Direct Testimony and Schedules Pamela K Graika Before tl

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					                                           Direct Testimony and Schedules
                                                        Pamela K. Graika




         Before tl~e Minnesota Public Utilities Commission
                        State of Minnesota




In the Matter of the Application of Northern States Prover Company,
                      a Minnesota corporation
  for AutlaoritT to Increase Rates for Electric Service in Minnesota




                  Docket No. E002/GR-08-1065
                          Exhibit




                       Supply Operations



                        November 3, 2008
                             Table of Contents


        Intzoducfions and Qualifications                                1

II.     Summary of Testimony                                            2

IlL     Ove*wiew of Energy Supply                                       3

IV.     Recent Performance                                             4

V.      2009 O&M Budget                                                 6

VI.     Deferred Requests                                             17

VII.    Other Capit~ Improvements                                     20

VIII.   Summary and Conclusion                                        21



                                Schedules



Rfisum4 of Pamela K. Graika                                    Schedule 1

NSPM Energy Supply Cost Improvements                           Schedule 2




                                    i            Docket No. E002/GR-08-1065
                                                                G~aika Direct
 1                I. INTRODUCTION AND QUALIFICATIONS
 2
         PLEASE STATE YOUR NAM]~ AND BUSINESS ADDRESS.
 4 A. My name is Pamela K. Graika. My business address is 250 Marquette Plaza,
 5       Minneapolis, MN 55102.
 6
 7 Q.    BY WHOM ARE YOU EMPLOYED, AND \X/HAT IS YOUR POSITION.>
 8 A. I am employed by Northern States Power Company, a Minnesota corporation
 9       ("Xcel Energy" or the "Company"), as the General Manager, Poxver
10       Generation.


12 q.    FOR WHOM ARE YOU TESTIFYING.>

13 A. I am testifying on behalf of Northern States Poxver Company, a Minnesota
14       corporation, which is an operating public ul~ty subsidiary of Xcel Energy
15
16
17 q.    PLEASE SUMIxIARIZE YOUR QUALIFICATIONS AND E~ERIENCE.

18 A.    I have a Bachelor’s Degree in Chemical Engineering and have xvorked for
19       Xcel Energy in va*~ous management positions since 1980. Prior positions I
2O       held within the Company include Production Engineer, Plant Manager, and
21       Director of Environmental and Regulatory Affairs and General Manager,
22       Power Generation. My resume is attached as Exhibit (PKG-1), Schedule 1.
23
         WHAT ARE YOUR JOB DUTIES AND ACCOUNTABILITIES.p

25 A. I am responsible for the overall direction and management of the Energy
26       Supply Operations organization for Northern States Power Company -
27       Minnesota ("NSPM’) service territory (which includes Minnesota, North

                                                        Docket No. E002/GR-08-1065
                                                                       Graika Direct
        Dakota and South Dakota). I oversee the operational and finandal
 2      performance of the Compaw’s generating plants, except for our nuclear
 3      facilities, xvhich are separately managed by Dennis Koehl, Vice President and
 4      Chief Nuclear Officer and are addressed in this proceeding in Dkect
 5      TestimoW offered by Charles Bomberger, Vice President, Nuclear Projects. I
 6      am also responsible for developing and managing the Operations and
 7      Maintenance ("O&M") budget for the Energy Supply Unit.
 8
 9                        II. SUMMARY OF TESTIMONY
10
11 q.   WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?
12 A.   I sponsor the 2009 O&M and Capitai budgets for the Energy Supply
13      organization, discuss the status of projects that xvere authorized for deferred
14      accounting treatment. I recommend that the iXlinnesota Public Utilities
15      Commission ("Commission") find that these costs are reasonable for recovery
16      from customers in this rate proceedh~g.
17
18 q.   HOW HAVE YOU ORGANIZED YOUR DIRECT TESTIMONY?

19 A.   I first describe the Energy Supply organization and explain hmv the 2009
2O      Energy Supply O&M Budget was created, including the key assumptions and
21      guidelines used. I then identify the major cost drivers for 2009. In addition, 1
22      will discuss how process improvements and changes in operations have
23      impacted our 2009 budget and the major differences between 2007 actual and
24      2009 budgeted O&~l amounts. This is followed by a brief discussion of our
25      projects authorized for deferred accounting. Next, I explain the capital
26      invesmaents made to our Energy Supply fleet since the last rate case. Finally,



                                            2               Docket No. E002/GR-08-1065
                                                                           Graika Direct
     I provide my conclusions and recommendations for the Commission to
 2   consider.
 3
 4                   IlL OVERVIEW OF ENERGY SUPPLY
 5
 6   PLEASE DESCRIBE ENERGY SUPPLY’S ROLES AND RESPONSIBILITIES.

 7   Energy Supply’s principal role is to operate and maintain NSPM electric
 8   generating facilities in a safe, reliable, cost-effective and enviro,m~entally
 9   sound manner. We are also responsibIe for managing major construction
10   projects (such as the Metropolitan Emissions Reduction Projects ("MERP")
11   at Allen S. King, High Bddge and Riverside generation units), dispatching
     electric generation resources, and overseeing environmental compliance.
13
     PLEASE DESCKIBE THE TYPES OF COSTS YOUR ORGANIZATION I~NAGES.

15   Energy Supply manages all O&M, fuel, fuel-handling, and capital costs
     associated xvith the operation, maintenance and improvement of our
17   generating plants. These costs range from daily operating and maintenance
18   expenses to multi-year, multi-million-dollar capital projects. Key cost
19   categories include labor, materials, chemicals, external contactors, suppliers
20   and vendors.
21
22   PLEASE FLM3ORATE.

23   The core costs in our business area are the costs of staffing and associated
24   expenses needed to operate and maintain our poxver plants, as xvell as the
25   supporting serwices of engineering setwices, environmental permitting, and
26   fuel procurement. Labor, professional set-vices and other associated costs are
27   significant drivers of our budget, tn addition, our O&M budget includes

                                        3               Docket No. EOO2/GR-08-1065
                                                                      Graika Direct
          expenses related to plant equipment maintenance and repair, periodic
 2        equipment overhauls, and projects required to maintain generation plant
 3        operation capacity and reliability.
 4
 5        Detailed descriptions of the va*~ous departments xvitl~n the Energy Supply
 6        organization are available in the 2009/2010 Budget Documentation
 7        narratives. (See Volume 6, tab "D. Energy Supply".)
 8
 9                            IV. RECENT PERFORMANCE
10
     Q.   DESCRIBE THE PERFOP&,IANCE OF YOUR LARGEST BASE-LOAD NON-NUCLEAR
12        FACILITY.

13        Operational performance at the Sherburne County Plant, our largest plant,
14        has been excellent. During the period of 2005 to 2007, the availability and
15        reliability of all three generating units at the Sherbume County Plant have
          been in the second or first quartile in accordance xvith the National Reliability
17        Standards 0NERC) measures. The folloxving table lists three key reliability
18        mettqcs for the Sherburne Couhty Plant (all three units) for the period 2005
19        through September 2008.
2O
21
22
23
24
25
26
27


                                                4            Docket No. E002/GR-08-1065
                                                                            Graika Direct
 1                                                  Table 1
 2                   Key Reliability Metrics - Sherbume County Plan
 3
               Year                  2005               2006               2007                2008
                                                                                          (through Sept)
     Sherco Total
     Annual Equivalent              7.20%              5.12%               4.14%                 5.33%
     Unplanned Outage
     Rate
     Sherco Total
     Annual Equivalent 88.30%                         89.70%              89.70%                 91.20%
     &vailability
     3herco Total
     Generation in Net              15,379             15,469             15,874                 11,358
     MWhrs
 4
 5   (Source: North American ReliabiliU Corporation, Generation AvaiiabiliU Reporting System).
 6
 7     1n 2007, the plant’s Equivalent Unplanned Outage Rate ("EUOR") was in the
 8     ist quartile of all plants reporting under the North American Electric
 9     Reliability Corporation (NERC) standards as reported in the NERC
10     Generation Avaihbility Reporting System (GADS). In addition, 2005, 2006
       and 2007 were record total generation years for the Sherco facility.
12
13     PLEASE SUMiVLAALIZE RECENT ACTIVITY AT OTHER KEY FACILITIES.
14    We proposed the Metro Emissions Reduction Project (2vIERP) partly because
15     of degrading perfolTnance at our older coal fired plants. A.S. King, High
16    Bridge and Riverside Plants xvere experiencing increasing maintenance due to
17     failures of aging components. Through MERP at King Plant, ;ve upgraded
18    environmental systems and replaced sections of the plant that were seeing the
19    most degradation (such as cyclone burners and the slag tank). High Bridge is
20    a totally nexv plant, replacing the older coal plant. The Riverside conversion

                                                       5                    Docket No. E002/GR-08-1065
                                                                                           Graika Direct
 1        to combined cycle integratges nexv Combustion turbines and Heat Recovery
 2        Steam generators with the older unit 7 turbines. Once these units have
 3        completed all startup testing and warranty pel:iods, xve expect performance on
 4        these new and modified units to be very good.
 5
 6   q.   WHAT IS YOUR VIEW OF THE PERFORMANCE OF XCEL ENIERGY~S NON-

 7        NUCLEAR GENEKATING FLEET?
 8        I believe our performance is sound and will improve. We have made
 9        significant investments to upgrade and extend the useful life of key facilities
10        that w~ benefit customers through improved performance and availability.
11        Because improved availablit3* of our fleet minimizes our need to make market-
12        based purchases through MISO to supply our customers’ needs, this approach
13        will keep overall rates loxver than without this investment.
14
15                               V. 2009 O&M BUDGET
16
17        PLEASE SUiX~IARIZE THE NSPM OENERATION 2009 O&M BUDGET.
18        After adjusting our total budget for costs recovered through rate riders rather
19        than base rates (such as the costs associated xvith the Grand Meadows wind
20        project) or costs that are otherwise not appropriate for recovery (such as our
21        budgeted costs for NOx allowances that are no longer likely to be incurred
22        due to the D.C Appeals Court’s reversal of the Clean Air Interstate Rule), our
23        total company Energy Supply budget is $t6~ million. Ms. Anne Heuer’s
24        direct testimony reflects these adjustments and converts this total budget to
25        revenue requirements for the MS~nesota jurisdiction.
26



                                              6               Docket No. E002/GR-08-1065
                                                                             Graika Direct
           As I abeady mentioned, these costs are pz~narily labor and contract labor, as
 2         shown on the chart below.
 3
 4                                                 Figure 1
 5                             NSPM Generation 2009 O&M Budget



                                    Other Expenses    Lime
                                          6%          3%

                                  Chemicals
                                     6%




                                                                 Labor
                                                                 55%



                                  Contract Labor
                                      14%




 6
 7   Q. WH~T WERE THE KEY ASSUMPTIONS AND BUDGET GUIDELINES USED FOR
 8         DEVELOPING THE 2009 BUDGET?

 9 A. When prepa~ing the budget, we assumed:
10
        Exjoected labor rates and externa! contract labor rates. As I previously mentioned,
              labor and contract labor make up almost 70 percent of our total budget.
13            Our 2009 budget assumed wage increases of 3.5 percent over 2008, as
              indicated by the bargaining unit contracts and general wage increases. Mr.
15            Matwin McDaniels’ direct testimoW provides support for our overall labor
16            rate increase.
17

                                                     7         Docket No. E002/GR-08-1065
                                                                               Graika Dkect
        tTxpected p*#ing for in, outs and commodities. The costs of chemicals used in
 2      electric generation and emissions control (including lime, sulfuric acid,
 3      caustic and ammonia) have significantly increased in recent years.
 4      L’tkewise, the costs of materials used in our maintenance activities (such as
 5      steal and copper) are projected to continue to rise. Our budget assumed
 6      costs for these commodities based upon commodity price forecasts.
 7
 8      Plant overhauls in accordance with the 2009 NSPM Overhaul Schedule. The type
 9      and timing of major plant maintenance projects and retrofits significantly
10      affect our costs, including labor, contract labor, and materials. Our plan
11      seeks to minimize outages while ensut~Lng we in~plement needed
12      maintenance and projects to maintain or improve plant performance. We
13      also seek to schedule outages t~ avoid peak periods and times when
14      replacement energy costs are high to minimize the cost impact to
15      customers. Our budg.et assumes the plant outage schedule required by this
16     plan for 2009; the plan actually covers the ?Tears 2009 through 2015, as
17      such outage planning is most effectively done on a longer-tet~rn basis.
18
19     Expected projects and operalions at each 2~lant in accordance with our o2~eraling plan.
20     For example, ou~c budget assumes a full year of operation of High Bridge,
21     whose portion of the MERP project was completed in 2008, and a partial
22     year of Riverside operation, xvhose conversion is expected to be completed
23     mid-year 2009.
24
25   LET’S DISCUSS A FEW OF THESE IN GREATER DETAIL, STARTING \VITH A I~d~Y

26   COST DRIVER, LABOR.       HOW DID YOU DETERMJNE THE LABOR PORTION OF

27   THE BUDGET?


                                             8                 Docket No. E002/GR-08-1065
                                                                              Graika Dkect
 ~   A. We budget for labor by detm~aining staffing levels and estimating overtime
 2        needs considering operations and maintenance requirements. Staffing-level
 3        changes are vaIidated and negotiated in a smSes of budget-reviexv meetings.
 4       Labor budgets are calculated based on staffing ievds and actual (historical) or
 5       projected labor rates.
 6
 7 Q. You PKEVIOUSLY MENTIONED HOW LABOR RATES HAXrE INC1LEASED. How
 8    HAVE STAFFING LEVELS CHANGED IN RECENT YEA~S?

 9       Our overatl levels remain below our 2004 staffing levels. Additionally, as
10       indicated in Figure 2, generation capacit3T per employee has increased steadily
         since 2004. There have been small increases in staff rdated to increased O&M
12       for emissions control activities. For example, the nmv emissions control
13       equipment at King requires more labor to operate and maintain, as do the two
         new generating units at Blue Lake. The conversion of High Bridge from coal
15       to natural gas provided for a reduction in labor to operate, as will the new
16       Riverside Combined cycle plant.
17
18                                        Figure 2
                  NSPM Energy Supply MW’s Per Employee Trend
                                                                           20




                   ~   4
                            2004 2005 2006 2007 2008 2009
                           Actuals Actuals Actuals Actuals Budget Budget


                                    I"=~’MW’s per Employee I

                                              9                Docket No. E002/GR-08-~065
                                                                              Graika Direct
        DO YOU HAVE ANY INDICATORS OF THE COMPANY’S EFFECTIVENESS AT

 2      MANAGING LABOR COSTS?

 3      Yes. Our cost of direct-loaded labor increased 6.0 percent from 2007 to
 4      2009, but during that same period, negotiated wage increases for bargaining
 5      employees increased by over 7.0 percent (3.5 percent in 2008, and 3.5 percent
 6      in 2009). Because over 75 percent of the total employees in the Energy
 7      Supply are bargaining unit employees, such savings are significant.
 8
 9      ]]LEASE EXPLAIN THE OTHER LABOR ELEMENTS INCLUDED IN THE 2009

10      BUDGET.

11      Overtime and Premium Time also affect our overall labor costs and are highly
12      dependent on our operating plans. Fox example, our 2009 budget for
13      Overtime is 18 percent lmver than 2007 actuals due prima@ to completion
14      of the High Bridge conversion. Premium Time, which is off-shift pay in
15      accordance with the terms of the Labor Agreement, is largely driven by
16      temporarily changing shifts for training purposes. Because of retirements, we
17      estimate our Preruium Time will increase somewhat over 2007 levels due
18      primarily to the need to train nmv employees.
19
20 Q.   COULD YOU EXPLAIN THE CONSULTING AND CONTRACT LABOR PORTION OF

21      THE BUDGET IN MOKE DETAIL?

22      These costs are primarily assodated with external contract labor employed for
23      plant equipment maintenance and repab. The 2009 contract labor budget
24      represents a 5 percent decrease compared to the 2007 actual cost of $20.4
25      million. One of the most significant dryers of the contract labor budget is
26      getaerating plant overhauls that vat7 in work scope from year to )Tear.
27

                                          10              Docket No. E002/GR-08-I065
                                                                         Graika Direct
 1   Q. How DO YOU ENSURE THE REASONABLENESS OF THE COMPANY’S OVERALL
 2       ACQUISITION AND MANAGEMENT OF CONTRACT LABOR?

 3       Through our operating planning process, we assess and select the most
 4       effective and efficient use of contractors to perform various work rusks at our
 5       generating facilities. Using contractors to perform certain non-routine tasks
 6       or to supplement our internal staff duting major outages can be the most
 7       cost-effective way to complete a project. Our operational planning process
 8       considers various alternatives and adopts the most reasonable staffing mix
 9       and resources to accomplish the needed operaling and maintenance tasks.
10       Major contracts are bid, and all contract ~vork is evaluated against budget and
11       engineering esOnates. Contractors are monitored to ensure performance
12       meets expectations.
13
14 Q. DO YOU BELIEVE THE 2009 TEST YEAR OPERATING PLANS AtLE A I~ASONABLE
15       BASIS FOR SE]TTING FINAL RATES?

16       Yes, I do. _As I noted, some aspects of our operating plans reduce costs, xvhile
17       others increase them. However, I believe it is clear that we ~ continue to
18       face increasing cost pressure. For example, while High Bridge labor costs
19       may decrease once the 12-month warranty inspection is complete, the same
20       inspection Hill be required at Riverside in 2010. L’~kewise, I anticipate that all
21       of our generating faUflities will likely experience changes in their operation and
22       dispatch as additional wind capacity is installed on our system.
23
24       LET’S DISCUSS SOME OF THOSE OTHER COST DRIVERS IN THE BUDGET.

25       PLEASE ELABORATE ON THE CHANGES IN COMivIODITY COSTS AND HOW THEY

26      AFFECT THE 2009 BUDGET.




                                             11              Docket No. E002/GR-08-1065
                                                                            Graika Direct
 1 A. We use substantial amounts of steal, pipe, xvire, cable and other commodity
 2           materials in the maintenance and repair of generathag plants. Changes in
 3           commodity costs directly affect our O&M budget due to both changes in
 4           price and changes in the volume of commodities we purchase - tl~e
 5           Combination of both price and volume changes compounds the effect of
 6           recent commodity price increases on our budget.
 7
 8           With respect to price changes, Figure 3 below illustrates the escalation over
 9           the past five years.
10                                                            Figure 31
11                                           Commodity Price t~sealation
12
13
                                                                            .... DieselFuel
14
t5
                                                                            --"~"" Steel Pipe
16.
17                                                                          "~Ready Mix Concrete
18
19
20
21                                                                                Aluminum

22
23                                                                                High Alloy Steel

24
                        2002   2003   2004   20~5   2006   2007   2008     ¯ "’1" Iron & Steel
25


      t U.S. Department of Labor, Bureau of Labor Statistics, Retrieved October 30, 2008, http:/data.bls.gov/
        cgi-bin/srgate.

                                                                                    Docket No, E002/GR-08-1065
                                                                                                   Graika Direct
 1      These commodity price increases have a particular impact on our budget, as
 2      our current operational plans require more materials, given the projects
 3      scheduled at our plants. For example, as I previously mentioned, we will be
 4      conducting the 12-month xvarranty inspection of High Bridge in 2009, which
 5      requires increased materials over prior years. Thus, our budgets expet-ience a
 6      double impact - higher prices on greater quantity purchased. We estimate
 7      that changes in material costs have increased our budget by 10 percent over
 8      2007 levels alone.
 9
10 Q. PLF.ASE Discuss THE COMTPARABLE CHANGES \Xq[TH RESPECT TO THE
11      CHEMICALS PORTION OF THE BUDGET.

12      Even more dramatic than material costs, our chemical costs have increased by
13      over 500 percent compared to 2007 actuals. As indicated in Figures 7 and 8,
14      this increase is driven by significant price increases in the chemicals we
15     purchase and the quantity we purchase.
16
17                                                  Figure 4
18
19                    NSPM Generation Ammonia Cost Trend
20

               $7,000,000
               $6,000,000
               $5,000,000
               $4,000,000
               $3,000,000
               $2~000,000
               $1,ooo,ooo
                       $o
                                     1

                      2006 Actuals       Increasedue to commodity pricing I~ increase due to usage ]

21

                                                        13                     Docket No. E002/GR-08-1065
                                                                                              Graika Direct
                                               Figure 5
 2                NSPM Generation Sulfuric Acid/Caustic Cost Trend
 3

                  $3,000,000

                  $2,500,000

                  $2,000,000


                  $1,500,000

                  $1,000,000

                   $500,000

                         $o
                                2006 Actuals 2007 Actuals 2008 Forecast 2009 Budget

                    ,l~Actuals based on 2006-07 pricing ~[ncrease dueto commodity pricing!
4
5
 6   Q.   Haw YOU EXPERIENCED SI~ INCREASES IN THE USAGE AND COM2~fODITY

 7        COST OF LIME.)
 8        Yes. The total budget for lime in 2009 is $4.9 million or approximately 4
9         percent of the total O&M budget. The 2009 budget represents a 113 percent
10        increase over actual 2007 cost of lime. The increase beVaTeen 2007 and 2009
          is attributable m both increased usage and increased commodity cost. Usage
12        of lime increased both at King Plant with the installation of new pollution-
13        control equipment and at the Sherbume County Plant (Sherco), where we are
14        increasing the removal rate of SO2. The following chart indicates the cost
15        trend of lime used in the operation of our generating plants.
16
17


                                                  14                 Docket No. E002/GR-08-1065
                                                                                    Graika Direct
 1                                             Figure 6
 2                           NSPM Generation Lime Cost Trend
 3

            $6,000,000

            $5,000,000

            $4,000,000

            $3,000,000

            $2,000,000

            $1,ooo,ooo

                   $o


              [12006 Actuals 13 Increase due to commodity pricing ~ Increase due to usage ]
 4
 5
 6   Q:   WHAT ELSE DO YOU DO TO I~IANAGE COSTS?

 7        We take advantage of technology changes and other potential improvements
 8        to continually manage our costs. Exhibit~(PKG-1), Schedule 2 provides a
 9        description of various process improvements, technology improvements and
10        capital investment that xve have taken to both manage current costs and avoid
11        future increases. Other actions that we have taken include:
12
13            We use a "Process Cost Analysis" process, under which we evaluate high
14            O&M cost systems and/or components and the best practices from our
15            peers who are perfotrning those same functions for less. Through this
16            process, we seek to fred lower-cost processes that may be applicable to
17            our system.

                                                  15                 Docket No. E002/GR-08-1065
                                                                                    Gzaika Dkect
 1       We have made other significant productivity improvements to control
 2        future cost increases. For example, we have made modifications that
 3       enable us to start and operate many of our peaking plants remotely, which
 4       contained our labor cost in the peaking area. These improvements and
 5       associated costs are tracked and are used in the annual budget
 6       development process.
 7
 8   Of course, some plant improvements lead to positive results but higher costs.
 9   As we have installed increasingly sophisticated environmental controls on the
10   NSPM generating plants, our environmental performance has dramatically
11   improved. However, this equipment requires larger O&M expenditures to
12   operate and maintain.
13
14   DO YOU HAXrE A1-4Y OTHER R~MARI(S ABOUT THE ENERGY SUPPLY O&M
15   BUDGET?
16   We exercise management controls and oversight to ensure our costs are
17   reasonable. We have and will continue to experience significant cost
18   pressures as xve continue to expand our system, implement environmental
19   improvements, and change the mix of our generating fleet to include
20   additional wind resources. While ]gnergy Supply costs are likely to continue
     to increase in the future, our Resource Planning and resource acquisition
22   processes will ensure that overall rates for customers are reasonable.
23
24
25
26
27

                                         16              Docket No. EOO2/GR-08-1065
                                                                       Graika Direct
                           VI. DEFER~D REQUESTS
 2
        PLEASE SUM3X4ARIZE THE PROJECTS RECEIVING DEFEtLRED ACCOUNTING

 4      TRF~TMENT.

 5 A.   In September 2006, we filed a request for deferred accounting treatment of
 6      costs associated with projects related to the Minnesota MercmT Emissions
 7      Reduction Act of 2006, Docket No. E002/M-06-1315. The costs included in
 8      the pedtion ~vere related to mercury emissions monitoring and control
 9      systems at our King and Sherco Plants, the mercutT sorbent injection system
10      at Sherco Unit 3, studies being undertaken to look at mercutT control
1i      technologies for these plants, NOx control projects at our Sherco Plant and
12      chemical costs at our A.S King plant to control for SO2 and NOx removal.
13      The Commission issued an order in this docket on JanuarT 31, 2007 that
14      authorized deferred accounting treatment.
15
        On August 26, 2008 xve filed to update this request such that if needed, the
17      deferral xvould extend to costs incurred through the end of 2009. We also
18      requested approval to defer costs for the mercmT sorbent injection system at
19      the King plant. Hoxvever, as a result of this rate case, we are requesting
20      recovet3T of these costs in base rates, with the exception of the mercmT
21      control systems at Sherco Unit 3 dm31ng 2009 and Y-Ang plants which ~vill not
22      be in service at the beginning of the test year. As discussed in Ms. Heuer’s
23      testimony, the CompaW proposed to amortize the revenue requirements
24      associated with the capital costs and expenses associated with this deferral
25      over the next four years resulting in a total of $2.2 million to be recovered
26      each year.
27


                                          17             Docket No. E002/GR-08-1065
                                                                        Graika Direct
 1   Q.     ]~LEASE DESCRIBE GENERATION INVESTMENTS THAT HAVE BEEN M~_DE TO

 2          IMPROVE ENVIRONMENTAL PERFORMANCE THAT \VERE SUBJECTS OF THE

 3          DEFERRAL REQUESTS.

 4          In 2006, 2007 and 2008, xve installed low NOx burners, ducting, dampers and
 5          controls on our Sherco units. It is anticipated that with the installation of this
 6          equipment, xve xvill be able to meet NOx regulations xvithout installation of an
 7          selective catalytic reduction ("SCR") on any units. These projects are
 8          examples of investments that improve environmental performance. These
 9          projects xvere included in our September 2006 deferral request (Docket No.
10          06-1315) and updated deferral request filed in August of 2008 in the same
11          docket. Total capital investment related to these projects is $33.3 million. Ms.
12          Heuer provides the revenue requirement impacts of these investments and
13          support for inclusion in the test year.
14
15                                                    Table 2
16                 Emissions Reductions from NOx Capital Projects at Sherco
17

                                         Project(~1   Projected0’)                 Projected{c?
                                         Emission     Post-Project     ~Ore_          Post-       Projected
                                           Rate                      Project{c)      Proiect      Emissions
                                         Ob/mmbt         Rate        Emissions     Emissions      Reduction
                                            ,)        0b/mmbtu)      (tons/yr)      (tons/yr)     ~on~/yr)
          Sherco Unit 1: Low NOx
          Burners/Separated Over Fi~e
          Air ("SOFA") Project and         0.34          0.15         8,258          3,643         4,615
          Damper Replacement Project

          Sherco Unit 2: NOx Control -
          Damper Replacement Project       0.20          0.15         4,791          3,593         1,198
          Sherco Unit 3:
          NOx Control - Burner
          Mods/ SOFA /Mill                 0.35          0.18        11,160          5,740         5,421
          Optimization Project

          Totals                                                      24,209        12,976        11,234

                                                        18                     Docket No. E002/GR-08-1065
                                                                                              Graika Direct
 1    Based on pre-2006 data.
 2    Projected 2009 NOx year-end data.
 3    Using 2003-2007 average annual heat input (furl-based values).
 4    Total values for ut~it 3 (includes both Xcd Energy and SMMPA shares)
 5
 6 Q. ARE THERE ANY OTHER INVESTM]~NTS THAT THE COMPANY HAS MADE TO
 7       CONTROL EMISSIONS AT VARSOUS PLANTS?

 8      Yes. MMERA required that the Company install mercury monitoring
 9       equipment at our Sherco and King Plant by July 1, 2007. The monitoting
10       equipment cost approximately $246,000. This equipment is being used to
11       establish our baseline emissions for mercm3~ in order that we can better
12      compare the emissions after we have installed the mercury control technology
13      to the emissions rates prior to the installation of the controls.
14
15 Q. ARE THERE ANY O&M EXPENSES THAT THE COMPANY HAS INCURPdgD FOR
        EMISSIONS CONTROL THAT ARE NOT CURRENTLY BEING 1LECOVEtLED IN

17      RATES?

18      Yes. We are using lime and ammonia at our I~dng Plant to control for SO2
19      and NOx. The lime is used in the Dry Flue Gas Scrubber to ~emove SO2 and
20      the ammonia is used in the Selective Catalytic Reduction unit to remove NOx.
21      We began using these chemicals in 2007 in order to comply xvith federal Clean
22      Air Act regulations. At King, the pollution control equipment can achieve the
23      permitted rates of 0.12 pounds SOa pe~ million BTU 0b/mmBtu) and 0.10 lb
24      NOx/mmBtu. Without the chemical reagents, SO2 emissions would be on
25      the order of 0.57 lb SO2/mmbtu and 0.80 lb NOx/ mmBtu. The
26      combination of the capital investment under the MERP project at King and
27      the King chemical agents O&M investment project results in significant
28      emission reductions at the King Plant.

                                             19               Docket No. E002/GR-08q065
                                                                            Graika Direct
 1                     VII. OTHER CAPITAL IMPROVEMENTS
 2
          \X/HAT AP~ THE PRIMARY BUSINESS DP,2VERS AFFECTING THE CAPITAL

 4        EXPENDITURES THAT YOUR ORGANIZATION IS RESPONSIBLE FOR?

 5   A. There are multiple factors driving annual capital budgeting requirements. The
 6        most significant factors include generatioIx load grmvth, emfiromnental
 7        regulations, unit operational condition (aging and degrading plant equipment)
 8        and safety. Capital projects are also impacted by the same external market
 9        forces discussed earlier that are driving up the costs of steel and other
10        materials.


12 Q. PLEASE DESCRIBE HOW GENERATION INVESTMENTS ARE IMPACTING THE
13        NEED FOR THIS REQUESTED INCREASE IN RATES.

14       I have categorized our generation investments into those investments
15        presently recovered under a rider, and the remaining investments. Since 2007,
16        NSPM Generation has added $1,368 million in nexv investment. Of this
17        amount, $1,226 million already is or xvill be recovered through rates under
18       various riders. These riders atloxv NSPM, with Commission approval, to place
19       into rates investments that meet certain legislated criteria outside of a rate
20        case. Certain investments have been deferred, and we are seeking recover of
21        deferred amounts in this case. Other investments are normal test-year capital
22       investments included in the 2009 cost of service.
23
24       Some of these larger investments include:
25
26           Sherco 2 Boiler Arch Replacement Replace boiler tube sections
27           including boiler arch, sootblower openings, and boiler corners. These

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  1           areas have been the source of maW leaks affecting plant reliabi~ty.
 2            Replacing these sections xvill lower furore O & M and improve unit
 3            reliabJfity. Tl~s project is a good example of an investment that will
 4            hnprove plant reliability and EUOR results. This project will add $8.9
  5           million to plant in set’vice in 2009.
 6
 7            Sherco 1 & 2 Cooling Tower Replacement           Unit l’s and 2’s cooling
 8            toxvers xvere experiencing deterioration of structural elements and support
 9            structures, leading to the increasing probability of local failures of the
10            cooling toxvers. Environmental permits require operation of the cooling
              toxvers at certain times of the year. These projects are good examples of
12            investments that are needed to maintain existing plant performance.
13            These txvo projects adds $2.4 million to plant in service in 2006, and $9
14            million to plant in service in 2007.
15
16       3)   Sherco Pond Vertical Expansion Investments Sherco ash, and some
17            metro ash are placed in this xvet storage facility. Ash disposal is necessary
18            to conlinue plant operations within permit regulations. Vertical extension
19            of the ponds wi~ economicaily extend the storage capacity until a new
20            pond is needed. This project is another example of investments needed
21            to maintain plant performance. This project will add $4.6 million to plant
22            in service in 2008 and $3.3 million to plant in setwice in 2009.
23
24                      VIII. SUMMARY AND CONCLUSION
25
26 Q. PLEASE SUMMARIZE YOUR CONCLUSIONS.
27 A. While our costs have and xvill likely continue to increase, the Commission
28       should find that our proposed Energy Supply O&M and Capital budgets are

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 1      reasonable and approD-iate for recovet’y from customers. Our cost increases
 2      result p,qmarily from increased input prices, changes in the operation of our
 3      system to increase the quantit3T of purchased inputs, and expansion of our
 4      system to meet growing customer requirements. Through our planning
 5      process and managerial oversight, xve exercise appropi~ate controls and have
 6      managed costs well in ]ight of external cost increases
 7
 8      WHAT ARE YOUR RECOiXh’vIENDATIONS IN THIS PROCEEDING?

 9      I recommend that the Commission approve our request of $i61 million for
10      Energy Supply O&M for additional capital expenditures and $2.2 million in
11      amortized expenditures.
12
13 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
14 A. Yes.




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                                                     Docket No. E002/GR-08-1065
                                                    Exhibit____(PKG-1) Schedule 1
                                                                      Page 1 of 5



                                  RESUME

                             Pamela K. Graika
                             250 Marquette Plaza
                            Minneapolis MN 55102



Education
Bachelor of Science, Chemical Engineering, University of Minnesota,
December 1978


Professional Experience
1979 - present
                                Xcel Energy
                  (formerly Northern States Power Company)
                            Minneapolis, Minnesota

Twenty-nine years of varied experience at a large Midwestern utility. I started
out as a Plant Engineer and have been steadily promoted to positions of
increasing responsibility, now managing all Minnesota Company fossil and
RDF power plants.


2002 – Present
                             General Manager,
                         North Region Energy Supply
                              Minneapolis, MN

Manage 5 large coal and gas fired power plants and 3 smaller RDF plants, for a
total of 4,500 MW’s. O&M budget is $124 Million and Capital budget is $43
Million for 2008. Current staffing is 826 full time employees. Major focus this
past year has been leading efforts to optimize operations and maintenance at
aging units while preparing for conversion to newer technology associated with
$1 billion major capital projects:
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   • Life extension and environmental upgrades at 600 MW super-critical
     cyclone unit. Replaced all cyclones, new control system, dry scrubbers,
     baghouse and SCR. Startup July 2007.
   • Shutdown 265 MW coal fired plant and replaced with new 500 MW
     Combined cycle. Coal Plant shutdown September 2007. New combined
     cycle on line May 2008.
   • Repowering 366 MW coal fired plant to combined cycle in 2009.


Other major initiatives:

   • Serve on joint management committee of co-owned unit. Negotiate
     operational and financial issues.
   • Negotiated contract extension with 5 local unions that resulted in
     elimination of requirement to maintain minimum staffing numbers.
   • Significantly improved employee safety by focusing on management
     accountability and increasing employee involvement. OSHA rate in
     2002 was 6.71; in 2007 it was down to 4.48.
   • Initiated an effort to establish key policies for all of Energy Supply to
     ensure that all facilities utilize procedures for key operating and
     maintenance standards.


2000 – 2002
                General Manager, Peaking and Renewables
                        Xcel Energy, Energy Supply

After the merger, I was asked to head all of the Peaking, Hydro Plants, RDF
and Wind Energy Plants for Xcel Energy Supply, reporting to the President of
Energy Supply. I was responsible for 16 Combustion Turbine Sites, 25 Hydro
Plants, 3 RDF plants and a small wind farm with facilities in 5 states. Total
number of MW’s was 3,090.

    • Combined Hydro operations into one department to reduce overhead,
      increase focus on maintenance planning and provide engineering
      support to Colorado Hydro operations.
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    • Developed maintenance and operations plan for all 16 combustion
      turbine sites. Improved operations reliability of CT’s as demonstrated
      by increased overall startup percentage.
    • Negotiated contract extension with LaCrosse County for continued
      operation of the RDF facility, and LaCrosse County payment of $19M
      for environmental equipment required by the large municipal waste
      combustor rules. Negotiated with EPA, and Wisconsin DNR on
      resolution of permit violations.


1994 – 2002
                      Director, Environmental Affairs
                           NSP, Minneapolis MN

Managed the Environmental and Regulatory Affairs Department in Northern
States Power Company. I set environmental policy for the company, ensured
compliance with all permits and regulations and reported on compliance to the
officers and Board of Directors. Under my direction the department mapped
out all key processes and developed procedures. Several databases including an
audit database were developed to enable the company to better track and
monitor performance.


1990 – 1994
              Plant Manager, High Bridge Generating Plant
                           St Paul, Minnesota

Managed operations, maintenance, engineering for 260 MW coal fired power
plant and 2 boiler steam line operation.
   • Annual operating budget reduced from $15Million (1990) to $9Million
       (1993)
   • Increased unit availability above five year and industry averages.
   • Implemented self managed work team in yard operations.
   • Reduced staff from 155 to 125 full time personnel ( includes negotiating
       major operations reorganization with bargaining unit)
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   • Focused management team efforts on leadership, empowerment and
     culture change by utilizing the Seven Habits of Highly Effective People
     and other programs focused on trust and communication.


1988 – 1990
                         Plant Superintendent
                      Combustion Turbines and Hydro

Managed five gas turbine plants, one hydro plant and one wind farm.
  • Managed first major overhaul in ten years on nine gas turbine units.
  • Developed operating/maintenance plan for continued operation of
     aging units beyond expected unit retirement dates.
  • Managed first major overhaul in 35 years on hydro unit
  • Reduced staff at St Anthony Falls Hydro by 50 % after shut down of
     Lower Dam Plant.


1986 – 1988
                       Senior Production Engineer
                          Combustion and Hydro

Supervised engineering for small Regional Power Plants


1982 -1986
              Administrator Plant Permits and Compliance
                         Environmental Services

   • Responsible for corporate environmental permitting and compliance.


1980-1982
                      Asst. Environmental Engineer
                             Power Production
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Coordinated compliance permitting and compliance requirements for power
plants.


1979 - 1980
                        Asst. Production Engineer
                              High Bridge Plant
Engineered modifications at the plant to meet regulatory requirements and
improve unit performance.
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                                                          Exhibit___(PKG-1) Schedule 2
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                 NSPM Energy Supply Cost Improvements


Several improvements have been implemented in the NSPM business area to reduce
or control future O&M costs. These improvements are typically in three areas. They
include process improvements, technology improvement and capital investment.
Process improvements include changes in business and/or plant operating and
maintenance processes designed to reduce future costs. Technology improvements
involve the application of new technologies to reduce or control future costs. Capital
investments improvements include the strategic capital replacement of plant
components that are determined to be high cost drivers. With the age of many
generating facilities in the NSPM area, strategic capital component replacement often
results in lower future O&M cost associated with that component or system. The
following are examples of each category of improvement implemented since 2006 in
the NSPM area.


A.    Process Improvements To Control Costs

1.    Equipment Condition and Evaluation Process

      To ensure optimum plant system and component reliability, all NSPM
      generating plants have implemented a Plant Equipment Condition Assessment
      tool and Plant System Health Report process. The Plant Equipment Condition
      Assessment is used to characterize the current condition of plant systems and
      components and aid in prioritizing O&M and/or capital replacement. All plant
      systems and components critical to plant reliability and capacity are rated using
      a color-coding system. The rating is performed by plant engineering personnel

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                                                          Exhibit___(PKG-1) Schedule 2
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     and other experts to determine the appropriate timing and scope of
     maintenance. In addition, the each plant system/component is evaluated as part
     of the System Health Report process. Both the Plant Equipment Condition
     Assessment and System Health Reports are used as input to annual O&M and
     capital budget process and both have improved the plant’s ability to prioritize
     equipment maintenance to optimize plant equipment reliability.

2.   Project Evaluation and Prioritization Process

     A process improvement was implemented in 2008 to control future O&M
     project costs. O&M projects are associated with routine and/or infrequent
     equipment maintenance and repair. Coal Mill overhaul and coal conveyor belt
     replacement are examples of O&M projects. The process, implemented for the
     2009/2010 NSPM plant budgeting process involves the rigorous evaluation and
     prioritization of all project requests for the NSPM generating plants. As part of
     the process every project is evaluated and ranked on attributes such as safety,
     plant    reliability,   environmental     compliance       and     future    cost
     reduction/avoidance. Projects are then ranked based on those attributes and
     selected based on their ranking. This process has significantly improved the
     evaluation and selection of plant projects. It ensures that only value-added
     projects that associated with reliability and compliance are funded.


B.   Technology Improvements to Control Costs


1.   Riverside Generating Plant Temperature Monitoring to Avoid Generating
     Plant Loss of Capacity.


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     One example of a technology improvement is at the Riverside Generating
     Plant. At that facility a team worked to obtain more flexible permit
     requirements, install an in-river temperature monitoring system and developed
     a method to install temporary cooling towers. These improvements combined
     to generate about 50,000 megawatt hours in avoided derates and/or units off
     line during the continuing drought conditions in 2007. The avoided reduction
     in generation, typically during the hottest days of the summer, allowed Xcel
     Energy to mitigate increased customer costs by avoiding the purchase of costly
     replacement power. Replacement power that did not need to be purchased
     resulted in cost savings of about $4,100,000. Subtracting implementation costs
     of the initiatives ($1,800,000) resulted in a net savings of $2,300,000 in 2007.

2.   Black Dog Generating Plant Lake/River Temperature Forecast Model to Avoid
     Generating Plant Loss of Capacity

     During peak demand periods during the recent summers the Black Dog
     Generating Plant was able to stay on line and maintain discharge permit
     compliance to the river while meeting customer needs. The plant staff
     developed and implemented a “Lake/River Forecast Discharge Model” to help
     plant and Energy Marketing personnel manage the unit loading by forecasting
     the probability of exceeding the discharge permit temperature limits and
     adjusting plant load. Through the use of this model, the plant was able to stay
     on-line, meeting environmental permit requirements and NSPM customer
     needs and thereby avoiding high spot market pricing, for a cost savings of
     approximately $12,000,000 in 2006. This type of savings could be realized in
     future years.


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3.   Process Cost Analysis for High-Cost Plant Systems

     The Energy Supply business area has implemented a “Process Cost Analysis”
     process to evaluate high O&M cost systems and/or components with the goal
     of finding ways to learn best practices from our peers who are performing
     those same functions for less. The process includes the identification of plant
     systems that require the highest O&M cost to maintain reliability. Once
     identified, peer generating plants and industry best practices are reviewed to
     determine improvements to control future maintenance costs.

C.   Improvements to Control Labor Costs

1.   Peaking Generating Fleet Technology Improvements

     Modifications have been made that enable many of the NSPM peaking plants
     to be started and operated remotely, which will contain future labor costs in the
     peaking area. In addition, the Company and IBEW have negotiated “multi-
     skilled” union positions that perform both operations and maintenance
     functions. This multi-skill approach aids in maintaining low staffing levels at
     NSPM peaking generating facilities.


2.   Labor Changes at High Bridge and Riverside Generating Plants

     Along with the conversion of the High Bridge Coal Plant and Riverside Plant
     to combined cycle plants as part of the Metro Emission Reduction Project
     (MERP) changes were also made in facility staffing levels to contain future
     labor costs. Those changes, negotiated with the IBEW and implemented at

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     both facilities included significant reduction in the workforce required to
     operate and maintain the facility. In the case of High Bridge the plant staff was
     reduced from approximately 100 employees in 2006 to 40 employees at the end
     of 2008. In addition, through collective bargaining all plant operations and
     maintenance personnel are new “multi-skilled” which reduces the total number
     of staff required to operate and maintain the facility.


D.   Capital Improvements to Control Costs


1.   Sherco Unit 2 Boiler Bottom Replacement

     In the NSPM area several capital projects have been implemented to reduce or
     control future operating and maintenance costs. One example is the boiler
     couton bottom on the Sherco Unit #2 boiler. Historically the majority of boiler
     tube failures on Sherco Unit #2 occurred in the couton bottom of the boiler.
     Boiler tube failures require the unit to come off-line and affect repairs which
     typically take 2-4 days to complete. This results in lost generation, and resulting
     higher cost replacement energy to serve load and the direct cost of boiler tube
     repair. In 2006, a capital project was completed to replace the boiler bottom.
     Since its completion, the unit has experienced very few boiler tube failures in
     that section of the boiler resulting in lower repair costs and improved plant
     reliability and availability.




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                                                       Exhibit___(PKG-1) Schedule 2
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2.   Sherco Unit 2 Nox Reduction

     The federal Clean Air Interstate Rule (CAIR) was anticipated to be
     implemented in 2009. It called for the reduction of NOx generation annually
     in the United States.   Sherco Unit 2 was directed to reduce their NOx
     emissions from 0.18-0.20 lbs/mbtu to 0.15 lbs/mbtu to meet this federal rule.
     We reviewed the bids to complete this project and determined that we could
     significantly reduce cost by performing the reduction in-house. The assigned
     team accomplished this at a lower cost and met the schedule and NOx
     reduction requirements. Capital cost savings were approximately $1,500,000 in
     2006 and the same in 2007.




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