1. Base Case Rocky Mountain Area Transmission Study Presentation to Steering Committee February 5, 2004

2. RMATS 2 Revised inputs  Monitor/enforce constraints on an additional 4 paths Naughton to Ben Lomand; Yellowtail N and S; Sierra total imports  Modify the way in which 2 additional paths are monitored Brownlee East and Flaming Gorge to Bonanza Also increase Brownlee East by 100 MW to 1850<W  Refine schedules for planned maintenance  Correct and update certain loads Adjust NW load flow data for change in aluminum smelters loads; add upper Missouri loads; zero out the negative loads in SSG-WI data for DC ties to Eastern Interconnect  Calculate average LMPs on seasonal as well as annual basis January and June months selected Changes since January 26 Technical Review

3. RMATS 3 Additional validation  Address discrepancy in COI and Pacific DC duration curves Model is loading DC less than actual practice Combine COI and the DC for comparison purposes Apply nomogram to enforce split of flows between DC and AC  Address discrepancy in TOT 2 Additional info  SCIT duration curve Examine discrepancy between modeling results and actuals  Compare base case load forecast to WECC forecast  Document process and key assumptions for load forecast (in progress – LFWG)  Examine dispatch of thermal units Esp. minimum run Changes since January 26 Technical Review

4. RMATS 4 Additional runs  Run “unconstrained” cases for internal RMATS paths only and for top 5 RMATS congested paths only, as well as for all Western Interconnect  A first look: transmission to address congestion in 2008 IPP DC line: Determine change in system-wide variable costs (VOM) if 500 MW capacity is added SW Wyoming to Bonanza: Determine change in VOM if line rating is increased by100 MW Idaho to Montana: Determine change in VOM if phase shifter added Changes since January 26 Technical Review

5. RMATS 5 Presentational improvements  Further clarify model capabilities and limitations  Clarify certain input and modeling assumptions For example, wind resource hourly shape assumptions, heat rates not adjusted for elevations, wheeling charges not included in LMP prices  Enhance contour maps Expand geographic scope and focus on time periods of greatest congestion  Add certain calculations to slides Add mean, Std Dev., and correlations to duration curves  Remove net position slides  Further refine formatting of duration curves  Editorial fixes Changes since January 26 Technical Review

6. RMATS 6 Base Case Observations  In concept, transmission congestion (bottlenecks) and losses cause differences in marginal prices at the nodal/bus level (LMPs) In this modeling, transmission congestion drives differences in LMPs  LMPs are calculated separately for loads and generation In the base case, the lowest LMPs for loads are at Laramie River, Colorado-West, and Yellowtail Lowest LMPs for generation are at Laramie River, Colorado-West, and Bonanza Indicates generation is bottled up  LMPs tend to decrease as relatively low cost resources are added High wind capacity sensitivity is an example  Targeted transmission investments would levelize/stabilize marginal prices because congestion is relieved Sensitivities were run to explore the change in VOM costs if constraints are removed – all constraints west-wide, constraints internal to the Rocky Mountain sub-region only, and constraints on Rocky Mountain import/export paths only VOM cost savings would be significant and reach broadly Such savings alone do not justify making investments, however. Investment costs and other factors must also must be considered

7. RMATS 7 Base Case Observations  The top 5 congested paths in the Rocky Mountain sub-region are also export-related paths: Idaho to Montana TOT 2C Bridger West IPP DC TOT 3  The top 5 congested paths at $4 gas price are also the top 5 at $5 gas price Dispatch ranking of plants is unchanged Exception: high wind capacity sensitivity  Analysis includes a first look at opportunity costs (congestion costs) and potential solutions for three of the top 5 congested paths  Next steps: consider other alternative transmission solutions for 2008, determine capital costs, determine technical feasibility

8. RMATS 8

9. Locational Marginal Prices (LMPs)

10. RMATS 10 LMP Prices Average Annual Load LMPGeneration LMP $4 Gas/ 2008 Load $4 Gas/ High Wind $4 Gas/ High Load $5 Gas/ 2008 Load

11. RMATS 11 January 2008 Monthly Average LMP $4 Gas

12. RMATS 12 June 2008 Monthly Average LMP $4 Gas

13. RMATS 13 Jan 24, 2008 hr 03 $4 Gas

14. RMATS 14 Jan 24, 2008 hr 06 $4 Gas

15. RMATS 15 Jan 24, 2008 hr 07 $4 Gas

16. RMATS 16 Jan 24, 2008 hr 10 $4 Gas

17. RMATS 17 Jan 24, 2008 hr 14 $4 Gas

18. RMATS 18 Jan 24, 2008 hr 17 $4 Gas

19. RMATS 19 Jan 24, 2008 hr 24 $4 Gas

20. RMATS 20 June 12, 2008 hr 03 $4 Gas

21. RMATS 21 June 12, 2008 hr 06 $4 Gas

22. RMATS 22 June 12, 2008 hr 09 $4 Gas

23. RMATS 23 June 12, 2008 hr 12 $4 Gas

24. RMATS 24 June 12, 2008 hr 15 $4 Gas

25. RMATS 25 June 12, 2008 hr 18 $4 Gas

26. RMATS 26 June 12, 2008 hr 21 $4 Gas

27. RMATS 27 June 12, 2008 hr 24 $4 Gas

28. RMATS 28

29. Evaluation of Rocky Mountain (RM) Area Congested Paths

30. RMATS 30 Rocky Mountain Area Path & Ratings Diagram

31. RMATS 31 Key RM Transmission Constraints $4 gas, 2008 loads, base case wind InterfaceLocation [Direction] Forward limit (MW) Reverse limit (MW) Opportunity cost of next MW % hours congested Idaho to MontanaE. Idaho to W. Montana [S – N] 337 $28,3245% TOT 2CS. Utah to S.E. Nevada [N – S] 300 $11,70615% Bridger WestS.W. Wyoming to S.E. Idaho & to Northwest [E – W] 2,200N/A$10,74919% IPP DCC. Utah to S. California [NE – SW] 1,920300$10,14172% TOT 3S.E. Wyoming to N.E. Colorado [N – S] 1,424N/A$5,6498% SW Wyoming to Bonanza* S.W. Wyoming to E. Utah [N – S] 200 $2,5903% * $4 Gas- H load- $26,325; 12%

32. RMATS 32 Opportunity Costs- RMATS Savings if increase path by 1 MW Sorted

33. RMATS 33

34. RMATS 34 Idaho to Montana Duration Curve S N

35. RMATS 35 Idaho to Montana ($4 gas, 2008 loads, high wind capacity) Base Case 2008 Opportunity cost of not increasing the line by 1 MW: $19,047 Forward limit (S – N): 337 MW Reverse limit (N – S): -337 MW Power flowing south is congested 3% of all hours Blue line is reverse limit S N Black line is forward limit 1,042,362 MWh Potential Line Loading represents that the interface was modeled with no constraints on all WI paths 1,373,642 MWh 576, 174 MWh/ 15%

36. RMATS 36 TOT 2C Duration Curve N S

37. RMATS 37 TOT 2C ($4 gas, 2008 loads, high wind capacity) Base Case 2008 Opportunity cost of not increasing the line by 1 MW: $20,341 Forward limit (N – S): 300 MW Reverse limit (S – N): -300 MW Power flowing south is congested 23% of all hours N S 1,687,891 MWh 1,579,072 MWh 708,400 MWh/ 19% 40,864 MWh/ 1%

38. RMATS 38 Bridger West Duration Curve W

39. RMATS 39 Bridger West ($4 gas, 2008 loads, high wind capacity) Base Case 2008 Opportunity cost of not increasing the line by 1 MW: $43,690 Forward limit (E – W): 2,200 MW Reverse limit (W – E): N/A Power flowing west is congested 36% of all hours EWEW E W 17,149,430 MWh 17,913,183 MWh EWEW 9,520,533 MWh/ 45%

40. RMATS 40 IPP DC Duration Curve NE SW

41. RMATS 41 IPP DC ($4 gas, 2008 loads, high wind capacity) Base Case 2008 Opportunity cost of not increasing the line by 1 MW: $13,067 Forward limit (NE – SE): 1900 MW Reverse limit (SW – NE): -1400 MW Power flowing south-east is congested 72% of all hours NE SW 17,147,800 MWh15,041,672 MWh 10,076,000 MWh/ 58%

42. RMATS 42 TOT 3 Duration Curve N S

43. RMATS 43 TOT 3 ($4 gas, 2008 loads, high wind capacity) Base Case 2008 Opportunity cost of not increasing the line by 1 MW: $8,259 Forward limit (N – S): 1424 MW Reverse limit (S – N): NA Power flowing south-east is congested 10% of all hours N S 7,880,417 MWh 8,903,396 MWh N S 1,418,324 MWh/ 10%

44. RMATS 44 SW Wyoming to Bonanza Duration Curve N S

45. RMATS 45 SW Wyoming to Bonanza ($4 gas, 2008 loads, high wind capacity) Base Case 2008 Opportunity cost of not increasing the line by 1 MW: $695 Forward limit (N – S): 265 MW Reverse limit (S – N): -300 MW Power flowing north is congested 1% of all hours N S 739,634 MWh 366,427 MWh/ 17%

46. RMATS 46

47. Western Interconnect Path Constraint Sensitivities

48. RMATS 48 Western Interconnect Impact for 2008 $4 gas, 2008 loads, High Wind Interface limitation Annual VOM ($000) Delta from Base Annual VOM ($000) Annual average LMP Delta from base annual average LMP Load ($/MW) Generator ($/MW) Load ($/MW) Generator ($/MW) Base Case 13,683,64637.9737.24 All interfaces unconstrained 13,562,347(121,299)38.0938.08.12.84 Only internal RM interfaces are unconstrained 13,642,615(41,031)38.0137.41.04.17 Only top 5 congested interfaces are unconstrained 13,691,688(8,042)38.0337.41.06.17

49. RMATS 49 Idaho to Montana Duration Curve Path Constraint Sensitivities S N

50. RMATS 50 TOT 2C Duration Curve Path Constraint Sensitivities N S

51. RMATS 51 Bridger West Duration Curve Path Constraint Sensitivities W

52. RMATS 52 IPP DC Duration Curve Path Constraint Sensitivities NE SW

53. RMATS 53 TOT 3 Duration Curve Path Constraint Sensitivities N S

54. RMATS 54 SW Wyoming to Bonanza Duration Curve Path Constraint Sensitivities N S

55. Evaluation of Potential Solutions

56. RMATS 56 Idaho to Montana ($4 gas, 2008 loads, base case wind) Potential solution  Potential Solution Added phase shifter at Peterson Flats to Amps  Results System-wide “VOM” cost decreases by ~$5 million in 2008 Decreases binding congestion to 1% from 5% of the time Path loading increases by 1,673 MWh 1,102,119 MWh 1,103,792 MWh 5% 1% S N BEFORE AFTER

57. RMATS 57 IPP DC ($4 gas, 2008 loads, base case wind) Potential solution  Potential Solution Increased line rating by 500 MW NE to SW (Forward limit ~ 2400 MW)  Results System wide “VOM” cost decreases by ~$4.6 million Line loading increases by 2,863,577 MWh Decreases binding congestion to 57% from 72% of the time 14,952,799 MWh 17,816,376 MWh 72% 57 % NE SW BEFORE AFTER

58. RMATS 58 SW Wyoming to Bonanza ($4 gas, 2008 loads, base case wind) Potential solution  Potential Solution Increased line rating by 100 MW (increase line limit to 300 MW from 200MW); this can be accomplished by adding a transformer and possibly line compensation.  Results System wide cost decreases by ~$4.3 million; hydro model does not allow hydro redispatch. Line loading increases by 7,170 MWh Alleviates binding congestion, which now occur 3% of the time 902,434 MWh 909,604 MWh 3% N S BEFORE AFTER

59. RMATS 59 Next Steps Potential Solutions  Proposed transmission solutions were tested based on VOM cost savings  Capital costs are not considered (TAWG)  Power Flow/Stability analysis should be run to confirm technical feasibility; other solutions should be examined (e.g., FACTS device instead of phase shifters, etc.)  Measured savings apply to the entire Western Interconnect; this raises question about sharing the costs 9

60. RMATS 60

61. Benchmarking

62. RMATS 62  The objective is to compare patterns of path loading  Applies to all paths Added about 1600 MW of resources to the SSG-WI 2008 case Compares 2002 actual loads to 2008 base case PDCI line flow is less than historic loadings; low load is caused by absence of contractual rights, tariff wheeling and tariff loss charges  Must consider modeling limitations when drawing conclusions Benchmarking

63. RMATS 63 Idaho to PNW Duration Curve Observation/Qualification  Path compares incredibly close; 99.4% correlation factor when comparing RMATS to actual  Minimal regional resources added

64. RMATS 64 West of Hatwai Duration Curve Observation/Qualification  Path compares incredibly close; 99.7% correlation factor when comparing RMATS to actual  Minimal regional resources added

65. RMATS 65 Montana to PNW Duration Curve Observation/Qualification  Path compares close; 99.4% correlation factor when comparing RMATS to actual  Minimal regional resources added

66. RMATS 66 COI Duration Curve  COI - Taxed heavier in the south to north direction than was in SSG-WI  Baring some of the PDCI load  Hydro peak shaving algorithm

67. RMATS 67 Path 26 Duration Curve  Path 26 - Between PG&E and Southern California Edison (Midway to Vincent; 3-500 kV lines)  Compares favorably with historic  One of the artifacts of not having wheeling; using the AC more than the DC

68. RMATS 68 SCIT Duration Curve  Southern California Import Transmission Nomogram (SCIT): Sum of Midway, PDCI, IPP, North of Lugo, and WOR  Market Place to Adelanto was left out in the SSG-WI model (counted twice; negative and positive, canceling each other out)  CISO no longer strictly enforces this path in their planning studies

69. RMATS 69 East of the River Duration Curve  The SSG-WI line was considered to be reasonable by the SSG-WI planning group, given new resource additions

70. RMATS 70 TOT2 (A+B+C) Duration Curve  TOT2 - discrepancy with historic is do to "glut" of generation in Arizona

71. RMATS 71 TOT 2B1 Duration Curve Pinto-Four Corners 345 kV  TOT2 - discrepancy with historic is do to "glut" of generation in Arizona

72. RMATS 72 TOT 2B2 Duration Curve Glen Canyon to Sigurd (230kV)  TOT2 - discrepancy with historic is do to "glut" of generation in Arizona

73. RMATS 73 TOT 2C Duration Curve Harry Allen-Red Butte  TOT2 - discrepancy with historic is do to "glut" of generation in Arizona

74. RMATS 74

75. Plant Performance

76. RMATS 76 Selected Unit Production: $4 Gas- H Wind

77. RMATS 77 Capacity Factors by Fuel Western Interconnect* RMATS* *Excludes Gas Peaker Units