Document 2232624

Contents Recommendations for Change – AESO GTA – Customer Contribution Policy Appendix A: Recommendation Summary Appendix A.1: Standards of Service Appendix A.2: Services Cost Increases Appendix B: Details of Support by Working Group Appendix B.1: AltaLink Appendix B.2: ATCO Electric Appendix B.3: Enbridge Pipelines Inc. Appendix B.4: ENMAX Power Corporation Appendix B.5: EPCOR Utilities Inc. Appendix B.6: FortisAlberta Inc. Appendix B.7: DEPAL Consulting Appendix B.8: Desiderata Energy Consulting Appendix B.9: TransCanada Appendix C: Comments from Stakeholder Session October 15, 2008 Appendix C.1: Comments from the Cities of Red Deer and Lethbridge Appendix C.2: List of Stakeholder Attendees and Participants Recommendations for Consideration – AESO Customer Contribution Policy Introduction In April, 2008, a cross‐industry stakeholder group was formed to determine if improvements could be made to the AESO’s Contribution Policy. The group consisted of members from ATCO Electric, Enbridge Pipelines Inc. ENMAX, EPCOR, FortisAlberta, Shell Canada Ltd., TransCanada, DEPAL Consulting, Desiderata Energy Consulting, StatOil Hydro, AltaLink, and as observers, the AESO and AUC (the “Working Group”) Customer contributions have been growing steadily over the past few years resulting in concerns for Transmission Facility Owners, Distribution Facility Owners and Customers. The objective of the Working Group was to deliver a set of recommendations to the AESO for consideration in design of its next General Tariff Application. The Working Group identified key concerns with the current policy, and formed sub‐
teams to identify improvements and recommendations for consideration in design of the next AESO Contribution Policy. These recommended changes are listed below, and are described in detail in Appendix A: Recommendation Summary. Recommendations 1. Adopt a set of guiding principles into the contribution policy. 2. Enhance the definition of standard facilities, and lead a stakeholder consultation to develop Planning Principles and Standards of Service. 3. Incorporate a method of fairly allocating the costs associated with an early system rebuild. 4. Use an inflation factor that is representative of the Alberta market place, and incorporate a mechanism to adjust the contribution formula to account for regulatory lag. 5. Align the timing of prepaid O & M with costs, and apply prepaid O & M exclusively to facilities in excess of standard. 6. Provide flexibility on the timing of contribution payments, and provide choices for customers transitioning between tariffs. 7. Provide the choice for the contribution payment to be a facilities charge rather than a balance sheet transaction. 8. Provide new customers with both generation and load at the site, the opportunity to be “load first” in determination of their contribution payment. -1-
Consensus – Without Prejudice The Working Group strived for consensus on all recommendations, despite some participants having conflicting interests on some of the recommendations. Even though consensus has not been reached on every recommendation, all recommendations have been provided in this report as most of them have a high degree of support. Included below is a summary of the recommendations and the amount of support on each recommendation. Appendix B: Details of Support by Working Group also includes a report which describes the degree of support for each recommendation by each member of the Working Group. These recommendations are being provided on a “without prejudice” basis. Finally, Appendix C: Comments from the Stakeholder Session captures the concerns raised by non‐participating stakeholders which were collected at a stakeholder session in October, 2008. Support for Recommendations by % Recommendation Support Neutral Oppose Support with Conditions 1.0 78% 0% 0% 22% Guiding Principles 2. 0 44% 0% 0% 56% Standards of Service 3.0 55% 12% 0% 33% Early System Rebuilds 4.0 33% 55% 12% 0% Dual Use Sites 5.0 77% 0% 0% 23% Prepaid O & M 6.0 100% 0% 0% 0% Inflation 7.0 88% 12% 0 % 0% Timing & Uncertainty 8.0 55% 21% 12% 12% Customer Contribution Payment Options -2-
Future Assistance to the AESO Members of the Working Group offer to meet with the AESO regarding any of these recommendations over the next few months to provide assistance with design of the contribution policy. In addition, the members of the Working Group offer to participate in any stakeholder sessions that the AESO may conduct while completing their next GTA stakeholder consultation.
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Appendix A: Recommendations Introduction This document describes in detail recommendations for consideration by the AESO as they develop their next General Tariff application. The Working Group recognizes that not all of the recommendations may be adopted, and many will be modified as the AESO designs its next Contribution Policy. Many of the recommendations will require additional stakeholder engagement as the AESO proceeds with the next GTA. 1.0 Guiding Principles The working group identified a main concern that the Customer Contribution Policy does not currently have an established set of Guiding Principles. In this regard, the objectives of the policy are unclear. The Working Group recommends adoption of the following set of Guiding Principles: 1.1 The Customer Contribution Policy needs to consider economic signals1 to customers to encourage the best long term economic solution. The maximum investment level and the required customer contribution will send economic signals to customers. These signals should financially encourage customers to make interconnection decisions that are the most economical (for themselves and the system), while considering the long term transmission plan. 1.2 The Customer Contribution Policy needs to consider the best long‐term2 economic and technical solution to meet standard customer and system requirements. An interconnection Proposal should consider both the economics of the interconnection proposal (investment and customer contribution) as well as the best technical solution. This should be based on the needs of standard customer and system requirements. This all must be considered in the context of concerns around the environmental and other community issues. 1.3 The Customer Contribution Policy needs to consider that technical interconnection solutions and current interconnection costs drive the investment levels, not vice versa. Costs to interconnect customers will fluctuate as the market for materials and labour 1
One partying conveying meaningful information to another party, via signals that will have financial
impact.
2
Covering a relatively long period of time, in this case that is definitely longer than 1 year and more in the
range of 5-10 years.
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varies. Depending on the technical details of the interconnection and the fluctuating costs the investment level should vary correspondingly. In addition, the contribution formula should not lead to sub‐optimal technical solutions. 1.4 The Customer Contribution Policy needs to consider current utility standards of service, and that standards may change over time. Utility standards vary over time and the investment level, and therefore the customer contribution, should vary to match those varying standards. 1.5 The Customer Contribution Policy needs to consider minimizing intergenerational inequity. Recognizing cost inflation, the maximum investment and therefore the customer contribution, should strive to be fair between customers of different vintages. To the extent possible, new customers, or customers increasing their service level, should not proportionately pay any more, or less, then customers who have been on the system for a period of time. 1.6 The Customer Contribution Policy needs to consider harmonization among utilities (including the AESO) to ensure a consistent approach and treatment for all customers. In order to maintain equity, customers in different jurisdictions, or served at the transmission or distribution levels, should be treated fairly. Given that the tariffs may be different, the maximum investment calculation may not be identical. As well, aligning utility investment levels with the AESO’s investment level will help to minimize customer confusion and sub‐optimal system development. 1.7 The Customer Contribution Policy needs to consider incremental revenue from interconnection of new customers compared to the cost to serve them. As new customers interconnect to the AIES they will provide incremental revenue to the utility serving them. This revenue should be compared to the costs to interconnect them. 1.8 The Customer Contribution Policy needs to consider most customers should not pay a contribution for standard facilities. In this way, utilities would be compensated for the assets that they own, operate, and use to provide service. Historically, policy in Alberta has supported postage stamp rates wherein transmission load customers with reasonable interconnection costs do not pay up‐front costs to interconnect to the AIES. Reasonable interconnection costs are recovered from customers, via tariffs, over the life of their connection to the system. This results in utilities being compensated for owning and operating assets that they utilize to serve customers. This principle has been largely met in some tariffs by applying the “80/20 rule.” 1.9 The Customer Contribution Policy needs to consider that the methodology should be simple to administer and applied in a consistent and transparent3 manner. The more simple, consistent and transparent the investment policy is, the easier it will be for 3
The full, accurate, and timely disclosure of information to all stakeholders
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customers to understand it and have confidence in it. This should reduce the amount of utility staff time required to explain it to customers and lower the number of customer complaints. This will also lead to lower requirement for AUC involvement. It is the belief of the Working Group that common principles across TFOs, DFOs, and the AESO are beneficial to improving the Customer Contribution Policy and the Interconnection Process. The Working Group identifies that the “80/20 rule” is not a principle; it is simply one way of measuring, monitoring, or assessing if a particular contribution policy meets other principles of reasonableness, fairness, or intergenerational equity. The guiding principles are intended to identify that the current contribution policy does not establish an interconnection solution; it only established who pays for the solution when the payment is made. The Working Group believes that the adoption of the guiding principles will alleviate the concerns outlined. 2.0 Standard Facilities ‐ Standards of Service CONCERN The current definition of “Standard Facilities” is “the least‐ cost interconnection facilities which meet good transmission practice including applicable reliability, protection, and operating criteria and standards, and generally consists of a single radial transmission circuit and a single transformer to supply an individual point where electric energy is transferred between the customer’s facility and the Alberta Interconnected Electric System (“Point of Connection”).” Interpretation of this definition, along with a number of other factors such as inflation, regulatory lag and the contribution formula design, has led to increased levels of customer contributions. In fact, other than small breaker addition projects, most customer interconnections have a customer contribution. In contrast, prior to 2005, customer contributions occurred on less than 20 % of transmission interconnections. The increase in customer contribution levels has resulted in dissatisfaction amongst TFO’s, DFO’s and interconnecting customers. In addition, the application of this definition focuses the planning effort on the least cost solution instead of the optimum long term solution. RECOMMENDATION 1. Change the definition of Standard Facilities in the AESO tariff to “the most economical interconnection facilities which meet good utility practice including applicable reliability, protection, and operating criteria and standards”. 2. The AESO to lead a stakeholder process to establish Planning Principles and Standards of Service to guide application of the Contribution Policy. The following draft Planning Principles and Standards of Service are a potential starting point for the Stakeholder Consultation. Utilities across Alberta may use different specific -3-
standards due to evolution of their distribution/transmission network but the Planning Principles should be the same for each utility. These principles should help guide the development of the electric system as it evolves from minimum facilities supplying relatively small loads e.g.10 MVA, up to a major substation supplying loads over 100 MVA. Planning Principles (draft) 2.1 Target Restoration Times: In the event of a contingency, power should be restored by the target restoration times as documented in Table 3.1‐1 in the AESO’s “Distribution Point‐of‐Delivery Interconnection Process Guideline‐ Standards of Service”. If power cannot be restored by the targets, new facilities should be requested to allow the utility (i.e. TFO or DFO) to meet the target restoration times. Following are the target restoration times. Area Urban (population greater than 5000) Rural (population less than 5000) Guidelines for Target Restoration Times < 1 hour < 4 hours 2.2 Long Term Planning: The following should be used to guide long term planning decisions: a. Most electric utility facilities have a life of 25 years or greater and should be planned to be in service for at least 25 years. b. A new facility should be added approximately 3 years before the capacity of an existing facility is expected to be exceeded to ensure facilities are in place before they are critical. 2.3 Substation Location: Substations should be located close to the load center to ensure appropriate levels of restoration and to minimize interruptions 2.4 T&D Losses: Facilities should be planned to minimize transmission and distribution losses. 2.5 Motor Starting: Electric facilities should be sized to ensure customer motors can start with up to three times inrush current. Customers should be able to start motors off the electric system and meet flicker limits with reasonable reduced voltage starting equipment up to 3 times inrush. If motor starting violates three times inrush, the customer is required to fund a cost effective solution such as a VFD. -4-
2.6 Reliability of Service: When assessing the reliability of service to customers, the planner should consider: c. Number of Customers affected, d. Type of load (hospital, or oil and gas customers such as H2S safety concerns), e. Density of load, f. Social/economic/environmental impacts, g. Time to repair, and h. Time to restore service, to ensure that the expected restoration times are less than the target restoration times as documented in Table 3.1‐1 in the “AESO’s Distribution Point‐of‐Delivery Interconnection Process Guideline ‐ Standards of Service”. 2.7 Transmission vs. Combined Transmission/Distribution Service: When the cost between two technically feasible interconnection alternatives is close (within plus or minus 10%), customers should be able to choose which of the two alternatives is the Standard Facility for contribution purposes. 2.8 Cost, economics and schedule should be considered for any interconnection solution The following draft Standards of Service are proposed. A detailed explanation of these proposed standards is contained in Appendix A.1 – Standards of Service. These standards are a guide only, recognizing that different TFO’s have different standards that have evolved over time and different operating practices. Standards of Service (draft) Load Rural < 15 MVA One 138 KV line One 15/20/25 MVA transformer One 138 KV line Two 15/20/25 MVA transformers Two 138 KV lines Two 25/33/42 MVA transformers N/A 15 – 25 MVA 25 – 42 MVA 42 – 83 MVA Rural Area with Multiple Customers N/A Urban Two 138 kV lines One 15/20/25 MVA transformer N/A Two 138 kV lines Two 15/20/25 MVA transformers N/A Two 138 kV line Two 25/33/42 MVA transformers Two 138 kV lines Two 138 kV lines Two 50/67/83 Two 50/67/83 MVA transformers MVA transformers -5-
Industrial One 138 KV line One 15/20/25 MVA transformer One 138 kV line Two 15/20/25 MVA transformers Two 138 kV lines Two 25/33/42 MVA transformers Two 138 kV lines Two 50/67/83 MVA transformers 83 – 167 MVA N/A 240 kV /25 kV Motor Starting 2 transformers 3 x Inrush Two 240 kV lines Two 100/138/167 MVA transformers 2 transformers 3 x Inrush Two 240 kV lines Two 100/138/167 MVA transformers 2 transformers 3 x Inrush Two 240 kV lines Two 100/138/167 MVA transformers 2 transformers 3 x Inrush KEY BENEFITS & IMPACTS Adoption of the recommended definition change, Planning Principles and Standards of Service are expected to provide the following benefits: • Provides a clear and transparent approach to application of the contribution policy. •
Assists the AESO with planning for the long term rather than one interconnection at a time. •
Facilitates better decisions when planning for an area (rural or urban) that includes a combination of distribution and transmission •
Provides DFOs, TFOs and industrials with substations that meet pre‐defined levels of reliability. •
Minimizes debate between the AESO and customers regarding application of the contribution policy •
Increases customer satisfaction •
Eliminates rework at existing substations because long term planning implications will have been considered 3.0 Early System Rebuilds The AESO should consider the following principles when finalizing the rebuild and salvage policy: 3.1 The allocation of capital costs to the account of customer or system will be fair to existing and new customers. -6-
3.2 The allocation of capital costs to the account of customer or system will be easy to understand and administer. 3.3 If there is a rebuild required at or near the end of the useful life, the total cost of the rebuild is rolled into system cost and recovered from all customers. 3.4 If a capacity increase is required at a substation and, due to physical condition or age of the facility it is prudent to rebuild part or all of the substation at the same time, the cost of the rebuild will be rolled into system and the incremental cost related to the capacity increase will be allocated to the customer. 3.5 If a load addition requires a capacity increase and major apparatus is being removed from service, and the salvaged apparatus has the potential to be re‐used, a salvage credit (RCN) will be applied to the customer related costs. 3.6 Costs incurred under these principles will be recoverable by a TFO through either the Capital Maintenance program or through the Direct Assign. 4.0 Inflation The AESO customer contribution formula is based on actual project costs escalated at CPI. However, the CPI escalator is significantly lower than actual transmission cost escalation rates in Alberta4. The net result is increased contributions for most interconnections. Regulatory lag is further complicating this problem, which can result in a single contribution formula being in place for 2‐3 years. In addition, the cycle time to build a transmission interconnection is reaching lengths of 2‐4 years. The Working Group recommends that: 4.1 The AESO include an annual automatic escalator within the contribution policy, and that this should be tied to a published index. 4.2 The AESO should also adopt an inflation factor which is reflective of transmission costs in Alberta. 5.0 Prepaid Operating and Maintenance Charge An area of concern was identified regarding prepaid Operating and Maintenance Charges (“PP O&M”). The Working Group generally supports the AUC review of the R and V on the decision regarding PP O&M. The concerns of the Working Group are listed below: 4
Refer the Appendix A.2 – Services Cost Increases
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•
•
•
•
The O&M payment is not aligned with when costs are actually incurred. The AESO tariff is unclear on how O&M payments flow back to the TFO on optional facilities. The current AUC decision would apply PP O&M to all customer TFO facilities and not just optional facilities. PP O&M may appropriately be different between DFO and TFO, harmonization to the same value may not be appropriate. The Working Group recommends the following guidelines: 5.1 PP O&M should only apply to facilities in excess of standard. 5.2 Facilities in excess of standard should have PP O&M paid by the customer directly to the TFO, and managed by the TFO. 5.3 When facilities in excess of standard become standard facilities and a refund is made to the customer, the balance of the PP O&M should be returned from the TFO to the Customer. The O&M refund process, when changing from an optional to a standard facility, should be incorporated into the overall refund process which is currently in the development stages at the AESO. The refund should be the remaining balance of the PP O&M based on the asset depreciation rate. No earnings on the account balance need to be refunded as the benefit of the cash balance is accounted for in the discount rate used in calculating the PP O&M rate. 5.4 PP O&M should be charged upon energization of the facility. 5.5 Development of an aligned approach between the AESO and the TFOs regarding management of, and refund of PP O&M. Proposed Practices for the TFO The following practices are suggested for the TFO’s to administer the Pre‐Paid O & M: The PP O&M held by the TFO should be recognized as offsetting O&M, and not as “no cost capital”. TFO’s should hold the PP O&M as a deferred revenue item on their balance sheet to offset future O&M costs. The balance in this account should be “drawn down” at a rate equal to the depreciation rate (excluding the impact of salvage) of the asset it supports. This ensures equitable treatment of all parties when and if the status of an asset -8-
changes from optional to standard. The “draw down” rate of the pre‐paid O&M should be based only on the expected life of the facility. Salvage costs and salvage value are capital related items and should not be funded from, or related to, the PP O&M account balance. The Working Group believes the adoption of the recommendations regarding PP O&M ensure that existing customers are kept whole, while new customers are treated fairly. The recommendations allow the timing of the PP O&M charges to align with asset commissioning. Finally, there will be a clear process for transitioning facilities from “optional” status to “standard”, and there is a clear, consistent process for all TFOs and DFOs. 6.0 Timing and Uncertainty The working group identified a concern with the timing of a contribution payment under the AESO’s current Customer Contribution Policy. Currently, the policy indicates that customer contributions are payable prior to the start of construction. The Customer Contribution Policy in effect at this time is the one that applies to the project. Depending on the degree of change in Contribution Policies, having a solid cut off date for contribution policies can be problematic. The first issue is fairness. Two identical projects with similar timelines could end up with different tariff treatment simply because Permit and License was issued at different dates. Such a hard and fast date could lead to customers making decisions, not for the benefit of their project or the associated timelines, but simply to delay or advance a project’s Permit and License date, so that they can take advantage of a particular customer contribution policy. Customer’s taking action to delay or attempt to advance Permit and License can place additional pressure on AESO and TFO processes to accommodate changes. Another concern with the AESO’s current Customer Contribution Policy is the lack of a clearly defined method for altering estimates on the “standard facility” case. Currently the utility industry is experiencing extreme inflationary pressures. This combined with protracted project timelines, leads to situations where significant price differences can occur between an estimate that was prepared when options were being explored and the final costs. In cases where the AESO has classified the proposed facilities as being “in excess of standard”, the commercial terms to the customer is based on estimated, rather than actual costs. During periods of rapid inflation, it’s important that the appropriate assumptions and adjustments are being made to the “standard facilities” estimate to ensure fairness and consistency. In light of these concerns the Working Group recommends that in their next tariff application, the AESO: -9-
6.1 Define reasonable book‐end key activities within a project wherein either a former approved or a current approved Customer Contribution Policy would apply to a project. If there is a change in the approved Customer Contribution Policies between the point at time at which the customer receives their first proposal from the AESO for service, and the point in time at which the customer executes their final contract for service (which typically occurs a month or two prior to energization), then the customer is given a choice which Customer Contribution Policy should apply. 6.2 Include a procedure for updating “standard facilities” estimates to accurately reflect the conditions that are impacting the actual project, and would impact the standard facilities project if it were being constructed. A pro‐rata adjustment based on the amount that the actual project costs have increased, or decreased from the estimate would be appropriate. The working group believes that the movement from a hard date to a window for migration from one policy to another should eliminate pressure on AESO and TFO processes to get to a particular point in a project by a particular timeline in order to accommodate a shift in policy. This transition provides customers with some degree of certainty that a proposal that they are reviewing and accepting in relation to a project is the worst‐case from a Customer Contribution Policy perspective. It provides assurance that the costs on which a customer’s commercial terms are based on are being adjusted to reflect current market conditions and provides fairness and certainty. Finally, putting an adjustment process in place would ensure consistency of application across all projects. 7.0 Customer Contribution Payment Options A concern regarding customer contribution payment options was identified by the Working Group. Through this period of rapid and large scale expansion of the Alberta transmission system, the majority of direct connect projects are requiring very large up front customer contributions for facilities the customers don’t own and operate. This also results in the TFO owning and operating facilities being used to provide service that they are not earning a return on, while still incurring operational, ownership, integration and prudency risk, the same as any other asset. In these situations, resulting in large customer contributions, customers are financing utility owned/operated assets, for which they have no control or management of, nor do they assume any risk. The Working Group recommends that the AESO Investment Policy should include an option for the contribution to be set up as an AESO tariff payment determined by the TFO cost of service method including income tax, applied over the DTS/STS contract term. The contribution structured as an AESO tariff payment would be made available to any creditworthy customer. The attractiveness of the AESO Tariff Option to the customer will depend on the customers IRR and other factors including the customer’s election for treatment of the transaction on their balance sheet. The customer/POD - 10 -
specific AESO tariff Payment Option, or what has been referred to as a Facilities Charge Agreement, is not a new concept and has been applied successfully to specific PODs in the past. The adoption of the aforementioned eliminates the need for customer to deploy large amounts of capital for facilities they will not own and operate. 8.0 Load First Contribution Policy The Working Group identified a concern that investment for dual use‐customers is reduced by the customer’s substation ratio5 with a corresponding reduction in the DTS tariff. The Working Group believes that some customers may want a higher investment amount, and be willing to pay the standard tariff rates over time. The Working Group recommends that for a new or expanded POD a customer can elect to be “load first” and have the full DTS contract capacity increase applied to the DTS rate, the Primary Service Credit and the investment policy, regardless if there is a corresponding increase in STS contract capacity. In this case the “deemed” substation ratio will be 100%, and will not be the same as the DTS/(STS+DTS) contract capacity ratio (the “real” substation ratio) The benefits of adoption of this recommendation include greater customer choice to determine an appropriate level of system investment. This may dissuade some customers from building customer owned substations, and this would allow for the optimization of a comprehensive and more readily integrated system. Conclusion The Working Group recognizes that the downward pressure on customer contributions causes upward pressure on the rates. In summary, the Working Group believes that the recommendations maintain the postage stamp philosophy, while promoting equitable treatment among customers, DFOs, and TFOs. In addition, the recommendations will help align long term transmission planning with good utility practices, improve flexibility for customers, and improve cycle times through improved clarity, transparency, and consistency. 5
DTS contract capacity/ (DTS+STS contract capacity)
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Appendix A.1: Standards of Service Introduction It is intended that this guideline be used in conjunction with the AESO’s approved guideline “AESO Distribution Point‐of‐Delivery Interconnection Process Guideline – Typical Supply Arrangements”, in which various substation designs, from simple bus through to more elaborate ring bus configurations for both primary and secondary busses has been covered. It is intended that this guideline be used by various TFOs, DFOs and Industrial Customers, all with different planning and operating environments. It is recognized that TFOs and DFOs have different standards across the province, which have evolved over time. It is also recognized that TFOs have standardized on different transformer sizes in the past. It is recommended, here, that this document be used as a starting point to guide planning decisions on minimum standards, recognizing that different standards exist between the utilities. For illustrative purposes, this document will use the AtlaLink and FortisAlberta system, which was the former TransAlta system. Voltage Levels and Single Line Diagrams Voltage levels discussed in this document apply to the AltaLink system. It is recognized that the standard voltage, for the connection of a substation, in the AltaLink and Enmax system is 138 kV and in the AE system is 144 kV and in the EPCOR system is 240 kV. Low voltage levels for industrial customers discussed in this document are 4.16 kV; however, 13.8 kV and 25 kV and other voltage levels may also be used. Single line drawings used in this document are also typical of AltaLink. Other TFO’s may have their own standard configurations. Please refer to the “AESO Distribution Point‐of‐
Delivery Interconnection Process Guideline – Typical Supply Arrangements” for other supply arrangements. Correlation between load and Population The correlation between load and number of customers serviced or population serviced will vary from community to community depending on factors such as commercial load density and industrial load density. Analysis indicates that a relationship between load, as measured in kVA, and population is 1‐ 2.25 kVA per population; and a relationship between load, as measured in kVA, and the number of customers is 2 – 3 kVA per customer. For illustration purposes, the table below has assumed a relationship between load and population of 1.5 kVA per population; and a relationship between load and customers of 3 kVA per customer. -1-
LOAD 15 MVA 25 MVA 42 MVA Customers 5,000 8,000 14,000 Population 10,000 16,000 28,000 This information will help the reader understand the impact on customers and population of contingencies at different load levels. For example, an outage to a single element affecting 42 MVA of load would translate into affecting 14,000 customers or a population of 28,000. RECOMMENDATIONS It is recommended that the following good utility practices be adopted by the AESO to guide the orderly development of new substations into the future. Recommendations have been grouped into the following categories: 1. DFO Load – Rural –not greater than 42 MVA 2. DFO Load – Rural – with multiple industrial / commercial customers and load greater than 42 MVA 3. DFO – Urban – high population density (greater than 5000) 4. Industrial Load Distribution Facilities Owners (DFOs) Load 1.0 RURAL For purposes here, a Rural area is a community, as defined by the Alberta Municipal Affairs and Housing official population statistics, having a population of less than 5,000. Since, rural areas usually develop at a slower growth rate; the smallest transformer being used is a 15/20/25 MVA. Stage RI – Rural ‐ Loads less than 15 MVA Recommendation In rural areas, for load less than 15 MVA, a single radial 138 kV transmission line and one 138/25 kV, 15/20/25 MVA transformer is an acceptable supply option. (R2) Stage RI arrangement is shown in SLD R2. The guideline for rural areas is that for load levels less than 15 MVA, the risk of a single element contingency can be manageable. The premise is that the distribution system should have back‐up capability in the event of a contingency to the single radial -2-
transmission line or the single transformer outage and restoration can be made in less than the target restoration time which is 4 hours. Stage RII – Rural ‐ Loads of 15 MVA to 25 MVA Recommendation In rural areas, for the loads of 15 MVA to 25 MVA, a supply option consisting of a single radial 138 kV transmission line and two (2) 138/25 kV, 15/20/25 MVA transformers is acceptable. (R4) When considering the installation of a second transformer, the back‐up capability of the distribution system should be considered in the event of a contingency to the single radial transmission line or the single transformer and restoration should be made in less than the target restoration time of 4 hours. The alternative selected should be the most economic solution between the distribution and the transmission alternatives. Stage RII arrangement is shown in SLD R4. The progression from Stage RI to RII would occur when the DFO is forecasting a load increase, in the next three years, to go above 15 MVA. When considering the installation of a second transformer, at Stage RII, the back‐up capability of the distribution system should also be considered in the event of a contingency to the single radial transmission line or the single transformer outage and restoration should be made in less than the target restoration time which is 4 hours. The alternative selected should be the most economic solution. Stage RIII – Rural ‐ Loads of 25 MVA to 42 MVA Recommendation In rural areas, for the loads of 25 MVA to 42 MVA, a supply option consisting of two (2) 138 kV transmission lines from different source stations and two (2) 138/25 kV, 25/33/42 MVA transformers is acceptable. (U5) When considering the installation of the larger transformers, the back‐up capability of the distribution system should also be considered in the event of a contingency and restoration should be made in less than the target restoration time which is 4 hours. The alternative selected should be the most economic solution. Stage RIII arrangement is shown in SLD U5. The progression from Stage RII to RIII, would occur when the DFO is forecasting a load increase, in the next three years, to go above 25 MVA. Again, when considering the installation of the larger transformers, at Stage RIII, the back‐up capability of the distribution system should also be considered in the event of a contingency and -3-
restoration should be made in less than the target restoration time which is 4 hours. The alternative selected should be the most economic solution. 2.0 RURAL AREA WITH MULTIPLE INDUSTRIAL/COMMERCIAL CUSTOMERS When the load being supplied from a single substation grows to greater than 42 MVA, the area likely is a mixture of rural load and multiple industrial/commercial customers. An example would be the area around Hardisty. This area is a central location for a number of pumping stations for different pipeline companies. Stage RIV – Rural ‐ Loads of 42 MVA to 83 MVA Recommendation In rural areas with a mixture of rural load and multiple industrial/commercial customers, for the loads of 42 MVA to 83 MVA, a supply option consisting of two (2) 138 kV transmission lines from different source stations and two (2) 138/25 kV, 50/67/83 MVA transformers is an acceptable. When considering the installation of a second 138 kV transmission line and larger transformers, the back‐up capability of the distribution system should also be considered in the event of a contingency to the single radial transmission line or transformer and restoration should be made in less than the target restoration time which is 4 hours. The alternative selected should be the most cost effective solution. Stage RIV arrangement is shown in SLD RIV. Stage RV – Rural Loads of 83 MVA to 167 MVA Recommendation In rural areas with a mixture of rural load and multiple industrial/commercial customers, for the loads of 83 MVA to 167 MVA, a supply option consisting of two (2) 240 kV transmission lines from different source stations and two (2) 240/25 kV, 100/138/167 MVA transformers is acceptable. When considering the installation of two 240 kV transmission lines and larger transformers, the back‐up capability of the distribution system should also be considered in the event of a contingency and restoration should be made in less than the target restoration time which is 4 hours. The alternative selected should be the most economic solution. Stage RV arrangement is shown in SLD RV -4-
3.0 URBAN For purposes here, an Urban area is a community, as defined by the Alberta Municipal Affairs and Housing official population statistics, having a population of greater than 5,000. Recommendation The guideline for urban areas is that for a single element contingency (n‐1) load must be restored in less than one (1) hour. Since, urban areas develop at a rapid growth rate; the smallest transformer being used is a 25/33/42 MVA. The progression from Stage UI to UII would occur when the DFO is forecasting a load increase, in the next three years, to go above 15 MVA. When considering the installation of a second transformer, the back‐up capability of the distribution system should also be considered in the event of a single transformer outage and restoration should be made in less than 1 hour. The alternative selected should be the most cost effective solution. The progression from Stage UII to UII, would occur when the DFO is forecasting a load increase, in the next three years, to go above 25 MVA, etc, etc. Stage UI – Urban ‐ Loads less than 15 MVA Recommendation In urban areas, for load less than 15 MVA, a supply option consisting of two (2) 138 kV transmission lines from different source stations and one (1) 138/25 kV, 25/33/42 MVA transformer is acceptable. (U3) Stage UI arrangement is shown in SLD U3. Stage UII – Urban ‐ Loads of 15 MVA to 25 MVA Recommendation In urban areas, for the loads of 15 MVA to 25 MVA, a supply option consisting of two (2) 138 kV transmission lines from different source stations and two (2) 138/25 kV, 25/33/42 MVA transformers is acceptable. (U5) When considering the installation of a second transformer, the back‐up capability of the distribution system should also be considered in the event of a single transformer outage and restoration should be made in less than 1 hour. The alternative selected should be the most cost effective solution. -5-
Stage UII arrangement is shown in SLD U5. Stage UIII – Urban ‐ Loads of 25 MVA to 42 MVA Recommendation In urban areas, for the loads of 25 MVA to 42 MVA, a supply option consisting of two (2) 138 kV transmission lines from different source stations and two (2) 138/25 kV, 25/33/42 MVA transformers is acceptable. (U5) Note: Stage UII and UIII facilities are identical. Stage UIII arrangement is shown in SLD U5. Stage UIV – Urban ‐ Loads of 42 MVA to 83 MVA Recommendation In urban areas, for the loads of 42 MVA to 83 MVA, a supply option consisting of two (2) 138 kV transmission line from different source stations and two (2) 138/25 kV, 50/67/83 MVA transformers is acceptable. When considering the installation of the larger transformers, the back‐up capability of the distribution system should also be considered in the event of a contingency and restoration should be made in less than the target restoration time which is 1 hour. The alternative selected should be the most cost effective solution. Stage UIV arrangement is shown in SLD UIV. Stage UV – Urban Loads of 83 MVA to 167 MVA Recommendation In urban areas, for the loads of 83 MVA to 167 MVA, a supply option consisting of two (2) 240 kV transmission lines from different source stations and two (2) 240/25 kV, 100/138/167 MVA transformers is acceptable. When considering the installation of two 240 kV transmission lines and larger transformers, the back‐up capability of the distribution system should also be considered in the event of a contingency and restoration should be made in less than the target restoration time which is 1 hour. The alternative selected should be the most cost effective solution. Stage UV arrangement is shown in SLD UV. -6-
240 kV / 25 kV PODs There has been a number of new 240/25 kV PODs built lately with only one (1) transformer. Currently, the TFO’s do not own a 240/25 kV mobile transformer. Also a 240 kV mobile may not be practical. 240 kV mobiles become very large and need multiple trucks to haul them. Access to substation sites can be extremely difficult. Recommendation The minimum standard of service for 240 kV/25 kV substations should be to have 100% distribution back‐up or a second transformer in order to meet the target restoration times. INDUSTRIAL LOAD The guideline for industrial load is that for load levels less than 15 MVA, the risk of a single element contingency is manageable. The mobile transformer can be used in the event of the loss of a transformer. When planning for an industrial site, the redundancy that the customer designs into the low voltage electrical system should be considered in planning the design of the high voltage system. If the customer is using a back‐up on‐
site generator, this should be considered in the design of the high voltage system. The progression from Stage I1 to I2 would occur when the industrial customer is forecasting a load increase, in the next three years, to go above 15 MVA. The progression from Stage I2 to I3, would occur when the industrial customer is forecasting a load increase, in the next three years, to go above 25 MVA, etc, etc. Note: Included here are recommendations for switch gear to be included in the minimum standard, even though this equipment is not generally supplied by TFO’s. Industrial customers normally include this equipment in their own building outside the substation fence. Stage I1 – Industrial ‐ Loads less than 15 MVA For industrial load less than 15 MVA, a supply option consisting of a single radial 138 kV transmission line and one 138/4.16 kV, 15/20/25 MVA transformer is acceptable. Stage I1 arrangement is shown in SLD I1. Stage I2 – Industrial ‐ Loads of 15 MVA to 25 MVA For industrial loads of 15 MVA to 25 MVA, a supply option consisting of a single radial 138 kV transmission line and two (2) 138/4.16 kV, 15/20/25 MVA transformers is acceptable. -7-
Stage I2 arrangement is shown in SLD I2. Stage I3 – Industrial ‐ Loads of 25 MVA to 42 MVA For industrial loads of 25 MVA to 42 MVA, a supply option consisting of two (2) 138 kV transmission lines from different source stations and two (2) 138/4.16 kV, 25/33/42 MVA transformers is acceptable. Stage I3 arrangement is shown in SLD I3. Stage I4– Industrial ‐ Loads of 42 MVA to 83 MVA For industrial loads of 42 MVA to 83 MVA, a supply arrangement consisting of two (2) 138 kV transmission lines from different source stations and two (2) 138/4.16 kV, 50/67/83 MVA transformers is acceptable. Stage I4 arrangement is shown in SLD I4. Stage I5– Industrial ‐ Loads of 83 MVA to 167 MVA For industrial loads of 83 MVA to 167 MVA, a supply arrangement consisting of two (2) 240 kV transmission lines from different source stations and two (2) 240/4.16 kV, 100/138/167 MVA transformers is acceptable. Stage I5 arrangement is shown in SLD I5. Motor Starting Transmission facilities should be sized to ensure customer motors can start with up to three times inrush current. Customers should be able to start motors off the transmission system and meet flicker limits with reasonable reduced voltage starting equipment up to 3 times inrush. If motor starting violates three times inrush, the customer is required to find a cost effective solution such as a VFD. -8-
Stage RI – Rural Loads less than 15 MVA -9-
Stage RII – Rural Loads of 15 MVA to 25 MVA - 10 -
Stage RIII ‐ Rural Loads of 25 MVA to 42 MVA - 11 -
Stage RIV – Rural Loads of 42 MVA to 83 MVA - 12 -
Stage RV – Rural Loads of 83 MVA to 167 MVA - 13 -
Stage UI – Urban Loads less than 15 MVA - 14 -
Stage UII – Urban Loads of 15 to 25 MVA - 15 -
Stage UIII – Urban Loads of 25 MVA to 42 MVA - 16 -
Stage UIV – Urban Loads of 42 MVA to 83 MVA - 17 -
Stage UV – Urban Loads of 83 MVA to 167 MVA - 18 -
Stage I1 – Industrial Loads less than 15 MVA - 19 -
Stage I2 – Industrial Loads of 15 MVA to 25 MVA - 20 -
Stage I3 – Industrial Loads of 25 MVA to 42 MVA - 21 -
Stage I4 – Industrial Loads of 42 MVA to 83 MVA - 22 -
Stage I5 – Industrial Loads of 83 MVA to 167 MVA - 23 -
Appendix A.2: Services Cost Increases 2003‐
2004 6.1% 1. ENGINEERING Data Source: Project Management, AACE‐
Project Controls, Cost Association of Estimating/Engineering Cost Engineering‐ 2004‐2007 Salary Report Engineering APEGGA‐2004‐ 2.8% 2007 Salary Survey PM‐Engineering 4.4% Average 2. CONSTRUCTION Data Source: 2003‐
2004 Price indexes of non‐ Stats Canada ‐ 10.55%
residential building Construction construction Alberta‐ Industrial‐
Institutional‐ 2003‐2007 3. EQUIPMENT Data Source: 2003‐
2004 Total Transmission Handy Whitman 9.30% Plant ‐ Total Transmission Plant ‐ ALL Regions Average
4. WEIGHTED AVERAGE WEIGHT 2003‐
2004 ENGINEERING 32% 4.4% EQUIPMENT 34% 9.3% CONSTRUCTION 34% 10.6% WEIGHTED AVERAGE 8.2% CPI 1.4% -1-
2004‐
2005 6.1% 2005‐
2006 9.6% 2006‐
2007 11.0% 4.8% 6.9% 4.4% 5.4% 8.2% 7.7% 2004‐
2005 6.80% 2005‐ 2006‐
2006 2007 17.23% 11.18% 2004‐
2005 6.72% 2005‐
2006 8.63% 2006‐
2007 8.01% 2004‐
2005 5.4% 6.7% 6.8% 6.3% 2.1% 2005‐
2006 8.2% 8.6% 17.2% 11.4% 3.9% 2006‐
2007 7.7% 8.0% 11.2% 9.0% 5.0% Appendix B: Details of Support by Working Group Appendix B.1: AltaLink Appendix B.2: ATCO Electric Appendix B.3: Enbridge Pipelines Inc. Appendix B.4: ENMAX Power Corporation Appendix B.5: EPCOR Utilities Inc. Appendix B.6: FortisAlberta Inc. Appendix B.7: DEPAL Consulting Limited Appendix B.8: Desiderata Energy Consulting Appendix B.9: TransCanada Appendix B.1: AltaLink Recommendations for Consideration - AESO GTA
Customer Contribution Policy
General Indication of Support Subject to Further Consultation
Company: AltaLink
Support
1. Guiding Principles
a.
Economic signals to customers
b.
The best long term and technical solution
c.
Technical solution and current costs drive the investment levels
d.
Current utility standards, and that standards change over time
e.
Minimizing intergenerational inequity
f.
Harmonization between utilities
g.
Incremental revenue from new customers
h.
Most customers should not pay a contribution for standard facilities
i. Simple and consistent methodology application
2. Standards of Service
a.
Target Restoration Times
b.
Long Term Planning
c.
Substation Location
d.
T&D Losses
e.
Motor Starting
f.
Reliability of Service
g.
Transmission vs. Combined Transmission/Distribution Service
h.
Cost, economics & schedule should be considered
Neutral
Oppose
Support with
Conditions
Conditions for support or reasons for opposition
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
AltaLink conditionally supports this recommendation, provided that we
participate in the Stakeholder process to finalize the Planning Principles and
Standards of Service.
Support
3. Early System Rebuilds
×
4. Dual - Use Sites
×
5. Prepaid O& M
×
×
×
×
×
×
×
×
×
a.
Applied to facilities in excess of standard only
b.
PP O&M paid directly from the customer to the TFO
c.
TFO should hold PP O&M as deferred revenue
d.
Salvage costs and value should not be related to or funded from PP O&M
e.
Facilities are standardized, the balance of the PP O&M returned to the customer
f.
Charged upon energization
g.
AESO identify process for rate harmonization
h.
Incorporate the O&M refund practice into overall refund practice
6. Inflation
a.
Inclusion of an annual automatic escalator
b.
Relative inflation factor
7. Timing & Uncertainty
a.
Procedure for applying competing contribution policies
b.
Procedure for updating standard facilities estimates
8. Customer Contribution Payment Options
a.
AESO Tariff payment option
b.
Availability to any creditworthy customer
Signature
Name: Tony Demassi
Title: Director, Client Services and Conceptual Engineering
Date: November 19, 2008
×
×
×
×
×
×
×
×
×
Neutral
Oppose
Support with
Conditions
Conditions for support or reasons for opposition
Appendix B.2: ATCO Electric Recommendations for Consideration - AESO GTA
Customer Contribution Policy
General Indication of Support Subject to Further Consultation
Company: ATCO Electric
Support
1. Guiding Principles
Neutral
Oppose
Support with
Conditions
Conditions for support or reasons for opposition
X
a.
Economic signals to customers
X
b.
The best long term and technical solution
X
c.
Technical solution and current costs drive the investment levels
X
d.
Current utility standards, and that standards change over time
X
e.
Minimizing intergenerational inequity
X
f.
Harmonization between utilities
g.
Incremental revenue from new customers
X
h.
Most customers should not pay a contribution for standard facilities
X
X
i. Simple and consistent methodology application
X
2. Standards of Service
X
a.
Target Restoration Times
X
b.
Long Term Planning
X
c.
Substation Location
X
d.
T&D Losses
X
e.
Motor Starting
X
f.
Reliability of Service
X
g.
Transmission vs. Combined Transmission/Distribution Service
X
h.
Cost, economics & schedule should be considered
X
recognizing certain limitations, geographical, urban/rural, etc
Support
3. Early System Rebuilds
Neutral
Oppose
Support with
Conditions
Conditions for support or reasons for opposition
X
4. Dual - Use Sites
X
5. Prepaid O& M
X
a.
Applied to facilities in excess of standard only
b.
PP O&M paid directly from the customer to the TFO
X
Practicality/TFO decision for accounting stmt/financial treatment of PP O&M
c.
TFO should hold PP O&M as deferred revenue
X
TFO decision for accounting stmt/financial treatment of PP O&M
d.
Salvage costs and value should not be related to or funded from PP O&M
X
e.
Facilities are standardized, the balance of the PP O&M returned to the customer
X
f.
Charged upon energization
X
g.
AESO identify process for rate harmonization
X
h.
Incorporate the O&M refund practice into overall refund practice
X
6. Inflation
X
X
a.
Inclusion of an annual automatic escalator
X
b.
Relative inflation factor
X
7. Timing & Uncertainty
X
a.
Procedure for applying competing contribution policies
X
b.
Procedure for updating standard facilities estimates
X
8. Customer Contribution Payment Options
X
a.
AESO Tariff payment option
X
would apply to all contributions (not optional), other details
b.
Availability to any creditworthy customer
X
acceptable credit terms
Signature
Name: Michael Gillis, P. Eng
Title: Manager, Regulatory - ATCO Utilities
Date: November 19, 2008
Appendix B.3: Enbridge Pipelines Inc. Appendix B.4: ENMAX Power Corporation ENMAX Power Corporation
141 – 50 Avenue SE
Calgary, AB T2G 4S7
Tel (403) 514-3000
enmax.com
November 19, 2008
Ms. Heidi Kirrmaier
Vice President, Regulatory
Alberta Electric System Operator
Calgary Place
2500, 330 - 5th Ave SW
Calgary, AB T2P 0L4
Dear Ms. Kirrmaier,
Re:
AESO Customer Contribution Policy Working Group Recommendations
ENMAX Power Corporation (EPC) has participated in the Customer Contribution Policy Working
Group sessions lead by AltaLink Management Ltd (AltaLink) and has reviewed the final
recommendations of the Working Group being submitted to the Alberta Electric System Operator
(AESO). EPC has appreciated the opportunity to discuss the issues associated with the AESO’s
Customer Contribution Policy with AltaLink and other stakeholders. EPC is of the view that the
Working Group recommendations act to identify issues of concern to stakeholders, provide input on
how these concerns may be addressed, and will assist the AESO when it prepares its next General
Tariff Application.
EPC is generally supportive of several of the Working Group recommendations; however, EPC
recognizes that the full impact of the recommendations, if adopted by the AESO, can only be
comprehensively assessed when they are translated into specific tariff provisions. Further, EPC
notes that its submissions are made in the context of the specific issue being addressed by the
Working Group. Accordingly, EPC’s submissions with respect to the Working Group
recommendations are made on a ‘without prejudice’ basis and may vary as the discussion
progresses.
Guiding Principles
EPC supports the establishment of a clearly stated policy objective and a set of Guiding Principles.
The Working Group has identified nine Guiding Principles that it suggests the AESO should consider
when assessing its Customer Contribution Policy. These Guiding Principles include economic,
technical, fairness, societal, and practical considerations. In EPC’s view, the use of the term
‘consider’ is key since it is likely that trade-offs between the various considerations will need to be
made. For example, the best ‘technical’ solution to meet standard customer and system
requirements should be considered within an assessment of the cost impacts.
With respect to Guiding Principle 1.6, EPC recognizes that varying customer contribution policies
amongst utilities has the potential to lead to sub-optimal system development (e.g. a customer
chooses to locate in one area rather than another or take distribution service in preference to
transmission service in response to differences in contribution policy) and that this should be
considered. At the same time, EPC is of the view that the specific circumstances of each utility must
be considered in the utility’s customer contribution policy and that the potential for benefits from any
harmonization must be assessed against the potential for negative impacts.
Standard Facilities - Standards of Service
The Working Group has proposed that the definition of Standard Facilities be changed to replace the
term ‘least cost’ with ‘most economical’ and remove the wording that states that this will ‘generally
consist of a single radial transmission circuit and a single transformer to supply an individual point
where electric energy is transferred between the customer’s facility and the Alberta Interconnected
Electric System (“Point of Connection”)”. The Working Group has also provided a set of draft
planning principles for determining Standards of Service.
EPC is of the view that the Working Group submissions provide a valuable starting point for the
conversation on this issue; however, EPC believes that additional conversation on the specifics of the
submission are required.
Early System Rebuilds
EPC is generally supportive of the concepts contained in the Working Group recommendations;
however, EPC reserves the right to make more detailed comment when specific tariff provisions are
available for review.
Inflation
EPC supports the recommendation that the AESO Customer Contribution Policy should include an
annual automatic escalator tied to a published index and that the inflation index should reflect Alberta
transmission costs to the extent possible. However, EPC is of the view that further work is necessary
to determine the correct index to use.
Prepaid Operating and Maintenance Charge
EPC supports the Working Group recommendation.
Timing and Uncertainty
EPC is still considering the implications of the Working Group recommendation that reasonable bookend key activities within a project be defined wherein either the Customer Contribution Policy in place
at the time the customer receives its first proposal from the AESO for service or the time at which the
customer executes its final contract for service be available to the customer.
Customer Contribution Payment Option
EPC is still considering the implications of the Working Group recommendation with respect to this
issue. Accordingly, EPC has no submissions to make with respect to this recommendation.
Load First Contribution Policy
EPC is still considering the implications of the Working Group recommendation with respect to this
issue. Accordingly, EPC has no submissions to make with respect to this recommendation.
As stated earlier, EPC is of the view that the Working Group recommendations act to identify issues
of concern to stakeholders, provide input on how these concerns may be addressed, and will assist
the AESO when it prepares its next General Tariff Application. EPC thanks AltaLink for its facilitation
of this process.
Yours truly,
(original signed by)
Deborah Emes
Vice-President, Regulatory
ENMAX Corporation
Appendix B.5: EPCOR Utilities Inc. 10065 Jasper Avenue
Edmonton AB T5J 3B1
Canada
November 19, 2008
Mr. Tony Demassi
AltaLink Management Ltd.
2611 – 3rd Ave SE
Calgary, AB T2A 7W7
Dear Tony:
Re: AESO Customer Contribution Policy – Consensus Sign-off Document
Thanks for your leadership in organizing the Working Group sessions which culminated in
the AESO Contribution Policy recommendations. Please find attached EPCOR Utilities
Inc.’s Consensus Sign-Off Document, prepared on a without prejudice basis, for your
consideration.
Please contact me if you have any questions regarding our comments.
Sincerely,
<Original signed by>
Pat Wong
Senior Manager, Regulatory Affairs
EPCOR Utilities Inc.
Encl.
Recommendations for Consideration - AESO GTA
Customer Contribution Policy
General Indication of Support Subject to Further Consultation
Company: EPCOR Utilities Inc.
Support
1. Guiding Principles
Oppose
Support with
Conditions
Conditions for support or reasons for opposition
X
a.
Economic signals to customers
X
b.
The best long term and technical solution
X
c.
Technical solution and current costs drive the investment levels
X
d.
Current utility standards, and that standards change over time
X
e.
Minimizing intergenerational inequity
X
f.
Harmonization between utilities
g.
Incremental revenue from new customers
h.
Most customers should not pay a contribution for standard facilities
i. Simple and consistent methodology application
Neutral
X
The appropriate level of harmonization amonst utilities should also be considered given
differences in tariff structures, facility design, load types, etc .
X
The standards should be used as a guide only, recognizing that different TFO's have
different standards and operating practices that have evolved over time. The AESO should
lead a stakeholder process to establish the standards. In that process, the AESO
X
See above comment in this section.
X
X
X
2. Standards of Service
a.
Target Restoration Times
b.
Long Term Planning
c.
Substation Location
X
d.
T&D Losses
X
e.
Motor Starting
X
f.
Reliability of Service
X
X
g.
Transmission vs. Combined Transmission/Distribution Service
X
If "two technically feasible interconnection alternatives" means alternatives that yield equal or
close to equal system reliabibity, then there is no issue. The customer's choice, whether to
be interconnected to a transmission or combined transmission/distribution service, must not
affect the overall reliability of the interconnected areas and their vicinity.
h.
Cost, economics & schedule should be considered
X
See above comments in this section.
Support
3. Early System Rebuilds
Neutral
Support with
Conditions
Conditions for support or reasons for opposition
X
4. Dual - Use Sites
The AESO's current practice of assigning a substation ratio for dual-use sites is reasonable.
X
5. Prepaid O& M
X
a.
Applied to facilities in excess of standard only
X
b.
PP O&M paid directly from the customer to the TFO
X
c.
TFO should hold PP O&M as deferred revenue
X
d.
Salvage costs and value should not be related to or funded from PP O&M
X
e.
Facilities are standardized, the balance of the PP O&M returned to the customer
f.
Charged upon energization
g.
AESO identify process for rate harmonization
h.
Incorporate the O&M refund practice into overall refund practice
X
When facilities are systemized, the balance of the PP O&M should be refunded to the
customer
X
The inflation factor should be reflective of the cost of constructing transmission facilities in
Alberta
X
6. Inflation
X
X
X
a.
Inclusion of an annual automatic escalator
b.
Relative inflation factor
7. Timing & Uncertainty
X
X
a.
Procedure for applying competing contribution policies
X
b.
Procedure for updating standard facilities estimates
X
8. Customer Contribution Payment Options
X
a.
AESO Tariff payment option
X
b.
Availability to any creditworthy customer
X
Pat Wong
Signature
Name: Pat Wong
Title: Senior Manager, Regulatory Affairs
Date: November 18, 2008
Oppose
Appendix B.6: FortisAlberta Inc. Miles Stroh
Director, Regulatory
FortisAlberta Inc.
320 17th Avenue SW
Calgary, AB
T2S 2V1
Phone:
(403) 514-4229
Fax:
(403 514-5229
[email protected]
www.fortisalberta.com
November 19, 2008
Attention:
Participants and Stakeholders in the
AltaLink Customer Contribution Policy Consultation
Re:
FortisAlberta’s Submission on the Working Group’s
Recommendations for Consideration to the AESO
As per the schedule agreed to with the Working Group, attached is FortisAlberta’s consensus
form and FortisAlberta’s accompanying submission on the Recommendations for
Consideration to the AESO.
Sincerely,
“original signed”
___________________________
Miles Stroh
Director, Regulatory
FortisAlberta’s Submission on the
Working Group’s Recommendations for Consideration to the AESO in the
AltaLink Customer Contribution Policy Consultation
FortisAlberta provides this written submission to supplement the attached consensus form,
and to provide further explanation and context for FortisAlberta’s participation in the
Working Group and its support/non-support for the recommendations that were developed by
the Working Group. It is our understanding that the Working Group recommendations, and
each participant’s submissions, are to be provided to the AESO for consideration in its next
tariff consultation and application.
Participation in the Process
FortisAlberta participated in the process largely driven by its commitment in its 2008/2009
NSA, which stated:
“..Commencing in the first half of 2008, FAI [FortisAlberta] will initiate discussions with
other utilities and stakeholders to attempt to arrive at a common approach to MIL [Maximum
Investment Levels] between Alberta utilities and FAI will file evidence in its next DTA on
the need, or necessity, for further changes to the level of MIL.”
In April 2008 and prior to FortisAlberta proceeding on the above consultation commitment,
AltaLink initiated its own consultation process focusing on similar investment and customer
contribution matters, but mainly focused at the transmission level (i.e. the AESO tariff).
Given that this process was already engaging many of the transmission and distribution wire
owners and large transmission connected customers, FortisAlberta chose to participate in this
process before initiating further and similar discussions at the distribution tariff level with the
distribution companies and our customer stakeholders.
As such, FortisAlberta provides its support or non-support for the Working Group
recommendations on a without prejudice basis, and without the benefit of having full input
from its distribution customers. FortisAlberta’s support for these recommendations may vary
in the future based on further customer consultation and input at the distribution level.
Additionally, FortisAlberta recognizes that many of the recommendations are currently in a
high level form and will require further detail to be developed before we can fully support the
recommendations.
FortisAlberta appreciates the opportunity to have provided input in this Working Group
process and looks forward to further consultation with the participants and other customer
stakeholders in future forums on similar and related matters.
November 19, 2008
1
Recommendations for Consideration
The following comments are provided by FortisAlberta to further explain its support,
neutrality, or opposition to the Working Group Recommendations for Consideration:
1. Guiding Principles
FortisAlberta supports the adoption of Guiding Principles as a means to effectively develop a
principle-based investment or customer contribution policy - That is, a policy that has
investment levels and provisions that are driven by the application of a certain set of adopted
principles. Not unlike the rate design process, each of these principles must be weighted
depending on the policy provision that is being assessed. They must also recognize that even
though a common approach is desired, various utilities and customers exhibit differing
characteristics that must be accommodated.
FortisAlberta took this approach in its 2008/2009 DT Application (Appendix N – Review of
Maximum Investment Levels) and similarly, other utilities have been making similar
principle-based proposals with respect to determination of investment levels and customer
contributions. While each of these utilities may have acknowledged the use of slightly
different principles, they all seem to be largely aligned, and consistent with those proposed in
these recommendations. With the adoption of these principles for purposes of the AESO
tariff, and further consultation among utilities to converge on a common set of principles to
be applied at both the transmission and distribution levels, FortisAlberta believes this will
provide a strong framework for the evolution towards customer contribution policies that are
common among utilities to the extent possible.
As such, FortisAlberta generally supports this recommendation but in our view some of these
principles should carry greater weight than others. For example, we would submit that using
present day costs, rather than future expected rate revenue, as the starting point for
establishing investment levels is consistent with cost causation in that it can be transparently
tied to actual customer costs that are being quoted to potential new customers, thus providing
an appropriate and economically efficient price signal.
2. Standards of Service
FortisAlberta conditionally supports this recommendation based on the following comments
on specific changes. We support the change of definition to Standard Facilities in the AESO
tariff, and the initiation of an AESO-led stakeholder process to establish principles and
standards of service to guide the application of the AESO Contribution Policy.
November 19, 2008
2
Target Restoration Times
While FortisAlberta agrees that establishing target restoration times are needed and
understands that these times are just a starting point, the times quoted in Table 2.1 are
not realistic for a single transformer substation. As such, FortisAlberta opposes this
guideline until such time that reasonable and realistic times are established.
Long Term Planning
FortisAlberta generally supports this recommendation.
Substation Location
FortisAlberta generally supports this recommendation.
T&D Losses
FortisAlberta conditionally supports this recommendation given that this is just one
cost element to be assessed and needs to be balanced with overall capital costs.
Motor Starting
FortisAlberta supports this recommendation with the condition that it is made clear
that this guideline is intended to be applied for the evaluation of economic
alternatives and investment, and is not to be misconstrued as a supply standard for
general distribution loads.
Reliability of Service
FortisAlberta conditionally supports the recommendation given that we agree in
principle but the considerations that are listed require further detail to be applied
usefully by planners. Also, there is reference to the restoration times in Table 2.1,
which we oppose.
Transmission vs. Combined T/D Service
FortisAlberta generally supports this recommendation.
Cost, Economics & Schedule
FortisAlberta generally supports this recommendation.
November 19, 2008
3
3. Early System Rebuilds
FortisAlberta conditionally supports this recommendation in principle. However, we would
recommend that more work be done to establish a formula/table driven criteria based on age
of facilities, as this will achieve more transparency and remove undue discretion in the
application of this provision.
4. Dual-Use Sites
As a distribution company representing load, FortisAlberta has remained neutral on this
recommendation. FortisAlberta does note that at the distribution level, a load first policy
would be applied to the equivalent distribution connected dual-use sites under our currently
approved distribution tariff.
5. Prepaid O&M
FortisAlberta generally supports this recommendation.
6. Inflation
FortisAlberta generally supports this recommendation. It is further recommended that these
inflation factors only be applied in years where the AESO has not rebased its transmission
costs during an AESO tariff proceeding.
7. Timing & Uncertainty
FortisAlberta generally supports this recommendation based on the understanding that the
“reasonable book-end activity” dates, which allow for the window of flexibility, are firmly
defined.
8. Customer Contribution Payment Options
FortisAlberta opposes this specific recommendation largely as a result of a concern that such
a significant proposal may set a significant precedent that could have far reaching
implications on other utilities’ tariffs at both the transmission and distribution levels. In
FortisAlberta’s view, before advocating such an option at the transmission level, a thorough
November 19, 2008
4
review of how such a proposal would be administered, flowed through and harmonized with
Distribution Tariffs must be undertaken. Such a review and analysis has not been undertaken
in this process.
In addition, FortisAlberta has some very real concerns about the shifting of risk, upon the
event of default, from large customers to all other customers, as well as the administrative
complexity and financial/accounting treatment associated with such a proposal. Lastly,
FortisAlberta is of the view that if investment levels are brought in line with costs, in
response to other recommendations, the frequency and magnitude of customer contributions
may be reduced, thus removing the need for such an option.
November 19, 2008
5
Recommendations for Consideration - AESO GTA
Customer Contribution Policy
General Indication of Support Subject to Further Consultation
Company: FortisAlberta Inc.
Support
Neutral
Oppose
1. Guiding Principles
a.
Economic signals to customers
X
b.
The best long term and technical solution
X
c.
Technical solution and current costs drive the investment levels
X
d.
Current utility standards, and that standards change over time
X
e.
Minimizing intergenerational inequity
X
f.
Harmonization between utilities
X
g.
Incremental revenue from new customers
X
h.
Most customers should not pay a contribution for standard facilities
X
i. Simple and consistent methodology application
Support with
Conditions
Conditions for support or reasons for opposition
X
Please refer to FortisAlberta's accompanying Submission
X
Please refer to FortisAlberta's accompanying Submission
X
2. Standards of Service
a.
Target Restoration Times
b.
Long Term Planning
X
c.
Substation Location
X
d.
T&D Losses
X
e.
Motor Starting
X
f.
Reliability of Service
X
g.
Transmission vs. Combined Transmission/Distribution Service
X
h.
Cost, economics & schedule should be considered
X
X
Support
Neutral
Oppose
3. Early System Rebuilds
X
4. Dual - Use Sites
Applied to facilities in excess of standard only
X
b.
PP O&M paid directly from the customer to the TFO
X
c.
TFO should hold PP O&M as deferred revenue
X
d.
Salvage costs and value should not be related to or funded from PP O&M
X
e.
Facilities are standardized, the balance of the PP O&M returned to the customer
X
f.
Charged upon energization
X
g.
AESO identify process for rate harmonization
X
h.
Incorporate the O&M refund practice into overall refund practice
X
6. Inflation
X
a.
Inclusion of an annual automatic escalator
X
b.
Relative inflation factor
X
7. Timing & Uncertainty
X
a.
Procedure for applying competing contribution policies
X
b.
Procedure for updating standard facilities estimates
X
8. Customer Contribution Payment Options
Please refer to FortisAlberta's accompanying Submission
Please refer to FortisAlberta's accompanying Submission
X
a.
AESO Tariff payment option
X
b.
Availability to any creditworthy customer
X
Signature
Date:
Please refer to FortisAlberta's accompanying Submission
X
a.
Title:
Conditions for support or reasons for opposition
X
5. Prepaid O& M
Name:
Support with
Conditions
Please refer to FortisAlberta's accompanying Submission
Appendix B.7: DEPAL Consulting Limited Recommendations for Consideration - AESO GTA
Customer Contribution Policy
General Indication of Support Subject to Further Consultation
Company: Depal Consulting Limited
Support
1. Guiding Principles
Economic signals to customers
X
b.
The best long term and technical solution
X
X
c.
Technical solution and current costs drive the investment levels
X
X
d.
Current utility standards, and that standards change over time
X
X
e.
Minimizing intergenerational inequity
X
X
f.
Harmonization between utilities
X
X
g.
Incremental revenue from new customers
X
X
h.
Most customers should not pay a contribution for standard facilities
X
X
i.
Simple and consistent methodology application
X
X
X
a.
Target Restoration Times
X
b.
Long Term Planning
X
X
c.
Substation Location
X
d.
T&D Losses
X
X
e.
Motor Starting
X
X
f.
Reliability of Service
X
X
g.
Transmission vs. Combined Transmission/Distribution Service
X
X
h.
Cost, economics & schedule should be considered
X
3. Early System Rebuilds
Oppose
Support with
Conditions
Conditions for support or reasons for opposition
X
a.
2. Standards of Service
Neutral
X
Customers need to retain the right to choose their preferred method of
interconnection. Standards should be applicable only to the design and
application of the investment policy.
Support
4. Dual - Use Sites
X
5. Prepaid O& M
Applied to facilities in excess of standard only
X
X
b.
PP O&M paid directly from the customer to the TFO
X
X
c.
TFO should hold PP O&M as deferred revenue
X
X
d.
Salvage costs and value should not be related to or funded from PP O&M
X
X
e.
Facilities are standardized, the balance of the PP O&M returned to the customer
X
X
f.
Charged upon energization
X
X
g.
AESO identify process for rate harmonization
X
X
h.
Incorporate the O&M refund practice into overall refund practice
X
6. Inflation
Inclusion of an annual automatic escalator
X
X
b.
Relative inflation factor
X
7. Timing & Uncertainty
Conditions for support or reasons for opposition
Potential issue of fairness with other forms of generation.
X
X
a.
Procedure for applying competing contribution policies
X
X
b.
Procedure for updating standard facilities estimates
X
8. Customer Contribution Payment Options
X
X
a.
AESO Tariff payment option
X
X
b.
Availability to any creditworthy customer
X
Signature
Date: November 19, 2008
Support with
Conditions
X
X
a.
Title: President
Oppose
X
X
a.
Name: Ed de Palezieux
Neutral
The AESO must carefully assess each customer's credit before granting
the use of this new policy.
Appendix B.8: Desiderata Energy Consulting Appendix B.9: TransCanada Recommendations for Consideration - AESO GTA
Customer Contribution Policy
General Indication of Support Subject to Further Consultation
Company:
TransCanada
Support
1. Guiding Principles
Oppose
Support with
Conditions
Conditions for support or reasons for opposition
X
a.
Economic signals to customers
X
b.
The best long term and technical solution
X
c.
Technical solution and current costs drive the investment levels
X
d.
Current utility standards, and that standards change over time
X
e.
Minimizing intergenerational inequity
X
f.
Harmonization between utilities
X
g.
Incremental revenue from new customers
X
h.
Most customers should not pay a contribution for standard facilities
X
i. Simple and consistent methodology application
Neutral
X
2. Standards of Service
X
a.
Target Restoration Times
X
Target Restoration times seem too short and need to be reviewed for
practicality
b.
Long Term Planning
X
Facilites should be added to avoid critical situationsas as function of
area load growth, not necessarily set lead times.
c.
Substation Location
d.
T&D Losses
X
Transmission expenditures to reduce Distribution lossess should be
bourne by Distribution customers
e.
Motor Starting
X
Support three times inrush for the transmission system, may not be
viable for all distribution lines
f.
Reliability of Service
X
The historical number of interuptions must be considered
g.
Transmission vs. Combined Transmission/Distribution Service
h.
Cost, economics & schedule should be considered
X
Urban should be defined based on technical considerations such as
looped vs radial service and not only poulation
X
X
Support
Neutral
3. Early System Rebuilds
Conditions for support or reasons for opposition
If RCN is used, the salvage credit at the old site must equal the capital
charge for the apparatus at the new site. Consideration should be given
to using RCN-D as salvage value
X
5. Prepaid O& M
X
X
a.
Applied to facilities in excess of standard only
b.
PP O&M paid directly from the customer to the TFO
c.
TFO should hold PP O&M as deferred revenue
d.
Salvage costs and value should not be related to or funded from PP O&M
X
e.
Facilities are standardized, the balance of the PP O&M returned to the customer
X
f.
Charged upon energization
X
g.
AESO identify process for rate harmonization
h.
Incorporate the O&M refund practice into overall refund practice
6. Inflation
X
X
X
X
X
a.
Inclusion of an annual automatic escalator
X
b.
Relative inflation factor
X
7. Timing & Uncertainty
X
a.
Procedure for applying competing contribution policies
X
b.
Procedure for updating standard facilities estimates
X
8. Customer Contribution Payment Options
X
a.
AESO Tariff payment option
X
b.
Availability to any creditworthy customer
X
Sent electronically
Signature
Title: Market Services Specialist
Date: November 21, 2008
Support with
Conditions
X
4. Dual - Use Sites
Name: Chris Best
Oppose
The proposed treatment of PP O&M as Deferred Revenue should not
impact the overall TFO revenue requirement
Appendix C: Comments from Stakeholder Session‐ October 15th,2008 The following outlines comments raised by Stakeholders at a session held in October, 2008. After each stakeholder comment, a response has been provided. Guiding Principles: 1. Include a definition and further clarity of the terms “economic signals”, “long term”, and “transparency”. Response: These definitions have been included as footnotes to the recommendation in the recommendation summary. Standards of Service: 2. Ensure that there is intergenerational equality in the suggested proposal for customers that have paid large contributions in the past. Response: The Working Group anticipates that this concern may be addressed in the AESO’s consultation process. 3. Explore further work in the area of comparing urban vs. industrial vs. rural areas while looking at the proposal from an operational perspective. Response: The Working Group anticipates that the AESO will lead a stakeholder consultation to establish Planning Principles and Standards of Service. 4. Include a definition and further clarity of the terms “rural” and “urban”. Response: The Working Group anticipates that the AESO will lead a stakeholder consultation to establish Planning Principles and Standards of Service. 5. Explore the suggestion that when developing the Standards of Service rather than a population justification, perhaps an engineering element related to this is a better criterion. Response: The Working Group anticipates that this concern may be addressed in the AESO’s consultation process. Inflation: 6. Explore whether or not the recommendation on inflation was intended to include productivity gains. Response: The Working Group anticipates that productivity gains will be considered by the AESO as they develop the inflation methodology . 7. Identify if the recommendation on inflation was meant to incorporate an input or an output measure. -1-
Response: The Working Group anticipates that the decision on input or output measures will be considered by the AESO as they develop the inflation methodology. Prepaid Operating and Maintenance Charges: 8. Examine the materiality threshold of this recommendation. For example on a small interconnection project with little capital expenditure, there is more work required to adopt this principle than there is value added. Response: The Working Group anticipates that this concern may be addressed in the AESO’s consultation process. Customer Contribution Payment Options: 9. Include a definition and further clarity of how to isolate rate payers from default risk. Response: The Working Group anticipates that this concern may be addressed in the AESO’s consultation process. 10. Include a definition and further clarity of the tax treatment. Response: The tax treatment will likely be reflected as part of the customer specific tariff design and will include approved methods. 11. Identify a comprehensive list (Utility, AESO, Direct Connect, Stakeholders) of risks and how stakeholders are being compensated or sheltered. Response: The Working Group anticipates that this concern may be addressed in the AESO’s consultation process. 12. Provide further clarity and understanding of the credit test that the AESO currently applies to deem a customer creditworthy. Response: The Working Group anticipates that this concern may be addressed in the AESO’s consultation process. -2-
Appendix C.1: Comments from the Cities of Red Deer and Lethbridge Stakeholders who were not members of the Working Group were given the opportunity to provide formal submissions of written comments to the Working Group for their inclusion and submission to the AESO. Attached please find comments from the Cities of Red Deer and Lethbridge. October 29, 2008
Cayla Saby
AltaLink Management Ltd.
2611-3rd Avenue SE
Calgary, Alberta
T2A 7W7
Dear Ms. Saby
SUBJECT:
Customer Contribution Policy - Stakeholder Session held October 15,
2008
On behalf of the Cities, thank you for hosting the stakeholder session to inform parties of
the recent efforts of the Customer Contribution Working Group. The Cities are
encouraged by the leadership of AML and others to offer solutions to many of what the
Cities consider to be conceptual and practical deficiencies with the current AESO
contribution policy.
As the Cities are not members of the working group, the final form of the
recommendations is unknown and the process by which the recommendations may
influence AESO and AUC policy is unclear, the Cities are unable to take a position on
any of the working group’s detailed recommendations at this time.
Should the policy proposal be presented to the Alberta Utilities Commission in a formal
regulatory proceeding, the Cities would be pleased to provide additional comment at that
time.
Should you have any comments or questions, please feel free to contact me at (403) 7817690.
Sincerely,
<sent by e-mail>
Nigel Chymko
President
cc:
Otto Lenz
Ligong Gan
Appendix C.2: List of Stakeholder Attendees and Participants Name
Jim Graves
John Martin
Heidi Kirrmaier
Company
Aboriginal Community
AESO
AESO
Grant Pellegrin
Alberta Direct Connect Consumers Association
Colette Kearl
Al Nagel, CEO
Alberta Direct Connect Consumers Association
Alberta Federation of Rural Electrification
Associations
Henry Unryn
Brian Jackowich
Wade Vienneau
Tom Chan
Jamie Cameron
Jay Halls
Terry Lovelace
Peter Burgess
Chris Clark
Jim Beckett
Mark Rowe
Doug Creighton
Michael Turner
Azad Merani
Ed de Palezieux
Peter Schubert
Dale Hildebrand
Kaare Svidal
Kirk Byrtus
Rod Crockford
Deborah Emes
Ken Hawrelko
Shamir Ladhani
Mike Windsor
Richard Stout
Pat Wong
Mr. Acrkroyd
John Holmes
Brian Jamieson
Alberta Sugar Beet Growers and the Potato
Growers of Alberta
Alberta Urban Municipalities Association
Alberta Utilities Commission
Alberta Utilities Commission
Alberta Utilities Commission
Alberta Utilities Commission
Alberta Pacific Forest Industries Inc.
BP Canada
ATCO Electric
ATCO Electric
City of Calgary
City of Medicine Hat
Chymko on behalf of City of Lethbridge/Red Deer
Consumers Coalition of Alberta
DEPAL Consluting
Dow Chemicals
Desiderata Energy Consulting
Enbridge Pipelines Inc.
Enbridge Pipelines Inc.
Encana
ENMAX Corporation
ENMAX Corporation
ENMAX Corporation
ENMAX Corporation
EPCOR Utilities Inc.
EPCOR Utilities Inc.
First Nations - Montana Band and Piikani Nation
FortisAlberta
FortisAlberta
-1-
Involvement
Did Not Attend
Working Group
Did Not Attend
Did Not Attend - Involved
in One on One
Conversations
Did Not Attend - Involved
in One on One
Conversations
Attended
Did Not Attend - Received
Recommendations via
mailout
Attended
Did Not Attend
Attended
Did Not Attend
Did Not Attend
Did Not Attend
Did Not Attend
Working Group
Working Group
Sent Representative
Did Not Attend
Attended
Did Not Attend
Working Group
Did Not Attend
Working Group
Working Group
Did Not Attend
Did Not Attend
Working Group
Working Group
Working Group
Working Group
Working Group
Working Group
Did Not Attend
Attended
Working Group
Miles Stroh
Cynthia Johnston
Bob Smith
Kateryna
Tsukanova
Mike Checkland
Sheldon Fulton
Evan Bahry
Greg Jansen
Edward Witstock
Raj Retnanandan
Mark Young
Brian Blattler
Ed Hucman
Michael Cote
Dan Levson
Chris Best
Nicole Martel
David Gray
Ron Henderson
Rick Cowburn
Tony Demassi
John Piotto
Zora Lazic
Cayla Saby
Kansie Merrill
Stan Miller
Mike Gillis
Jana Mosley
Raj Sharma
Kevin van
Koughnett
Greg Matwichuck
FortisAlberta
FortisAlberta
Working Group
Did Not Attend
Did Not Attend - Received
Recommendations via
mailout
TransAlta
Imperial Oil Ltd.
Imperial Oil Ltd.
Industrial Power Consumers Association of Alberta
Independent Power Producers Society of Alberta
Petro-Canada
Petro-Canada
Public Institutional Consumers of Alberta
Shell Canada Ltd.
StatoilHydro ASA
Did Not Attend
Did Not Attend
Did Not Attend
Did Not Attend
Did Not Attend
Did Not Attend
Did Not Attend
Working Group
Working Group
Nexen Canada
TransCanada Pipelines Keystone
TransCanada Energy
TransCanada Energy
Urban Development Institute
Utilities Consumer Advocate
Utilities Consumer Advocate
Utilities Consumer Advocate
AltaLink
AltaLink
AltaLink
AltaLink
AltaLink
Did Not Attend - Received
Recommendations via
mailout
Did Not Attend
Working Group
Working Group
Did Not Attend
Did Not Attend
Did Not Attend
Attended
Working Group
Working Group
Working Group
Working Group
Working Group
ATCO Electric
ATCO Pipelines
AESO
AESO
Did Not Attend - Received
Recommendations via
mailout
Working Group
Working Group
Attended
TransAlta Wind
Stephen Johnson Chartered Accountants
Did Not Attend - Received
Recommendations via
mailout
Attended
-2-