IRP Public Input Meeting. July 27, 2004

Transcription

1 IRP Public Input Meeting July 27, 2004

2 Agenda» Market Price Forecast» DSM Update» Update on Planning Margin Study (Bathtub chart)» Update on Capacity Expansion Model» Proposed Stress Cases» Portfolio Development Process» Treatment of Short Term Contracts in the IRP» Distributed Generation» Next Steps 2

3 Market Price Forecast Jim Henry and Rick Link

4 Agenda - Market Clearing Price Model» Model background» Key Assumptions» Forward power prices Forward price users Components Findings Sensitivities 4

5 Model Background

6 MIDAS Gold - Introduction» Licensed from MS Gerber (owned by Global Energy Decisions Co. ) User support Data delivery Updates» Powerful planning and analysis module Ability to model complex scenarios Flexible to user-defined inputs Decision framework ability to recognize uncertainties in fundamental drivers» Chronological, hourly dispatch 6

7 Fundamentals Drive Long-term Forecast Resources Size Location Heat rates VOM Min/Max cap Emis. Rates New capacity Hydro Demand Load shapes Reserves Growth rates PacifiCorp WECC Transmission Limits Wheeling Consumables Fuel Emission costs MIDAS Market Prices 7

8 WECC Load Centers & Transmission Topology» Transmission limits represent Total Transfer Capability» Midas is blind to transmission ownership 8

9 Model Logic: Supply/Demand & Marginal Pricing P E V E V E V» By Hour $/MWh V F Nuke E V F Coal F MW F Gas F D» By Load Center Legend F = Fuel V = VOM E = Emissions P = Price D = Demand 9

10 Model Logic: Resource Scarcity Premiums» Reflects ability of sellers to charge higher prices in scarcity situations» Energy costs + a premium when demand stretches available resources D Value of Energy $/MWh P 2 P 1 Scarcity Premium Operating Cost 0% 70% 75% 80% 85% 90% 95% 100% % of Resource Base P = Price, D = Demand 10

11 Model Logic: Transmission MONT $60 $45 MW SP15 MW WYOM $15 $130 $35 $50 $55 11

12 Model Logic: Supply/Demand & Marginal Pricing (part 2) P E V E V S W E V» By Hour $/MWh V F Nuke E V F Coal F MW F Gas F D» By Load Center Legend F = Fuel V = VOM E = Emissions W = Wheeling S = Scarcity P = Price D = Demand 12

13 Model Logic: Economic Resource Additions» Compares revenues to dispatch costs among potential new resource options» Operating Costs include fuel, Variable O&M and emission costs.»fixed Costs include capital and Fixed O&M.» Revenues > costs = positive margin, resource added = Combustion Turbine (Operating Costs) = Combine Cycle (Operating Costs) $/MWh Hours 13

14 Model Logic: Reliability Resource Additions» Planning reserve margins assumed at 15%» Economic additions not always enough to satisfy planning reserves» Options having least negative margins added until reserves are met 14

15 Key Assumptions

16 Key Assumptions: Load Growth Peak Demand 2005 Projected Peak (MW) Average Demand Growth 2005 Projected Energy (GWh) Net Load Average Energy Growth ALBE 9, % 64, % PALO 15, % 73, % BAJA 2, % 10, % BCHA 10, % 61, % MONT 1, % 9, % NP15 22, % 106, % MEAD 5, % 25, % NEVA 1, % 12, % MIDC 26, % 146, % SP15 33, % 167, % IDAH 3, % 20, % UTAH 4, % 32, % COLO 8, % 47, % FCRN 4, % 27, % WYOM 1, % 11, % COB 1, % 7, % WECC Total 144, % 824, % Source: WECC, PacifiCorp, MS Gerber 16

17 Key Assumptions: New Resource Cost and Performance Resource Type Size (MW) Capital ($/kw) Fixed ($/kw-yr) VOM ($/MWh) Heat Rate (Btu/kWh)* 2x1 CC (Dry) ,462 2x1 CC (Wet) ,186 Duct Fire (Dry) ,512 Duct Fire (Wet) ,868 SCCT Aero ,352 SCCT 7FA ,990 Utah Coal 575 1, ,483 Montana Coal 575 1, ,483 Idaho Coal 575 1, ,483 Colorado Coal 575 1, ,483 Four Corners Coal 575 1, ,483 Palo Coal 575 1, ,483 Mead Coal 575 1, ,483 * Heat rates improve for all but coal by 1% - 2% in 2011 and 2018 to represent technology improvements 17

18 Key Assumptions: Natural Gas» Future price of natural gas is the most important component of power price forecast» Blend of market quotes and fundamentally derived natural gas curve from PIRA Energy Group» Gas prices for the IRP are calculated as follows: West = Average (Sumas, Stanfield, Rockies) + transportation East = Rockies + transportation» Adjustments for CO2 sensitivities PacifiCorp is participating in a multi-client study being generated by CERA A series of natural gas forecasts based upon a range of scenarios PacifiCorp will consider using the CERA study to derive natural gas forecast for sensitivity studies 18

19 West - Natural Gas Prices $8 $7 $6 $5 $/mmbtu $4 $3 $ IRP 2004 IRP $1 $

20 East - Natural Gas Prices $8 $7 $6 $5 $/mmbtu $4 $3 $ IRP 2004 IRP $1 $

21 Key Assumptions: Environmental Costs SO 2 ($/ton) NO X ($/ton) Hg ($/lb) CO 2 ($/ton) CY ,105 40, ,158 41, ,210 42, ,265 44, ,321 45, ,393 46, ,028 2,468 47, ,061 2,547 49, ,096 2,631 51, ,133 2,720 52, ,172 2,813 54, ,212 2,908 56, ,254 3,010 58, ,298 3,115 60, » All prices but CO2 derived from PIRA forecasts» SO2: assumes tighter restrictions on emissions in 2010 leading to reduction in current national cap (~ 50% reduction)» NOX: assumes western states will have a 2010 emissions cap requiring SCR on the margin» Hg: 2010 cap-and-trade mercury policy hitting inflation adjusted $35k backstop» CO2: delayed timing (little activity since last IRP) and probability weighted prices in

22 Key Assumptions: Miscellaneous Average Annual Inflation Rate % 2.94% 3.48% Capital Charge Rates CT CC Coal 9.93% 10.13% 8.39% Planning Reserve 15% (7 planning areas) RTO Grid West and West Connect in 2007: Export fees implemented, eliminates pancaked wheeling within RTO, $1 wheel within to account for line losses Resource Additions and Retirements Pre-specified RPS Retirements 25,047 MW ~ 9,500 MW 9,249 MW Hydro Median hydro conditions: ~255,000 GWh 22

23 Forward Power Prices

24 Forward Price Curve Users» Updated quarterly» Single, consistent forward price curve used throughout the company IRP Risk Management Financial Statements: mark-to-market accounting of FAS 133 contracts Regulation» Each update undergoes rigorous review and validation Internal risk management review and external audit Sarbanes-Oxley compliance 24

25 Forward Price Curve Components» Market: actual market quotes from front office (3 years)» Blending: gradual transition to Midas Gold forecast (3 years)» Fundamentals: Midas Gold outputs (through 2023)» Extrapolation: growth at inflation (beyond 2023) 100 Blending 80 Market $/MWh Fundamentals Extrapolation

26 Power Price Comparison: MidC 7x24 Calendar Year Average $80.00 $70.00 $60.00 $50.00 $/MWh $40.00 $30.00 $20.00 $ IRP 2003 IRP $

27 Power Price Comparison: Palo 7x24 Calendar Year Average $80.00 $70.00 $60.00 $50.00 $/MWh $40.00 $30.00 $20.00 $ IRP 2003 IRP $

28 Power Price Sensitivities» CO2 Sensitivities $0/ton $10/ton (1990 $) $25/ton (1990 $) $40/ton (1990 $)» Gas prices Gas price assumptions will be adjusted to reflect changes in gas demand with various CO2 costs Magnitude of gas price adjustments are pending (CERA multiclient) 28

29 New DSM Programs Mike Koszalka

30 Class 1» Commercial and Industrial Lighting Load Control 10 year program. Initial launch in Utah. Build up to 27 MW of load control by CY2008 Includes 1.4 MWa of Class 2 DSM Currently in contract negotiations with selected vendor Expect a contract by the end of 2004 Program design and tariff review by UT DSM Advisory Group by the end of Tariff filing, approval and program launch in first quarter of

31 Class 2» Residential New Construction Incentives (UT) 5 year program, 20,732 MWh (2.37 MWa) of savings 7,500 single-family units; 2,200 multi-family units (about 10% of new construction) Detailed program design in progress Determination of individual measure savings being finalized Survey underway to determine building practices and market size Contract negotiations with selected vendor in progress Expect preliminary program design to reviewed by UT DSM Advisory Group August Final program design and tariff filing to be completed by September, 2004 Program launch in October, 2004» Commercial Re-Commissioning (UT) 5 year program, 129,444 MWh (2.1 MWa) of savings. Peak reduction of 5.3 MW Contract negotiations with selected vendor in progress Program concept/design to be reviewed by UT DSM Advisory Group in August. Expect program design and tariff filing to be completed by November, Program launch in first quarter of

32 IRP 2003 DSM Plan (FY ) 2012)» Class 1 Cool Keeper program, build up to 90 MW (at meter) of load control in FY 2007» Class MWa of base programs DSM from PacifiCorp 123 MWa from the Energy Trust of Oregon 269 MWa total of planned DSM programs (base case) Planning decrements to determine value of additional DSM were run through the Prosym model: 150 MW and 300 MW load decrements were modeled at various load shapes. 32

33 IRP 2003 Progress/Update (FY ) 2012)» Class 1 Cool Keeper on track to achieve 90 MW (at meter) in FY2007 Currently at 27.5 MW ID Irrigation Load Control added at 35 MW (at meter) Commercial Lighting Load Control added at 27 MW by FY2009 Total of 152 MW (at meter) of load control Modeling additional load control programs as peaking units based on DSM RFP 2003 data.» Class MWa of base programs DSM from PacifiCorp 94 MWa from the Energy Trust of Oregon 260 MWa total of planned DSM programs (base case) Planning decrements to determine the value of additional DSM will be run through the Prosym model at various load shapes 33

34 Estimate of DSM Impact on System Peak (FY ) 2012) Class MW at meter 172 MW at generator Class MWa at meter 297 MW at time of peak Total System Peak Impact builds to: 469 MW 34

35 Update on Planning Margin Study (Bathtub chart) Chris Turner

36 Update on Planning Margin Study» Results of Planning Margin Study were presented on June 10, 2004» PacifiCorp s rationale for using the 1 day in 10 years LOLP criteria for the planning margin target was questioned Many utilities use the probabilistic criteria of LOLP over a deterministic criteria such as largest unit for reserve margin A common reserve margin LOLP metric is 1 day in 10 years The LOLP index is a mathematical concept measuring the probability that load cannot be met. The main difficulty with LOLP is the metric is based on judgment, there is no bullet proof reason why 1 day in 10 years is best.» PacifiCorp was asked to use a cost of unserved energy approach, i.e. produce a bathtub chart, which clearly shows the cost tradeoff of EUE at different planning margins. 36

37 Description of Bathtub Chart» X-Axis: Planning Margins Study was run at various planning margin levels using the capital costs of adding SCCT s» Primary Y-Axis: $/year The calculation for the y-axis for each level of planning margin would be (EUE x Cost of EUE ) + ($/yr of capital cost). EUE costs from EPRI study ranged from $5,210/MWh to $44,910/MWh* The capital cost component is the MW SCCT added x 1000 x $72/kw-yr.» Secondary Y-Axis: EUE (MWh) MWh s of EUE at each planning margin level * Many studies have been conducted on the cost of unserved energy. These costs are for PG&E s system from EPRI report EL-6791, Cost- Benefit Analysis of Power System Reliability: Determination of Interruption Costs. Note: EUE = Expected Unserved Energy 37

38 Bathtub Chart $1,300,000 The Planning Margin Tradeoff (Capital Investment vs Customer Outage) 30,000 $1,200,000 $1,100,000 $1,000,000 Residential $6,590 Small LP $44,910 Large LP $15,290 Agricultural $5,210 25,000 SCCT Capital Cost + EUE Cost ($000's/year) $900,000 $800,000 $700,000 $600,000 $500,000 $400,000 $300,000 Weighted $24,000 EUE Economic Efficiency 15% Planning Margin which is equivalent to ~ 2 days in 10 years 20,000 15,000 10,000 EUE (MWh) $200,000 5,000 $100,000 $0 6.3% 7.5% 8.6% 9.7% 10.8% 12.0% 13.1% 14.0% 15.0% 15.9% 16.9% 17.8% 18.8% 19.7% 20.7% 21.6% 22.6% Planning Margins 0 38

39 Observations» The Bathtub chart analysis provides no compelling reason to change from a 15% Planning Margin» Results of bathtub analysis is based on PacifiCorp specific analysis instead of historical 1 day in 10 LOLP criteria Cost of unserved energy approach is an extension of the LOLP study presented in the last public input meeting Moving from a 18% to 15% Planning Margin results in ~ MW less requirement over the ten year horizon Increases the risk of LOLP from 1 days in 10 years to approximately 2 days in 10 years» Based on the results of our studies and feedback from participants, PacifiCorp feels 15% is the appropriate Planning Margin» Comments? 39

40 Update on Capacity Expansion Model Stan Williams

41 Agenda - Capacity Expansion Model (CEM)» Review IRP modeling approach» Provide update on model description» Update on model validation and use 41

42 The IRP Analytical Approach» 1. Portfolio Development Add new resources to incumbent portfolio to develop candidate portfolios CEM does not replace manual methods» 2. Operational Simulation (PROSYM) Deterministic, hourly cost simulations Hourly cost schedule for each portfolio» 3. Analyze Costs Narrow list to the best PVRRs» 4. Stochastic Risk Analysis Simulate each portfolio under a large number of possible futures Sensitivities to assumptions about the future Reveal the cost variability of each portfolio Result: Best portfolio(s) from perspectives of cost and risk Portfolio Development Operational Simulation (PROSYM) Analyze Costs For Best Performers (PVRR) Risk Analysis Stochastic Runs 42

43 Update on Model Description» Has not changed: A mixed integer programming (MIP) model that schedules new resource additions and existing resource retirements to minimize total costs over the planning horizon Simplified granularity with a two-bubble topology» Changed: Model East and West separately with energy transfers Originally, time periods were to be by month and TOD Model now has ability to use finer time granularity Can do an hourly dispatch for one week per month» A more robust design than originally negotiated 43

44 Limitations of the Model» Not a magic box! Additional analyses will be necessary to develop portfolios that are truly optimal» Moderately Detailed Model High level focus as compared to the detailed focus of PROSYM (transmission and resource location)» Not fully functional yet Requires more testing to be fully validated 44

45 Model Implementation Progress» Model validation 3 step process Generation and variable costs of existing resources have been validated between the CEM and PROSYM Validate the short position the CEM computes to L&R balance Validate CEM portfolio generation and costs against PROSYM Portfolios will be generated with the CEM and then simulated with PROSYM. The generation and variable cost outputs of both models can then be compared.» Model testing Run parallel to manual portfolio process Perform a check on manually built portfolios» Once fully validated and tested, the CEM will be used for: Determining new least-cost portfolios Further analyzing manually built portfolios 45

46 Model Implementation Progress cont.» Unfortunately, our technical workshop was delayed because of delays with model delivery and validation» The workshop has been rescheduled for August 26 Contingent upon successful model validation 46

47 2004 Stress Cases Christine Jerko and Michael Rife

48 Overview» Stresses from the 2003 IRP are on pages of 2003 IRP Document.» Two Types of Cases Those Identified during portfolio building Changing Planning Margin, CO 2 Allowance Some have been redefined as portfolio analysis (DSM Decrements). Those Identified after portfolio building To be determined 48

49 Modify CO 2 Allowance Cases» $0, $10, $25, $40 per ton cases (in 1990$) compared with $8 per ton base case. Base case seen on slide 21. Cap is based on 2000 level of emissions. Environmental Costs are inflated Using GDP deflator from 1990 through Using slide 22 inflation from 2003 through Stresses are graduated from CY2010 to CY2012 similar to base case. $0 $8 (2008 $) $10 (1990 $) $25 (1990$) $40 (1990 $) CY $ 4.19 $ 7.45 $18.62 $29.80 CY $ 6.45 $11.45 $28.63 $45.82 CY $ 8.80 $15.64 $39.10 $

50 Planning Margin Stress» Change Planning Margin Assumption Base Case of 15% Stress tests consist of 12% and 18% planning margins. 50

51 Oregon SB1149» Kick Start Program for Open Access Maximum of 100 MWs of PacifiCorp s Customers can leave system between 9/05 and 9/06. Customers can leave for between 6 months to three years. Customers must return to PacifiCorp.» PacifiCorp must continue to plan for all OR customers Provider of last resort All customers have a right to cost of service; the OPUC has not waived that right for any customers» Thus, we are proposing no stress testing for SB1149 in this IRP cycle. 51

52 Hydro Relicensing and Renewable Energy» High Hydro Case Approximately 100 MW of new capacity in the western control area, no associated energy due to technical upgrades or renegotiated capacity» Low Hydro Case Approximate loss of 130 MW of capacity, and 100,000MWh per annum in the western control area Due to technical constraints and potential capacity losses during renegotiations» No Production Tax Credit Removal of the 1.8 cents/kwh subsidy for wind energy. 52

53 Portfolio Development Process Peter Warnken

54 Presentation Goals» Help you understand the manual portfolio development process and its role in relation to overall IRP process» Provide walk-through of the portfolio-building process using a hypothetical example» Report on portfolio development status 54

55 Manual Portfolio Development Process: Summary Process Inputs: Starting Position / Resource Options Manual Portfolio Development Development Guidelines Automated Portfolio Development (In Parallel) Build Portfolios Build Portfolios with CEM Generate and Evaluate Results Generate and Evaluate Results Select Top Portfolios (Lowest PVRR) Detailed Analysis Select Portfolio with Best Cost/Risk Balance 55

56 ,015 1,184 1,353 1,522 1,691 1,860 2,029 2,198 2,367 2,536 2,705 2,874 3,043 3,212 3,381 3,550 3,719 3,888 4,057 4,226 4,395 4,564 4,733 Process Inputs: Starting Position & Resource Options» Load/Resource Balance: Coincident peak capacity charts will be used to determine build target Duration curves and energy graphs will be used to determine the type and timing of portfolio resource additions 14,000 Peak Obligation + Planning Margin 2,500 4,000 12,000 Resource Deficit 2,000 3,000 1,500 10,000 2, ,000 8, ,000 Available Resources (1,000) (500) 4,000 (2,000) (1,000) 2,000 Fiscal Year Apr-05 Jul-05 Oct-05 Jan-06 Apr-06 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09 Jul-09 Oct-09 Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11 Jul-11 Oct-11 Jan-12 Apr-12 Jul-12 Oct-12 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Jul-14 Oct-14 Jan-15 (1,500) (2,000) PAC East Off-Peak PAC East On-Peak (3,000) (4,000) (5,000) MWa MWs 1, » Resource Options Fuel type Technology Location Timing Cost/Operating Characteristics MW 4,902 56

57 Portfolio Development Guidelines» Objective Build to, and maintain, target planning margin» Process Create range of portfolios reflecting resource configuration concepts: Technology type (for example, CCCT vs. Intercooled SCCT) Timing of Resource Additions Location Construct portfolio alternatives by varying a single factor to ease comparative analysis 57

58 Building Portfolios: A Hypothetical Example Assumptions:» Existing resource base starts at 10,000 MW in FY2006» Starting Position Includes Planning Margin Target of 15% Net Position is long 800 MW in 2006, short 200 MW in 2008, short 3500 MW by 2015 (next slide shows graph) Includes impact of plant retirement and Power Purchase Agreement expiration» Resource Options List consisting of four generating unit types (details in forthcoming slide) Example will show a base case portfolio and one alternative portfolio 58

59 Initial Starting Position Capacity (MW) Capacity (MW) Year 59

60 Generation Resource Options» Natural Gas, Combined Cycle Combustion Turbine 3-year lead-time, Minimum unit size 500 MW» Simple Cycle Combustion Turbine (SCCT) 2-year lead-time, Minimum unit size 100 MW» Greenfield Pulverized Coal 5-year lead-time, Minimum unit size 600 MW» Wind 2-year lead-time, Minimum unit size 150 MW (Peak Capacity Credit = 20%) 60

61 Portfolio Development Example Portfolio 1 Build Table > All Options» Resources added to maintain 15% target planning margin, and minimize blockiness of resource additions Resource CCCT ,000 1,000 1,000 1,500 1,500 2,000 2,000 SCCT Coal Wind Total Additions ,190 1,290 1,890 2,390 2,620 3,120 3,380 Total Resources 10,000 10,000 10,190 11,190 11,290 11,890 12,390 12,620 13,120 13,380 Obligation (incl. 15% PM) 9,200 9,400 10,200 11,200 11,400 11,600 12,500 12,700 13,000 13,500 Derived Planning Margin 25.0% 22.3% 14.9% 14.9% 13.9% 17.9% 14.0% 14.3% 16.1% 14.0% Derived Planning Margin (FY2008-FY2015) = 15.0% 61

62 Portfolio Development Example Portfolio 1 Build Table > All Options Resource CCCT ,000 1,000 1,000 1,500 1,500 2,000 2,000 SCCT Coal Wind Total Additions ,190 1,290 1,890 2,390 2,620 3,120 3,380 Total Resources 10,000 10,000 10,190 11,190 11,290 11,890 12,390 12,620 13,120 13,380 Obligation (incl. 15% PM) 9,200 9,400 10,200 11,200 11,400 11,600 12,500 12,700 13,000 13,500 Derived Planning Margin 25.0% 22.3% 14.9% 14.9% 13.9% 17.9% 14.0% 14.3% 16.1% 14.0% Derived Planning Margin (FY2008-FY2015) = 15.0% Portfolio 2 Build Table > In FY2012, add coal unit and defer CCCT Resource CCCT ,000 1,000 1,000 1,000 1,000 1,000 1,500 SCCT Coal ,200 1,200 1,200 1,200 Wind Total Additions ,190 1,290 1,890 2,490 2,720 2,720 3,480 Total Resources 10,000 10,000 10,190 11,190 11,290 11,890 12,490 12,720 12,720 13,480 Obligation (incl. 15% PM) 9,200 9,400 10,200 11,200 11,400 11,600 12,500 12,700 13,000 13,500 Derived Planning Margin 25.0% 22.3% 14.9% 14.9% 13.9% 17.9% 14.9% 15.2% 12.5% 14.8% Derived Planning Margin (FY2008-FY2015) = 14.9% 62

63 Generate and Evaluate Results» Run deterministic simulation to create operational profile for each portfolio; evaluate monthly model run output by Control Area to verify results» Consolidate fixed and variable cost financial results to determine Present Value Revenue Requirements (PVRR) for each portfolio» Generate Scorecard for each portfolio summarizes PVRR and other evaluation criteria to identify best-performing portfolios 63

64 Generate and Evaluate Results: Portfolio Scorecard ProSym Output Financial Data Consolidation & Results Calculation Generation/ Transmission Capital Costs Portfolio Scorecards» Scorecard measures: Present Value Revenue Requirements (Key Metric): 20 year period Capacity Factors Market Purchases/Sales Control Area Transfers/Change in Transfers Total Emission Cost Emission Rates for SO 2, NO x, CO 2, HG Resource Composition 64

65 Generate and Evaluate Results» Iterate through portfolio development-simulation-evaluation cycle to: Filter out poor performers Further refine superior portfolios to optimize favorable characteristics Lower PVRR Lower emissions/emission costs Higher capacity utilization» End result is master list of screened portfolios from which to select top performers 65

66 Select Top Portfolios» Rank screened portfolios by PVRR: PVRR 1000$ Portfolio Number» PVRR of top performers expected to cluster around PVRR of the Least Cost Portfolio; select all portfolios in this low-cost cluster» Detailed analysis conducted on top-performing portfolios 66

67 Portfolio Development Status» Updated market prices in the PROSYM model database (End of June)» Developing preliminary portfolios and running deterministic simulations (July/August)» Preparing consolidated financial results and Scorecards for preliminary portfolios (July/August)» Select top-performing portfolios and conduct detailed analysis (August/September) 67

68 Treatment of Short Term Contracts in the IRP Stacey Kusters & Melissa Seymour

69 Short Term Transaction Discussion» Some amount of volume that the Front Office will procure on a rolling forward basis (as sellers demonstrate an interest) to cover net position.» Forward procurements made in advance for standard products using standard enabling agreements (i.e, EEI, WSPP). Solicitations made year(s) in advance and, if necessary, quarters in advance.» Standard Products (such as HLH, LLH, and/or daily HLH call options) to garner greatest response.» Transaction Timeline Annual Can be available as much as 3 or more years in advance (depending on POD and product), Seasonal Typically deliver during quarters. Can be available from one to three years in advance (depending on POD and product), Custom Typically single month or non-typical monthly patterns (i.e., June- September). Can be available up to 1-year in advance (depending on POD and product). Greatest opportunity for customized delivery patterns (i.e, super-peak 6X8 or 7X8).» Term - Varies by counterparty. Greatest number of offers can be expected for single year commitments (i.e.., Q as opposed to Q3 2006/2007/2008). 69

70 IRP Treatment of Front Office Transactions» 2003 IRP Used proxy resource to fill gap in load/resource balance» Possibilities for 2004 IRP Same methodology as 2003 IRP, with understanding that part of the resource deficit may be filled with shorter-term procurements. Directly assume an amount of Front Office transactions. Choose MW amounts, products, and delivery points based on experience. Plan to deficit less this amount» Feedback? Use mix of annual and seasonal standard products as proxies for these transactions. 70

71 Distributed Generation Mike Koszalka

72 Distributed Generation (DG) Definition» DG has been defined in many ways - this has created confusion.» Most commonly defined as the generation of electricity near the intended place of use» Some parties define it with a size limitation» Some exclude back-up generation» Some offer no distinction between generation connected to the transmission or distribution system» DG can be customer sited or grid sited» The California Energy Commission definition: DG is electric generation connected to the distribution level of the transmission and distribution grid usually located at or near the intended place of use 72

73 Distributed Generation Types» QF s (obligated by law to purchase power at avoided cost) CHP (cogeneration) Solar (photovoltaic) Wind Biogas fueled engine Small hydro» Non-QF s (not obligated to purchase) Fuel Cell Internal or external combustion engine (gensets) Conventional combusition turbine generator (natural gas, oil) Gas turbine Reciprocating engine Micoturbine (non CHP) Stirling engine 73

74 Distributed Generation Issues in Planning» Customer sited Customer Economics, not utility or utility customer economics Operates according to customer need Customer determines operation & longevity (i.e. customer may go out of business)» Costs QF s come in at avoided cost at any time they are constructed. Non-QF s are generally not cost-competitive» Forecasting construction Customer economics and opportunities prevail To be economic for the customer, the generation opportunity usually needs to be timed with a boiler replacement, major remodeling or new construction project 74

75 IRP Distributed Generation Policy Policy» PacifiCorp is very supportive of acquiring cost effective DG to meet our future resource needs» Solicitation action items emanating from the IRP will take DG into account» We don t know how to include them (very complicated and shifts avoided cost calculation) as we build portfolios and that is why we will seek them out as we actually acquire resources» We will work with you on the best way to solicit cost effective DG» PacifiCorp stands ready to accept all DG projects which are QF s Benefits» Assures that the company has plans in place to meet resource needs.» Allows distributed resources to be constructed as part of the least cost portfolio. (QF s come in at avoided costs)» Distributed Resources can displace planned resources as sufficient projects are completed. 75

76 Next Steps Melissa Seymour

77 Next Steps» Schedule of Future Meetings: IRP Public Input Meetings - August 27 Technical Workshop to Discuss Automatic Resource Addition Logic August 26 (PM)» Topics for the Next Meeting Include: Results of Portfolio Runs Risk Analysis Discussion 77