IAMU 2008 Fall Conference

1. 1 IAMU 2008 Fall Conference October 1, 2008 Marlin Vrbas, P.E. PS Analytics, LLC

2. 2 Outline MAPP Integration Overview How Do LMP Markets Work? ARR & FTR Basics New Resource Adequacy Requirements

3. 3 MAPP Integration Overview

4. 4 Proposed MISO-MAPP Integration Areas

5. 5 Motivating Factors On January 30, 2007 the MISO gave notice of its intent to terminate the MISO-MAPP Seams Agreement that had been in place since market startup, citing: Higher than expected generation re-dispatch within the MISO market needed to accommodate the seams agreement. Increasing occurrences of Transmission Loading Relief curtailments in MAPP. Increasing difficulty in getting transmission service in MAPP.

6. 6 Proposed Solution MISO developed three new tariff services (Module F) to replace the Seams Agreement: Part I: Reliability Coordination Service Part II: Interconnected Operations and Congestion Management Service Part III: Market Coordination Service FERC has approved Parts I & II. Module F Part III is still under FERC review.

7. 7 Most Recent MEC Timeline MEC is proposing to: Take Module F Parts I & II service initially to replace seams agreement services. Take Module F Part III Market Coordination Service when approved by FERC and offered by MISO. FERC Technical Conference 11/12/08 on Module F Part III Market Coordination Services. Assuming FERC order approving Module F Part III in December 2008: March 15, 2009: MEC & all Market Participants in MEC BAA submit completed commercial model data. July-August 2009: Transitional FTR allocation process September 1, 2009: MISO market entrance

8. 8 Expected Benefits to Market Coordination Customers & Others from Joining MISO MISO Security Constrained Economic Dispatch System Is Expected to: Reduce or eliminate Transmission Loading Relief (TLR) curtailments. Improve efficiency of generation dispatch. Capture missed opportunities for favorable transactions that are presently lost due to transmission reservation requirements. Expose transmission congestion via LMP price signals to identify & correct transmission constraints on an economic basis. Other?

9. 9 Deterrents to Joining MISO Under Proposed Module F Part III Objections by Existing MISO Participants to Tariff Provisions: Allows existing Market Participants to exit Transmission Owner agreements and re-enter under new tariff. New entrants & “re-entrants” retain transmission rate making authority leaving rate “pancaking” in place.

10. 10 Deterrents to Joining MISO Under Proposed Module F Part III Objections by Potential New MISO Participants and Transmission Customers: Retention of pancaked transmission charges impedes access to new resources. New Market Integration Transmission Service (MITS) includes after-the-fact charges that may impact generator offer practices & net revenues for municipals w/ significant generation. Retention by Transmission Owners of non-RTO planning practices may hamper access to ARR & FTR revenues.

11. 11 Impact on MEC JOU Owners & Other Iowa Municipal Utilities Cancellation of bilateral wholesale agreements & replacement by energy purchases at market based rates. New MITS charges & related changes in transmission cost re-distributions. Transmission planning practices inconsistent with MISO RTO principals may limit the ability to hedge against congestion charges.

12. 12 Current Bilateral Transactions

13. 13 Proposed MISO Market Transactions After Integration

14. 14 Transmission Tariff Overview

15. 15 MISO Footprint Transaction Overview

16. 16 Current Import/Export Transactions (Without MITS)

17. 17 MISO Market Coordination Customer Transaction Overview

18. 18 MISO Market Coordination Customer Transaction Overview

19. 19 MISO Market Coordination Customer Transaction Overview

20. 20 MISO Long-Term Transmission Rights Working Group Position

21. 21 MEC Transmission Planning Considerations Under the Midwest ISO’s proposal, the Midwest ISO will not allocate any infeasible ARRs under the guarantee provisions of Section 43.2.4a.v of Module C to the TEMT to the extent that the Market Coordination Customer has failed to place into service a network upgrade required in accordance with the Market Coordination Customer’s own reliability or economic planning criteria and identified through the inter-regional coordination process, unless the Market Coordination Customer has made a good faith effort to complete the network upgrade. Because MidAmerican Energy’s planning criteria do not obligate MidAmerican Energy to build projects for economic reasons, if MidAmerican Energy becomes a Market Coordination Customer, MidAmerican Energy’s obligation under Part III of Module F would consist of the obligation to build projects on the MidAmerican Energy Transmission System which meet MidAmerican Energy’s reliability criteria and which are identified through the inter-regional coordination process. (August 15, 2008 MEC Informational Filing to FERC)

22. 22 MISO Long-Term Transmission Rights Working Group Position

23. 23 MAPP Integration Take Aways... Final rule formation regarding MITS charges, transmission planning & LTTRs processes, and other factors related to Module F Part III will have a significant impact on bulk power costs for many Iowa municipal utilities in the MISO market. These issues are expected to be taken up in the November 12, 2008 FERC Technical Conference.

24. 24 How Do LMP Markets Work?

25. 25 LMP Market Overview The MISO Provides Two Energy Markets Day Ahead Market Facilitates next-day matching of load bids and generation offers. Gives generators a “heads up” for committing & dispatching generation units. Real-time Market Facilitates next-hour matching of loads and generation offers. Functions as a “balancing market.”

26. 26 LMP Clearing Price

27. 27 LMP Market Overview Bid/Offer clearing process results in $/MWh LMP values for registered Elemental Price Nodes (EPnodes) which correspond to electric system buses. EPnode LMP values are averaged on a load weighted basis to determine LMP values at Commercial Price Nodes (CPnodes) upon which settlements are based. LMP values may be illustrated by contour diagrams.

28. 28 Off-peak Hour

29. 29 Late Morning Hour

30. 30 Peak Hour

31. 31 Mid Afternoon

32. 32 Late Afternoon

33. 33 Late Evening Off-peak

34. 34 MISO Real-Time LMP Contour Diagram http://www.midwestmarket.org

35. 35 3 Bus Example: No Congestion

36. 36 Congestion Imminent

37. 37 Re-dispatch or Transmission Loading Relief Required

38. 38 Market Based Congestion Management - Pre-congestion

39. 39 Congestion Imminent

40. 40 Congestion Pricing

41. 41 The marginal cost is computed as the cost of serving the next MW of load increase: LMP A = 2 x $100 – 1 x $30 = $170 LMP is the price paid for load that is withdrawn, or generation that is injected. Note: The impact of losses is not considered in this example. LMP Calculation

42. 42 Doing the Accounting… Load Pays … $170 x 180 MW = $30,600 Gen Receives … $30 x 120 = $3,600 $100 x 60 = $6,000 Total $9,600 Difference = $21,000 = Congestion charge Where does this money go?

43. 43 Transmission Usage Charge (TUC) TUC is the difference between the LMPs at the sink and source of a transaction.

44. 44 Financial Transmission Rights (FTRs) This case (shown before) shows that loads up to 150 MW may be received at Load C before congestion occurs.

45. 45 Assume: 180 MW Load 150 MW FTR Loss = 0 TUC = Sink LMP–Source LMP = $170-$30=$140/MW Net congestion charge for that hour is: Congestion Charge = $140 x 180 MW = $25,200 FTR Payment = (Sink LMP – Source LMP) x FTR MW FTR Payment = $140 x 150 MW FTR = $21,000 Net Congestion Charge = $25,200 - $21,000 = $ 4,200 Congestion Settlement Example

46. 46 ARR & FTR Basics

47. 47 Definitions FTR = Financial Transmission Rights ARR = Auction Revenue Rights FTRs and ARRs are defined as specific source-sink pairs for a specific time period and MW value. FTRs: Provide a hedge against congestion charges as shown in previous example. (They can also incur charges.) Are purchased via annual or monthly auctions. ARRs: Entitle the holder to receive a portion of the FTR auction revenues. Are allocated based on transmission rights.

48. 48 FTR & ARR Basics If your source points (e.g. JOUs) & loads do not change from the reference year in which your Base Load ARRs were first allocated, ARRs can be converted to FTRs and your congestion charges can normally be reasonably well hedged. If your Base Load source points DO change, i.e. new sources are added, the cost of congestion from the new source(s) may be hedged by some combination of new ARR allocations, exchanging of existing allocated ARR value via the annual auction, and/or purchasing FTRs in the auction. ARRs & FTRs are designed to facilitate transmission access for Network Customers by placing the responsibility for managing congestion costs upon the Transmission Customer.

49. 49 FTR & ARR Basics A Base Load (MISO “Stage 1A”) ARR with a source and sink that matches a desirable FTR source-sink hedge can be “self-scheduled” in the FTR auction which effectively converts the ARR into an FTR. An ARR that is allocated in Year 1 with a Base Load resource as the source: Is called a Long Term Transmission Right (LTTR) Is guaranteed for each subsequent year as long as they are nominated each year and as long as the Transmission Owner makes a good faith effort to complete network upgrades using economic planning criteria.

50. 50 FTR & ARR Take Away... It is important that owners of Jointly Owned Unit shares take the necessary steps to procure ARRs and FTRs by: Properly registering your load and generation assets. Participating in the annual ARR registration and nomination process. (The first year is the hardest and the most important.) Participating in the annual FTR auction (and monthly auctions in some cases.) Assuring that appropriate transmission system upgrades are completed.

51. 51 New Resource Adequacy Requirements

52. 52 Existing MISO & MAPP Resource Adequacy Requirements Capacity requirement = (Load + Firm Sales – Firm Purchases) x (1 + Planning Reserve Margin) Capacity requirement is measured as Installed Capacity (ICAP) and is verified via URGE tests.

53. 53 Proposed Resource Adequacy Requirements (RAR) Are intended to: Place Demand Resources on a more equal basis with Generation Resources. Take into consideration the historical availability and failure rates of claimed resources. Take into consideration regional transmission limitations and Loss of Load Expectations (LOLE) via zonal Planning Reserve Margin definitions. Module E resources are called “Planning Resources” Planning Resources may consist of: Capacity Resources Load Modifying Resources

54. 54 Capacity Side RAR Considerations Capacity Resources include: Generation Resources External Resources (outside of MISO) Demand Response Resources (DRR) Demand Reduction/Load Control Behind-the-Meter Generation Load Modifying Resources include: Demand Resources Behind-the-Meter Generation

55. 55 Capacity Side RAR Considerations Capacity Resources: Carry MISO “must offer” requirement. Require ICCP for metering. ICCP = Inter-Control Center Communications Protocol. ICCP may be available as an add-on for some SCADA systems. Requires WAN service. Are eligible for participating in the ASM if qualified. Require ICCP for control if participating in ASM.

56. 56 Capacity Side RAR Considerations Load Modifying Resources: Are required to be available during declared MISO energy emergencies. Are subject to penalties and loss of accreditation if unable to start during declared emergencies.

57. 57 Capacity Side RAR Considerations Municipal Generation may be used to meet Module E capacity requirements and may be registered as: Capacity Resources / Generation (Front-of-Meter generation with a must offer requirement) Capacity Resources / DRR (Behind-the-Meter generation with a must offer requirement) Load Modifying Resources (Behind-the-Meter generation with no must offer requirement but with penalties & possible loss of accreditation upon failure to start)

58. 58 Capacity Side RAR Considerations Accreditation for Capacity Resources will be defined as Unforced Capacity (UCAP) taking into consideration the historical forced outage rate of each respective generating unit as reported via the NERC Generation Availability Data System (GADS) Capacity accreditation criteria for Load Modifying Resources has not yet been defined. (The first year, the installed capacity rating will be used.)

59. 59 Planning Reserve Margin (PRM) Considerations Planning Reserve Margins to be defined separately for each planning zone Planning zones and corresponding PRMs will be defined annually based on transmission limitations generally by identifying areas where the marginal cost of congestion is positive whenever congestion exists. Planning Reserve Margins take into consideration the system average Loss of Load Expectation (LOLE).

60. 60 Other RAR Considerations Details of new RAR requirements are still being worked out as Business Practice Manual (BPM) is developed by the MISO Supply Adequacy Working Group (SAWG) Issues under consideration that will directly impact many Municipal Utilities are: Options available for sharing & exchanging Planning Reserve Credits for LMRs. Start up notification requirements for LMR BTMs (e.g. 12 hours or <10 minutes.) Options to be provided for forming municipal resource sharing pools.

61. 61 Resource Adequacy Requirements Take Aways ... Municipals with Behind-the-Meter generation must choose between: Capacity Resource registration with ICCP costs, must offer requirements and GADS reporting requirements, vs. Load Modifying Resource with penalties and possible loss of accreditation upon failure to run. Municipals should stay involved in the development of RAR market rules to assure fair consideration of local generation resource capabilities & limitations. Municipals opting for LMR BTM should consider forming reserve sharing groups to hedge against the loss of accreditation due to failure to start.

62. 62 Marlin J. Vrbas, P.E.PS Analytics, LLC316 E Klubertanz Dr.Sun Prairie, WI 53590608-834-0646  608-886-3653 (mobile) 608-318-1133 (fax)