Cost Allocation Issues Whitepaper. September 14, 2015

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1 Cost Allocation Issues Whitepaper September 14, 2015 Revised November 9, 2015

2 Table of Contents Executive Summary... 2 Introduction... 2 Summary of Issues... 2 Path Forward... 3 Background... 3 Importance and Purpose of Cost Allocation... 3 MISO s Current Cost Allocation Options... 5 MISO South Region Transition Period... 5 Cost Allocation Issues... 6 Issue 1: Otherwise beneficial projects that fail to meet the current eligibility criteria for cost allocation may not proceed, or may proceed without the ability to appropriately allocate costs to beneficiaries... 6 MEP Voltage Threshold... 6 Risk Metrics... 7 Lack of Clear Procedures for Treatment of All Projects...11 Issue 2: Widespread Allocation of Costs...11 Granularity of MEP Cost Allocation...11 MVP Postage Stamp and Portfolio Requirement...12 Issue 3: Gaps and Overlaps Between Various Cost Allocation Rules...13 Regional Project Hierarchy...13 Interregional and Regional Criteria Misalignment...13 Gap Between MISO South Transition Period and Interregional Cost Allocation...14 Work Plan Appendix

3 Executive Summary Introduction The bulk electric system is in the process of undergoing significant change. State renewable portfolio standards and new federal environmental regulations have and will continue to drive fundamental changes in the mix of resources. This generation portfolio shift, MISO s materially changed geographic scope and the new planning, interregional coordination and cost allocation requirements stemming from FERC Order 1000 highlights the importance of ensuring that MISO maintains effective cost allocation methodologies which will support the necessary transmission build and drive ongoing alignment of costs and beneficiaries. The Planning Framework of the Transmission Owner s Agreement (TOA) tasks MISO with the responsibility to ensure the reliable operation of the transmission system, support achievement of state and federal energy policy requirements, and enable a competitive electricity market to benefit all customers. 1 As these system changes have unfolded, MISO stakeholders have voiced diverse concerns regarding the effectiveness of certain regional and interregional cost allocation provisions of the MISO Tariff. The MISO Tariff may not be providing the tools necessary to pursue the most effective overall transmission solution, and in some cases, may create barriers to that solution. Thus, MISO is undertaking a review of issues related to cost allocation. Summary of Issues MISO believes it is an appropriate point in time to evaluate the current cost allocation metrics and criteria to determine: (1) if they are appropriate or are generally too conservative; (2) if and to what extent they may cause barriers to cost-effective and beneficial transmission investment; and (3) to evaluate if modifications are appropriate given the changing planning environment. The cost allocation and metric issues can be categorized as follows: 1. Otherwise beneficial projects that fail to meet the current eligibility criteria for cost allocation may not proceed, or may proceed without the ability to appropriately allocate costs to beneficiaries 2. Widespread allocation of costs (in certain instances) is incompatible with the geographic size of the footprint 3. Gaps and overlaps between various cost allocation rules Conservative cost allocation metrics affect planning and may result in misalignment between costs and beneficiaries 1 Transmission Owners Agreement, Appendix B, Section VI 2

4 Path Forward MISO proposes to collaborate with stakeholders to evaluate the effectiveness of MISO s current cost allocation methodologies and, if found appropriate, drive necessary changes to the cost allocation provisions of the Tariff. This paper is the first step in this process and is intended to provide a comprehensive summary of Market Efficiency Project, Multi-Value Project, and interregional cost allocation issues. MISO will engage in discussions with stakeholders to validate these issues and identify others. This will be followed by a process to prioritize issues and pursue solution development based on the issue priority. Background Importance and Purpose of Cost Allocation Fair and equitable cost allocation methodologies are integral to successful implementation of long-term robust transmission plans that support future load growth, accommodate new energy policy, and provide system flexibility. Robust business case Policy consensus Match who benefits with who pays over time In order for transmission projects to be successful there are four conditions precedent that must be met: 1. A robust business case for the project, 2. Policy consensus around what issue is being addressed, 3. Clearly defined cost allocation methods that closely align who pays with who benefits, and 4. Cost recovery mechanisms that reduce financial risk Cost recovery mechanisms that reduce financial risk If one of these four elements is not met by a transmission project, then there is a high likelihood that the project will fail. In addition, as discussed above, MISO is responsible to ensure the reliable operation of the transmission system, support achievement of state and federal energy policy requirements, and enable a competitive electricity market to benefit all customers 2. In support of these requirements, MISO s regional expansion planning process is governed by six Guiding Principles, one of which recognizes that cost allocation mechanisms must ensure that costs of transmission projects are allocated in a manner roughly commensurate with the projected benefits of those projects. 2 Transmission Owners Agreement (TOA), Appendix B, Section VI 3

5 A lack of sufficiently robust cost allocation options or cost allocation that interferes with planning decisions may jeopardize MISO s ability to fulfill its planning obligations and adhere to the Guiding Principles. FERC s Order 890 and Order 1000 also recognize that sound cost allocation policies are critical to the development of new transmission infrastructure. These FERC Orders require: Planning processes to address cost allocation, The cost of transmission solutions chosen to meet regional transmission should be allocated fairly to beneficiaries, and Six cost allocation principles be satisfied for regional and interregional cost allocation 3 : 1. Costs should be allocated to those who benefit in a manner that is roughly commensurate with estimated benefits 2. Costs should not be allocated involuntarily to those that receive no benefit, at present or in likely future scenarios MISO Transmission Planning Guiding Principles 1. Make the benefits of an economically efficient electricity market available to customers by identifying transmission projects that provide access to electricity at the lowest total electric system cost. 2. Develop a transmission plan that meets all applicable NERC and Transmission Owner planning criteria and safeguards local and regional reliability through identification of transmission projects to meet those needs. 3. Support state and federal energy policy requirements by planning for access to a changing resource mix. 4. Provide an appropriate cost allocation mechanism to ensure that costs of transmission projects are allocated in a manner roughly commensurate with the projected benefits. 5. Analyze system scenarios and make the results available to state and federal energy policy makers and other stakeholders to provide context and to inform choices. 6. Coordinate planning processes with neighbors and work to eliminate barriers to reliable and efficient operations. 3. Project benefit-to-cost ratio thresholds should not exceed 1.25 unless justified and approved by FERC 4. Costs of regional and interregional facilities must be allocated solely within the transmission planning region unless an entity outside the region voluntarily agrees to assume a portion of the costs 5. The cost allocation method and data requirements for determining benefits and identifying beneficiaries must be transparent 6. Different cost allocation methods may be applied to different types of transmission facilities. 3 Order 1000, Docket No. RM10-23, Order dated July 21, 2011, paragraphs 586 and 587 4

6 MISO s Current Cost Allocation Options Within MISO, projects that meet certain metrics qualify as Market Efficiency Projects (MEPs) or Multi-Value Projects (MVPs) and are eligible for regional cost allocation. Cost allocation methods were designed for each of the two project types. Under MISO s Tariff Generator Interconnection Projects (GIPs) may also qualify for limited cost sharing. The following table summarizes current MEP and MVP regional cost allocation metrics and methods: Market Efficiency Projects 4 Multi-Value Projects 5 > $5 million cost > $20 million cost > 345kV or higher >100 kv or higher > 1.25 benefit-to-cost (b/c) ratio Must be a portfolio of projects meeting one of the following criteria: Energy policy mandates or laws Multiple economic benefits and >1.0 b/c ratio Economic and reliability benefits and >1.0 b/c ratio Metrics = Adjusted Production Cost (APC) Metrics = APC, capacity savings, loss reductions, and others Allocated 80% to benefitting Local Resource Zones and 20% postage stamp to load MEPs approved = two since 2006 Allocated 100% postage stamp to load and exports other than PJM MVP portfolios approved = one portfolio (17 projects) since 2010 Please refer to the Appendix for tables of all MISO current regional and interregional cost allocation options. MISO South Region Transition Period MISO believes the transition period 6 provisions of the Tariff can be respected while we continue to look ahead in considering beneficial and necessary MEP and MVP metric revisions and cost allocation methodology changes. While it is important that the transition period provisions of the Tariff are respected, these provisions introduce unique challenges in that it is equally important for MISO cost allocation to be fair, equitable, and supportive of the implementation of long-term transmission plans that support future generation growth and accommodate new energy policy. 4 Attachment FF, Section II.B and Section III.A.2.f 5 Attachment FF, Section II.C and Section III.A.2.g 6 See Appendix to this paper for a summary of transition period provisions, and Attachment FF-6, Transmission Planning and Cost Allocation for Second Planning Area s Transition 5

7 It is important to address cost allocation issues discussed further in this report well in advance of the expected 2019 expiration of the MISO South transition period. Cost Allocation Issues The remainder of this paper describes the cost allocation issues that have been identified by MISO and its stakeholders and follows the framework of issues noted above. Issue 1: Otherwise beneficial projects that fail to meet the current eligibility criteria for cost allocation may not proceed, or may proceed without the ability to appropriately allocate costs to beneficiaries The conservatism of the MEP and certain MVP criteria largely restrict the number of projects that can be considered for regional and interregional cost sharing. For example, hundreds of potential MEPs have been evaluated since the MEP criteria was approved, but only two MEPs have been approved under the current cost sharing criteria. Although MISO has the authority and responsibility to recommend projects that address reliability, market efficiency and public policy needs, the lack of clear procedures for projects that meet the planning objectives but fail the current cost allocation criteria can result in projects that do not proceed, or projects that proceed without the ability to appropriately allocate costs to beneficiaries. Historically, when evaluating or proposing economic solutions to address congestion, MISO and stakeholders have focused almost exclusively on projects that meet the narrow eligibility criteria for cost sharing and not directly on the amount of congestion relieved. As a result beneficial projects may have been overlooked that relieved congestion as well as reduced fuel costs and may have provided other benefits. MISO s cost allocation metrics should be designed so that they align costs with beneficiaries. MEP Voltage Threshold Regional MEP Voltage Threshold The original 2006 RECB II filing included the 345 kv voltage criteria for MEPs. At that time, stakeholder concerns about the possible development of a high number of economic projects that could result in financial burdens drove the adoption of the 345 kv threshold. The 345 kv threshold was also intended to recognize that wide-reaching benefits generally result from higher voltage projects. 7 MISO believes it is possible for projects below 345kV to provide congestion relief benefits to more than one pricing zone, however, there currently is no Tariff mechanism to consider these projects for cost allocation. Nor is there a cost allocation method that considers the appropriateness of a more granular allocation of these lower voltage projects that may better 7 Docket No. ER06-18, November 1, 2006 compliance filing, page 6 6

8 align with those who benefit. In addition, the MEP 345 kv voltage threshold could also place premature and undue restrictions on the planning process. And although MISO is committed to considering all projects regardless of voltage, the current 345 kv criteria introduces the risk that beneficial lower-voltage economic projects could be overlooked because processes are primarily constructed to evaluate only projects that are 345 kv and higher. Furthermore, favorable lower-voltage economic projects that are identified run the risk of becoming stalled or opposed in the approval process because there is no allocation method to regionally cost share these projects to all who benefit. In addition, there is the potential for additional complexity resulting from lowering the voltage threshold for MEPs due to the introduction of completion under Order This concern should be considered in the evaluation of the MEP voltage threshold. Other RTOs, such as PJM and the Southwest Power Pool (SPP), regionally cost share lower voltage economic projects. In PJM, economic projects that are 500 kv and above or double-circuit 345 kv facilities are allocated 50 percent postage stamp and 50 percent to individual pricing zones based on benefits distribution. Lower voltage economic projects are allocated 100 percent to individual transmission pricing zones based on benefits distribution. The cost of any project costing less than $5 million is assigned 100 percent to the pricing zone where the project is located 8. SPP uses a Highway/Byway approach. The costs of projects (including economic projects) greater than 300 kv are allocated 100 percent postage stamp. Costs of economic projects between 100 kv and 300 kv are allocated 1/3 postage stamp and 2/3 to the local pricing zone(s). Economic projects below 100kV are paid for by the local pricing zone. 9 Interregional MEP Voltage Threshold Because MISO s regional 345 kv threshold is more limiting than the voltage threshold criteria of PJM and SPP, it may also prevent consideration of beneficial interregional transmission projects. For interregional projects that do not meet MISO s defined criteria, a separate arrangement must be created for each project. This negotiation process introduces added risk and can increase timelines for project approval. Risk Metrics The MEP eligibility criteria include a conservative suite of metrics consisting of the benefit-to-cost (b/c) ratio, benefits considered, and the project term and discount rate used to value project benefits. Many of these metrics are also used in the MVP analysis. Each of these metrics independently 8 PJM Tariff, Schedule 12(b)(i), (ii), (v), and (vi) 9 SPP Tariff, Attachment J, Section III Risk of future uncertainty is accounted for multiple times 7

9 gives recognition to the risk of future uncertainties and thus may account for the same risk multiple times. A balance should be struck between the risk that benefits may not materialize and the risk that excess delivered energy costs will persist. Because a change to any of these metrics could impact the overall risk profile of the project, the b/c ratio and related suite of metrics should be evaluated in combination. Benefit-to-Cost Ratio The MEP b/c ratio was reviewed by stakeholders in 2011 and it was determined that a b/c ratio of 1.25 would appropriately capture the economic uncertainty of transmission projects, while not setting the threshold to high. 10 Prior to 2011, MISO used a sliding scale b/c ratio varying from 1.2 to 3.0 depending on the project in-service date. The 1.25 may be conservative, particularly when compared to the 1.0 b/c ratio used in the MVP criteria which uses similar assumptions to the MEP on project term and discount rate, two other risk management metrics used in the evaluation. MISO believes it is appropriate to revisit the MEP b/c ratio with stakeholders and determine if the 1.25 b/c ratio is still meeting its intent of capturing the economic uncertainty of transmission projects. Project Term Regional Projects Regional project benefit evaluations used to calculate the b/c ratio include Adjusted Production Cost (APC) benefits for the first 20 years of a project even though the useful-life of projects is often 40 years or longer. Evaluating only 20 years of benefits is conservative and is another way to mitigate the risk of future uncertainties. Interregional Projects For interregional economic projects between MISO and PJM, the Joint Operating Agreement (JOA) requires project benefits to be determined by calculating the present value of annual benefits for at least a minimum of the first 10 years of the life of the project after the projected inservice date, with a maximum planning horizon of 20 years from the current year. As noted above, MISO s regional tariff requires the benefits of MEPs be calculated for the first 20 years of a project s life. PJM requires the benefits of economic projects be calculated for the first 15 years of a project s life. However, the MISO/PJM JOA values benefits for a lesser period of time than either the MISO or PJM regional Tariffs, but still requires a b/c ratio of This shorter benefit evaluation period underestimates the benefits a project can provide and makes it more difficult for interregional economic projects to meet the 1.25 b/c ratio requirement. This issue is being reviewed by the Interregional Planning Stakeholder Advisory Committee (IPSAC). The MISO/SPP JOA calculates benefits based on the first 20 years of the project s life after the projected in-service date. This is the same term as is used to evaluate MISO regional projects and, therefore is not an issue on the MISO/SPP seam. 10 Docket No. ER , April 19, 2012 Transmittal Letter, pgs. 4 and 5. 8

10 Discount Rate The level of risk premium assumed by the current discount rate MISO uses, which reflects an investor discount rate, has a material impact on the value of the project, may be overly conservative, and may need to be evaluated for its appropriateness. The discount rate MISO utilizes to calculate the Net Present Value (NPV) of project benefits and costs is the average after-tax weighted cost of capital of the MISO Transmission Owners and was originally determined to be appropriate because this is the expected cost applied to a new project. This discount rate represents an investor s point of view and includes a risk premium which represents the minimum amount by which the return on an asset must exceed the known risk free rate of return to induce an investor to hold the asset. However, the MISO discount rate is being used to calculate the NPV of benefits a transmission project will provide to ratepayers not investors. MISO believes that the Tariff specified discount rate calculation should be evaluated to determine if it is providing an appropriate level of certainty that long-term projects will be evaluated consistently from year to year, or if the discount rate is too conservative in that it accounts for risks beyond the projects ability to provide societal benefits into the future. Benefits Considered Regional MEP Benefits Currently, the only MEP benefit evaluated is APC. During the 2011 MEP review, stakeholders determined that it was reasonable to utilize 100 percent APC because focusing on one congestion relief metric limits the potential overlap with other cost sharing project types such as MVPs. 11 However, evaluating only one benefit, the APC benefit, is another way to counter the risk that future events will diminish project benefits. Transmission projects provide benefits in addition to APC benefits including reliability and public policy benefits. Utilizing only APC benefits may prevent consideration of otherwise beneficial MEP projects which are also not eligible for treatment as MVPs for other reasons, such as the requirement that an MVP be part of a portfolio 12. Consideration of a more broad range of benefits, including reliability, economic, and public policy benefits may be useful to capture and quantify the value MEPs can provide. Over the past few years, stakeholders have suggested the following benefits be reviewed for consideration: Costs of avoided reliability projects Reduced cost of ancillary services Lower system capacity prices/costs Limited benefits considered may understate project value 11 Docket ER , Transmittal Letter April 19, 2012, page 4 12 Portfolio requirements are discussed in a separate section of this paper labeled MVP Postage Stamp and Portfolio Requirement 9

11 Improved optionality on the system in advance of the EPA Clean Power Plan Reduced planning reserve margins due to increased transfer capability Net load payments Reduced transmission losses Reduced environmentally harmful emissions Reduced congestion due to transmission outages Explore reduction in b/c ratio as a way to compensate for unmeasured benefits Congestion cost relief Market-to-market payment avoidance Multiple benefits of a project were recognized and accepted as a part of the MVP project type development but the broad cost treatment of MVPs precludes reasonable classification of many smaller projects or portfolios that have those same benefits as MVP s. Any evaluation (regional or interregional) of additional metrics should include a full understanding of 1) how to model the metric, and 2) how long/what effort is involved in determining the metric. Interregional Economic Project Benefits For interregional economic projects between MISO and PJM, the JOA requires a benefit metric of 70% Adjusted Production Cost (APC) plus 30% Net Load Payment (NLP) be utilized. This metric was initially proposed, and accepted, in the 2009 JOA filing and gave recognition to the then existing protocols within each RTO for identifying economic projects 13. In addition, at the time, stakeholders expressed preference for this metric because it struck the proper balance between the interests of all stakeholders, including the interests of each RTO s customers, which ultimately would bear the costs of such projects. 14 Interregional economic projects may provide benefits in addition to the 70% APC / 30% NLP benefit currently considered. Utilizing the current metric may prevent consideration of otherwise beneficial interregional economic projects. Stakeholders have suggested numerous benefits be reviewed for consideration and this issue is actively being reviewed by the MISO/PJM IPSAC. MISO believes it is time to evaluate whether there is merit to including additional benefits for interregional economic project evaluation, and to determine if additional benefit metrics can be calculated accurately and consistently enough to justify their inclusion in project evaluation. The MISO/SPP JOA does not require a specified b/c ratio, so economic interregional projects may move forward to regional review even with a b/c ratio of less than Therefore, although only APC benefits are considered, this does not create a JOA related hurdle for project approval. However, without further enhancements differences between models, process and other criteria can still become hurdles. 13 Docket ER05-6, Transmittal Letter January 28, 2009, pages 7 through 9 14 Docket ER05-6, Transmittal Letter January 28, 2009, pages 7 through 9 10

12 Lack of Clear Procedures for Treatment of All Projects As discussed above, MISO is responsible for planning to address reliability, public policy, and economic issues. The cost allocation treatment for any given project is secondary to the system need for that project. The Tariff provides a hierarchical process to determine cost allocation for each project type. For example, if a reliability project qualifies as an MEP or MVP it becomes an MEP or MVP. If an MEP qualifies as an MVP, it becomes an MVP. If a project does not qualify as any project type, it may be determined to be other. Although MISO s responsibilities and authority are clearly described in the Transmission Owners Agreement, some stakeholders feel that there is an issue in that the remainder of the Tariff does not include detailed provisions or processes regarding the project definition and cost allocation treatment (which could be assignment to local zone) for a broad enough type and/or size of transmission upgrades. This lack of clarity creates confusion, uncertainty, and can prevent or delay beneficial projects. In order to efficiently move needed transmission projects through the approval process MISO needs clearer procedures for those projects that do not meet the criteria for regional cost allocation. Issue 2: Widespread allocation of costs In December 2013, MISO s geographic footprint increased significantly with the integration of the MISO South region. MISO s footprint now stretches from the Canadian border to the Gulf of Mexico. As a result, the granularity with which existing beneficiaries are determined and/or costs are allocated should be reviewed to assure it is consistent with the expanded footprint. Increased geographic size creates need to revisit allocation methods Granularity of MEP Cost Allocation Postage Stamp Allocation Due to the increase in MISO s geographic scope, it is timely to reevaluate whether the footprintwide postage stamp cost allocation for 20% of MEP costs remains fair and equitable. Absent MISO South transition period provisions (discussed below), 20 percent of MEP costs are postage stamped to the entire MISO footprint. Due to the increase in MISO s geographic scope, consideration should be given to the 20 percent portion of MEP costs and if it should continue to be postage stamped footprint wide or if a more granular sub regional approach would be more appropriate. Reconsideration of postage stamp is also essential if the MEP 345 kv voltage threshold is lowered. Local Resource Zone (LRZ) Allocation of Lower Voltage MEPs The currently defined LRZs for transmission cost allocation vary in geographic size and can contain a varying number of pricing zones. Pricing Zones located within LRZs can vary from a single Pricing Zone up to as many as seven. Furthermore, some pricing zones are compact while others cover large portions of entire states. 11

13 Due to the varying size of LRZs and the differing number of Pricing Zones within each LRZ, it is prudent to re-evaluate the current allocation of 80 percent of MEP costs to benefitting LRZs is appropriate. In addition, projects below 345 kv generally provide more localized benefits. If the 345 kv voltage threshold is lowered, a more granular cost allocation method is one alternative that could be considered to assure the costs of these projects are allocated roughly commensurate to those who benefit. MVP Postage Stamp and Portfolio Requirement The MVP requirement that projects be part of a portfolio is inextricably linked to the postage stamp cost allocation method. Both present potential barriers to the approval of new transmission projects. If future MVP projects are approved, continued application of the footprint wide postage stamp cost allocation method may not fairly allocate costs to those who benefit. Furthermore, the portfolio requirement makes an assumption about homogeneity of benefits across the footprint. Although the MISO South transition period and cost allocation rules must be respected, with the increased geographic size of the footprint, MISO believes it is appropriate to evaluate if more flexibility in the portfolio requirement combined with more 12

14 targeted cost allocation could provide a more effective means to address subregional policy issues than could occur under the tariff today. Issue 3: Gaps and overlaps between various cost allocation rules Regional Project Hierarchy The MISO tariff includes an upward looking hierarchy for the cost allocation treatment of certain transmission projects. Excluding expedited projects, the result is that transmission projects will be cost allocated based on the most regional allocation the project qualifies for with Baseline Reliability Project (BRP) being the most local and MVP being the most regional. Originally the hierarchy was developed as a method to ensure costs are allocated roughly commensurate with beneficiaries. In practice, however, the hierarchy has been the source of much confusion in the planning process. With the introduction of the developer selection process into the MISO tariff the categorization of projects has become increasingly important and at times controversial. Currently MISO s Tariff specifies that a BRP (excluding expedited projects) that also qualifies as an MEP is classified as an MEP for cost allocation purposes 15. For example, as part of the MTEP 15 process MISO reviewed all BRPs that were greater than 345 kv and determined that none of them would qualify as an MEP. There were only four BRPs that met the 345 kv limit. If the MEP voltage level were to be lowered, there would be many more BRPs to review for MEP qualification. Consideration must also be given to the increased timeline associated with MEP projects due to the developer selection process. BRP projects are needed to meet NERC or local reliability criteria and are often near term in nature. Increasing the timeline associated with these projects may expose MISO and the local transmission owner to reliability and compliance risk. The current project hierarchy provisions should be evaluated to determine and address the implications to reliability projects with time-sensitive reliability requirements. MISO s Tariff also currently specifies that an MEP that also meets MVP criteria will be classified as an MVP for cost allocation purposes 16. It is important to note, that if the scope of MEP benefits is expanded and the MVP portfolio requirement is changed or eliminated, it may become difficult to distinguish MEPs from MVPs. Consideration will need to be given to determine what characteristics, if any, differentiate the two project categories for purposes of cost allocation. MISO believes the project hierarchy should be reviewed to determine if the specified hierarchy is having, or will have, any unintended consequences including the potential delaying of reliability projects. Interregional and Regional Assumptions and Criteria Misalignment Misalignment between regional modeling assumptions and criteria and interregional Joint Operating Agreement (JOA) requirements complicates interregional planning. MISO has three major seams; PJM, the Southwest Power Pool (SPP), and the Southeastern Regional 15 MISO Tariff, Attachment FF, Section III.2.h 16 MISO Tariff, Attachment FF, Section II.C.4 13

15 Transmission Planning (SERTP) region. Examples of types of misalignments are noted throughout this document and in the Appendix. In addition, each of the regions has differing approaches to planning which can further complicate interregional planning. Gap Between MISO South Transition Period and Interregional Cost Allocation Although the MISO South transition period Tariff provisions determine cost allocation based on where regional projects terminate, the transition period provisions are silent concerning allocation of costs between MISO South and MISO North/Central for an Interregional Project. Consider an interregional MEP that terminates outside of MISO entirely. Transition period provisions do not address how Interregional Projects terminating outside of MISO but providing benefits to MISO South should be allocated. Tariff provisions are needed to clarify cost allocation under these circumstances and would require modification to the transition period provisions of the Tariff. Absent modifications to the Tariff, the MEP and MVP postage stamp provisions will apply footprint wide. As noted above, because of ongoing system changes, the current rules need refinement to ensure identification of the best projects and ongoing alignment of costs and beneficiaries. As a result, it is important to address these cost allocation issues well in advance of the expected 2019 expiration of the MISO South transition period. 14

16 Work Plan The following is the proposed timeline for this work effort. April COMPLETED MISO provides high level outline of main cost allocation issues Request stakeholders review outline and provide input on issues in outline Sept COMPLETED Provide draft issue paper to stakeholders for review Oct COMPLETED MISO review and incorporate stakeholder input Nov 2015 Finalize issue paper Begin issue prioritization Jan - Feb 2016 Finalize issue prioritization April 2016 Begin in-depth issue review Identify work plans to address prioritized issues Jun-Dec 2016 Continue issue reviews and work plan implementation 15

17 Appendix MISO s Current Project Types Allocation Category Participant Funded ( Other ) Transmission Delivery Service Project Generation Interconnection Project Baseline Reliability Project Driver(s) Transmission Owner-identified project that does not qualify for other cost allocation mechanisms; can be driven by reliability, economics, public policy or some combination of the three Transmission Service Request Interconnection Request NERC Reliability Criteria Allocation to Beneficiaries Paid by requestor (local zone(s)) Generally paid for by Transmission Customer; Transmission Owner can elect to roll-in into local zone rates Primarily paid for by requestor; 345 kv and above 10 percent postage stamp to load 100 percent allocated to local Pricing Zone Market Efficiency Project Multi-Value Project Reduce market congestion when benefits exceed costs by 1.25 times Address energy policy laws and/or provide widespread benefits across footprint Distributed to Local Resource Zones commensurate with expected benefit; 345 kv and above 20 percent postage stamp to load 100 percent postage stamp to load and exports other than PJM Project Types Subject to Regional Cost Allocation Market Efficiency Projects MEPs were first defined in October 2005 in the Regional Expansion Criteria and Benefits filing (RECB I) 17 and were known as Regionally Beneficial Projects (RBPs). Cost allocation procedures were subsequently developed and filed in November 2006 (RECB II) 18 and became effective April 1, In 2010, as part of the MVP filing, RBPs were renamed MEPs. 17 Docket No. ER06-18, October 7, 2005 compliance filing (RECB I) 18 Docket No. ER06-18, November 1, 2006 compliance filing (RECB II) 16

18 To qualify as an MEP a transmission project must cost $5 million or more; involve facilities that are 345 kv or higher (345 kv facilities must represent more than 50 percent of total project costs); and have a benefit-to-cost (b/c) ratio of 1.25 or greater. The benefits considered are Adjusted Production Cost (APC) benefits. Project benefit evaluations include the present value of the first 20 years of the project life using a discount rate that represents the after-tax weighted average cost of capital of MISO Transmission Owners (roughly 8 percent). The costs of MEPs are allocated 80 percent to transmission customers in the benefitting Local Resource Zones (LRZs) in proportion to the positive benefit each LRZ is estimated to receive. The remaining 20 percent is allocated to all transmission customers on a system wide basis. Since the creation of the MEP project type in 2005 only two MEP projects have been approved by MISO s Board of Directors. Past Evaluations of MEP Criteria MEP criteria were initially developed during a period when regional cost allocation was fairly new. Stakeholders weighed the risk of future uncertainties, new requirements, and unfamiliar new processes, and created a fairly conservative suite of MEP criteria. A comprehensive stakeholder review of MEP criteria was conducted in In June FERC accepted MISO s proposal to change the b/c ratio to 1.25, to use Adjusted Production Cost (APC) as the sole metric to calculate benefits, to calculate the present value of benefits over 20 years, to implement a discount rate methodology, and to allocate 80 percent of costs to benefitting Local Resource Zones. In 2013 another review of MEP criteria was initiated. This review focused on the consideration of additional MEP benefits and the 345 kv MEP voltage threshold. In early 2014, a significant majority of stakeholders did not support changes to the criteria or metrics and the discussion was tabled. Multi-Value Projects In June 2010, MISO and the MISO Transmission Owners proposed the Multi-Value Project (MVP) type for projects that enable the reliable and economic delivery of energy in support of documented energy policy mandates and address, through the development of a robust transmission system, multiple reliability and/or economic issues affecting multiple transmission zones. In December 2010 FERC accepted the MVP proposal and it was incorporated into the MISO Tariff. 20 An MVP must be evaluated as part of a portfolio of projects whose benefits are spread broadly across the footprint. An MVP must cost $20 million or more, involve facilities that are 100 kv or higher, and meet one of these three criteria: Developed to meet energy policy mandates or laws 19 Docket No. ER , June 29, 2012 Order 20 Docket ER , December 16, 2010 Order 17

19 Provide multiple types of economic value across multiple pricing zones and have a b/c ratio of 1.0 or higher Address at least one reliability issue and at least one economic-based issue that provides economic value across multiple pricing zones. Financially quantifiable benefits must exceed total project cost. Several types of economic value are evaluated. The costs of MVPs are allocated on a system-wide basis to transmission customers that withdraw energy, including external transactions sinking outside the MISO footprint other than those that sink in PJM. Since the establishment of the MVP project type in 2010 one MVP portfolio has been approved by the MISO Board of Directors. 18

20 Interregional Projects MISO s three main seams are with PJM, the Southwest Power Pool (SPP), and the Southeastern Regional Transmission Planning (SERTP) region. Multiple regional cost allocations complicate interregional planning efforts. The table below provides a general summary of the regional cost allocation differences between the RTOs: APC = Adjusted Production Cost 19

21 Interregional Project Metrics Differing Joint Operating Agreement (JOA) requirements can also complicate interregional planning. Below is a table generally summarizing interregional project metrics and cost allocation methodologies for each of MISO s three seams. 20

22 MISO South Integration and Cost Allocation Type and Location of Project Approved before Transition Period Treatment During Transition Period Treatment After Transition Period Approved and/or Identified during Transition Period Treatment During Transition Period Treatment After Transition Period Approved after Transition Period Ends Multi Value Project terminating in exclusively one planning area Within first planning area at 100% MVP rate 1. First planning area at 100% MVP rate 2. Second planning area at 8-year phase-of MVP rate Within applicable Planning Area at 100% MVP rate 1.MVP s in FPA are allocated: FPA at 100% MVP Rate and SPR at 8-year phase-in of MVP Rate 2.MVP s in SPA are allocated to: FPA at 8-year phase-in of MVP Rate and SPA at 100% MVP Rate Applicable to both Planning Areas, each at 100% MVP rate Multi Value project terminating in both planning areas Not Applicable Not Applicable Applicable to both Planning Areas, each at 100% MVP rate Applicable to both Planning Areas, each at 100% MVP rate Applicable to both Planning Areas, each at 100% MVP rate

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