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									           BEFORE THE PUBLIC UTILITIES COMMISSION
                OF THE STATE OF COLORADO




IN THE MATTER OF THE APPLICATION OF   1
PUBLIC SERVICE COMPANY OF COLORADO    )   DOCKET NO.
FOR APPROVAL OF ITS 2007 COLORADO     1
RESOURCE PLAN                         1




       DIRECT TESTIMONY AND EXHIBITS OF KAREN T. HYDE

                            ON

                        BEHALF OF

            PUBLIC SERVICE COMPANY OF COLORADO




                      November 15,2007
                        BEFORE THE PUBLIC UTILITIES COMMISSION
                             OF THE STATE OF COLORADO




     IN THE MATTER OF THE APPLICATION OF                                 )
     PUBLIC SERVICE COMPANY OF COLORADO                                  )    DOCKET NO.
     FOR APPROVAL OF ITS 2007 COLORADO                                   )
     RESOURCE PLAN                                                       1


                DIRECT TESTIMONY AND EXHIBITS OF KAREN T. HYDE

                                                      INDEX

SECTION                                                                                                       PAGE

1.     INTRODUCTION AND PURPOSE OF TESTIMONY .........................................
                                                                                     I

 I
I.     INTERRELATIONSHIPS AMONG APPLICATIONS FILED BETWEEN

       OCTOBER 31, 2007 AND NOVEMBER 21, 2007 .............................................
                                                                                          3

111.   OVERVIEW OF THE CRP .................................................................................
                                                                                                           5

IV.    DETAILS OF THE CRP ...................................................................................20

v.     DSM, ISOC, AND RES.....................................................................................
                                                                                                             28

VI.    PLANT RETIREMENTS AND REPOWERING ................................................
                                                                                       31

VI.    WIND ACQUISITION PLAN AND RFP............................................................
                                                                                               38

VII. ALL SOURCE NEED AND RFP ......................................................................
                                                                                                  54

VIII. SMALL PROJECTS.........................................................................................
                                                                                                           68

IX. SB07-100 .........................................................................................................
                                                                                                                     71

X.     PLAN COMPARISON AND SUMMARY..........................................................
                                                                                           71
              BEFORE THE PUBLIC UTILITIES COMMISSION
                   OF THE STATE OF COLORADO


IN THE MATTER OF THE APPLICATION OF              )
PUBLIC SERVICE COMPANY OF COLORADO               )
FOR APPROVAL OF ITS 2007 COLORADO                )   Docket No.
RESOURCE PLAN                                    1

        DIRECT TESTIMONY AND EXHIBITS OF KAREN T. HYDE


         1.      INTRODUCTION AND PURPOSE OF TESTIMONY

    PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

    Karen T. Hyde. 550 Fifteenth Street, Denver, Colorado 80202.

    BY WHOM ARE YOU EMPLOYED AND             IN WHAT CAPACITY?
    I am employed by Xcel Energy Services Inc., the service company subsidiary

   of Xcel Energy Inc., the registered public utility holding company parent of

    Public Service Company of Colorado ("Public Service", or "Company"). My

   title is Vice President, Resource Planning and Acquisition. My qualifications

   are included as Attachment A to this direct testimony.

   WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY?

    I present policy testimony associated with the Colorado Resource Plan

   ("CRP"), which is filed as part of this application, and I outline how this

   application coordinates with several other contemporaneous Company

   applications. 1 provide an overview for the Commission and interested parties

   of the CRP.    I am the Company's primary sponsor of the 2007 Colorado

   Resource Plan ("CRP"), which I present as Exhibit No. KTH-1. I explain the

   Company's goals in developing our 2007 CRP.              I introduce the three
alternative resource plans required under the Commission's Resource

Planning Rules.     I describe the Company's preferred resource plan and

explain how this plan furthers the Company's goal of reducing our carbon

emissions, while serving increased load in a reliable manner and keeping

rates at reasonable levels.   I describe the new methods of competitive

acquisition that the Company proposes to use in order to avoid adverse

financial impacts from lease accounting and imputed debt by credit rating

agencies. I explain why the Company wishes to retire early four coal units

and replace them with a combined cycle gas facility in order to achieve

carbon reduction benefits, and why a rule waiver should be granted to allow

us to do so.

       I also introduce the testimony of other Public Service witnesses.

Several other Company witnesses will address various sections of this CRP

in their testimonies.

WHAT OTHER COMPANY WITNESSES FILED TESTIMONY WITH THIS

APPLICATION?

Mr. Prager, the Company's Vice President of Environmental Policy filed

testimony that outlines the current options being debated by states and the

federal government in how to reduce carbon emissions to address climate

change concerns, and the compelling case for Public Service to take action

today to reduce our carbon emissions. Ms. Madden, the Vice President and

Controller, describes the lease accounting issues impacting the Company's

purchased power agreements ("PPAs").       Mr. Tyson, Vice President and
      Treasurer, details the financial implications of these lease accounting issues

      and how credit rating agencies treat purchased power agreements when

      rating utilities.

              Jim Hill, Manager, Resource Planning, describes the analysis of the

      three alternative cases and the development of the Company's preferred

      plan. Mr. Hill supports those sections of the CRP in my Exhibit No. KTH-1.

      Jannell Marks, Director, Energy and Demand Forecasting, describes the

      demand and sales forecast methodology used in the CRP. Greg Ford,

      Director, Engineering and Design Services, describes the Arapahoe

      combined cycle facility that the Company proposes to use to replace the

      retired Cameo and Arapahoe coal units.              Gary Magno, Principal

      Environmental Analyst, describes the emission reductions that the Company

      expects to obtain by replacing these coal units with a gas combined cycle unit

      and the permitting advantage that Public Service has for constructing a

      combined cycle facility at the Arapahoe site.      Gerry Stellern, Manager,

      Transmission Reliability Assessment, supports the transmission issues

      discussed in the CRP.


II.       INTERRELATIONSHIPS AMONG APPLICATIONS FILED BETWEEN
               OCTOBER 31,2007 AND NOVEMBER 21,2007

      CAN YOU LIST THE APPLICATIONS FILED BY THE COMPANY THAT

      ARE LINKED IN SOME WAY TO THE COLORADO RESOURCE PLAN

      FILED IN THIS DOCKET?

      Yes. The recent applications are summarized in Table KTH-1.
                                           -
                        Table KTH - 1 Summary of Applications

Application                        Purpose         How incorporated in
                                                   CRP?
Approval of DSM'         Requests approval of the   Proposed levels of DSM
                         Company's proposal for    are included in the CRP
                         demand side management through reductions in
                                                   forecast demand and
                                                   energy requirements
Approval of ISOC~        Requests approval of the  Proposed levels of
                         modifications to the      interruptible load are
                         current ISOC program for  included in the CRP
                         load management           through reduction in
                                                   forecast demand
Approval of Pawnee -     Seeks CPCN approval to    RFPs filed with CRP
                   in
Smoky Hill C P C N ~     construct new             include information on
compliance with SB07-100 transmission and          available transmission in
                         determination of          SB07-100 areas, including
                         appropriate Noise and     this new transmission line
                         EMF levels
Submittal of SB07-100    Describes the Designation RFPs include direction
Zone Designation and     of Energy Resource        when transmission is likely
Transmission plans4      Zones; describes the      available in SB07-100
                         transmission plan for     areas and the impact on
                         those zones               RFP evaluations
For approval of the 2008 Describes Company's       On-site solar and early
Renewable Energy         eligible energy resource  central solar acquisitions
Standard Compliance      acquisitions for          are detailed in the RES
Plan ("2008 RES Plan")   compliance in 2008 and    and are included in the
                         establishes the needed    CRP. The CRP seeks
                         RESA levels to meet the   approval of other
                         Company's preferred plan renewable resource
                         in this CRP docket        additions that will be
                                                   funded by the RESA and
                                                   other mechanisms.

Q.      IS THE COMPANY SEEKING CONSOLIDATION OF THESE DOCKETS?



' Application for the approval of Public Service Electric Demand Side Management program, Docket
No. 07A-420E, filed October 31, 2007.
  Advice Letter 1495-Electric, for the approval of Public Service Electric Interruptible Service Option
Credit program, filed November 1, 2007
3
  Application for the approval of Public Service Pawnee - Smoky Hill 345 kV Transmission Project,
Docket No. 07A-421E, filed October 31, 2007
4
  Submittal of Public Service compliance filing under SB07-100, filed October 31, 2007, also posted at
http://www.rmao.com/wtpp/SBl00.     html.
A.   No. We have filed for appropriate approvals in each docket. In the CRP, we

     have assumed that the requests that we have made in the other dockets will

     be granted.   Notwithstanding that assumption, I believe that our CRP is

     flexible enough to accommodate whatever the results may be in each of

     those dockets. Because some of these dockets have shorter time frames

     than this CRP docket, we would like to preserve those shorter decision time

     frames.


                       Ill.   OVERVIEW OF THE CRP

Q.   PLEASE DESCRIBE THE COLORADO RESOURCE PLAN, OR CRP, THAT

     IS CONTAINED IN YOUR EXHIBIT NO. KTH-I?

A.   It is four volumes of detailed information and plans filed in compliance with

     Commission Resource Planning Rules ("RP Rules").           The first volume

     includes the executive summary and the details of the plan. The second

     volume is the technical appendix which includes much of the detailed

     information required by the RP Rules as well as more detail about the

     information provided in Volume 1. Volume 3 contains the Wind Request for

     Proposals and the associated model agreements. Volume 4 contains the All-

     Source RFP and the associated model agreements. The CRP explains our

     proposed resource acquisitions between now and 2015 and provides general

     information about resource additions in the period from 2016 through 2046.

Q.   WHAT PRINCIPLES GUIDED THE COMPANY IN THE DEVELOPMENT OF

     THE 2007 COLORADO RESOURCE PLAN?
We had five major objectives to guide our development of the plan. First and

foremost, we developed a plan that reliably met our customers' growing

desire for electric energy in a cost-effective manner.      Second, we were

mindful of the carbon emissions associated with our plan and we worked to

find and propose resources that met our first objective of reliable service at

just and reasonable rates, but that, for the first time, reduced the overall

amount of carbon dioxide that the Company would emit or cause to be

emitted to meet our customers' energy needs. You will see that our preferred

plan, which is the plan that we are asking the Commission to approve, meets

our growing customer needs while reducing the amount of carbon dioxide

produced by our system resources (both owned resources and the resources

that supply our purchased power agreements).

      Third, we wanted to develop a plan that increased our system fuel

diversity, both as a percentage of generation and in absolute terms. This was

important to us because of concerns that our customers might face ever

increasing reliance on natural gas generation that will expose them to price

volatility (both high and low prices) over time. Our preferred plan shows that

by 2015 we will use significantly less natural gas than we will in 2007, due in

part to increased renewable generation and in part to completion of the highly

efficient Comanche 3 coal plant in 2010. Our plan also shows significantly

higher levels of renewable energy generation, which we believe is consistent

with the intent of HB07-1281.
       Fourth, we wanted to ensure that the Company remained a financially

healthy company and an attractive investment for shareholders. To achieve

this goal, we had to find a way to reduce our exposure to the balance sheet

effects of lease accounting and imputed debt from PPAs. We propose to

ameliorate these problems through changes to the competitive resource

acquisition processes.

       Fifth, we wanted to continue to be a leader on environmental issues by

taking prudent steps today, even when not yet required for compliance, so as

to mitigate future risks for our customers and create a plan that was in the

long-term best interest of our customers and our community.

PLEASE      DESCRIBE       THE     IMPACT     OF     RECENT      COMMISSION

RULEMAKING ON PUBLIC SERVICE'S FILING.

Beginning July 3, 2007, the Commission conducted an emergency

rulemaking to align Commission resource acquisition rules with revisions

stemming for recent legislative changes, in particular, HB07-1037, HB07-

1281, and HB06-1281.

       HB07-1037 established energy savings goals and peak reduction

goals for utility energy efficiency and demand side management programs

and created incentives for utilities to invest in cost-effective DSM. HB07-1037

stated that the primary goal of electric utility resource planning is to minimize

the net present value of revenue requirements, but that due consideration

must be given the impact of DSM programs on non-participants and on low-

income customers. This statute required the Commission to change the LCP
Rules, which had formerly employed the minimization of the net present value

of rate impacts as its objective standard.

       HB07-1281 increased the renewable energy resources that Public

Service must acquire for compliance with the Renewable Energy Standard

("RES"). Figure KTH-1 shows the new compliance requirements. Because of

the preference for renewable resources voiced by the General Assembly, the

Commission eliminated the previous rule provisions that required resource

acquisitions be "fuel neutral".

          Figure KTH-1- Increase in RES due to HB07-1281




       HB 06-1281, enacted by the 2006 General Assembly, encouraged

utilities to propose, fund, and construct integrated gasification combined cycle

("IGCC") generation facilities that demonstrate the use of IGCC technology

using Colorado or other western coal and that demonstrate the capture and

sequestration of a portion of the project's carbon dioxide emissions. As Frank
1   Prager discusses, Public Service is still investigating IGCC technology for our

    electric system. In this 2007 CRP, we are not recommending the construction

    of an IGCC facility during the resource acquisition period, although we believe

    that IGCC is a feasible and effective method of using coal to generate

    electricity in an environmentally responsible manner. At this point, we have

    delayed the in-service of the plant until 2016, which is outside of the RAP,

    and will continue to work to resolve regulatory, liability, and partnership

    Issues.

    NEW RULE 3604 (j) INTRODUCES A NEW CONCEPT OF SCENARIO

    PLANNING.      CAN YOU PROVIDE A DESCRIPTION OF HOW THE

    COMPANY HAS INTERPRETED THIS NEW RULE?

    Yes. Rule 36040') states:

                 The plan shall include the following:

          Descriptions of three alternate scenarios that can be used to represent,
          after the receipt of bids to the utility's competitive acquisition process,
          the costs and benefits from increasing amounts of Section 123
          resources included in a cost-effective resource plan. One of the three
          scenarios shall represent a baseline case that describes the costs and
          benefits of the new utility resources required to meet the utility's needs
          during the planning period that minimize the net present value of
          revenue requirements consistent with reliability considerations,
          financial, and development risks, and the evaluation criteria approved
          by the Commission under rule 3613 and that complies with the
          Renewable Energy Standard as well as with the demand-side
          management resource requirements. The two other scenarios shall
          represent alternative combinations of resources that meet the same
          resource needs as the baseline case but that include proportionately
          more Section 123 resources.

    The Company interprets this rule to require that the Company produce at

    least three resource plans representing three scenarios as part of its CRP
filing:     one that is the "least cost" plan after meeting the minimum

requirements of       HB07-1037 (DSM Standard) and HB07-1281 (RES

Standard); and two other plans with different levels of Section 123 resources.

In the filing of the CRP, these plans are necessarily prepared without

knowledge of the Commission-approved criteria under Rule 3613 or without

benefit of having received any bids.

          The Company interprets Section 123 resources to be three types of

resources as they are added through the Resource Acquisition Period: all

demand side management resources, eligible energy resources defined by

Rule 3652(g), and IGCC. The Company believes that these Section 123

scenario plans will be used by the Commission and intervenors to inform a

policy debate about the levels of these types of resources to be acquired by

the utility in Phase II through the processes approved in Phase I, and that the

Commission will provide some direction to the Company as to the levels of

Section 123 resources to be acquired at the conclusion of Phase I.

          While we are not recommending an IGCC facility be constructed during

the resource acquisition period of this 2007 resource plan, we do present

three plans - a Low Section 123 Plan (which meets the minimum levels of

resources required by HB07-1037 and HB07-1281), a Medium Section 123

Plan, and a High Section 123 Plan. We are requesting Commission approval

for the High Section 123 Plan, which is the Company's Preferred Plan. We

specifically seek approval from the Commission of the policy direction where

we want Public Service to go - to acquire more than the minimum level of
renewable generation, to acquire non-traditional renewable generation, to

reduce carbon dioxide emissions, and to own more of the future generation

than we have in recent plans.

IS PUBLIC SERVICE'S RESOURCE PLAN CONSISTENT WITH THE NEW

RULES?

Yes.

IS THIS 2007 RESOURCE PLAN A CONTINUATION OF THE COMPANY'S

LAST RESOURCE PLAN?

No. The plan that we file today is unlike previous resource plans. In 2007,

we are in the midst of a step change in both public opinion and public policy.

Every night the news has stories on the implications of increased greenhouse

gases in the atmosphere and on efforts by companies and the public to

address those issues. Governor Ritter was elected, in part, on his platform to

transform the Colorado economy through energy policy - The New Energy

Economy.     Since the time of our last resource plan, voters passed a

Renewable Energy Standard to ensure that 10% of Public Service's energy

needs were met by renewable energy by 2015.           In the 2007 legislative

session, the Colorado General Assembly voted to increase the Renewable

Energy Standard to 15% by 2015 and 20% by 2020.             In addition, as 1

discussed, we now have definitive legislation promoting utility-sponsored

demand-side management, with minimum goals for energy savings and

demand reduction.
       Xcel Energy is committed to continuing our role as an industry leader

in providing solutions to concerns about global climate change and regional

environmental issues. As a result, our operating company, Public Service

Company, is proposing a 2007 resource plan built around significant

renewable energy and DSM additions, resource additions that go above and

beyond the levels required to meet the minimum goals of HB07-1037 and

HB07-1281.     We present a plan that makes significant carbon dioxide

emission reductions from 2005 levels, both through increasing the percentage

of non-carbon-dioxide emitting resources in our porlfolio and by replacing

existing coal facilities with combined cycle gas generation.   Our industry

needs to make significant carbon dioxide reductions, and the time to act is

now. We believe our customers will benefit if we begin to change our system

now because we can mitigate future risks and diversify supply to meet a

variety of potential future regulatory courses.

PLEASE PROVIDE A HIGH LEVEL SUMMARY OF PUBLIC SERVICE

CRP?

Our Colorado Resource Plan provides three alternative plans with different

levels of, and types of, resources - renewable, demand side management,

existing and new generation. We call these scenarios Low, Medium, and

High Section 123 Plans and we seek Commission approval to implement the

High Section 123 Plan. This high case is Public Service's preferred plan and

that is the plan that I discuss in my testimony.    Our preferred plan will

dramatically change the carbon dioxide emissions picture of the Company's
Colorado generation portfolio while still meeting load growth and keeping

rates reasonable.

       Figure KTH-2 shows the dramatic change in carbon emissions that we

expect will result from our preferred plan, as compared to the Low and

Medium Section 123 Plan. In every case, our future plans show a significant

reduction in carbon dioxide emissions from where we would have been if the

long-term path from the 2003 resource plan were continued today. In that

case, we would have shown 2020 carbon dioxide emissions rising about 20%

over 2005 levels due to load growth and resource additions.

                    Figure KTH-2 - Carbon Dioxide Emissions




       The top line down shows the expected carbon dioxide emissions in the

Low Section 123 Plan - the plan that meets the minimum requirements of the

law.   By 2020, that plan shows about a 9% increase in carbon dioxide
emissions over 2005 levels. The middle line shows the expected carbon

dioxide emissions resulting from the Medium Section 123 Plan. The bottom

line shows the expected production of carbon dioxide if the Company's

preferred plan - the High Section 123 Plan - is adopted and then the same

principles of resource additions are applied through 2020. This path shows a

ten percent reduction in carbon dioxide emissions all while meeting the same

growing load. The major changes incorporated into this plan that provide the

carbon reductions are the addition of early renewable generation in advance

of when those resources are needed to comply with HB07-1281, specifically

wind, biomass, concentrating solar thermal generation, and geothermal

generation.    This plan also has an increased level of DSM and the

replacement of certain Company-owned coal generating facilities with an

efficient natural gas fired combined cycle plant.

HOW DOES THE PLAN CHANGE THE FUELS USED FOR GENERATION

OVER TIME?

When we compare generation in 2007 to 2015, we see that we will meet

significantly more of our customers needs with renewable energy and

significantly less with natural gas fired energy.   We also will reduce the

percentage of energy served by coal-fired resources. Figure KTH-3 illustrates

the impact in a pie chart.
       Figure KTH-3 - Change in system sources of energy for 2007 (left)
                         and 2015 (right)




        Hvdro




                 Coal                           Coal
                 64%                            61%



HOW DOES THIS CHANGE IN ENERGY MIX IMPACT GAS USAGE IN

THE FUTURE?

It results in significant reductions in the expected use of natural gas. Figure

KTH-4 shows the expected reduction of natural gas used for generation of

about 40% when comparing 2015 under the preferred plan to 2007. This

dramatic change will significantly impact the exposure that our customers

have to the volatility of natural gas prices.
        Figure KTH-4 - Expected Gas Usage for Generation




WHAT RESOURCES DOES YOUR PREFERRED PLAN ADD OVER THE

RESOURCE ACQUISITION PERIOD?

Our preferred plan includes in the resource acquisition period from October

2007 through the end of 2015 the following resources: a total of 537 MW of

demand side management, which is above and beyond what is required by

the 2003 Comprehensive Settlement Agreement and HB07-1037.             Our

preferred plan meets load growth of 300 MW and maintains a 16% reserve

margin during the Resource Acquisition Period ("RAP").

      While we remain enthusiastic about the technology, we are not seeking

approval of an integrated gasification combined cycle within the resource

acquisition period, so we are not asking for Commission approval of any

IGCC facility in this docket.   We will continue to study this promising
     technology and therefore we continue to represent a future IGCC project in

     our preferred plan; we show 150 MW of a 600 MW facility in 2016, which is in

     the Planning Period but not within the Resource Acquisition Period.

             We have been working with state and federal policy makers to develop

     policies that address climate change and greenhouse gas reduction.           No

     carbon regulation policy has been established yet at either the state or federal

     level, but it is important for us to act now, both to address climate change and

     to manage the risks of increasing regulation. To this end, we seek approval

     for our preferred plan, which puts us on the path towards significant carbon

     dioxide reduction, while leaving us flexible to respond to future governmental

     mandates on the state and federal levels. As Mr. Prager discusses in his

     testimony, state legislatures and Congress are discussing various ways to

     mandate reductions in the emissions of greenhouse gases economy wide.

     Carbon dioxide is the primary greenhouse gas emitted during the production

     of electricity.

     ARE THE COLORADO STATE LEGISLATURE AND GOVERNOR RITTER

     INTERESTED IN REDUCING CARBON DIOXIDE EMISSIONS?

A.   Yes.    In addition to the significant renewable energy and demand side

     management legislation passed by Colorado General Assembly in 2007 and

     signed into law by the governor, Governor Ritter announced a plan to reduce

     carbon dioxide emissions economy wide in Colorado by 20% by 2020 and by

     80% by 2050 in the Colorado Climate Action Plan released on November !jth.

     Our preferred plan is a "bridge strategy," as the governor used that term in the
Colorado Climate Action Plan; it makes the significant change from increasing

carbon dioxide production to decreasing carbon dioxide production and starts

us along the path that the governor envisions for the state while technology

progresses.    While the preferred plan does not achieve the 20% goal

advanced by the governor, we believe the preferred plan is an aggressive

step and is flexible enough to respond to future changes while not over

committing to the extent that the future changes substantially from our base

case, as Governor Ritter expects.

IS THE COMPANY'S PREFERRED PLAN A "LEAST COST" PLAN?

That is a tougher question than most people probably think. The

determination of future costs implies a level of certainty around many things

that are clearly uncertain. I do not know what future natural gas prices will be,

or future customer load, or the future cost of carbon regulation, or the extent

to which new technologies may emerge and become cost effective, to name a

few of the major uncertainties in any resource plan projections. The level of

argument that we always have around what future gas prices will be indicates

that no one can be seen as having the perfect forecast of the future.

      Notwithstanding all of these uncertainties, when we do our resource

plan analyses, we need to use point estimates of prices as inputs to our

model. We do the best job we can and we use these models to advise us as

we make resource decisions. But we all know that there are uncertainties in

the forecasts of many, if not all, of the inputs used in our models. Using our

best estimates at this time, we estimate that the Low Section 123 Plan will
have a 2007 Present Value of Revenue Requirements ("PVRR") over the

planning period of $42,127 million and our preferred plan - the High Section

123 Plan will have a 2007 PVRR cost of $42,448 million. On a PVRR basis,

that impact is relatively small - less than 1%. In part the difference between

the two plans is driven by the time value of money. Under the minimum

compliance plan, the Low Section 123 Plan, we eventually need to add many

of the resources that we add earlier in the Preferred Plan: therefore the PVRR

difference becomes driven by the extra cost on a PV basis of deploying the

technologies early.

       Furthermore, the rate differential of the renewable resources in our

preferred plan, over the "No RES" plan which we analyze to comply with

Commission Rule 3661(h) can all be accomplished with an incremental cost

through our Renewable Energy Standard Adjustment of 2%. This analysis is

being presented as part of the Company's 2008 Renewable Energy Standard

Compliance Plan.

      However, whether these rate differentials will really occur is highly

dependent upon the input assumptions and, as I mentioned, we cannot

accurately predict at this time at least two of the major inputs - the price of

natural gas and the cost of carbon regulation. What we do know is that if we

include increased levels of wind and solar generation and DSM, we are

insulating customers from the volatility of natural gas prices so that if gas

prices turn out to be higher than we have predicted in our analysis, the

preferred plan could become the least cost plan. If gas prices are lower than
expected, customers will see lower rates than predicted in any of these

cases. Using our current best estimates of gas prices, we believe that the

incremental rate impacts we have modeled are reasonable prices to pay to

obtain this hedge against higher gas prices and to reduce the carbon dioxide

emissions in our resource plan. The dramatic reduction in carbon dioxide

emissions in the Preferred Plan over the Low Section 123 Plan also provides

a good hedge against the potential cost of future carbon regulation.

Depending upon the actual cost of carbon regulation in the future, our

Preferred Plan could become the traditional least cost plan. It is clear under

the RP Rules that the Commission, urged on by the people of Colorado and

the General Assembly, wants to see more renewables and energy efficiency

in utility resource plans, even if the plan results in somewhat higher cost. Our

analysis shows that the incremental cost of the acquisitions that we propose

to make through the Resource Plan has a small incremental cost over the

plan for minimum compliance with standards and we estimate that the

renewable capacity and energy proposed in this plan can be acquired within

the rate impact allowed by HB07-1281.


                    IV.    DETAILS OF THE CRP

WHAT IS THE RESOURCE NEED TO BE FILLED BY THIS CRP?

Figure KTH-6 shows the system load growth and existing resources. The gap

is the resource need. From Figure KTH-5 you can see that the system has

resource needs starting in 2013.
              Figure KTHd - Resource Need over the RAP



                                                                            Resource Need




          I                      Caeacitv
              Total Net De~endable          -  Firm Load + 16% Reserves /




         Table KTH-2 shows the resource need between now and 2015.

              Table KTH-2 - Resource Need over the RAP


         Year                               2013       2014          2015
         2013 need                           458        458            458
         2014 need                                      752            752
         2015 need                                                     173
     I   Total Resource Need      1         458    1   1,210 1
                                                              I


                                                                     1,383 ]

CAN YOU DESCRIBE THE RESOURCES ACQUIRED IN THE LAST

RESOURCE PLAN, THE 2003 LCP, AND PROVIDE A CURRENT

STATUS?

Yes. Table KTH-3 summarizes the resource acquisitions that we have made

since the last LCP was filed in 2003.
                         Table KTH-3 - Recent Resource Acquisitions

1 Proiect                    1 In-Service 1 Contracted          1 COD YearIStatus
                              Year           Capacity
    Spring Canyon             2006           60 MW Wind           2006
    Twin Buttes               2007           75 MW Wind           2007
    Cedar Creek               2007           300 MW Wind          2007
    PeeWLogan                 2007           400 MW Wind          2007
    Alamosa Solar             2007           8.2 MW Solar         2007 Anticipated
L
    Gross Reservoir           2007           8.1 MW Hvdro         2007
    Existing DWB Hydros*      Various        13.8 MW Hydro        New PPA Purchases 2007
    Lake George               1991           220 kW Hydro         New PPA Purchases 2007
    STS Hydro Extension       1985           2.5 MW               New PPA Purchases 2005
    Redlands Hydro            1982           1.4 MW               New PPA Purchases 2005
    Extension
    Waste Management          2008           3.2 MW               PPA in negotiation
    PacifiCorp                1992           25 - 175 MW          2008
                                             Exchange
                                             Agreement
    Tri-State Deferral        2000           63** MW Limon       2013
                                             132** MW
                                             Brighton
    Spindle Hill              2007           269** MW            2007
    Plains End Expansion      2008           115 MW              Under construction
    Plains End Extension      2002           113 MW              2012
    Brush 113 Extension       1999           76** MW             PPA Extension 2007
    Brush 2 Extension         1994           68 MW               PPA in negotiation
    Brush 4D Extension        2002           135** MW            PPA Extension 2012
    Manchief Extension        2000           261** MW            PPA Extension 2012
    Comanche 3                2010           750 MW coal         Under construction
                                             plant1500 MW
                                             Public Service

*Dillon Reservoir 1987; Foothills 1986, Hillcrest 1988, Roberts Tunnel 1988, Strontia Springs I986
**Summer Capacity


           Obviously, these resource decisions impact the nature and magnitude

           need in this resource plan.

Q.         DID ALL OF THE PROJECTS FROM THE 2005 ALL-SOURCE RFP COME

           TO FRUITION?

A.         No. Two projects are missing from the list in Table KTH-3.                  First is the

           renewal of the Blue Spruce Energy Center PPA in 2013.                    Although this

          contract was included in the approved 2013 Contingency Plan, Calpine
withdrew its offer to renew the Blue Spruce contract at the prices bid and as a

result a PPA extension was never completed. Second, there were significant

risks associated with completion of the Squirrel Creek project and the

Company is replacing that project with two combustion turbines to be on-line

by the summer of 2009 at Fort St. Vrain. This is the subject of a separate

CPCN filing being made with the Commission.

PLEASE DESCRIBE THE PREFERRED PLAN.

Our preferred plan is set forth on Table KTH-4. The first four columns are

resource additions that are transferred from other dockets. The DSM and

Interruptible load that form the foundation of the Preferred Plan were recently

proposed to the Commission by separate applications. The on-site solar

resources and the all-solar technology central solar acquisitions are justified

in the docket addressing the Company's 2008 Renewable Energy Standard

Plan, which we are planning to file with the Commission in November. We

will incorporate into our final resource plan the outcomes of each of those

dockets.

      We are seeking approval in this resource plan docket for the

acquisition of the remaining resources set forth in the preferred plan. We are

also seeking Commission approval for the methods of resource acquisition

that I discuss in my testimony.
                  Table KTH-4 - Resource Additions in the Preferred Plan (MW)

2
          1          2       3      4        5          6           7       8     9           I0

                                                       -
    1   Sedisn              Yes     Yes     Yes         bh          No     Yes    No         Likely
         123
                                    RES Docket                       CRP Docket

                                                                                        Evaluate as
                                                                                         available
                                                                                       Small Projects
                                                                                         < 30 MW




                                                                                          4 MW
                                                                                       Biomass and
                                                                                       Boulder Hydro
                                                                                        STS Hydro


                                                                                         Bridal Veil
                                                                                           Hydro



                                                                                        Ouray Hydro

                                                                                       Redlands and
                                                                                         Maxwell
                                                                                          hydros



              DESCRIBE THE RESOURCE ACQUISITION PERIOD AND PLANNING

              PERIOD THAT THE COMPANY IS PROPOSING.

              Under the resource planning rules, there are two evaluation time periods -

              the first is the "Planning Period". This is the period over which we perform

              economic analyses, which can range from 20 to 40 years. The Company is

              proposing a Planning Period of 40 years, so that the full value of Company-

              owned resources can be reflected in the analyses. Rule 3604(a) allows the

              utility to choose a Resource Acquisition Period ("RAP") of between 6 to 10

              years. Public Service has chosen to use an eight-year resource acquisition
period. The resource acquisition period is the period over which the utility

acquires specific resources to meet the projected electric system demand.

      Rule 3610(c) gives the utility the flexibility to propose multiple resource

acquisitions at various times over the resource acquisition period.       Based

upon our experience, we have found that we can get more competition and

better pricing if we schedule our acquisitions in relation to the lead times

required by developers of the technologies sought by the acquisition process.

Therefore, we are proposing staged acquisition of resources over the 8 year

RAP with our first RFP being issued in January 2008 to accelerate our

acquisition of more wind resources. We also plan to issue our all-solar RFP

as part of our 2008 Renewable Energy Compliance Plan in January 2008.

The All Source Acquisition would begin at the conclusion of Phase I of this

docket. We anticipate that a second wind RFP would be issued around

January 2010.

      Finally, we have concluded that given the pace of legislative and

technology change, it would be not be wise to commit to resources too far out

into the future. Solar thermal resources, IGCC, geothermal, pumped storage

hydro, compressed air, battery storage, demand side management, biomass,

and other "environmentally-friendly" technologies are attracting significant

research interest and investment capital in the marketplace. We expect to

see technology advances in these areas and further commercialization of

more experimental technologies in the near future. Therefore, we have opted

for slightly less than the maximum RAP allowed under the resource planning
rules (eight years rather than ten years) to retain flexibility to take advantage

of future developments in these new technologies. To access these new

technologies, we plan to file our next resource plan in two years, not four, so

that we do not have to wait until the 2011 resource plan to fill resource needs

in 2016. Since the two phase resource planning process established under

the Emergency Rules can now take approximately 2 years from start to finish,

we do not want to limit the technologies that we can use in 2016 by waiting

until October 2011 to address the 2016 need. Some of these resources may

have lead times that require earlier acquisition and longer development and

construction lead times than would be allowed if we waited until 2011 to

address these years. As a result, the Company commits to file its next

resource plan early, in late 2009iearly 2010 and to closely follow the

development of technology changes between now and then.

SO THE PLAN SHOWS RESOURCES THROUGH 2046, BUT THE

COMPANY       IS   ONLY     ASKING      FOR    COMMISSION ACTION             ON

ACQUISITIONS THROUGH 2015?

Yes.

ARE THERE OTHER REASONS TO LIMIT THE RESOURCE ACQUISITION

PERIOD TO EIGHT YEARS NOW?

Yes. We do not advocate a ten-year RAP because (1) technology in this time

period is still developing; (2) it is unlikely that projects can determine their

expected prices with any certainty for time periods beyond 2015 today; (3)

laws are likely to change to express public policy direction on renewable
resources and climate change, among other things; and (4) construction

schedules allow us to wait on acquisitions for the period after 2015.

WHAT WILL THE COMPANY DO TO ENSURE THAT IT IS READY TO FILL

THE FUTURE RESOURCE NEEDS IN 2016?

At a minimum, we will do the following:

   a. We will study higher levels of wind penetration;

   b. We will monitor the development of central solar thermal technology

      ("CSP"), especially the advancement of thermal storage technology;

   c. We will monitor the development of the new generation of standardized

      nuclear reactors, including participating in industry groups looking at

      this technology;

   d. We will continue to work with EPRl to study and develop carbon

      capture technology relating to pulverized coal technology;

   e. We will continue to evaluate integrated gasification combined cycle

      technology;

   f. We will continue our association with NREL including the analysis of

      wind-to-hydrogen;

   g. We will evaluate new technologies brought to the Company for

      potential investment or PPAs;

   h. We will monitor progress on the Colorado Climate Action Plan,

      including agricultural sequestration, and customer and government

      initiated energy-use changes;
  i. We will look at geothermal sites for potential development of

       geothermal and hydro resources;

  j.   We will look at expansion of the Windsource program;

  k. We will evaluate expansion of utility DSM programs and we will

       continue to evaluate the potential impacts of Smart Grid on our future

       load forecast; and

  I. We will evaluate the cost of retiring additional coal capacity and we will

       evaluate life extension at Zuni and potential repowering of Zuni Station.


                     V.     DSM, ISOC, AND RES

CAN YOU LEAD US THROUGH THE COMPANY'S PREFERRED PLAN,

STARTING AT THE LEFT OF TABLE KTH-4?

Yes.    We have incorporated a level of demand side management and

conservation in the plan that exceeds that required by HB07-1037. We call

this level "Enhanced DSM". The details of our enhanced DSM proposal are

explained in Docket No. 07A-420E. As we look to the future, our best ability

to respond to climate change concerns quickly is through demand side

management and we believe the Enhanced DSM suite of programs

represents a good balance between cost-effectiveness and urgency. As I

mentioned, we are not seeking approval of this level of DSM in this CRP

application and we will modify our final estimates of resource need based on

the outcome of the DSM docket.

CAN YOU DESCRIBE THE INTERRUPTIBLE LOAD?
Yes. Public Service has an existing interruptible load program in place that

allows the Company to call interruptions of certain customers who voluntarily

take this service under a tariff. The Company has recently proposed a new

program under Advice Letter No. 1495-Electric. The program expansion is to

allow greater participation by the lowering the interruption capacity threshold

and more flexibility in how customers participate by leveraging the customers

energy management systems (EMS) for managing the load reduction. As I

mentioned, we assumed that this interruptible tariff application is granted for

purposes of our analysis in the CRP, but we can and will modify our final

estimates of resource need based on the outcome of the interruptible load

docket.

CAN YOU DESCRIBE THE ON-SITE SOLAR?

Yes.    The details are in 2008 RES Compliance Plan. We have seen a

significant amount of pent-up demand for projects under our rebate program

called Solar*Rewards, especially in the greater than 10 kW to 2 MW range -

projects above the minimum standards for compliance. We are seeking to

satisfy that customer demand and take advantage of existing federal tax

credits by increasing our purchase of On-Site Solar RECs - or SO RECs - in

excess of minimums needed to comply with the RES.

THE NEXT COLUMN ON TABLE KTH-4 (COLUMN 5) SHOWS THAT THE

PROPOSED PLAN INCLUDES A 25 MW CENTRAL SOLAR PROJECT IN

2011.     CAN YOU       DESCRIBE THAT          PROJECT AND         PLANNED

ACQUISITION METHOD?
Yes.     The Company is currently participating in two solar thermal

consortiums, one a project jointly developed with multiple Southwestern U.S.

utilities and the other an EPRl led project in New Mexico. Both projects have

issued Requests for Information from prospective solar project developers

and both study groups have elicited technical support from the U.S.

Department of Energy, Sandia National Laboratory, and the National

Renewable Energy Laboratory. The Southwestern US. project is in the

process of developing and issuing an RFP for a PPA for the output of a new

large concentrating solar thermal project to be located in Arizona or Nevada.

This consortium is aiming for a project in the range of 200-250 MW; we would

be entitled to purchase a share of the output of that facility. The EPRl project

is aiming for a project in the range of 50-500 MW. Similarly, our company

would be entitled to purchase or own a share of the output of that project. We

believe that the options to purchase under those consortiums will mature in

approximately six (6) months. We propose issuing a bid for solar resources in

early January 2008 for in-service in the 2009 - 2012 time frame under the

2008 RES Compliance Plan.          In accord with the stipulation in our SunE

Alamosa settlement in Docket No. 06A-534E, we will not exclude any form of

solar technology from this bid.         The bid will be all-source solar for

approximately 25 MW, either on-system or off-system.            We would allow

multiple projects to fill the need., Given our current projections for the addition

of on-site solar, approximately 15 MW of non-on-site solar generation located

in Colorado is needed by 2013 and we propose to slightly accelerate that
 1        process to coordinate with the opportunity afforded by participation in the

 2        consortiums. We will take the most cost-effective proposals among all these

 3        opportunities, which may or may not include participation in one of the

 4        consortiums. Note that our participation in the consortiums does not obligate

 5        us to purchase or own a share of either facility.

 6              As with the on-site solar, we are not seeking approval of this level of

 7        central solar addition in this CRP application; we are instead seeking approval

 8        through our 2008 Renewable Energy Compliance Plan. We will modify our

 9        final estimates of resource need based on the outcome of the 2008 RES

10        Compliance Plan docket.


                   VI.    PLANT RETIREMENTS AND REPOWERING

          DOES THE COMPANY PROPOSE RETIRING ANY POWER PLANTS

          DURING THE RAP?

          Yes. The next column on Table KTH-4 (Column 6) shows that we propose

          retiring six units at three power plants: Zuni, Arapahoe, and Cameo, although

          the retirements of Arapahoe and Cameo are dependent upon the

          Commission granting us a waiver from the RP Rules to replace this

          generation with a Company-built natural gas combined-cycle facility at our

          Arapahoe Station.

          PLEASE DESCRIBE THE REASONS FOR RETIREMENT OF ZUNI.

21   A.   Previous studies have indicated that the electrical generating equipment at

22        Zuni Station is likely close to the end of its useful life and that the cost to

23        refurbish or replace the equipment is more than the cost of retirement and
replacement. In the Preferred Plan, we show Zuni 1 retiring after summer

peak in 2009 and Zuni 2 retiring after summer peak in 2012. As we get closer

to those retirement dates and have a chance during overhaul or outage, we

will fully inspect the generating equipment and determine a current estimate

of cost to refurbish or replace the equipment based on its then-current

physical condition and we will confirm the analysis to retire the electrical

generating equipment or determine that refurbishment is the most economic

alternative. We have included retirement in this plan so that we show our

best estimate of the overall resource need.

WILL THE NEEDS OF THE THERMAL ENERGY CUSTOMERS IN DENVER

BE SERVED RELIABLY AFTER ZUNl IS RETIRED?

Yes.   The retirement plan calls for retirement of the electrical generating

equipment only and the thermal portion of the plant will still be available to

serve the steam system.

DOES THE COMPANY HAVE PLANS TO REPOWER ZUNl OR REUSE

THE SITE?

Yes, we are investigating repowering options. The site, which is within the

load center of Denver and which already has good gas interconnection and

transmission service, is likely to have significant brown field advantage as a

future generation site. We do not have definitive plans to repower at this

time. The Company likely will propose a repowering alternative as part of a

future bid process or in the next CRP.
     WHY DO YOU PROPOSE TO RETIRE AND REPLACE ARAPAHOE AND

     CAMEO?

     Together those two power plants, four units in total, are 229 MW and produce

     about two million tons of carbon dioxide along with other emissions. Retiring

     these power plants will allow the Company to stabilize our carbon dioxide

     emissions so that they do not increase over 2005 levels and will put the

     Company on the path to reduce overall system carbon emissions.

           Our retirement studies, which are set forth in Volume 2 of the CRP,

     show that it would be cost effective to continue to operate these plants - the

     costs for life extension are less than the cost of replacement capacity and

     energy at our baseline carbon assumptions.       However, the environmental

     benefits of retiring the plants are significant. The retirement of these plants

     significantly reduces our customers' exposure to the future uncertainty around

                                                                          O
     carbon dioxide regulation and significantly reduce the emissions of N , SO2,

     and mercury.

Q.   WHAT GENERATION CAPACITY REPLACES THESE RETIREMENTS?

A.   We propose that a new combined cycle at Arapahoe replace the energy and

     capacity produced by Cameo and Arapahoe.           At these two plants, the

     Company is proposing to retire 229 MW of generating capacity.               In

     determining the best replacement for that capacity, the Company considered

     plants at both Arapahoe and Cameo and plants that closely matched the size

     of the existing facilities. We determined that the best solution is the one we

     are proposing. As a result, Public Service is seeking a waiver from the
competitive acquisition requirements of the rules to retire early, for carbon

reduction purposes, our coal-fired plants at Cameo and Arapahoe and

replace them with a new 480 MW (summer rating)/537 MW (winter rating)

combined cycle gas plant at the Arapahoe site. When you compare the

carbon dioxide emissions of these older less efficient coal plants (about 2700

IbsIMWh) to that of a natural gas combined cycle carbon dioxide emission

(about 850 IbsIMWh), there are significant carbon reduction benefits from this

replacement. We estimate that the annual carbon dioxide reduction would be

1.4 million tons - between retirement and 2020, which would save about 11

million tons of carbon dioxide emissions.        There are also significant

reductions in sulfur dioxide emissions and in nitrogen oxide emissions.

WHY SHOULD THE COMMISSION GRANT THE COMPANY A WAIVER

FROM THE COMPETITIVE ACQUISITION RULES TO ALLOW THE

COMPANY TO REPOWER THE ARAPAHOE SITE?

The retirements of Cameo and Arapahoe are a key element in the Company's

carbon reduction strategy.    Public Service wants to retire these units to

respond to the Governor's call for reducing greenhouse gas emissions.

      Retiring these units requires replacement energy and capacity. Under

our generic resource plan analyses, the optimal replacement unit in a

retirement scenario is a generic combined cycle gas plant. The Arapahoe

combined cycle project, therefore, is the type of resource replacement that we

need to accomplish these retirements.
      We need more combined cycle plants to help our system operators

regulate for wind. Further, repowering at the Arapahoe site improves on the

generic plan because of certain brownfield advantages of this site:

          Reuse of the railroad loop during construction and maintenance

          Reuse of the administration building, the control room, the

          warehouse facilities, and the maintenance shop.

          Reuse of raw water supply infrastructure, sewage treatment

          facilities, and storm water and settling ponds.

          Reuse of existing interconnections to the electric and gas

          transmission systems. While both will need to be expanded, the

          value of the embedded facilities will be retained, including the

          switchyard.

          Reuse of the cooling towers on the site and the associated ponds

          and water intake and outtake facilities

          Reuse of the site in the Denver Metro area, close to load, avoiding

          the need to develop a green field site in the state

          Continued and increased levels of transmission capability and

          system voltage support under normal and outage conditions

          Continued injection point of electricity on the transmission system.

          The Company can net SO2 and NOx emission reductions of the

          retired Arapahoe units for the repowered Arapahoe unit and

          thereby allow permitting of the unit in the metro area.
          Adding a combined cycle at Arapahoe will help defray the loss of

          tax base in the City and County of Denver based on the retirement

          of Arapahoe and Zuni and retain an employee base in the area.

The repowering is expected to cost $436 million. We believe that this is a

savings of $20 - $40 million compared to a new green field 2 X 1 combined

cycle facility. It makes good economic sense to use the existing infrastructure

and property that Public Service owns within a transmission and emission

constrained area.

      Public Service requests that the Commission grant the Company a

waiver of the RP Rules so that we may retire early, for carbon reduction

purposes, our Arapahoe 3 and 4 and Cameo 1 and 2 coal units and replace

that capacity with new Company-owned 480 MW (summer rating) 2x1

combined cycle generation. The Company will file a full CPCN for approval of

Arapahoe repowering while Phase I is pending in order to support equipment

ordering and construction.

BASED UPON THE EVALUATION OF THE COST DIFFERENTIAL, WHAT

IS YOUR CONCLUSION IN TERMS OF LOCATING THE NEW UNITS AT

THE ARAPAHOE SITE?

I have concluded that the cost advantage and all of the other factors

discussed above clearly favor locating the new combined cycle units at the

Arapahoe site.

DOES THE COMPANY PROPOSE OTHER UTILITY-BUILT RESOURCE

ADDITIONS?
No, not at this time. However, in our analysis, we have assumed continued

operation of our Cabin Creek pumped storage facility. The current Federal

Energy Regulatory license to operate Cabin Creek expires in March 2014. In

2008, Public Service plans to start the process to re-license the plant for 30

more years of operation.       As part of the relicensing activity, we are

investigating modification of the facility to increase efficiency and capability.

Should we find a cost-effective upgrade project, we will make the appropriate

application with the Commission.

      Separately, we are planning to perform a small upgrade to the control

system ($40-$look) to allow the turbines to act as demand response spin

when the units are pumping. The controls would quickly shutdown pumping

mode and change to generation mode to give the operators a large amount of

spinning reserve.    Cabin Creek is key to operational control for wind

generation on the system and this improvement should result in $1 million -

$3 millionlyear in system savings. We have proposed this treatment to the

Western Electric Coordinating Council ("WECC").         WECC has agreed to

monitor testing and then determine if they agree with allowing us to count

Cabin Creek toward our spinning reserve obligations. Public Service is not

seeking approval of this project in the CRP, but I explain it here because it is

important for the Commission to understand the benefits provided by the

Cabin Creek facility for allowing cost effective integration of the wind

generation being proposed in the CRP.
Q.   WHAT IS THE REMAINING RESOURCE NEED IN THE RESOURCE

     ACQUISITION PERIOD?

A.   Table KTH-5 shows the resource need between now and 2015.

                Table KTH-5 - Remaining Resource need after DSM,
                RES compliance renewables, Retirement of Arapahoe
                     and Cameo and Repowering of Arapahoe

          Year                                       2013 2014 2015
          Oriainal Total Resource Need               458     1.210 1.383
      I     Y


          Enhanced DSM (adjusted for reserves)     ( 98    ( 1 2 5 1154
          RES Solar (capacity equivalent of 25 MW)   17      17     17
          Unit Retirements                           336     336    336
          Arapahoe CC                                (480) (480) (480)
          Remaining Resource Need                    199     924    1,068


                     VI.   WlND ACQUISITION PLAN AND RFP

Q.   COULD YOU DESCRIBE THE COMPANY'S WlND ACQUISITION PLAN?

A.   Yes.       We have included 800 MW of new wind generation for the Public

     Service system between 2010 and 2015. To comply with the Renewable

     Energy Standard Rules, even as increased under HB07-1281, we do not

     need to add significant non-solar renewable resources to the system until

     after 2020, but then we have to add a significant amount. Current estimates

     are that at least 700 MW by 2025 and as much as 1200 MW.

             We assume that the General Assembly, by increasing the Renewable

     Energy Standard in HB07-1281, did not want us to wait until after 2020 to

     acquire more wind. Our plan delivers on expectations by continuing a diligent

     effort to expand wind generation in rural Colorado. In fact our plan keeps us

     ahead of the amounts of wind generation, as a percentage of retail sales, that

     the legislation requires each year.    Figure KTH-6 shows that, when the
benefits of in-state generation are counted, we are well ahead of the

Renewable Energy Standard in every year of the RAP.

                      Figure KTH-6 - Annual REC Generation


                      Preferred Plan RECs vs. RES Standard
                                    (% of Retail Sales)




        I                            % RECs +RES Standard


WHAT ARE THE ADVANTAGES OF STEADY ADDITIONS OF WIND

POWER?

In addition to the environmental, public policy, and economic development

benefits, we believe that there are two additional advantages to steady wind

additions: the ability to integrate the wind efficiently into our system; and the

ability to insulate customers from the cyclical nature of wind development

pricing that we have seen in the past.

       For 2007, we are adding 775 MW to the Public Service system and

that has resulted in some growing pains. System operators, who in 2006 only

had to deal with about 280 MW of wind, now have to manage four times as

much. While we are happy to take the steps necessary to develop operating

protocols to integrate more intermittent wind into our system, we think that it
would be better to add additional wind to the system in relatively even steps

over a longer time period, rather than try to accommodate significant wind

additions in a single year. In addition, we have seen nationally that there have

been dramatic price and availability swings for wind projects based on

expiration and reinstatement of the federal production tax credit.              By

establishing a steady demand for wind projects in Colorado, whether or not

the production tax credit is extended, we would hope to make our market

more stable. This disciplined and measured approach will allow for continued

deployment of wind, deployment of wind as transmission is made available

under the SB07-100 process, and will allow ample time to acquire and

construct resources.

WHAT DO YOU ANTICIPATE WILL BE THE RELATIONSHIP BETWEEN

THE COST OF WIND AND SYSTEM AVOIDED COSTS OVER THIS

PERIOD?

As long as we have Production Tax Credits, the federal program to provide

tax credits to wind generators for each MWh produced, the cost of wind will

likely be slightly above our avoided costs, but it will still provide value project

as a hedge against natural gas price volatility and carbon policy and cost

uncertainty. We have assumed for our analysis that the federal PTCs are

extended through the entire Resource Acquisition Period.

      If the production tax credits are not renewed, wind will cost more than

assumed in our analysis of the Resource Acquisition Plan and we will need to

evaluate whether all the wind that we propose can be accommodated within
the retail rate impact cap in the Commission's Renewable Energy Standard

Rules.

      We have seen the prices of wind projects rise dramatically, not just in

Colorado but also all across the Xcel Energy system. That situation may

continue or we might see the market settle down and see the improved

economics that drove our previous acquisitions. However, I don't think that

we should stop acquiring wind resources while we figure out which direction

prices are headed. Like my earlier discussion about the price impact of the

overall CRP, additional wind resources will reduce the system's reliance on

natural gas and will provide a carbon free resource. Later in my testimony,

after I complete the description of the overall preferred plan, I will outline the

cumulative impact of the plan on gas purchases.

      Our acquisition strategy will pick the least cost wind resources, but we

are not suggesting that this level of wind is least cost compared to a plan

without these wind resources. In fact, based on projected economics, our

current analyses did not include any wind additions based on economic

savings in the Low Section 123 Plan before 2020.

HAVE YOU STUDIED THE COST OF INTEGRATING INTO THE PUBLIC

SERVICE SYSTEM THE LEVEL OF WIND GENERATION INCLUDED IN

THEPREFERREDPLAN?

Not yet.   As part of the 2003 Comprehensive Settlement Agreement, we

commissioned an integration study to look at the cost of a 20% capacity

penetration level. This 20% capacity penetration equates to about 1,400 MW
of wind, or about 350 additional MW of wind on the Public Service system.

We do not believe that this 20% capacity penetration is a ceiling on the

amount of wind that the system can accommodate. However, we do need to

perform further studies and to look beyond the concepts in our current studies

to determine how we might modify system operation or plant generation in

ways to allow cost-effective integration of wind resources. As a result, our

plan includes 800 MW of additional wind resources and we think that amount

will be possible and we will continue to carefully review and plan wind

integration in advance of actual wind acquisition.

HOW DO YOU PROPOSE TO ACQUIRE WIND RESOURCES?

We propose to use an RFP that solicits for a combination build-transferIPPA

resources in a staged, targeted competitive acquisition.

CAN YOU EXPLAIN WHAT YOU MEAN BY "STAGED"?

Yes.   In the 2005 All Source RFP, we found that wind bidders only bid

projects for in-service dates in the time frames for which they could secure

turbine delivery commitments from turbine manufacturers - in that case only

for the one or two years immediately following the RFP. Today our survey of

the market is that turbine manufacturers are willing to provide manufacturing

commitments and reasonably firm turbine prices in 2008 for deliveries in 2009

through 2011, but the demand for turbines is far outstripping supply. We

propose to stage our acquisition of wind projects roughly in-line with turbine

manufacturers' commitment behavior.
      To enhance the likelihood that projects can acquire turbines in this tight

market for the 2010-2012 period, we propose to issue the first Wind RFP in

January 2008, prior to completion of Phase I of this CRP. This RFP would

seek to acquire roughly 300 MW of wind, relatively evenly spaced over the in-

service years of 2010, 201 1, and 2012. By issuing the RFP in January 2008,

we are not presuming approval by the Commission of our overall acquisition

plan, but we need to take advantage of what our industry contacts believe is

the timing of turbine manufacturers' releasing prices and turbine orders for

this time period.   Under this plan, we would solicit bids and begin our

evaluation in parallel with the Phase I proceeding and then we would file for

approval of any successful transactions in a Phase II process that would

quickly follow Phase I. In other words, by issuing the first Wind RFP early, we

will simply reduce the time between Phase I and Phase II for this portion of

the plan and we would be able to incorporate Commission direction in Phase I

into our evaluation of the wind project bids. We are concerned that if we wait

to issue the RFP until the conclusion of Phase I, we will miss the window for

turbine allocation for projects in the 2010 to 2012 time period and we may

even miss the extension period of the federal production tax credits. Our

customers are best served by timing our wind RFP to make sure that we are

entering the wind market at the appropriate time.

IS IT ASSURED THAT TURBINES WILL BE AVAILABLE FOR PROJECTS

IN COLORADO IN THIS TIME PERIOD?
No. We have found that there are many opportunities for developers and

turbine manufacturers to deploy turbines both nationally and internationally.

The world demand for wind turbines far exceeds the supply and therefore

both developers and turbine manufacturers have been allocating these scarce

resources to their best projects. We hope to work with the Commission to

make Colorado an attractive place for further wind project development.

WHEN WOULD YOU ISSUE SUBSEQUENT WlND RFPS?

We would then issue a second RFP about 2 - 3 years later. If we find that we

don't get bids for 2011 or 2012, we would like the flexibility to issue

subsequent RFPs to fill the roughly 800 MW proposed acquisition in roughly

the years proposed (100 MWIyear in 2010 - 2013 and 200 MWIyear in 2014

and 2015) based on bidder response. In other words, we might issue the two

RFPs described above or we may need to issue more RFPs over the six-year

period.

WILL YOU ACCEPT ONLY 100 MWMEAR EXACTLY?

No. We are targeting 100 MWIyear, but it is unlikely to economically come on

line as smoothly as modeled. The goal is to gradually increase wind capacity

on our system over time and to find the most cost-effective projects. As we

learn about any potential extension of the production tax credit, that could

also impact the distribution through the RAP.

WHY ARE THESE RFPS TARGETING ONLY WlND PROJECTS?

We believe that a targeted wind RFP will allow us to quickly evaluate

proposed wind resources and proceed more quickly to Phase I I and to
contracts; the targeted solicitation will also lessen the likelihood of project and

price changes during the course of bid evaluation and contracting, thereby

increasing the likelihood of success.      In other words, we are asking the

Commission to make a policy determination as to the amount of wind we

should acquire during the RAP, as a Section 123 resource, and then to let us

acquire those resources in a bid specifically designed for wind resources.

Targeted solicitations for wind are contemplated by Rules 3610 (a) and 3655

(b) (iii).

CAN YOU DESCRIBE THE WIND RFP STRUCTURE?

Yes. Under this structure, which we call build-transfer, bidders would develop

a wind site and transfer the site to the Company; bidders would then construct

the wind turbines on the site under an engineering, procurement and

construction ("EPC") contract. In addition, the bidder could propose some

combination of a build-transfer project and a traditional power purchase

agreement, under which the bidder (or another party) retained ownership to

the wind facilities in a separate project and sold the output to us under a PPA.

WHY          IS   THE   COMPANY       PROPOSING         A    BUILD-TRANSFER

STRUCTURE?

Because the Company would like to be an owner of wind generation assets.

Investors in Xcel Energy are interested in having an equity stake in renewable

generation. By the end of 2007, Xcel Energy will have 2700 MW of operating

wind generation on its combined electric systems - we are the number one

provider of wind power to retail customers in the nation -- yet Xcel Energy
owns less than 30 MW of operating wind capacity, and that is the Ponnequin

expansion facilities, constructed in phases during the 1999-2001 period. In

Colorado, Public Service will have over 1000 MW of purchased power

sourced from non-Company owned resources by the end of 2007. The CRP

proposes adding 800 MW of wind generation to the Public Service system

between 2010 and 2015. The Company is targeting ownership of 50% of the

proposed wind additions in the resource acquisition period to better balance

our wind resource portfolio.

       HB07-1281 reserved up to 50% of new eligible energy resources for

utility ownership. In part this law reads:

       §40-2-124(1) ... the commission shall revise or clarify existing rules to
       establish the following:

             (f) Policies for the recovery of costs incurred with respect to
      these standards for qualifying retail utilities that are subject to rate
      regulation by the commission. These policies shall provide incentives
      to qualifying retail utilities to invest in eligible energy resources in the
      state of Colorado. Such policies shall include:

               (I) Allowing a qualifying retail utility to develop and own as utility
       rate-based property up to twenty-five percent of the total eligible
       energy resources the utility acquires from entering into power purchase
       agreements and from development and owning resources after the
       effective date of this subparagraph (I), if the new eligible energy
       resources proposed to be developed and owned by the utility can be
       constructed at a reasonable cost compared to the cost of similar
      eligible energy resources available in the market. The qualifying retail
       utility shall be allowed to develop and own as utility rate-based
       property more than twenty-five percent but not more than fifly percent
       of the total new eligible energy resources acquired after the effective
      date of this subparagraph (I), if the qualifying retail utility shows that its
       proposal would provide significant economic development,
      employment, energy security, or other benefits to the state of
       Colorado. The qualifying retail utility may develop and own these
       resources either by itself or jointly with other owners, and, if owned
      jointly, the entire jointly owned resource shall count toward the
      percentage limitation in this subparagraph (I). For the resources
      addressed in this subparagraph (I), the qualifying retail utility shall not
      be required to comply with the competitive bidding requirements of the
      Commission's rules; except that nothing in this subparagraph (I) shall
      preclude the qualifying retail utility from bidding to own a greater
      percentage of new eligible energy resources than permitted in this
      subparagraph (I). In addition, nothing in this subparagraph (I) shall
      prevent the commission from waiving, repealing, or revising any
      commission rule in a manner otherwise consistent with applicable law.


Public Service's proposed plan includes acquisition of 800 MW of wind

resources in the RAP and 1200 MW of wind planned through 2017. The

Company therefore is entitled to own at least 200 MW and perhaps as high as

600 MW of the wind resources that we add during the Resource Acquisition

Period.

      However, the Company does not have wind projects developed with

sites and turbine queue positions that are ready to be filed with the

Commission. In addition, the Company respects the Commission's desire to

lower costs for all resources to customers through competition. We also are

aware of many developers working throughout the state to develop wind

projects; we would like to give those entrepreneurs an opportunity for return

on their development investment sooner rather than later and potentially free

their cash flow to develop subsequent sites

      In Minnesota, Xcel Energy operating company Northern States Power

initiated an informal bidding process for a build-transfer project in 2006. NSP

has selected a winning bidder and has negotiated contracts to acquire a

project from a developer. Under these agreements, the developer will be

responsible for acquiring the site and necessary operating permits and
approvals and transferring them to NSP. The developer will then build a 100

MW wind project under an engineering, procurement, and construction

agreement. While that project is still before the Minnesota Public Utilities

Commission for approval, the project was recently endorsed by the

Department of Commerce, which is structurally equivalent to PUC Trial Staff

in Colorado, as being at reasonable cost and in the public interest. A Build-

Transfer structure in Colorado would provide competition in the acquisition of

utility-owned projects, assure reasonably priced projects, and meet the

State's goals of advancing renewable energy expansion in Colorado.

DOES THE COMPANY BELIEVE THAT THIS APPROACH SATISFIES THE

REQUIREMENTS FOR COMPETITIVE PROCUREMENT?

Yes. The Commission's Resource Planning Rules do not specify the form of

competitive procurement that a utility must use. We believe that this process

will allow for a form of competitive market procurement that will yield the

benefits for our customers that actually exceed the benefits that are provided

through power purchase agreements.           I discuss later why Company

ownership of wind assets is better for our customers than acquiring wind

energy only through power purchase agreements. We also believe that the

potential benefits for developers by this RFP structure will provide sufficient

motivation to produce a healthy, vibrant solicitation process. In recent years,

several other utilities have engaged in these types of solicitations in order to

successfully procure wind generation resources for utility ownership.
THE COMPANY HAS ACTUALLY                  PROPOSED A HYBRID BUILD

TRANSFER-PPA RFP. CAN YOU DESCRIBE WHY YOU ADDED THE PPA

COMPONENT?

Yes. Our survey of the wind development market shows that there are two

basic types of developers - those who develop projects to sell them to long-

term owners and others who develop projects to be long-term owners. We

feel that incorporating a PPA component to the Build-transfer RFP will

broaden the base of developers who will find this bid format attractive.

      The Company is proposing that in the first of the staged targeted

acquisitions we would seek bids that include at least 50% Company

ownership and up to 100% Company ownership; conversely, this would limit

the PPA component to no more than 50%. Under the ownership structure,

there would be no joint project ownership. To the extent that PPA and Build-

Transfer projects were co-located, there would be a requirement to designate

the turbines, real estate, and other assets to be owned by the Company and

those to be owned by another party.        Just as the Company has sought

flexibility to time these RFP acquisitions to accommodate the realities of wind

project development, we also seek flexibility to modify the structure of the

acquisition process. We may need to modify these RFPs based on the

market response.

CAN YOU DESCRIBE THE BASIS FOR THE RFP STRUCTURE AND

OWNERSHIP PROVISIONS OF THE RFP?
Yes - it is a multi-staged theory. First, we rely on the model of competition to

satisfy the provision in legislation that the utility is a successful bidder in a

competitive process. Second, we rely on the 25% set-aside provision of the

same legislation to allow a minimum level of ownership and third, we propose

the standards upon which the Commission could find that the "benefits"

standard of the 50% set aside are met.

CAN YOU DETAIL THE FIRST ITEM                -   RELYING ON THE MODEL OF

COMPETITION TO SATISFY THE BIDDING PROVISIONS OF THE

LEGISLATION?

Yes.   In general, the legislation exempts the utility from using competitive

bidding to acquire the renewable resources as rate based property under the

"set-asides" in C.R.S. §40-2-124(1)(f)(l). The legislation then goes on to say

that "nothing in this [legislation] shall preclude the qualifying retail utility from

bidding to own a greater percentage of new eligible energy resources than

permitted [by the set asides]."

       The Wind RFP requires bidders to offer a minimum of 50% of the

capacity they are bidding for Company ownership. These required minimum

amounts are authorized by, and count against, the set-aside percentages in

the statute. However, to the extent that a bidder offers more than the 50%

minimum for Company ownership, the incremental capacity above the 50%

would be acquired through a competitive process, where a Company

ownership proposal is competing against a PPA proposal. Since this capacity

would be acquired through competition, it should not count against the
statutory set-asides. To the extent that a pool of projects with ownership

percentages above 50% (the minimum in our bid) are less expensive than a

pool of resources with ownership percentages at the 50% level, we believe

that we will have satisfied the requirements of having utility ownership

acquired through competitive procurement.

      For illustrative purposes only, assume that the lowest 300 MW of bids

in the first wind solicitation have a PVRR of $500 million and the bid pool

consists of 100 MW of 50% ownership and 200 MW of 100% ownership

projects, resulting in 250 MW of Company ownership and 50 MW of

purchases under a PPA. Assume that the lowest cost pool of bids with only

50% Company ownership (resulting in 150 MW of Company ownership and

150 MW of PPA) had a PVRR of $520 million.         Under these facts, the

Company should only be required to count 150 MW toward the statutory set-

aside with the other 100 MW of Company ownership being acquired through

competitive bid.

WOULDN'T THE WHOLE 250 MW IN THAT EXAMPLE MEET THE

QUALIFICATIONS FOR EXEMPTION FROM THE SET ASIDES BECAUSE

OF COMPETITIVE BIDDING?

There is certainly an argument that all 250 MW should be considered

acquired through competitive bidding, but we are taking a conservative

approach. Our proposal is that the Commission should allow the Company to

use a minimum bid threshold of 50% ownership for the first solicitation,

because 150 MW (of the 300 MW solicited) is less than 25% of the 800 MW
of wind that we intend to acquire through the Resource Acquisition Period. If

each of the 300 MW of wind projects acquired in the first solicitation had

exactly 50% utility ownership, Public Service would own 150 MW of projects.

Through the RAP, the Company proposes acquiring 800 MW of wind, so the

25% set aside means that we can own at least 200 MW without competitive

acquisition. In addition, we propose the 50% standard for practical reasons -

we believe it will result in projects that are administratively easier to deal with

because ownership projects will be utility-sized.

WILL THE COMPANY MODIFY THE MINIMUM OWNERSHIP STRUCTURE

IN THE RFP(s) THAT ARE STAGED FOR LATER ISSUE DATE?

We would like to retain the flexibility to do that based on the results of the first

solicitation and market changes.

IS THE COMPANY PROPOSING TO USE A FACTOR TO ACCOUNT FOR

THE IMPUTED DEBT BURDEN OF THE PPA COMPONENT OF THE BID?

Yes.   Mr. Tyson discusses in his testimony how Standard & Poor's now

imputes debt associated with renewable energy PPAs. The Commission

should note, however, that per Standard and Poor's methodology the amount

of imputed debt assigned to energy only contracts is relatively small.

Nevertheless we do think that it is appropriate to reflect the cost to our

customers of the equity infusions that will be needed to counterbalance this

imputed debt in evaluating the relative cost of PPA bids against Company

ownership bids. The proposed calculation is in Volume 3 of the CRP- as

Appendix F to the Wind RFP.            The calculation for energy-only priced
     renewable contracts results in a relatively small adjustment.        Under the

     Company's proposal, this adjustment would only apply to the PPA portion of

     bids and would be factored into the PVRR analysis to evaluate the bids.

Q.   IS THE COMPANY SEEKING APPROVAL OF 50% OWNERSHIP OF WIND

     RESOURCES UNDER 40-2-124 (1) (F) (i)?

A.   Not at this time.        However, we have asked bidders to indicate in their

     responses the economic development, employment, energy security, and

     other benefits to the state of Colorado that are provided by their propose

     projects. To the extent that the bid projects provide significant benefits, they

     would entitle the Company to the 50% statutory set-aside.

             We believe that certain factors could create the case for the 50%

     ownership set-aside and that such a designation can be provided in the

     Phase 11 proceeding as the Commission approves acquisitions under the

     RFP Those factors include, but are not limited to, the following:

        rn   The linking of a project with significant employment or manufacturing

             opportunities;

        rn   benefits of long-term ownership after depreciation of the assets,

        rn   lower costs to curtail wind production in system disturbances,

        rn   ability to use curtailment to maximize use of the transmission system,

        rn   the flexibility to develop new ways to interface between wind turbine

             control systems and the utility's energy management system to make

             project curtailment as efficient as possible and to coordinate

             curtailment with control area performance,
               a showing that a project is developed in a new area for wind

               development or an area with significant underutilization of wind

               resources, and

               a showing that a project includes community wind participation and

               therefore provides economic development and other benefits to the

               state.

       We believe that debate on this topic can be accomplished at the time, if any,

       that the Company proposes using the 50% set aside.


                          VII.    ALL SOURCE NEED AND RFP

       WHAT IS THE NEXT SET OF RESOURCE NEED?

       The next two columns in Table KTH-4 (columns 8 and 9). when taken

       together show the bulk of the capacity needs in the RAP. Table KTH-6 below

        indicates the level of remaining resource need after accounting for the wind

       acquisitions proposed in the preferred plan.

Table KTH-6     - Remaining Resource need after adding wind to Table KTH-5
            Year                                  2013        2014     2015
            Remaining Resource Need               199         924      1,068
            Capacity equivalent of wind           50          75       100
            (12.5% of nameplate)
            Remainina Resource Need               149         849      9685


               In our generic plan, we show the need for approximately 1,000 MW of

       capacity resources - non-intermittent resources -- that have some level of

       dispatchability and a high likelihood of on-peak availability. Traditionally, we


  To correspond to numbers in the CRP volumes, subtract the 4 MW of biomass discussed later in
this testimony.
would look to gas-fired peaking and intermediate capacity - typically

combustion turbines and combined cycle plants - to fill this need. In this

CRP, we propose a process to fill this resource need through an all-source

process that would allow a wider range of resources to meet this need.

WHAT TYPE OF RESOURCES COULD FlLL THlS NEED?

Any resource that provides our electric system with a high coincident capacity

value and some level of dispatchable or firm energy. We anticipate that this

need could be met by gas-fired combustion turbines or combined cycles,

concentrating solar thermal with thermal storage, pumped storage hydro, or

other dispatchable renewables. Of this approximate1,000 MW need, we also

propose that we designate the addition of 200 MW of concentrating solar

thermal capacity as a Section 123 set-aside to this acquisition.

DOES THE COMPANY PROPOSE USING AN ALL-SOURCE BID TO FlLL

THlS NEED?

Yes, we do. But due to some important accounting issues and issues

surrounding the 2005 All Source bid process, we propose a new form of all-

source bidding. First, we believe that the all-source bid structure for large

amounts of capacity (in this case 1000 MW) does not accommodate small

projects well, so we propose to set a minimum size of project in this all-source

bid of 30 MW, which is consistent with the Commission's break point for

various types of acquisitions and exemptions from competitive resource

acquisitions in Rule 3611.     Second, we propose to exclude intermittent

resources, like solar and wind generation without thermal or battery storage,
because we propose acquiring those resources through separate segmented

bidding processes, and because our system needs 1000 MW of firm, peak

available, capacity.   Rule 3612 (b) allows RFPs to designate whether the

system needs base load, intermediate, or peaking power, and whether the

system requires dispatchable resources.       In this RFP, we must acquire

resources that can provide peaking and intermediate power       - we   need the

power to be available during these periods and therefore have proposed RFP

restrictions that meet system needs (so a wind or solar project would need

some form of storage).

       Further, because we are proposing to change the direction of carbon

emissions - from growth to reductions, we will not accept bids from coal-fired

facilities that do not include significant carbon capture and sequestration. Our

RFP requires any coal project bid to us to capture and sequester at least 50%

of the carbon emissions from the facility; this would put a coal plant roughly

on a carbon emission par per kilowatt hour with a gas combined cycle facility.

       Most significantly, the Company proposes that the all-source bid be

structured as a competitive bidding process that results in Public Service

Company's ownership of assets.         This is to address certain technical

accounting issues discussed by Ms. Madden and Mr. Tyson in direct

testimony.

CAN YOU FURTHER EXPLAIN THE TECHNICAL ACCOUNTING ISSUES?

Yes. Ms. Madden explains in detail that the lease accounting standards have

been applied to purchased power agreements and that the application has
resulted in all of our new fossil fuel agreements being classified as leases.

She explains further that under the evolving application of the FASB lease

accounting rules, Public Service's PPAs have come under greater scrutiny to

determine whether they should be classified as capital leases today. As a

capital lease, a PPA will be reflected not as discounted imputed debt, but

rather as actual 100% debt on the Company's balance sheet. Moreover, we

face the future risk that we will be required to recognized all of our PPAs

classified as leases as on-balance sheet liabilities. As Ms. Madden testifies,

the FASB is currently considering moving to an accounting model under

which lessees would be required to recognize a liability for the fair value of

their obligation to make lease payments over the term of the lease for all

leases other than very short-term leases. If adopted by FASB, the new model

would result in on-balance sheet recognition of assets and liabilities for almost

all leases that today are classified as operating leases as well as those that

are classified as capital leases.

       In short, we have designed our PPAs to minimize costs to our

customers, economically dispatch our system, manage gas supply in a way

that reduces costs and assures fuel availability, and with recognition of the

limited import capability that we have due to inadequate transmission to areas

outside of the Colorado Front Range. To change any of these features in an

attempt to avoid lease accounting treatment will result in increased costs to

our system and our customers, andlor system operating problems.
       We have looked at numerous ways to structure PPAs differently to

avoid the lease characterization, but we have not found a reliable formula that

keeps the PPA a cost-effective resource for our customers. We spent years

perfecting the gas tolling arrangement to align the interests of generators and

Public Service - to assure that generators take steps to be available during

important times on the electric system and to ensure that units are

compensated fairly to ensure that they run when requested. Changing these

agreements to allow sellers to provide capacity and energy from other

resources or to allowing sellers the opportunity to sell electricity to the market

would undermine that careful operating balance and our economic dispatch.

In addition, we believe that to be effective in eliminating the lease accounting

implications, sellers would need to actually take advantage of these contract

provisions. Our transmission import capability is so limited that we could not

regularly expect a seller to be able to deliver alternate capacity to the Public

Service system.

       Paying a fixed rate for capacity and energy would again subject

generators to gas price volatility and make them less willing to generate in

periods of high gas prices, which is devastating to system reliability.

Purchasing less than the full output of the unit results in significant operating

problems unless each utility off-taker can operate the unit at least at

minimum. Purchasing less than the full output may result in a higher per unit

price if the seller is unable to find another offtaker.
       The problem is that once a PPA is categorized as a lease, the

economic tests to determine if the obligation is a capital or operating lease

are done at commercial operation not at the time of bidding or contracting and

therefore can not be stipulated when the obligation is entered into. As a

result, we are unable to issue an RFP for PPAs that would definitively outline

how to avoid this accounting treatment in a manner that is both foolproof and

cost-effective for our customers.

WHAT IS THE FINANCIAL IMPACT ON PUBLIC SERVICE OF THE LEASE

ACCOUNTING FOR PPAS?

Mr. Tyson shows the impact of lease accounting treatment on our balance

sheet and quantifies the additional cost to our customers if the Company were

required to fulfill the majority of the resource need identified in this proceeding

through PPAs.

HOW DID THE RESULTS OF THE 2005 ALLSOURCE INFLUENCE THE

COMPANY'S PROPOSAL FOR THE BIDDING STRUCTURE IN THIS CRP?

In the 2003 LCP and the associated 2005 All-Source RFP, the Company, for

the first time, had a significant number of then-existing PPAs expiring during

the 2003 - 2013 RAP; in fact, we had 2,000 MW expiring during the RAP.

We solicited and received many offers for contract renewals from the existing

generation facilities located in or near our service territory. Our theory, and

the theory accepted or anticipated by the Commission until that time, was that

we would see bids from projects with expiring contracts that reflected

substantially lower prices, because these projects had already received
substantial payments toward retiring debt service. But, to our chagrin, the

bids we received from the majority of these existing projects were priced

close to, and in some cases even greater than, the cost of new generation.

Because of these high prices, we declared most of these bids to be

uneconomic and we rejected them. The details of these bids and our review

of them were presented to the Commission in Docket No. 05A- 543E. As a

result, we did not fill our full 2013-resource need from the 2005 All-Source

RFP process.

      As it turns out, Dr. Schechter of the Office of Consumer Counsel was

proven to be correct in his prediction of bidder performance. For many years,

Dr. Schechter has been arguing that our customers were not benefited by

power purchase agreements, because the Company and the customers were

deprived of the use of the depreciated generation plant at the end of the

power purchase agreement term. Public Service had always argued, against

Dr. Schechter, that we expected to see economic bids from contract

renewals, and that competition among renewing bidders would drive down the

prices to a reasonable level. The results we saw in the 2005 All-Source RFP

supported Dr. Schechter's prediction, not ours.    We now believe that we

need to structure our competitive acquisition processes in a manner that

results in Company ownership of the facility - if we are to capture for our

customers the benefits that Dr. Schechter has always argued should be there

for our customers.
SO WHAT KIND OF MODIFIED ALL-SOURCE BID DOES THE COMPANY

PROPOSE?

We propose using a "reverse auction"/"build transfer" competitive bid

structure, with the ultimate price paid for resources capped at the price of a

Company-owned resource. Since this is a new concept, I will describe it in

detail.

          Our proposal involves essentially two forms of bidding. Public Service

will release an All-Source solicitation (modified as discussed above to meet

carbon goals and to exclude intermittent resources) to two groups of eligible

bidders. The first set of eligible bidders will be the group of existing resources

with capacity over 30 MW with PPAs expiring before or during the RAP.

These bidders would compete to sell their projects to the Company in a

"reverse auction" process. What we mean by this is that the bidders would

compete to sell their existing generating facilities to the Company. Bids would

be evaluated based on the quality (including, but not limited to plant age, heat

rate, efficiency, emissions, expected remaining life, cost of expected

maintenance and capital investment to maintain operation) of the asset as

well as the bid price. At this point, we believe that this pool of bidders could

include the following:
   Table KTH-7 - Contracts that expire between now and 2015


      Project                                     Summer
                                                  Capacity
      Blue Spruce Energy Center                   271 MW
      Thermo Cogeneration                         150 MW
      Thermo Monfort                               32 MW
      Black Hills Arapahoe                        122 MW
      Black Hills Valmont                          79 MW
      Fountain Valley                             238 MW
      Rocky Mountain Energy Center                497 MW
      Thermo Power IUNC)                           69 MW
      Front Range Power Company                   133 MW
      Total                                      1591 MW


      Note that our resource need is for approximately 800 MW, if the

Commission approves the concentrating solar thermal Section 123 set-aside

proposed later in my testimony. On the other hand, we have 1,591 MW of

existing capacity that could bid to meet that need. What is obvious but worth

noting is even if we proposed bidding for PPAs to fill the 800 need, our

resource need is far below the capacity represented by these projects, so

some of them will not have a continued outlet for their resources with Public

Service.   We believe this glut of capacity should provide substantial

competitive pressure on these projects to offer their best deals to Public

Service.

YOU    MENTIONED TWO          BIDDING STRUCTURES, WHAT               OTHER

BIDDERS WILL BE ELIGIBLE UNDER THE MODIFIED ALLSOURCE

STRUCTURE?

The second set of eligible bidders will be entities who want to build new

generation projects and sell the projects to the Company either during the
development process or as completed projects.         We are calling this the

Buildrrransfer bidding structure.    As I discussed earlier, because of our

commitment to carbon reduction, we would not accept bids from coal plants

that did not include carbon capture and sequestration. Also, because we are

creating a substantial segment for wind under a separate Section 123 set-

aside, and because we need dispatchable resources to operate our system

reliably, we would not allow wind bids without storage into this competitive

acquisition. We would accept a range of dispatchable technologies into this

bid process, including gas-fired resources, wind or solar with storage,

pumped storage hydro, coal with carbon capture and sequestration, etc.

      As allowed by Rule 3604u) we propose to have a Section 123 set-

aside for new concentrating solar thermal resources that bid into this All-

Source RFP. To meet the requirements of the RFP, the concentrating solar

thermal bidders would need to propose to build a concentrating solar thermal

resource and sell the project to the Company, either during the development

process or as a completed project. Our bidding proposals would give "two

bites at the apple" for concentrating solar thermal resources.                First,

concentrating solar thermal projects would be given a chance to compete

head-to-head with other resources to fill the portfolio based on price

competition. Second, within the All-Source, we would have a Section 123

competition to fill our proposed 200 MW set-aside from projects that were not

successful in the first attempt. With the combination of the acquisitions into

an all-source format, the overall need to be filled will be about 1,000 MW.
        In Volume 4 of the resource plan, we have provided the proposed All-

source reverse auctionlbuild transfer RFP that describes the RFP process in

more detail. We also include the model contracts that would be used in this

solicitation.

WHEN WOULD THE COMPANY ISSUE THIS RFP?

                                              ,
We would issue it at the conclusion of Phase 1 which we expect to be the fall

of 2008. In preparing for the CRP, our engineering and construction group

has been monitoring the lead-time for the equipment needed to supply this

resource need.     We have found that lead times are increasing quite

dramatically. In order to meet the combined cycle need in 2014, we believe

that a CPCN would need to be filed in 2009, so we plan to issue the RFP in

order to allow completion of the evaluation in time to support any needed

CPCN and permit filings and construction.     Note that we will continue to

monitor this situation and will recommend adjustment as needed.

DO YOU BELIEVE THAT THE REVERSE AUCTION AND BUILD-

TRANSFER BIDDING STRUCTURES ARE ACCEPTABLE FORMS OF

COMPETITIVE BIDDING UNDER THE RESOURCE PLANNING RULES?

Yes. This bidding structure will elicit head to head competition, which is in

accord with Commission competitive bidding rules. The Commission's rules

do not specify that the bidding must result in power purchase agreements,

although that certainly has been an acceptable outcome in the past. But we

now need to consider other forms of competitive procurement if we are to

meet the objectives of the Commission rules, remain a financially healthy
company, and ensure our customers obtain good generation value in the

long-term.   Rule 3604(j) requires the utility to present resource plans that

minimize net present value of revenue requirements consistent with reliability

considerations, financial and development risks and taking into consideration

the costs and benefits of proportionately more Section 123 resources. We

will evaluate bids as required by the Commission rules.

WILL THE COMPANY BE ABLE TO ENTER INTO ANY MORE PPAS?

We are proposing to acquire certain energy-only priced assets through PPAs,

because these assets will not be subjected to lease accounting treatment.

But we have not found a reliable and practical way around the accounting

issues for most long-term PPAs that price capacity and energy separately.

Unfortunately, this issue is not within Public Service's control - but is being

dictated to us by accounting standards and national credit-rating agencies.

We understand that the Commission has repeatedly expressed a desire for

competitive procurement, to incorporate the price discipline of the competitive

market into our resource acquisition.    We encourage the Commission to

broaden its view of what may properly be considered competitive acquisition

under the Commission's resource planning rules.

WHY DO YOU PROPOSE TO USE A SECTION 123 SET-ASIDE FOR THE

CONCENTRATING SOLAR THERMAL PROJECT?

Today, we believe that concentrating solar thermal projects cost about

$150/MWh, and that there is significant promise in that technology, especially

as advances are made in thermal storage.        In our plan, we advocate a
Section 123 set-aside within the overall Reverse Auction/Build-transfer

process, which will assure 200 MW of concentrating solar thermal within the

RAP, and allow for more than that amount if the promises of generation

efficiencies and thermal storage are realized. We read Rule 3610 (j) to

encourage that Section 123 resources be acquired through a set aside in all-

source bidding so that the Commission can evaluate the cost impact of the

set aside in Phase II.

WHY DO YOU PROPOSE TO WAIT UNTIL 2015 FOR THE SECTION 123

SET-ASIDE FOR CONCENTRATING SOLAR THERMAL?

We believe a target in-service date of 2015 is prudent given the current

prediction of cost decreases over time and the recent announcements from

other US utilities for large solar thermal additions in the 2011/2012 time

frame. By waiting, we do not compete with those projects for equipment;

instead we will be able to take advantage of technical advances associated

with those projects. To the extent that lower cost projects are bid in earlier

years than 2015, we will consider them on their merits as either economic

bids or for early satisfaction of the set-aside. We are somewhat concerned

that the solar thermal bids under this All-Source RFP may not be as firm as

we traditionally expect because of pace of technology development between

the time the bid is issued and the 2015 in-service date. We will have to

address this as we see bids in that solicitation.

DOES THE COMPANY PROPOSE ANY CONTINGENCY PLAN OR PRICE

CAP FOR THIS ALL-SOURCE SOLICITATION?
Yes. We propose that at the time the bid is issued, we will file at least two

site-specific utility build projects - a combined cycle and a combustion turbine

and potentially a self-build concentrating solar thermal project, which will

serve as both the price cap and the contingency plan should bidders either

bid projects that are found to be too expensive or should we fail to attract

sufficient bidders. We propose that those utility build alternatives will be filed

under seal prior to the receipt of bids under the RFP so that we don't receive

bids clustered just under the prices of the contingency alternatives. The

sealed alternatives would be made available to the Commission, Commission

Staff and the OCC.

DOES THE CONCENTRATING SOLAR THERMAL ACQUISITION USE

PART OF THE HB-1281 SET-ASIDE FOR UTILITY OWNERSHIP?

No. Because we are acquiring the concentrating solar project as part of an

all-source bid, which meets the requirements for competitive acquisition under

the Commission rules. Because the lease accounting issues push us toward

utility ownership, we believe that the process satisfies the requirements under

the legislation for utility ownership through bidding and, therefore, we believe

that the ownership should not be included in the calculation of the set aside.

CAN OTHER RESOURCES BID INTO THIS RFP?

Yes, other resources may be bid so long as they meet the terms of the RFP -

have a capacity greater than 30 MW, provide non-intermittent capacity, and

bid in a form to ultimately be owned by the Company. Geothermal resources,
     biomass resources, pumped storage hydro are all examples of resources that

     could qualify under this structure.


                            VIII.   SMALL PROJECTS

Q.   CAN YOU DESCRIBE THE COLUMN (COLUMN 10) LABELED SMALL

     PROJECTS IN TABLE KTH-4?

A.   Yes. This column is a catchall for projects less than 30 MW and represents

     multiple technologies and projects.

Q.   CAN YOU DESCRIBE THE 4 MW BIOMASS PROJECT?

A.   Yes. The Company proposes to work with a technology vendor to utilize a

     proprietary technology that the vendor is developing to gasify wood to

     produce a gas for power generation. Our proposal is to work on this as a

     sole-source PPA. We can financially accommodate both this PPA and the 25

     MW all-solar PPAs because of their relatively small size and the expected

     energy-only payment structure, which will not trigger lease accounting. The

     idea is to use pine-beetle-kill wood as the feedstock for the gasifier. The

     expected price of this project is above our avoided costs, but the project has

     significant societal benefit. For years, the State of Colorado has been looking

     for a way to dispose of this natural tragedy and to date we haven't found a

     project that works.    Disposing of the wood waste in this manner has a

     beneficial effect on greenhouse gas emissions because the alternative is to

     either allow the wood to rot in place or to be landfilled, both of which

     contribute significant carbon and methane to the atmosphere.          We are

     currently working on a term sheet with the technology vendor. To the extent
that this project does not come to fruition, it will not have a material impact on

our overall plan.

WHAT OTHER PROJECTS MIGHT BE PART OF THE PLAN THROUGH

THIS CATEGORY?

The Company has PPAs with several hydroelectric generating projects that

expire during the RAP. We have been allowing small projects, like hydros

and landfill gas projects, to bid in the last three All-Source solicitations and

each time the projects are so small that it is very hard for us to accurately

evaluate them in the analysis that we perform to evaluate the larger projects.

As part of the plan, we included an energy-only priced PPA for renewable

energy resources in Volume 2 of the CRP. We propose to evaluate small

projects, including hydroelectric contract renewals, landfill gas projects, and

biomass or geothermal projects under the competitive acquisition exemptions

afforded by Rules 3611 (c) and (f). We will evaluate these options as they

become available and will enter into PPAs with projects where we deem the

supply of energy and capacity to be cost effective. We do not anticipate that

this will have a significant impact on the overall resource plan. With the

exception of government-owned projects, we plan to include purchase options

in the PPAs so that we have an option for long-term ownership on beneficial

projects and we remain open to the opportunity to invest in small projects.

We will file any executed PPAs with the Commission promptly.

HOW     WILL    YOU     ACCOMMODATE           COMMUNITY         BASED      WIND

PROJECTS?
In multiple ways. HB07-1281 limits the community based projects that qualify

for the higher REC multiplier to 30 MW in size. Community based projects

under 30 MW that are interested solely in a PPA can provide a proposal to

the Company at any time and we will evaluate for cost-effectiveness and

would use the energy-only PPA included in Volume 2 the CRP.             Larger

projects can propose a Company-owned portion in addition to the

Community-based portion and bid into the Build-TransferIPPA RFP and

economic consideration will be given to the statutory REC bonus for the

community-owned portion.

WHAT ABOUT OTHER PROJECTS LESS THAN 30 MW?

We will consider all small projects (< 30 MW) on a case-by-case basis and

will evaluate them for cost-effectiveness and benefits, as those projects are

available.

MIGHT OTHER PROJECTS BE CONSIDERED?

Yes. The Company is considering a small concentrating solar thermal project

which could produce the equivalent of about 5 MW of solar powered thermal

energy to one of our fossil-fuel fired coal plants. To the extent that we are

able to find a technologically feasible and attractive option, we would make an

application with the Commission.      In addition, we are investigating the

possibility of a innovative clean technology program which would provide

either investment opportunities or PPAs for some set of small projects that

employ new technologies but which haven't yet reached a level of cost-

effectiveness that would typically be required for exemption from competitive
acquisition under the RP Rules. As we determine the parameters of this

alternative, we will similarly make an application with the Commission for

approval of the program.


                           IX.    SB07-100

HOW WILL THE BID PROCESSES TIE TO THE SB07-100 TRANSMISSION

EXPANSIONS?

The first wind acquisition will encourage development in Zones 1 and 3.

Under the plan, about 300 MW of additional transmission capacity will be

available by the first in-service date (2010) in northeastern Colorado (Zone 1)

and 80 MW will be available in southeastern Colorado (Zone 3). Subsequent

solicitations will benefit from the full build-out described in the Company's

SB07-100 filing, more specifically the Eastern Plains Transmission Project,

the 57-mile transmission line from Lamar, CO into Baca county, and the

Pawnee-Smoky Hill 345 kV Transmission line project that was submitted for a

CPCN. The Wind and the All-Source RFPs are timed so that those projects

could also take advantage of this full build out. The Concentrating solar

thermal set-aside would likely be located in the San Luis Valley (Zone 4),

which under the SB07-100 filing indicates an additional 200 MW of additional

transmission capacity is available to interconnect a new resource.


            X.     PLAN COMPARISON AND SUMMARY

HOW DOES THE PREFERRED PLAN COMPARE TO PLANS WITH

OTHER LEVELS OF SECTION 123 RESOURCES?
We provide three levels of Section 123 Resource penetrations in our CRP - a

low case, a medium case, and a high case. Our preferred plan is the high

case.

        The Low Section 123 Plan is essentially a "meet the minimum

requirements of the law and system reliability" case - in other words, with

REC borrow-forward and banking, that plan satisfies the requirements of

HB07-1281 and the DSM satisfies the requirements of HB07-1037.              All

renewable resources are added at the last-possible date for compliance.

Consistent with Commission rule 3604(j), this plan is labeled throughout the

CRP volumes as the Low Section 123 Plan and will generally be the lowest

cost plan.

        A Medium Section 123 Plan was developed by accelerating some wind

additions into the RAP and including the replacement of the coal plants with

the Arapahoe combined cycle repowering. The details of that plan are

included in the CRP volumes, although I do not discuss that plan in any detail

in my testimony.

        Figure KTH-7 details the levels of Section 123 resources in each plan.
   Figure KTH-7   - Level o f Section 123 Resources i n each Plan




      I                Low 123      Medium 123       High 123




WHY IS THE COMPANY ADVOCATING THE HIGH CASE?

For the following reasons:

   a. The high case projects the lowest utilization of natural gas for

      generation and the plan is therefore the most resilient to changes in

      natural gas prices. It provides the customers with an energy hedge

      against the price of natural gas.

   b. The high case produces the lowest level of carbon dioxide emissions

      from generation. It is therefore the case that exposes customers the

      least to high costs of carbon dioxide emissions in the future.

   c. The high case deploys very close to the maximum amount of

      renewable resources within the 2% rate cap determined to be in the

      public interest by the legislature in HB07-1281.

   d. The high case positions the Company on a glide path toward meeting

      more aggressive carbon reduction targets.
Q.    CAN YOU SUMMARIZE THE WAY THAT THE COMPANY PROPOSES TO

      ACQUIRE RESOURCES UNDER THIS CRP?

A.    Yes. We propose issuing the following RFPs as part of this CRP. In addition,

      we will issue an all-solar RFP in January 2008 and RFPs for more on-site

      solar facilities under the Company's 2008 Renewable Energy Standard

      Compliance Plan.

                            TABLE KTH-8 - RFP Schedule

Solicitation                  Expected Acquisition        Expected Issue Date
Wind - First Acquisition      300 MW for in-service in    January 2008 during
                              2010 through 2012           Phase l
Wind - subsequent             500 MW for in-service in    Approximately 2010
                                                           ~   ~




acquisitions                  2013 through 2015
All-source                    1000 MW of capacity         Fall of 2008 at the
                              resources including a 200   conclusion of Phase I
                              MW concentrating solar
                              thermal set aside


      WHAT RESOURCES DO YOU PROPOSE ACQUIRING WITHOUT RFPS?

      The Arapahoe combined cycle and the 4 MW beetle kill biomass project. In

      addition, we propose to consider offers to sell Public Service energy and

      capacity from projects under 30 MW on a case-by-case basis under the

      resource plan exemptions to competitive resource acquisition using a cost

      effectiveness test.

      IS PUBLIC SERVICE SEEKING ANY WAIVERS OF THE RESOURCE

      PLANNING RULES?

      Yes. Public Service is seeking a waiver for the ArapahoeICameo retirements

      replaced by the Arapahoe combined cycle.            We understand from the

      discussion around the Commission rules that the Commission's preference is
to delay that decision until Phase II.     However, we respectfully ask the

Commission to give the Company some direction in this matter as the

Commission makes its public policy decisions in Phase I. This proposal has

significant implications for our resource needs in subsequent years and on

the Company's ability to start squarely down a path of meeting increasing

load requirements while reducing carbon. We intend to file a full CPCN for

this project while Phase I is being debated.

CAN YOU DESCRIBE THE RATE RELIEF THAT THE COMPANY IS

REQUESTING?

Yes. At this point we are asking, in the 2008 Renewable Energy Compliance

Plan docket, for the Commission to immediately raise the RESA to the 2%

level allowed under legislation. We expect that we can acquire the resources

that are contained in our preferred plan through 2015 within the 2% retail rate

impact allowed by HB07-1281.

GOVERNOR RITTER RECENTLY ANNOUNCED HIS PROPOSAL ON

CLIMATE CHANGE AND IT CREATES A GOAL FOR THE STATE TO

REDUCE CARBON           DIOXIDE     EMISSIONS BELOW 2005             LEVELS

ECONOMY WIDE BY 20% BY 2020. HE ASKS UTILITIES TO REDUCE

CARBON DIOXIDE EMISSIONS BY THAT SAME AMOUNT. HOW WILL

THE COMPANY MEET THAT OBJECTIVE?

In the CRP, we describe some alternatives that we have to meet that

objective. To start, if we continue along the path that we have proposed in

the preferred plan and add similar resources in the years between 2016 and
2020, we would have carbon emissions in 2020 that are about 10% below

2005 emission levels. We believe that legislative relief from the HB07-1281

retail rate impact cap will be required to continue to add renewable energy

post 2015, given today's estimates of future costs. As we look at our options

today, getting to a 20% reduction by 2020 will require retirement of additional

coal plants and replacement with no or low carbon dioxide emitting resources

and additional DSM, all of which will have upward pressure on electric rates.

       However, this analysis does not reflect significant structural changes

as envisioned by Governor Ritter in the way that consumers use energy and

in the way that customers and the utility generate energy. For example, the

Colorado Climate Action Plan calls for significant customer and government

reductions in energy usage, including improvements in lighting performance,

a call for industrial users to increase efficiency, and changes in building

codes. None of these changes in usage have been reflected in our current

base demand and energy forecasts or our DSM programs. Governor Ritter

envisions a market for agricultural carbon sequestration in which utilities

might fund changes in agricultural practices in exchange for carbon credits -

this source of carbon reduction has not been analyzed in this CRP. Governor

Ritter envisions that the Collaboratory will drive "the research and

development of new energy resource technologies" - these future

technologies could be used to generate electricity in ways that we have not

envisioned in this CRP.      The Colorado Climate Action Plan envisions

significant reductions in the cost of distributed generation. The plan forecasts
that rooftop solar panels could fall from $8 - $9/watt to $1 - $2/watt by 2017 -

such a dramatic change in the cost of generation is not factored into this

CRP.

       Our plan does include several factors that the governor cites as key to

meeting the state's goals - increased renewable generation including wind,

biomass, and solar, and our plan provides a path for new technologies to be

implemented.     Our plan shows a significant commitment to DSM and

distributed solar generation. Our plan includes the retirement of older and

less efficient coal-fired generation and the replacement of that energy with

cleaner generation for net savings in carbon dioxide production.

       The governor admits that the goal that he presented to Colorado is

ambitious and challenging. He indicated that the Climate Action Plan is a

"living document" that will change as technology and energy usage changes.

Our CRP is a bridging strategy that makes the significant change from

increasing carbon dioxide emissions to decreasing carbon dioxide emissions,

while meeting our customers' growing demand for electricity. As that demand

pattern shifts and as technologies develop and become more cost-effective,

our plan will change. In the Climate Action Plan, the governor says that he

will issue an executive order directing the Commission and other government

agencies to seek specific plans to achieve the proposed goals. We envision

that our next resource plan, the plan that we are pledging to file early in 2009

rather than 2011, will outline those strategies in more detail than was possible

in this plan. Keep in mind that much of the information Governor Ritter's plan
is not available today and will be developed over the next several years; for

example the report on agricultural carbon sequestration is not due until March

2009, so there is time for us to learn about these alternatives and to develop

a thoughtful plan that accomplishes the state's goals.

CAN YOU SUMMARIZE THE CRP FILING?

Yes. As a Company we feel that we have placed before the Commission a

resource plan that will ensure system reliability and integrity and keep

customer costs at a reasonable level, all while maximizing the use of

environmentally friendly sources of new generation.      Our plan increases

system fuel diversity, reduces natural gas usage from today's level, increases

renewable generation in Colorado, retires two older coal plants, includes

aggressive levels of DSM, meets the Renewable Energy Standard and all

other laws, follows the Commission rules, and ensures financial viability of

Public Service.

DOES THIS CONCLUDE YOUR TESTIMONY?

Yes.
                                                                      Attachment A


                               Statement of Qualifications

                                     Karen T. Hyde

         I have a Bachelor of Science in Metallurgical Engineering from Lafayette

College and a Master of Science in Mineral Economics from the Colorado School of

Mines.

         I began my career at Public Service 18 years ago.     I have held various

positions including, Research Analyst where I forecasted regional economics as well

as customer and sales growth, Planning Engineer and Senior Planning Engineer in

System Planning, where I negotiated power purchase agreements, amendments to

Power purchase agreements and financing documents for PPAs.              In System

Planning, I also performed production cost and expansion planning modeling and

provided expert testimony in the 1993 IRP and FSV CPCN dockets on these topics

on behalf of Public Service.

         In 1995, 1 became a Business Development Analyst where I developed

pricing for Public Service's bids under various wholesale requests for proposals and

I worked on a team looking at restructuring various purchased power contracts. I

eventually led that team and become Team Lead over Purchased Power

administration for New Century Energy.        In 1998, 1 was promoted to Manager,

Purchased Power. In 2002, 1 was promoted to Director, Purchased Power. In this

position, I was responsible for all long-term purchased power contract negotiation

and administration for all of Xcel Energy's utility operating companies. In 2006, 1

was promoted to the position of Vice President, Resource Planning and Acquisition.
In this position I am responsible for ensuring that the Company acquires sufficient

generation and gas transportation resources to meet its customer needs across the

Xcel Energy operating companies, I am also responsible for long-term wholesale

requirements sales and for securing transmission system access for native load. I

have provided testimony before the Colorado Public Utilities Commission in support

of QF contract restructuring, new purchased power contracts, the Purchased

Capacity Cost Adjustment, the 2004 renewable RFP, and for approval of the projects

associated with the 1999 IRP and the 2003 LCP. I provided policy testimony in the

2003 LCP contingency plan. I have also provided testimony in Texas, New Mexico,

Minnesota, and at the Federal Energy Regulatory Commission.

      Prior to working for Public Service, I worked as a forecaster for Baltimore Gas

and Electric and as a Lead Nuclear Engineer for the Department of Defense.
                                                                Exhibit No. KTH-1




Exhibit No. KTH-1 contains the 2007 Colorado Resource Plan, which is submitted in
four individual volumes

								
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