irp public input meeting - rocky mountain power public input meeting june 10, 2004. 2 ... dummy...

IRP Public Input MeetingIRP Public Input Meeting

June 10, 2004

2

AgendaAgenda

» 2004 IRP Resource Alternatives• Supply Side Resources

• DSM & Distributed Generation

• Transmission Alternatives

» Renewable Assumptions (Green Tags, RPS, Product Tax Credit)

» Market Assumptions

» Environmental Adder Assumptions (NOx, SO2, Hg, CO2)

» Henwood Planning Reserve Margin Study

» Load and Resource Balances

» Next Steps

2004 Resource Alternatives2004 Resource Alternatives

Jim Lacey, Mike Koszalka & Melissa Seymour

4

Resource AlternativesResource Alternatives

» Coal• Type

⇒ Brownfield– Hunter 4 (earliest date FY2011)

⇒ Greenfield

• Technology⇒ Pulverized Coal

– Subcritical (9,483 Btu/kWh heat rate (HR))

– Supercritical (3.7% better HR, Increases of 2.8% Capital - 1.5% O&M)

⇒ Integrated Gasification Combined Cycle (IGCC)– New technology (FutureGen)

– Probably not available for consideration until 2012

– IGCC an option starting in FY 2015

• Location⇒ Utah and Wyoming

5


» Natural Gas• Type

⇒ Simple Cycle Combustion Turbine (SCCT)– Aero and Frame

– Flexibility is key

⇒ Combined Cycle Combustion Turbine (CCCT)– Wet and Dry Cooled

– Duct Firing

• New Technology⇒ Intercooled Aero SCCT

• Location⇒ System

6

Intercooled Simple CycleIntercooled Simple Cycle

» New Technology• Not expected to be available till FY2008 at the earliest

• Considered as an option starting in FY 2010

• Vendor specific to GE

» Comparison (East Side ~ 4250 ft):

$730$560$682Capital Cost ($/kW)

392424Lead Time (Months)

7,1868,35210,225Heat Rate (Btu/KWh)

4508740MW

“F” CCCTIntercooledAero SCCT

7


» Renewables• Projected costs are higher consistent with the Renewables

RFP responses

• Wind

• Geothermal

» Storage• Pumped Hydro

• Compressed-Air Energy Storage (CAES)

8

Resource OptionsResource Options

» Distributed Resources (PacEast/PacWest)• DG projects will displace least cost plan resources at the avoided cost

(indifference cost to customers) as they are constructed on customer facilities. QF’s can be proposed by customers at any time.

• Technologies⇒ CHP

⇒ Solar (PV)

⇒ Fuel Cells

⇒ Microturbines (Demonstration project, 200 Market Bldg, Portland)

⇒ Battery Storage (Castle Valley VRB demonstration project)

• Costs updated

» Demand Side • Class 1 Load Control Summer loads (PacEast/PacWest)

• Class 1 Load Control Winter (PacWest)

• Class 2 Resources treated as decrements to load

9

Transmission OptionsTransmission Options

» Support Supply Side Options• Cost of building transmission to integrate supply-side alternatives

» Regional Transmission Initiatives• Rocky Mountain Area Transmission Study (RMATS) & Northwest

Transmission Assessment Committee (NTAC) scenarios⇒RMATS report expected in July

⇒NTAC result may not be available for use in 2004 IRP

• Later years – FY2013 and beyond

Renewables AssumptionsRenewables Assumptions

Christine Jerko

11

Production Tax CreditProduction Tax Credit

» Definition• Created in 1992 to support development of wind and biomass

• Provides 1.8 cents/kWh for the first 10 years of a project’s output

» Current Status• Renewal required after December 31, 2003 but did not occur

⇒Broad support for the PTC, however there was not broad support for the energy bill in which is was embedded

• Progressive support in 2004⇒The Senate recently passed a corporate tax bill including the PTC

⇒House leadership has indicated interest in the bill’s energy provisions

12

Production Tax Credit (cont.)Production Tax Credit (cont.)

» PacifiCorp is adopting the PTC at 1.8 cents/kWh for the 2004 IRP • While PTC is not in place now, historical experience indicates

durability

• Less certain is how long it will last

• However, it is very difficult to guess when it will permanently expire, and what could replace it (e.g., Federal Renewable Portfolio Standard)

» PacifiCorp will run a sensitivity to estimate impact of no PTC

13

Green TagsGreen Tags

» A green tag represents a unit of generation from renewables• Renewable generation whose tags are sold is considered to be “null

power” – that is, power without renewable characteristics

» There are regional, national and international markets for greentags

» Green tags are used for two main purposes• Voluntary “green power” programs, (e.g. Blue Sky)

• Compliance with renewable portfolio standards

» Tags are theoretically priced at the difference between the ‘all-in’ renewable cost and the prevailing market price

14

Green Tags (cont.)Green Tags (cont.)

» PacifiCorp will valued tags at $5/MWh for first five years of a new project• Consistent with the 2003 IRP

• Reflects market-clearing prices

• In addition our stakeholders placed value on “new” renewable projects for supplying our Blue Sky subscriptions

• The $5/MWh value translates into approximately $2/MWh levelized over 20 years for a 20 year purchase contract or a plant with a 20 year life⇒Plants or contracts less than 20 years will be valued at a fraction of the

20 year amount

15

Renewable Portfolio Standard AssumptionsRenewable Portfolio Standard Assumptions

» Based on California State Law• 20% of California load must be met with renewable energy or small

hydro projects.

• For PacifiCorp⇒energy from 2003 small hydro projects serves as starting point

⇒Linear projection through 2017 to meet 20% of load

⇒Starting at 5MW in 2005 up to 20MW in 2017

Market AssumptionsMarket Assumptions

Christine Jerko

17

Role of Markets in 2004 IRPRole of Markets in 2004 IRP

» Purpose• Physical balancing

⇒ Interconnected with WECC

• Not used in Portfolio Build Targets⇒Difficult to predict the numerous fundamental drivers of market size

» Application⇒Market is assumed to exist at least up to the point that we have firm

transmission rights (FTR)

⇒Markets will also economically interact with contractual obligations if they exist within the market boundaries

⇒FTR out of the market plus contractual purchases comprise potential market purchase depth, FTR into the market plus contractual sales comprise potential market sales depth

18

Differences from 2003 IRPDifferences from 2003 IRP

» Approach used in 2003 IRP• Markets were used for balancing

• Markets were assigned specific capacities⇒Markets capped at 500 MW in the eastern control area and

500 MW in the western control area

» Approach for 2004 IRP• Markets are still used only for balancing, not for portfolio

development

• Markets are now limited by firm transmission rights and potential obligations within a particular market, as opposed to assigning a specific capacity

19

IRP TopologyIRP Topology

West Main

ARIZONA

Wyoming

CA-OR Border

Borah

Jim Bridger

Palo Verde

Path CDummy Bubble

Utah North

Goshen

Mona

PacifiCorp IRP Topology(2004 IRP)

PacifiCorp East

$

$

Path C

4-Corners

$

Load

Generation

Purchase/Sale Markets

Contracts/Exchanges

Owned Transmission on PacifiCorp

Owned Transmission on others

Utah South

Wasatch Front South

Brady

$

Cholla ExportDummy Bubble

Colorado

Washington

Mid Columbia

PacifiCorp West

$

Environmental Adder Environmental Adder AssumptionsAssumptions

Bill Edmonds

21

Climate Change Policy OverviewClimate Change Policy Overview» Significant risk surrounding future CO2 regulations to warrant continued

consideration in planning. » Uncertainty around climate change in a number of areas:

• Timing/Stringency of requirements• Compliance mechanisms

» Climate Change is not addressed by adding control technology to our existing generation facilities• DSM, increased renewable energy, increased hydroelectric use, fuel switching,

distributed generation, improved efficiency, off-system efforts» Policy

• International: In 2001, the Bush Administration withdrew from the Kyoto Protocol; other nations moving forward to ratify.

• Domestic: President Bush’s Global Climate Change Initiative -- 18 % intensity reduction by 2012; Carper/Lieberman -- impose a 2000 ton emissions cap in 2010; Jeffords -- 1990 levels by 2009.⇒ In October 2003, McCain/Lieberman congressional debate on carbon restrictions led to a

43-55 vote against. ⇒ Currently, not enough votes for either 3P or 4P bill -- prospects dim heading into

Presidential election year.• State: Some states considering policy moves in GHGs (e.g. voluntary registry,

Renewable Portfolio Standard, and emission caps.)

22

2004 CO2004 CO22 IRP AssumptionsIRP Assumptions» Previous IRP contained base case of $8 in 2008 with a 2000 cap.» Company reconfirms the necessity to use a CO2 adder to address risk. The

2004 IRP Model will include:• carbon adders as a proxy for the wide range of potential CO2 policy scenarios;• baseline cap closely mimicking likely US policy options;• probabilistic curve incorporating policy timing uncertainty

» Base Case: 2004 IRP curve has a gradual climb to an inflation adjusted $8.73 price with a 2000 cap. • Reflects timing uncertainty. Even though legislation may pass before 2010,

implementation would not occur until 2010 – 2012 timeframe. • Better aligns with blending of market and fundamental forecasts in the Forward Price

Curve

» By 2010 we’re reasonably certain that a climate change policy will begin.• 2010 - $4.18/ton (50% chance of occurrence)• 2011 - $6.40/ton (75% chance of occurrence)• 2012 - $8.73/ton (most likely chance of occurrence)

» Additional sensitivities run: 0, $2 with a 2000 cap in 2015, $25 and $40 with a 1990 cap in FY 2009

23

SOSO22, , NOxNOx and Hgand Hg

» The 2004 IRP Model includes environmental adders for SO2, NOx, and Hg (mercury).• SO2, NOx and Hg numbers based on PIRA study on emissions costs and timing.• Existing and future resources are penalized according to their emissions of SO2 ,

NOx, & Hg.

Note: SO2 and NOx are $/ton, Hg is $/lb

$46,091 $41,339NA2010~34 Ton Cap (backstop price); 15 ton cap in later yearsHg

$2,370 $2,126 NA2010National Annual Trading (0.15 to0.25 lb/MMBtu System Target)NOx

$988 $886 $337 2010~ Halving of Current Acid Rain CapSO2

201520102004StartPolicy

» Previous IRP assumptions

Note: Prices are $/ton

$2,757 $2,437 NA2008National Annual Trading Program with SCR Setting PricesNOx

$446 $394 $226 1995Title IV Acid Rain ProgramSO2

201520102004StartPolicy

Henwood Planning Reserve Henwood Planning Reserve Margin StudyMargin Study

Carl Huppert – Sr. Project Manager

Henwood Energy Services, Inc.

25

Agenda Agenda –– Planning Reserve Margin StudyPlanning Reserve Margin Study

» Historical approaches to Loss of Load

» Regional Criteria and Studies

» General Study Approach

» Overview of PacifiCorp Analysis

» Modeling Steps

» Results

» Observations

» Recommendations

26

Historical Loss of Load Probability AnalysisHistorical Loss of Load Probability Analysis

» Probabilistic –• deploys the fundamental data regarding unit capacity, random and

planned outage rate, and load demand

Sample Station Innage/Outage Rates Capacity FOR Innage Rate

Unit A 50 .05 .95 Unit B 100 .07 .93 Unit C 200 .10 .90

System 350

27


Sample Combined Station Outage Probabilities On

Outage MW of outage In Service Probability

None 0 A,B,C .95*.93*.90=.79515 A 50 B,C .05*.93*.90=.04185 B 100 A,C .95*.07*.90=.05985 C 200 A,B .95*.93*.10=.08835

A,B 150 C .05*.07*.90=.00315 A,C 250 B .05*.93*.10=.00465 B,C 300 A .95*.07*.10=.00665

A,B,C 350 None .05*.07*.10=.00035 1.00000

Consider the probability of not being able to supply a 220 MW load demand. If 220 MW or less capacity is in service, a 220 MW load cannot be served. Since the capacity of the three-unit system is 350 MW, the load could not be supplied if (350-220) or 130 MW of capacity or more is on outage. According to the data in the table above, the probability of 130 MW or more on outage is:

.08835+.00315+.00465+.00665+.00035=.10315 This is the probability of not meeting a peak load of 220 MW in one day.

28


» Look at each daily peak in a year and determine the probability of not meeting the peak in each day

» Sum the probabilities for all days

» A sum of 1.0 means there is a probability of 1-day outage in one year

» A sum of probabilities of 0.1 means there is a probability of 1-day outage in 10 years

29

Limitations of Historical Approach Limitations of Historical Approach

» Focuses on meeting load on peak hour

» Does not consider load volatility

» Does not consider interconnections

» Does not consider magnitude of energy not served

30

Reliability Councils Resource Adequacy CriteriaReliability Councils Resource Adequacy Criteria

WECC

MAPP

SPP

ERCOT

MAIN

ECAR

FRCC

SERC

MAAC

NPCC

Regional resource adequacy

criteria

Unspe-cified

LOLE of 1day/10

years

1–in–10

year LOLP

Unspe-cified

1–in–10

year LOLP

Dependence on Supplemental

Capacity Resources

(DSCR) index for 1 to 10 days/yr is

consistent with an LOLE of 1

day in 10 years

1–in–10

year LOLP

No

uniform criterion for entire council

LOLE of 1day/10 years or

0.1 day/yr

LOLE of disconnecting firm load

due to resource

deficiencies shall be no more than 0.1 day/yr

Resource Adequacy Require-

ment

Some sub-

regions have requir

e-ments

15% Planning Reserve Margin

(10% for a pre-

dominantly hydro sub-

region)

12 %

Planning

Reserve (9 % if

member is 75% hydro)

12.5

% Re-serve Margi

n

15-20% Reserve Margin

ECAR uses a criterion of 0.1 day/yr LOLE to

assess the adequacy of

ECAR capacity margins

15%

Reserve Margin

Varies—each

member system

establish own

require-ments

Reserve margin of

PJM members based on this LOLE criterion

Unspecified

Methodo-

logy

Unspe-cified

The

planning reserve

margin is derived using an

LOLE requiremen

t of 1day/10

years

Reviews

LOLE analyses per-

formed by SPP

working group

Re-

serve Margi

n based in part on a LOLE study

Based

on LOLP and

LOLE studies

Analyses show 1 to 10 days DSCR was

determined to be consistent

with an LOLE of 1 day in 10 years in a

multi-regional assessment,

which includes the

transmission

Periodic analyses performe

d to be sure

reserve margin is consistent

with 1–in–10

year LOLP

SERC member systems

are of the opinion

that resource adequacy is a local or state

jurisdiction-al issue

Approval

of the required reserve

margin is the

responsibility of the

PJM Board

Based on LOLP and

LOLE studies

Source: WRAT Resource Adequacy Briefing Paper, March 23, 2004

No Direction from WECC!No Direction from WECC!

31

Changes beginning in the West Changes beginning in the West -- CaliforniaCalifornia

» CPUC asked the IOUs to address the following in their IRP filings in 2003• What level of planning reserve would provide a loss of load

probability of one day in 10 years?• What level of planning reserve would you suggest and why?

» Southern California Edison used the approach we are proposing for PacifiCorp. They only had one zone. They had little hydro.

» San Diego Gas & Electric used the approach we are proposing here. They had a significant import constraint to their system.Their study reflected different locations and import capabilities. One with all new resources added outside of San Diego and no new import capability. One with all new resources inside San Diego.

» PG&E used a similar approach but simply found one day in 10 years without doing a range. PG&E had hydro volatility.

32

Changes beginning in the West Changes beginning in the West -- ColoradoColorado

» Public Service of Colorado (PSCo) used similar approach to determine appropriate planning reserve margin for their IRP portfolio build-out

» PSCo used the 1 day in 10 year result (16-17%) as the reserve level above the base demand forecast

33

General Study ApproachGeneral Study Approach

» Determine measure of reliability for a range of planning margins• Probability of not meeting load

⇒Loss of load hours/days in 10 years (LOLH or LOLD)

• Magnitude of load not served⇒Expected Unserved Energy (EUE)

⇒EUE as a percent of load

» Determine the cost tradeoff between improved reliability and thecost of new resources

» Analysis performed through simulation-based approach • Hourly dispatch of system resources versus load with stochastic

parameters

34

Overview of PacifiCorp Analysis Overview of PacifiCorp Analysis

» Modeled PacifiCorp system• Inputs consistent with 2004 IRP

• Two-bubble topology

• Fiscal Year 2009 used as test year

• Interconnection to WECC markets via firm transmission

» Hourly economic dispatch• Stochastic inputs of hydro and load via 100 Iterations of Monte

Carlo draws

» Build out to test range of reserve margins • Used SCCT to build reserve margin ($72/kw-yr)

» Measurement of loss of load hours and expected unserved energy

35

Portrayal of PacifiCorp SystemPortrayal of PacifiCorp System

East Market

West Market

PacifiCorp West

PacifiCorp East

(loads, resources & contracts)

(loads, resources & contracts)

Access

Access

36

Stochastics:Stochastics:Load and Weather Induced VolatilityLoad and Weather Induced Volatility –– PAC EastPAC East

Monthly Load - 100 Iterations

2500

2700

2900

3100

3300

3500

3700

3900

4100

4300

Apr-08 May-08 Jun-08 Jul-08 Aug-08 Sep-08 Oct-08 Nov-08 Dec-08 Jan-09 Feb-09 Mar-09

Mon

thly

Loa

d (G

Wh )

Expected Load

37

Stochastics:Stochastics:Load and Weather Induced VolatilityLoad and Weather Induced Volatility –– PAC WestPAC West

Monthly Load - 100 Iterations

1000

1200

1400

1600

1800

2000

2200

2400

2600

2800

Apr-08 May-08 Jun-08 Jul-08 Aug-08 Sep-08 Oct-08 Nov-08 Dec-08 Jan-09 Feb-09 Mar-09

Mon

thly

Loa

d (G

Wh )

Expected Load

38

Stochastics:Stochastics:Hydro Volatility Hydro Volatility –– PacifiCorpPacifiCorp

0

50

100

150

200

250

300

350

400

450

500

550

600

650

700

750

800

1/3/

2005

1/17

/200

5

1/31

/200

5

2/14

/200

5

2/28

/200

5

3/14

/200

5

3/28

/200

5

4/11

/200

5

4/25

/200

5

5/9/

2005

5/23

/200

5

6/6/

2005

6/20

/200

5

7/4/

2005

7/18

/200

5

8/1/

2005

8/15

/200

5

8/29

/200

5

9/12

/200

5

9/26

/200

5

10/1

0/20

05

10/2

4/20

05

11/7

/200

5

11/2

1/20

05

12/5

/200

5

12/1

9/20

05

Date

GW

h

Projected Weekly PacifiCorp West Generation – by Exceedence Level

39

Modeling StepsModeling Steps

» First effort is to find a starting point with fairly high level of expected load to unserved energy, and with the % of unserved energy roughly the same in the West and the East

» Then step both the West and the East up a notch in planning reserve level to see how much the unserved energy is reduced

» Develop a set of results with increasing reserves to test the benefit from moving from one level to the next

40

Results Results –– DefinitionsDefinitions

» Case # – Defines the run. Each case represents base resources with incremental additions for each run. The goal is to line up EUE as a % of load, and LOLH for each control area.

» System Peak Obligation – Load + Sales at the time of the system peak.

» Total Resources – (Existing Resources (Plants, Purchases, Interruptibles, DSM) + Incremental Additions to establish Planning Margin) available at the system peak

» Loss of Load Days per 10 Years – Probability of not meeting load.

» Expected Unserved Energy & EUE as a % of Load - Magnitude of load not served

» Planning Margin – [(Total Resources - System Peak Obligation) / System Peak Obligation] + WECC Operating Criteria (7%, 5%)

» SCCT Addition Costs – SCCT Levelized Cost ($72,000/mw-yr)*MW incremental SCCT additions

41

Results Results –– Loss of Load Days in 10 Years Loss of Load Days in 10 Years -- EastEast

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

12.9% 13.9% 14.9% 15.9% 16.8% 17.8% 18.8% 19.8% 20.8% 21.8% 22.8%

Planning Margin

Loss

of L

oad

Day

s

42

Results Results –– Loss of Load Days in 10 Years Loss of Load Days in 10 Years -- WestWest

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

13.4% 14.3% 15.2% 16.1% 17.0% 17.8% 18.7% 19.6% 20.5% 21.4% 22.2%

Planning Margin

Loss

of L

oad

Day

s

43

Results Results –– Expected Unserved Energy Vs. Reserve Margin Expected Unserved Energy Vs. Reserve Margin -- EastEast

0

50

100

150

200

250

300

350

400

450

500

550

600

650

700

750

800

850

13.9% 14.9% 15.9% 16.8% 17.8% 18.8% 19.8% 20.8% 21.8% 22.8%

Planning Margin

EUE

Red

uctio

n (M

Wh)

44

Results Results –– Expected Unserved Energy Vs. Reserve Margin Expected Unserved Energy Vs. Reserve Margin -- WestWest

0.0

25.0

50.0

75.0

100.0

125.0

150.0

175.0

200.0

225.0

14.3% 15.2% 16.1% 17.0% 17.8% 18.7% 19.6% 20.5% 21.4% 22.2%

Planning Margin

EUE

Red

uctio

n (M

Wh)

45

Results Results –– Cost of Reducing LOLDCost of Reducing LOLD in 10 Years in 10 Years -- EastEast

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

12.9% 13.9% 14.9% 15.9% 16.8% 17.8% 18.8% 19.8% 20.8% 21.8% 22.8%

Planning Margin

Cum

ulat

ive

Cos

ts fo

r Inc

reas

ing

Plan

ning

Mar

gin

($00

0/yr

)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

LOLD

in 1

0 Ye

ars

AdditionsLOLD

46

Results Results –– Cost of Reducing LOLDCost of Reducing LOLD in 10 Years in 10 Years -- WestWest

$-

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000

13.4% 14.3% 15.2% 16.1% 17.0% 17.8% 18.7% 19.6% 20.5% 21.4% 22.2%

Planning Margin

Cum

ulat

ive

Cos

ts fo

r Inc

reas

ing

Plan

ning

Mar

gin

($00

0/yr

)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

LOLD

in 1

0 Ye

ars

AdditionsLOLD

47

ResultsResults

Case

System Peak

Obligation (MW)

System Total (MW)

Planning Margin

EUE as a % of Total Annual Load

1 10,511 11,886 13.1% 0.0068%2 10,511 11,986 14.0% 0.0049%3 10,511 12,086 15.0% 0.0035%4 10,511 12,186 15.9% 0.0025%5 10,511 12,286 16.9% 0.0018%6 10,511 12,386 17.8% 0.0013%7 10,511 12,486 18.8% 0.0009%8 10,511 12,586 19.7% 0.0006%9 10,511 12,686 20.7% 0.0004%10 10,511 12,786 21.6% 0.0002%11 10,511 12,886 22.6% 0.0002%

PacifiCorp SystemCase

East Peak Obligation

(MW)

East Total Resources

(MW)

Loss of Load Days per 10

Years


Planning Margin

SCCT Addition Cost ($000)

1 7,102 8,019 4.2 0.0087% 12.9% $60,7682 7,102 8,089 3.1 0.0061% 13.9% $5,0403 7,102 8,159 2.2 0.0042% 14.9% $5,0404 7,102 8,229 1.7 0.0031% 15.9% $5,0405 7,102 8,299 1.2 0.0022% 16.8% $5,0406 7,102 8,369 0.9 0.0015% 17.8% $5,0407 7,102 8,439 0.7 0.0010% 18.8% $5,0408 7,102 8,509 0.5 0.0006% 19.8% $5,0409 7,102 8,579 0.3 0.0004% 20.8% $5,04010 7,102 8,649 0.2 0.0002% 21.8% $5,04011 7,102 8,719 0.1 0.0001% 22.8% $5,040

Case

West Peak Obligation

(MW)

West Total Resources

(MW)

Loss of Load Days per 10

Years


Planning Margin

SCCT Addition Cost ($000)

1 3,409 3,867 3.4 0.0041% 13.4% $30,8162 3,409 3,897 2.7 0.0031% 14.3% $2,1603 3,409 3,927 2.1 0.0023% 15.2% $2,1604 3,409 3,957 1.6 0.0017% 16.1% $2,1605 3,409 3,987 1.2 0.0012% 17.0% $2,1606 3,409 4,017 0.9 0.0009% 17.8% $2,1607 3,409 4,047 0.7 0.0007% 18.7% $2,1608 3,409 4,077 0.6 0.0005% 19.6% $2,1609 3,409 4,107 0.4 0.0004% 20.5% $2,16010 3,409 4,137 0.4 0.0003% 21.4% $2,16011 3,409 4,167 0.3 0.0002% 22.2% $2,160

PacifiCorp East

PacifiCorp West

48

ObservationsObservations

» “Counting” is a big issue. • The same probability of outage can be characterized as a different

reserve level simply by “counting” differently⇒ Control area peak or system peak?

⇒ How much hydro? Average water year? Critical year? Nameplate?

⇒ WECC reserve requirement added? Or 3% like CAISO?

» It is generally prohibitively expensive to build so much that there is no possibility of shortage. • There is sensitivity to the cost of obtaining smaller and smaller

reduction in probable outages.

• How much are you thinking you should pay in order to reduce the next level of possible outage?

49

Observations Observations (continued)(continued)

» West• Hydro volatility

• Large units in a small system⇒Each Bridger unit is roughly 10% of West peak load

» Generally Accepted Resource Reliability Criteria Across US ?• 1 day in 10 years loss of load probability

50

ConclusionsConclusions

» ~ 18% planning margin results in a 1 day in 10 years equivalent loss of load probability in this simulation-based analysis of the PacifiCorp system.• Is this large? Small?

⇒Consider that PacifiCorp average thermal outage rate is ~ 10%.

⇒Recommended WECC Operating Reserve is 5 – 7%

⇒Regulating Reserve is ~ 2%

• The buffer created by operating reserve and WECC interconnectionis required for unexpected fluctuations in load, hydro and outages.

Load/Resource BalancesLoad/Resource Balances

Melissa Seymour

52

L&R AgendaL&R Agenda

» Review Major Assumptions

» Capacity Charts

» Net Position Duration Curves

» Energy Graphs

53

Major Assumptions Common to All Major Assumptions Common to All L&R’sL&R’s

» Currant Creek, Lake Side, and all contracts as of May 1, 2004 are included (i.e. DG&T)

» West Valley Lease• For FY 2006 – FY 2008, assume either extension of West Valley or

equivalent purchase

• For FY 2009 and beyond, L&R will be not include West Valley lease

» Current DSM programs and the two new RFP Class 2 Programs

» For planning purposes, there are no plant retirements in the Action Plan horizon (3-5 years)

» 90 MW QF in Utah included (1/1/2006)

» 1,400 MW of Renewable Generation included• 20% Planning Credit at Peak

• Modeled after characteristics of currently owned wind generation

54

Capacity ChartsCapacity Charts

» Capacity Charts show the Peak Obligation plus the Planning Margin requirement as compared to the Available Resources for the peak load hour • Peak Obligation = Load + Sales

• Coincident peak Planning Margin = 18%

• Non-coincident Planning Margins = 16.5% (East) and 16.2% (West)

• Available Resources = Available (Thermal + Hydro + Purchases + Interruptible + Class 1 DSM)

» Results are shown for the system coincident peaks, and for the non-coincident peak for each control area

55

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Fiscal Year

MW

s

Available Resources

Resource Deficit

Peak Obligation + Planning Margin

Coincident Peak Coincident Peak –– SystemSystem

» > 4,000 MW of need by FY 2015

56

2004 IRP Waterfall Chart 2004 IRP Waterfall Chart -- SystemSystem

» Waterfall charts identifies the major components that define the need in FY 2015.

» The major contributors to the short position include peak load growth, contract expirations, and planning margin

1100

(1800)

1300

(400)

(1900)

(2100)(300)

(4,500)

(3,500)

(2,500)

(1,500)

(500)

500

1,500

L/R Balance(FY2006)*

Planning MarginRequirement at18% (FY2006)**

Additions fromFY2006 toFY2015***

Retirements/ De-Rates

ContractExpiration Load Growth

18% PlanningMargin (FY2015)

****

MW

* L/R Balance is PacifiCorp's total resources less its total peak requirement** L/R Balance with 18% planning margin requirement*** Includes Lake Side, Currant Creek (245 MW), and renewables (1300 MW multiplied by 0.2, or 260 MW)**** Incremental planning margin requirement by FY2015

57

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Fiscal Year

MW

s

Available Resources


Resource Deficit

West to East Transfer Limit

Coincident Peak Coincident Peak –– PAC EastPAC East

» West to East transfers include the Borah to Utah and Bridger to Wyoming paths

58

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Fiscal Year

MW

s

Available Resources


Coincident Peak Coincident Peak –– PAC WestPAC West

» 2008: TransAlta purchase ends» 2009: Clark County contract ends» 2013: BPA contract ends

Resource Deficit

59

NonNon--Coincident Peak Coincident Peak –– PAC EastPAC East

» West to East transfers include the Borah to Utah and Bridger to Wyoming paths

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Fiscal Year

MW

s

Available Resources


Resource Deficit

West to East Transfer Limit

60

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015Fiscal Year

MW

s

Available Resources


NonNon--Coincident Peak Coincident Peak -- PAC WestPAC West

» Non-coincident peak in the winter » More hydro capacity in the winter

Resource Deficit

61

Net Position Duration CurvesNet Position Duration Curves

» Constructed by computing the net position for each hour of a year, sorting them in descending order, and graphing them starting with the longest position

» Net Position = Thermal + Exchange + Hydro + Wind + Interruptible + DSM + Purchase + Imports (into Control Area) –WECC Reserves - Sale - Load - Exports (out of Control Area)

» Measures the number of hours per year the net position is at or above a given level

» De-rated thermal capacity included for forced outages

» On-Peak hours are weekdays & Saturday hour ending 7:00 am to 10:00 pm; Off-Peak hours are all other hours

62

System OnSystem On--Peak Position Duration CurvesPeak Position Duration Curves

» 2008 curve is above 2006 due to the addition of Currant Creek & Lake Side

(5,000)

(4,000)

(3,000)

(2,000)

(1,000)

0

1,000

2,000

3,000

4,000

1

170

339

508

677

846

1,01

5

1,18

4

1,35

3

1,52

2

1,69

1

1,86

0

2,02

9

2,19

8

2,36

7

2,53

6

2,70

5

2,87

4

3,04

3

3,21

2

3,38

1

3,55

0

3,71

9

3,88

8

4,05

7

4,22

6

4,39

5

4,56

4

4,73

3

4,90

2

MW

2006 2008 2010 2012 2014

2006 2008 2010

2012

2014

63

System OffSystem Off--Peak Position Duration CurvesPeak Position Duration Curves

(4,000)

(3,000)

(2,000)

(1,000)

0

1,000

2,000

3,000

4,000

5,0001

130

259

388

517

646

775

904

1,03

3

1,16

2

1,29

1

1,42

0

1,54

9

1,67

8

1,80

7

1,93

6

2,06

5

2,19

4

2,32

3

2,45

2

2,58

1

2,71

0

2,83

9

2,96

8

3,09

7

3,22

6

3,35

5

3,48

4

3,61

3

3,74

2

MW

2006 2008 2010 2012 2014

20062008 2010

20122014

64

West OnWest On--Peak Position Duration CurvesPeak Position Duration Curves

(3,000)

(2,000)

(1,000)

0

1,000

2,000

3,000

4,0001

173

345

517

689

861

1,03

3

1,20

5

1,37

71,

549

1,72

11,

893

2,06

5

2,23

72,

409

2,58

12,

753

2,92

5

3,09

7

3,26

9

3,44

13,

613

3,78

53,

957

4,12

9

4,30

14,

473

4,64

54,

817

4,98

9

MW

2006 2008 2010 2012 2014

2006 2008 2010

2012 2014

65

West OffWest Off--Peak Position Duration CurvesPeak Position Duration Curves

(3,000)

(2,000)

(1,000)

0

1,000

2,000

3,000

4,0001

128

255

382

509

636

763

890

1,01

7

1,14

4

1,27

1

1,39

8

1,52

5

1,65

2

1,77

9

1,90

6

2,03

3

2,16

0

2,28

7

2,41

4

2,54

1

2,66

8

2,79

5

2,92

2

3,04

9

3,17

6

3,30

3

3,43

0

3,55

7

3,68

4

MW

2006 2008 2010 2012 2014

2006

20082010 2012

2014

66

East OnEast On--Peak Position Duration CurvesPeak Position Duration Curves

(3,000)

(2,000)

(1,000)

0

1,000

2,000

3,000

4,0001

170

339

508

677

846

1,01

5

1,18

4

1,35

3

1,52

2

1,69

1

1,86

0

2,02

9

2,19

8

2,36

7

2,53

6

2,70

5

2,87

4

3,04

3

3,21

2

3,38

1

3,55

0

3,71

9

3,88

8

4,05

7

4,22

6

4,39

5

4,56

4

4,73

3

4,90

2

MW

2006 2008 2010 2012 2014

2006 2008 2010

2012

2014

67

East OffEast Off--Peak Position Duration CurvesPeak Position Duration Curves

(3,000)

(2,000)

(1,000)

0

1,000

2,000

3,000

4,0001

130

259

388

517

646

775

904

1,03

3

1,16

2

1,29

1

1,42

0

1,54

91,

678

1,80

7

1,93

6

2,06

5

2,19

4

2,32

3

2,45

2

2,58

12,

710

2,83

92,

968

3,09

7

3,22

6

3,35

5

3,48

4

3,61

3

3,74

2

MW

2006 2008 2010 2012 2014

2006 2008 2010

20122014

68

Energy GraphsEnergy Graphs

» The energy graphs show the net position by month for on-peak and off-peak hours for each Control Area

» Includes average monthly outages and the WECC reserve requirement

» All results are shown after transfer

69

West Energy CurvesWest Energy Curves

(2,000)

(1,500)

(1,000)

(500)

0

500

1,000

1,500

2,000

2,500

Apr

-05

Jul-0

5O

ct-0

5Ja

n-06

Apr

-06

Jul-0

6O

ct-0

6Ja

n-07

Apr

-07

Jul-0

7O

ct-0

7Ja

n-08

Apr

-08

Jul-0

8O

ct-0

8Ja

n-09

Apr

-09

Jul-0

9O

ct-0

9Ja

n-10

Apr

-10

Jul-1

0O

ct-1

0Ja

n-11

Apr

-11

Jul-1

1O

ct-1

1Ja

n-12

Apr

-12

Jul-1

2O

ct-1

2Ja

n-13

Apr

-13

Jul-1

3O

ct-1

3Ja

n-14

Apr

-14

Jul-1

4O

ct-1

4Ja

n-15

MW

a

PAC West Off-PeakPAC West On-Peak

70

East Energy CurvesEast Energy Curves

(2,000)

(1,500)

(1,000)

(500)

0

500

1,000

1,500

2,000

2,500

Apr

-05

Jul-0

5O

ct-0

5Ja

n-06

Apr

-06

Jul-0

6O

ct-0

6Ja

n-07

Apr

-07

Jul-0

7O

ct-0

7Ja

n-08

Apr

-08

Jul-0

8O

ct-0

8Ja

n-09

Apr

-09

Jul-0

9O

ct-0

9Ja

n-10

Apr

-10

Jul-1

0O

ct-1

0Ja

n-11

Apr

-11

Jul-1

1O

ct-1

1Ja

n-12

Apr

-12

Jul-1

2O

ct-1

2Ja

n-13

Apr

-13

Jul-1

3O

ct-1

3Ja

n-14

Apr

-14

Jul-1

4O

ct-1

4Ja

n-15

MW

a

PAC East Off-PeakPAC East On-Peak

71

Portfolio Construction TargetsPortfolio Construction Targets

» Automatic Resource Addition Logic Tool will use planning margin target as constraint

» Manual portfolio construction process will use L&R balances to construct portfolios• 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

72

L&R ObservationsL&R Observations

» PAC West • Capacity – Sufficient until ~ FY 2012

• Energy – Short in the off-peak period until expiration of BPA Peaking contract

» PAC East • Capacity – Deficit beginning in FY 2006

• Energy – Off-peak length for 10 years without any resource additions. On-Peak short during summer periods beginning in the summer of 2008.

Next StepsNext Steps

Melissa Seymour

74

Next StepsNext Steps

» Schedule of Future Meetings:• Load Forecasting Technical Workshop – June 25

• IRP Public Input Meetings - July 27, August 27

• Technical Workshop to Discuss Automatic Resource Addition Logic – July 28

» Topics for the Next Meeting Include:• Update on the Price Forecast (Electric & Gas)

• Scenarios

• Preliminary Portfolio Results

HandoutsHandouts

PacifiCorp 2004 Integrated Resource Plan DRAFT Public Input Meeting June 10, 2004

Fuel Installation Location Technology

Plant Lead Time - Months

Average Capacity MW

Not Incl. Degradation

Maximum Capacity

Addition per Site

Capital Cost in $/kW

(Average)Design Plant Life in Years

Annual Avg. Heat Rate

HHV - Incl. Degradation (Btu/kWh)

Maint. Outage Rate

(1-EAF-EFOR)

Equivalent Forced

Outage Rate (EFOR)

Var. O&M $/MWh

Fixed O&M in $/kW-yr

CoalBrownfield PC Subcritical Coal PAC East Pulverized Coal-Subcritical 52 575 575 $1,687 40 9,483 5.00% 4.00% $0.80 $32.23

Brownfield PC Supercritical Coal PAC East Pulverized Coal-Supercritical 52 575 575 $1,735 40 9,129 5.00% 4.00% $0.78 $33.77Greenfield PC Coal PAC East Pulverized Coal 63 575 1,150 $1,729 40 9,483 5.00% 4.00% $0.80 $38.78

Greenfield IGCC Coal PAC East Integrated Gasification Combined Cycle 66 368 1,104 $2,171 40 8,311 15.00% 10.00% $1.83 $30.52Greenfield PC 2 Coal PAC East Pulverized Coal 66 575 1,150 $1,813 40 9,483 5.00% 4.00% $0.80 $38.78

Natural GasGreenfield SCCT Aero Nat. Gas PAC East Aero SCCT 24 80 400 $682 25 10,225 5.00% 5.22% $4.00 $13.01Intercooled Aero SCCT Nat. Gas PAC East Intercooled CT 24 87 435 $560 25 8,352 5.00% 5.22% $4.20 $9.05

Greenfield Internal Combustion Engines Nat. Gas PAC East Natural Gas Engines 24 165 165 $633 25 8,700 5.00% 3.00% $5.50 $12.72SCCT Frame Nat. Gas PAC East Frame SCCT 30 280 1,120 $555 35 10,990 4.90% 2.80% $5.35 $10.97

CCCT (2x1) - 4250 feet (Wet Cooling) Nat. Gas PAC East Wet Cooling CCCT 39 450 450 $730 35 7,186 4.95% 2.80% $3.17 $8.85 Wet CCCT Duct Firing (2x1) Nat. Gas PAC East Duct Firing with Wet Cooling CCCT 39 110 110 $186 35 8,868 4.95% 2.80% $0.10 $2.80

CCCT 2x1 - 5100 feet (Dry Cooling) Nat. Gas PAC East Dry Cooling CCCT 36 420 420 $789 35 7,462 4.95% 2.80% $3.27 $10.63Dry CCCT Duct Firing 2x1 Nat. Gas PAC East Duct Firing with Dry Cooling CCCT 36 105 105 $207 35 9,512 4.95% 2.80% $0.10 $2.93CCCT (2x1) - (Dry Cooling) Nat. Gas PAC East Dry Cooling CCCT 32 420 420 $682 35 7,462 4.95% 2.80% $3.18 $4.66 Dry CCCT Duct Firing (2x1) Nat. Gas PAC East Duct Firing with Dry Cooling CCCT 32 105 105 $207 35 9,512 4.95% 2.80% $0.10 $2.93

Greenfield SCCT Aero Nat. Gas PAC West - Elevation 1500 ' Aero SCCT 24 89 447 $595 25 10,225 5.00% 5.22% $3.58 $11.64Intercooled Aero SCCT Nat. Gas PAC West - Elevation 1500 ' Intercooled CT 24 97 486 $501 25 8,352 5.00% 5.22% $3.76 $8.10

Greenfield SCCT Frame Nat. Gas PAC West - Elevation 1500 ' Frame SCCT 30 313 1,252 $497 35 10,990 4.90% 2.80% $4.79 $11.42Greenfield Internal Combustion Engines Nat. Gas PAC West - Elevation 1500 ' Natural Gas Engines 24 165 165 $633 25 8,700 5.00% 3.00% $5.50 $12.72Greenfield CCCT 2x1 - (Wet Cooling) Nat. Gas PAC West - Elevation 1500 ' Wet Cooling CCCT 36 503 1,006 $653 35 7,186 4.95% 2.80% $2.83 $9.51

Greenfield CCCT Duct Firing 2x1 - (Wet Cooling) Nat. Gas PAC West - Elevation 1500 ' Duct Firing with Wet Cooling CCCT 36 123 246 $167 35 8,868 4.95% 2.80% $0.10 $2.50Greenfield CCCT 2x1 - (Dry Cooling) Nat. Gas PAC West - Elevation 1500 ' Dry Cooling CCCT 36 469 939 $706 35 7,462 4.95% 2.80% $2.93 $9.51

Greenfield CCCT Duct Firing 2x1 - (Dry Cooling) Nat. Gas PAC West - Elevation 1500 ' Duct Firing with Dry Cooling CCCT 36 117 235 $185 35 9,512 4.95% 2.80% $0.10 $2.62Greenfield SCCT Aero Nat. Gas PAC West - Sea Level Aero SCCT 24 94 471 $566 25 10,225 5.00% 5.22% $3.40 $11.06Intercooled Aero SCCT Nat. Gas PAC West - Sea Level Intercooled CT 24 102 512 $476 25 8,352 5.00% 5.22% $3.57 $7.69

Greenfield SCCT Frame Nat. Gas PAC West - Sea Level Frame SCCT 30 329 1,318 $472 35 10,990 4.90% 2.80% $4.55 $10.85Greenfield Internal Combustion Engines Nat. Gas PAC West - Sea Level Natural Gas Engines 24 165 165 $633 25 8,700 5.00% 3.00% $5.50 $12.72Greenfield CCCT 2x1 - (Wet Cooling) Nat. Gas PAC West - Sea Level Wet Cooling CCCT 36 529 1,059 $620 35 7,186 4.95% 2.80% $2.69 $9.04

Greenfield CCCT Duct Firing 2x1 - (Wet Cooling) Nat. Gas PAC West - Sea Level Duct Firing with Wet Cooling CCCT 36 129 259 $158 35 8,868 4.95% 2.80% $0.10 $2.38Greenfield CCCT 2x1 - (Dry Cooling) Nat. Gas PAC West - Sea Level Dry Cooling CCCT 36 494 988 $670 35 7,462 4.95% 2.80% $2.78 $9.04

Greenfield CCCT Duct Firing 2x1 - (Dry Cooling) Nat. Gas PAC West - Sea Level Duct Firing with Dry Cooling CCCT 36 124 247 $176 35 9,512 4.95% 2.80% $0.10 $2.49Renewables

East Side Wind (34.5% CF) n/a PAC East Wind 12 50 400 $1,256 20 n/a n/a n/a $0.00 $40.63West Side Wind (33.5% CF) n/a PAC West - Elevation 1500 ' Wind 12 50 300 $1,251 20 n/a n/a 5.00% $0.00 $29.56

East Side Geothermal Geothermal PAC East Various (RFP Data) 24 30 70 $1,650 35 n/a 2.50% 1.00% $2.34 $80.17West Side Geothermal Geothermal PAC West - Elevation 1500 ' Various (RFP Data) 24 40 55 $2,310 35 n/a 4.50% 2.00% $2.34 $93.47

StoragePumped Storage Water/coal PAC East Pumped Hydro 36 200 400 $871 35 0 n/a n/a $0.52 $40.63

Compressed Air Energy Storage (CAES) Gas/Coal PAC East CAES 36 323 323 $799 25 4,330 4.90% 2.80% $1.41 $5.53Compressed Air Energy Storage (CAES) Gas/Coal PAC West - Elevation 1500 ' CAES 36 361 361 $715 25 4,330 4.90% 2.80% $1.26 $4.95Compressed Air Energy Storage (CAES) Gas/Coal PAC West - Sea Level CAES 36 380 380 $679 25 4,330 4.90% 2.80% $1.20 $4.70

Distributed GenerationCHP Nat. Gas PacWest Cogeneration 24 6 6 $919 20 12,590 5.00% 10.0% $5.39 $23.06CHP Nat. Gas PacWest Cogeneration 24 11 11 $833 20 11,765 5.00% 10.0% $5.39 $23.06CHP Nat. Gas PacWest Cogeneration 24 28 28 $718 20 9,945 5.00% 10.0% $4.49 $23.06CHP Nat. Gas PacWest Cogeneration 24 45 45 $630 20 9,220 5.00% 10.0% $3.59 $23.06CHP Nat. Gas PacEast Cogeneration 24 5 5 $1,112 20 12,590 5.00% 10.0% $6.51 $27.89CHP Nat. Gas PacEast Cogeneration 24 9 9 $1,008 20 11,765 5.00% 10.0% $6.51 $27.89CHP Nat. Gas PacEast Cogeneration 24 23 23 $869 20 9,945 5.00% 10.0% $5.43 $27.89CHP Nat. Gas PacEast Cogeneration 24 37 37 $762 20 9,220 5.00% 10.0% $4.34 $27.89

Microturbines Nat. Gas PAC East Gas Turbine 12 0.034 0.343 $1,776 15 15,075 1.00% 1.00% $8.75 $410.02Microturbines Nat. Gas PAC West - Elevation 1500 ' Gas Turbine 12 0.035 0.355 $1,934 15 15,075 1.00% 1.00% $6.53 $356.65Microturbines Nat. Gas PAC West - Sea Level Gas Turbine 12 0.033 0.334 $2,030 15 15,075 1.00% 1.0% $6.20 $338.82

Fuel Cells Nat. Gas PAC East SOFC 12 0.271 3 $3,342 25 7,580 1.00% 1.00% $22.16 $50.89Fuel Cells Nat. Gas PAC West - Elevation 1500 ' SOFC 12 0.279 3 $3,249 25 7,580 1.00% 1.00% $21.54 $49.48Fuel Cells Nat. Gas PAC West - Sea Level SOFC 12 0.279 3 $3,249 25 7,580 1.00% 1.0% $21.54 $49.48

Solar Solar PAC East PV 24 0.108 0.108 $5,309 20 n/a n/a n/a $0.19 $21.24Demand Side (Class 1 Load Control)

Res./Small Comm'l Air Conditioner Control none PacWest Radio Control 36 45 45 n/a 10 n/a 0.00% 0.00% $0.00 $58.35Electric Space/Water Heat Control none PacWest Radio Control 36 45 45 n/a 10 n/a 0.00% 0.00% $0.00 $58.35

Commercial Lighting Control none PacWest Radio Control 36 45 45 n/a 10 n/a 0.00% 0.00% $0.00 $58.35Commercial Cooling Control none PacEast/PacWest Radio Control 36 44 44 n/a 10 n/a 0.00% 0.00% $0.00 $58.90

Irrigation Control none PacEast/PacWest Radio Control 36 44 44 n/a 10 n/a 0.00% 0.00% $0.00 $27.19

Supply Side Resources - CY 2004 $

Page 1 of 2

PacifiCorp 2004 Integrated Resource Plan DRAFT Public Input Meeting June 10, 2004

Supply Side Resources - CY 2004 $

Minimum Load as a percent of Capacity

Minimum Time to Full

Load in Minutes

(Warm Start)

Average Down

Time in Minutes

Cost per Startup (Fuel to

Sync. only)SO2 in

lbs/MMBtuNOx in

lbs/MMBtu

Hg in lbs/trillion

BtuCO2 in

lbs/mmBtu CommentsCoal

Brownfield PC Subcritical 25% 240 720 $15,907 0.059 0.072 0.6 205 Costs based on Hunter 4 Consortium ProposalBrownfield PC Supercritical 25% 240 720 $15,907 0.059 0.072 0.6 205 Data Taken from S&W report dated May 2004.

Greenfield PC 25% 240 720 $15,907 0.059 0.072 0.6 205 Costs based on modified Hunter 4 Consortium ProposalGreenfield IGCC 25% 360 720 $4,483 0.030 0.050 0.6 205 Assume Technology not available for decision till 2006 at earliestGreenfield PC 2 25% 240 720 $15,907 0.059 0.072 1.5 210 Costs based on modified Hunter 4 Consortium Proposal

Natural GasGreenfield SCCT Aero 25% 10 30 $73 0.00059 0.0181 0.255 118 Costs/Performance based on WV and Gadsby 2002 FERC Form 1Intercooled Aero SCCT 25% 10 30 $73 0.00059 0.0110 0.255 118 Not available till 2008 - Capital increased 15% (1 Unit vs 4 Unit comparison)

Greenfield Internal Combustion Engines 50% 10 10 $700 0.00059 0.0200 0.255 118SCCT Frame 25% 25 60 $897 0.00059 0.0323 0.255 118 Two machines - S&W cost study for NBA - VOM based on 8 hour/start

CCCT (2x1) - 4250 feet (Wet Cooling) 25% 130 0 $897 0.00059 0.0110 0.255 118 Not specific to Gadsby Repower Wet CCCT Duct Firing (2x1) 25% 20 0 $0 0.00059 0.0110 0.255 118 Only Available with base CCCT

CCCT 2x1 - 5100 feet (Dry Cooling) 25% 130 0 $897 0.00059 0.0110 0.255 118Dry CCCT Duct Firing 2x1 25% 20 0 $0 0.00059 0.0110 0.255 118 Only Available with CCCTCCCT (2x1) - (Dry Cooling) 25% 130 0 $1,793 0.00059 0.0110 0.255 118 Not available till 2008 Dry CCCT Duct Firing (2x1) 25% 20 0 $0 0.00059 0.0110 0.255 118 Only Available with CCCT

Greenfield SCCT Aero 25% 10 30 $73 0.00060 0.0181 0.255 118 Based on East numbers adjusted by elevation factorIntercooled Aero SCCT 25% 10 30 $73 0.00059 0.0110 0.255 118 Not available till 2008 - Capital increased 15% (1 Unit vs 4 Unit comparison)

Greenfield SCCT Frame (2-7FA) 25% 25 60 $897 0.00060 0.0323 0.255 118 Based on East numbers adjusted by elevation factorGreenfield Internal Combustion Engines 50% 10 10 $700 0.00060 0.0200 0.255 118Greenfield CCCT 2x1 - (Wet Cooling) 25% 130 0 $897 0.00060 0.0110 0.255 118 Longer Permit Time for Wet - Use West Side Dry Fixed O&M

Greenfield CCCT Duct Firing 2x1 - (Wet Cooling) 25% 20 0 $0 0.00060 0.0110 0.255 118 Longer Permit Time for Wet - Use Gadsby Repower Dry Fixed O&MGreenfield CCCT 2x1 - (Dry Cooling) 25% 130 0 $897 0.00060 0.0110 0.255 118 Based on Utah numbers adj. elev. factor

Greenfield CCCT Duct Firing 2x1 - (Dry Cooling) 25% 20 0 $0 0.00060 0.0110 0.255 118 Based on Utah numbers adj. elev. factorGreenfield SCCT Aero 25% 60 30 $73 0.00060 0.0181 0.255 118 Based on East numbers adjusted by elevation factorIntercooled Aero SCCT 25% 10 30 $73 0.00059 0.0110 0.255 118 Not available till 2008 - Capital increased 15% (1 Unit vs 4 Unit comparison)

Greenfield SCCT Frame 25% 25 60 $897 0.00060 0.0323 0.255 118 Based on East numbers adjusted by elevation factorGreenfield Internal Combustion Engines 50% 10 10 $700 0.00060 0.0200 0.255 118Greenfield CCCT 2x1 - (Wet Cooling) 25% 0 30 $897 0.00060 0.0110 0.255 118 Longer Permit Time for Wet - Use West Side Dry Fixed O&M

Greenfield CCCT Duct Firing 2x1 - (Wet Cooling) 25% 0 10 $0 0.00060 0.0110 0.255 118 Longer Permit Time for Wet - Use Gadsby Repower Dry Fixed O&MGreenfield CCCT 2x1 - (Dry Cooling) 25% 0 60 $897 0.00060 0.0110 0.255 118 Based on Utah numbers adjusted by elevation factor

Greenfield CCCT Duct Firing 2x1 - (Dry Cooling) 25% 0 0 $0 0.00060 0.0110 0.255 118 Based on Utah numbers adjusted by elevation factorOther - Renewables

East Side Wind (34.5% CF) 5% 10 0 $0 0.00000 0.0000 0.000 0 Based on 2004 Renewables RFP average responsesWest Side Wind (33.5% CF) 5% 10 0 $0 0.00000 0.0000 0.000 0 Based on 2004 Renewables RFP average responses

East Side Geothermal 25% 60 240 n/a 0.00000 0.0000 0.000 0 Based on RFP Responses (assume fixed O&M includes steam charge)West Side Geothermal 25% 60 240 n/a 0.00000 0.0000 0.000 0 Based on RFP Responses (assume fixed O&M includes steam charge)

StoragePumped Storage 20% 15 480 $0 0.10000 0.4000 3.000 204 Capacity Factor limited to 17% - cost based on system average coal

Compressed Air Energy Storage (CAES) 20% 15 480 $897 0.00059 0.0110 0.255 118 Heat rate for CT = 4,330 Btu/kWh / 0.765 kWh power needed for each kWhCompressed Air Energy Storage (CAES) 20% 15 480 $897 0.00060 0.0181 0.255 118 Heat rate for CT = 4,330 Btu/kWh / 0.765 kWh power needed for each kWhCompressed Air Energy Storage (CAES) 20% 15 480 $897 0.00060 0.0181 0.255 118 Heat rate for CT = 4,330 Btu/kWh / 0.765 kWh power needed for each kWh

Distributed GenerationCHP 0% 120 480 N/A 0.00147 0.0870 0.255 118 CHP information from two sources:CHP 0% 120 480 N/A 0.00147 0.0850 0.255 118 (1) "Gas-Fired Distributed Energy Resource Technolygy Characterization,"CHP 0% 120 480 N/A 0.00147 0.0900 0.255 118 NREL, November, 2003CHP 0% 120 480 N/A 0.00147 0.0870 0.255 118 (2) 2003 IRP assumptions if no updated information from NRELCHP 0% 120 480 N/A 0.00147 0.0870 0.255 118 East units adjusted for altitude: 5% from sea level to 1,500 ft. andCHP 0% 120 480 N/A 0.00147 0.0850 0.255 118 12% for 1,500 ft. to East elevations.CHP 0% 120 480 N/A 0.00147 0.0900 0.255 118CHP 0% 120 480 N/A 0.00147 0.0870 0.255 118

Microturbines 25% 5 240 $0.54 0.00147 0.0338 0.255 118 Microturbine information from two sources:Microturbines 25% 5 240 $0.54 0.00147 0.0338 0.255 118 (1) "Gas-Fired Distributed Energy Resource Technolygy Characterization,"Microturbines 25% 5 240 $0.54 0.00147 0.0338 0.255 118 NREL, November, 2003 (2) 2003 IRP

Fuel Cells 25% 30 240 $6.00 0.00000 0.0070 0.000 118Fuel Cells 25% 30 240 $6.00 0.00000 0.0070 0.000 118Fuel Cells 25% 30 240 $6.00 0.00000 0.0070 0.000 118

Solar 25% 60 720 $0.00 0.00000 0.0000 0.000 0 Data sources: NWPPC, ETO, Sanida Nationa LabsDemand Side (Class 1 Load Control)

Res./Small Comm'l Air Conditioner Control 0% 10 n/a $0.00 0.00000 0.00000 0.00000 0.00000 100 hours per year maximum use, 6 hours per 24 hour period, June-Sept.Electric Space/Water Heat Control 0% 10 n/a $0.00 0.00000 0.00000 0.00000 0.00000 100 hours per year maximum use, 6 hours per 24 hour period, Dec-Feb

Commercial Lighting Control 0% 10 n/a $0.00 0.00000 0.00000 0.00000 0.00000 100 hours per year maximum use, 6 hours per 24 hour period, all monthsCommercial Cooling Control 0% 10 n/a $0.00 0.00000 0.00000 0.00000 0.00000 100 hours per year maximum use, 6 hours per 24 hour period, June-Sept.

Irrigation Control 0% 10 n/a $0.00 0.00000 0.00000 0.00000 0.00000 4 days per week, 6 hours/day, June-mid-Sept.

Emissions

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irp public input meeting - rocky mountain power public input meeting june 10, 2004. 2 ... dummy...

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