Slide 1: PCA Workshop
PCA Workshop me Power.
Slide 2: Simplified Revenue Requirement
Simplified Revenue Requirement Revenue Requirement = r (Rate Base) + Expenses r = Overall Rate of Return
Slide 3: Composite Cost of Capital
Composite Cost of Capital 8.500% 100% 2,000,000,000 Total Capitalization 5.625% 11.250% 50% 1,000,000,000 Common Equity 2.875% 5.750% 50% 1,000,000,000 Long Term Debt Weighted Cost Embedded Cost Capitalization Structure Amount Percent
Slide 4: Revenue Requirement Example
Revenue Requirement Example • If Rate Base = $2 Billion • And r = 8.5% • And Expenses = $570 Million • Then: Rev. Req. = 8.5% ($2 Billion) + $570 Million = $740 Million
Slide 5: In This Example: Return and Expense
In This Example: • Return = r (Rate Base) = 8.5% ($2 Billion) = $170 Million • Expense = $570 Million
Slide 6: Net Power Supply Expenses (NPSE) within Expense Category
Within the Expense Category are Net Power Supply Expenses (NPSE) • Fuel = $135 Million • QF Purchases = $65 Million • Non QF Purchases = $60 Million • - Surplus Sales = $110 Million $150 Million
Slide 7: Variability of NPSE
Variability of NPSE • Low Water (1992) = $310 Million • High Water (1984) = -$10 Million }Range $320 Million $150 Million ± $160 Million = -$10 to $310 Million
Slide 8: Impact of Expense Changes on Rate of Return
Because 8.5% Rate of Return = $170 Million • A $20 Million Change in Net Expenses = 100 Basis Points • A $160 Million Change in NPSE results in an approximate $100 Million Change in Net Expenses due to increased or decreased taxes. • $100 Million = 500 Basis Point shift in actual Rate of Return
Slide 9: Change in NPSE vs Overall Rate of Return
12.5% $270 8.5% $170 3.5% $70 Change in NPSE 40 80 120 160 Change in Net Expenses 25 50 75 100 3.5% 9% 8% Overall Rate of Return 12.5% -1.5% 18.5%
Slide 10: Lower-Than-Allowed Return on Equity
Lower-Than-Allowed Return on Equity Idaho Power– Allowed Vs. Actual Return on Equity 2003-2007 0% 2% 4% 6% 8% 10% 12% 14% 2003 2004 2005 2006 2007 Allowed ROE Actual ROE
Slide 11: Idaho Power Credit Rating History
Idaho Power Credit Rating History Moody’s / S&P A1 / A+ Stable Neg. Moody’s Standard & Poor’s A2 / A A3 / A- Stable Stable Stable Stable Neg. Neg. Stable Stable Neg. Stable Stable Stable Stable Stable Neg. Stable Baa1 / BBB+ Baa2 / BBB Baa3 / BBB- 2000 2001 2002 2003 2004 2005 2006 2007 2008
Slide 12: Interest Cost Comparison by Rating Category
Interest Cost Comparison by Rating Category (30-Year Fixed Interest) Cumulative Customer Pre-tax Impact Interest Costs (Year-end 2007 Utility Bond Rates) $0 $50 $100 $150 $200 $250 $300 A BBB BB Rating Catagory Interest Cost on $100 Bond 30-Year Cumulative Interest Expense on $100 million Bond
Slide 13: Idaho Power Rates vs. National Average
Idaho Power rates vs. National Average 2000 2001 2002 2003 2004 2005 2006 2007 National Average Idaho Power 0 ¢ kWh 2 ¢ kWh 4 ¢ kWh 6 ¢ kWh 8 ¢ kWh 10 ¢ kWh 12 ¢ kWh Residential Rates 2000 2001 2002 2003 2004 2005 2006 2007 National Average Idaho Power 0 ¢ kWh 2 ¢ kWh 4 ¢ kWh 6 ¢ kWh 8 ¢ kWh 10 ¢ kW
Slide 14: Issues
Issues • LGAR • Risk 90/10 Sharing • Forecast Methodology • Base Line Shape for Deferrals • 3rd Party Transmission Expense } SYMMETRY
Slide 15: Issue #1 - LGAR
Issue #1 - LGAR • What is it? The Load Growth Adjustment Rate is multiplied by changes in Load from Test Year Levels with the product either removed from (due to load growth) or added to (due to load decline) actual power supply expense. • What is its purpose? The parties have historically disagreed
Slide 16: Example: Current Rate
Example • Say the Current Rate is 5.4 cents/kWh This is equivalent to $54/MWh • The $54/MWh is based upon a snapshot in time (i.e. Test Year) • The Regulatory Compact suggests that based upon the Test Year, it is reasonable to assume that the ongoing cost to serve customers will be the same as refle
Slide 17: Components Included in the $54/MWh
Included in the $54/MWh are Numerous Components • Transmission: Return on Plant Recovery of Expenses • Distribution: Return on Plant Recovery of Expenses • Generation: Return on Plant Recovery of Expenses
Slide 18: Return and Expenses by Function
Assume Return Expenses • Transmission: $32 Million $108 Million 19% • Distribution: $56 Million $188 Million 33% • Generation: $82 Million $150 Million (NPSE) 48% $124 Million (Other) • Total Return $170 Million • Total Expense $570 Million • Total Revenue Requirement $740 Million
Slide 19: Example of Unbundled Rate Components
Example of Unbundled Rate Components Return Expenses • Transmission: $2.34/MWh $7.88/MWh • Distribution: $4.09/MWh $13.72/MWh • Generation: $5.98/MWh $10.95/MWh (NPSE) $9.05/MWh (Other) • Total Return $12.41/MWh • Total Expense $41.60/MWh • Total Revenue Requirement $54.01/MWh
Slide 20: Historical LGAR Removed
Historical LGAR Removed ($30) ($25) ($20) ($15) ($10) ($5) $0 2001 2002 2003 2004 2005 2006 2007 LGAR $/M (140) (120) (100) (80) (60) (40) (20) - Basis Points
Slide 21: Issue #2: Risk 90/10 Sharing
ISSUE #2: RISK 90/10 SHARING 1] Se Poner.
Slide 22: Impact of 90/10 Sharing on NPSE and ROE
Issue #2 Risk 90/10 Sharing Impact of 90/10 Sharing on NPSE and ROE ($18) ($16) ($14) ($12) ($10) ($8) ($6) ($4) ($2) $0 2001 2002 2003 2004 2005 2006 2007 Unrecovered NPSE $/M (300) (250) (200) (150) (100) (50) 0 Basis Points
Slide 23: Combined Impact of 90/10 Sharing & LGAR
Combined Impact of 90/10 Sharing & LGAR ($45) ($40) ($35) ($30) ($25) ($20) ($15) ($10) ($5) $0 2001 2002 2003 2004 2005 2006 2007 Unrecovered NPSE $/M (400) (350) (300) (250) (200) (150) (100) (50) - Basis Points
Slide 24: Issue #3: Forecast Methodology
ISSUE #3: FORECAST met
Slide 25: PCA Forecast Issues
PCA Forecast What are the issues associated with the PCA Forecast? 1. Cash flow 2. Sending appropriate pricing signals to our customers The current forecast methodology worked well in the 90’s; however fundamental changes in the market have occurred since the PCA was implemented. Net Power Supply co
Slide 26: PCA Forecast vs. Actual
PCA Forecast vs. Actual Net Power Supply Exp. above Base ($50.0) $0.0 $50.0 $100.0 $150.0 $200.0 $250.0 PCA Forecast $33.4 $38.1 $35.7 $61.3 ($37.6) $28.3 NPSE $115.0 $114.8 $102.3 $34.5 $90.8 $190.4 2002/2003 2003/2004 2004/2005 2005/2006 2006/2007 2007/2008 $ millions Let’s take a closer look at t
Slide 27: PCA Forecast vs. Actual – Add Op Plan
PCA Forecast vs. Actual Net Power Supply Expense above Base – Add Op Plan ($50.0) $0.0 $50.0 $100.0 $150.0 $200.0 $250.0 PCA Forecast ($37.6) $28.3 NPSE $90.8 $190.4 Op Plan Forecast 39.3 75.2 2006/2007 2007/2008 Improvement of ~$77 Million Improvement of ~$47 Million $ millions
Slide 28: PCA Forecast: Operating Plan Alternative
PCA Forecast Idaho Power’s Operating Plan, which is produced at least monthly, as a part of Idaho Power’s risk management process, is an example of another alternative for forecasting PCA costs. The Op Plan considers: – Forward market prices – Forecast PURPA resource production – Actual hedge transa
Slide 29: Issue #4: Base Line Shape for Deferrals
ISSUE #4: BASE LINE SHAPE FOR DEFERRALS
Slide 30: Preview
Preview Background • Base Net Power Supply Expense • Relevance to the PCA “true-up” mechanism • Present the various Base NPSE shapes used or considered The Problem • Defined • Examples and demonstration
Slide 31: Background: 2007 Base Net Power Supply Expense
Background • 2007 Base Net Power Supply Expense (NPSE) – Includes: • $124.9 million including Danskin addition • Non-qualifying Facilities: fuel expense & purchased power net of surplus sales • Qualifying Facilities: PURPA contracted purchased power – Embedded in base electricity rates • Relevance t
Slide 32: Base Net Power Supply Expense
Base Net Power Supply Expense $124.9 million $ millions ($10.0) ($5.0) $0.0 $5.0 $10.0 $15.0 $20.0 $25.0 $30.0 $35.0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2003 Shape (2005) 2007 Shape Even Distribution Normalized Sales Shape
Slide 33: The Problem
The Problem • Our Financial Communication Goal - – Transparency – Quarterly financial results should reflect positive or negative deviation from a normalized viewpoint... • Return on Investment • Changes in operating conditions • The Problem - – Base NPSE as used in the PCA causes confusion to our s
Slide 34: Examples: Assumptions
Examples: Assumptions The Only Variable • The shape of Base NPSE used in the PCA calculation: The Constants • Revenues equal the collection of embedded NPSE normalized MWh sales X embedded rate (Base NPSE / normalized MWh sales) • Base NPSE = $124.9 million; “Actual” NPSE = $250 million • 90/10 Shar
Slide 35: Quarterly Impact: 2007 Shape
Quarterly Impact: 2007 Shape Presented amounts are for demonstration purposes only. 1st Q 2nd Q 3rd Q 4th Q Total Revs (Embedded NPSE) $29.2 $30.0 $36.3 $29.4 $124.9 NPSE 50.0 70.0 80.0 50.0 250.0 PCA Deferral: Base 1.8 15.7 73.1 34.4 124.9 NPSE 50.0 70.0 80.0 50.0 250.0 PCA Deferral (48.2) (54.3) (
Slide 36: Quarterly Impact: 2003 Shape (2005)
Quarterly Impact: 2003 Shape (2005) Presented amounts are for demonstration purposes only. 1st Q 2nd Q 3rd Q 4th Q Total Revs (Embedded NPSE) $29.2 $30.0 $36.3 $29.4 $124.9 NPSE 50.0 70.0 80.0 50.0 250.0 PCA Deferral: Base 15.7 28.2 49.4 31.6 124.9 NPSE 50.0 70.0 80.0 50.0 250.0 PCA Deferral (34.3)
Slide 37: 1st Quarter Example: Shape Impacts
1st Quarter Example: Shape Impacts The Only Variable • The shape of Base NPSE used in the PCA calculation: $ in millions 1st Q 2nd Q 3rd Q 4th Q Total 2007 Shape $1.8 $15.7 $73.1 $34.4 $124.9 2003 Shape (2005) $15.7 $28.2 $49.4 $31.6 $124.9 Even Distribution $31.2 $31.2 $31.2 $31.2 $124.9 Norm Sales
Slide 38: 1st Quarter Focus: Base NPSE Shape Impacts
1st Quarter Focus: Base NPSE Shape Impacts 2007 2005 Even Sales Shape Shape Distribution Distribution Revs (Embedded NPSE) $29.2 $29.2 $29.2 $29.2 NPSE 50.0 50.0 50.0 50.0 PCA Deferral: Base 1.8 15.7 31.2 29.2 NPSC 50.0 50.0 50.0 50.0 PCA Deferral (90/10) (43.4) (30.8) (16.9) (18.7) Op Income (Loss)
Slide 39: Impact of Base Changes: PCA Deferral
Impact of Base Changes: PCA Deferral $ millions Presented amounts are for demonstration purposes only. $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 $140.0 1st Q 2nd Q 3rd Q 4th Q 2003 Shape (2005) 2007 Shape Even Distribution Normalized Sales Shape No matter what shape is used, the total amount to be
Slide 40: Impact of Base Shape Changes: Cumulative Op Income
Impact of Base Shape Changes: Cumulative Op Income $ millions Presented amounts are for demonstration purposes only. ($20.0) ($10.0) $0.0 $10.0 $20.0 $30.0 $40.0 1st Q 2nd Q 3rd Q 4th Q 2003 Shape (2005) 2007 Shape Even Distribution Normalized Sales Shape No matter what shape is used, the total amou
Slide 41: Key Takeaways
Key Takeaways • Our Financial Communication Goal is not met.... Customers, Shareholders, Debt Holders, Future Investors – Stakeholder Confusion: • Quarterly financial results are difficult to understand • Results contradict what is general news – Lacks Transparency: • External financial community re
Slide 42: Issue #5: 3rd Party Transmission
ISSUE #5: 3rd PARTY TRANSMISSION
Slide 43: 3rd Party Transmission
3rd Party Transmission • 3rd Party Transmission expenses and losses are directly related to the power supply expenses (purchases and sales) incurred to balance and optimize Idaho Power’s system. • There can be a high degree of variability in 3rd Party Transmission expense from year-to-year. • The PC
Slide 44: 3rd Party Transmission
3rd Party Transmission • 3rd Party Transmission expenses, and losses, can be a big number! • Idaho Power has not fully recovered 3rd Party Transmission expenses in any year since 2001. • From 2002 through 2007, the cumulative amount of under recovery is approximately $12.5 million.
Slide 45: 3rd Party Transmission Expense vs. Amount in Rates
3rd Party Transmission $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 3rd Party Trans Exp 1.6 5.4 6.8 6.3 8.7 12.9 8.4 Amount in Rates 1.5 1.5 5.4 5.4 7.7 7.7 7.2 2002 2003 2004 2005 2006 2007 2008 Estimated $ millions FERC 890
Slide 46: 3rd Party Transmission Cumulative Under Recovery
3rd Party Transmission $0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 $14.0 $16.0 Cumulative Under Recovery 0.1 4.0 5.4 6.2 7.2 12.5 13.7 2002 2003 2004 2005 2006 2007 2008 FERC 890 Estimated $ millions
Slide 47: What Drives 3rd Party Transmission Expenses
3rd Party Transmission What drives Idaho Power’s 3rd Party Transmission expenses? • Streamflows: – overall amount of hydro generation – distribution/timing of hydro generation – operational considerations: e.g., timing of flow augmentation, flood control operations, etc. • Energy Risk Management Pol
Slide 48: 3rd Party Transmission Expense Distribution
3rd Party Transmission Estimated Example 3rd Party Transmission Expense Distribution (including losses) 4.0 6.0 8.0 10.0 12.0 14.0 16.0 0.0 5.0 10.0 15.0 20.0 Brownlee Annual Inflow Volume Million $ Median = 11.6 MAF, 2006 IRP 3rd Party Transmission Expense Distribution (2008 & 2009) (including loss
Slide 49: Actual 3rd Party Transmission Expense 2003-2007
3rd Party Transmission Actual 3rd Party Transmission Expense 2003-2007 (including losses) 4.0 6.0 8.0 10.0 12.0 14.0 16.0 0.0 5.0 10.0 15.0 20.0 Brownlee Annual Inflow Volume Million $ 2007 2004 2003 2005 2006 ~ $6 Million
Slide 50: 3rd Party Transmission Conclusions
3rd Party Transmission Conclusions: • Idaho Power is not recovering 3rd Party Trans. Exp. • Idaho Power’s border points (LaGrande, Lolo, Enterprise, Midpoint, Borah/Brady, etc.) are not regional market hubs. • 3rd Party Transmission expenses are necessary to balance our system and import or export e