AESO 2014 Business Plan and Budget Proposal November 1, 2013
Table of Contents Section 1 Section 2 Section 3 Board Decision Items Executive Summary Stakeholder Presentations to the AESO Board Stakeholder Consultation Undertaken Terms of Reference for Budget Review Process Budget Review Process Budget Review Process Schedule Section 4 AESO 2014 Business Plan and Budget Proposal General & Administrative and Interest Costs and Amortization Market Systems Replacement Project Capital Costs Other Industry Costs Wires Costs Transmission Line Loss Costs Ancillary Services Costs Section 5 Stakeholder Comments and AESO Responses AESO 2014 Business Plan and Budget Proposal
Section 1 Board Decision Items Executive Summary
Over the last several months, we have reviewed and discussed with stakeholders and the AESO Board, our proposed business initiatives for 2014. From this review, we have indicated our planned direction for our operations in the upcoming year that will enable the AESO to meet its mandate 1 and advance its strategic plan. This AESO 2014 Business Plan and Budget Proposal (Business Plan) provides an understanding of our proposed business initiatives that we are planning to focus on for the upcoming year. The business initiatives being proposed form the foundation from which we have developed our 2014 budget (general and administrative and capital). At this time, we are presenting this Business Plan to the AESO Board for approval which includes the following: General and Administrative and Interest Costs and Amortization Market Systems Replacement Project Capital Costs Other Industry Costs Wires Costs Transmission Line Losses Costs Ancillary Services Costs We have engaged stakeholders interested in reviewing our initiatives and budgets in more detail and providing us with their comments and feedback as we were working through this process. This consultation process, referred to as the Budget Review Process (BRP), allows us to prepare a business plan and budget that has been reviewed, discussed and at times challenged before we reach this point. As a part of this presentation to our Board, we provide the stakeholder written comments that we have received to date. The purpose of providing these comments is for the AESO Board to gain insight into some of the areas that created discussion throughout this process. We continue to believe that this open and transparent process enables us to prepare a thorough and comprehensive Business Plan, and we believe our stakeholders continue to appreciate this inclusive process. The end result is a well communicated and understood Business Plan that will provide us direction in the coming year. Our budget is based on the funding required for us to achieve our business initiatives and maintain our bases business as outlined in the Business Plan. In addition to this, we are also providing the wires, transmission line losses and ancillary service cost budgets for 2014 which are within the AESO Board s mandate for approval based on the provisions in the Transmission Regulation. These budgeted costs have been developed internally and have been included in the process to engage stakeholders for review and comment, consistent with our general and administrative and capital costs budgets. 1 The Alberta Electric System Operator (AESO) is responsible for the safe, reliable and economic planning and operation of the Alberta interconnected electric system (AIES) and the facilitation of a fair, efficient and openly competitive electricity market. AESO 2014 Business Plan and Budget Proposal Page 1 Section 1 - Board Decision Items Executive Summary
The following are the approvals that we will be requesting from the AESO Board. AESO Board is Requested to: 1. Endorse the 2014 business initiatives as outlined in the Business Plan. 2. Approve the following proposed 2014 budget amounts as outlined in the Business Plan and summarized as follows: Budget/Forecast Revenue Source ($ million) Category Transmission Energy Market Load Settlement Total General and Administrative 71.1 23.6 1.3 96.0 Market Systems Replacement Project 0.5 1.5-2.0 Interest (0.3) 0.8 0.0 0.5 Amortization 16.3 10.8 0.2 27.3 Capital 19.9 Other Industry 16.2 7.7-23.9 Wires 1,407.3 1,407.3 Transmission Line Losses 117.3 117.3 Ancillary Services 224.4 224.4 AESO 2014 Business Plan and Budget Proposal Page 2 Section 1 - Board Decision Items Executive Summary
Section 2 Stakeholder Presentations to the AESO Board
Stakeholder presentations to the AESO Board to be inserted when received. AESO 2014 Business Plan and Budget Proposal Page 1 Section 2 - Stakeholder Presentations To the AESO Board
Section 3 Stakeholder Consultation Undertaken
The Transmission Regulation 1 (T-Reg) includes provisions addressing the approval of the AESO s own costs, ancillary services costs and transmission line losses costs. The T-Reg provides that the AESO must consult with stakeholders with respect to the proposed costs to be approved by our Board. It also provides that these costs, once approved by the AESO Board, must be considered by the Alberta Utilities Commission (Commission) as prudent unless interested persons satisfy the Commission otherwise. The practice we have established to carry out this consultation is the Budget Review Process (BRP). The BRP is a transparent process which provides a level of prudence review with input from stakeholders. At the conclusion of the BRP, we will make a recommendation with respect to our own costs (general and administrative, interest, amortization, capital and other industry costs), transmission line losses costs and ancillary services costs to the AESO Board for approval. We have posted the BRP overview, terms of reference and a calendar providing the BRP milestone activities leading up to an AESO Board decision (the calendar was revised throughout the process to accommodate process changes and schedules). These documents have been included as Appendices A to C to this Section. At a high level, the BRP steps followed are: Notice to stakeholders AESO Develop 2014 Business Initiatives AESO Develops Own Costs Budgets and Ancillary Services and Transmission Line Losses Cost Forecasts Review 2014 Business Initiatives with stakeholders Technical Meeting(s) to Review the Own Cost Budget, Ancillary Services and Transmission Line Losses Costs Forecasts for 2014 AESO Board Decision As with prior years BRP, the process has been open to all stakeholders and the process had been transparent as all presentation materials, stakeholder comments (if any) and our responses have been posted on the AESO website. Through this process, we have ensured that all stakeholders have had an opportunity to provide input. The BRP will be re-evaluated with stakeholders at its conclusion and refinements made to the process going forward as required. 1 A/R 86/2007 AESO 2014 Business Plan and Budget Proposal Page 1 Section 3 - Stakeholder Consultation Undertaken
Appendix A Terms of Reference for Budget Review Process July 29, 2013 Transparency is the overarching principle in the BRP. The following will help ensure transparency to stakeholders during this process. The process should be open to all stakeholders that are interested. The size of the group should not be limited. Stakeholders are encouraged to register as participants at the outset of each year s process in order to ensure a consistent understanding and to minimize inefficiencies. Comments will be collected in written form only, and will be responded to by the AESO and shared with all stakeholders (i.e., posted to AESO website). As well, stakeholders will have the opportunity to comment on each others comments. Comment submissions are a requisite during the technical consultation period in order to be entitled to present to the AESO Board on the same comments. The written decision rendered by the AESO Board on these matters will contain reasons / rationale. Throughout the process, the AESO will endeavor to provide as much information as reasonably possible to ensure stakeholders have all information relevant to the subject matters under review. However, the AESO and stakeholders will need to agree on the level of detail to discuss (including confidential information), on an issue by issue basis, in an effort to be most effective and efficient. At the end of each AESO budget process review cycle, the AESO and stakeholders will evaluate the effectiveness of the process and make appropriate changes if required for the following year. In Addition: Everyone is able to present their views. Everyone must work within the timeline agreed upon at the start of the process. This process is not a negotiated settlement. The material to be delivered to the AESO Board in order to prepare a decision does not have to be agreed upon unanimously. Information will be provided to all stakeholders in a timely manner. Stakeholders will have a reasonable time period to review and respond to AESO material. Nothing will preclude the opportunity for stakeholders to ultimately appeal any decision using the dispute mechanism outlined in the ISO Rules. AESO 2014 Business Plan and Budget Proposal Page 2 Appendix A - Terms of Reference for Budget Review Process
Appendix B Budget Review Process Refer to the following BRP flow diagram. AESO 2014 Business Plan and Budget Proposal Page 3 Appendix B - Budget Review Process
AESO 2014 Budget Review Process Overview - Steps Process to approve forecasted Ancillary Services & Transmission Line Losses and update Stakeholders on 2014 Business Initiatives and Own Cost budget 1.0 2.0 3.0 4.0 5.0 6.0 Invitation to Stakeholders AESO Develops Strategies & Business Initiatives AESO develops Own, Ancillary Services and Transmission Line Loss Costs Forecasts Technical Meeting to Review Forecasted Costs AESO Board Decision Dispute Process Notice sent to all stakeholders that the process to develop and review forecasted costs will commence Process includes developing a schedule with all milestone dates AESO to solicit stakeholder input on strategies and business initiatives Review progress on existing strategies and business initiatives with stakeholders Stakeholders receive AESO strategies and business initiatives for the upcoming year AESO prepares Own Cost forecast for the upcoming year based on the business initiatives and strategic plan set out in step 2.0 AESO prepares forecasts of Ancillary Services and Transmission Line Loss Costs AESO provides documents to stakeholders in advance of holding a technical review meeting AESO holds technical session(s) with stakeholders where the AESO presents forecasted costs, assumptions and responds to stakeholder comments AESO posts meeting overview document to AESO website and asks for written comments AESO makes revisions as deemed necessary AESO prepares an AESO Board Decision Document and provides to stakeholders for review prior to submission to the AESO Board AESO submits Board Decision Document to the AESO Board for review and decision AESO Board reviews Board Decision Document Stakeholders make oral or written presentations to the AESO Board on issues of disagreement or concern (multi-lateral) based on comments submitted in step 4.0 AESO Board considers stakeholder presentations and reply comments in its approval process AESO Board issues a decision for AESO s Own, Ancillary Services and Transmission Line Loss Cost forecasts with rationale Dispute resolution mechanism for instances where a stakeholder disagrees with the AESO Board Decision. The Dispute Resolution process is outlined in the ISO Rules Alberta Electric System Operator July 29, 2013 Page 4
Appendix C Budget Review Process Schedule Refer to the following calendar providing the BRP milestone activities. AESO 2014 Business Plan and Budget Proposal Page 5 Appendix C - Budget Review Process Schedule
Budget Review Process External Calendar - Revised August 29, 2013 Meeting Material Distributed Stakeholder Mtgs Stakeholder Comments Requested Stakeholder Comments Received AESO Posts Meeting Summary JULY AUGUST SEPTEMBER Mon Tues Wed Thurs Fri Mon Tues Wed Thurs Fri Mon Tues Wed Thurs Fri 1 2 3 4 5 1 2 2 3 4 5 6 Holiday Holiday 8 9 10 11 12 5 6 7 8 9 9 10 11 12 13 Holiday Distribution of materials for Business Strategies / Initiatives mtg. (Step 2) 15 16 17 18 19 12 13 14 15 16 16 17 18 19 20 Receive Stakeholder comments on Invitation and Process materials (Step 1) Business Strategies / Initiatives meeting (Step 2) Web posting for comments on Business Strategies / Initiatives (Step 2) 22 23 24 25 26 19 20 21 22 23 23 24 25 26 27 Web posting of comments on Invitation and Process materials (Step 1) Receive Stakeholder comments on Business Strategies / Initiatives (Step 2) 29 30 31 26 27 28 29 30 30 Distribution of Invitation to Stakeholders and Process materials (Step 1) Web posting for comments on Invitation and Process materials. (Step 1) OCTOBER NOVEMBER DECEMBER Mon Tues Wed Thurs Fri Mon Tues Wed Thurs Fri Mon Tues Wed Thurs Fri 1 2 3 4 1 2 3 4 5 6 Distribution of materials for Tech Mtg Forecasts, Own Costs and MSR (Step 4) Web posting of comments on Business Strategies / Initiatives (Step 2) 7 8 9 10 11 4 5 6 7 8 9 10 11 12 13 Tech. Mtg. Forecasts, Own Costs and MSR Calgary (Step 4) Web posting for comments on Forecasts, Own Costs and MSR (Step 4) Receive Stakeholder written submissions to AESO Board (Step 5) Web posting of Stakeholder written submissions to AESO Board (Step 5) 14 15 16 17 18 11 12 13 14 15 16 17 18 19 20 Holiday Tech. Mtg. Forecasts, Own Costs and MSR Edmonton (Step 4) Holiday Meetings with AESO Board (TBC) Oral Presentation to AESO 21 22 23 24 25 18 19 20 Board or Board 21 Committee 22 23 24 25 26 27 (Step 5) Receive Stakeholder comments on Forecasts, Own Costs and MSR (Step 4) Holiday Holiday 28 29 30 31 25 26 27 28 29 30 31 Web posting of comments on Forecasts, Own Costs and MSR (Step 4) Web posting of 2014 Draft - Business Plan and Budget (Step 4) * MSR - Market Systems Replacement 2014 BRP External Calendar revision 1.xlsx
Section 4 AESO 2014 Business Plan and Budget Proposal
Table of Contents AESO Vision... 2 AESO Mission... 2 Letter from the President and CEO... 2 AESO Operations... 4 2014 Business Plan... 5 Electric System Operations... 6 2013 Achievements... 7 2014 Plans... 7 Electric System Development... 8 2013 Achievements... 9 2014 Plans... 9 Customer Access Services... 10 2013 Achievements... 11 2014 Plans... 11 Corporate Services... 14 2013 Achievements... 15 2014 Plans... 15 Information Technology Services... 16 2013 Achievements... 17 2014 Plans... 17 Financial Highlights... 18 Section I 2013... 19 Section II 2014... 21 Appendix A: Year-to-Date September 2013 Financial Results Detail... 33 Appendix B: Transmission Operating Cost Definitions... 41 Appendix C: 2014 General and Administrative Cost Detail... 44 Appendix D: Capital Projects... 48 Appendix E: Market Systems Replacement... 53 Appendix F: Allocation of Costs... 56
AESO Vision The AESO will be seen as a significant contributor to the development of Alberta and the quality of life for Albertans, through our leadership role in the facilitation of competitive electricity markets and the reliable operation and development of the Alberta Interconnected Electric System (AIES). AESO Mission The AESO facilitates a fair, efficient and openly competitive market for electricity and provides for the safe, reliable and economic operation of the AIES. Letter from the President and CEO We have made good progress in advancing our initiatives in 2013 and we are on track to deliver another year of solid performance. This will position us well to execute on the ambitious plans we have for 2014. The AESO s 2014 Business Plan and Budget Proposal (Business Plan) provides our most notable achievements for 2013 and our initiatives for the upcoming year to advance our Strategic Plan. New for 2014, our Business Plan has been presented based on our business activities and associated costs. A significant amount of effort has been expended into the development of this presentation basis and we believe this will provide better transparency and understanding of our operations. Here are some of our highlights. Maintaining safe, reliable, economically efficient electric system operations continues to be an important priority at the AESO and is a critical part of our mandate. We expect the electric system to continue to be stretched in 2014 and beyond until some of the major transmission reinforcement projects in Alberta are operational. The expertise of our world-class System Controllers will continue to be crucial throughout this period. Our controllers were put to the test this summer during the supply shortfall events that we experienced and we were able to mitigate the impact to Albertans, which was quite remarkable under the circumstances. Further to this we have initiatives underway to enhance overall grid reliability such as the integration of the high voltage direct current (HVDC) transmission projects currently being constructed. We are well on our way to reestablishing a robust transmission system in Alberta as we continue to execute on our electric system development plans. Construction has begun on several major projects across Alberta as we continue to advance several of the projects which were included in our 2012 Longterm Transmission Plan. Improving Customer Access Services continues to be an important area of focus for us particularly to reduce customer connection cycle times and to provide higher quality customer service overall. We have advanced connection process enhancements and the Market Participant Choice initiatives which will continue to progress in 2014. To be successful with these initiatives, we will need to continue to collaborate with industry so the full benefit of these initiatives can be realized. The wholesale electricity market is functioning well and contributing many benefits for the province: the price of electricity in Alberta is competitive; we have healthy supply margins; diverse generation technologies and access to a wide variety of fuel sources; and we have a higher percentage of wind generation on our system than any other Canadian province. The initiatives that we plan to execute in this area are designed to further evolve the market including advancing the wind framework, various intertie AESO 2014 Business Plan and Budget Proposal Page 2
initiatives and the implementation of the new transmission constraint management rule. In addition, a validation project was initiated in 2013 to determine if our current market systems should be replaced with new technology. This included initial research on market systems and consultation with market participants to develop requirements. In December the AESO Board will decide if the project should proceed to the next phase, Request for Proposals. If the decision is to proceed, this will become a significant initiative for our organization in 2014. To enable the AESO to successfully achieve our mandate and the initiatives I have highlighted, we need great people, processes and tools. We continue to invest in our most important assets our people as well as supporting processes and technologies to ensure we can deliver effectively and efficiently to meet the high standards we set for ourselves. As a mature organization, our operations are stable and we see opportunities to streamline processes to reduce our spending without sacrificing the value we add or the quality of our work. Each year we take a careful look at our costs and manage them diligently. This year we took this a step further to examine our overall activities, sharpen our focus and become more efficient. As a result of this work, our proposed general and administrative budget for 2014 is $96.0 million, which is a $2.3 million or a two per cent reduction from our 2013 budget of $98.3 million. In addition, our capital budget for 2014 is $19.9 million compared to the 2013 budget of $27.0 million, a reduction of $7.1 million or 26 per cent. As we move forward we will continue to seek further efficiencies or reduced costs. In closing, we have a solid electricity framework in place, we are focused on the right initiatives and we are well equipped to deliver on our commitments. We will continue to work hard and apply our knowledge to advance our strategic and business plans. David Erickson, President and Chief Executive Officer AESO 2014 Business Plan and Budget Proposal Page 3
AESO Operations The AESO s 10-year anniversary occurs in 2013 and over the last ten years the operations of the organization have changed significantly in response to increased participation in the restructured electricity industry, wholesale electricity market evolution and additional growth in Alberta which impacts the provincial electricity infrastructure. It has been a challenging 10 years and during this period, the role and focus of the AESO has needed to be agile to respond to these changes. The AESO s operations have historically been described using five key processes: Electric System Development; Electric System Operations; Customer Access Services; Market Development; and Corporate Services. In preparation for the Business Plan, the day-to-day activities, resulting deliverables and associated general and administrative costs (mainly staff and contract services) for each process were examined and summarized. Each key process is described through an overview and the respective activity groups. Resource costs in 2014 represent approximately $74 million or 77 per cent of the AESO s total general and administrative budget of $96.0 million. The associated resources, notable achievements for 2013 and plans for 2014 are presented by activity group to provide greater transparency and understanding of AESO operations and all of the work that goes into delivering on the AESO mandate every day. The AESO s information technology program was set apart from the key processes for 2014 to provide additional time for management to complete a thorough review and analysis of the information. 2014 Resource Costs ($74 million) 1. Electric System Operations ($22 million) 3. Customer Access Services ($10 million) 2. Electric System Development ($17 million) 4. Market Development ($5M) 5. Corporate Services ($10 million) Information Technology Services ~ Resources ($11 million) With the passage of time and as the industry evolves, the AESO will continue to refine its focus and reallocate its resources to best serve Albertans. This will become apparent when comparing the activity grouping information on an annual basis. While annual changes may have subtle impacts, the impact from material changes will be more evident. For instance, over the last several years, the focus has been on the evaluation of the transmission system and the approval and construction of reinforcement which resulted from that evaluation. Looking forward to the future, that level of activity is will slow as system development plans are executed. For the presentation of AESO operations, the shift will be evident in Electric System Development resources when it occurs. AESO 2014 Business Plan and Budget Proposal Page 4
2014 Business Plan In 2009, the AESO refreshed its Strategic Plan which provided both the AESO and industry with the view of the AESO s role in leading the industry into the future and furthering the economic development of Alberta for a period out to 2013. This Strategic Plan provided a path forward so that the AESO would be well positioned to proactively identify those opportunities for success, as well as emerging issues, on a timely basis and address them in the best way possible. The Strategic Plan is meant to set the direction of the organization for multiple years. It is the annual business plan that will influence the day-to-day and annual initiatives. During 2013, the AESO has once again taken the step back to confirm and reassess the longer term direction for the organization. This work is ongoing with plans for a new 2014-2018 Strategic Plan to be communicated in 2014. It is not anticipated that this updated Strategic Plan will change the course of any of the 2014 business initiatives presented in this Business Plan given the multi-year nature of the initiatives currently underway and the long term nature of the Strategic Plan. The AESO s annual business plan and budget are presented to industry through the Budget Review Process for valued feedback. The business plan initiatives presented reflect that consultation. AESO 2014 Business Plan and Budget Proposal Page 5
Electric System Operations We will direct the safe and reliable operation of the Alberta transmission and market system in a fair, efficient, and openly competitive manner. The optimal management of electric system operations continues to be a primary focus and a crucial piece of the AESO s mandate. Effectively maximizing the use of transmission capacity and monitoring transmission system performance is critical as Alberta s demand for electricity grows on an already constrained system. The AESO operates the Alberta Interconnected Electric System (AIES) and competitive market, in accordance with the North American Electric Reliability Corporation (NERC) and Western Electricity Coordinating Council (WECC) reliability criteria and standards. We will proactively manage risks and operate the AESO and the AIES compliantly. The AESO fosters a culture of compliance through demonstrated adherence to Alberta Reliability Standards (ARS), legislation, regulations and Independent System Operator (ISO) rules, and by monitoring compliance to ARS by market participants. The AESO delivers Electric System Operations through four primary activity groups: Real-time Operations; Operations Business Services; Operations Engineering; and Operations Systems. It is not surprising that the significant work accomplished in these critical activity groups represents the largest portion of the AESO s resources at 30 per cent or $22 million of 2014 resource costs. Electric System Operations Costs $22 million to deliver 30% of total AESO resource dollars Real-time Operations requires the largest amount of time and dollars spent on Electric System Operations. A critical component of this is the 24/7 real-time operation of the AIES and AESO markets. Resources are also associated with planning for operating limits and preparations for system restoration. Operations Business Services includes the resources dedicated to maintaining System Controller procedures and training as well as managing and facilitating energy market settlement and credit. It also includes the activities related to developing and implementing the ARS and monitoring both the AESO and external market participants to ensure their operations are in compliance with these standards. Operations Engineering reflects the studies, analysis, monitoring tool development and coordination required for operations planning as well as providing real-time engineering support. Technical rule development is also captured in this activities group. Operations Systems focuses on the Energy Management System (EMS) application to provide real-time support, modifications resulting from changes to the AIES as well as the project management required for operations system changes. Electric System Operations Costs by Activity Group 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Real-time Operations ($8.7M) Operations Engineering ($4.9M) Operations Business Services ($6.0M) Operations Systems ($2.5M) AESO 2014 Business Plan and Budget Proposal Page 6
Achievements and Plans In addition to the ongoing electric system operations activities, the following table outlines the notable achievements completed or expected to be completed in 2013 and planned initiatives for 2014 categorized by activity group. Real-time Operations Operations Business Services Operations Engineering Operations Systems 2013 Achievements Managed the AIES within the appropriate limits identified for short and long term operations. Completed preparations to assume Alberta Reliability Coordinator (RC) function. Continued ongoing development and implementation of ARS. Completed the grid restoration review and initiated implementation plans. Developed a revised Energy Management System (EMS) strategy. Implemented changes to the EMS model to accommodate the Montana-Alberta Tie Line. Completion of 120 or more energizations. 2014 Plans Integrate 29 additional RC-related requirements as the AESO assumes the RC responsibilities from WECC. Assume RC function for Alberta. Continue to prioritize and implement ARS. Continue to advance Security/Critical Infrastructure Protection program to enhance system reliability and operate the AIES in accordance with industry-wide reliability criteria and standards. Design and implement operations engineering studies to prepare for high voltage direct current (HVDC) operations. Implement process and system enhancements designed to improve grid reliability and those designed to support the integration of electric system development initiatives (reliability programs). Implement the revised EMS strategy that was developed in 2013. AESO 2014 Business Plan and Budget Proposal Page 7
Electric System Development We will lead the development of a reliable transmission system, including interties to other jurisdictions, which fully enables the operation of the competitive market. The transmission system and the electricity market are mutually interdependent and together form Alberta s electricity framework. The market s continued success is underpinned by a robust transmission system. Its ability to continue to function well and encourage economic prosperity in Alberta relies on having an unconstrained, reliable transmission system that can keep pace with the evolving market. The AESO continues to advance the transmission projects outlined in its Long-term Transmission Plan and filed its 2012 Long-term Plan Progress Report with the Alberta Utilities Commission (AUC) in July of 2013. Several of these projects are now well into the implementation stages, helping to establish a system to deliver electricity where needed while maintaining confidence that new generators will have access to the AIES. As specified in the Transmission Regulation, and as outlined in the Electric Statutes Amendment Act, the AESO received AUC approval for its Competitive Process in February of 2013. The Competitive Process, which will be used to select a successful bidder to develop, design, build, finance, own, operate and maintain the Fort McMurray West 500 kv Transmission Project, is currently in the Request for Qualifications (RFQ) stage. From the RFQ, up to five respondents will be shortlisted to move forward into the Request for Proposals (RFP) stage. A successful bidder will be announced in early 2015. Electric System Development is accomplished at the AESO through three primary activity groups: Plan to Need Identification Document (NID) Approval; System NID Approval to Energization; and Maintenance. The work supporting these activity groups combined amounts to 22 per cent or $17 million of 2014 resource costs. Electric System Development Costs $17 million to deliver 22% of total AESO resource dollars Plan to NID Approval encompasses the planning and preparation work leading up to NID approval for system projects. This includes maintenance and program management for the long-term regional and bulk transmission plans; all of the activities prior to receiving NID approval including the regulatory process; and planning for system enhancements and affected power system and transmission-related market models. System NID Approval to Energization describes the work completed after a NID is approved and includes all of the activities leading up to energization such as providing transmission program support; project benchmarking, communication strategies; and developing and implementing the Competitive Process for certain transmission projects. Maintenance involves data and model maintenance for power system and transmission-related market models. Electric System Development Costs by Activity Group 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Plan to NID Approval ($6.3M) System NID Approval to Energization ($9.6M) Maintenance ($0.7M) AESO 2014 Business Plan and Budget Proposal Page 8
Achievements and Plans In addition to the ongoing electric system development activities, the following table outlines the notable achievements completed or expected to be completed in 2013 and planned initiatives for 2014 categorized by activity group. Plan to NID Approval System NID Approval to Energization Maintenance 2013 Achievements Filed 2012 Long-term Transmission Plan Progress Report with the AUC. Updated and filed the 2013 Longterm Transmission Plan with the AUC including advancing a robust and comprehensive regional planning process as part of the AESO s major long-term planning process. Filed and/or received AUCapproval of system project Need Identification Documents (NIDs) and amendments for Algar Area, FATD East, Kettle River, Medicine Hat SATR, North Central and Windy Flats SATR. 2014 Plans Implement the updated 2013 Longterm Transmission Plan advancing regional and system transmission projects. Advanced plans for system and customer connection projects for improved delivery. Implemented new transmission cost monitoring practices and protocols. Progressed plans for the three stages of the Competitive Process for the Fort McMurray West 500 kv Transmission Project (REOI, RFQ and RFP stages). Continued to advance work on the Transmission Facilities Cost Monitoring Committee including enhancing cost estimate quality and reporting, implementing cost oversight initiatives and drafting amendments to ISO Rule Section 9.1 Compliance Monitoring (describes the obligations of the transmission facility owner in carrying out transmission projects). Energized major system projects across the province including projects in the southern Alberta, Hanna, Calgary, Edmonton, and Fort McMurray areas Continue implementation of the Competitive Process. Initiate the first stages of the Competitive Process for the Fort McMurray East 500 kv Transmission Project. Implement recommendations from the Department of Energy s Transmission Cost Management Policy development. Continue to plan and build out the transmission plan with various major system projects under development. No notable initiatives for 2014. - AESO 2014 Business Plan and Budget Proposal Page 9
Customer Access Services We will consistently meet or exceed customer expectations in the delivery of AESO services. Connecting customers with expedience and providing excellent customer service throughout the process is essential to effective Customer Access Services. Additional system access requests are anticipated in 2014. The AESO continues to advance initiatives to streamline the connection process and improve cycle times including the Abbreviated Needs Identification Approval (ANIA) process and the Market Participant Choice process (MPC) as well as other refinements. The AESO is committed to ongoing improvements in Customer Access Services including increasing the number of Need Identification Documents (NIDs) filed with the AUC, and is confident the rigor and focus being applied in this area will lead to increasing customer satisfaction. This will be achieved through a continued focus on well-defined project scopes, high-level scheduling and clean transfer of engineering work and generally improved execution by all players at each stage of the process. The AESO provides Customer Access Services through four primary activity groups: Plan the Customer Connection; Connection Approval; Construction to Energization; and Customer Management. The work accomplished in these activity groups costs $10 million and represents 13 per cent of 2014 resource costs. Customer Access Services Costs $10 million to deliver 13% of total AESO resource dollars Plan the Customer Connection focuses on the thorough analysis and project management performed by the AESO. It involves conducting customer connection studies; power system model management; and coordination of customer requests and time spent moving through the connection proposal approval process. Connection Approval involves completing the regulatory requirements such as NID development, technical review and hearing management as well as creating functional specifications. Construction to Energization is mostly comprised of coordinating with the transmission facility owner (TFO) on various aspects of the customer connection through to energization as well as the transmission program support provided by the AESO internally and within the industry. Customer Management includes the financial transactions (transmission settlement and credit management) and consultation and development of the AESO tariff. Customer Access Services Costs by Activity Group 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Plan the Customer Connection ($3.3M) Construction to Energization ($1.9M) Connection Approval ($3.4M) Customer Management ($0.9M) AESO 2014 Business Plan and Budget Proposal Page 10
Achievements and Plans In addition to the ongoing customer access services activities, the following table outlines the notable achievements completed or expected to be completed in 2013 and planned initiatives for 2014 categorized by activity group. Plan the Customer Connection Connection Approval Construction to Energization Customer Management 2013 Achievements Enhanced metrics reporting to continue monitoring performance of parties affecting customer access processes. Obtained approval of implementation schedule to advance the Market Participant Choice pilot project. Continue to advance process enhancements. - 2014 Plans Continue to advance process enhancements. Further reduce customer connection cycle times. Continue to advance pilot projects such as Market Participant Choice to further align processes between transmission industry stakeholders and achieve additional efficiencies. Continue to advance process enhancements including the Abbreviated Needs Identification Approval (ANIA) process. No notable initiatives for 2014. AESO 2014 Business Plan and Budget Proposal Page 11
Market Development We will operate a fair, efficient and openly competitive (FEOC), real-time energy-only wholesale electricity market, where market evolution is driven by participants and the AESO. The current competitive wholesale market and Alberta s electric system create an overall electricity framework that continues to reliably serve consumers in one of the fastest growing jurisdiction in North America and generate numerous benefits for the province. The market is not stagnant and evolves along with changes in industry, technology and other relevant influences or circumstances. The AESO monitors developments and evaluates the impact of these changes to identify appropriate courses of action. When addressing market changes, the principal objective is to maintain a FEOC market and ensure market stability is maintained. Market stability is instrumental to ensuring investor confidence in opportunities in Alberta s electricity sector. Compliance monitoring to ensure market participants adhere to rules and procedures in their operations is an important aspect of maintaining a FEOC market. Rule development, operating procedure enhancements and implementation of IT solutions are all impacted when the design of the wholesale market is advanced. Incorporating storage technologies into the Alberta market is an example of a market enhancement where rules, tariff, technical standards and operating procedures are being reviewed by the AESO to ensure they are applicable and appropriate considering the market design and principles, including a FEOC market and reliable grid operations. Stakeholder engagement is vital to the success of market changes. At all times, an emphasis on stakeholder engagement is maintained; industry experience is essential to identifying and testing issues, opportunities, and solutions regarding market refinements. The AESO supports market development through three primary activity groups: Design and Create; Implement; and Monitor. The work accomplished in these activity groups combined amounts to $5 million and represents seven per cent of 2014 resource dollars. Market Development Costs $5 million to deliver 7% of total AESO resource dollars Design and Create involves identifying market evolution initiatives and determining the AESO s position and implementation plan through stakeholder consultation. The implementation plan may include the design of business processes, policies, procedures, or products; and changes to IT systems. The development of compliance expectations and monitoring procedures for new or changing rules is also a focus. Implement includes stakeholder consultation and execution of the implementation plan determined in the Design and Create activities and any required regulatory filings. Monitor encompasses the compliance monitoring of market participants through audits and assessments in addition to monitoring market performance and operations (market metrics) for issues and required changes. Market Development Costs by Activity Group 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Design and Create ($1.7M) Implement ($1.7M) Monitor ($1.6M) AESO 2014 Business Plan and Budget Proposal Page 12
Achievements and Plans In addition to the ongoing market development activities, the following table outlines the notable achievements completed or expected to be completed in 2013 and planned initiatives for 2014 categorized by activity group. Design and Create Implement Monitor 2013 Achievements Continued to facilitate demandside participation in the market and advanced work that will enable load to sell spinning reserves (continue to advance rules, Authoritative Documents and Information Documents). Anticipate issuing a discussion paper to industry on incorporating storage technologies into the Alberta market. Completed Market Systems Replacement Validation to address aging market systems impacting the reliable operation and timely evolution of the market. Targeting AESO Board approval in December 2013. Initiated TCM rule development. 2014 Plans Consult on, design and implement demand-side participation in the market. Consult on, design and implement plans to facilitate the integration of energy storage technologies. Complete and file TCM rule with the AUC. Wind integration: Implementation schedule for Phase 2 approved (up to 2,500 MW) including potential refinements to ancillary service products and a wind dispatch pilot project. Interties: Integrated the Montana-Alberta Tie Line (MATL), Alberta s first merchant intertie. Completed tool changes for implementation of the Western Electricity Coordinating Council (WECC) Dynamic Scheduling System to allow dispatchable interties. Implement plans to facilitate development, integration and restoration of the interties. Design and implement Phase 2 of wind integration. Implement the next phase of market systems replacement work (i.e. Request For Proposals) if given AESO Board approval. Continue market evolution through the development and implementation of the Operating Reserve market review recommendations. Continued to evolve market metric data. Implemented new/revised compliance monitoring for priority rule areas, including Offer Control rule, Wind Power Management Directives, Available Capacity changes, Ancillary Services declarations, detection of premature dispatch ramping, and generator testing rules to reflect market rule changes. Implement new compliance monitoring tools for new market rules as they are approved (e.g., dispatchable interties, intergration of storage technologies, dispatchable wind, and other initiatives). AESO 2014 Business Plan and Budget Proposal Page 13
Corporate Services We will design a high performance culture and provide an environment that makes the AESO an exceptional place to work, learn, succeed and make a difference. The AESO is comprised of an experienced team of many specialized technical experts and the competition to retain and attract these talented individuals is high. Recognizing that talent is a key enabler of the AESO s success, a number of talent management practices continue to be implemented as part of its longer-term roadmap. Some of these include an engineer-in-training rotation program, implementation of a new collaborative and self-serve talent management system, and a concerted focus on organizational and individual learning and development. We will build appropriate levels of public, industry and government support to ensure effective execution of our mandate. The AESO maintains effective relationships with government and industry as key stakeholders and enablers to successfully fulfilling the AESO s mandate for the province. The AESO continues to engage in ongoing public consultation in areas affected by transmission developments to fulfill the mandate of operating in the public interest and to help Albertans understand the role it plays in keeping the lights on. The AESO s Corporate Services are provided through four primary activity groups: Corporate Management; People Management; Administration and Executive general strategy. The work accomplished in these activity groups costs $10 million and requires 14 per cent of the 2014 resource dollars. Corporate Services Costs $10 million to deliver 14% of total AESO resource dollars Corporate Management includes the operations of corporate service functions including legal, accounting, security, facilities management, internal audit, project management and corporate communication. People Management describes the human resources activities such as compensation, workforce planning, recruiting and learning and development. Administrative accounts for the administrative support staff. Executive (general strategy) portion of Corporate Services relates to general strategy development and leadership of the AESO; executive resources have also been associated with other key processes. Corporate Services Costs by Activity Group 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Corporate Management ($6.1M) Administrative ($1.6M) People Management ($1.7M) Executive - general strategy ($0.9M) AESO 2014 Business Plan and Budget Proposal Page 14
Achievements and Plans In addition to the ongoing corporate services activities, the following table outlines the notable achievements completed or expected to be completed in 2013 and planned initiatives for 2014 categorized by activity group. Corporate Management People Management Administrative Executive 2013 Achievements Completed an assessment of the AESO communications program. Implemented year one of a three-to-five year customer service initiative. Developed and began implementation of a new enterprise-wide talent management system. - Advanced development of the AESO s 2014-2018 Strategic Plan. 2014 Plans Continue refinement and implementation of communications plans. Continue to advance implementation of talent management system. No notable initiatives for 2014. Complete and publish the AESO s 2014-2018 Strategic Plan. Continue to advance the customer service initiative. AESO 2014 Business Plan and Budget Proposal Page 15
Information Technology Services Underlying the five key processes of the AESO are the Information Technology Services that provide the systems and tools to allow for seamless operations. The activities and costs in this area can be associated with the five key AESO processes but additional time is required to complete a thorough review and analysis of the information prior to its inclusion in the key processes as part of the 2015 business plan. We will learn and leverage leading technologies. Information technology is critical to the AESO s ability to support ongoing operations. Investing in this area allows the AESO to better support its operations and prepare for future initiatives that will require additional infrastructure support. Information Technology Services includes the operational support of critical real-time systems as well as general business systems. This comprises of 150 active applications used by over 200 market participants and 500 AESO personnel across two data centres with over 900 servers and 300 databases. The resources for Information Technology Services are focused on five primary activity groups: Infrastructure and Operations; IT Planning; Application Support and Validation. The work supporting these activity groups combined amounts to 15 per cent or $11 million of 2014 resource costs. Information Technology Costs $21 million to deliver ($11 million for resources & $10 million for systemrelated costs) Infrastructure and Operations involves the ongoing maintenance and administration of the information technology systems and applications for critical real-time and general business systems and front line customer service staff supporting corporate applications. IT Planning ensures alignment between the AESO s business strategy and IT capabilities. It also includes the creation of standards and practices supporting business systems and general and administrative costs related to capital development. Application Support includes fulfillment of standard application-related service requests and troubleshooting to identify the root cause and fix issues related to applications. Validation includes reviewing feasible options to achieve a business outcome and providing a recommendation in a business case the decision if a project should proceed or not. Information Technology Costs by Activity Group Resources 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Infrastructure and Operations ($4.8M) Application Support ($2.8M) IT Planning ($3.1M) Validation ($0.4M) AESO 2014 Business Plan and Budget Proposal Page 16
In addition to the resources that are focused to plan and maintain the information technology infrastructure, system-related costs of $10 million are incurred annually on licenses, maintenance agreements, managed service program and telecommunications. System-related 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% IT Maintenance ($5.3M) Telecomm ($1.5M) IT Services ($0.2M) IT Managed Services ($2.4M) Wind Forecasting Service ($0.3M) In general, the information technology activity groups described above relate to general operating activities required to run the business systems and maintain the infrastructure. There are also a large number of information technology activities that are carried out as part of the capital plan and are outlined in Appendices A and D. The following tables outlines the notable achievements completed or expected to be completed in 2013 and planned initiatives for 2014. Infrastructure and Operations 2013 Achievements Relocated the AESO s Backup Coordination Centre seamlessly. Completed Phase 1 validation of the Market Systems Replacement (MSR) project that captures long-term business needs, determines potential solutions and builds a business case for MSR Phase 2 which is the request for proposals (RFP) project. 2014 Plans Execute Phase 2 of the MSR project to define the detailed target state, priorities and issue RFP(s) to market systems vendors. Enable grid and market-related initiatives including wind participation in the energy market and implementation of HVDC functionality in the Energy Management System (EMS). Initiate EMS infrastructure lifecycle upgrades. Implement processes and system changes to advance AESO s cyber security program. Advance implementation of the AESO s document management and collaboration tool. AESO 2014 Business Plan and Budget Proposal Page 17
Financial Highlights As part of this 2014 Business Plan, the AESO is also presenting its 2014 budget. The budget is the culmination of the analysis from the activity reporting process undertaken and includes identified efficiencies, new initiatives for 2014 and changes to general operations. The 2014 budget is one that meets the needs of the organization to deliver on its commitments and to demonstrate that financial management continues to be a focus. The financial information is presented in two sections: Section I reviews the 2013 financial results for year-to-date September and Section II provides budget information for 2014. Additional information is included in Appendices A to F. AESO 2014 Business Plan and Budget Proposal Page 18
Section I 2013 Costs The following table provides a summary of costs as of September 2013 compared to the budget. Year-to-Date September 2013 Costs ($ million) ~ by production year YTD Sept Actual YTD Sept Budget YTD Sept Variance 2013 Budget Transmission Operating Costs 1,274.9 1,101.7 173.2 1,470.4 Other Industry Costs 18.4 18.1 0.3 24.1 General and Administrative Costs 1 70.5 73.7 (3.2) 98.3 Market Systems Replacement Project 1 0.6 0.6 0.0 1.0 Interest 0.8 1.0 (0.1) 1.3 Amortization of Intangible and Capital Assets 18.5 17.5 1.0 23.3 Differences are due to rounding. The notable variance in the year-to-date results relates to transmission operating costs and more specifically, operating reserves. Additional information on year-to-date costs is provided in Appendix A. Market Systems Replacement Project $ Millions 1,800 1,500 1,200 900 600 Due to a potential misalignment with the annual budgeting process, the introduction of a significant new expenditure may be reviewed and approved by the AESO Board during the year without first being introduced in the Budget Review Process. This approval does not occur without the involvement and consultation with market participants through a process that is similar to the annual budgeting process (the presentation of project information to market participants, the receipt of comments and feedback followed by the presentation to the AESO Board for consideration of approval). 300 0 YTD Actual Trans Operating Costs G&A Costs Amortization YTD Budget 2013 Budget Other Industry Costs Interest The AESO currently has one such project that followed this process in 2013; the Market Systems Replacement (MSR) project. The MSR project was first introduced to market participants and the AESO Board in early 2013 with initial project funding for Phase 1 of $1.0 million approved in April 2013. This project will be managed in three distinct phases. Further details on the MSR project are provided in Section II - 2014 under the Market Systems Replacement Cost Section. 1 While the AESO Board approved an additional general and administrative project in April 2013 - the Market Systems Replacement project - the actual and budget amounts are reported separately for 2013 and 2014. AESO 2014 Business Plan and Budget Proposal Page 19
Capital Expenditures The estimated capital expenditures in 2013 are $22.1 million which is $4.9 million or 18 per cent lower than the capital budget of $27.0 million. In general, the AESO s capital projects which are predominately multi-year in nature, have continued to progress or have been completed in 2013. Additional detailed information on the status and progress of specific projects is provided in Appendices A and D. $ Millions 30 25 20 15 10 While capital development progressed in many areas, there are some notable timeline changes that occurred during the year. The following projects are of particular note: The Energy Management System (EMS) upgrade was deferred pending the completion of an internal strategy review. The Operating Reserve product development was deferred pending BAL-002-WECC 2 standard approval by the Federal Energy Regulatory Commission (FERC). 5 0 YTD Actual Life Cycle Funding Key Capital Initiatives 2013 Projection 2013 Budget Other Capital Initiatives Portions of the Intertie Framework program (e.g., dispatchable interties) were deferred pending the development and approval of Independent System Operator (ISO) Rules. The following table provides a summary of the current capital project investment for 2013. Capital Expenditures ($ million) 2013 YTD Sept Actual 2013 Remaining 2013 Projection Key Capital Initiatives 6.8 2.1 8.9 Other Capital Initiatives 5.5 2.2 7.6 Life Cycle Funding 3.2 2.3 5.5 Total Capital Spending 15.5 6.6 22.1 Differences are due to rounding. Key Capital Initiatives represent the most critical capital projects over the planning period that the AESO believes must be completed within the identified timeframe. Other Capital Initiatives are also necessary projects; however, they have more flexibility in planning or delivery so timing is not as critical as the Key Capital Initiatives. Life Cycle Initiatives are typically leasehold improvements, replacement of end-of-life IT hardware and recurring software upgrades. 2 The purpose of the reliability standard is to specify the quantity and types of Contingency Reserve necessary to replace generating capacity and energy lost due to forced outages of generation or transmission equipment. AESO 2014 Business Plan and Budget Proposal Page 20
Section II 2014 Financial Outlook In planning for 2014, five distinct cost categories are reviewed. These cost categories are the following: Transmission Operating Costs (i.e., wires, transmission losses, ancillary services) Other Industry Costs General and Administrative and Interest Costs and Amortization Market Systems Replacement Project Capital Expenditures The focus of the following section is to highlight the changes from the 2013 budgets. ($ million) 2014 Budget 2013 Budget Transmission Operating Costs 1,749.0 1,470.4 Other Industry Costs 23.9 24.1 General and Administrative 1 96.0 98.3 Market Systems Replacement Project 1 2.0 1.0 Interest Costs 0.5 1.3 Amortization 27.3 23.3 Capital Expenditures 19.9 27.0 Differences are due to rounding. 2014 Budget Other Industry General and Administrative Market System Replacement Project Amortization Transmission Operating Interest AESO 2014 Business Plan and Budget Proposal Page 21
Costs Transmission Operating Costs The following table provides a summary of transmission operating costs. Transmission Operating Costs ($ million) ~ by production year 2014 2013 Forecast Projection 2013 Forecast 2012 Actual 2011 Actual Wires Costs 1,407.3 1,120.8 1,074.3 944.0 782.4 Transmission Line Losses 117.3 185.4 136.9 150.7 183.9 Operating Reserves 193.7 346.6 181.2 320.6 325.0 Transmission Must-Run - 5.0 2.0 27.0 31.2 Other Ancillary Service Costs 30.7 38.4 76.0 26.5 9.5 Transmission Operating Costs 1,749.0 1,696.2 1,470.4 1,468.8 1,332.0 Differences are due to rounding. Additional information on the 2014 forecast methodology and descriptions of the cost categories is provided in Appendix B. Wires Wires costs represent the amounts paid primarily to owners of transmission facilities (TFOs) in accordance with their Alberta Utilities Commission (AUC)-approved tariffs and are not controllable costs of the AESO. $ Millions 2,000 1,500 1,000 The 2014 forecast for wires costs is $1,407.3 million which is a $333.0 million or 31 per cent increase from the 2013 forecast of $1,074.3 million. The 2014 forecast is based on the current applied-for or AUCapproved TFO tariffs ($1,401.5 million) and the AESO s forecast for Invitation to Bid on Credit (IBOC) and Location Based Credit Standing Offer (LBC SO) costs ($5.8 million). 500 0 2014 Forecast 2013 Projection Other Ancillary Service Costs Operating Reserves Wires Costs 2013 Forecast 2012 Actual Transmission Must-Run Transmission Line Losses The AESO understands that the TFO tariff increases reflect capital and operating costs associated with projects providing additional transmission system capacity as well as higher costs to operate and maintain existing transmission facilities. Included in wires costs are long-term contracts related to IBOC and LBC SO programs, which were initiated as an incentive for supply to locate closer to major load centres and provide a non-wires solution to transmission wires issues in Alberta. AESO 2014 Business Plan and Budget Proposal Page 22
Transmission Line Losses The 2014 forecast for transmission line losses is $117.3 million based on 2.34 terawatt hours of energy and the average hourly pool price forecast of $48 per megawatt hour (MWh). The 2014 forecast for transmission line losses costs is $19.6 million or 14 per cent lower than the 2013 forecast of $136.9 million, which was based on 2.22 terawatt hours of energy and an average pool price of $60 per MWh. Lower costs are the result of the lower pool price forecast for 2014, which is attributable to changes in the anticipated generation mix, including the return of several generating units that experienced long-term outages in 2013. The 2014 transmission line losses volumes forecast of 2.34 terawatt hours of energy represents an increase of 0.12 terawatt hours of energy or six per cent from the 2013 volumes forecast of 2.22 terawatt hours of energy. This increase is a reflection of recent hourly trends in actual losses volumes, which are factored into the forecasting model for 2014. Operating Reserves The 2014 forecast for operating reserves costs is $193.7 million which is $12.5 million or seven per cent higher than the 2013 forecast of $181.2 million. The 2014 operating reserves volumes forecast of 7.9 terawatt hours is slightly lower than the 2013 forecast of 8.0 terawatt hours and the average hourly pool price forecast for 2014 of $48 per MWh is also lower than the 2013 average hourly pool price forecast of $60 per MWh. The increase in the operating reserves costs forecast from 2013 to 2014 is primarily the result of a change in the calculation methodology used. In 2013, the forecasted costs for operating reserves were based on the 95 th percentile of costs forecasted for the whole year; whereas in 2014, the forecasted costs are based on the summation of the 95 th percentile of the monthly operating reserves costs forecasts to establish the annual cost forecast. This change in methodology allows the AESO to better capture the effect of monthly and seasonal price volatilities in the operating reserve market. Transmission Must-Run (TMR) The 2014 forecast for TMR costs is nil 3, which is $2.0 million lower than the 2013 forecast. Due to transmission enhancements in the Northwest area of Alberta in 2013 and current TMR requirements forecasted for 2014, there are no contracted TMR services forecast for the coming year. Other Ancillary Services Other ancillary services that the AESO procures for the secure and reliable operation of the Alberta Interconnected Electric System (AIES) include load shed service for imports (LSSi), black start and services provided by Poplar Hill generator. The 2014 forecast for these services is $30.7 million which is $45.3 million or 60 per cent lower than the 2013 forecast of $76.0 million. This decrease is mainly attributable to lower LSSi costs forecasted for 2014. The 2014 LSSi forecast is based on the current monthly average costs which have been consistent over the period of use of LSSi and are expected to continue into the coming year. The lower LSSi costs are slightly offset by higher black start services costs due to the forecast procurement of additional black start capability for the province, which is expected to be available in the last quarter of 2014. 3 In the 2014 Budget Review Process Technical Meeting presentation, the 2014 forecast for TMR costs was $2.5 million. These costs relate to the 2014 forecast for services provided by Poplar Hill generator and have been moved to the other ancillary services costs category for consistent presentation with prior years. AESO 2014 Business Plan and Budget Proposal Page 23
The AUC has approved the recovery of LSSi costs in the 2013 ISO Tariff on an interim refundable basis. The treatment and recovery of LSSi costs are currently before the AUC in the AESO s deferral account proceeding for 2012 and the tariff application proceeding for 2013 and 2014. Other Industry Costs Other industry costs represent fees or costs paid based on regulatory requirements or membership fees for industry organizations; the amounts or requirement for the costs are not under the direct control of the AESO. These costs relate to regulatory process costs, the annual administration fee for the AUC, and the AESO s share of Western Electricity Coordinating Council (WECC) and Northwest Power Pool (NWPP) membership fees. Other Industry Costs ($ million) 2014 Budget 2013 Projection 2013 Budget 2012 Actual 2011 Actual Regulatory Process Costs 4 1.8 1.7 1.1 2.5 0.2 AUC Fees Transmission 13.6 13.2 12.9 14.0 12.5 AUC Fees Energy Market 7.2 6.9 7.2 7.1 6.9 WECC/NWPP Costs 5 1.3 2.8 2.9 3.0 2.8 Other Industry Costs 23.9 24.6 24.1 26.6 22.4 Differences are due to rounding. Regulatory Process Costs The costs associated with the AESO s involvement in an AUC proceeding to hear objections and complaints to ISO Rules or any regulatory application are included in the cost category regulatory process costs; this does not include application preparation costs. These proceedings become a high priority relative to other business initiatives that were identified in the business planning process, and the level of AESO resources required to address these matters brought before the AUC is difficult to determine in advance of a budget year. To ensure ongoing focus and achievement of the planned business initiatives and to avoid constraints on the general and administrative budget management, these costs appear as other industry costs. Intervener costs that received AUC cost order approval are also included in this category. The 2014 budget for regulatory process costs is $1.8 million compared to the 2013 budget of $1.1 million. The 2014 estimate is comprised of the following components: $0.7 million for potential objections and complaints to ISO Rules or Alberta Reliability Standards, $0.8 million for proceedings related to Need Identification Documents (NIDs) filed by the AESO, and $0.2 million for AESO regulatory applications (specifically the ISO Tariff). $ Millions 25 20 15 10 5 0 2014 Budget 2013 Budget WECC/NWPP Costs Regulatory Process Costs AUC Fees - Energy Market AUC Fees - Transmission 2012 Actual 4 Prior to the 2013 budget, referred to as External Regulatory Costs 5 Western Electricity Coordinating Council/Northwest Power Pool AESO 2014 Business Plan and Budget Proposal Page 24
The increase in the 2014 budget is due to the number and complexity of the potential proceedings anticipated. AUC Fees The AESO is required to pay annual administration fees to the AUC. The AUC recovers its operating and capital costs through an administration fee imposed on the natural gas and electricity market participants that it has jurisdiction over or any person to whom the AUC provides services. The AUC uses a cost assessment model to allocate its costs to the various classes and categories of utilities and persons and to determine the amount of the administration fee imposed on each class and category. Two classes of fees are paid to the AUC one related to transmission operations and the other to energy market operations. WECC/NWPP Fees The AESO is an active member of the WECC, the organization that coordinates and promotes reliability in the Western Interconnection. Its members coordinate the day-to-day interconnected system operations and long-range planning required to provide reliable electric service in the WECC service territory that extends from Canada to Mexico. The 2014 budget for WECC fees is $1.2 million compared to the 2013 budget of $2.8 million. The fee reduction of $1.6 million in 2014 relates to the AESO assuming all responsibilities for the function of a Reliability Coordinator 6 for the province of Alberta starting on January 1, 2014. This effective date aligns with changes to the organizational structure of WECC that will see it retain its function as a Regional Entity and no longer provide Reliability Coordinator-type services. The following list highlights both the operational and cost impacts associated with this change. Minimize conflict of authority with other jurisdictions. Utilize the AESO s authority under Alberta legislation to direct the safe, reliable and economic operation of the Alberta system. Clearly identify the reliability area which will be governed by Alberta Reliability Standards and ISO Rules. Increase efficiencies through the removal of duplication of Reliability Coordinator-type activities. Take advantage of the expertise in the distinct geographic areas with the AESO System Controllers being the most knowledgeable about the AIES. Reduce the WECC fees associated with the Reliability Coordinator function. Increase the AESO staff complement by five staff resources in 2014. The AESO is also a member of the NWPP, which operates to achieve maximum benefits of coordinated operations for its member organizations. Participation in the NWPP allows the AESO to take advantage of their Reserve Sharing Group, thereby reducing Alberta s reserve requirements at times. The annual budget for NWPP fees is $0.1 million. 6 The Reliability Coordinator function as it is defined in the North American Electric Reliability Corporation (NERC) Functional Model is to maintain the real-time operating reliability of its Reliability Coordinator Area and in coordination with its neighboring Reliability Coordinator s wide-area view. An entity performing this function monitors transmission services; coordinating, and in some instances, issuing directives to participants to ensure secure operation of the transmission system. AESO 2014 Business Plan and Budget Proposal Page 25
General and Administrative Costs The focus for 2014 is delivery on commitments while being more innovative in finding operational efficiencies. This is not a one-time endeavor for the AESO; this is the way of doing business. Organizations evolve and change and it was during 2013 that time was dedicated to review the current business operations of the AESO to assess the value or outcome of its work efforts and determine the costs for delivery. The goal was twofold. First, to ensure there is full understanding of where resources are focused, and second, to identify potential process improvements or resource reassignments. The results of this work are reflected in the 2014 general and administrative budget. The analysis of costs by activity grouping for 2014 confirmed several factors. The AESO is a cross functional organization that must be well coordinated internally to ensure quality work is produced, timelines are met and all resources are working efficiently. Using both the information from ongoing dayto-day management and the activity groupings provides insight to identify areas that need additional resources in 2014 to meet commitments or changes in scope or conversely, where commitments have been fulfilled and resources can be reassigned. The net impact for 2014 was a reduction to the general and administrative budget and a commitment to continue this efficiency focus into 2015 and future years. The 2014 budget will be $2.3 million or two per cent lower than the 2013 budget for total general and administrative costs of $96.0 million. The budget adjustments for 2014 have mainly focused on resource costs (staff and contract services). 2013 Approved G&A Budget ($ million) $ 98.3 1 Staff Costs 0.7 Contract Services and Consultants (2.4) Administration (0.4) Facilities (0.1) Computer Services and Maintenance & Telecommunications (0.0) (2.3) 2014 Budget $ 96.0 1 Differences are due to rounding. There are several components in the 2014 budget that are worth highlighting. As previously mentioned in the other industry costs section, the AESO will assume all responsibilities that relate to the functions of a Reliability Coordinator 6 for the province of Alberta on January 1, 2014. Planning for this change has been underway for the last several months and the new functions will be integrated into the AESO s Electric System Operations processes. The AESO will achieve a $1.6 million cost saving in 2014 for other industry costs through a reduced annual WECC fee though these savings will be partially offset by an increase to general and administrative costs with the addition of five staff resources in 2014 to support this additional work. AESO 2014 Business Plan and Budget Proposal Page 26
The 2014 budget has incorporated a three and a half per cent salary adjustment for staff. This annual adjustment allows the AESO s pay structure to stay aligned with organizations that compete for the same technical staff and the general labour market as a whole. To offset these higher costs, savings have been identified mainly through reduced staff costs and reliance on contract services and consultants. Some savings were easier to identify when associated with non-recurring or completed initiatives (such as connection studies and cost benchmarking) with the remaining reductions from efficiencies and re-prioritization. The organization is confident that these reductions will not put the operations or deliverables at risk; it will create a heightened level of financial management within the operations. $ Millions 100 75 50 25 0 2014 Budget Telecommunications Facilities Consulting 2013 Budget 2012 Actual Comp Services & Maint Adminstration Staff Costs General and Administrative Costs ($ million) 2014 Budget 2013 Budget 2012 Actual 2011 Actual Staff 61.8 61.1 57.9 52.5 Contract Services and Consultants 12.7 15.0 15.3 17.9 Administration 5.4 6.0 6.3 7.0 Facilities 6.3 6.5 5.7 4.7 Computer Services and Maintenance 8.3 8.3 7.6 4.9 Telecommunications 1.5 1.4 1.5 1.4 General and Administrative Costs 1 96.0 98.3 94.3 88.5 Differences are due to rounding. Market Systems Replacement Project Market System Replacement Project ($ million) 2014 Budget 2013 Budget 2012 Actual 2011 Actual Market Systems Replacement Project 1 2.0 1.0 - - The Phase 1 (validation) of the Market Systems Replacement (MSR) project is currently underway and in December 2013, the AESO Board will decide if Phase 2 of the project should proceed, the request for proposals (RFP). Assuming a decision to proceed is received, the AESO plans to issue one or more RFPs to potential implementation partners to evaluate and ultimately select as a partner for project development and implementation. The cost estimate to proceed with Phase 2 for the RFP project is $2.0 million and is tentatively scheduled for completion in 2014. The AESO will consult with market participants should any other component of the MSR project (e.g., Phase 3 for project implementation) need to be advanced into 2014. Additional information on the MSR project Phase 2 is provided in Appendix E. AESO 2014 Business Plan and Budget Proposal Page 27
Interest Costs and Amortization Interest Costs and Amortization ($ million) 2014 Budget 2013 Budget 2012 Actual 2011 Actual Interest 0.5 1.3 0.9 2.6 Amortization of Intangible and Capital Assets 27.3 23.3 24.4 17.5 Interest Interest expense is incurred as a result of bank debt held throughout the year and the associated borrowing rate. Bank debt is issued to fund intangible and capital asset purchases and working capital deficiencies due to timing differences in the collection of revenues and payment of expenses. Intangible and capital assets are financed through the AESO s credit facilities and recovered over the useful lives of the assets (included in amortization). The AESO s working capital includes deposits for generating unit owner s contributions that are held by the AESO and refunded to generators in accordance with the terms and conditions within the ISO Tariff. For 2014, these deposits are estimated to be approximately $66 million and are used to offset otherwise required borrowings until such time as they are refunded. Amortization of Intangible and Capital Assets Intangible and capital assets are amortized over their estimated useful lives in accordance with generally accepted accounting principles and reviewed on an annual basis. Additional information on the AESO s 2014 capital projects is provided in Appendix D. AESO 2014 Business Plan and Budget Proposal Page 28
Capital Expenditures A detailed review of the capital requirements for 2014 incorporated the progress that has been made on the 2013 projects that are multi-year in nature, the new requirements for 2014 and the AESO s capacity to design and implement system solutions. Based on these findings, the 2014 capital budget is $19.9 million, $7.1 million or 26 per cent lower than the 2013 budget of $27.0 million. $ Millions 30 25 20 15 The AESO considers the budgeting process for capital expenditures as the determination for the annual level of capital expenditures for use in the portfolio management process; not the review and approval of specific capital projects. All capital projects initiated by the AESO are reviewed and approved through the portfolio management process. This process is led by senior management and facilitates a regular review and prioritization of major projects to ensure business requirements are met and, at the same time, achieve the most beneficial and cost-effective results. This process also allows for the flexibility to re-evaluate capital plans throughout the year. 10 5 0 2014 Budget 2013 Budget Life Cycle Funding Other Capital Initiatives Key Capital Initiatives 2012 Actual The following table identifies a preliminary list of projects that are planned for 2014 based on current operations and the business initiatives. As time progresses in 2014, requirements and circumstances may change and the portfolio management process will be used to manage these changes. Additional information on the 2014 capital projects is provided in Appendix D. AESO 2014 Business Plan and Budget Proposal Page 29
Capital Expenditures ($ million) Key Capital Initiatives 2014 Budget 2013 Projection 2013 Budget 2012 Actual 2011 Actual 1. Reliability (EMS 7 components) 3.2 0.8 4.0 1.2 1.6 Reliability (HVDC 8 & other components) 2.0 1.4 2. Wind Integration 0.9 0.0 0.5 0.3 2.1 3. FEOC 9 Regulation Implementation - 0.2 0.0 1.0 0.0 4. Market Evolution (Incorporates TCM 10 ) 0.2 0.6 0.7 0.0 0.7 5. Demand Response 0.6 0.1 0.4 0.0 2.5 6. Intertie Framework 0.6 2.3 2.2 3.4-7. Operating Reserve 0.5 0.3 8. Transmission Cost Accountability 0.3 9. Information Management Platform - 0.6 1.3 1.2 1.8 10. ISO Tariff Application 0.2-0.2 0.2-11. BUCC 11 Replacement - 2.5 2.6 0.4 - Total Key Capital Initiatives 8.4 8.9 11.9 7.7 8.7 Other Capital Initiatives 5.3 7.6 8.3 9.6 7.8 Life Cycle Funding 6.2 5.5 6.8 8.2 12.2 Total Capital Spending 19.9 22.1 27.0 25.5 28.7 Differences are due to rounding. Key Capital Initiatives represent the most critical capital projects over the planning period that must be completed within the identified timeframe. Other Capital Initiatives are also necessary projects; however, there is more flexibility in planning or delivery so timing is not as critical as the Key Capital Initiatives. Life Cycle Initiatives are typically leasehold improvements, replacement of end-of-life IT hardware and recurring software upgrades. Additional detailed information on capital projects is provided in Appendix D. 7 Energy Management System (EMS): Project components were recorded as general and administrative costs after the decision to defer the upgrade (the EMS strategy review) 8 High Voltage Direct Current (HVDC) 9 Fair Efficient Open Competitive (FEOC): The multi-year project is complete with no additional funding required 10 Transmission Constraint Management (TCM) 11 Backup Coordination Centre (BUCC): The multi-year project is complete with no additional funding required AESO 2014 Business Plan and Budget Proposal Page 30
Revenue The AESO recovers its operating and capital costs through three separate revenue sources. Each is designed to recover the costs directly related to a specific service as well as a portion of the shared corporate services costs. The AESO s operations integrate the functions of transmission, energy market and load settlement to maximize benefits under the Electric Utilities Act (EUA). This integration results in cost allocations in many parts of the organization for the purpose of cost recovery. In determining the revenue requirement on a function-by-function basis, all AESO costs are assigned or allocated to one of the three functions. Additional information on the 2014 cost allocation methodology is provided in Appendix F. Transmission The AESO is responsible for paying the costs of the provincial transmission system and recovering the costs through a tariff approved by the AUC. The ISO Tariff is designed to allocate the costs to all users of the transmission system based on level of usage. The 2014 budget costs related to the transmission function will be incorporated into the AESO's rates through a comprehensive tariff application currently in progress before the AUC. Energy Market The AESO recovers the costs of operating the real-time energy market through an energy market trading charge on all MWhs traded. Based on the 2014 budget and a current trading volume forecast, an energy market trading charge of 37.9 per MWh traded is required for 2014. The increase in the 2014 trading charge recoverable amount is mainly due to an increase in amortization associated with the intangible and capital asset additions in recent years and a shortfall in collections from 2013 and prior years. The cumulative shortfall balance is affected by actual energy market costs being higher than the amounts incorporated into the annual charge calculation (i.e., unanticipated budget to actual variances) and lower revenue collections. These trading charge amounts are independent of the Market Surveillance Administrator (MSA) charge. The 2014 MSA cost recovery amount will be communicated to the AESO in the latter part of 2013. The MSA cost recovery amount is approved by the Chair of the AUC in an independent budget process. $ Million 55 45 35 25 15 5 (5) 2014 Budget 2013 Budget 2012 Budget AUC Admin Fee Prior Year (Shortfall) / Surplus Regulatory Process Interest & Amortization G&A Trading Charge Recoverable Amounts ($ million) 2014 Budget 2013 Budget 2012 Budget AESO Costs 37.2 33.1 32.7 Energy Market Shortfall / (Surplus) 4.0 (1.0) 3.0 AESO Component 41.2 32.1 35.7 AUC s Portion of Energy Market Administration Fee 7.2 7.2 7.2 Total Recoverable Amount 48.4 39.3 42.9 Differences are due to rounding. AESO 2014 Business Plan and Budget Proposal Page 31
Trading Charge ( per MWh) 2014 Budget 2013 Budget 2012 Budget AESO Costs 29.1 26.7 25.8 Energy Market Shortfall / (Surplus) 3.1 (0.8) 2.3 AESO Component 32.3 25.9 28.1 AUC s Portion of Energy Market Administration Fee 5.6 5.8 5.7 Total 37.9 31.7 33.8 Differences are due to rounding. Load Settlement Expenses that the AESO incurs to provide services related to administering provincial load settlement are charged to the owners of electric distribution systems and wire service providers conducting load settlement under AUC Rule 21 Settlement System Code Rules. AESO 2014 Business Plan and Budget Proposal Page 32
Appendix A: Year-to-Date September 2013 Financial Results Detail Costs Transmission Operating Costs The following table provides the transmission operating costs as of September 2013 compared to the forecast. Year-to-Date September 2013 Transmission Operating Costs ($ million) ~ by production year YTD Sept Actual YTD Sept Forecast YTD Sept Variance 2013 Projection 2013 Forecast Wires Costs 794.0 805.7 (11.7) 1,120.8 1,074.3 Transmission Line Losses 151.3 106.1 45.2 185.4 136.9 Operating Reserves 307.1 131.4 175.7 346.6 181.2 Transmission Must-Run 3.4 1.5 1.9 5.0 2.0 Other Ancillary Service Costs 19.1 57.0 (37.9) 38.4 76.0 Transmission Operating Costs 1,274.9 1,101.7 173.2 1,696.2 1,470.4 Differences are due to rounding. Transmission operating costs represent wires, transmission line losses and ancillary services costs. As of September 2013, actual costs of $1,274.9 million are $173.2 million or 16 per cent higher than the forecasted costs of $1,101.7 million. This variance is mainly attributable to variances in operating reserves. 1,500 1,000 Wires Costs Wires costs as of September 2013 are $794.0 million, which is $11.7 million or one per cent lower than the forecast of $805.7 million based on the amounts paid primarily to the owners of transmission facilities (TFOs) in accordance with their AUC-approved tariffs. This variance is attributable to wires payments to some providers being lower than forecast due to pending AUC decisions. $ Millions 500 0 YTD Actual YTD Forecast The 2013 projection is anticipating actual wires costs of $1,120.8 million, which is $46.5 million or four per cent higher than the 2013 forecast of $1,074.3 million due to the approval of pending AUC decisions in the last quarter of the year. Other Ancillary Service Costs Transmission Must-Run Operating Reserves Transmission Line Losses Wires Costs AESO 2014 Business Plan and Budget Proposal Page 33
Transmission Line Losses Transmission line losses costs at the end of September 2013 are $151.3 million, which is $45.2 million or 43 per cent higher than the forecast of $106.1 million. This variance is due to the year-to-date actual average hourly pool price, which has been $91 per MWh compared to a forecast of $61 per MWh. The higher pool price is primarily due to changes to the duration and timing of planned outages as well as unanticipated outages of several key generating units in 2013. Transmission line losses volumes to the end of September are 1.6 terawatt hours compared to the forecast volumes of 1.6 terawatt hours, representing an increase of approximately two per cent. The 2013 projection is relatively consistent with the year-to-date results, anticipating actual transmission line losses costs of $185.4 million, which is $48.5 million or 35 per cent higher than the 2013 forecast of $136.9 million mainly attributable to pool price. Operating Reserves Operating reserve costs at the end of September 2013 are $307.1 million, which is $175.7 million or 134 per cent higher than the forecast of $131.4 million. This variance is mainly attributable to the costs of operating reserves during periods of much higher than average pool prices. In the time period from January to September 2013, there were 47 days when the on-peak average pool price was above $200 per MWh and the operating reserve costs associated with these days was $218.6 million or 71 per cent of the $307.1 million costs. As operating reserve costs are indexed to the hourly pool price, higher than forecast pool prices result in higher than anticipated operating reserve costs. The higher pool prices can be associated with periods of planned and unplanned generation outages and transmission system constraints. Actual operating reserve volumes to the end of September are 6.0 terawatt hours which is 0.1 terawatt hours or approximately one per cent higher than the forecast volumes of 5.9 terawatt hours. The 2013 projection is anticipating actual operating reserve costs of $346.6 million, which is $165.4 million or 91 per cent higher than the 2013 forecast of $181.2 million due to pool price variances from budget. Transmission Must-Run (TMR) Transmission must-run costs at the end of September 2013 are $3.4 million, which is $1.9 million or 127 per cent higher than the forecast of $1.5 million. TMR costs include both contracted and unforeseeable amounts. Contracted TMR costs at the end of September 2013 are $1.9 million, which is $0.4 million or 27 per cent higher than the forecast of $1.5 million due to the 2013 forecast being determined prior to the finalization of contract negotiations in late 2012. The 2013 forecast was based on the expression of interest submissions and forecast volume requirements available at that point in time. Unforeseeable TMR costs at the end of September 2013 are $1.4 million, attributable to payments for unforeseeable events that have occurred that were not included in the 2013 forecast. Unforeseeable TMR is required to mitigate the overloading of transmission lines associated with line outages, system conditions in real time and the loss of generation in an area. The 2013 projection is anticipating actual transmission must-run costs of $5.0 million, which is $3.0 million or 150 per cent higher than the 2013 forecast of $2.0 million. This increase is consistent with the continuation of the current actual variances for contracted TMR and additional projected unforeseeable TMR costs. AESO 2014 Business Plan and Budget Proposal Page 34
Other Ancillary Service Costs Other ancillary services that the AESO procures for the secure and reliable operation of the Alberta Interconnected Electric System (AIES) include load shed service for imports (LSSi), black start and services provided by Poplar Hill generator. Other ancillary services costs at the end of September 2013 are $19.1 million, which is $37.9 million or 66 per cent lower than the forecast of $57.0 million mainly due to costs for LSSi, which have been lower than expected due to the limited historical information available when preparing the 2013 forecast. The 2013 projection is relatively consistent with the year-to-date results, anticipating actual other ancillary services costs of $38.4 million, which is $37.6 million or 49 per cent lower than the 2013 forecast of $76.0 million. Other Industry Costs The following table provides other industry costs as of September 2013 compared to the budget. Year-to-Date September 2013 Other Industry Costs ($ million) YTD Sept Actual YTD Sept Budget YTD Sept Variance 2013 Projection 2013 Budget Regulatory Process Costs 4 1.4 0.8 0.5 1.7 1.1 AUC Fees Transmission 9.8 9.7 0.1 13.2 12.9 AUC Fees Energy Market 5.1 5.4 (0.3) 6.9 7.2 WECC/NWPP Costs 5 2.1 2.2 (0.1) 2.8 2.9 Other Industry Costs 18.4 18.1 0.3 24.6 24.1 Differences are due to rounding. Other industry costs represent fees or costs paid based on regulatory requirements or membership fees for industry organizations; the amounts or requirement for the costs are not under the direct control of the AESO. These costs relate to 20 regulatory process costs, the annual administration fee for the Alberta Utilities Commission (AUC), and the AESO s share of Western Electricity Coordinating Council (WECC) and Northwest 15 Power Pool (NWPP) membership fees. For regulatory process costs, there are three categories: i) objections and complaints to ISO Rules or any regulatory application, ii) the AESO s regulatory proceedings and iii) intervener cost recovery for AESO applications all of which can be challenging to estimate in advance of a budget year. $ Millions 10 5 As of September, regulatory process costs are $0.5 million or 63 per cent higher than budget due mainly to: objections and complaints to ISO Rules - the transmission constraint management (TCM), available transfer capabilities (ATC) and transmission loss factor methodology and requirements proceedings and proceedings related to Need Identification Documents (NIDs). 0 YTD Actual YTD Budget WECC/NWPP Costs Regulatory Process Costs AUC Fees Energy Market AUC Fees Transmission AESO 2014 Business Plan and Budget Proposal Page 35
General and Administrative Costs The following table provides the general and administrative costs as of September 2013 compared to the budget. Year-to-Date September 2013 General and Administrative Costs ($ million) YTD Sept Actual YTD Sept Budget YTD Sept Variance 2013 Projection 2013 Budget Staff Costs 45.0 45.8 (0.9) 61.1 61.1 Contract Services and Consultants 8.9 11.3 (2.4) 13.1 15.0 Administration 3.5 4.5 (1.0) 5.1 5.9 Facilities 5.3 4.9 0.4 6.6 6.5 Computer Services and Maintenance 6.7 6.2 0.4 8.7 8.3 Telecommunications 1.3 1.1 0.2 1.6 1.4 General and Administrative Costs 1 70.5 73.7 (3.2) 96.2 98.3 Market Systems Replacement Project 1 0.6 0.6 0.0 1.0 1.0 Differences are due to rounding. Staff Costs The AESO maintains market-based compensation for staff which incorporates a benefits plan and a performance based incentive. It is anticipated that staff costs will be at or slightly below budget in 2013 due to lower than budgeted average per person salary costs offset by a lower than budgeted vacancy rate throughout the year. To ensure that the AESO s business initiatives continue to advance and are not impacted by high vacancy rates associated with the tight labor market for both electric industry professionals and general staff, the AESO s recruitment strategy is to target an actual vacancy rate close to zero per cent. Contract Services and Consultants By the end of September, costs related to contract services and Telecommunications consultants are 21 per cent lower than budget mainly due to Computer Services and Maint several studies supporting AESO planning for the bulk Facilities transmission system, customer connections or issue-specific Administration initiatives being deferred or determined to no longer be required. Contract Services & Consultants In 2013, an emphasis was placed on updating regional studies Staff Costs that will support future transmission needs for customer connections. In addition, the scope of the AESO s work related to transmission cost monitoring was reduced and fewer costs were incurred. $ Millions 80 60 40 20 0 YTD Actual YTD Budget AESO 2014 Business Plan and Budget Proposal Page 36
Administration Administration costs include corporate communications, recruiting, travel and training, AESO Board fees and office costs that present the general operating costs of the organization. Based on current estimates, it is anticipated that actual costs in 2013 will be approximately $0.8 million or 14 per cent lower than budget due to the reduction in the number of system projects requiring stakeholder consultation and lower publication costs. Facilities Facility costs include rent and operating costs for three AESO locations. The facility costs in 2013 are anticipated to be consistent with the 2013 budget. Computer Services and Maintenance Ongoing costs are incurred to purchase annual software operating licences and maintenance agreements for the AESO s systems. Based on current estimates, it is anticipated that actual costs for computer services and maintenance in 2013 will be approximately $0.4 million or five per cent higher than budget due to additional maintenance agreements. Telecommunications The AESO incurs costs for network systems and telecommunications to support general business operations and, to a much larger extent, to support real-time operations. Based on current estimates, it is anticipated that actual costs for telecommunications in 2013 will be approximately $0.2 million or 14 per cent higher than budget due to one-time installation costs associated with the relocation of the AESO s Backup Coordination Centre and for duplication of services required during the relocation process. Market Systems Replacement Project The Market Systems Replacement project received AESO Board approval for Phase 1 project funding of $1.0 million in April 2013. This project will be managed in three distinct phases. Further details on the MSR project are provided in Section II 2014 under the Market Systems Replacement Cost section. The Phase 1 costs are anticipated to be consistent with the 2013 budget. AESO 2014 Business Plan and Budget Proposal Page 37
Interest and Amortization Costs The following table provides the interest and amortization costs as of September 2013 compared to the budget. Year-to-Date September 2013 Costs ($ million) YTD Sept Actual YTD Sept Budget YTD Sept Variance 2013 Projection 2013 Budget Interest 0.8 1.0 (0.1) 1.0 1.3 Amortization of Intangible and Capital Assets Differences are due to rounding. 18.5 17.5 1.0 25.0 23.3 Interest 20 Actual interest costs are lower than budgeted for 2013 due to lower borrowing requirements and lower interest rates. The lower borrowing requirements are the result of the deferral account balances averaging to a net payable balance year-to-date combined with generating unit owner s contribution deposits averaging $55 million from January to September 2013, compared to the budgeted $45 million. Both the deferral account balances and the generating unit owner s contribution deposits are used to offset borrowing requirements for working capital and intangible and capital asset purchases. $ Millions 15 10 5 0 YTD Actual YTD Budget Amortization Amortization Interest A number of variables are taken into consideration in developing the annual amortization budget. These variables include the asset addition types (impacting the estimated useful life), the purchase amount and the timing (commissioning date) of asset additions. Based on current estimates, it is anticipated that the actual amortization for 2013 will be $25.0 million, which is $1.7 million or seven per cent higher than budget. This increase is due to higher than estimated amortization on 2012 additions in 2013. AESO 2014 Business Plan and Budget Proposal Page 38
Capital Expenditures The AESO has three main asset categories: people, technology and processes. While investment occurs in all three areas, only the technology assets (computer systems and System Coordination Centre) are the focus for capital expenditures. The development and acquisition of capital assets is a major budget component given the AESO s significant reliance on IT infrastructure and applications for business operations. As with all IT-intensive organizations, the challenge is to find the right balance between implementing technology advancements, determining the level of IT development that can be supported by business operations and then establishing the funding requirements to make it all happen. To address these challenges, a vetting and prioritization process has been implemented and continues to be enhanced to ensure capital expenditures achieve the most beneficial and cost-effective results to continue to meet operating requirements. This is referred to as the portfolio management process. Throughout the year, capital projects are reviewed on an ongoing basis to assess progress and budget spending and identify unanticipated issues. Any new or modified requirements are also reviewed and prioritized to determine how they align with existing work. This is a continual process to ensure alignment of priorities and business needs. The estimated capital expenditures in 2013 are $22.1 million which is $4.9 million or 18 per cent lower than the capital budget of $27.0 million. Additional information on capital projects is provided in Appendix D. AESO 2014 Business Plan and Budget Proposal Page 39
Capital Expenditures ($ million) Key Capital Initiatives 2013 YTD Sept Actual Oct to Dec Estimated Expenditures 2013 Projection 1. Energy Management System 7 0.6 0.2 0.8 2. Wind Integration 0.0 0.0 0.0 3. FEOC 9 Regulation Implementation 0.2 0.0 0.2 4. Transmission Constraint Management 1.2 0.9 2.0 5. Demand Response 0.2 0.2 0.4 6. Intertie Framework 1.8 0.5 2.3 7. Information Management Platform 0.5 0.1 0.6 8. Dropchute Replacement 0.0 0.0 0.0 9. BUCC 11 Replacement 2.2 0.3 2.5 Total Key Capital Initiatives 6.8 2.1 8.9 Other Capital Initiatives 5.5 2.2 7.6 Life Cycle Funding 3.2 2.3 5.5 Total Capital Spending 15.5 6.6 22.1 Differences are due to rounding. Key Capital Initiatives represent the most critical capital projects over the planning period that must be completed within the identified timeframe. Other Capital Initiatives are also necessary projects; however, there is more flexibility in planning or delivery so timing is not as critical as the Key Capital Initiatives. Life Cycle Initiatives are typically leasehold improvements, replacement of end-of-life IT hardware and recurring software upgrades. Additional detailed information on capital projects is provided in Appendix D. AESO 2014 Business Plan and Budget Proposal Page 40
Appendix B: Transmission Operating Cost Definitions 2014 Pool Price Forecast Methodology The AESO has prepared its 2014 pool price forecast using the AURORAxmp Power Market Model, which reflects the Alberta market fundamentals. The most up-to-date information available on future supply, demand and market fundamentals, as well as random variables including forced outages, weather-related demand fluctuations and gas prices are used to generate price volatility in the forecast. However, many planned outages can change in duration and timing throughout the year and this will impact the hourly pool price in ways that the AESO cannot predict. The AESO has run 1001 simulations of the hourly pool price forecast, producing price distributions that reflect the volatility seen in the Alberta market. The AESO has selected the results from the 95 th percentile of the 1001 simulations as the 2014 pool price forecast. The average hourly pool price forecast for 2014 of $48 per MWh is $12 per MWh or 20 per cent less than the 2013 average hourly pool price forecast of $60 per MWh, which was derived using the same model and methodology. This decrease in pool price forecast is primarily due to increases in available generation capacity in 2014, including the return of several generating units (representing close to 1000 MW of baseload generation) that incurred long-term outages in 2013. The 2014 average hourly pool price forecast is used as an input to calculate the transmission line losses and ancillary services costs forecasts. Transmission Line Losses Transmission line losses represent the amount of energy that is lost as a result of electrical resistance on the transmission lines. Volumes associated with line losses are determined through the energy market settlement as the difference between generation and import volumes less consumption and export volumes. The hourly volumes of line losses vary based on load and export levels, generation (baseload, peaking units and import) available to serve load, weather conditions and changes in the transmission topology. System maintenance schedules, unexpected failures, dispatch decisions on the Alberta Interconnected Electric System (AIES), and short-term system measures (such as demand response) may also affect the volume of losses. The annual volume forecast for transmission line losses is based on the hourly forecasted losses volumes, which are calculated based on the following: Historical actual losses volumes from the AESO s settlement system, incorporating post-final restated metering data; and A forecasting model using the historical data. The annual forecast for transmission line losses costs is the accumulation of the hourly forecasted losses volumes multiplied by the hourly forecasted pool prices. As such, the transmission line losses costs are highly correlated with the pool price forecast. For 2014, the AESO has applied the 95 th percentile of the 1001 simulations of the hourly pool price forecast, as discussed above, to the forecasted transmission line losses volumes to create a projected cost curve for the transmission line losses cost forecast. Ancillary Services Ancillary services are procured by the AESO to ensure reliability of the transmission system. Ancillary services are procured through various methods including a daily competitive exchange for operating reserves, which includes generation capacity and load reduction capabilities, and competitive processes that result in contracts for other ancillary services such as transmission must-run (TMR), load shed service for imports (LSSi) and system restoration services. AESO 2014 Business Plan and Budget Proposal Page 41
Operating Reserves Operating reserves are generating capacity or load that is held in reserve and made available to the System Controller to manage the transmission system supply-demand balance in real time. Operating reserves are procured through an online exchange, where offer prices are indexed to the pool price. In exchange for this payment, the AESO obtains the right to utilize the provider s energy and/or capacity as reserves. Over-the-counter contracts are used only as a back-up to procure operating reserves in the absence of the availability of the online exchange. All providers who sell volumes over-the-counter are paid their offer price. While the prices of operating reserves procured through the online exchange are indexed to the hourly pool price, changes to the average pool price do not result in proportional changes to the operating reserve costs; the pool price for each hour has a significant impact on the operating reserve costs for that hour. Additionally, during periods of high hourly pool prices, the less expensive operating reserve suppliers may not be available which results in higher operating reserve costs. The AESO procures the different types of operating reserves in two forms: active and standby. Active operating reserves are the operating reserves that are forecast by the AESO as necessary to operate the AIES securely and meet the AESO s reliability obligations. Standby operating reserves provide additional reserves for use when the resources available under the active portfolio are insufficient. Payments for standby reserves include a premium for the option to activate the standby reserves and an activation price that is paid if the reserves are activated. Operating reserves are comprised of three types of active reserves, with the minimum levels of operating reserves required based on standards established by the Western Electricity Coordinating Council (WECC): Regulating reserves The amount of generation capacity, energy and maneuverability responsive to the AESO s automatic generation control (AGC) system that is sufficient to provide normal regulating margin. In Alberta, regulating reserves track variations in the load that cannot be met with energy dispatches. The volumes of regulating reserve are specified as a range in megawatts over which a level of control is required by the AGC system. Spinning and supplemental reserves are used to replace supply following an unexpected loss of generation in Alberta or in the WECC region. Alberta must comply with WECC policies for maintaining specific volumes of spinning and supplemental reserves in order to maintain reliability. - Spinning reserves Unloaded generation that is synchronized to the system, automatically responsive to frequency deviation and ready to serve additional energy following an AESO System Controller directive. A customer offering spinning reserves must be able to ramp up its generator within 10 minutes in response to a System Controller directive. - Supplemental reserves While similar to spinning reserves, supplemental reserves are not required to respond to frequency deviations. They include unloaded generation, off-line generation or system load that is ready to serve additional energy (generator), or reduce energy (load), within 10 minutes of a directive from the System Controller. The annual forecast for operating reserves costs is based on the forecasted annual operating reserves volumes (governed by WECC requirements), the distribution curve for the forecasted pool price and historical premiums/discounts. The hourly premium/discount estimates are derived from a rolling window of 24 months of historical data. A probabilistic analysis using 1001 simulations is then performed on the input parameters to establish monthly and annual cost curve projections. For 2014, the AESO has used the summation of the 95 th percentile of the monthly cost forecasts to establish the annual operating AESO 2014 Business Plan and Budget Proposal Page 42
reserves cost forecast. This methodology allows the AESO to better capture monthly and seasonal volatilities. Transmission Must-Run (TMR) TMR is generation required to be on-line and operating to ensure reliability in specific areas of the AIES with insufficient transmission capacity. This service is typically procured through commercial contracts involving fixed and variable payment components. A market participant may be directed to provide unforeseeable TMR service when the provider does not have an existing contract for the service. In these circumstances, the ISO Tariff specifies the method to calculate the amount to be paid to the provider. Other Ancillary Services Other ancillary services that the AESO procures for the secure and reliable operation of the AIES include LSSi, black start and services provided by Poplar Hill generator. These services are procured through bilateral contracts with suppliers using competitive procurement processes whenever possible. The Poplar Hill generator provides voltage support (VArs) in addition to power (MW), to support the transmission system reliability in the Northwest part of the province. As such, the associated costs are included in Other Ancillary Services. AESO 2014 Business Plan and Budget Proposal Page 43
Appendix C: 2014 General and Administrative Cost Detail Human Resources Human Resources ($ million) 2014 Budget 2013 Projection 2013 Budget 2012 Actual 2011 Actual Staff 61.8 61.1 61.1 57.9 52.5 Consulting 11.5 11.5 13.8 13.9 15.4 Legal 1.0 1.3 0.9 1.2 2.3 Audit/Reviews 0.2 0.3 0.3 0.2 0.2 Human Resources 74.5 74.2 76.1 73.3 70.5 Differences are due to rounding. Staff Costs These costs are based on several key budget variables or factors: Base pay adjustments for existing staff or an overall change in the AESO s compensation philosophy While the compensation philosophy will remain unchanged in 2014, the AESO has incorporated a three and a half per cent base pay adjustment for general salaries. This adjustment percentage is the result of current economic indicators (such as the Consumer Price Index and salaries surveys). Near the end of the year, management will recommend a final base salary adjustment to the AESO Board s Human Resources, Compensation and Nominations Committee for final approval. Short-term (annual) incentive plan The AESO s short-term incentive plan is based on an assessment of corporate and individual performance, as aligned to corporate goals. In preparing the budget, the AESO has confidence in its approach to successfully deliver on its goals and has reflected this in its incentive compensation at 60 per cent of eligibility. In addition, and similar to the last two years, incentive amounts also include a segmented approach for a select number of critical roles to provide for staff retention to enable delivery on critical projects and work. Vacancy rate Due to staff attrition trends and the time to hire, a number of positions may remain vacant for a period of time. The AESO has included an eight per cent vacancy rate in 2014 which is consistent with the 2013 budget. To ensure that the AESO s business initiatives continue to advance and are not impacted by high vacancy rates associated with the tight labor market for both electric industry professionals and general staff, the AESO s recruitment strategy is to target an actual vacancy rate close to zero per cent. The AESO anticipates a six per cent vacancy rate in 2013. Benefit costs In addition to their salary, each employee participates in the organization s comprehensive benefit plan. For the organization, this represents costs such as health and dental coverage, defined contributions for retirement savings and government payroll costs. These costs are presented as a percentage of salary costs to determine the benefits load factor which has been budgeted at 22 per cent of salary costs in 2014 which is consistent with the 2013 budget. AESO 2014 Business Plan and Budget Proposal Page 44
Consulting The AESO uses consultants to supplement staff resources for three general purposes. It is not practical to retain staff that have all the skill sets that may be required from time to time. In these circumstances, consultants are utilized to either complete the work or assist in training AESO staff. Consultants are also used to address workload peaks to maintain seamless operations and continual progression on key initiatives. And finally, support services for IT infrastructure are consolidated or cosourced to facilitate more coordinated and reliable service support. Legal Legal counsel is retained to support general business operations by supplementing in-house legal resources and to provide expertise on legal matters such as regulatory filings. Starting in 2012, costs associated with the AESO s involvement in an AUC proceeding to hear objections and complaints to ISO Rules or any regulatory application are included in the cost category regulatory process costs as opposed to the general and administrative cost category. This change in process explains the changes in costs in comparing 2011 actual costs to subsequent years. Audit/Review To conduct audits or reviews on AESO processes, systems or reporting, the professional services of others will be used to assist in these initiatives. Administration Administration Costs ($ million) 2014 Budget 2013 Projection 2013 Budget 2012 Actual 2011 Actual AESO Board Fees 0.6 0.6 0.6 0.5 0.6 Travel and Training 1.8 1.8 1.8 2.0 2.1 Insurance 0.6 0.6 0.6 0.5 0.5 Other Administrative 2.5 2.1 3.0 3.2 3.9 Administration 5.4 5.1 6.0 6.3 7.0 Differences are due to rounding. AESO Board Member Fees The AESO is governed by the AESO Board whose members are appointed by the Alberta Minister of Energy. While the number of Board members can vary from time to time, there can be no more than nine members with their compensation based on a retainer fee and additional fees based on their Board committee involvement and time spent on corporate matters. Travel and Training The travel and training category covers costs incurred for general business travel, staff training and associated travel, corporate meetings and related meals. In addition, costs related to stakeholder consultation and open houses for proposed transmission projects and public communication and education are included in this category. Insurance The EUA provides limited statutory protection for the business risks of the AESO organization, directors, officers and staff. To ensure business risks are properly insured, the AESO carries insurance for exposures not covered by the EUA, specifically for direct damages resulting from negligence. The AESO has statutory protection for indirect damages, which would typically be the most costly damages that would occur for business interruption and lost revenue. Other Administrative Costs This includes corporate relations, general office costs, printing, recruiting, corporate subscriptions/memberships and professional membership fees. The 2014 budget is $0.5 million lower than the 2013 budget related to a change in the recruitment strategy that occurred in 2013 and nonrecurring move costs associated with the relocation to the new AESO Backup Coordination Centre. AESO 2014 Business Plan and Budget Proposal Page 45
Facilities Facilities Costs ($ million) 2014 Budget 2013 Projection 2013 Budget 2012 Actual 2011 Actual Rent 6.3 6.6 6.5 5.7 4.7 Facility costs are associated with three office locations: i) the main offices in downtown Calgary which are leased through long-term lease arrangements, ii) the System Coordination Centre which is owned and operated by the AESO, and iii) additional space for the AESO s Backup Coordination Centre to accommodate redundant computer systems to support seamless operating performance in the event of a disruption to the operations at the System Coordination Centre. To accommodate staff and contract resources in the main offices, 105,000 square feet of office space is currently leased through agreements that will expire in 2024. During 2013, the AESO began occupying a new Backup Coordination Centre that is leased from another electric industry organization. This new Backup Coordination Centre incorporates the infrastructure needs of the AESO into the construction design of the larger facility construction project. The AESO s facility costs will be significantly lower under this new 20-year lease in comparison to the previous Backup Coordination Centre lease. In the 2014 budget, the cost savings associated with the relocation of the Backup Coordination Centre are offset by higher operating costs related to the downtown office space. Computer Services and Maintenance Computer Services and Maintenance ($ million) 2014 Budget 2013 Projection 2013 Budget 2012 Actual 2011 Actual IT Maintenance and Services 8.3 8.7 8.3 7.6 4.9 As the AESO continues to invest in IT infrastructure to support its business operations, ongoing costs are incurred to purchase annual software and hardware operating licences and maintenance agreements for these systems with high availability requirements that are supported by premium class maintenance and support agreements. The AESO operates with a managed services model 12 for IT infrastructure operating support (network, server and database). The software and hardware operating licences and maintenance agreements for the systems are a combination of core base infrastructure system and applications that change as new projects are approved. In 2014, the costs for IT maintenance and services are anticipated to be consistent with the 2013 budget with no additional growth. Any additional requirements are either funded from new negotiated agreement or the retirement of obsolete licences or agreements. 12 A managed service model is where the AESO transfers the day-to-day management and operations of a support function (not the strategic management) to a third party provider. With this new support approach the AESO would be able to leverage available technical resources and tools to provide more effective support for its critical processes. The managed services approach will facilitate resource efficiencies and improve reliability. AESO 2014 Business Plan and Budget Proposal Page 46
Telecommunications Telecommunication ($ million) 2014 Budget 2013 Projection 2013 Budget 2012 Actual 2011 Actual Telecommunications 1.4 1.6 1.4 1.5 1.4 The AESO incurs costs for network systems and telecommunications to support general business operations and, to a much larger extent, to support real-time operations. The strategy for developing and maintaining the telecommunication infrastructure is based upon the requirement for high availability, which necessitates redundancies of services and equipment. AESO 2014 Business Plan and Budget Proposal Page 47
Appendix D: Capital Projects The following tables provide information on the AESO s current capital plan for 2014. Actual projects to be completed in 2014 will vary, and include the addition of projects yet to be determined, deferral of projects in this plan or elimination of projects deemed no longer necessary. Key Capital Initiatives These are the most critical capital projects over the planning period that the AESO believes must be completed within the identified timeframe. Reliability Program - EMS (Energy Management System) Components Reliability Program (Other components) Key Capital Initiatives Description The next phase of the EMS program in support of current operational requirements and upgrades required to ensure the successful integration of High Voltage Direct Current (HVDC). The planned upgrades are intended to support HVDC commissioning, monitoring, analysis and operation. 2013 Progress Major investment activities were deferred while AESO management completed a review of its EMS strategy. During this period EMS upgrades were limited to the enhancement of the System Controller operating environment. Management has since completed and confirmed its EMS investment strategy, which is to utilize the existing software base and implement functional upgrades as required. 2014 Plan Implementation of software upgrades that integrate specific Network Applications and Dispatch Training Simulation features in support of HVDC operations. This work includes replacement of end of life equipment associated with the network and server infrastructure, commissioning of software upgrades and System Controller training. Description System projects that are intended to enhance the efficiency and improve the ability to operate the AIES systems. 2013 Progress Completed HVDC engineering studies which identified the need to monitor system stability during the HVDC ramping activities and enhance outage reporting information during commissioning periods. 2014 Plan A number of system developments have been identified to support HVDC commissioning activities and ongoing operations. These include: the expansion of the outage planning software to correct existing business processes with System Controller Procedures and outage coordination, the development and deployment of specific Critical Infrastructure Protection (CIP) standards and the implementation of the PhasorPoint software to provide System Controllers the ability to observe system stability conditions in real time and run studies for various HVDC loading scenarios to find the appropriate loading levels to facilitate grid reliability. AESO 2014 Business Plan and Budget Proposal Page 48
Wind Integration Market Evolution Demand Response Intertie Development Key Capital Initiatives Description Develop and deploy tools, market rules and products that assist with the integration of additional wind power facilities to the AIES. 2013 Progress Completed the wind power forecast integration project, which integrates wind power forecast information into AESO systems and extends the wind power forecasting capabilities available to the AESO s System Controllers. Published Phase 2 Wind Integration Recommendation Paper incorporating lessons learned during the Wind Dispatch Pilot. An implementation plan for wind participation in the merit order has been developed based on this information. 2014 Plan Continue with the development and implementation of tools and appropriate rule changes to support long-term wind integration requirements as contained in the Phase 2 Wind Integration Recommendation Paper. This includes tools that support wind participation in the merit order. Description The identification, development and implementation of tools in support of market optimization and/or performance improvements. This includes the ongoing review (assessment and consultation) of the market design and its structural elements in consideration with the potential Market Systems Replacement (MSR) project. 2013 Progress Monitor, assess and consult on the Transmission Constraint Management (TCM) requirements. 2014 Plan Initiate development of a TCM systems changes and a new TCM metrics reporting tool. Description Implement tools to facilitate demand side participation in the market and remove barriers to the degree possible. 2013 Progress The advancement of 2013 plans was postponed pending the FERC decision regarding BAL-002-WECC. The approval of the standard has been received and the project has been restarted. 2014 Plan Develop and implement system changes to enable non-generating resources such as load to provide spinning and regulating reserve. Description Develop and implement a framework and tools that support increased transfer capacity with neighbouring jurisdictions. This includes but is not limited to restoring existing intertie capacity, support for merchant transmission additions and implementation of dynamic scheduling solutions. 2013 Progress Completed system and procedural changes supporting the integration of Montana Alberta Tie Line (MATL). Implemented ISO Rule 203.6 Available Transfer Capability and Transfer Path Management. Implemented IT system changes that enable ISO use of the WECC Dynamic Scheduling System. Evaluated dynamic scheduling software solution to assess the opportunity to use the tool to support the use of regulating reserve across interties. 2014 Plan Complete and implement the results from updated operating horizon limit studies in AESO systems. Complete joint AESO / BC Hydro planning horizon study and initiate appropriate next steps AESO 2014 Business Plan and Budget Proposal Page 49
Key Capital Initiatives Operating Reserve Cost Accountability ISO Tariff Application 2014 based on the results. Complete the implementation of the dispatchable interties project. Description Design, develop and implement AESO systems that allow for ancillary services market changes to accommodate harmonization and convergence with interjurisdictional reliability standards. 2013 Progress The advancement of 2013 plans was postponed pending the FERC decision regarding BAL-002-WECC. The approval of the standard has been received and the project has been restarted. 2014 Plans Implement system changes required to support a new Alberta Reliability Standard reflecting the WECC Reliability Standard BAL- 002-WECC with related changes to EMS so that the System Controller can operate to the new standard. Validate Compliance reporting requirements for the NWPP to ensure the AESO is reporting the contingency reserve change correctly. Description Develop transmission cost benchmarking competency and a database to assist in the assessment of reasonableness of the costs. The AESO would use the benchmarking data to test cost estimates proposed by transmission facility owners in the need identification document phase and proposal to provide services stages. 2013 Progress The AESO has created a benchmarking database using cost estimate data from Alberta transmission projects over the 2005 to 2012 time period. This benchmarking data is now available on the AESO website. The database is currently hosted on a public server (tableausoftware.com). The AESO is in the process of migrating the database and application in-house. 2014 Plans Define and develop enhancements to the benchmarking application intended to enhance the efficiency of data management and reporting. Description Develop and implement changes to the transmission billing system that support the 2014 ISO Tariff application rate and calculation structure. 2013 Progress New initiative 2014 Plan Progress system changes in support of the 2014 tariff rate and calculation structure. AESO 2014 Business Plan and Budget Proposal Page 50
Other Capital Initiatives ($ million) These are necessary projects that have more flexibility in planning or delivery so timing is not as critical as the Key Capital Initiatives. Other Capital Initiatives Information Management Tools Human Resources Management Tool Cyber Security Upgrades Loss Factor Compliance Secure Portal Description Expansion of the AESO s information/records management program to include policy, retention and governance revisions to support automated archiving and deletion practices. This includes the implementation of software and infrastructure to support the expanded governance model. Implementation of commercial software that supports the AESO s HR talent management processes (e.g. talent acquisition, compensation planning, learning and development, performance planning and review, and succession planning.) A multi-year program supporting the implementation of the information technology component of NERC s Critical Infrastructure Protection (CIP) v5 standard. Initial emphasis will be the identification of CIP requirements that need to be incorporated into the Alberta Rules. Modify system HVDC logic into the associated forecasting algorithms. An electronic information portal for market participants, AESO, and MSA to manage compliance evidence and information regarding market participant compliance to ISO Rules, AUC Rule 21, and Alberta Reliability Standards. 2014 Capital Budget Total 0.9 System Enhancement Ongoing high priority minor enhancements to production 2.5 Program applications. Miscellaneous Other projects not exceeding $0.25 million. 0.4 Other Capital Initiatives 5.3 0.7 0.3 0.3 0.2 Differences are due to rounding. AESO 2014 Business Plan and Budget Proposal Page 51
Life Cycle Initiatives ($ million) These are typically replacement of end-of-life hardware and recurring software upgrades. Life Cycle Initiatives Server Upgrades Storage Upgrade Enterprise Services Monitoring Solutions Security/IT Network Upgrades Non Project Capital Leasehold Improvements Description Retire and replace corporate server hardware/software based on a pre-determined corporate retirement plan. Priority replacements include EMS and critical database servers and servers within the development environment. Implement selected storage infrastructure upgrades to address existing end-of-life cycle considerations, support the high-performance storage requirements of on-line market participants systems and increase the reliability / availability of critical data systems between AESO s data centres. Upgrades to the AESO inter-application messaging platform to ensure consistent and accurate data is exchanged. Upgrade and integration of disparate monitoring solutions to a single console for a more holistic view of infrastructure and application performance. Upgrade vulnerability scanner, add additional capacity to spam filters to meet increasing and changing volumes of spam as well as increasing our Identity and Access Management capabilities. Upgrade AESO voice and data networks to ensure vendor support, meet reliability requirements and address increased capacity needs. This includes data switches, remote access capabilities, and redundancy of critical network services. Ongoing investment in desktop systems, services and mobile devices to replace aging software and equipment and accommodate resource growth (e.g. data storage). Office furniture purchase, replacement and other leasehold improvements. 2014 Capital Budget Total 1.2 Life Cycle Initiatives 6.2 1.1 0.8 0.7 0.5 0.4 1.4 0.2 Differences are due to rounding. AESO 2014 Business Plan and Budget Proposal Page 52
Appendix E: Market Systems Replacement MSR Project Overview Description Reliable operation of the wholesale electricity market and timely evolution of the market both require reliable and flexible AESO market systems. The AESO s market systems have endured a significant amount of change and growth over the past several years including enablement of the DDS (Dispatch Down Service) market, wind management, LSSi (Load-Shed Service for Imports), congestion management, supply surplus, multiple intertie projects and others. Many systems have been stretched past their useful life and in many cases, have become increasingly difficult and costly to change and operate reliably. Market evolution is expected to continue with changes resulting from continued advancement of the intertie program, alignment of dispatch and settlement periods, enhanced market metrics reporting, etc. The current state of the AESO s market systems poses a risk to the reliability of market operations and to the AESO s ability to evolve the market in a timely manner. These risks increase with time as the market system technology becomes increasingly obsolete and the systems become more complex as a result of additional market change. While the AESO has taken actions over the past two years to temporarily extend the life of our existing market systems, it would be prudent to begin addressing the long term lifecycle replacement needs of these systems. Scope of the Market Systems Project Approach This project has the following objectives: Improving and sustaining the reliability of existing market system functions Positioning our market systems to accept future changes (i.e. enable timely market evolution) Multiple interrelated market systems are in scope for this project. This includes the AESO s Energy Trading System (ETS), Ancillary Services Procurement system (ASP), Dispatch Tool (DT), settlement systems and other market related tools. The market components of the Energy Management System (EMS) are also included. The project is expected to be executed in three phases: Phase 1 - Validation This phase includes project definition, understanding long-term business requirements, business process analysis, high-level solution option analysis, narrowing the list of potential implementation partners, business case development and implementation planning. This phase will result in a better understanding of the risks and assist in the initial development of estimates (timing and costs) for Phases 2 and 3. The validation phase could result in a decision not to proceed. No Phase 2 or Phase 3 commitments will be made during Phase 1. This phase will also identify potential quick wins. These are AESO 2014 Business Plan and Budget Proposal Page 53
MSR Project Overview recommendations that could be implemented as part of initiatives outside of this project and would result in improvements to existing AESO operations. For example, the business process documentation is expected to be of immediate value to current operations and other in-flight projects. The project team will consist of a combination of AESO employees with core business knowledge and external consultants with expertise in subject matters not unique to AESO. The project will be led by an internal resource reporting to a steering committee. The validation phase is divided into four stages: Project Definition Create the charter, engage internal and external stakeholders, create project plans, build the team, engage external resources to assist in validation, and perform other project kickoff activities. Business Requirements & Process Work with internal subject matter experts from various AESO departments including Market Services, Operations and IT, as well as all interested market participants to define long-term business requirements (10+ years) and document business processes. The outcome of this stage is essential for a successful RFP (Requests For Proposal) in Phase 2 and will also add immediate value to existing operations in the form of quick wins (e.g. business processes improvements). Option Analysis Research the potential options to meet the business requirements. Narrow the options down to those that are most feasible (technical and costs). Existing systems will be assessed for potential reuse of components. This phase will also include issuing vendor RFIs (Request For Information) and narrowing down of potential partners that will be issued RFP(s) in Phase 2 by the AESO. Business Case & Implementation Plan Develop the business case including pros and cons of replacing or reengineering the AESO s market systems, develop capital cost estimates, develop an initial implementation plan and develop preliminary RFP information. Phase 2 - RFP Assuming a decision to proceed is received in Phase 1, the AESO plans to issue one or more RFPs to potential implementation partners, evaluate the responses and select the partner(s). This phase is scheduled for 2014. The outcome of the validation phase may change the timing and scope of Phase 2 substantially. Phase 3 Implementation The implementation phase includes the bulk of the execution effort to design, build, configure, test and transition to an appropriately upgraded set of market systems and retire the existing ones. The timing and budget requirements for this phase are largely unknown at this point and will be better substantiated after Phases 1 and 2 are complete. The following high level estimates provide an order of magnitude sense of what this phase might look like: Timing: 2-3 years in duration. Cost: In the range of approx. $30-40 million. Phase 3 estimates were arrived at by examining project timing and costs AESO 2014 Business Plan and Budget Proposal Page 54
MSR Project Overview incurred by ISOs in other jurisdictions and comparing their market structures with that of Alberta. It is important to note that the actual timing and costs could be substantially different from those estimates provided. AESO 2014 Business Plan and Budget Proposal Page 55
Appendix F: Allocation of Costs Management reviews allocation percentages twice a year. They are first reviewed when the annual budget is prepared and again at year end when the allocations are finalized based upon actual activities and costs for each department. Cost Type Direct Operating Shared Services Corporate Services 13 Shared Services Information Technology Shared Services Office Leases Allocation Methodology Individual Department Review / Analysis for Current Year Work Focus Based on Allocation of Direct Operating Group Costs Activity-Based Analysis on System and People Costs Based on AESO Staff Count Capital Assigned on a Project-by-Project Basis Other Industry Costs Fees and Memberships Other Industry Costs Regulatory Process Costs Based on Related Function Individual Review/Assessment for Each Proceeding 13 Corporate Services includes departments such as: Accounting, Settlement & Risk, Human Resources, Corporate Communications, Legal, etc. AESO 2014 Business Plan and Budget Proposal Page 56
Section 5 Stakeholder Comments and AESO Responses
Throughout the current year Budget Review Process (BRP), we held meetings with stakeholders to discuss our business plan and budget materials and provided stakeholders with an opportunity to provide comments on this information. The following table lists those that participated in the current year BRP and the meeting dates they attended. Stakeholders in the Budget Review Process Sept 18 Oct 10 Oct 16 Alberta Direct Connects (ADC) Attendance ATCO Electric Attendance ATCO Power Attendance Industrial Power Consumers Association of Alberta (IPCAA) Attendance Office of the Utilities Consumer Advocate (UCA) Attendance Capital Power Corp. Attendance AltaLink Attendance BP Attendance TransAlta Corporation Attendance ENMAX Corporation Attendance ENERNOC Attendance Dow Chemical Canada Attendance AESO 2014 Business Plan and Budget Proposal Page 1 Section 5 - Stakeholder Comments and AESO Responses
The following table identifies the key BRP dates in 2013. Key BRP Dates in 2013 July 29 September 18 October 10 (Calgary) October 16 (Edmonton) November 14 Purpose Notice to stakeholders A notice was distributed to stakeholders regarding the initiation of the 2013 BRP (i.e., stakeholder consultation process), an overview of the process steps, terms of reference, and proposed process schedule. First stakeholder meeting Stakeholder meeting to discuss the 2014 business initiatives. First technical meeting - Stakeholder meeting to review the 2014 own costs budgets (general & administrative, interest, amortization, capital and other industry costs) and for transmission line losses and ancillary services costs. Second technical meeting - Stakeholder meeting to review the 2014 own costs budgets (general & administrative, interest, amortization, capital and other industry costs) and for transmission line losses and ancillary services costs Stakeholder and AESO Board meetings (as required). Following stakeholder meetings and/or the posting of BRP information on the AESO website, we asked stakeholders for their questions and comments. Stakeholder comments and AESO responses to those comments are enclosed. AESO 2014 Business Plan and Budget Proposal Page 2 Section 5 - Stakeholder Comments and AESO Responses
Stakeholder Comments and AESO Replies Matrix AESO Consultation 2014 Budget Review Process: Meeting September 18, 2013 - AESO s Draft Business Initiatives for 2014 The AESO is asking market participants and interested parties to comment on the 2014 draft Business Initiatives presentation given at the Budget Review Process (BRP) stakeholder review meeting September 18, 2013. Draft Business Initiatives for 2014 September 18, 2013 meeting Do stakeholders have any comments on the AESO s Business Initiatives proposed for 2014? Stakeholder Stakeholder Comment AESO Replies Alberta Direct Connect (ADC) 1. Market Development: ADC encourages the AESO to continue work in the area of Demand Response. 2. One area that could be improved is a real time indicator of the peak DTS load. 3. The AESO committed to studying the ALR (Alberta Load Response) and AIL (Alberta Interconnected Load) history and produce an information document on how the ALR is determined. Comment 1. The AESO will continue to focus on removing barriers and encouraging load participation in the market. This includes changes to expand loads participation in the Operating Reserve (OR) market. As well as the implementation of changes from the LSSi review currently being undertaken by the AESO. Comment 2. Noted. AESO management will include this item as one of the Market System Replacement requirements for consideration. Comment 3. Noted. This item is included in the AESO s work plans. A scheduling update will be provided once it becomes available. AESO Stakeholder Comment and AESO Replies Matrix 1
4. Electric System Development: The ADC appreciates the AESO s efforts in providing the transmission rate impact model. As many change orders are anticipated for system projects, the ADC asks that the AESO update the model on a biannual basis. Comment 4. The AESO has assessed the impact of changes to transmission projects on its rate impact projection over the last two years and found the impact to be small. The AESO plans to update the rate impact projection when long-term transmission plans are filed, which are every two years. The AESO notes that its next long-term transmission plan will be filed later this year and the impact on the rate impact projection will be re-assessed at that time. 5. Customer Access Service: Our observations of improvements that could reduce cycle time include: a. Errors in Data files members have faced additional cost and delays due to errors in idev files for doing system studies. b. Behind the Fence Generation process members have faced delays in projects because of unclear requirements for protection and control and not sufficiently addressing these requirements early on in the project cycle. Comment 5 (a. and b.). The AESO is committed to working with industry to enhance system modeling information included in data files and identifying protection and control requirements for projects. Both these activities require coordination and information sharing between the AESO, Transmission Facility Owners (TFOs) and Customers and in cases the Distribution Facility Owners (DFOs). AltaLink Strategic Objective 3 Customer Access Services 1. Even though Connection Process improvement was a priority for the AESO in 2013, cycle time improvements have not occurred. In fact, cycle times may actually be increasing. We believe a significant change effort is required to compress Comment 1. AESO management highlights that it remains fully committed to work with industry to improve connection cycle time, which is the sum of efforts by all parties involved in the process. The Connection Process Work Group analysis suggests that significant changes in cycle time will likely AESO Stakeholder Comment and AESO Replies Matrix 2
cycle times in this complex process. We request the AESO dedicate resources to lead the significant changes required to improve this process in order to ensure our customers are connected to the grid on time. require changes that need to be supported by legislative or ISO Rule changes. The average connection stage durations reported in the AESO s quarterly metrics report identifies that some of the stage durations have in fact increased. Each project s unique characteristics will determine how long a project will take. The AESO s Connection Queue Business Practices provides for cancellation of projects that remain in a stage longer than the maximum duration. There are exceptions based on the legitimacy of market participant needs, however, moving forward with these projects will continue to have a negative impact on the average stage durations. Strategic Objective 2 - Electric System Development 2. For 2013 the AESO included a Transmission Cost Monitoring initiative in its 2013 Business Plan and Budget Proposal where additional resources were identified and allocated. AltaLink has observed the AESO has removed this initiative from its 2014 business initiatives. AltaLink requests the AESO dedicate resources to Transmission Cost Monitoring for 2014 as the Department of Energy (DOE) is currently working with stakeholders and implementing agencies on transmission cost initiatives that will overlap with AESO and stakeholders cost initiatives started in 2013, but are currently on hold. AESO resources will be required to implement recommendations from the DOE stakeholder sessions as well Comment 2. Transmission Cost Monitoring recommendations implementation is identified as an AESO 2014 Business Initiative under Strategic Objective 2. AESO management considers this initiative a priority and has allocated resources in support of Alberta Energy s Transmission Cost Management policy development. If additional resource requirements are identified as a result of this initiative as it progresses, they will be addressed by the AESO as required. AESO Stakeholder Comment and AESO Replies Matrix 3
as other AESO cost initiatives that are currently on hold i.e. the ISO Rule 9.1 Review which AltaLink has actively participated in and supports. Strategic Objective 7 Enabling Core Business Areas by Engaging our Stakeholders 3. AltaLink requests the AESO continue engagement with the TFOs in continuous improvement (i.e. initiatives arising out of our customer improvement focus meetings, our overall operations model/working relationship, etc.). Comment 3. Noted. The AESO will continue to engage all industry stakeholders as required. Strategic Objective 8 Enabling our Core business Areas through Risk Management and Compliance 4. AltaLink requests the AESO continue finalizing the implementation of ARS, which, based on the plans and schedules in play would see a significant number of new standards issued in 2014 (in addition to the security and cyber ones listed under Strategic Objective #4). A significant change effort is required to fully implement/engage the ARS compliance framework within the industry. Comment 4. The AESO recently posted a revised ARS work plan which identifies a number of new standards slated for development in 2014. Most of these standards are directly related to the AESO becoming a Reliability Coordinator and will have little, if any, impact on stakeholders. The exception to this is that the AESO is moving forward to adopt the Critical Infrastructure Protection (CIP) standards. The AESO acknowledges that these standards are very IT technical and complex. The AESO is committed to working with the AESO Reliability Committee (ARC) and its working groups to ensure that processes are in place to facilitate an effective implementation of the CIP standards. AESO Stakeholder Comment and AESO Replies Matrix 4
ATCO Electric 1. ATCO is in overall support of the AESO s Business Initiatives proposed for 2014. In particular, ATCO commends the AESO for its move towards greater transparency through the introduction of activity based costing for its proposed Own Costs in this year s BRP. 2. However, with respect to the AESO s Electric System Development strategic objective, ATCO encourages the AESO to allocate adequate resources in 2014, not only to implement any recommendations stemming from Transmission Cost Management policy development, but also to address any elements of cost monitoring and accountability that may remain outstanding (e.g. through Rule 9.1 reforms). ATCO supports the continuation of the AESO s audit role, as well as its other cost monitoring initiatives, such as the development of an improved cost information sharing protocol. 3. ATCO also concurs with the comments made by other stakeholders at the September 18 meeting that additional resources within the AESO would assist ensuring that compliance audits related to Alberta Reliability Standards (ARS) could be completed with the AESO s target range of 2-3 months so that, in a case of non-compliance, any actions required to rectify a breach and prevent further non-compliance could be implemented in a more timely manner, Comment 1. Noted. Comment 2. See AESO Reply to AltaLink Comment 2. above. Comment 3. The AESO acknowledges that audit times on the ARS compliance areas are not within industry expectations. AESO is currently reviewing the sources of potential delays with the audits, and will be discussing potential areas of improvement such as reviewing program scope, improving audit processes internally, and improving submission expectations with market participants. Some of the delays may be attributable to AESO Stakeholder Comment and AESO Replies Matrix 5
thereby better contributing to the reliability of the system. A more efficient compliance review process would also help to reduce the regulatory costs that are ultimately borne by ratepayers. the newness of the audit process and as a result of allowing market participants additional opportunities to re-submit or add evidence. We do not expect these same issues to occur in the next cycle of audits. The AESO is expecting to see improvements in the audit timelines by the start of the next 3 year audit cycle in January 2014. Additional resources to support auditing activities will be considered as a potential solution and will be considered along with the potential process improvements discussed previously. ATCO Power ATCO Power notes that Alberta Reliability Standards (ARS) are mentioned in the September 18, 2013 presentation titled Budget Review Process (BRP) AESO Draft Business Initiatives for 2014 as follows: a. Alberta Reliability Standards - Continued implementation of standards b. Electric System Operations: Compliance / Regulatory programs (continued Alberta Reliability Standards implementation) c. Enabling our Core Business Areas through Risk Management and Compliance: Continue to develop, file and implement Alberta Reliability Standards as per plan 1. ATCO Power s experience to date regarding the AESO s ability to manage various aspects of ARS implementation and monitoring suggests that the AESO is unable to adequately accomplish its present work. We are concerned that increasing the work required, as Comment 1. Noted. The AESO acknowledges the opportunity to improve the existing development and implementation processes for Alberta Reliability Standards (ARS). NERC has faced similar criticism in the US and is moving towards a Risk/Results based approach to standard development to AESO Stakeholder Comment and AESO Replies Matrix 6
indicated in point three above, will lead to an even further erosion of the AESO s performance. As a concrete example to illustrate our concern, ATCO Power s AESO ARS audit, as at Sep 27/13, is into day 239. We know that other companies have had similar audit experiences and the AESO itself has said that an average audit is taking over 200 days. In our view, the length of time the AESO requires to complete an ARS audit is an unacceptable service standard. Audits without a work-to-end date ultimately end up being inefficient, increase costs and create an additional administrative burden by the work expanding to fill the time. In addition to the sheer frustration and added expense of being held in an audit for such a long period of time, compliance is a genuine concern as a company will not know if it is potentially out of compliance until the audit findings are finalized. This extends the period of potential non-compliance for an unreasonable period of time before it is known what steps must be taken to deal with any compliance breach asserted by AESO. It also significantly increases a company s compliance risk in terms of the potential for penalties; particularly as such a long audit extends significantly into the subsequent audit period. reduce the administrative burden and refocus on the primary objective of maintaining and improving reliability. The AESO will continue to monitor this initiative in the US and work with AESO Reliability Committee (ARC) members and its working groups to make improvements. This will allow AESO resources to focus on the important issues and to provide support to stakeholders To further improve the quality of ARS, the AESO encourages market participants to engage during the development phase so that standards requirements and associated compliance expectations are clear. This will help reduce the number of questions the AESO receives during implementation of new standards and enable a speedy response. Also, see AESO Reply to ATCO Electric Comment 3 and AESO Reply to AltaLink Comment 4 above. AESO Stakeholder Comment and AESO Replies Matrix 7
From the AESO s perspective, such long audit periods should also be concerning, as if there is an actual noncompliance, it would not necessarily be dealt with until identified by the audit. Given that ARS are specifically intended to ensure system reliability, this implies that system reliability could be at risk unnecessarily due to unidentified ARS non-compliance. Based on our observations and interactions with the AESO, ATCO Power s view is that the AESO appears to be struggling with a number of issues that impede its ability to effectively interact with stakeholders and carry out its work. ATCO Power strongly suggests that the AESO resolve its resourcing issues, improve its organization and planning approach, in addition to realistically prioritizing its workload. In our view, it is not appropriate for the AESO to consider increasing its workload relative to ARS until it is able to manage its present workload in a timely and effective manner. Capital Power 1. Capital Power appreciates the opportunity to participate in the 2014 BRP, as well as the updates that were provided at the September 18, 2013 stakeholder session. 2. As previously stated, the Market System Replacement (MSR) Project and the activities, processes, and potential costs associated with this Comment 1. Noted. Comment 2. Noted. The target date for publishing the estimated trading charge information is October 31, 2013 in the AESO s Board Decision Document. AESO Stakeholder Comment and AESO Replies Matrix 8
initiative that are planned for 2014 are of particular interest to Capital Power. We look forward to receiving more information about the project at the October 10, 2013 Technical Review Meeting. In addition, Capital Power would appreciate receiving any available updates at the Technical Review Meeting that the AESO may have concerning the forecast trading charge for 2014. 3. Overall, Capital Power has no objections to the eight strategic objectives for 2014 identified by the AESO. Capital Power appreciates the AESO stating that, in order to accommodate stakeholder requests, they will provide a breakdown of costs associated with each strategic objective at the Technical Review Meeting. However, Capital Power also feels it would be helpful to stakeholders for the AESO to prioritize the various projects the AESO plans on addressing in 2014, particularly those initiatives related to Market Development. It would be helpful for the AESO to advise market participants what the basis for determining the priority of each project or initiative is, and how the AESO plans on coordinating the various processes to ensure stakeholders have a reasonable opportunity to participate and aren t stretched too thin from a resource perspective. This information could be shared with stakeholders at the upcoming Technical Review Meeting. Comment 3. AESO management considers the list of 2014 Business Initiatives presented to stakeholders as its priorities for the upcoming year. That said the initiatives identified often require consultation and the feedback from market participants and could result in relative priorities being established over the course of the year as it unfolds. AESO Stakeholder Comment and AESO Replies Matrix 9
IPCAA 1. IPCAA appreciates the opportunity to provide feedback on the AESO s Business Initiatives. In 2013, IPCAA observed substantial improvements and actions taken to implement Transmission Cost Monitoring, customer connection process enhancements, and modeling transmission rates. These are areas that significantly impact IPCAA members and we would like to take this opportunity to recognize the individuals at the AESO who are driving these initiatives forward. For the AESO s 2014 planned business initiatives, IPCAA provides the following comments: Market Development: 2. Progress needs to be made to enable load resources to provide spinning reserves. A review of the existing suite of OR and reliability services may be warranted to identify whether there are changes that can be made to incentivize more demand response. IPCAA is willing to work with the AESO to promote load provision of OR through a series of consumer workshops. 3. The debate on TCM is an important area of focus. However, efforts should be placed on compliance to AUC directions as issued by Decision 2013-135, rather than legal actions for appeal. IPCAA strongly submits that Comment 1. Noted. Comment 2. The AESO appreciates IPCAA s offer to work with the AESO to promote load provision of OR. At present ISO Rules are being modified to align with new reliability standards. This work is intended to make OR market access for loads easier. Comment 3. Noted. The AESO and stakeholders have formed a working group that is focused on implementing the AUC directions from Decision 2013-135 TCM complaint. This work will continue into 2014. AESO Stakeholder Comment and AESO Replies Matrix 10
having two public agencies spending ratepayer dollars objecting to each other s views is not an efficient and prudent use of ratepayer dollars. Transmission Development 4. IPCAA sees transmission project prioritization as an important factor that is not included in the existing framework. Albertans need to recognize that not all projects can be built at the same time. An overly ambitious development plan may artificially create shortages in the construction labour force and further escalate the costs of transmission development. Project prioritization need to be based on sound economic assessment. In Section 11.3 of the ATCO Electric 2013-2014 GTA Decision (2013-358) the AUC states that the Ratepayer Group proposal, and including ratepayers in the project prioritization process has merit. IPCAA encourages the AESO to reconsider its project prioritization approach, and improve transparency in its planning process. 5. A review of the technical requirements (i.e. ISO Rule 502.2) for bulk transmission development is a critical initiative. Ratepayers are extremely concerned that the reliability level dictated by the current technical requirements is excessive, resulting in more expensive infrastructure being built than in other jurisdictions. Comment 4. The AESO notes that planning is an iterative process and that iteration provides an ongoing opportunity to review transmission project requirements and priorities. In 2013 the AESO s regional planning efforts and its plans to file a Long Term Plan (LTP) will provide the AESO opportunities to review and revise project priorities if necessary. Comment 5. The AESO has initiated a transmission line rule review this quarter and efforts will continue into 2014. AESO does not agree with IPCAA comments on reliability levels in the current standard. AESO Stakeholder Comment and AESO Replies Matrix 11
6. IPCAA applauds the AESO bottom up approach to the budget process this year. Comment 6. Noted. TransAlta TransAlta has the following concerns in relation to the AESO s Strategic Objective #8: 1. TransAlta s experience is that ARS audits are currently taking a year to complete and this timeline is unacceptable. Since the ARS are in place to address system reliability, delays in assessing compliance can also result in increased risk of a reliability event on the AIES. Market participants face increased compliance risk as they are unable to get timely guidance on rules all the while assuming compliance for the duration of the audit. Any instances of noncompliance identified at the conclusion of the audit have basically been continuing for an additional year. The extended duration also creates increased administrative burden for both the market participant and the MSA as any non-compliance identified in the audit period will now also require a self-report as the audit findings will not cover this intervening year. Execution of an audit, along with associated information requests is time consuming and creates an additional burden on market participants when the audit evidence must be revisited repeatedly over the course of a year when the process should be completed in 2 to 3 months. Comment 1. Noted. See AESO Reply to ATCO Electric Comment 3 above. AESO Stakeholder Comment and AESO Replies Matrix 12
How does the AESO plan to address the duration of ARS audits in their business plan? How will the AESO continue to expand this initiative given that current workloads appear unmanageable today? 2. TransAlta s experience is that it currently takes the AESO up to 6 months to answer compliance related questions on ARS. This timeline is unacceptable for reasons expressed (1) above. There are a number of outstanding questions the AESO has yet to address in regards to new ARS that will be effective on Oct 1, 2013. Comment 2. Noted. See AESO Reply to ATCO Power Comment 1 above. How does the AESO plan to address response times on compliance related questions on ARS? 3. The AESO plans to seek AUC approval on the CIP standards next year and market participants will need to begin implementation efforts in 2013. These standards are very IT-specific and will require both technical and compliance SMEs. Implementation will be complex as these standards are new to industry and unlike other ARS which have a basis in Good Operating Practice. TransAlta expects there will be a number of questions as market participants begin implementation efforts. Does AESO s business plan include the hiring of appropriate resources to facilitate implementation? Comment 3. Noted. The AESO has identified the need to reallocate resources to facilitate CIP implementation. In addition, see AESO Reply to AltaLink Comment 4 above. AESO Stakeholder Comment and AESO Replies Matrix 13
Other Comments Do stakeholders have any other comments to offer at this time? Stakeholder Stakeholder Comment AESO Replies ADC 1. The meeting with the Board is currently scheduled at the same time as an upcoming Transmission Cost Management Policy meeting on November 14. Our preference would be to have time with the Board on November 12 th or the afternoon of November 13 th. 2. The ADC appreciates the AESO scheduling an Edmonton meeting on Oct 16 th, 2013. Comment 1. The AESO will review the request to advance the stakeholder presentations to the AESO Board meeting, however, it is anticipated that there is limited flexibility in rescheduling this meeting. As an alternative to stakeholders presentations, formal letters can be presented by AESO management on behalf of stakeholders. Comment 2. Noted. ATCO Electric 1. ATCO suggests that audit compliance initiatives, such as recent efforts to amend the Rule 9.1 Information Document, be coordinated with, and conditional upon, completion of the Rule 9.1 working group s recommendations and AUC approval of any proposed rule amendments. In this respect, budgeted resources and efforts to improve and enhance the AESO cost accountability role through Rule 9.1 working group discussions should be continued. Stakeholders, then, will be able to provide input, not only on the proper residual relationship of the AESO s cost accountability role to the proposed AUC s cost management role, but also on the optimal coordination of AESO rule development work with AESO compliance initiatives. Comment 1. See AESO Reply to AltaLink Comment 2 in the section above. AESO Stakeholder Comment and AESO Replies Matrix 14
Capital Power IPCAA TransAlta 1. The BRP is helpful in providing Capital Power with an understanding of the AESO priorities for 2014, which supports our internal planning and resource management. Capital Power appreciates the opportunity to participate in this consultation and supports the overarching principle of transparency identified and emphasized by the AESO in this context. 1. As requested at the stakeholder meeting, IPCAA is interested in determining the amount of ratepayer dollars the AESO is allocating to appealing AUC decisions. This information could assist in promoting an alternative industry approach and avoiding the regulatory arena, where possible. 1. TransAlta is concerned about the increased frequency of hearings with regard to market rules in the past year. TransAlta believes there is a need for facilitation services in order to enable an effective and efficient consultation process. TransAlta suggests that the AESO s business plan include resources to obtain such facilitation services. Comment 1. Noted. Comment 1. AESO management will endeavor to include this specific information request at the upcoming Technical meeting on Own Costs or during the subsequent consultation process. Comment 1. The AESO s consultation process for rules development is not necessarily expected to result in a facilitated settlement. In certain cases, market participant positions will remain polarized due to the diversity of business drivers and the complexity of issues being consulted on. There may be situations where facilitation services could be considered but AESO management would consider this to be the exception not the norm. AESO Stakeholder Comment and AESO Replies Matrix 15
Stakeholder Comments and AESO Replies Matrix AESO Consultation 2014 Budget Review Process (BRP): Technical Meetings October 10 th and October 16 th, 2013 AESO s 2014 Draft Pool Price, Ancillary Services and Transmission Line Losses Costs Forecast, Own Costs Budgets and Market Systems Replacement Project Update The following information is intended to summarize AESO management s responses to stakeholder comments on the AESO s 2014 Draft Forecasts, Own Costs Budget and Market Systems Replacement Project update. This information was presented at the October 10 th and 16 th BRP technical meetings in Calgary and Edmonton. AESO Pool Price Forecast for 2014 October Technical Meeting Do stakeholders have any comments on the Pool Price forecast for the upcoming year? ADC 1. Can the AESO publish a price duration curve for the 2014 pool price forecast? Noted. The AESO does not plan to publish this information as part of the BRP. The AESO has provided the annual average pool price as a key element of the BRP forecasting process. ATCO Electric No comments. ATCO Power 1. ATCO Power appreciates the difficulty to forecast prices in the Alberta market but nonetheless notes that the AESO s 2014 forecast is significantly below recent history and the forward market. The supply/demand picture provided by the AESO provides no apparent justification for this outcome. Increases in available generation capacity in 2014 are the primary justification behind the expectation of a lower average pool price. The return of Sundance 1, Sundance 2 and Keephills 1 units being the key changes considered as this represents close to 1000MW of baseload generation returning to service, or comparably over 15% of the coal fleet. As well, the AESO cannot include the impact of unexpected long term forced outages in its forecast, which has been a driver of higher prices in recent years. 2. Using the P95 iteration doesn t rectify the issue since the prices are not driven by an appropriately high level of variability but instead by a gas price that is unrealistically inflated by about 50%. Noted. Natural gas is one of the drivers of the higher prices in the P95 iterations used in the forecast. There are many variables that are run through monte carlo simulation that would have higher impact through the creation of volatility in each input. 3. Being cognizant of the difficulty to model the market and keeping in mind the timing of this process, ATCO Power therefore suggests using an alternative way to establish a price forecast, for example through the use of forward prices shaped based on historical variability. Noted. The AESO feels that the modeling we undertake, which takes a fundamental view of the market, our knowledge and available information is the best approach. AESO uses an industry standard model for price forecasting that accounts for many historical variables. AESO also updates the prices every quarter to take into account any changes in fundamentals throughout the year. AESO Stakeholder Comment and AESO Replies Matrix Page 1
AESO Pool Price Forecast for 2014 October Technical Meeting Do stakeholders have any comments on the Pool Price forecast for the upcoming year? Capital Power 1. Capital Power appreciates the opportunity to participate in the review of the 2014 AESO Budget; this process enhances our understanding of AESO priorities and the corresponding impact to our own workload. Noted. 2. Capital Power is supportive of the AESO developing its own pricing forecast for the Budget Review Process, and appreciated the high level overview of its forecast methodology that the AESO provided on October 10, 2013. Capital Power has no concerns with the forecast methodology for the pool price, load forecast, or the expected supply additions identified by the AESO. Noted. IPCAA 1. Last year, IPCAA commented that it would be useful for the AESO to publish a high level description of how the hourly price forecast is modeled. Such a description would indicate the assumptions, inputs/outputs at each stage of the forecast model, and the intent of the various scenarios used to arrive at the final set of numbers. This would give stakeholders an idea on how the results were obtained. This explanation remains to be seen. The response to this question was published in the AESO 2013 Business Plan and Budget Proposal and follows: In creating the price forecast the AESO used the most up to date information available on future supply, demand and market fundamentals. Key uncertainties such as gas price, forced outages and weather related demand fluctuation were varied stochastically in the simulations. The AESO created this pool price forecast for the BRP using a proprietary simulation model. Expectations regarding future supply and demand can be found in the 2012 LTOU and the Quarterly LTA Metric report. Additional details regarding the AESO s supply and demand forecast and assumptions can be found in the 2012 LTO and updated LTOU. For additional input, the AESO runs 1001 hourly price simulations, with monte carlo simulation imbedded in several variables as noted above, and other variables are held constant that are known to AESO such as supply additions and planned outages. No scenarios are used in the BRP process. No sensitivities are tested either. Wind output and hydro output are assumed to be relatively normal. As mentioned above, the AESO price forecasting algorithm is considered proprietary and details considered confidential. 2. In 2013 BRP, the AESO s model predicted a $50.73/MWh median and $75.20/MWh max for 2013, yet the actual market price is $85.28 year-to-date. IPCAA understands the high price levels in 2013 are attributable to unexpected generation outages and import/transmission constraints that occurred in 2013; therefore it was difficult to predict. Has the AESO taken a review of system conditions and assessed whether the same conditions might persist in 2014? If so, what is done differently in the Forced Outages simulation in the price model this year? Is $48.48/MWh a reasonable price level to expect? (The forward curve is currently $58.25/MWh.) Random forced outages, as well as planned outages are imbedded in the 2014 simulations much like the 2013 process. Planned outages can change in duration and timing throughout the year and this will impact the price in ways the AESO cannot predict. The AESO feels the 2014 price forecast used is reasonable based on the information available at this time. The AESO also notes that there are other third party forecasts that are in line with its own but is unable to publish these due to copyright. AESO Stakeholder Comment and AESO Replies Matrix Page 2
AESO Pool Price Forecast for 2014 October Technical Meeting Do stakeholders have any comments on the Pool Price forecast for the upcoming year? 3. IPCAA notes that the AESO has reduced its wind generation additions significantly. For example, a. in the 2013 BRP, the forecasted 2013 wind generation addition was more than 200 MW, yet none of it has materialized and this is recognized in the 2014 model. The AESO acknowledges that an oversight occurred when preparing the technical meeting presentation by mistakenly omitting the wind additions for 2014 from the Supply Additions slide (11 of 60) presented at the October 10 & 16 stakeholder meetings. A revised graph is included in the response. The 2014 model includes 300 MW of wind capacity additions, capturing capacity from the Blacksprings project that is now under construction. The following is a revised Slide 11 from the Technical Meeting AESO s 2014 Forecasts, Own Costs Budget and Market Systems Replacement Update Stakeholder Meeting Presentation. b. How is the lack of wind addition affecting AESO s system development prioritization in bulk transmission planning? Up-to-date project information is included in the updates to the AESO project and planning processes. In addition, see AESO reply to IPCAA comment 1 in the Any Other Comments section below. AESO Stakeholder Comment and AESO Replies Matrix Page 3
AESO Pool Price Forecast for 2014 October Technical Meeting Do stakeholders have any comments on the Pool Price forecast for the upcoming year? TransAlta 1. TransAlta appreciates the opportunity to comment on the AESO s pool price forecast and does not have any specific concerns about the forecast presented. Noted. 2. TransAlta is interested in the point of discussion at the October 10th meeting regarding the impacts of the EATL line coming online in 2014. TransAlta suggests that at some point prior to the EATL line coming online that the AESO publish its assessment of the expected system and market impacts as well as impacts on the pool price and line losses. Given its role in the operation of the grid and the market, the AESO is in the best position to do so. The AESO is planning an information session on HVDC commissioning Monday, November 4, 2013. Information regarding anticipated grid and market impacts will be presented at this time. Stakeholders will find additional details on aeso.ca. AESO Stakeholder Comment and AESO Replies Matrix Page 4
AESO Ancillary Services Cost Forecast for 2014 October Technical Meeting Do stakeholders have any comments on the Ancillary Services Costs forecasts for the upcoming year? ADC 1. Does the AESO anticipate any material cost change for Ancillary Services if the BAL002 standard is implemented in 2014? No material change in 2014 Ancillary Services costs are anticipated as a result of the implementation of the standard at this time. ATCO Electric No comments. ATCO Power 1. In ATCO Power s view, LSSi is not an Ancillary Service. While the AESO has the right to approve Ancillary Service costs, the AESO does not have the right to unilaterally determine whether a product is an Ancillary Service or not. Absent confirmation from the AUC that LSSi is an Ancillary Service, ATCO Power considers it inappropriate to simply treat it as such. Given that the finding could have significant implications regarding the determination of the prudency of the costs, at the very least it should be highlighted to stakeholders that this is a contentious item. Noted. The treatment and recovery of LSSi costs are before the AUC in the AESO s current deferral account proceeding for 2012 and current tariff application proceeding for 2013 and 2014. The AUC is aware of ATCO Power s concerns in those proceedings, and has approved the recovery of LSSi costs in the AESO s 2013 tariff on an interim refundable basis. The AESO will note this information in the AESO 2014 Business Plan and Budget Proposal to the AESO Board. 2. With regard to other Ancillary Services costs, ATCO Power is concerned about the link to the price forecast. In ATCO Power s experience as an Ancillary Service provider, OR costs are largely nonlinearly related to pool and gas prices. Any error or bias coming from the price forecasting would therefore translate into the AS cost forecast. Given the previous observation about the low price forecast, ATCO Power is concerned that the AS costs might be significantly understated. Noted. Agree that recent annual Ancillary Services costs are less correlated to pool prices. Partly in response to the lower correlation, the AESO s tariff allocates actual costs incurred for operating reserves to system access services on an hourly basis at the end of every month and does not depend on forecast correlation with pool price; this change occurred in July 2011. The AESO also recognizes that a reasonable forecast remains important and has allowed for volatilities and uncertainties in the forecast. Specifically, we use P95 monthly forecasts to account for the seasonal volatility embedded in the 2014 cost estimates. We also published a high and low forecast for Ancillary Services costs for 2014 to provide a range of outcomes. The AESO will continue to monitor events that impact costs and update these estimates quarterly. Capital Power 1. Capital Power has no concerns with the Ancillary Services Costs forecasts identified by the AESO. Noted. AESO Stakeholder Comment and AESO Replies Matrix Page 5
AESO Ancillary Services Cost Forecast for 2014 October Technical Meeting Do stakeholders have any comments on the Ancillary Services Costs forecasts for the upcoming year? IPCAA 1. There appears to be a trend of consistent under-forecasting in the OR cost category. It is understood this is primarily due to the higher than expected pool prices, but are there any differences in forecasted capacity vs. actual procured/activated capacity? This information would be helpful in understanding forecast accuracy. Noted. There are differences between forecasts and actual of both price and capacity, but a majority of the difference in Operating Reserve (OR) costs is attributed to a difference in price not capacity. For example, the year-to-date OR volumes (September 30, 2013) were 6.0 terawatt hours which is 0.1 terawatt hours or approximately one percent higher than the forecast volumes of 5.9 terawatt hours. In addition, the OR volumes forecast reported for 2014 are 7.9 terawatt hours which is slightly less than the 2013 forecast of 8.0 terawatt hours. 2. In predicting OR costs, it is unclear how the AESO came up with the estimated hourly premium/discounts that are indexed to the pool price. It is unclear whether this comes out as a part of the AURORA model, or if another methodology was used. Noted. The hourly premiums/discounts estimates are derived from a rolling window of twenty four months of historical data. The estimate is then combined with the pool price results from the AURORA model. 3. IPCAA observes that the 2014 LSSi forecasted cost is much more aligned with the 2012 and 2013 actual and projected levels, but it is significantly lower than the forecasted levels in the past. What are the reasons for this? Noted. A review of historical LSSi data identified that the actual requirements were consistently lower than the forecasted. 4. Last year, IPCAA promoted the idea of conducting a thorough cost-benefit analysis on LSSi. We emphasized that it was important to evaluate the merits of the program in case there are changes that can be made to improve cost efficiency. We haven t seen any published result on this. Is a review being conducted? Noted. The AESO s target date to publish the LSSi review report is year end. The report intends to review product features, summarize the benefits and limitations and identify potential areas for improvement. Additional interim LSSi information has been published as part of the AESO s response to information requests on the 2014 ISO Tariff Application. See www.auc.ab.ca Proceeding ID No. 2718 Response to UCA-AESO-001 September 30, 2013 for details. TransAlta 1. TransAlta appreciates the opportunity to comment on the AESO s AS cost forecast and does not have any specific concerns about the costs presented. Noted. AESO Stakeholder Comment and AESO Replies Matrix Page 6
AESO Transmission Line Losses Costs Forecast for 2014 October Technical Meeting Do stakeholders have any comments on the Transmission Line Losses Costs forecasts for the upcoming year? ADC 1. The losses in 2014 are forecast to increase over 2013, can the AESO explain what is causing the increase? The AESO s loss forecast is based on historic hourly loss volume data. The 2014 BRP loss forecast uses the same forecasting model that was used in previous BRP forecasts with updated hourly historic data. The forecast results for 2014 reflect the increasing trend in the historical hourly data up to 2013. This aligns with the current projection for 2013 actual loss volumes to be higher than the 2013 forecast loss volumes. 2. What is the projected impact on line losses once the HVDC lines are in service? AESO is currently undertaking analysis and operational impacts of HVDC, including impact to system losses. This work is ongoing and results are not final. The losses forecasts will be impacted in 2015. ATCO Electric No comments. ATCO Power 1. Just as with AS costs, ATCO Power is concerned about the linkage between the price forecast and the forecast for line loss costs. Noted. The transmission line losses cost forecast is created by valuing the forecast losses at forecast prices. Actual transmission line losses actual deviations are primarily the result of pool price variance that can be explained. See also AESO response to IPCAA comment 1 below. Capital Power 1. Capital Power has no concerns with the Transmission Line Losses Costs forecasts identified by the AESO. Noted. AESO Stakeholder Comment and AESO Replies Matrix Page 7
AESO Transmission Line Losses Costs Forecast for 2014 October Technical Meeting Do stakeholders have any comments on the Transmission Line Losses Costs forecasts for the upcoming year? IPCAA 1. In contrasting the actual vs. forecast losses costs in the past years (referring to page 20 and 22 in the presentation slides), it would be useful to have a column that indicates the $ and GWh differences, as well as the % error between the two sets of numbers. The following table provides the variance information requested. Also see the AESO 2014 Business Plan and Budget Proposal for year-to-date 2013 information on losses. Total Losses Costs ($M) Total Volumes (GWh) Average Pool Price ($/MWh) 2010 F/C 2010 Actual Variance Under (Over) % Variance 2011 F/C 2011 Actual Variance Under (Over) % Variance 2012 F/C 2012 Actual Variance Under (Over) % Variance 173.6 131.2 42.4 24.4% 121.0 185.8 (64.8) -53.6% 220.8 150.7 70.1 31.7% 2,643 2,667 (24) -0.9% 2,564 2,367 197 7.7% 2,553 2,216 337 13.2% 64.40 50.88 13.52 21.0% 46.70 76.22 (29.52) -63.2% 83.32 60.47 22.85 27.4% F/C - forecast TransAlta 1. TransAlta appreciates the opportunity to comment on the AESO s line loss costs forecast and does not have any specific concerns about the costs presented. Noted. AESO Stakeholder Comment and AESO Replies Matrix Page 8
AESO Own Costs Budget for 2014 - October Technical Meeting Do stakeholders have any comments on the AESO s Activity-Based reporting presentation? ADC 1. The activity based reporting method was helpful in seeing how the AESO is allocation resources to business priorities. Noted. ATCO Electric 1. ATCO supports the AESO s introduction of activity-based reporting as part of its 2014 BRP and its efforts to promote transparency of its Own Costs and asks the AESO to provide comparative 2013 budget numbers with year over year variance explanations for each of the key activities and their sub-processes. The following table provides a comparison of the 2013 and 2014 budgets by key activity. AESO Stakeholder Comment and AESO Replies Matrix Page 9
AESO Own Costs Budget for 2014 - October Technical Meeting Do stakeholders have any comments on the AESO s Activity-Based reporting presentation? 2. ATCO encourages the AESO to continue this initiative by also categorizing the AESO s Information Technology Services under their associated processes in the future. Noted. ATCO Power 1. This is the first time ATCO Power participates in the budget review process. ATCO Power is therefore unable to compare the current format to the earlier format. The current presentation seems intuitive though and appropriate for the process. Noted. 2. ATCO has the following comments regarding specific activities: (a) Given the concerns expressed by stakeholders regarding the ARS, particularly the audit, ATCO Power is interested in better understanding how the AESO plans to address them. These efforts would seem to fall under Electric System Operations. Noted. As identified in the response to comments on the AESO business initiatives, the AESO acknowledges that audit times on the ARS compliance areas are not within industry expectations. AESO is currently reviewing the sources of potential delays with the audits, and will be discussing potential areas of improvement such as reviewing program scope, improving audit processes internally, and improving submission expectations with market participants. For further comments, refer to the AESO s response to ATCO Electric question 3 from the September 18, 2013 stakeholder meeting on the AESO s Draft Business Initiatives for 2014. The document is located on the AESO s website (http://www.aeso.ca/downloads/replies- Comments_Matrix_Business_Initiatives_final.pdf). Agreed. The AESO considers ARS (compliance program development and operations) as an Electric Systems Operations process activity. It is classified under the Operations Business Services activity grouping. (b) ATCO Power is also interested in further detail on Market Development. Unfortunately stakeholder concerns seem to not get resolved in the AESO s consultation process resulting in a significant amount of proceedings in front of the Commission. This creates a significant cost burden. ATCO Power would like to see a more detailed breakdown of the costs in this area and get a better understanding on how the AESO is planning to reduce or avoid costs in this area. The following table presents the Regulatory Process Costs for expenditures incurred by the AESO. These amounts are for third party costs associated with the regulatory proceeding and do not include internal AESO staff costs. All Regulatory Process Cost expenditures occur in a cost-effective manner to ensure prudent financial decisions are made and to demonstrate responsible stewardship of funds. For new ISO Rules or Alberta Reliability Standards, or for amendments to existing ISO Rules or Alberta Reliability Standards, stakeholder consultation is an important step in the AESO s process to ensure receipt and consideration of stakeholder feedback and comments. It is ultimately the AESO s responsibility to proceed in a manner that it feels is most appropriate; at times that may lead to objections or complaints by market participants. AESO Stakeholder Comment and AESO Replies Matrix Page 10
AESO Own Costs Budget for 2014 - October Technical Meeting Do stakeholders have any comments on the AESO s Activity-Based reporting presentation? Proceeding Category ($ million) 2014 2013 YTD Sept 2012 Plan Projected 2013 Costs Actuals Competitive Process - 0.2 0.2 0.8 Objections and Complaints - 2013 and 2012 0.7 0.7 0.5 0.8 Objection to Available Transfer Capability and Transfer Path Management Objection to Transmission Loss Factor Methodology and Requirements Complaint to Real Time Transmission Constraint Management Rule Needs identification documents 0.8 0.7 0.5 0.6 2013: Fidler 312S 240/138 kv Substation BluEarth Hand Hills Wind Energy Connection Foothills Area Transmission Development Goose Lake to Chapel Rock Southern Alberta Transmission Reinforcement AUC Notices of Hearings 2012: Airdrie Area 138 kv Transmission Reinforcement East Calgary Transmission Project and Shepard Energy Centre Interconnection Red Deer Region Transmission Development South Calgary 69 kv Transmission System Upgrade Spruce Grove 595S Substation and Interconnection Weasel Creek 947S and Abee 993S Substations AUC Notices of Hearings Transmission facility owner applications - 0.0 0.0 0.3 Western Alberta Transmission Line (WATL) - 2013 and 2012 Eastern Alberta Transmission Line (EATL) - 2012 Heartland Transmission Project - 2012 Transmission Line 902L Conductor Replacement - 2012 Other 0.2 0.1 0.1 0.0 Total 1.8 1.7 1.4 2.5 Totals may not add due to rounding Capital Power 1. Capital Power appreciates the AESO s efforts in preparing the activity-based cost reporting in response to stakeholder requests to increase transparency, and has no concerns with the breakdown provided at the Technical Review meeting on October 10, 2013. Capital Power encourages the AESO to provide activitybased cost reporting in all future BRPs going-forward. Noted. AESO Stakeholder Comment and AESO Replies Matrix Page 11
AESO Own Costs Budget for 2014 - October Technical Meeting Do stakeholders have any comments on the AESO s Activity-Based reporting presentation? IPCAA 1. IPCAA appreciates the efforts taken by the AESO to implement the Activity-Based reporting structure. It is a helpful to gain insight into the budget allocation amongst the different functions. Noted. 2. IPCAA would like to see this reporting format be continued in the future and to have each year being contrasted with the previous in order to identify cost changes. Any cost changes should be tracked back to an area of activity with provided explanations. This type of reporting does improve the level of transparency around the AESO s operating costs. Hopefully this has been valuable for internal purposes as well, and not simply for external stakeholders. The process and results of the activity-based cost reporting provided additional insight on all business activities underway at the AESO and resources dedicated to those deliverables. This information has allowed management to confirm or reassess the alignment of resources to general AESO activities and priorities. The plan is to continue this reporting format in future years. TransAlta 1. TransAlta appreciates the AESO s efforts in providing greater transparency into its own costs through the use of the new activity-based format. TransAlta requests that a further breakdown of each activity block by project also be provided to help stakeholders understand the AESO s focus for the upcoming year and conduct their own planning activities. TransAlta understands the industry is dynamic and priorities shift during the year, but a breakdown of the activities by project will facilitate conversation during the BRP phase and help participants understand the status of each initiative when priorities change. The business initiatives presented to stakeholders at the September 18 BRP meeting identify the AESO s focus for the upcoming year; they will be documented in the AESO 2014 Business Plan and Budget Proposal. The AESO will report its progress against these business initiatives, including changes to priority or timing on a quarterly basis during 2014. The activity-based cost reporting is developed at a level to provide useful information on the general operations of the company as opposed to a much more detailed project-level. Project-level reporting is used internally when management is reporting and monitoring specific tasks or initiatives. (Also refer to the response to ATCO Electric 2 c). AESO Stakeholder Comment and AESO Replies Matrix Page 12
AESO Own Costs Budget for 2014 - October Technical Meeting Do stakeholders have any comments on the General & Administrative budget proposal for the upcoming year? ADC 1. The ADC encourages the AESO to allocate sufficient resources to the Customer access services activities to ensure that load and generation connections advance on a timely and streamlined basis. AESO management believes there are sufficient resources allocated to this area. Management continues to review customer connection access service requirements on an ongoing basis and will add additional resources if necessary. ATCO Electric 1. It would be useful to see a comparative split of the AESO s General and Administrative costs associated with its regional vs bulk transmission plans. Noted. The AESO will take this comment under consideration for the next BRP cycle. 2. Re: Electric Systems Development Costs: (a) Please clarify if the $5.5 million budgeted for the Competitive Process includes costs for both the Fort McMurray West and East projects. If so, how much was budgeted for each project? Development of Tendering and Commercial Documents (Financial, Tendering and Legal Advisors) Fort McMurray West Fort McMurray East 2014 Plan 1.1 0.3 2013 Forecast 2.1-2013 Plan Evaluation Teams & Fairness Advisor 1.0 1.0 1.2 Route Development & Owner s Engineer 1.2 1.0 1.7 Integration Costs (AESO internal resources) 1.0 1.0 1.0 Communications 0.3-0.8 Issues Based Outreach 0.4 - - Total General and Administrative Costs 5.4 5.1 5.6 Regulatory Process Costs* - 0.2 - * These costs are not recorded as General and Administrative costs; they are included in Other Industry Costs. 0.9 - (b) ATCO notes that these Competitive Process costs may be better classified as Market Development activity cost. This would increase the total Market Development costs from $5 million to $10.5 million and reduce Electric System Development costs from $16.5 million to $10.5 million. The AESO considers Competitive Process a transmission development activity, not market-related, which results in its classification within the Electric System Development process. (c) Please specify what is intended to be accomplished and the amount budgeted for the AESO to develop AESO Stakeholder Comment and AESO Replies Matrix Page 13
AESO Own Costs Budget for 2014 - October Technical Meeting Do stakeholders have any comments on the General & Administrative budget proposal for the upcoming year? cost benchmarking for transmission projects, separate from the costs of transmission program support and the costs of communications strategies for transmission projects. The AESO s intention in providing activity-based cost reporting is to describe general activity groupings for each process and the associated dollars. The intention is not to associate dollars and specific deliverables for each activity grouping. That level of information is considered too detailed for the purpose of providing the activity-based cost reporting. (Also refer to the response to TransAlta 1).) 3. Please provide all metrics and external benchmarks used by AESO to help ensure that its corporate services costs are as lean as possible. Noted. When the information is available, the AESO compares its budgeted costs with other ISOs. In general, the comparison shows that the business drivers between organizations are not comparable which impacts the usefulness of the information. The AESO is open to ideas stakeholders have regarding potential metrics or external benchmarks. This proposal has been offered to stakeholders in prior BRPs. 4. The costs of developing benchmarking for transmission projects included under Electric Systems Development would also be better classified as a Market Development cost, similar to other monitoring activities listed under Market Development, such as the auditing and assessment of market participants for compliance. The activities included in Market Development include the compliance for ISO Rules. The cost benchmarking activity included in Electric System Development relates to the development of a cost benchmark database to be used to evaluate transmission projects within Alberta. A compliance function performed by the AESO is not a part of the cost benchmarking activity. The AESO believes the current categories are appropriate. 5. ATCO urges the AESO to review and re-consider the key activities included in each of its key processes. Noted. ATCO Power 1. ATCO Power is interested in additional detail around the transition of the reliability coordinator function and the associated costs of $1 Million. In addition, ATCO Power would like to better understand the WECC/NWPP Costs. Additional information on the transition of the reliability coordinator (RC) function and the AESO impact as well as WECC/NWPP costs will be provided in the AESO 2014 Business Plan and Budget Proposal. Also refer to http://www.aeso.ca/downloads/aeso_to_provide_rc_functions_091213_(2).pdf for RC information published on aeso.ca. AESO Stakeholder Comment and AESO Replies Matrix Page 14
Capital Power 1. As all costs are essentially flowed-through to either load or generators, Capital Power commends the AESO s efforts to self-fund new initiatives and attempts to identify further reductions for the 2015 G&A budget. Noted. IPCAA IPCAA has several specific questions with regard to AESO cost allocations: 1. What are the 2013 Actual YTD and Projected and 2014 Budget amounts allocated to Transmission Constraints Management regulatory costs (i.e. AUC proceeding-related, etc.)? Refer to the response provided in the Activity-based Reporting section to ATCO Power 2 b). The total third party costs for Objections and Complaints are provided. Internal AESO resource time or costs is not available. 2. What are the 2013 Actual YTD and Projected and 2014 Budget amounts allocated to Line Loss regulatory costs (i.e. AUC Proceeding ID 2581, etc.)? Refer to the response provided in the Activity-based Reporting section to ATCO Power 2 b). The total third party costs for Objections and Complaints are provided. Internal AESO resource time or costs is not available. 3. What are the 2014 Budget amounts allocated to the AESO Competitive Process compared to the 2013 Actual YTD and Projection numbers? Are all of the Competitive Process costs part of the ESD category? If not, where else are they allocated? Refer to the responses provided in the Activity-based Reporting section to ATCO Power 2 b) and in the General and Administrative Cost section to ATCO Electric 2 a). Yes, all competitive process costs are included in the Electric System Development process. 4. Are all of the Transmission Cost Monitoring and Oversight activities part of the ESD cost category or are some included elsewhere? What are the total FTEs and costs attributable to Transmission Cost Monitoring and Oversight in 2014? How does this compare to 2013? The Electric System Development process includes resources that are specifically dedicated to the cost monitoring processes or activities but other resources also contribute to the deliverables for cost monitoring. 2014 Plan 2013 Plan Staff (number of staff resources) 3 4 Contract resources ($ million) 0.1 0.5 TransAlta No comments. AESO Stakeholder Comment and AESO Replies Matrix Page 15
AESO Own Costs Budget for 2014 - October Technical Meeting Do stakeholders have any comments on the Capital Budget proposal for the upcoming year? ADC No comments. ATCO Electric 1. ATCO would be interested in seeing the AESO s 2014 Capital Budget presented in an activity-based manner, similar to the profile shown for 2013 Capital Investments on slide 49 of the meeting presentation. The AESO will take this comment under consideration for the next BRP cycle as part of AESO management s review of information technology costs. 2. ATCO would encourage the AESO to provide business cases and rationale for its capital budget decisions. Noted. Additional high-level information regarding the AESO s capital projects will be provided in the AESO 2014 Business Plan and Budget Proposal and in the Quarterly Stakeholder Report. Detailed business case information will continue to be managed internally through the AESO s established portfolio management process as discussed in the Business Plan and Budget Proposal. ATCO Power No comment. Capital Power 1. Capital Power has no concerns with the Capital Budget proposal. IPCAA No comment. TransAlta 1. TransAlta does not have any specific comments but would like to better understand how and when selffunding will be used and its impacts on planned initiatives. The AESO is committed to continuing to prioritize our work and streamline our processes. We know that new projects or initiatives will be identified in the future, but we plan to offset these additional costs by identifying savings as we become a more focused and efficient organization. These changes will occur without compromising the reliability or quality of our work. AESO Stakeholder Comment and AESO Replies Matrix Page 16
Other Comments Do stakeholders have any comments on the Market System Replacement project update? ADC 1. After reviewing the consultation summary on the MSR project, it is unclear that a 15 minute settlement is being contemplated as one of the underlying requirements of the system. Can the AESO confirm its position on this? Dispatch and Settlement period alignment has been captured in the current list of system requirements. The complete set of requirements will be assessed as part of the Phase II (Request for Proposal) project process. ATCO Electric No comments. ATCO Power No comments. Capital Power 1. The Market System Replacement (MSR) Project, stakeholder consultation, and potential costs associated with this initiative are of particular interest to Capital Power. As such, we appreciated the update provided by the AESO on October 10 th advising that Phase II will cost approximately $1.5-2 Million in 2014 and that the depreciable life of the new system should be approximately 7-10 years. Noted. 2. Capital Power also looks forward to receiving more information about the potential impact to the trading charge and the rate methodology that will be employed to recover costs associated with the project. This information will be part of the AESO 2014 Business Plan and Budget Proposal. The 2014 trading charge will incorporate the costs incurred in 2013, Phase 1- Validation (Business Case Development) and the 2014 budget for the Business Plan and Budget Proposal, Phase 2 - Request For Proposal. Capital cost for the project will not occur until 2015. 3. Given the significance of the scope of the MSR project and the estimated cost for Phase III, Capital Power urges the AESO to take steps to ensure that stakeholders are actively engaged and consulted in all phases of the project s development and implementation. Stakeholder involvement is essential to the success of the MSR project. Stakeholders will be engaged throughout the entire project. IPCAA No comments. AESO Stakeholder Comment and AESO Replies Matrix Page 17
Other Comments Do stakeholders have any comments on the Market System Replacement project update? TransAlta 1. TransAlta believes that while it is important to replace aging technology and infrastructure, given the significant cost of this project, the AESO should lay out a clear long term vision for the new system and what it will be built to. TransAlta believes that the new system must have sufficient flexibility to accommodate not only the market design requirements that exist today, such as the participation of wind in the market, the ability for more than one participant to offer energy from an asset and constraints management, but also any known initiatives that might be required in the next 5 to 10 years. Agreed. AESO Stakeholder Comment and AESO Replies Matrix Page 18
Other Comments Do stakeholders have any other comments to offer at this time? ADC No comments. ATCO Electric 1. ATCO values the opportunity to participate in the AESO s BRP and appreciates the information that the AESO has shared. The AESO appreciates the involvement and commitment that all stakeholders have provided throughout the 2014 BRP. ATCO Power 1. While it is informative to see the AESO s forecast of costs, it would also be helpful to see detail around: a. how costs have deviated from expectations; b. whether changes compared to expectations represent anomalies or can be expected to persist; and c. how the AESO intends to work towards lowering costs. All amounts have budget to actual information presented. This information was covered as part of the technical meeting review or can be located in the AESO 2014 Business Plan and Budget Proposal. Review and management of the AESO s general and administrative and capital costs is discussed in the AESO 2014 Business Plan and Budget Proposal. Also see the AESO s reply to ATCO Power comments on Pool Price, Ancillary Services Costs and Transmission Line Losses Costs above. 2. Finally, ATCO Power would like to thank the AESO for the opportunity to provide comments and apologizes in case any of the comments provided here have already been addressed during the technical meeting. Unfortunately no representative from ATCO Power was able to attend the meeting due to a scheduling conflict with an AESO R&V application. Noted. It was unfortunate that ATCO Power representatives were unable to attend. The AESO tries to accommodate all schedules. We look forward to ATCO Powers future participation. Capital Power Capital Power has no other comments at this time. IPCAA 1. Under Electric System Development, IPCAA would like to see additional transparency from the AESO on project prioritization and cost-benefit analysis, and for the AESO to start incorporating ratepayer input into its planning and prioritization process. In the recent AUC Decision 2013-358, the Commission offered the following statement regarding project prioritization: Notwithstanding, the Commission considers the approach advocated by the [Ratepayer Group] RPG to include rate payers in the process, and to plan transmission on the basis of overall project prioritization, to have merit. However, as set out in Section 17 of the Electric Utilities Act and Part 2 of the Transmission Regulation, system planning is clearly the responsibility of the AESO. Consequently, apart from encouraging the AESO to consider this approach, the Commission cannot direct the AESO to engage in this process. paragraph 388 AESO Stakeholder Comment and AESO Replies Matrix Page 19
Other Comments Do stakeholders have any other comments to offer at this time? As identified in the response to comments on the AESO s Business Initiatives the AESO notes that planning is an iterative process and that iteration provides an ongoing opportunity to review transmission project requirements and priorities. In 2013, the AESO s regional planning efforts and its intent to file an updated Long-term Transmission Plan will provide the AESO opportunities to review and revise project priorities if necessary. As this comment is considered beyond the scope of the BRP process, it will be forwarded to the appropriate executive for reference. TransAlta TransAlta has three other comments to offer in relation to the AESO s responses to the Business Initiatives comments: 1. In its response to TransAlta, Comment 3, the AESO states The AESO has identified the need to reallocate resources to facilitate CIP implementation. As stated in its comments on draft Business Initiatives, TransAlta raised the question that the skill set required in order to facilitate implementation of CIP standards requires both IT specific technical and compliance expertise. Is the AESO of the opinion that they have the appropriate resources internally and just need to reallocate those resources, or will the AESO need to acquire a new skill set, in which case additional resources will need to be added? If new resources are to be added, has the AESO made appropriate allowances for it in their 2014 business plan? Noted. The specific reference is with respect to finding a self-funded solution. This means that should additional resources be required, a vacant staff position or budget dollars would be transferred from another area. The required skill set may or may not be available internally. 2. In its response to ATCO Electric, Comment 3, the AESO states The AESO acknowledges that audit times on the ARS compliance areas are not within industry expectations, and further The AESO is expecting to see improvements in the audit timelines by the start of the next 3 year audit cycle in January 2014. TransAlta would like the AESO to make a commitment to meet their target of 2-3 months for the audit timelines. Noted. The AESO intends to perform its requirements according to plans. 3. In its response to ATCO Power, Comment 1, the AESO states The AESO will continue to monitor this [NERC] initiative in the US and work with AESO Reliability Committee (ARC) members and its working groups to make improvements. This will allow AESO resources to focus on the important issues and to provide support to stakeholders. TransAlta requests clarification on the types of improvements the AESO is expecting and what would be considered a satisfactory standard. Noted. As identified in the response to comments on the AESO s Business Initiatives the review of improvements is currently work in progress and the details are to be provided by the process owners and discussed with market participants when available. AESO Stakeholder Comment and AESO Replies Matrix Page 20