Technical Meeting AESO’s 2015 Forecasts, Own Costs Budget

1. Technical MeetingAESO’s 2015 Forecasts, Own Costs Budget Stakeholder Meeting October 6 and 8, 2014

2. Purpose • Purpose of this presentation is to: • Provide stakeholders with an overview of: • AESO’s 2015 Pool Price, Ancillary Services and Transmission Line Losses Costs Forecasts • AESO’s 2015 draft Own Costs budget • Update on the Market Systems Replacement project • Update on the Energy Management System project • Obtain preliminary feedback • Provide stakeholders with a BRP status update and discuss next steps

3. 2015 BRP - StepsStatus Update

4. 2015 BRP - Steps Calendar (revised) 3.0 Develop AESO Own Costs, Ancillary Service and Line Loss Forecasts (internal) June - September 5.0 AESO Board Decision November 14 – Stakeholder presentations 1.0 Notice to Stakeholders 2.0 Updated Business Initiatives AESO Board Decision 4.0 Technical Review Meetings with Stakeholders September 22 - Business Initiatives October 6 (Calgary) and October 8 (Edmonton) - Ancillary Service, Transmission Line Losses Costs Forecast and Own Costs 5.0 AESO Board Decision (continued) - finalize

5. 2015 Pool Price Forecast October 2014

6. The information contained in this document is published in accordance with the AESO’s legislative obligations and is for information purposes only. As such, the AESO makes no warranties or representations as to the accuracy, completeness or fitness for any particular purpose with respect to the information contained herein, whether express or implied. While the AESO has made every attempt to ensure the information contained herein represents a reasonable forecast, the AESO is not responsible for any errors or omissions. Consequently, any reliance placed on the information contained herein is at the reader’s sole risk.

7. Purpose of AESO Price Forecast • Hourly Price Forecast is Required for the Budget Review Process • Forecast feeds cost calculations for Ancillary Services and Transmission Losses • Third year of the AESO providing a Forecast • Price Forecasts from EDC were used prior to the 2013 BRP

8. Forecast Methodology • Created Using the AURORAxmp Power Market Model • Model reflects the Alberta Market Fundamentals • Random Variables are Used to Generate Price Volatility • Forced Outages – random times and duration • Demand – accounts for weather impact • Gas Prices – lognormal distribution of monthly gas prices • potential long-term forced outages, congestion, unanticipated load growth, wind output, and high/low hydro years are currently not modeled using random variables • Price Simulation • Ran 1001 separate price simulations • Price distributions reflect volatility seen in the Alberta Market

9. Load Forecast

10. Supply Additions

11. 2015 Simulation Results Results from 1001 Price Simulations Results from the P95 Simulation and Comparables

12. Actual/Forecast Price Comparison • 2015 forecast is based on the P95 iteration

13. 2014 Daily Price Duration Curve

14. 2015 Ancillary Services Cost Forecast October 2014

15. Cost of Ancillary ServicesAnnual Comparison * Conscripted TMR and Operating Reserves not included in the table above

16. Forecast Methodology Operating Reserves • Annual cost of OR is estimated by the sum of forecasted hourly OR volumes (governed by WECC requirements) multiplied by the forecasted hourly price of OR • Forecasted cost of OR is evaluated once for each of the 1001 pool price simulations

17. Forecast Methodology Contracted TMR and Other Ancillary Services • Annual TMR cost forecast based on historical contract costs • Annual LSSi cost forecast based on current monthly averages and expected costs for 2015 • Annual blackstart cost forecast based on contract terms governing compensation and expected new contracts in 2015

18. 2015 Transmission Line LossesCost Forecast

19. Cost of Transmission Line LossesAnnual Comparison

20. Forecast MethodologyLine Losses • Annual cost of transmission line losses is estimated by the sum of forecasted hourly volumes multiplied by the forecasted pool price • Forecasted cost of line losses is evaluated once for each of the 1001 pool price simulations

21. Draft 2015 Own Costs Budget

22. 2015 Budget Overview • 2015 G&A budget • 2015 capital budget excluding major projects

23. General & Administrative CostsYTD August 2014 * Excludes the Market Systems Replacement Validation Project approved for $2.0 million Differences are due to rounding

24. 2015 Budget Overview • Continued delivery for AESO and industry required initiatives • Refer to business initiative presentation • Most 2015 initiatives began in 2014 or prior years • Reflects efficiencies and corporate focus • Leverage existing work to reduce ongoing effort • Capital development focus on major system projects • Limited system enhancements in 2015 • Limited flexibility to incorporate unanticipated initiatives • Consistent with prior budgets, significant changes will require additional review and approval

25. General & Administrative Costs2015 Preliminary Budget Differences are due to rounding

26. Notable Changes in 2015 • Progression of Competitive Process • Integration of Fort McMurray West transmission line • Begin Fort McMurray East transmission line process • 3.5% salary adjustment to maintain market-based compensation • Rent and operating cost changes on existing leased facilities • Assignment of existing staff to major project work • Day-to-day operational requirements for these positions reduced during the project which eliminates need to back-fill • Energy Management System upgrade, Market Systems Replacement • Net new maintenance and support costs associated with annual capital investments

27. 2015 Preliminary Budget * Excludes Market System Replacement project

28. Competitive Process Initiative Differences are due to rounding

29. Transmission Cost Monitoring and Oversight Initiative

30. Historical G&A Costs * Excludes Market System Replacement project

31. Interest and Amortization

32. Other Industry Costs * Western Electricity Coordinating Council / Northwest Power Pool

33. Activity-based Cost Reporting • A transparent presentation of the AESO’s operating costs • Operations of the AESO described using five key processes • Key processes are unchanged from 2014 • Activity reporting allows for more detailed understanding of the resources required for process delivery • Multi-year comparisons will identify shift in priorities/ focus • No significant shift has occurred in 2015

34. Summary of AESO G&A Costs 2. Electric System Development 1. Electric System Operations • Proportion of 2015 costs associated with the five key processes is similar to 2014 ~ no material shift • Details provided in the final document will include IT costs associated with the five key processes 2. Electric System 1. Electric System Operations 4. Market Development 4. Market Development Staff and Contract Services ($61 million) 2014 Budget by Key Process 3. Customer Access Services 5. Corporate Services 5. Corporate Services 3. Customer Access Services Administration ($5 million) Facilities ($8 million) Information Technology Services ~ Resources ($11 million) Computer Services and Telecomm ($10 million) not actual data Budget of $94 million

35. Capital Budget

36. Capital Budget - Historical Definitions: Key Capital Initiatives – Most critical projects that the AESO believes must be completed within the timeframe identified Other Capital Initiatives – Other projects that have more flexibility in planning or delivery so timing is not as critical Life Cycle Funding – Hardware replacements (end of useful life) and recurring software upgrades and leasehold improvements

37. Capital Budget – Key Messages for 2014 • 2014 forecast is $18.5M • Decrease of $1.4M from 2014 budget of $19.9M • Factors include • Deferred capital requirements for Business Initiatives - Energy Management System (EMS) deferred to 2015 • Continued improvements resulting from Portfolio Management Process – roadmaps, change control and resource management

38. Capital Budget - 2015 draft

39. Capital Budget - Key Messages for 2015 • Initial assessment is that a $21.8M capital budget is required • Increase of $1.9M from 2014 budget and increase of $3.3M from 2014 forecast • Factors include • Critical Infrastructure Protection and Cyber Security requirements (facilities and information technology) • Planning considerations related to foundational systems • Market System Replacement project (business applications and supporting infrastructure – $5.8M) • Energy Management System Upgrade project (advanced applications and supporting infrastructure - $3.6M) • Reduction in enhancement requirements as a result of foundational system projects

40. Capital Budget - Trend

41. Capital Budget – “Other Capital Initiatives” for 2015 - Summary • Other application or infrastructure upgrades • PI Software Upgrade • System Enhancements • AESO website tools and content • Human Resources Management Tool

42. Capital Budget – “Life Cycle Initiatives” for 2015 - Summary • Investment in general infrastructure • Communications • Database • End User Computing • Enterprise Services • Monitoring • Network • Non-project Capital • Servers • Storage

43. Special Projects Market Systems Replacement (MSR) Project - Update

44. MSR Project - Background • On December 11, 2013, the AESO Board approved Phase II of the Market System Replacement and Reengineering (MSR) project to address the long term lifecycle needs of our market systems In progress  Business case, plan, and decision to proceed to Phase II Business case, plan, cost effective solution(s) identified, and decision to proceed to Phase III

45. MSR Project - Overview of Phase II Sourcing / RFP • Implementation strategy • Phase I research indicates that available end-to-end solutions do not have broad flexibility to mitigate the uncertainty of future market scenarios • Hence, implementation strategy is to incrementally/iteratively address highest priorities with a minimum amount of change until we gain more certainty regarding future market scenarios • Phase II objectives align with this strategy: • Refine target state including clear priorities and further defined business requirements (sufficient for RFP) • Determine candidate vendors, execute and evaluate RFP(s) • Establish sequencing and implementation plan for Phase III

46. MSR Project - Phase III Roadmap Phase III Future Iterations Iteration 1 Design Build Note: Future iterations are likely to overlap and run in parallel at certain times SOW (Contract for Design) Term: Jan 1 to Sept 30, 2015 System Integrator (SI) proposal covers entire roadmap (Evaluation criteria considers entire proposal) Indicative Ballpark Detailed/Certain Level of accuracy of estimates and other aspects of a proposal 46

47. MSR Project – Phase III Preliminary Estimates • MSR Phase III (Implementation) expected to begin in Q1 2015 upon Board approval • Preliminary estimates are $5.8M capital, $500K G&A in 2015 • Estimates based on following assumptions • Able to leverage existing infrastructure • Additional infrastructure requirements are fulfilled via the technology lifecycle program • Estimates include SI, internal labor and product related costs

48. Special Projects Energy Management System (EMS) Upgrade Project - Update

49. EMS Upgrade Project - Background • Energy Management System (EMS) • Mission critical control system used by AESO system controllers to manage and operate the Alberta Interconnected Electric System • Project Justification • EMS components at end-of-life • Risk avoidance, Regulatory Requirements, Vendor Support/Costs • Project Scope • Includes EMS network, infrastructure and application suite

50. EMS Upgrade Project - Program Approach • Execute in three phases • Validation: • Assessment of long term requirements (business/technology); Evaluation of option risks/opportunities (replace reengineer); Peer Reviews • Definition: • Define detailed business, design & implementation requirements; Greater degree of confidence in timing and cost estimates(given the scale of the project) • Similar approach BCHydro (EMS 3.0 upgrade) • Implementation • Development/deployment of design requirements into production • Data conversion, skills development, commissioning, warranty and decommissioning