TJ/d) Columbia 28 28 28 29 29 29 Lower Mainland 9 00 8 92 8 98 9 05 9 10 9 15 Ft. Nelson 5 5 5 5 6 6 Inland 2 84 2 85 2 87 2 89 2 92 2 93 Whistler 7 7 7 7 7 7 Total Peak Day Load 1,224 1,218 1,226 1,235 1,243 1,250 Change n/a -6 8 9 8 7 % Change n/a -0.5% 0.7% 0.7% 0.6% 0.6%
Winter Normal Load Summer Normal Load Average Daily Normal Load
Annual Normal Load
485 190 312
(PJ/yr) 113.8
512 187 321
(PJ/yr) 117.3
516 188 324
(PJ/yr) 118.1
519 190 327
(PJ/yr) 119.5
523 191 328
(PJ/yr) 119.8
526 192 330
(PJ/yr) 120.4
For the 2013/14 contract year, the annual normal load is forecast to increase to 117.3 PJ from 113.8 PJ in 2012/13, resulting in an average daily normal load of 321 TJ/d in 2013/14 compared to 312 TJ/d in 2012/13. The 321 TJ/d will be the new daily baseload supply that will be received by FEI on behalf of the Commodity Providers, which includes FEI in its role as default commodity provider for customers who are not enrolled with marketers, in accordance with the ESM. The increase in normal loads in 2013/14 over 2012/13 is primarily attributable to an increase in forecast demand from commercial and small industrial customers.
2.3 Commodity Portfolio Overview: 2013/14 Commodity Providers, , supply the daily baseload volume that is equivalent to the normalized annual demand, which itself is derived from the normal load forecast. Commodity Providers must provide the normalized annual load requirement of 321 TJ/d, plus fuel, effective November 1, 2013.
Baseload supply for the 2013/14 contract year will be based on the following receipt point allocation percentages: 75 percent at Station 2, 25 percent at AECO/NIT, and 0 percent at Huntingdon. The percentage allocations have changed from previous years and are discussed in detail in Appendix C. Since the inception of the Customer Choice Program, the allocations for
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the provision of daily supply from Commodity Providers had been set as follows: 70 percent at Station 2; 15 percent at AECO/NIT and 15 percent at Huntingdon.
The Customer Choice Program was opened up to residential customers starting on May 1, 2007 with enrolments for an entry date of November 1, 2007. At that time, a large portion of residential unbundling contracts with Gas Marketers were termed up by customers for five years and the majority of these expired on October 31, 2012. Commencing on November 1, 2012, there was a significant reduction in the number of customers that decided to continue with Gas Marketers and instead opted to return to FEI as their commodity supplier based on the standard variable rate that is offered by the utility. FEI had estimated a high and a low case of gas volumes that would be supplied by Gas Marketers serving residential and commercial customers for the 2012/13 contract year as 40 TJ/d and 30 TJ/d in the 2012/13 ACP. However, after the 2012/13 ACP was filed, FEI significantly lowered its projection to 21 TJ/d as a more reasonable estimate for the 2012/13 contract year.
For the 2013/14 contract year, FEI expects that the volume supplied by Gas Marketers serving residential and commercial customers will drop even further. The average daily volume provided by Gas Marketers is expected to average 12 TJ/d while 309 TJ/d will be provided by FEI out of the total daily baseload supply of 321 TJ/d. As a result, the Gas Marketer supplied volume will represent less than 4 percent of daily baseload supply requirements while FEI will provide over 96 percent of the total daily supply. Gas Marketer supplied baseload volumes forecasted in this ACP are illustrated in Figure 1 below.
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3 Figure 1: 2013/14 Estimate of Gas Marketer Volumes
The estimated average daily consumption of 12 TJ/d is determined by taking the number of customers remaining with marketers per month multiplied by the use rate per customer that is then averaged for the November 1, 2013 to October 31, 2014 period. After netting Gas Marketer supplied baseload volumes from total forecast baseload volumes, means FEI will be required to provide the following amounts at the specified delivery points starting November 1, 2013:
Station 2: Alberta:
(321 TJ/d – 12 TJ/d) x 75% plus 3.1% fuel = 239 TJ/d (321 TJ/d – 12 TJ/d) x 25% plus 1% fuel = 78 TJ/d
The methodology used to calculate the fuel percentages that are used above for 2013/14 is consistent with the previous year’s approach, which is described in FEI’s letter to the Commission dated February 7, 2008. The fuel rates that are used above have remained unchanged since the start of the 2011/12 contract year 4 . FEI will continue to monitor the Fuel Gas account and will report the results of its review of the Fuel Gas Percentages to the Commission by the end of the 2013 summer, including a request to modify the fuel rates if necessary.
2.4 FEI Midstream Portfolio Overview: 2012/13 FEI Midstream’s annual evaluation of its portfolio considers critical factors such as security of supply, reliability, delivered cost of supply, and availability of alternative incremental resources.
3 4
This estimate is based on actual enrollments in the Customer Choice Program taken in January 2013. Approved via Commission Order G-120-12, dated September 11, 2012.
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To replace expiring resources and/or meet future growth requirements, FEI Midstream assessed a number of alternatives for 2013/14 including:
Station 2 supply and associated T-South transportation capacity; seasonal winter storage; shorter duration market area storage; Huntingdon and/or Stanfield, spot and peaking supply; and Kingsgate and/or Alberta supply..
Additionally, FEI also has on-system gas supply from resources such as the Tilbury and Mt. Hayes LNG storage facilities that can provide high volume supply on short demand during periods of cold and extreme winter weather or emergency situations.
FEI performed a review of the supply options available for the upcoming winter period, taking into account key market developments which have affected regional pricing and supply sourcing dynamics in the Pacific Northwest (PNW). After evaluation of the new peak and normal day load forecasts, current portfolio mix, and market developments, FEI Midstream recommends the following resource portfolio for 2013/14:
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Table 2: Planned Peak Day Portfolio for 2013/14 vs. 2012/13 Actual Portfolio
FEI recommends a forecast peak day value for 2014/14 of 1,218 TJ/d, a decrease of 0.5 percent from the 2012/13 value of 1,224 TJ/d.
1. Incremental storage contracts and third party storage redelivery service agreements that have been or will be negotiated will be outlined in greater detail within the confidential sections of the 2013/14 ACP.
2. Contracting at Station 2, Alberta, and Kingsgate supply is outlined in greater detail within the confidential sections of the 2013/14 ACP.
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3 FEVI 2013/14 ACP FEVI strives to procure and deliver natural gas in the most reliable manner possible which includes the responsibility to identify, monitor and mitigate potential operational and market-related risks. In addition, the minimization of costs related to the annual portfolio, while ensuring the delivery of gas each day, is a key objective.
Significant topics that follow in the FEVI 2013/14 ACP include the forecast design peak day and annual normal loads, changes in contracting of resources from the previous year, and long term contracting considerations. Key elements of FEVI’s porfiolio include:
Forecast Design Peak Day Demand for 2013/14 A decrease of 2.5 TJ or 2.3 percent in 2013/14 over the 2012/13 contract year is attributable mainly to a decline in the forecast use per customer.
Annual Normal Demand for 2013/14 A decrease of 0.3 PJ or 2.5 percent in 2013/14 over the 2012/13 contract year is also attributable mainly to a decline in the forecast use per customer.
Commodity Supply For 2013/14 FEVI proposes changes to its seasonal supply to account for changes in market conditions.
Storage and Transportation Contracting FEVI will adjust its pipeline transportation contracting according to the changes to its commodity supply for 2013/14. Storage resources remain unchanged from 2012/13.
3.1 Demand Forecast (Design Peak Day and Normal Load) FEVI’s forecast 2013/14 design peak day supply requirement is estimated at 106.2 TJ/d, excluding system gas and fuel, which equates to approximately 111.4 TJ/d with system gas and fuel. FEVI’s forecast design peak day has decreased from the prior year’s forecast primarily as a result of a decrease in use per customer. The forecasting methodology is consistent with that used to forecast the demand for other FEI regions.
Table 3 sets out the forecast design peak day and normal loads during the winter and summer season projected for the next five years starting with the 2013/14 gas year. This table also sets out the forecast 2012/13 design peak day and normal loads that was used in the 2012/13 ACP.
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Table 3: FEVI’s Forecast Design Peak Day and Normal Volumes. Contract Year 2012/13 2013/14 2014/15 2015/16 2016/17 2017/18 (TJ/d) (TJ/d) (TJ/d) (TJ/d) (TJ/d) (TJ/d) Total Peak Day Load in 108.7 106.2 108.2 110.2 112.1 113.6 Change n/a -2.5 2.0 2.0 1.9 1.44 % Change n/a -2.3% 1.9% 1.8% 1.8% 1.3%
Winter Normal Load Summer Normal Load Average Daily Normal Load
Annual Normal Load in TJs
47 23 32.6
(TJ/yr) 11.9
47 21 31.8
(TJ/yr) 11.6
48 21 32.6
(TJ/yr) 11.9
49 22 33.2
(TJ/yr) 12.1
50 22 33.7
(TJ/yr) 12.3
51 22 34.0
(TJ/yr) 12.4
The decrease in 2013/14 annual normal load forecast, compared to last year’s forecast, is attributable primarily to a decrease in the use per customer. However, the total annual forecast demand increases in future years, after the 2013/14 contract year, as a result of a projected increase in total customers (when multiplied with the same use per customer that was used to calculate the 2013/14 normal load).
3.2 FEVI Portfolio Overview Table 4 that follows sets out FEVI’s design peak day portfolio for 2013/14 and compares it to that from 2012/13.
Table 4: FEVI 2013/14 Recommended Peak Day Portfolio
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4 REGIONAL DEVELOPMENTS Significant changes are occurring in the natural gas marketplace in western Canada. These changes will likely impact traditional supply and demand dynamics and regional gas flows as well as regional market prices. The major supply potential in northeast BC has prompted the development of infrastructure initiatives that will be needed to serve new sources of demand. With declining gas supplies in Alberta and increasing demand from industrial, power generation and oil sands demand, TransCanada is expanding into northeast BC to access the significant new production basins that are being developed there. Furthermore, numerous LNG export projects have been announced for the west coast of BC. In addition, several projects have been proposed in the US PNW to move more gas to the growing I-5 market. The FEU are monitoring these developments as they will impact future resource availability and its cost effectiveness.
The proposed BC LNG export projects could significantly impact regional gas flows by the end of the decade. The recent announcement by the provincial government of British Columbia that four additional proponents are interested in potentially locating LNG liquefaction terminals at a new site, Grassy Point north of Prince Rupert, bring to eleven the projects considered for development in northern BC. Separately, Pacific Energy Corp. announced plans to develop a smaller scale LNG export project on the FEVI system near Squamish. These projects are driven primarily by an interest in accessing large supplies of reliable natural gas required to serve growing demand in key Asian markets that include Japan, South Korea, and China. These markets are seeking to diversify their sources of supply and are attracted by the political stability and mature market structure for accessing natural gas that Canada offers. LNG exports from BC represent the most significant new market opportunity that the Western Canadian Sedimentary Basin (WCSB) has seen and comes at a time when production from this basin is being increasingly pushed from traditional markets in eastern North America by new shale gas developments located closer to those markets.
BC is poised to be in the forefront of various developments surrounding pipeline, infrastructure and potentially significant volumes export of LNG to Asian markets over the next few years. However, the growth of natural gas production in BC is also subject to various influences such as pricing of commodity, influence of changing demand dynamics and cost of production. Continued expansion of gas production should benefit consumers in BC as this provides opportunities for increased supplies to be available in BC markets well into the future.
Developments on the regulatory front will also impact regional gas flow patterns. Earlier this year the NEB reach a decision on TransCanada’s Mainline Restructuring and Komie North applications, denying key aspects of each application, while approving others. It is unclear at this point how TransCanada will respond to these decisions, which makes the business impacts uncertain.
Based on these developments, the FEU will continue to act to ensure secure, reliable and cost effective supply for its customers.
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The FEU will continue to actively participate in pipeline infrastructure developments, tolling proceedings and other initiatives to ensure that the marketplace in BC offers supply liquidity and competitive pricing compared to neighbouring regional markets.
The FEU will continue to establish key relationships with major producers who plan to develop gas supply in the Horn River, Montney and other producing regions of BC over the long term including producers actively involved in attempting to develop an export LNG market to Asian markets.
The FEU will evaluate opportunities within their own operating region to improve infrastructure that will provide greater access to markets leading to better diversity and reliability within the portfolio over the long term.
The FEU believe that any increase in gas production in BC should provide a level of direct benefit to consumers in the province, which can be achieved by enhancing the liquidity and flow of gas at the Station 2 market hub. Therefore, the FEU will continue to proactively monitor developments and foster relationships with key producers in order to help ensure that accessible supply and competitive pricing are available at Station 2 over the long term.
The FEU are actively involved in NEB proceedings that affect the FEU’s access to supply and are also actively involved in developing solutions with regional stakeholders to help ensure issues related to third party pipeline infrastructure are favourably resolved. These activities are important because they help to ensure that customers in BC will continue to have access to cost effective supply over the long term.
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5 CONCLUSION The key objectives of the FEU are to contract for gas supply that offer security and diversity within the portfolio while minimizing overall portfolio costs over the short and long term. Therefore, the FEU continually evaluate developments in the regional marketplace such as infrastructure developments, regional pricing, cost and availability of resources, and growth opportunities in order to meet these objectives.
FEI and FEVI will continue to meet normal and peak day loads through diverse, flexible and cost effective portfolios of resources. While the forecast normal and peak day load requirements have changed only slightly from the previous year, other market factors are driving more significant changes in the FEI and FEVI portfolios for 2013/14. The FEU will continue to make appropriate changes to their portfolios as market conditions change in order to meet the objectives.
The FEU will continue to actively monitor and participate in pipeline infrastructure developments, tolling proceedings and other initiatives that will affect gas flows and pricing in the region. The FEU will also explore infrastructure improvements within its own service regions to promote liquidity and supply availability over the long term. The FEU will attempt to ensure that they continue to be able to access secure and reliable gas supply in a cost effective manner for core customers.
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