Bulletin 2016-16 August 25, 2016 Transmission rate treatments to recover electric transmission related investments On January 31, 2013, the Alberta Utilities Commission issued a letter stating it was initiating a coordinated process to examine alternative approaches and rate treatments that might mitigate or smooth the impact on consumers of rate or bill increases, while ensuring regulated utilities continue to have an opportunity to earn a fair return on capital. 1 The Commission has concluded its process and provides its final determinations on this initiative in this bulletin. 2 1 Forecast transmission additions Significant transmission capacity additions to the bulk electric system 3 are underway in Alberta. The Alberta Electric System Operator s (AESO) five-year 2013 long-term plan, released on January 31, 2014, 4 identified 37 transmission projects to be constructed. The report estimated the cost for these projects to be $11.6 billion in 2013 dollars, of which $7.5 billion in projects had been approved by the AUC and the remaining $4.1 billion in projects had yet to receive regulatory approval. In November 2015, the AESO updated its five-year long term plan and provided the following updates: 5 Southern Alberta Transmission Reinforcement (SATR) project this project was initially scheduled to be implemented in three stages. Stage 1 was completed; some projects within Stage 2 were deferred and Stage 3 was cancelled. Foothills Area Transmission Development (FATD) east project this project was approved by the AUC in October 2013. This project includes a new 240/138-kilovolt (kv) substation, a new 240-kV line and enhancements to the related 138-kV system; all of which were expected to be completed by fall 2015. 1 2 3 4 5 Alberta Utilities Commission efiling System, Proceeding 2421, Exhibit 0001.01.AUC-2421. In addition to this bulletin, the report Alternative Approaches and Rate Treatments to Recover Electric Transmission Related Investments and the appendices are available on the AUC s efiling System, Proceeding 2421. The bulk electric system generally includes transmission lines and associated equipment generally operated at voltages of 100 kv or higher. AESO 2013 Long-Term Transmission Plan, January 31, 2014. AESO 2015 Long-Term Transmission Plan, November 23, 2015.
Page 2 The Edmonton to Calgary Transmission System Reinforcement project this project includes the Eastern Alberta Transmission Line (EATL) and the Western Alberta Transmission Line (WATL). Both lines were expected to be in service by the end of 2015. Heartland Transmission System Reinforcement (Heartland) project this project was initially energized at 240 kv in December 2013 and then energized at 500 kv in mid- 2014. Fort McMurray Transmission System Reinforcement project this project includes two major components, the west and east 500-kV transmission projects. The west project was awarded in 2014 through the AESO s competitive procurement process and the in-service date is forecast for 2019. The AESO has deferred the in-service date for the east project. The actual costs for the completed projects have yet to be finalized. However, given the number of announcements 6 about increasing costs, it is anticipated that the combined total cost for these projects will be higher than originally forecast in the 2013 long-term plan. The AESO also identified a number of regional transmission projects in the 2015 long-term plan and indicated that, while the near-term (to 2020) regional transmission projects are likely to proceed, many other regional projects will likely be deferred for several years. 7 In its low-growth scenario, the AESO proposed 11 near-term regional transmission projects with projected costs of $800 million; in its main outlook for growth, the number of transmission projects increased to 17 at a projected cost of approximately $2.5 billion. 8 The added costs for new transmission infrastructure will result in higher rates for consumers. The higher transmission costs may have implications for the way in which these costs are allocated to end-use customers. 2 The rate impact of new transmission on consumers In the Commission s view, the allocation of capital costs associated with new transmission investment should be clear, predictable and based on sound principles. In general, beneficiaries of the new transmission investment, or those that cause the costs, should pay for new transmission, and prices should reflect the cost of the transmission services that are being provided. In practice, the allocation of capital costs associated with new transmission investment must also be consistent with governing legislation which may be influenced more by public policy than by economic principles. A number of principles have been relied upon in past decisions in assessing cost allocation. These principles are at times in conflict with one another and, in specific circumstances, 6 7 8 For example, the AUC posts correspondence it receives on matters that are to be dealt with in future proceedings on its website under the link Items of Interest and then Items related to future proceedings. AESO Long-Term Transmission Plan, November 23, 2015, page 4. Ibid., page 4.
Page 3 judgment must be exercised in determining the relative weighting to be assigned to individual principles. The following concepts should be considered in an examination of the rate impact of new transmission investment on consumers: A principled basis for cost allocation. Intergenerational equity. Balancing rate mitigation with the provision of price signals that support efficient outcomes. The opportunity for regulated utilities to earn a fair return on capital. 2.1 Principled basis for cost allocation In Alberta, the AESO applies to the AUC under Section 30 of the Electric Utilities Act, SA 2003, c. E-5.1 for approval of the Independent System Operator (ISO) tariff. The rates, and terms and conditions in the tariff determine how costs are to be recovered from customers. Under the tariff, the costs are recovered from all electricity load customers (residential, commercial, farm and industrial) largely in proportion to their use of the transmission system, and the costs for transmission are included as part of the delivery charges on a customer s bill. Section 30(3)(a) of the Electric Utilities Act stipulates that the rates set out in the tariff shall not be different for customers as a result of their location on the transmission system. 9 This is commonly referred to as a postage stamp rate. The AESO applies cost causation principles to the rate design set out in the ISO tariff application 10 and relies upon a cost causation study and a point of delivery cost function to determine the functionalization and classification of costs for rates set out in the ISO tariff. 11 In previous decisions, the Commission has found that rates based on cost causation should provide price signals that result in fair, objective, and equitable outcomes, and should minimize or eliminate inter-customer subsidies. 12 The Commission determined that cost causation is the primary consideration when evaluating a rate design proposal and, barring unusual regulatory events such as regulatory lag or dramatic changes in cost structure, has found that rates that reflect cost causation should generally prevail over other secondary considerations, including rate shock, when assessing the AESO s rate design. 13 9 10 11 12 13 Electric Utilities Act. Proceeding 2718, 2014 ISO tariff application, Exhibit 0002.00.AESO-2718, Section 6.2, paragraph 257, page 47. Ibid., Section 5.0, pages 28-42. Ibid., paragraph 254, page 47. The application of these principles to the AESO s rate design was discussed in both Decision 2005-096: Alberta Electric System Operator (AESO), 2005/2006 General Tariff Application, Application 1363012-1, August 28, 2005, and in Decision 2007-106: Alberta Electric System Operator, 2007 General Tariff Application, Application 1485517-1, December 21, 2007. Ibid., paragraphs 254-255, page 47.
Page 4 Consideration of the principles governing the allocation of costs for new transmission development was beyond the scope of this initiative. Nevertheless, the concepts that support the allocation of costs for transmission are discussed below, as they will continue to be considered by the Commission with respect to future ISO tariff applications. 2.2 Intergenerational equity New transmission capacity is generally built in large increments, which often include surplus capacity to allow for future increased load. For this reason, the addition of new transmission capacity tends to be lumpy in nature, where significant periods of large investment in transmission are often followed by lengthy periods in which there is little or no increase in transmission capacity. In Alberta, current ratepayers have been benefitting from transmission investments, some of which were made more than 20 years ago, with only limited investment in the late 1980s and 1990s. Consequently, in the recent past, transmission costs in Alberta have not significantly increased. As multiple large transmission projects are completed and put into service, customers will necessarily face increasing rates. The principle of intergenerational equity requires that both present and future customers bear a fair share of the costs of new transmission. The assessment of which customers benefit from the use of transmission assets determines the timing and basis for cost recovery. If benefits are not properly considered, current customers could pay for capacity put in place to serve future customers. Correspondingly, future customers that benefit from additional transmission capacity may not pay their fair share of its cost if, for example, the cost recovery period is too short. Applying the regulatory principle that there should not be a transfer of equity between different generations of customers, dictates that the costs associated with the transmission additions should be allocated over the economic life of a transmission asset proportionate to the consumption of the service potential of the asset. However, it is difficult to apply this principle in practice. First, it is difficult to determine the total capacity of a transmission network, let alone the contribution of an individual asset. Second, it is challenging to develop a rational methodology to allocate service potential to current and future customers for a number of reasons, including the difficulty in forecasting future use given the expected longer service lives of recent investments in bulk transmission. In addition, because Alberta has an interconnected electric system, any change in the configuration of the system could alter the network interactions and may affect the pattern of usage on the transmission system. The Commission considers the interests of all customer classes and the transmission facility owners (TFOs) in light of the principle of intergenerational equity in determining the revenue requirements of the TFOs and ultimately, the rates to be paid by customers for transmission service through the ISO tariff. 2.3 Balancing rate mitigation with the provision of price signals that support efficient outcomes Rate treatments that might mitigate or smooth the impact on consumers of large investments in transmission must be balanced with the need to provide price signals that reflect the true cost of the transmission services that are being provided. The manner in which costs are recovered and,
Page 5 in turn, the incentives that the resultant price signals provide, should support efficient outcomes. The Commission recognizes that care must also be taken not to distort the underlying principles with respect to cost causation or to distort how different customers use the transmission system. The Commission understands that providing price signals that support efficient outcomes can often be in conflict with rate mitigation or rate smoothing measures, and can also be in conflict with the objective of minimizing intergenerational inequity. Nevertheless, the importance of providing economic signals has been extensively discussed in prior AESO tariff proceedings and the Commission remains of the view that giving price signals that support efficient outcomes should be given more weight relative to other objectives. 14 2.4 An opportunity for regulated utilities to earn a fair return on capital When the Commission launched this initiative, it clearly stated that an examination of alternative approaches and rate treatments to mitigate or smooth the impact on consumers must also ensure that regulated utilities continue to have an opportunity to earn a fair return on capital. The rate mitigation alternatives examined in this initiative represent a significant departure from current practices and therefore, would need to be considered in a comprehensive tariff application or in a separate Commission-initiated proceeding. In this way, all factors, including any risks, would be examined in a full and transparent manner and all stakeholders, including a regulated utility that may be affected by a change, would have an opportunity to comment on the proposed changes. 3 Alternative approaches and rate treatments that might mitigate or smooth the impact on consumers In a letter dated November 28, 2013, the Commission indicated that this initiative would focus on two alternatives that offered the greatest potential for mitigating or smoothing the rate impact on consumers in the Alberta context: (1) a rate cap and deferral account mechanism and (2) the use of depreciation alternatives to delay capital recovery. 15 Other alternatives were identified at a stakeholder conference 16 and considered by the Commission, but rather than analyze a large number of alternatives, the Commission determined that the two options selected would allow it the flexibility to vary the inputs and test the level of rate mitigation that could be achieved relative to the status quo. If the analysis showed promise in achieving the desired objective, the two options could then be examined in greater detail and 14 15 16 Decision 2012-362: Alberta Electric System Operator, 2012 Construction Contribution Policy, Proceeding 1162, Application 1067193-1, December 28, 2012, paragraph 40; other decisions include Decision 2000-1: ESBI Alberta Ltd, 1999/2000 Phase I and II, Application 990005, Files 1803-1 and 1803-3, February 2, 2000, and Decision 2005-096: Alberta Electric System Operator (AESO), 2005/2006 General Tariff Application, Application 1363012-1, August 28, 2005. Proceeding 2421, Exhibit 0023.01.AUC-2421. The Commission invited parties to participate in a stakeholder conference to provide input on: the scope of the initiative, the process for conducting the initiative and any timing considerations. The stakeholder conference was held on March 18, 2013 at the AUC Calgary offices.
Page 6 further refined for possible implementation. However, if this objective could not be achieved, the exercise could provide insight into the potential effectiveness of other alternatives that offered a lesser degree of rate mitigation or rate smoothing. 3.1 Rate cap and deferral account mechanism The rate cap and deferral account mechanism was proposed in a report prepared by the Transmission Cost Recovery Subcommittee (TCRS); a subcommittee of the Transmission Facilities Cost Monitoring Committee. 17 A copy of the TCRS report is available on the Commission s efiling System, under Proceeding 2421. The TCRS report concluded that, of the several alternatives examined, a cap on the transmission costs passed on to consumers, combined with a deferral account mechanism, would be an effective method of shifting costs from current to future customers. 18 Under the rate cap and deferral account mechanism, the transmission costs to be included in the ISO tariff would be capped and increased each year by the forecast rate of inflation. However, the AESO would continue to pay the TFOs their approved revenue requirements. The differences between the capped transmission costs and the actual revenue requirements would be accumulated in a deferral account that would be increased by the accrual of carrying costs. In later years, the transmission rate would be increased as the balance in the deferral account is drawn down. 3.2 Depreciation alternatives to delay capital recovery Given the changes in technology and design associated with new transmission capital additions, and changes in transmission reliability standards, the Commission considered that recent investments in transmission assets may have much longer lives than existing transmission assets. Therefore, the Commission examined the rate mitigation impact of changes in depreciation methods and changes in service lives that might be implemented to reflect the new investments. A utility s revenue requirement is the sum of operating expenses, including depreciation, income taxes and a return component, representing a fair rate return on the assets employed to provide utility service (rate base). The depreciation method adopted by a utility affects not only its depreciation expense, but its rate base and return and, for a company using the flow-through method, its income taxes. The selection of the depreciation method should reflect the loss in service potential of the asset not restored by ongoing maintenance. Depreciation methods may be flat over the life of the asset, increase over time or decrease over time. Regulators examine the depreciation component of the revenue requirement to ensure that rates reflect the loss in service potential of the assets. 17 18 Proceeding 2421, Exhibit 2421-X0001. The Transmission Facilities Cost Monitoring Committee, Transmission Cost Recovery Subcommittee Report, June 8, 2012. bullet number 3, page 4.
Page 7 Depreciation methods that delay capital recovery for transmission assets that have been built to include capacity for future users, reflect a greater loss in service potential in later years, as the asset s capacity is utilized. The Commission retained Foster Associates Inc. (Foster) to examine depreciation alternatives that would delay capital recovery. The objective of the study was to evaluate depreciation alternatives that delay capital recovery without abandoning generally accepted depreciation and ratemaking principles. In its report, Evaluating Depreciation Alternatives for Delaying Capital Recovery (Foster report), 19 Foster concluded that regulatory practices that defer recognition and recovery of depreciation are not necessarily in conflict with cost allocation and accounting theory, as long as the opportunity for capital recovery is preserved and any unrecovered investment from early retirements is allowed to remain in rate base and earn an authorized rate of return. A copy of the Foster report is available on the Commission s efiling System, under Proceeding 2421. The Foster report explained that, both from an accounting and a valuation perspective, depreciation can be used to represent the service potential of an asset, or group of assets, that is consumed during an accounting interval (e.g., year). The dual objective of depreciation accounting is cost allocation over the economic life of an asset in proportion to the consumption of service potential. The economic life of an asset is the time period over which economic benefits or service potential are realized. Ideally, the cost of an asset should be allocated to future periods of operation in proportion to the amount of service potential expended during each accounting interval. Depreciation expense is an estimate of the cost of the service potential consumed. It follows that, if it is predictable that the net revenue generated by an asset will either increase or decrease over time, an accelerated or decelerated time-based method should be used to approximate the rate at which service potential is actually consumed. Foster explained that a compound interest method using a zero discount rate produces the equivalent of the straight-line method currently used in Alberta, but when used with positive discount rates the compound interest method achieves a delay of capital recovery and thus could provide rate mitigation. 4 Scenario testing results To assist with this initiative, the Office of the Utilities Consumer Advocate (UCA) agreed to work with stakeholders to test the two mitigation alternatives using the AESO s Transmission Rate Impact Projection (TRIP) model. The UCA engaged EDC Associates Ltd. (EDC) to review the TRIP model, run sensitivity analyses, make any necessary adjustments to the model and run scenarios to test the impact of each mitigation alternative. A copy of the Commission s report, prepared with input from EDC and the UCA, which details the results of the analysis 20 (Analysis report) is available on the Commission s efiling System, under Proceeding 2421. 19 20 Proceeding 2421, Exhibit 2421-X0002. Proceeding 2421, Exhibit 2421-X0003.
Page 8 As described in the Analysis report, under the rate cap and deferral account alternative, the rate associated with the transmission wires cost, 21 or TFO cost, was capped at $26/MWh in 2015 and escalated annually by inflation. In the analysis, the deferral account balance was constrained such that it would be eliminated in 20 years. Under this constraint, the balance grew to a peak of $2 billion. This analysis also assumed a government of Alberta-backed carrying cost of 3.8 per cent. The table below is reproduced from the Analysis report and summarizes the extent of the mitigation or smoothing of the rates using the rate cap and deferral account alternative, under the assumptions in the Analysis report. Table 1. Typical customer Extent of the mitigation or smoothing of the rate rate cap and deferral account Maximum savings per month (2018) TFO cost per month Savings as a percentage of TFO cost per month Total delivered cost per month Savings as a percentage of total delivered cost per month Residential $3.38 $30.17 11.2% $128.67 2.6% Large industrial $129,192 $1,212,083 10.7% $3,226,767 4.0% The maximum rate reduction relative to the baseline monthly electricity bill for a residential customer was $3.38 per month in 2018, a savings of 11 per cent on the transmission component of the bill, but only a 2.6 per cent saving relative to the total delivered cost. 22 A large industrial customer would experience a similar percentage saving on the transmission component of its electricity bill and a four per cent saving relative to its total delivered cost. 23 However, the Analysis report states that the use of the rate cap and deferral account mechanism would result in average costs being higher than customers would otherwise pay beyond 2024, as the deferral account balance was drawn down. The analysis performed by EDC demonstrated that a deferral account balance would be very sensitive to changes in several input assumptions; specifically, load forecast, capital costs, and interest rate. Further, if it were to become necessary to increase the rate cap to ensure the deferral account balance would be contained within acceptable limits, this would serve to counteract any rate mitigation achieved. The depreciation alternative was tested for the four largest Alberta transmission development projects. 24 The analysis included extending the average service lives from 40 years to 50 years; switching from straight-line to a compound interest method of depreciation using a discount rate of 6.37 per cent (assumed weighted average cost of capital); and testing the compound interest 21 22 23 24 The transmission wires cost or TFO cost are those costs paid by the AESO to the TFOs for the use of a TFO s transmission facilities, it represents only a portion of the total transmission cost, which also includes the cost of operating reserves, ancillary services and the AESO s own general and administrative costs. The total delivered cost for a residential customer (or distribution connected customers) includes the total transmission cost, distribution cost, local access fee, retail charge and the cost of energy used. The total delivered cost for a large industrial customer (or transmission-connected customer) includes the total transmission cost plus the cost of energy used. The large transmission development projects include: EATL, WATL, SATR and FATD.
Page 9 method of depreciation using a discount rate of 15 per cent. The assumption of a 15 per cent discount rate was an extreme case to test the limits of the method. The table below is reproduced from the Analysis report. It demonstrates the aggregate extent of rate mitigation associated with using a compound interest depreciation method for the four largest transmission development projects, with a 50-year asset life and a 15 per cent discount rate. Table 2. Typical customer Extent of the mitigation or smoothing of the rate compound interest depreciation Maximum savings per month (2018) TFO cost per month Savings as a percentage of TFO cost per month Total delivered cost per month Savings as a percentage of total delivered cost per month Residential $1.48 $30.17 4.9% $128.67 1.2% Large industrial $56,894 $1,212,083 4.8% $3,226,767 1.8% Using the 50-year compound interest depreciation method instead of the 40-year straight-line depreciation method reflected in the status quo resulted in a maximum rate reduction of $1.50 per month in 2018 (a five per cent reduction) for a residential customer. The reduction for a residential customer relative to the total delivered cost of electricity was 1.2 per cent. A large industrial customer would also experience a maximum five per cent saving in 2018 on the transmission component of its monthly electricity bill but less than a two per cent saving relative to its total delivered cost. Again, similar to the rate cap and deferral method, using a compound interest depreciation method to mitigate rates in the short term would result in consumers paying more than they otherwise would beyond 2033. The Analysis report also states that should the depreciation alternative be implemented to achieve these monthly savings, other factors must also be taken into consideration: The financial implications for the transmission facility owners of delaying capital recovery (e.g., credit metric concerns, higher risk). Delaying recovery of depreciation expense nearer to the end-of-life raises the risk that the asset may become no longer physically used or useful in providing utility service before the asset is fully depreciated, thus increasing the potential for a stranded cost. The compound interest method is a significant departure from the depreciation methodology that is currently used in Alberta (generally a straight-line, equal life group or whole life approach) and there will likely be concerns raised with respect to implementation costs. The rate cap and rate deferral account methodology resulted in a larger percentage reduction in a typical customer s rates than the compound interest methodology. However, in terms of the total delivered cost per month, the percentage mitigating effects on consumer rates with either method are relatively small. While the two methods do achieve some level of rate mitigation, these small
Page 10 benefits associated with the rate reductions achieved must be weighed against the risks contemplated above. 5 Future considerations This initiative set out to examine alternative approaches and rate treatments that might mitigate or smooth the impact on consumers of rate or bill increases, while ensuring regulated utilities continue to have an opportunity to earn a fair return on capital. The Commission chose to examine two alternatives, each of which represented a significant departure from current practices in Alberta to test whether taking certain actions could result in an overall smoothing of rate increases and in turn, mitigate the rate or bill impact on consumers. The results of the analysis suggest that no one method, on its own, is likely to produce a meaningful reduction or significant smoothing of the impact on consumers rates or bill increases. In addition, the analysis suggests that the adoption of either alternative would mean that consumers would pay more over time than they would if the Commission were to retain the status quo. The Commission is also mindful that if the alternatives considered were to be adjusted to further mitigate short-term rate increases, consumers would pay even more over time than they would if the Commission were to retain the status quo. This does not mean that the Commission cannot seek to mitigate the rate effects occasioned by the addition of the capital investments in transmission to the rate bases of the TFOs. Rate impacts are routinely considered by the Commission as part of ISO and TFO tariff applications. The Commission considers the existing regulatory framework will continue to be the best way to address the regulatory treatment of transmission investment in the future. This approach recognizes that the ISO tariff is subject to periodic review to determine whether the beneficiaries from the investment have changed in any major way that would require a change to the method by which costs are attributed to rate classes, in order to ensure that the incentives provided by price signals support efficient outcomes. Examples where the Commission has already taken steps to mitigate rate impacts in past applications include: In the AltaLink Management Ltd. 2013-2014 general tariff proceeding, AltaLink was encouraged to separately track the large bulk system assets currently being placed into service. The ability to maintain the actuarial data for these distinct assets will assist in determining whether the service life data indicates that the substantial engineering improvements implicit in recent plant additions result in extending useful service life. Similarly, in the EPCOR Distribution & Transmission Inc. (EPCOR) 2013-2014 general tariff proceeding, EPCOR was directed by the Commission to maintain the accounting and depreciation records for its Heartland transmission line assets and assets of a similar nature in a manner that would allow for the isolation of depreciation and net book value of those assets at some future time. EPCOR was also directed to explore the effects of ISO Rule 502.2 as they relate to EPCOR s transmission lines and towers and consider the requirements of enhanced functional specifications, and the impact that any new design
Page 11 and selection requirements may have on the expected service lives of newly constructed assets falling under this rule. In Decision 2014-258, 25 the compliance filing for the AltaLink 2013-2014 general tariff application, the Commission stated that its directive to AltaLink to review its project inservice dates with the AESO was intended to address any cost mitigation opportunities that might be available through delaying projects during this period of significant transmission capital investment. In Decision 2014-242, 26 related to the AESO 2014 ISO tariff proceeding, the Commission directed the AESO to develop revised language in its tariff terms and conditions pertaining to the designation of system versus market participant costs. As stated in that decision, the purpose of this direction was to ensure that, if there is advancement in the in-service requirement of an end-use customer dependent on a system project that does not provide congestion relief, the end-use customer may be required to pay for some or all of the incremental costs associated with that advancement. In Bulletin 2015-15, 27 the Commission stated that Proceeding 20922 was initiated to address the customer advancement cost component of the ISO tariff. In Decision 2011-134 28 and Decision 2011-453, 29 the Commission suspended the construction work in progress (CWIP) accounting treatment in place at that time for ATCO Electric Ltd. and AltaLink, respectively. This allowed the utilities to recover construction-related financing costs as they were incurred during construction rather than waiting until after the asset was constructed and placed into service. This treatment is commonly referred to as CWIP in rate base. This relief was granted by the Commission primarily as a means of addressing credit metric concerns due to abnormally high balances in the utilities CWIP accounts as a result of the large investment in transmission. However, in Decision 2011-453, the Commission also recognized that CWIP in rate base treatment would result in a more gradual increase in customer rates over time, which would smooth out and help to mitigate the sudden large increases in revenue requirement that would occur under the traditional treatment. In the recent AltaLink and ATCO Electric general tariff applications (proceedings 3524 and 20272 respectively) rate relief was an issue in both proceedings. The Commission approved certain aspects of the rate relief measures proposed in the AltaLink proceeding. 25 26 27 28 29 Decision 2014-258: AltaLink Management Ltd., Refiling Pursuant to Decision 2013-407 and Decision 2013-459, Proceeding 3024, Application 1610245-1, September 8, 2014. Decision 2014-242: Alberta Electric System Operator, 2014 ISO Tariff Application and 2013 ISO Tariff Update, Proceeding 2718, Application 1609765-1, August 21, 2014. Bulletin 2015-15, Commission-initiated proceeding to address the customer advancement cost component of the Alberta Electric System Operator s tariff, October 22, 2015. Decision 2011-134: ATCO Electric Ltd.. 2011-2012 Phase I Distribution Tariff, 2011-2012 Transmission Facility Owner Tariff, Proceeding 650, Application 1606228-1, April 13, 2011. Decision 2011-453: AltaLink Management Ltd., 2011-2013 General Tariff Application, Proceeding 1021, Application 1606895-1, November 18, 2011.
Page 12 The Commission has determined that it will not, as a policy, adopt either of the rate mitigation proposals it has considered in this initiative. Rather, alternative approaches and rate treatments to mitigate or smooth the impact on consumer rates will be considered on a case-by-case basis, from time to time, in the context of comprehensive tariff applications. Should parties wish to pursue the alternatives examined in this report or to pursue other alternatives, a proposal must be brought forward in either an ISO tariff application, in the case of a rate cap and deferral account mechanism or a similar proposal, or a TFO general tariff application in the case of depreciation alternatives. (original signed by) Robert D. Heggie Chief Executive