Status of Canadian Markets

1. Status of Canadian Markets APEX Conference – Sydney, Australia October 13, 2008 Warren Frost, Vice President Operations & Reliability

2. Alberta's Electricity Market

3. Markets: develop and operate Alberta’s real-time wholesale energy market to facilitate fair, efficient and open competition Transmission System Development: plan and develop the transmission system to ensure continued reliability and facilitate the competitive market and investment in new supply Transmission System Access: provide system access for both generation and load customers System Operations: direct the reliable operation of Alberta’s power grid Settlement: accountable for administration of the provincial load settlement AESO - Our Core Business

4. Quick Facts - Alberta’s Electric Industry • 9,710 MW peak & 80% LF • 12,085 MW total generation • Over 280 generating units • Wholesale market with ~ 200 market participants • > 21,000 km of transmission • Interties BC (up to 780 MW) & Sask. (up to 150 MW) (Wind)510 MW 5,893 MW BC (Other renewables)178 MW 4,635 MW Alta 869 MW Sask

5. Industry Structure Alberta Utilities Commission Act Electric Utilities Act Minister of Energy Appoints Board members & MSA Cabinet Appoints Commission Members and Chair of AUC Balancing Pool Alberta Electric System Operator Market Surveillance Administrator AUC Consumer Financial accts Wholesale Energy Market Compliance Surveillance PPA Obligations Load Settlement Transmission Planning Real-time Operation of Electric System

6. Grid & Market Operations Operate the Grid Operate the Market TFO/GFO Generators AESO System Controller Neighbouring BA and TOP Marketers Reliability Coordinator Ancillary Service Providers SC Support 24/7 Operations Engineering EMS/IT

7. Wholesale Markets • Real-time energy only market • Clearing market – one price for all • No capacity payments • Price cap @ $1,000 • Day-ahead operating reserve market • Supply shortfall procedures • Postage stamp transmission rates paid by load • Siting signals for generators • Loss factors • System contributions for interconnections

8. Market Operations • Participants submit bids/offers by noon day ahead – can restate price up to two hours before delivery (T- 2 hours) • Each asset can use 7 price-quantity pairs for each hour • AESO creates an Energy Merit Order (EMO) for each hour from the bids and offers • SC Dispatches up and Down the EMO • Schedules inter-provincial energy schedules hourly • Imports offered at $0 • Exports bid at $999.99 • Highest dispatched asset sets SMP • Ex-post pool price is the arithmetic average of the 60 one minute system marginal prices

9. Demand $ per MW SMP Generation units dispatched MW Setting System Marginal Price (SMP)

10. Ancillary Services • AESO is the buyer of reserves - procured 5 days to 1 day ahead of delivery • Contingency reserves • Replaces unexpected lost supply • 500 MW of spinning and non-spinning reserves • Must be able to provide in 10 minutes • Regulating Reserves • Normally use 130 to 225 MW • Responds to instantaneous fluctuations in supply/demand balance

11. Adequacy • No centrally planned generation - market signals to encourage generation investment • Established a threshold where stop-gap action will be taken by AESO to ensure adequacy until investors can build • Threshold looks at supply two years out • If 2 year supply picture appears to breach threshold AESO will procure: Demand products and/or emergency generation • Out of market actions invoked when energy market merit order is exhausted using Supply Shortfall Procedures: • Curtail exports, loads • Cut reserves • Acquire emergency energy from neighboring jurisdictions • Curtail firm load

12. Transmission and Interties • Market Policy • Transmission is required for reliability and to facilitate a competitive market • ISO must create long term plans – 10 and 20 year • Transmission Must Run • Generally expected to be short-term solutions • Using dispatch down service to remove pool price impact • Congestion management rules • Interties – essential to a well functioning market • Reliability – reserves, frequency, stability • Market – imports during scarcity and export during surplus • Merchant Interties - TransCanada NorthernLights (NL) and MATL

13. Major Initiatives in the Alberta Market • Wind integration • Congestion Management Rules and Procedures • Market Power Mitigation • Market share and a pivotal supplier test • Dispatchable Interties • Operating Reserve Market Redesign • Demand Response • New Intertie Capacity

14. Ontario’s Electricity Market

15. Ontario at a Glance(year-end 2007) The IESO is the reliability coordinator for Ontario and works closely with other jurisdictions to ensure energy adequacy across North America.

16. Ontario’s Electricity Market Ontario Energy Board Contracted/Regulated Prices $ Consumers Suppliers Offers/Schedules Bids Local Distribution Companies78(e.g. Toronto Hydro, Hydro Ottawa, Hydro One) Generators45 (e.g. Shell, Constellation) Dispatch Dispatch Wholesale Sellers68(e.g. Shell, Constellation) WholesaleConsumers98(e.g. Dofasco, Norampac, De Beers) Payments Billing $ $ Direction Tariffs $ Transmitters(Hydro One, Great Lakes Power, Canadian Niagara Power, Five Nations Energy) Electricity

17. Fixed or Capped Prices in Ontario • More than 75 percent of the generation in Ontario has a contract or fixed price for example: • Non utility generator (NUG) contracts • Contracts for new (selected under RFP) and existing plants based on market price • Fixed rates for ‘heritage’ generation owned by the monopoly generator (nuclear and 85% of baseload hydro) • 85% of coal and peaking hydro output from monopoly generator pays a rebate if market price exceeds a set rate • Fixed rates for renewable generation – Standard Offer Program for small-scale renewable • In addition, Ontario is initiating a large volume of conservation and demand response contracts • All Ontario consumers pay an adjustment to the Hourly Ontario Energy Price to cover these contracts • Adjustment fluctuates between a credit and debit depending on the market price

18. Major Initiatives in the Ontario Market • Government RFP for new nuclear • Smart Meters for all Ontarians by 2010 (4 million customers) • 1.3 million installed to date • 27,000 customers now billed on time-of-use rates • Day-ahead mechanisms planned for 2010 • Assessing an energy forward market • Day-ahead price forecast implemented this summer • Ontario’s target for renewables is over 10,400 MW by 2010 • Coal replacement strategy being implemented, with shutdown complete in 2014 • Significant conservation and demand response programs launched and under development • Target 6,300 MW reduction through CDM by 2025

19. New Brunswick’s Electricity Market

20. New Brunswick System Operator(Independent Not-for-Profit System Operator) NBSO is 1 of 17 Reliability Coordinators

21. Reliability

22. Interconnections

23. Market Design • Market activity through physical bilateral contracts • Competitive supply must match load obligation • Open access transmission by FERC 888 and compatible tariff operated through FERC 889 compatible OASIS • NBP Genco responsible to backstop delivery of • Standard offer services for supply and backup • All ancillary transmission and market services • Central system operator to be responsible for market • PUB to have regulatory authority • Remove embedded generation barriers

24. Market Structure Suppliers Market Delivery Loads NBP Genco NBP Nuclear Marketers IPPs HQ/NS NBP Transco NBSO NBP Disco Large Industry SJ/Ed/PA PEI/NM

25. Market Implementation • Contracts between two parties (supplier and load) • terms, conditions and price negotiated privately • scheduled every day through system operator OASIS • imbalance & transmission settled after the fact by system operator • Eligible loads are • Large Industry at transmission voltage (about 50) • Wholesale municipals (SJ, Ed, P-A) • NB Power Disco • Eligible suppliers are • NB generators (NBP Genco, NBP Nuclear, WPS, Bayside, others?) • Industrial self generation (existing, new?) • External utilities (HQ, NS, MPS/EA) • Others (Marketers, Aggregators, brokers)

26. Transmission Tariff • FERC 888 compatible open access tariff • Point to point service • Network service • Unbundled ancillary services • System Dispatch and Voltage Support (mandatory) • AGC and Operating Reserves (optional) • Energy Imbalance (mandatory settlement) • Billing determinants • Net non coincident demand by delivery point

27. Ongoing Work • Continue to pursue efficiencies in dispatch, market administration, and operations. • Seek details on the standard service rates, terms, and conditions that would apply in the case of a customer serving all or a part of its load from an alternative supply (e.g. exit fees, partial service policies). • Enhance automated market assessment and monitoring tools. • Increase system flexibility and competitiveness of balancing energy supply by increasing levels of participation in the balancing energy market. • Pursue additional supplies of capacity-based ancillary services and competitive pricing of those services. • Simplify and fine tune the market rules where appropriate (especially with respect to wind power integration).

28. Ongoing Work (cont.d) • Actively monitor transmission planning studies in adjacent jurisdictions and their potential impacts on the New Brunswick market. • Pursue regional cooperation on issues such as transmission planning, reducing inter-market barriers, and easing wind power integration. • In keeping with the intent of some aspects of FERC 890 the NBSO will consider the expansion of the regional transmission planning function beyond reliability and ten year time frames to include overall system needs inclusive of economics. • Review of the overall approach to transmission investment, usage and tariffs given the magnitude of the potential generation, the non-dispatchable nature of proposed generation, and the requirements for significant transmission investments.

29. Questions