Item 3 LEAP Attachement B - Palo Alto, California4. Renewable Resource Analysis UAC/Council...

Attachment B to April 2, 2003 UAC report: LEAP Implementation Plan

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MEMORANDUM

TO: Utilities Advisory Commission

FROM: Utilities Department

SUBJECT: Update on LEAP Implementation

AGENDA DATE: March 5, 2003

REQUEST:

This report is provided for the Commission’s information and discussion only. No action is necessary. Staff plans to present specific recommendations at the Commission’s April meeting. Preliminary recommendations are made in this report and staff desires the Commission’s feedback on these recommendations.

BACKGROUND

The term of the current contract with the Western Area Power Administration (Western) ends on December 31, 2004. In October 2000 Council approved the 20-year Western Base Resource Contract (CMR:378:00) which will replace the existing Western contract in year 2005

At its October 4, 2000 meeting, the Utilities Advisory Commission (UAC) considered staff’s plan to investigate energy supply alternatives for the post-2004 period. The proposed approach was to evaluate a set of alternatives in a deliberate, orderly fashion and subject them to diverse scenarios of the future in order to develop a robust and value-added energy supply portfolio that meets our electric rate payer needs.

In February 2001, the UAC approved an analysis and conceptual recommendations to fill the electric energy deficits expected to occur.

In September 2001, a presentation was made to the UAC outlining strategies that could be adopted to meet the energy deficit. At that time, an initial 25 MW purchase to fill ~15% of the expected energy deficit projected in year 2005 and beyond was recommended. The UAC approved the purchase and a set of primary objectives to guide staff when developing and managing the electric supply portfolio. In November 2001, the City Council approved the 25 MW purchase and the primary objectives (CMR:425:01).

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On October 3, 2001, the UAC received a report on the FY 2001-03 Demand-Side Management (DSM) and Public Benefits plan. The DSM and Public Benefits plan was reported to the Council on December 3, 2001 (CMR:421:01).

On January 9, 2002, the UAC received an analysis of alternative energy resource options for the electric supply portfolio plan. The report discussed both demand-side management initiatives (i.e. energy efficiency and load management) and renewable energy supply options. The Council received an informational report on alternative electric supplies on March 18, 2002 (CMR:176:02).

In June 2002 a comprehensive presentation was made to the UAC based on all prior analysis, customer surveys, and public input. A preliminary set portfolio acquisition guidelines were also proposed to direct staff in the acquisition efforts. After further discussion, the UAC approved a set of seven Long-term Electric Acquisition Plan (LEAP) Guidelines in August 2002. The City Council adopted the LEAP Guidelines on October 21, 2002 (CMR:398:02). Attachment A provides a complete listing of the 7 Guidelines.

The following graphic shows the process for LEAP evaluation so far:

Post 2004 Electric Portfolio Process

1. Portfolio Analysis Presentations;Approval of Energy Risk ManagementPolicies

UAC analysis presentations:Feb 14 & Sept 152001; Council approval of risk managementpolicies, Feb 20, 2001 (CMR: 103:01)

2. Approval of Primary Portfolio PlanningObjectives

UAC/Council approval - 9/25/01 & 11/13/01

(CMR:425:01)

3. Approval of Initial 25 MW Purchase UAC/Council approval - 9/25/01 & 11/13/01 (CMR

425:01)

4. Renewable Resource Analysis UAC/Council presentation - 1/9/02 & 3/18/02(CMR:176:02)

5. Portfolio Plan Update June ‘02 UAC presentation on LEAP GuidelinesCouncil approved 10/21/02 (CMR:398:02)

7. Final Plan & Implementation Process Today’s UAC presentation - Action from UACrequested in April 2003

8. Specific Deal Approval Requests To UAC/Council, when required 2003-2004

6. Additional Public Input August 1, 2002 - Energy Forum #4

To do

Completed


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EXECUTIVE SUMMARY

The City is moving from a position of electric load-resource balance over the past 40 years, with primary reliance on Western and NCPA-owned resources, to a position of a large energy deficit, multiple suppliers, and introduction of new risk elements. As the City makes this transition, staff is in the process of reformulating its operating strategy to ensure that adequate systems and controls are in place to plan and manage a more complex electric supply portfolio.

A number of elements must be considered when making such a transition.

1. There must be a clear understanding of the City’s primary portfolio planning objectives and long-term supply options that will be considered by the City. This to a large part has been achieved with the City Council’s approval of the 4 Primary Portfolio Planning Objectives and the 7 LEAP Guidelines.

2. The development of short- (~ 1 year) and medium- (~3 years) term plans to implement elements of the approved long-term supply options to ensure that the goals of reliable supply at low, stable and competitive retail rates are achieved.

3. The assurance that the City has adequate operational expertise and systems to manage a more complex electric supply portfolio in a streamlined manner.

While constantly monitoring gas and electric market prices, staff is in ongoing discussions with suppliers, potential partners, and NCPA to gain an understanding of resource options and strategies. In addition, staff continues to monitor other situations that have an impact on any future decision, including regulatory proceedings such as those related to transmission access, pricing and policies. Using that information, staff conducted evaluations and analysis of many resource and portfolio options in the context of the many remaining uncertainties. This report outlines staff’s analysis, recommendations and implementation strategies for the long-term and the short-term electric supply portfolios.

Long-term Supply Portfolio Implementation RecommendationsThe implementation plan at this time for the long-term supply acquisition consists of the following elements:

1. Begin acquiring renewable energy resources to meet LEAP Guideline 7. The first step is to issue a Request for Proposals (RFP) to potential suppliers. NCPA is coordinating this activity as many of its members have an interest in acquiring new renewables for the post-2004 period.

2. Continue to monitor opportunities for participation in gas-fired generation as they arise. This occurs through staff’s contacts in the market and at NCPA.

3. Monitor technology costs and opportunities for smaller cogeneration and gas-fired generation that can be located within Palo Alto and/or at customer sites.


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4. Continue to discuss gas tolling options with suppliers. To effectively use tolling contracts, Palo Alto may need to be able to purchase gas financial products. Staff will investigate using these products and, if attractive, will pursue approval from the Risk Oversight Committee and the Council to add these products to the list of approved products in the Energy Risk Management Policies.

Short-term Supply Portfolio Implementation RecommendationsThe short-term implementation plan consists of the following elements:

1. To reduce cost variability and to diversify the purchase commitments in tenor and timing, while leaving sufficient flexibility to commit to long-term resources, three fixed-price block purchases are being contemplated for execution in year 2003: a. Block 1 – 25 MW, around-the-clock for the months September through March

for 2005-2007. b. Block 2 – 25 MW for peak periods only for the months September through

December for 2005-2006. c. Block 3 – 25 MW for peak periods only for all months for 2005.

2. Seek Council approval of a set of master agreements with suppliers by summer 2003 with the authority to transact for terms of up to 3 years out. Any transactions outside the 3-year limit, although still able to be executed under the master agreements, will be brought to the UAC and Council for approval. The Block 3 purchase can be executed using these master agreements since its term is within the 3-year allowable term if executed in 2003. The Block 1 and Block 2 purchases are outside the 3-year term limitation, therefore, staff expects to seek specific Council approval of those purchases in the next six months.

Planning and Management of Supply Procurement OperationsThe City expects to utilize its master agreements with suppliers to contract for supplies for terms greater than approximately a year or when there are no benefits of transaction through NCPA. As the number of transactions and the complexity of the electric portfolio increases, the need to closely monitor and report transactions increases, too. Utilities plans to compare skill sets needed for the future with those of existing staff and address any gaps with training and to evaluate the potential of utilizing alternative software tools. In addition, Utilities must be ever vigilant to control overhead costs with the goal of remaining competitive. Costs from within Utilities and from other City departments and NCPA bear constant monitoring.

In summary, the planning and management of short- and long-term supply procurement operations is expected to be undertaken at the present staffing levels with the objectives of:

Clearly identifying and capturing supply needs and supply portfolio risks;


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Whenever possible, utilizing simple tools to manage risks and utilizing NCPA resources and expertise; and

Managing the electric portfolio to achieve the portfolio objectives with streamlined operations to minimize overhead costs and to act expeditiously, while maintaining the appropriate level of oversight and control.

DISCUSSION

Long-term Supply Portfolio Development

There are many portfolios that can be developed that fall within the Council-approved LEAP Guidelines. To be in compliance with those guidelines, each portfolio must have the following common elements:

1. Maintaining adequate supply rate stabilization reserve 2. Assuming average hydrologic condition, be exposed to market prices for a

minimum of 10% of expected load for 2 to 5 years out 3. Assuming average hydrologic condition, be exposed to market prices for a

minimum of 25% of expected load for 5 to 20 years out 4. Target thermal plant ownership (or equivalent) of between 25 and 50 MW 5. Maximum term of 10 years for fixed-price energy purchase contracts 6. Ensure the reliability of supply at fair and reasonable transmission cost 7. Monitor the potential of local generation options 8. Procure 10% new renewables by 2008, 20% new renewables by 2015 provided

that the rate impact does not exceed 0.5¢/kWh 9. Continue to fund energy efficiency programs using the 2.85% Public Benefits

charge

If these components are combined, the base portfolio for the next thirty years is shown in the chart below:


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The long-term deficit remaining to be filled over the next 20 years is most acute in the years 2005-2010 as the investment in new renewables is ramping up. There are many potential portfolios that comply with the LEAP Guidelines. A range of portfolios with different “themes” has been identified. They include the following:

1. Do Nothing Portfolio – this portfolio assumes that no new long-term commitments are made for the post-2004 period except for complying with the new renewables guideline. This alternative is included as a baseline for comparison.

2. Base Portfolio – make no additional commitments beyond the 25 MW thermal generation. This portfolio has the maximum exposure to market prices. The deficit will be filled in with short-term purchases of less than a year length to real-time spot market purchases. The gas purchased for the 25 MW of thermal generation is assumed to float with market prices.

3. Maximum Fixed-Price Market Purchases – commit to fixed-price contracts with different terms (2-, 3-, 5-, and 10-year contracts) totaling the maximum allowable without violating the minimum exposure to market requirements of the guidelines. In addition, purchase the gas for 25 MW of thermal generation on a fixed-price basis.

Electric Resources in AVERAGE Hydro Year

0

200

400

600

800

1000

12002005

2006

2007

2008

2009

2010

2011

2012

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2015

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2034

GW

h/y

ea

r

New Renewables (Phase 1)

Western Base Resource

Calaveras

25 MW

Resource Deficit

25 MW Thermal Base Load Plant (with unhedged gas cost)

Deficit to remain exposed to market (spot) prices

New Renewables (Phase 2)


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4. Maximum Thermal Portfolio – commit to 50 MW of thermal generation ownership. The gas purchased for the generation is assumed to float with market prices.

5. Maximum Tolling Portfolio – commit to 25 MW of short-term (maximum 10-year) of round-the-clock thermal tolling contracts. The gas purchased for the generation is assumed to float with market prices.

6. Maximum Local Resources Portfolio – commit to a total of 50 MW ownership of gas-fired generation within the City of Palo Alto. This could take the form of joint ownership of combined cycle, co-generation, or other efficient-low emission technologies or siting 2-5 MW generation and co-generation plants at customer facilities dispersed around the City. The gas purchased for the generation is assumed to float with market prices.

7. Minimum Hydro Portfolio – divest all of the 54 MW Calaveras resource. Fill in greater deficit with 25 MW of fixed-price contract commitment (maximum term = 10 years). The gas purchased for the 25 MW of thermal generation is assumed to float with market prices.

8. Super Green Portfolio – all new commitments made are for green resources. Maximize demand-side efficiency programs and customer site co-generation.

9. Minimum Exposure to Congestion Portfolio – Commit to ownership of 25 MW of large generation plant in Bay Area. Commit to ownership of 25 MW of generation sited within Palo Alto. The gas purchased for the generation is assumed to float with market prices.

10. Hydro Hedge – in this portfolio, it is assumed that Palo Alto could find a partner who would be willing to take the hydrologic risk in the Western Base Resource product. The City would pay the partner an annual fee and in return would get the average year output from the Western Base Resource every year regardless of hydro conditions. The gas purchased for the 25 MW of thermal generation is assumed to float with market prices.

Long-term Supply Portfolio Analysis

The ten portfolios were developed so as to test a wide range of potential strategies. The evaluation plan was to look at results from the tested portfolios and determine the expected costs and mark-to-market valuations as well as the risks of, or uncertainty around, those results. To evaluate the portfolios, a spreadsheet model was developed to calculate the monthly cost for each of the portfolios. Attachment C describes the assumptions used to characterize the resource options and for the uncertain variables.Attachment D provides a synopsis of the analysis approach and results.

Future UncertaintiesAssumptions were made for every uncertain variable. “Base” projections”, or “50%” values, were developed for the key uncertain variables. In addition, “low” (10%) and “high” (90%) values were developed. The ranges used for each key uncertain variable are shown in the chart below:


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Uncertain Variable Low (10%)

Value

Base (50%)

Value

High (90%)

Value

Hydrologic Year Dry Average Wet

Electric Market Prices Low Base High

Gas Market Prices Low Base High

Western Annual Cost $6 million $7.25 million $10 million

Western Cost Escalation Rate 1%/year 3%/year 5%/year

Western Availability Degradation 0%/year 1%/year 3%/year

Congestion Cost – Outside Bay Area * $1/MWh $3/MWh $5/MWh

Congestion Cost – Inside Bay Area * $0/MWh $0.50/MWh $1/MWh

* Congestion costs are highly uncertain and could be much higher than the values used in this analysis. Congestion cost outside the Bay Area could be as high as $20/MWh. Congestion costs inside the Bay Area could be as high as $10/MWh.

Results of AnalysisAn expected value of the annual average cost of each portfolio was calculated given the assumptions for each uncertain variable and the probabilities assigned to the low, base, and high values. Attachment D provides a brief account of the major results. In summary, the portfolio with the lowest expected cost was the “Maximum Thermal Portfolio”, the portfolio with 50 MW of gas-fired generation located outside the Bay Area. The results of the analysis comparing the portfolios over a 20-year period is shown in the following graph:

LEAP Portfolio ResultsCost to Serve Load (sorted by Expected Value)

45

50

55

60

65

70

75

80

85

90

95

Max

. The

rmal

Min. C

onge

stion

Max

. Fixed

Price

Min. H

ydro

Max

. Loc

al

Base

Max

. Toll

Hyd

ro H

edge

Do

Not

hing

Super

Gre

en

EV

of

Co

st

to S

erv

e L

oa

d (

$ m

illio

n/y

ea

r)

Expected Value

High (90%) Cost

Low (10%) Cost

Medium (50%) Cost


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Long-term Implementation Plan

The results of the analysis and the market information staff has gained at this time indicates that a long-term commitment to a large, efficient, gas-fired generation plant be pursued. However, there are many options and uncertainties that remain that make staff shy away from pursuing such a commitment at this time. First, Palo Alto is not in a position to drive the construction of such a plant. Second, the cost of congestion is not known at this time and the resolution of that issue could greatly impact Palo Alto’s cost for many of the portfolio options.

Efforts by NCPA with active support by Palo Alto to build a plant in Lodi and to buy a merchant plant in the bay area have not been successful. However, staff is participating in a joint request for proposal with other NCPA members to procure long-term renewable resources and is confident that, before the year end, the City will be able to make a long-term commitment for renewable energy that will meet 5-10% of the City’s projected load.The cost premium is expected to be ~1¢/kWh over market energy prices for a generic firm resource with a corresponding seasonal generation profile.

The implementation plan at this time for the long-term supply acquisition consists of the following elements:

Preferred Recommendations for Long-term Portfolio

1. Begin acquiring renewable energy resources to meet LEAP Guideline 7. The first step is to issue a Request for Proposals (RFP) to potential suppliers. NCPA is coordinating this activity as many of its members have an interest in acquiring new renewables for the post-2004 period.

2. Continue to monitor opportunities for participation in gas-fired generation as they arise. This occurs through staff’s contacts in the market and at NCPA.

3. Monitor technology costs and opportunities for smaller cogeneration and gas-fired generation that can be located within Palo Alto and/or at customer sites.

4. Continue to discuss gas tolling options with suppliers. To effectively use tolling contracts, Palo Alto must be able to purchase gas financial products. Staff will investigate using these products and, if attractive, will pursue approval from the Council to add these products to the list of approved products in the Energy Risk Management Policies.

The analysis completed is representative of information known at this time about the resource options and possible states of the future (e.g. market price projections, congestion cost estimates, etc.). The analysis of the portfolio options will necessarily change as assumptions change and as new information on actual projects and products is established. Staff intends to use the model, and especially the development of future scenarios, to evaluate new opportunities that arise and any products that are offered by suppliers for the City’s consideration. As such, the model is a framework that will be


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utilized to examine responses to requests for proposals that the City may issue in its quest to find supplies to fill the resource “hole” after 2005 that meet the LEAP Guidelines.

Short-term Supply Portfolio Development

The long-term portfolio plan was developed with a long-term view, and it includes, by design, exposure to market prices of at least 10% of the load (LEAP Guideline 3).Therefore, staff will need to actively manage the portfolio in the short term (0 to 3 years out) to fill the expected deficits in average hydro years and to make adjustments as actual availability of Western and Calaveras is better known.

As explained in the long-term implementation plan, it is not expected that the 25-50 MW of thermal generation identified in the long-term plan will be in place by 2005, or even 2007. To limit exposures and to provide rate stability, staff recommends a laddering approach to fill the expected deficits over the next three years. Since the time of the year of most need in all hydro year types is the fall and winter, the purchases are heavily weighted to those time periods. Three energy blocks are contemplated to fill the deficits in the coming months include:

Short-term Purchases (2005-2007)

1. A fixed-price purchase of 25 MW, around-the-clock during Q1 (January, February, and March), September, and Q4 (October, November, and December) for three years (2005 through 2007).

2. A fixed-price purchase of 25 MW, during the heavy load period for 4 months (September through December) for two years (2005 and 2006).

3. A fixed-price purchase of 25 MW, during the heavy load period for every month of the year for calendar year 2005.


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Assuming average hydrologic conditions and that 10% new renewable resources (shaped like wind, the most likely renewables purchase in the short-term) are in place, the portfolio for the next three years is shown in the following chart:

Short-term Supply Portfolio Analysis

The cost of the portfolio for years 2005-2007 was modeled with and without the three block purchases. The model calculated the expected costs and mark-to-market valuations as well as the risks around those results. As in the long-term analysis, assumptions and ranges of values were made for key uncertain variables: hydrologic year, electric market prices, and wind year.

The results showed that, as expected, the three proposed block purchases would reduce the risk (cost variability). The hydrologic year is the uncertainty causing the greatest cost risk. The results show that the cost to serve the load ranges1 from about $29 to $67

1 The ranges used here span 90% of the distribution, or from the 5% to 95% of the cumulative distribution of the cost.

Load/Resource Balance - 2005-2007

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20,000

40,000

60,000

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100,000

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5

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b-0

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th

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Western

Coral Purch

Block 1

Block 2

Block 3

Deficit

2005: 7% exposed 2006: 19% exposed 2007: 23% exposed


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million/year (with an expected value of about $43 million/year) for 2005-2007 if no commitments are made. Note that the range from low to high is about $38 million/year.If the three block purchases are made, the cost to serve the load ranges from about $30 to $62.5 million/year, a reduction in the range of cost by about $5.5 million/year.

The chart below indicates the sources of the risk in cost that can be attributed to hydrologic year, electricity market prices, and both together.

The City should ensure that the Supply Rate Stabilization Reserve (SRSR) is adequate to ensure stable rates in such an environment of uncertainty. For example, if the hydrologic year is dry, the expected value of the average annual cost is about $56 million, or about $13 million more than an average hydro year. Staff is conducting analysis on the proper target for the SRSR and considering potential guidelines such as being able to maintain stable rates in the event of two dry years in a row.

Short- and Medium-term Implementation Plan

Guideline 3 sets the upper limit for fixed price resource commitments in the medium term, with a minimum market exposure of 10% of expected load for 2 to 5 years out. Given that we are in year 2003, this guideline provides the 90% maximum fixed price resource targets until year 2008. It, however, does not provide a minimum target, except

Source of Cost Risk90% Range of Average Cost of 2005-2007 with and without 3 block purchases

0

5

10

15

20

25

30

35

40

hydro/elect price hydro only elect. price only hydro/elect price hydro only elect. price only

Uncertainties Included

Ran

ge (

hig

h-l

ow

) o

f C

ost

to S

erv

e L

oad

($m

illio

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ear)

Without Block Purchases With Block Purchases


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the long-term resource already available and the fixed-price renewable resource commitments.

Staff will undertake analyses of alternatives taking in to consideration the City’s resource balance, retail rate targets, and reserve positions before making resource procurements in the short- to medium-term that fit under the LEAP Guidelines.

The short-term implementation plan consists of the following elements:

Preferred Recommendations for Short-term Portfolio

1. To reduce this cost variability and to ladder the purchase commitments, while leaving sufficient flexibility to commit to long-term resources, three fixed-price block purchases are being contemplated for execution in year 2003:

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

on-pk X X X X X X X Block 1

(2005-2007) off-pk X X X X X X X on-pk X X X X Block 2

(2005-2006) off-pk on-pk X X X X X X X X X X X X Block 3

(2005) off-pk

2. Seek Council approval of a set of master agreements with suppliers by summer 2003 with the authority to transact for terms of up to 3 years out. Any transactions outside this limit will be brought to the UAC and Council for approval. The Block 3 purchase can be executed using these master agreements since its term is within the 3-year allowable term if executed in 2003. The Block 1 and Block 2 purchases are outside the 3-year term limitation, therefore, staff expects to seek specific Council approval of those purchases in the next six months.

Planning and Management of Supply Procurement Operations

The functions of electric procurement, supply risk management, contracting, resource and contract optimization, balancing, coordination of dispatch and scheduling functions with NCPA, and billing and settlement functions of the City are primarily organized under the Assistant Director of Utilities Resource Management. The City achieves large economies of scale by leveraging NCPA’s contracting and market expertise when procuring resources.

The City expects to utilize its master agreement with suppliers to contract for supplies for terms greater than approximately a year or when benefits of transaction through NCPA are non-existent. The additional cost associated with closer monitoring and control of long-term supply contracts may be justified for these contracts with a term of a year or


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longer based on higher likelihood of supplier default, value loss that may be associated with defaults, and the higher dollar amount associated with such transactions.

The City’s present electric portfolio modeling efforts are centered around interlinked spreadsheet based models with optimization routines. As the number of transaction and complexity of the electric portfolio increases and the need to closely monitor and report transactions arise, the City will be evaluating the potential of utilizing other software tools.

The City’s Energy Risk Management Policies and Guidelines along with Portfolio Planning Objectives and LEAP Guidelines provide the framework for operations and control. The recent addition of a dedicated Energy Risk Manager will strengthen oversight and control and will facilitate reporting procedures to the Risk Oversight Committee and to the UAC and Council.

In summary, the planning and management of short- and long-term supply procurement operations is expected to be undertaken at the present staffing levels with the objectives of:

Clearly identifying and capturing supply needs and supply portfolio risks;

Whenever possible, utilizing simple tools to manage risks and utilizing NCPA resources and expertise; and

Managing the electric portfolio to achieve the portfolio objectives with streamlined operations to minimize overhead costs and to act expeditiously, while maintaining the appropriate level of oversight and control.

NEXT STEPS

The final LEAP Implementation Plan will be presented to UAC at its April 2003 meeting.Council will be asked to approve the plan in May or June. Council will be asked to approve master enabling agreements in the June or July of 2003. Council authorization will be sought as required for specific transactions.

ATTACHMENTS:

A. LEAP Guidelines approved by the City Council B. Description of Existing Supply Resources C. Portfolio Modeling Assumptions D. Portfolio Modeling Results

PREPARED BY: ________________________________________ Shiva Swaminathan and Jane Ratchye


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Senior Resource Planners, Resource Management

REVIEWED BY: ___________________________ Girish Balachandran

Assistant Director, Resource Management

APPROVED BY: ___________________________ John Ulrich

Director of Utilities

Attachment B to April 2, 2003 UAC Report: LEAP Implementation Plan

Attachment A

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Attachment A: LEAP Guidelines approved by the City Council (October 21, 2002 –

CMR:398:02)

Guideline 1: Electric Portfolio Dependence on Western – While maintaining the flexibility to adopt favorable ‘custom products’ offered by Western, manage a supply portfolio independent of Western beyond the Base Resource Contract.

Guideline 2: Hydro Risk Management – Manage hydro production risk by: A. Planning for an average hydro year on a long-term basis; B. Diversifying to renewable and/or fossil generation technologies; and C. Maintaining adequate supply rate stabilization reserve.

Guideline 3: Market Risk Management – Manage market risk by adopting a portfolio strategy for electric supply procurement by:

A. Diversifying energy purchases across commitment date, start-date, duration, suppliers, pricing terms and fuel sources;

B. Targeting additional thermal plant ownership/investment commitment at ~25 MW but in no event more than 50 MW;

C. Maintaining a prudent exposure to changing market prices by: 1. Procuring resources at fixed price for at most 90% of expected load for 2 or more

years out, assuming average hydro conditions; and 2. Procuring resources at fixed price for at most 75% of expected load for 5 or more

years out, assuming average hydro conditions; and D. Avoiding contract-based fixed price energy purchases (except for contracts for renewable

resources) for durations greater than 10 years.

Guideline 4: Reliable and Cost Effective Transmission Services – Ensure the reliability of supply at fair and reasonable transmission cost by:

A. Supporting, through political and technical advocacy and/or direct investment, the upgrading of Bay Area transmission to improve reliability and relieve congestion;

B. Participating in transmission market design to ensure that market design results in workable competitive markets and equitable cost allocation;

C. Pursuing the option of forming and/or joining a Public Power Transmission Control Area to increase control over transmission operations and related costs; and

D. Ensuring PG&E honors the Stanislaus Commitments by providing to us firm-transmission rights or equivalent.

Guideline 5: Local Generation – Monitor the potential of local generation options to meet customer needs, improve local reliability, minimize congestion and wheeling charges, and stabilize/reduce costs.


Attachment A

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Guideline 6: Renewable Portfolio Investments – The City shall continue to offer a renewable resource-based retail rate for all customers who want to voluntarily select an increased content of renewable energy. In addition to the voluntary program, the City shall invest in new renewable resources to meet the City’s sustainability goals while ensuring that the retail rate impact does not exceed 0.5 ¢/kWh on average. Pursue a target level of new renewable purchases of 10% of the expected portfolio load by 2008 and move to a 20% target by 2015, contingent on economic viability. The contracts for investment in renewable resources are not to exceed 30 years in term.

Guideline 7: Electric Energy Efficiency Investments – Offer quality Public Benefits programs, utilizing funds collected through the 2.85% Public Benefits charge embedded in electric retail rates, to meet the resource efficiency needs of customers. Additional funding for cost-effective programs will be recommended as appropriate. Pursue these investments by:

A. Providing expertise, education and incentives to support cost-effective customer efficiency improvements;

B. Demonstrating renewable and/or alternative generation technologies and new efficiency alternatives; and

C. Providing rate assistance and efficiency programs to low-income customers.


Attachment B

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Attachment B: Description of Existing Supply Resources

The table below shows CPAU’s inventory of existing generation and transmission resources that will be available in year 2005.

Inventory of CPAU’s Existing Generation and Transmission Portfolio, Year 2005

Asset or Resource Term/

Expiry

Nominal

Capacit

y (MW)

Expected

Energy

(GWh/yr)

Dry Year

Energy

(GWh/yr)

Wet Year

Energy

(GWh/yr)

Unit Cost (after

removing

stranded cost)

Western Base Resource 2024 ~175 383 222 568 $19/MWh*

Calaveras Hydroelectric

plant

2032 54 130 48 235 $32/MWh*

SCL receipt (June-Oct) 2014 10 16 16 16 NA

SCL return (Nov-April) 2014 (9) (21) (21) (21) NA

25 MW, Q1 & Q4 contract 2009 NA 110 110 110 $36.60/MWh

COTP Transmission 50 NA NA NA $1.7million/yr

TOTAL 618 375 908 $25/MWh (energy only)

* The average unit cost is shown for average hydrologic conditions and can vary widely depending on the hydro conditions.

Description of the Western Base Resource

Western’s Base Resource is a very different product than the current Western Commercial Firm product. Currently, Western provides a capacity and energy allocation with minimum and maximum hourly, monthly, and yearly entitlements. Beginning in 2005, Palo Alto must commit to pay an 11.62024 percentage share of Western’s costs (Palo Alto share is expected to be ~$9 million per year) in exchange for the same percentage of the daily output from the Base Resource. Therefore, the Base Resource is essentially a slice of the available hydroelectric resource. As such, it is a non-firm2 product and is subject to uncertain water supply conditions and uncertain water pumping load obligations.

Western’s Base Resource is defined as the resource “available after meeting the requirements of Project Use [water pumps for the Central Valley Project (CVP)] and First Preference customers [customers from the ‘counties of origin’, where the CVP Trinity and New Melones dams are located] and any adjustments for maintenance, reserves, transformation losses and certain ancillary services”. The generation designated as the Base Resource consists of: 1) CVP generation, which provides the majority of the energy produced; 2) a power purchase contract for 50 megawatts (MW) of peak load hour, market-priced energy that terminates in 2014; and 3) generation from the Washoe project, which is a small project located in northeast California producing an average annual generation of 10 gigawatt-hours (GWh).

Western is currently negotiating with the supplier for the 50 MW of peak load power to terminate that contract in exchange for a lump sum payment. Therefore, staff expects that this power will not be part of the Western Base Resource.

2 Firm supplies are those whose delivery can be counted on. Non-firm supplies can be interrupted for any reason (e.g. unit outage, hydrologic conditions, or economics).


Attachment B

19

Additionally, though not included in staff’s interpretation of the Base Resource contract, Western is proposing to include a several year, fixed–price, 4- to 6-month purchase of ~200 GWh/year to help meet Project Use obligations. If implemented, Palo Alto will be allocated its share (11.62%) of this purchase.

The estimated average annual energy available from Western’s Base Resource (CVP generation less Project Use obligations) is expected to be ~3,300 GWh. CVP generation is highly dependent on water supply conditions. During a dry year, the corresponding energy available is 1,900 GWh/year. A wet year is expected to produce 4,900 GWh/year. CVP generation is also dependent on environmental regulations and constraints and water delivery obligations to CVP water customers and can change periodically. The potential impact of Trinity River restoration issues could reduce Base Resource energy availability by ~10% from projected levels (CMR:423:02, October 21, 2002).

Due to a variety of reasons, staff expects that the output from the Western Base Resource will gradually degrade over time. Continuing regulatory pressure, environmental issues and pressure from new users are expected to increase over time and, thereby, reduce the amount of power available for Western’s Base Resource product.

Palo Alto’s Base Resource Allocation and CostSince Palo Alto’s Base Resource allocation is about 11.6 percent, the energy available should be approximately 380 GWh/year in an average year. Annual energy available to Palo Alto in dry and wet years are expected to be 220 GWh and 570 GWh, respectively. This compares to Palo Alto’s energy entitlement of 1000 GWh/year in the current Western contract and Palo Alto’s fiscal year 2001-02 load of approximately 1100 GWh.

Western’s Base Resource (without the 50 MW power purchase) is expected to cost about $62 million/year. This means that Palo Alto’s 11.6 percent obligation will be about $7.25 million/year regardless of how much of the Base Resource is available and utilized by Palo Alto. Thus, in an average hydrologic year, the cost of Base Resource energy in 2005 is expected to be about $19 per megawatt-hour (MWh). In a dry year (10th percentile), the 2005 cost of Base Resource energy could be $33/MWh. Extremely dry years could increase costs even more. A wet year would yield more energy (90th percentile), at an estimated cost of only $13/MWh in 2005. These cost, even in a dry year, compare favorable to the estimated market value of energy for 2005 of approximately $40-45/MWh.

Description of the Calaveras Resource

The 250 MW Calaveras hydroelectric power plant is situated along the North Fork of the Stanislaus River in Calaveras County. The Northern California Power Agency (NCPA) owns and operates this power plant. The City of Palo Alto has a permanent share of 21.6%, or 54 MW. The City temporarily divested 16 MW of the plant ownership; however, this capacity reverts back to the City in January 2005 so that the City will again have access to its permanent share of 54 MW of the plant output.


Attachment B

20

As with the Western Base Resource product, output from the Calaveras project is subject to hydro conditions. Palo Alto’s share of the expected output in an average hydro year is 130 GWh/year with dry and wet hydro years yielding 48 GWh/year and 235 GWh/year, respectively.The Calaveras project, coupled with the Western Base Resource, makes the bulk of the existing supply portfolio highly subject to variable hydro conditions.

The bulk of the cost of the Calaveras project consists of debt payments. The variable operational and maintenance costs are small, as are the annual fixed maintenance costs. The City pre-collected part of the investment cost of the Calaveras project that were deemed “stranded costs” associated with this plant via increased retail rates during the 1997-1999 period. Thus, the remaining costs result in this resource being competitively priced at the prevailing electricity prices.

Seattle City Light Energy Exchange Contract

This 10 MW contract with Seattle City Light (SCL) was entered into in 1994 and is expected to end in 2014. Through this contract the City receives energy from June through October, and returns energy to SCL from November to April. This contract, though a very small portion of the supply portfolio, has served Palo Alto well in meeting the City’s energy needs, which are greater in the summer period of energy receipt than in the winter return period.

Description of the Council-approved 5-year, 25 MW Q1/Q4 Contract

Since the post-2004 deficit is so pronounced in the fall and winter months, staff desired to partially fill the “hole” with a medium-term purchase after market prices had fallen significantly from the highs of 2000 and 2001. On November 13, 2001, the City Council approved staff’s proposal to purchase 25 MW of round-the-clock energy for the months of January, February, and March (Quarter 1, or Q1) and October, November, and December (Quarter 4, or Q4) for a five year term between years 2005 and 2009 (CMR:425:01). On August 13, 2002, a contract was executed with Coral Power, LLC for the approved product for a price of $36.60/MWh.

COTP Transmission

The California-Oregon Transmission Project is a 500 kV/1,600 MVA high voltage, 350 mile transmission line from the Oregon border to Northern California. The City owns 50 MW of this transmission line and utilizes it for access to generation resources in the Pacific Northwest. For example, the SCL contract energy receipts and deliveries are transmitted via this line.

The City pre-collected part of the investment cost associated with COTP that were deemed “stranded costs” via increased retail rates during the 1997-1999 period.

With the creation of the Independent Systems Operator in California (CAISO), the transmission grid operator, there is a possibility that Palo Alto may turn over the operation of the transmission line to the CAISO. Palo Alto will, in turn, be provided first preference for the use of the line. Another option being considered is to utilize the transmission to facilitate a new transmission control area for municipal utilities in conjunction with Western.


Attachment B

21

Load and Resource Balance

Adjusting the load by the SCL contract obligations, the figure below shows the stack of supply resources available to meet load in an average hydro year for the years 2005-2009. Included in this stack is the 10% new renewables target for 2008 that is found in LEAP Guideline #6. That guideline also proposes a 20% new renewables fraction by 2015

Resource Deficit in 2008AVERAGE Hydro Year

0

20,000

40,000

60,000

80,000

100,000

120,000


MW

h/y

ear

Deficit

Calaveras

Western Base Resource

25 MW purch

10% New Renewables

Load (SCL adjusted)


Attachment B

22

Supply Variability due to Hydrologic Conditions

The monthly energy availability of the existing generation portfolio, its variability based on hydro conditions, and the energy deficit that needs to be filled to meet City load is shown below.

Existing Energy Portfolio Characteristics

The existing resource portfolio can be characterized as follows:

a. There are insufficient energy resources to meet the City’s annual energy needs of ~1,100 GWh in the 2005. The projected shortfall in an average hydro year is ~500 GWh, or ~45% of the total annual needs.

b. The energy deficit is highly variable by month with greater deficits in the fall and winter than in the spring months.

c. The total existing generation is highly variable and dependent on annual hydro conditions. In a normal hydro year the total energy available (given 10% renewables in place) is ~730 GWh/year, while wet and dry year generation are 490 GWh /year and 1020 GWh/year respectively.

d. The total generation capacity3 is close to the City’s capacity needs; hence, the deficit is mainly related to energy and not capacity.

3 Generation capacity is the rated load-carrying capability, typically expressed in megawatts (MW). Capacity is the peak amount of instantaneous production a generator can supply. It is analogous to peak demand on the demand side. The City must have sufficient supply generation capacity to meet its peak demand.

2008 Supply Resources

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000


MW

h/y

ea

r

Add'l Hydro in Ave. Hydro Year

Dry Year Hydro Resource

25 MW purchase

10% New Renewables

Add'l Hydro in Wet Hydro Year SCL Adjusted Load


Attachment B

23

e. The energy limited hydroelectric resource capacity is well suited to provide ancillary services. The City is expected to have an overall surplus of ancillary service provision capability.

f. The portfolio contains some diversity in that it has access to Pacific Northwest resources due to ownership of COTP transmission.

g. The existing non-new renewable resources are low cost resources, with an average unit cost of ~$25/MWh compared to current market energy prices of ~$45/MWh.

h. Hydro variability is lowest in fall months when deficits are the greatest. The greatest hydro variability is in the winter and spring months (December-May).


Attachment C

24

Attachment C: Portfolio Modeling Assumptions

Evaluation of the LEAP portfolios requires making many assumptions about the future. This attachment is a brief documentation of the key variables used in the spreadsheet model.

PortfoliosA set of portfolios consisting of a group of resources was developed. The portfolios included:

1. Do Nothing Portfolio – this portfolio assumes that no new long-term commitments are made for the post-2004 period except for complying with the new renewables guideline.This alternative is included as a baseline for comparison.

2. Base Portfolio – make no additional commitments beyond the 25 MW thermal generation. This portfolio has the maximum exposure to market prices. The deficit will be filled in with short-term purchases of less than a year length to real-time spot market purchases. The gas purchased for the 25 MW of thermal generation is assumed to float with market prices.

3. Maximum Fixed-Price Market Purchases – commit to fixed-price contracts with different terms (2-, 3-, 5-, and 10-year contracts) totaling the maximum allowable without violating the minimum exposure to market requirements of the guidelines. In addition, purchase the gas for 25 MW of thermal generation on a fixed-price basis.

4. Maximum Thermal Portfolio – commit to 50 MW of thermal generation ownership. The gas purchased for the generation is assumed to float with market prices.

5. Maximum Tolling Portfolio – commit to 25 MW of short-term (maximum 10-year) of round-the-clock thermal tolling contracts. The gas purchased for the generation is assumed to float with market prices.

6. Maximum Local Resources Portfolio – commit to a total of 50 MW ownership of gas-fired generation within the City of Palo Alto. This could take the form of joint ownership of combined cycle, co-generation, or other efficient-low emission technologies or siting 2-5 MW generation and co-generation plants at customer facilities dispersed around the City. The gas purchased for the generation is assumed to float with market prices.

7. Minimum Hydro Portfolio – divest all of the 54 MW Calaveras resource. Fill in greater deficit with 25 MW of fixed-price contract commitment (maximum term = 10 years). The gas purchased for the 25 MW of thermal generation is assumed to float with market prices.

8. Super Green Portfolio – all new commitments made are for green resources. Maximize demand-side efficiency programs and customer site co-generation.

9. Minimum Exposure to Congestion Portfolio – Commit to ownership of 25 MW of large generation plant in Bay Area. Commit to ownership of 25 MW of generation sited within Palo Alto. The gas purchased for the generation is assumed to float with market prices.

10. Hydro Hedge – in this portfolio, it is assumed that Palo Alto could find a partner who would be willing to take the hydrologic risk in the Western Base Resource product. The City would pay the partner an annual fee and in return would get the average year output from the Western Base Resource every year regardless of hydro conditions. The gas purchased for the 25 MW of thermal generation is assumed to float with market prices.

For purposes of modeling these portfolio options, the following thermal resources were assumed:


Attachment C

25

Description Heat Rate

(Btu/kWh)

Fixed cost (capital

and fixed O&M)

($/MW-yr)

Variable

O&M

($/MWh)

Outside Bay Area Generation 7400 $46,000 $2.00

Inside Bay Area Generation 7200 $67,000 $3.00

Local Generation 9000 $81,000 $5.00

Tolling Contract (take-or-pay) 7000 $66,000 $2.00

A matrix of the resources in each portfolio is shown below:

Resources

Do n

oth

ing

Base

Max F

ixed

Pri

ce

Ma

x.

Th

erm

al

Ma

x.

To

ll

Max. L

oca

l

Min

. H

yd

ro

Su

per

Gre

en

Min

.

Con

ges

tion

Hy

dro

Hed

ge

Western X X X X X X X X X X 1

Calaveras X X X X X X layoff

X X X

Coral Q1/Q4

purchase

X X X X X X X X X X

Seattle City Light X X X X X X X X X X

Renewables 2 100%

100%

100%

100%

100%

100%

100%

200%

100%

100%

Additional DSM

Programs 3 Yes Yes

Forward Purchase 25MW

25MW

Outside Bay Area

Generation

25MW

25MW

50MW

25MW

25MW

Inside Bay Area

Generation

25MW

Local Generation 50MW

Tolling Contract

(take-or-pay)

25MW

Gas Exposure 4 float float fix float float float float N/A float float

Notes:1 Output = average year output every year (no hydrologic uncertainty from Western) 2 Super Green Portfolio to have renewables at twice that required by LEAP Guidelines 3 Enhanced DSM programs to reduce load by 5%. 4 Whether to lock in the gas price for thermal generation or let it float at market prices


Attachment C

26

Resources

WesternThe output from the Western Base Resource is assumed to be as estimated by Western and be dependent upon the hydrologic year type. This resource is a part of all portfolios. For the “Hydro Hedge Portfolio”, the output is assumed to be as for an average hydrologic year for every year.

CalaverasThe output from the Calaveras Hydroelectric Project is assumed to be as estimated by NCPA and be dependent upon the hydrologic year type. NCPA’s estimates are based on years of actual hydrologic data. This resource is a part of all portfolios except for the “Minimum Hydro Portfolio”, in which the resource is laid off in order to reduce the hydrologic exposure for that portfolio.

Seattle City Light ContractThe SCL contract obligations are specified in the contract and are expected to expire when the contract expires in 2014. This resource is a part of all portfolios.

25 MW Q1/Q4 PurchaseThis forward purchase is for 25 MW of energy round-the-clock for Quarter 1 (January, February, and March) and Quarter 4 (October, November, and December) for the years 2005-2009. The contract cost is $36.60/MWH for all hours of the contract. This resource is a part of all portfolios.

New Renewables ProgramThe LEAP Guidelines require increased investment in new renewable technologies. The target of 10% of load by 2008 and 20% of load by 2015 is assumed in all the portfolios. The cost for these resources is assumed to cost $25/MWh above the cost of today’s forward cost for electricity in the market. This will result in an increased cost of about 0.5¢/kWh as allowed by the LEAP guidelines. This resource is in all the portfolios except for the “Super Green Portfolio”, which has twice as much new renewables as required in the guidelines.

Forward PurchaseForward purchases are priced at the forward electric market prices at the time of the analysis. The “Maximum Fixed-Price Portfolio” has a fixed-price forward purchase for 25 MW of on-peak energy and 10 MW of off-peak energy. The “Minimum Hydro Portfolio” includes a fixed-price forward purchase for 25 MW of on-peak energy. No other portfolio includes forward purchases.

Thermal Generation Sited outside the Bay AreaThis thermal generation, assumed to be combined cycle technology, has a 7400 Btu/kWh heat rate and a 95% availability factor (assumes it is unavailable due to maintenance, etc. 5% of the time). The annual fixed costs (capital and fixed O&M) are estimated at $3.83/kW-month, or $46,000/MW-year. This corresponds to $800/kW of fixed costs financed over 30 years at an interest rate of 4%/year. Variable O&M costs are assumed to be $2/MWh escalating at 3%/year.Twenty-five megawatts (25 MW) of this resource is a part of the following portfolios: “Base”,


Attachment C

27

“Maximum Fixed-Price”, “Minimum Hydro”, and “Hydro Hedge”. 50MW of this resource is part of the “Maximum Thermal Portfolio”. Gas costs are assumed to float with market prices for all portfolios except the “Maximum Fixed-Price Portfolio”, which is assumed to fixed the gas prices for greater cost certainty.

These cost estimates are supported from ongoing communication with marketers, suppliers, NCPA, a recent Wall Street Journal report and the analysis of a municipal utility in the Central Valley considering such a generator.

Thermal Generation Sited inside the Bay AreaThis combined-cycle thermal generation assumes a 7200 Btu/kWh heat rate and a 95% availability factor. It has a better heat rate than the outside Bay Area generation due to the more moderate temperatures in the Bay Area than in the Central Valley, the likely site for generation outside the Bay Area. Due to higher labor and permitting costs in the Bay Area, the costs of this generation are assumed to be higher than if located in the Central Valley. The annual fixed costs (capital and fixed O&M) are estimated at $5.58/kW-month, or $67,000/MW-year. This corresponds to $1150/kW of fixed costs financed over 30 years at an interest rate of 4%/year.Variable O&M costs are assumed to be $3/MWh escalating at 3%/year. Gas costs are assumed to float with market prices. Twenty-five megawatts (25 MW) of this generation resource is a part of the “Minimum Congestion Portfolio”.

These cost estimates are based on recent negotiations with a merchant plant developer in the Bay Area and discussions with a municipal utility building generation in the Bay Area.

Locally Sited GenerationThermal generation sited locally is assumed to have a 9000 Btu/kWh heat rate and a 95% availability factor. Its heat rate is consistent with a combustion turbine technology for a 50 MW unit. The annual fixed costs (capital and fixed O&M) are estimated at $6.75/kW-month, or $81,000/MW-year. This corresponds to $1400/kW of fixed costs financed over 30 years at an interest rate of 4%/year. Variable O&M costs are assumed to be $5/MWh escalating at 3%/year.Gas costs are assumed to float with market prices. The “Maximum Local Portfolio” has 50 MW of this resource.

Gas Tolling AgreementA price for a gas-tolling contract was developed to try to reflect the costs of thermal generation. It is a take-or-pay type contract for round-the-clock energy. Its cost is $5.50/kW-month, or fixed costs of $66,000/MW-year. Variable costs are assumed to be $2/MWh, escalating at 3%/year. The heat rate is 7000 Btu/kWh and the gas costs are assumed to float with market prices. The “Maximum Toll Portfolio” has 25 MW of this resource.

Expanded DSM ProgramThe load forecast in the model assumes ongoing Demand-Side Management programs are in place. The “Super Green Portfolio” and the “Minimum Congestion Portfolio” are assumed to have an additional 5% of load reductions due to aggressive DSM programs. The costs for these programs are estimated to cost $50/MWh above the costs of market priced electricity.


Attachment C

28

Hydrologic HedgeIn the “Hydrologic Hedge Portfolio” a hedge for hydrologic risk is in place. This hedge assumes that the output from the Western Base Resource is constant at the average hydro year output.For this certainty, the City pays $5/MWh. This cost is assumed to escalate at 3%/year.

Ranges for Key Uncertain Variables

Hydrologic YearHydrologic condition is a key variable for Palo Alto’s post-2004 portfolios. Production from both the Western Base Resource and the Calaveras Hydroelectric Project change with hydrologic year. Production estimates in “wet” (90% of the time, it is expected to be drier than this), “average” (50%) and “dry” (it is only drier than this 10% of the time) years were obtained from Western for the Western Base Resource and from NCPA for the Calaveras resource. Together the impact of hydrologic year on production from the hydro-based resources is shown on the following chart:

Electric Market PricesElectricity market prices were developed from on-peak market quotes as of the time of the analysis (January 31, 2003) through calendar year 2007. “Base” electric market costs were expected to increase at 3%/year after 2007. Off-peak prices were assumed to be priced at 30% discount from on-peak prices. This is in line with marketer quotes for off-peak energy through calendar year 2007. A “high” electric spot price scenario was developed that used an escalation rate of 3.7%/year after 2007. Similarly, the “low” electric spot price scenario has a 1.3%/year escalation after 2007. The resulting range of electric prices is shown in the chart below:

Monthly Hydro-Based Resource Production

versus Hydrologic Year Type

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000


Pro

du

ctio

n (

MW

h/m

on

th)

Dry Year ProductionAdd'l Available

in Average Year

Add'l Available in Wet Year


Attachment C

29

Due to the predominance of natural gas as a fuel source for electricity generation in California, long-term forward market prices during the fall and winter months have been higher than the summer months to reflect the higher gas prices during this period.

In the uncertainty analysis, it was assumed that electric prices depend somewhat on hydrologic year. In a wet year, electric prices are more likely to be low than high and, conversely, more likely to be high than low in a dry year.

Gas Market PricesGas market prices were developed from market quotes as of the time of the analysis (January 31, 2003). Ranges were developed to capture the uncertainty in those estimates. A “high” range assumed prices 50% higher than the base and the “low” estimate was 30% lower than the base estimate. The resulting range of gas market prices is shown in the following chart:

Electricity Market Price Forecast at NP15 (round-the-clock)

$20

$30

$40

$50

$60

$70

$80

$90

$100

$110

$120

2004

2006

2008

2010

2012

2014

2016

2018

2020

2022

2024

$/M

Wh

Forward Price

Low Spot Market

High Spot Market

Base Spot Market


Attachment C

30

In the uncertainty analysis, it was assumed that gas and electric prices are somewhat correlated. If electric prices are high, gas prices are more likely to be high than low and, conversely, if electric prices are low, gas prices are likely to be low than high.

Western Annual CostThe fixed annual cost of the Western resource is uncertain due to increasing O&M costs, different cost allocation schemes between water and power customers, etc. The cost for the Western Base Resource is assumed to be about $7.25 million/year without Western’s Enron purchase contract included. This variable was assumed to be uncertain and in a range of $6 million to $10 million per year.

Western Annual Cost Escalation RateThe cost for the hydroelectric part of the Base Resource is assumed to escalate at 3%/year. A range from 1%/year to 5%/year was tested for this uncertain variable.

Western Availability DegradationThere is some uncertainty with regard to the long-term energy available under the Western Base Resource contract. These uncertainties include the extent of energy purchases by Western and included within the Base Resource, the long-term decline of electricity production due to various environmental considerations, the extent of project use and first preference customer energy delivery obligations, etc. The estimated decline in availability is about 1%/year. A range from 0%/year to 3%/year was tested for this uncertain variable.

Gas Market Price Forecasts

$2

$3

$4

$5

$6

$7

$8

$9

$10

$11

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

Gas P

rice (

$/M

MB

tu)

Base Forecast

High Forecast

Low Forecast


Attachment C

31

Congestion Cost for Outside Bay AreaDue to Palo Alto’s location in the Bay Area, it is expected to pay congestion costs for bringing resources located outside the Bay Area into Palo Alto. These costs are highly uncertain and could be as high as $20/MWh. For purposes of this analysis, the base value for congestion costs was set at $3/MWh, escalating at 3%/year. A range of from $1/MWh to $5/MWh was used to test the sensitivity of the variable.

Congestion Cost for Inside Bay AreaThe costs of congestion for resources inside the Bay Area are highly uncertain and could be as high as $10/MWh. For purposes of this analysis, the costs are expected to be between $0 and $1.00/MWH, with an expected cost of $0.50/MWH. The cost is estimated to increase at a rate of 3%/year.

Miscellaneous Uncertain Variables

Palo Alto LoadsA long-term load forecast was developed using standard forecasting methodology. The load is not increasing and is lower than actual load in FY 99-00. It is assumed that DSM programs that have been implemented would continue to hold down load growth as well as the fact that Palo Alto is basically built out.

Discount rateThe City’s discount rate is assumed to be 4%/year for the duration of the analysis period.Changing this variable will not change the outcome of the analysis.

Transmission costsTransmission costs to the citygate are assumed to be $5.50/MWh, escalating at 3%/year for the duration of the analysis period. Changing this variable is not expected to change the outcome of the analysis. This cost is avoided for resources sited locally, including enhanced DSM programs.


Attachment D

32

Attachment D: Portfolio Modeling Results

Analysis Approach

The ten portfolios were developed so as to test a wide range of potential strategies. The evaluation plan was to look at results from the tested portfolios and determine the expected costs and mark-to-market valuations as well as the risks of, or uncertainty around, those results. To evaluate the portfolios, a spreadsheet model was developed to calculate the monthly cost for each of the portfolios. Assumptions were made for every uncertain variable and ranges were developed for the most significant variables. Attachment C lists all assumptions used to characterize the resource options and for the uncertain variables.

Uncertain VariablesAlthough there are many assumptions required to model the alternatives, some are expected to be the most significant for the purposes of the analysis. Those critical variables include:

1. Hydrologic year – production from both the Western Base Resource and the Calaveras Hydroelectric Project change with water availability, or hydrologic year. Production estimates in “wet” (90% of the time, it is expected to be drier than this), “average” (50%) and “dry” (it is only drier than this 10% of the time) years were used in the analysis.

2. Electric market prices – the long-term forward curve for electric prices was developed from on-peak market quotes through calendar year 2007 and estimated for the period after 2007. “Base” electric market costs were expected to increase at 3%/year after 2007.“High” and “low” electric spot price scenarios were developed to test sensitivity of the portfolios to unknown future electric prices.

3. Gas market prices – the long-term forward curve for gas prices was developed from market quotes. Ranges were developed to capture the uncertainty in those estimates.

4. Western annual cost – consistent with a hydroelectric resource, the yearly cost for the Western Base Resource is largely independent from the output of the Base Resource.

5. Western annual cost escalation rate – since Western is such a large resource in the electric portfolio, the overall portfolio costs are expected to be dependent upon the assumption for future Western costs.

6. Western long-term production degradation – due to regulatory, environmental and other pressures, the availability of Western is expected to decline over time.

7. Congestion Cost for Outside Bay Area – the costs of congestion that must be paid to bring resources located outside the Bay Area into Palo Alto.

8. Congestion Cost for Inside Bay Area – the costs of congestion that must be paid to bring resources located inside the Bay Area into Palo Alto.

Ranges for Uncertain Variables“Base” projections”, or “50%” values, were developed for the key uncertain variables. In addition, “low” (10%) and “high” (90%) values were developed. Attachment C provides additional detail for each uncertain variables.


Attachment D

33

The ranges used in the analysis for each uncertain variable are shown in the chart below:

Uncertain Variable Low (10%)

Value

Base (50%)

Value

High (90%)

Value

Hydrologic Year Dry Average Wet

Electric Market Prices Low Base High

Gas Market Prices Low Base High

Western Annual Cost $6 million $7.25 million $10 million

Western Cost Escalation Rate 1%/year 3%/year 5%/year

Western Availability Degradation 0%/year 1%/year 3%/year

Congestion Cost – Outside Bay Area * $1/MWh $3/MWh $5/MWh

Congestion Cost – Inside Bay Area * $0/MWh $0.50/MWh $1/MWh

* Congestion costs are highly uncertain and could be much higher than the values used in this analysis. Congestion cost outside the Bay Area could be as high as $20/MWh. Congestion costs inside the Bay Area could be as high as $10/MWh.

Results

The cost to serve the projected load was calculated for each portfolio using the assumptions and uncertainties described. In addition, the cost to serve the load from the market was also calculated so that each portfolio could be “marked-to-market”, or compared to the cost to serve the load at electric market prices. An expected value of the cost and the mark-to-market valuation was developed given the assumptions for each uncertain variable and the probabilities assigned to the low, base, and high values.


Attachment D

34

Cost to Serve LoadThe cost to serve load includes all costs of the supply portfolio to meet the projected load in an average year over the 20-year modeling period. With the assumptions used in the analysis, including the uncertainties, the portfolio with the lowest expected value was the “Maximum Thermal Portfolio”, the portfolio with 50 MW of gas-fired generation located outside the Bay Area. The expected value of the cost for an average year was about $64 million/year. The range of cost, given the uncertainties, was from a low (10%) of $49 million to a high (90%) of $81 million. The results of the analysis comparing the portfolios is shown in the following graph:

Mark-to-Market ValueMark-to-market (MTM) value is a comparison of the cost to serve load to the cost to serve the load at market prices. For example, if it would cost $75 million to serve the load at market prices and the cost to serve the load of a particular portfolio was $65 million, that portfolio would have a MTM value of $10 million. It is important to calculate the MTM value of portfolios, especially the risk of having a negative MTM value, so that decision-makers can determine the risks to locking in to long-term contracts or commitments under changing market conditions. With the assumptions used in the analysis, including the uncertainties, the portfolio with the highest expected value for MTM was the “Maximum Thermal Portfolio”, the portfolio

LEAP Portfolio ResultsCost to Serve Load (sorted by Expected Value)

45

50

55

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Attachment D

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with 50 MW of gas-fired generation located outside the Bay Area. The expected value of the MTM for an average year was about $64 million/year. The MTM ranged from a low (10%) of $49 million to a high (90%) of $81 million. The results of the analysis comparing the MTM of the portfolios is shown in the following graph:

Risk/Reward Comparison – Cost to Serve LoadAs discussed in this analysis, the cost to serve load is uncertain and depends on many uncertain variables. The actual cost is expected to lie somewhere between the high (90% value) and low (10%value) cost. The plot below shows the expected value of the cost to serve load on the x-axis and the risk of the cost to serve load on the y-axis. The risk is the difference between the high and low values for cost.

The chart below illustrates the relationship between cost to serve load and the risk on cost to serve load for all the portfolios except “Do Nothing”(which had extremely high risk) and “Super Green” (which was very costly). The best portfolio from a cost to serve load perspective would have low cost to serve load and low risk of cost to serve load. The chart of cost and the risk in

LEAP Portfolio ResultsMark-to-Market Value (sorted by Expected Value)

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Attachment D

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cost shows that there are some portfolios that are superior to others since either their cost is lower at the same or less risk or the risk is less at the same or less cost. For example, the “Maximum Local Portfolio” is more costly and higher risk than the “Minimum Congestion Portfolio”. While the “Maximum Thermal Portfolio” is the lowest cost, there are several portfolios with lower risk. Although the “Minimum Hydro Portfolio” has the lowest risk, its expected cost is $2.25 million higher than the “Maximum Thermal Portfolio’s”.

Risk/Reward Comparison – Mark-to-MarketAs discussed in this analysis, the mark-to-market value of each portfolio is uncertain and depends on many uncertain variables. The actual MTM value is expected to lie somewhere between the high (90% value) and low (10%value) MTM value. The plot below shows the expected value of the MTM value on the x-axis and the risk of the MTM value on the y-axis.The risk is the difference between the high and low values for MTM.

The chart below illustrates the relationship between MTM value and the risk on MTM value for all the portfolios except “Do Nothing” (which had extremely high risk) and “Super Green” (which had extremely low MTM value). The best portfolio from a MTM perspective would have high MTM values and low risk of MTM value. The “Maximum Thermal Portfolio” has the highest expected value for MTM ($15.1 million), but a relatively high risk on MTM ($36.1

LEAP Portfolio Analysis Results

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Attachment D

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million). The portfolio with the lowest risk ($28.2 million) on MTM is the “Hydro Hedge Portfolio”, but it also has the lowest MTM value ($10.4 million). The Base Portfolio” is in between with a MTM value of $12.5 million and a risk on MTM of $31.2 million.

Sensitive Variables

The variables with the greatest impact on the risk were hydrologic year, electric market price, and gas market price. Hydrologic year was by far the greatest source of risk, followed by electric market price.

Hydrologic Year TypeNot surprisingly, hydro risk is the greatest source of risk for the portfolios. For example, if all other variables were held at their base values, the variation in hydrologic year type alone would cause the cost of the “Maximum Thermal Portfolio” to vary from $50 million to $74 million. Although the costs varied the most due to uncertainty around the hydrologic year, most of the portfolios don’t differ as to hydro resource content. Only the “Minimum Hydro” (laying off the Calaveras resource) and “Hydro Hedge” (purchase a hedge against Western Base Resource variability) portfolios show less risk than other portfolios. However, the reduction of that risk comes at a cost.

LEAP Portfolio Analysis Results

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Electric Market PricesThe cost of the “Maximum Thermal Portfolio” varies from $57.5 to $70 million/year if all other variables are held at their base values while the electric cost projection is varied from “low” to “high”. This is less than the variation in hydrologic year, but still significant.

Gas Market PricesThe cost of the “Maximum Thermal Portfolio” varies from $58 to $67 million/year if all other variables are held at their base values while the gas cost projection is varied from “low” to “high”. This is less than the variation in hydrologic year or electric market price uncertainty, but still significant. This variation could be reduced if gas costs were fixed, instead of being allowed to float with the market. However, if allowed to float, the risk on Mark-to-Market valuation would increase.

Portfolio Sensitivities

Maximum Thermal PortfolioThis portfolio is sensitive to both electric and gas market prices. The cost risk could be reduced if gas prices were locked in, rather than allowed to float. If the capital costs of the thermal generation increased from the assumed annual fixed costs (capital and fixed O&M) of at $3.83/kW-month to ~ $7/kW-month, then the Minimum Congestion Portfolio is superior.

Minimum Congestion PortfolioThis portfolio is highly sensitive to the cost of congestion. This variable is a very uncertain one given the lack of consensus on the outcome of several ongoing regulatory initiatives. If congestion costs for outside and inside the Bay Area were ~ $10-12/MWh and $2/MWh, respectively, then the cost of all the portfolios would increase and the Minimum Congestion Portfolio would be the lowest cost portfolio.

Maximum Fixed Price PortfolioThis portfolio has greater cost, but less risk than the Maximum Thermal Portfolio, but is superior to the Base Portfolio on both cost and risk. It is sensitive to electric market prices and if prices are lower than expected, then this has a greater risk of having a negative mark-to-market value. The reason that the Maximum Thermal Portfolio has a lower expected cost is that the spark spread encourages thermal generation. If gas prices rose with respect to electric prices, this would not be the case and 25 MW of generation would likely be superior to 50 MW.

Minimum Hydro PortfolioThis portfolio is quite sensitive to electric market prices as the Calaveras project is laid off at the current valuation, which is based on the forward curve for electric prices. If electric prices increase, then the layoff would have been unfortunate. However, the risk could be reduced by purchasing electricity at a fixed-price for the expected output from the plant.

Maximum Local PortfolioThis portfolio, as with the Minimum Congestion Portfolio, is sensitive to congestion costs. If congestion costs were higher than projected, this portfolio would become much more attractive.

Item 3 LEAP Attachement B - Palo Alto, California4. Renewable Resource Analysis UAC/Council...

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Transcript of Item 3 LEAP Attachement B - Palo Alto, California4. Renewable Resource Analysis UAC/Council...