Source: http://www.docstoc.com/docs/121192633/Direct-Testimony-of-Randall-Falkenberg
Timestamp: 2014-04-24 05:05:11
Document Index: 35618981

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Direct Testimony of Randall Falkenberg
Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817
Witness: Randall J. Falkenberg
WASHINGTON UTILITIES AND                    )
TRANSPORTATION COMMISSION,                  )
Complainant,                 )
)          Docket No. UE-061546
PACIFICORP d/b/a PACIFIC POWER &amp;            )
LIGHT COMPANY                               )
In the Matter of the Petition of            )
PACIFIC POWER &amp; LIGHT COMPANY               )
)          Docket No. UE-060817
For an Accounting Order Approving Deferral )
of Certain Costs Related to the MidAmerican )
Energy Holdings Company Transition.         )
DIRECT TESTIMONY OF RANDALL J. FALKENBERG
PUBLIC COUNSEL AND
THE INDUSTRIAL CUSTOMERS OF NORTHWEST UTILITIES
1   Q.     PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2   A.     Randall J. Falkenberg, PMB 362, 8343 Roswell Road, Sandy Springs, GA 30350.
3   Q.     BY WHOM ARE YOU EMPLOYED?
4   A.     I am President of RFI Consulting, Inc. (“RFI”). I am appearing in this proceeding
5          as a witness for Public Counsel regarding interstate cost allocation and net power
6          cost issues, and for the Industrial Customers of Northwest Utilities (“ICNU”) on
7          these issues and the proposed Power Cost Adjustment Mechanism (“PCAM”).
8          My qualifications are shown in Exhibit No.___(RJF-2).
9   Q.     WHAT KIND OF CONSULTING SERVICES ARE PROVIDED BY RFI?
10   A.     RFI provides consulting services in the electric utility industry. The firm provides
11          expertise in electric restructuring, system planning, load forecasting, financial
12          analysis, cost of service, revenue requirements, rate design, and energy cost
13          recovery issues.
14                       I.      INTRODUCTION AND SUMMARY
15   Q.     WHAT IS THE PURPOSE OF THIS TESTIMONY?
16   A.     My testimony addresses PacifiCorp’s West Control Area (“WCA”) jurisdictional
17          cost allocation model and the GRID study of normalized net power costs for the
18          pro-forma period, April 2006 to March 2007. I identify numerous problems in the
19          WCA and GRID models that overstate the Company’s Washington revenue
20          requirement. I also address the proposed PCAM.
21   Q.     PLEASE SUMMARIZE YOUR TESTIMONY.
22   A.     I recommend a number of adjustments to the WCA model and to PacifiCorp’s test
23          year net power costs, resulting in a reduction to the Company’s Washington
24          allocated revenue requirements. Table 1, below, shows the dollar impact and
Randall J. Falkenberg Direct Testimony                           Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                  Page 1
1          approximate Washington allocation of each of my proposed adjustments. The
2          following is a brief summary of each proposed adjustment.
3                                  WCA Allocation Model
4          1. PacifiCorp’s WCA model is flawed because it fails to comply with the
5             Washington Utilities and Transportation Commission (“WUTC” or
6             “Commission”) used and useful standard. The model includes resources that
7             are not used and useful to Washington while ignoring resources that are used
8             and useful. Further, the model produces results that are demonstrably
9             unrealistic and unreasonable. For this reason, the model should be
10             substantially modified or simply rejected.
11          2. The WCA model ignores the fact that the Company has the option to buy and
12             sell power between PacifiCorp’s Area of Control West (“PACW”) and
13             PacifiCorp’s Area of Control East (“PACE”) and to arbitrage between trading
14             hubs. Leaving this capability out of the model substantially increases PACW
15             power costs and Washington revenue requirements by the amount shown on
16             Table 1.
17          3. The WCA model also ignores the fact that energy from former Pacific Power
18             and Light (“PP&amp;L”) resources in Wyoming (Johnson and Wyodak) flows into
19             the western control area via Jim Bridger. Consequently, these resources are
20             used and useful to Washington. At a minimum, the WCA model should
21             reflect the direct benefits of this energy flowing to PACW from the Johnson
22             and Wyodak resources in the WCA model. This (Part 1 Adjustment) reduces
23             Washington revenue requirements by the amount shown on Table 1.
24          4. In addition, the WCA model should be expanded to include all former PP&amp;L
25             (eastern Wyoming) loads and resources in the WCA model. This (Part 2
26             Adjustment) reduces Washington revenue requirements by the amount shown
27             on Table 1.
28          5. PacifiCorp proposes to use a Control Area Energy West allocation factor
29             (“CAEW”) for jurisdictional allocation of production and transmission
30             demand related costs in the WCA methodology rather than the traditional
31             Control Area Generation West (“CAGW”) factor. The Company has used the
32             CAGW type of demand allocation factor for all other jurisdictions and in
33             previous Washington cases. PacifiCorp provides no cost justification for the
34             change to the CAEW. It appears this change was simply an opportunistic
35             attempt to increase Washington revenue requirements. Use of PacifiCorp’s
36             traditional type of CAGW factor in the WCA model reduces Washington
37             revenue requirements in the amount shown on Table 1.
Randall J. Falkenberg Direct Testimony                        Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                               Page 2
1          6. PacifiCorp uses loss factors that overstate energy losses for Washington as
2             compared to other WCA states. This problem overstates the fixed costs
3             allocated to Washington, as well as the total WCA production costs. More
4             realistic loss factor assumptions (based on five years of actual data) results in
5             a reduction to revenue requirements in the amount shown on Table 1.
6                            Net Power Cost (GRID Adjustments)
7   Short-Term Firm Transaction Adjustments
8          1. The short-term firm transactions modeled in GRID show a disproportionate
9             number of below-market sales. The Company has not demonstrated these
10             transactions are prudent or necessary to provide service to Washington, and
11             they fail the Commission’s used and useful test. Removal of these
12             transactions results in a reduction to net power costs in the amount shown on
13             Table 1.
14   Long-Term Contract Adjustments
15          2. PacifiCorp imputes a price to the Sacramento Municipal Utility District
16             (“SMUD”) contract of $37/megawatthour (“MWh”) based on a previous
17             Southern California Edison (“SCE”) contract price. This treatment was first
18             used by the Utah Public Service Commission (“UPSC”) because it found the
19             SCE contract to be a prudent, contemporaneous contract that established a
20             benchmark price for SMUD. Because the SCE contract has expired it is no
21             longer an appropriate benchmark and the WUTC should develop its own
22             policies regarding this contract. I recommend the SMUD contract be removed
23             from GRID, reducing power costs by the amount shown on Table 1.
24          3. PacifiCorp failed to replace all of the capacity of the Centralia plant when the
25             resource was sold. The TransAlta contract replaces only 74% of the plant’s
26             energy. Because the Company retained 50% of the gain on the Centralia sale,
27             it should assume 50% of the risk associated with its failure to replace all of the
28             associated capacity and energy. This adjustment reduces net power costs by
29             the amount shown on Table 1
30          4. PacifiCorp overstates the likely generation from the Georgia-Pacific (“GP”)
31             Camas cogeneration facility compared to recent actual data and current trends.
32             Correcting this problem reduces net power costs as shown on Table 1.
33   Modeling Adjustments
34          5. PacifiCorp’s Vista modeling of 40 water years of data should be modified to
35             exclude water years resulting in power costs that are more than one standard
36             deviation from the mean. This treatment was proposed by the WUTC Staff in
37             Docket No. UE-032065 and accepted by the Company and Commission in
Randall J. Falkenberg Direct Testimony                            Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                   Page 3
1             that case. This adjustment reduces net power costs by the amount shown on
2             Table 1.
3          6. I recommend the Commission reverse the adjustments proposed by the
4             Company related to ramping, and the use of monthly outage rates. These
5             adjustments are not industry standard practices and are not well supported.
6             Reversing these assumptions reduces net power costs by the amount shown on
7             Table 1.
8          7. The Company proposes to increase its maximum PACW regulating margin
9             from 125 MW to 225 MW. This change in assumptions is unsupported and
10             unrealistic. Reversing this assumption change reduces net power costs as
11             shown on Table 1.
Randall J. Falkenberg Direct Testimony                       Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                              Page 4
1          Table 1 quantifies the impact on net power costs associated with implementing
2          each of my proposed adjustments.
Summary of Recommended Adjustments
Total         Washington
PACW         Jurisdiction
22.5244%
I. Jurisdictional Allocation Issues
WCA Model Corrections                                        N/A          -$23,482,877
1 Interconnection Benefits                   N/A           -$8,567,749
2 Johnson/Wyodak Part 1 (Actual Flow)        N/A           -$3,842,443
3 Johnson Wyodak Part 2 (Include E WY)       N/A           -$8,243,613
4 CAGW Allocation Factor                     N/A           -$2,192,439
5 Historical Loss Factors                    N/A             -$636,633
II. GRID (Net Power Cost Issues)
A. Short-Term Firm Adjustments                            -$35,235,790     -$7,936,636
6 Remove Short-term firm                   -$35,235,790     -$7,936,636
B. Long Term Contract Adjustments                         -$20,361,095     -$4,586,206
7 SMUD Contract                            -$12,299,225     -$2,770,322
8 TransAlta/Centralia Risk Sharing          -$7,924,453     -$1,784,932
9 GP Camus                                    -$137,417        -$30,952
B. Modeling Issues                                        -$10,003,260     -$2,253,170
10 Hydro Water Year Modeling                  -6,313,925     -$1,422,171
11 Monthly Outages                            -2,521,331       -$567,914
12 Ramping                                     -$322,172        -$72,567
13 Regulating Margin Modeling                  -$845,832       -$190,518
Total Power Cost Adjustments -                            -$65,600,145    -$14,776,013
PacifiCorp GRID Request                                  $417,037,230      $93,934,968
Adjusted GRID Result                                     $351,437,085      $79,158,955
Total Adjustments                                           N/A           -$38,258,890
3   Q.     HOW IS THE REMAINDER OF THIS TESTIMONY ORGANIZED?
4   A.     In Section II, I address the jurisdictional allocation (WCA model) issues. In
5          Section III, I address net power cost (GRID model) issues. In Section IV, I am
6          testifying on behalf of only ICNU and I address PacifiCorp’s proposed PCAM.
Randall J. Falkenberg Direct Testimony                         Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                Page 5
1                        II. JURISDICTIONAL ALLOCATION ISSUE
2   WCA Allocation Model
3   Q.     WHAT IS THE PURPOSE OF THE WCA ALLOCATION MODEL?
4   A.     The WCA model is PacifiCorp’s latest version of a jurisdictional allocation
5          methodology for Washington. Unlike previous iterations, this model will be
6          applicable only to Washington as other states have adopted the Revised Protocol
7          methodology, albeit with various modifications unique to each state.1/
8                   Since the merger between PP&amp;L and Utah Power and Light (“UP&amp;L”) in
9          1989, regulators have struggled to find an equitable means of allocating the costs
10          between the six states in which PacifiCorp operates. A jurisdictional allocation
11          methodology is needed to allocate both the fixed and variable production costs of
12          the PacifiCorp system to each of the states.
13                   There are really two elements to this problem: the disparity in costs
14          between the former PP&amp;L and UP&amp;L systems, and Washington’s statutory “used
15          and useful” requirement. The lack of a solution can be traced back to decisions
16          made by PP&amp;L and UP&amp;L at the time of the merger. The applicants were
17          anxious to gain approval of the merger and did not resolve this difficult issue
18          when approval of the merger was being sought. Rather, the Company offered to
19          convene a jurisdictional allocation committee with all of the involved states only
20          after approval of the merger was obtained.2/ As a result, there have been a series
21          of processes among the various states designed to address the issue, but even
The Revised Protocol may be only a shortlived solution in the states that have adopted versions of
it. PacifiCorp has already considered proposing significant changes to the Revised Protocol to
address what the Company calls divergent state energy policies related to new resource
Re PP&amp;L, WUTC Docket No. U-87-1338-AT, Second Supp. Order at 13 (July 15, 1988).
Randall J. Falkenberg Direct Testimony                                      Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                             Page 6
1          today, I do not believe there has ever been a true and permanent “meeting of the
2          minds” between the various states, and most certainly there has been no
3          agreement between the WUTC and the Company.
4   Q.     DISCUSS THE FIRST PROBLEM RELATED TO THE DISPARITY IN
5          COSTS BETWEEN PP&amp;L AND UP&amp;L.
6   A.     The WUTC has been quite concerned about the potential problems stemming
7          from this combination since the first order approving the merger:
8                       Staff witness Folsom correctly points out the discrepancy in
9                       average system cost between PP&amp;L and UP&amp;L. The Commission
10                       continues to be concerned about the effects on Pacific’s ratepayers
11                       of merging with a higher cost system, and believes that any
12                       integration of the power supply function for the two companies
13                       should be done in a manner consistent with Pacific’s least-cost
14                       planning process, now getting under way. In the meantime, the
15                       Commission views Pacific’s current average system costs as the
16                       appropriate basis for rates.3/
17                       From the above, it is well established that the differences in the
18          predecessor system costs was a concern of the WUTC from the start. While
19          western parties traditionally sought to retain the benefits of their lower cost
20          predecessor resources (particularly hydro and low-cost coal), the eastern parties
21          sought to “roll-in” all costs to a simple system average. While versions of the
22          Revised Protocol method is the current compromise on these issues adopted by
23          other states, Washington was unable to adopt this framework owing to its “used
24          and useful” standard.
25   Q.     PLEASE EXPLAIN.
26   A.     In Docket No. UE-050684, PacifiCorp proposed the Revised Protocol
27          methodology for Washington. However, the WUTC rejected the Company filing
Randall J. Falkenberg Direct Testimony                               Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                      Page 7
1          on the basis that it did not establish what resources were “used and useful” in
2          providing service to the state:
3                  PacifiCorp has failed to meet its burden of proof to show that the
4                  resources included in the Revised Protocol inter-jurisdictional cost
5                  allocation methodology provide tangible direct or indirect benefits
6                  to Washington ratepayers and are “used and useful for service in
7                  this state.” See RCW 80.04.250.4/
8                  Because the Revised Protocol method included all of the resources on the
9          system, and the Company failed to establish which of those resources were used
10          and useful in serving Washington, the WUTC rejected the Company’s proposed
11          2005 rate increase.
12                  It is against this backdrop that the Company developed its new WCA
13          model. The Company contends that this approach addresses the used and useful
14          standard by including only the costs of those resources located in the Company’s
15          WCA.
16   Q.     WHAT IS THE WCA?
17   A.     Please see the figure below.       This is a copy of the PacifiCorp transmission
18          topology map used in the Company’s GRID model.5/ This map breaks the system
19          down into PACE and PACW. Each control area contains a specific amount of
20          generation and load and is dispatched more or less independently of the other,
21          though there are some important benefits of integration. Washington is included
22          in PACW, or the WCA.
WUTC v. PacifiCorp, WUTC Docket No. UE-050684, Order No. 04 at &#182; 342 (Apr. 17, 2006).
Algorithm Guide GRID-U020-02-02 Draft v6.1.a, page 55
Docket Nos. UE-061546/UE-060817                                                      Page 8
265   w
Columbia                                                                           Walla
100                      Walla                                                                                                     281 s
**86                Goshen
H  LH                                                             Hot Springs
100 LLH
Jim                104*
BPA*                                                                                                                                            Path
Bridger                                                                            C(N)*
685-52 LLH
Path C(S)*
254 Firm +            cut plane
0 – 191                                  415                 Utah
IPC*                                  Day Ahead
West Main                                                                          transmission                                                                                         North
Utah                                                               &amp; Monsanto,
South                  435
HLH/LLH
and HLH/LL
48 59 s
328 - 514
38 30 s           6
4                                                           280
Varies by mo
4C             67 On-peak            Legend
15 0 s
25                                        $             100 Off-peak
Mona                                                                                                             - Load points***
Pinnacle Peak        350                     30                    - Resource
Notes:                                                                                                              PV                       350
Not a physical path/area – represents contract terms                                                                                                                                 Cholla                - FTR (MW)
**     Begins October 2006 with the expiration of Flathead Sale
$          350
***    Contracts may deliver in any of the transmission areas                                                                                                           350                                       As of 12 December 2005
2   Q.              DESCRIBE THE MAJOR ELEMENTS OF THE WCA MODEL.
3   A.              The WCA model includes only the PACW resources.                                                                                                              This would limit the
4                   thermal resources to the Bridger and Colstrip coal plants, Hermiston, and the
5                   PACW hydro. There are also various contracts and liquid trading hubs contained
6                   in PACW as well.
7                                                            The model includes both the fixed (return on investment, taxes,
8                   depreciation, etc.) and variable costs of power production for PACW. A special
9                   version of the GRID model provides the dispatch, and production simulation used
10                   to determine variable costs. While the model includes the cost for all of the
11                   transmission lines and contracts included in PACW, the Company assumes that
12                   there is no physical or contractual interconnection with PACE. The Company
Randall J. Falkenberg Direct Testimony                                                                                                                                  Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                                                                                                                         Page 9
1          completely ignores the fact that PACW resources provide benefits to the
2          integrated system, and would have opportunities to make profitable energy sales
3          in eastern markets. This is a significant omission that will be discussed in depth
4          later.   Effectively, the WCA model assumes the “world ends” at the
5          interconnection between PACW and PACE. While PacifiCorp has insisted for
6          years that it operates a fully integrated system, the Company now tries to
7          “unscramble the egg” within the WCA model, and treat PACW as a stand alone
8          system. In so doing, it grossly exaggerates the cost of serving PACW.
9   Q.     IS THIS “STAND ALONE” PACW SYSTEM REQUIRED BY THE
10          COMMISSION’S ORDER FROM DOCKET NO. UE-050684?
11   A.     No. Nothing in the Commission’s order requires or even suggests that only
12          PACW resources should be included in Washington’s cost structure. Instead, the
13          Commission articulated a “used and useful” standard that is the key determinant
14          of which resources should be considered. The Company provides regulatory
15          simplicity (by selectively modeling only a part of the system’s resources) while
16          ignoring the Commission’s longstanding requirement that the combination of the
17          high cost UP&amp;L system with the much lower cost PP&amp;L system should not harm
18          Washington ratepayers. I will show that the method completely fails to address
19          the Commission’s used and useful standard.
20   Q.     DOES THE WCA MODEL PROVIDE A REASONABLE AND REALISTIC
21          METHODOLOGY?
22   A.     No. The model is too simplistic and ignores many elements that exist in the real
23          world. For this reason, it substantially overstates costs for PACW, as I will now
24          demonstrate. Despite these significant problems, the WCA may provide a starting
Randall J. Falkenberg Direct Testimony                          Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                Page 10
1          point within which to develop an appropriate cost allocation methodology because
2          it assumes that the eastern resources are not used and useful in Washington.
3   WCA Model: PACW vs. PACE and GRID vs. Actual Cost
4   Q.     ELABORATE ON YOUR POINT REGARDING THE DISPARITY IN
5          COSTS BETWEEN PACW AND PACE IN THE WCA MODEL.
6   A.     Exhibit No.___(RJF-3) compares the net variable power costs of PACW and
7          PACE based on the WCA GRID model, and one of the most recent GRID studies
8          performed by the Company in Oregon. Intuitively one would expect that the west
9          would have lower power costs than the east, owing to the preponderance of low-
10          cost hydro and coal-fired generation, coupled with the lowest cost gas-fired
11          generation on the system. However, in the WCA model just the opposite occurs.
12          In the WCA model, PACW has an average cost of $20.6/MWh compared to
13          $12.7/MWh for the east.
14                 Some of the cost differences between PACE and PACW can be explained.
15          For example, the Company asserts that transmission costs for PACW are higher
16          than PACE because PACW relies more on contractual paths, rather than
17          ownership of assets. Further, there are gas resale revenues associated with PACE
18          resources, but not PACW resources. Finally, the Oregon GRID model included
19          certain credits for a settlement in the most recent rate case (UE 179). Even after
20          adjusting for all of these known differences, the WCA GRID model still shows
21          power costs almost 30% higher than the Oregon GRID model implies for PACE.
22                 These are unreasonable results, and certainly ones that fly in the face of
23          the longstanding expectation that, by virtue of its much lower cost resources,
Docket Nos. UE-061546/UE-060817                                                Page 11
1          PACW should enjoy lower variable power costs than PACE. The fact that the
2          WCA model produces this anomalous result leads one to question its veracity
3          from the very start. I find it hard to believe that the Commission would wish to
4          support a method that results in power costs some 62% higher for customers in
5          Washington than those in the eastern states. Certainly, there has never been any
6          evidence to support the notion that PACW, rather than PACE, was the “high cost”
7          system. This certainly runs counter to the general tone of the discussion in the
8          recently completed Multi-State Process (“MSP”), to say the least. In the end, I
9          suspect that the WCA GRID model has been contrived by the Company to
10          produce these spurious results. I will demonstrate later many ways in which the
11          model has been manipulated to produce unrealistic results.
12   Q.     HAVE YOU DEVELOPED A COMPARISON OF THE WCA GRID
13          MODEL TO PACIFICORP’S ACTUAL NET POWER COSTS?
14   A.     Yes. While PacifiCorp contends that it has not developed any analysis of actual
15          PACW costs, I have developed a reasonable approximation of actual PACW costs
16          from the Company’s monthly power cost reports.           Exhibit No.___(RJF-4)
17          compares the normalized actual PACW net variable power costs to the WCA
18          GRID model results. The actual results were developed from the response to
19          ICNU data request (“DR”) No. 1.27.6/ This analysis compares the actual costs for
20          the PACW resources included in the WCA GRID model. Because the PACW
21          resources provide more generation than required to serve PACW load, load and
22          supply were balanced using PacifiCorp’s projected average price for short-term
23          purchases. Because GRID balances load and supply at these (input) prices it
See Exh. No.___(RJF-12) at 6.
Docket Nos. UE-061546/UE-060817                                                Page 12
1          provides for a better comparison if the GRID prices are used. However, my
2          analysis indicates the results would not change significantly, if actual short-term
3          transactions prices were used instead. To make the results comparable to the
4          GRID results, I also used the projected test year loads and hydro generation,
5          GRID transmission costs, and re-priced the SMUD sale at $37/MWh, the price
6          used in the GRID model by the Company.7/ These results can be thought of as
7          “normalized actual costs” and are comparable to the figures used in GRID.
8                   The exhibit compares the GRID model results for varying time periods
9          including the 2006 fiscal year, the 12 months ended October 2006, and the most
10          recent 12-month period (December 2005 to November 2006). The results show
11          that the GRID model consistently overstates power costs for the WCA by $50
12          million or more compared to normalized actual costs. This illustrates that the
13          proposed WCA model is unrealistic from the very start and not suitable for use by
14          the Commission at this time. Exhibits No.___(RJF-3) and No.___(RJF-4) clearly
15          illustrate that the Company’s proposed net variable power cost model for PACW
16          is simply not credible as it implies substantially higher normalized costs for
17          PACW than PACE, as well as much higher costs than actual.
18   Used and Useful Standard
19   Q.     DOES THE WCA MODEL COMPLY WITH THE COMMISSION’S USED
20          AND USEFUL STANDARD?
21   A.     No. The Company assumes (in the absence of any proof) that nearly all PACW
22          resources are a priori used and useful to Washington, and are the only resources
23          on its system used and useful for Washington. Neither assumption is true.
Docket Nos. UE-061546/UE-060817                                                 Page 13
1                 In its Final Order in Docket No. UE-050684, the Commission never once
2          stated that it required the Company to produce a model whose costs were limited
3          to PACW resources. Rather, the Commission stated in numerous places that it
4          required resources “used and useful” to Washington be included in the model.
5   Q.     REVIEW THE COMMISSION’S USED AND USEFUL STANDARD.
6   A.     The Commission defined used and useful resources as those resources that were
7          useful in providing service to the state:
8                 In determining whether public utility property is “used and useful
9                 for service in this state,” the Commission considers whether a
10                 resource provides benefits to ratepayers in Washington either
11                 directly (e.g., the flow of power from a resource to customers)
12                 and/or indirectly (e.g., reduction of costs to Washington customers
13                 through exchange contracts or other quantifiable tangible or
14                 intangible benefits), commensurate with its cost.8/
15          PacifiCorp simply ignored this direction from the Commission, and in so doing
16          overlooked significant resources that benefit the west. In the end, the greatest
17          problem is that the Company has failed to reflect all of the resources that are used
18          and useful to Washington, while including other resources that are not used and
19          useful to Washington.       I will discuss this problem later in my testimony
20          concerning net power costs.
21   Q.     SUMMARIZE YOUR VIEWS ON THE WCA MODEL?
22   A.     The model fails to address the Commission’s longstanding concerns, and the
23          requirements stated in its order in Docket No. UE-050684. It is a shallow attempt
24          to court favor with the Commission by trading simplicity for higher cost to
25          customers. I recommend the Commission either substantially modify the model
26          or reject it out of hand, as it did with the Revised Protocol model in Docket No.
WUTC Docket No. UE-050684, Order No. 04 at &#182; 340.
Docket Nos. UE-061546/UE-060817                                                 Page 14
1          UE-050684. In that case, the Commission wisely chose to reject the Company’s
2          argument claiming it had an entitlement to use of a flawed jurisdictional model.
3          The Commission should not abandon its position in this case simply because the
4          Company has created the appearance of a more compliant model. As explained
5          by the Commission:
6                   The Company claims that it is entitled to full recovery of its
7                   prudently incurred costs systemwide and should not bear the risk
8                   that state decisions about cost recovery will not, in combination,
9                   ensure this entitlement. The Company points to no provision of
10                   law in support of this proposition. In fact, the Company created
11                   and accepted the risk that divergent allocation decisions among the
12                   states might result in under-recovery when it chose to merge 20
13                   years ago. Our order approving that merger read together with the
14                   merger order of the Oregon Commission make clear that this risk
15                   existed, that the Company was aware of it, and that the Company
16                   accepted that it alone would bear the risk:
18                             Pacific agrees, however, that its shareholders will
19                             assume all risks that may result from less than full
20                             system cost recovery if interdivisional allocation
21                             methods differ among the merged company’s
22                             jurisdictions.
24                   Further, the Company admits in the Revised Protocol that it bears
25                   the risk of inconsistent allocation methods adopted by the states.
26                   In short, any claim of entitlement to a uniform allocation
27                   methodology among the states is inconsistent with the “deal” the
28                   Company agreed to in the merger.9/
30                   As in Docket No. UE-050684, the Commission could reject the Company
31          filing, and refuse to grant the requested rate increase. However, for reasons that
32          will be discussed shortly, this may actually be an overly generous treatment for
33          the Company because even the most obvious corrections to the WCA and GRID
34          models support a reduction in rates for the Company.
Id. at &#182; 56 (internal footnotes omitted).
Randall J. Falkenberg Direct Testimony                              Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                    Page 15
1   Corrections to the WCA Model
2   Q.     ASSUMING THE COMMISSION DESIRES TO CORRECT, RATHER
3          THAN REJECT THE WCA MODEL, WHAT CORRECTIONS DO YOU
4          RECOMMEND?
5   A.     The most fundamental problem with the WCA model is that it is too simplistic in
6          assuming that PACW resources would have no connection to the eastern side of
7          the system and that only PACW resources are used and useful for Washington. It
8          ignores the Commission’s fundamental test for whether a resource is used and
9          useful. That test is stated in terms of a cost-benefit analysis:
10                   The Company’s reliance on this citation is misplaced and
11                   overlooks the Commission’s fundamental premise—facilities must
12                   serve and be found to provide quantifiable benefits before costs
13                   can be allocated to ratepayers. Recognizing the need for
14                   allocation is not the same as determining how the allocation should
15                   be made.10/
16                                                    ***
17                   We find, however, that the Company must demonstrate tangible
18                   and quantifiable benefits to Washington of resources in the system
19                   before we will include the resources in rates. The test for including
20                   a resource in rates is not whether it is “needed, deliverable and
21                   least cost” but rather whether it provides quantifiable direct or
22                   indirect benefits to Washington commensurate with its cost.11/
23                   In developing its WCA model based solely on PACW resources without
24          interconnections, the Company has completely ignored every aspect of these tests.
25          The Company has not produced any evidence that the resources it includes
26          provide direct or indirect benefits to Washington commensurate with cost. Nor
27          has the Company performed any test of resources outside of PACW to see if they
28          provide benefits that are commensurate with cost. As a result, the Company has
Id. at &#182; 58 (emphasis added).
Id. at &#182; 68 (internal footnotes omitted, emphasis added).
Docket Nos. UE-061546/UE-060817                                                    Page 16
1          skewed the model against Washington ratepayers by ignoring some of the most
2          obvious resource choices, specifically the PACW-PACE interconnection and the
3          Dave Johnson and Wyodak coal plants. These facilities should be reflected in the
4          WCA model. I will discuss both of these topics next.
5   Benefits of Interconnections
6   Q.     ARE PACW AND PACE INTERCONNECTED?
7   A.     Yes. The Transmission Topology Map shown above demonstrates that the two
8          systems are interconnected, and are fully capable of moving power across the
9          system. In the normal operation of the system, PACW provides benefits to the
10          east by providing low-cost energy, and provides operating reserve (“dynamic
11          overlay”) benefits. This reduces the overall cost of system operation. In prior
12          cases, the Company estimated the benefits of system integration to be more than
13          $200-300 million NPV for the period 2005 to 2018.12/ Under the proposed WCA
14          model, all of the benefits of system integration would inure to the states that have
15          adopted the Revised Protocol methodology, and Washington would receive none
16          of these benefits. This is hardly an equitable allocation of benefits, considering
17          Washington will be assigned costs of various resources (generating units and
18          transmission costs) that enable these benefits to be produced. The proposed WCA
19          model is also inconsistent with how PacifiCorp built and actually operates its
20          system.
Re PacifiCorp, Oregon Public Utility Commission (“OPUC”) Docket No. UM 1050, Exhibit
ICNU/200 at 7 (Aug. 6, 2004).
Docket Nos. UE-061546/UE-060817                                                 Page 17
1   Q.     IS THIS A REASONABLE TREATMENT?
2   A.     No. The system operates in a manner that minimizes total cost. Even if there was
3          no joint ownership of the PACW and PACE resources, the interconnections
4          would still exist. Indeed, the Company has included all of the costs of PACW
5          transmission equipment and contracts in the WCA model. If the transmission
6          costs are included, the opportunity to use those assets for the maximum benefit of
7          the customers should also be considered. Unfortunately, in the WCA model, the
8          Company includes only the costs, while ignoring some of the most important
9          benefits of the PACW–PACE interconnections.          This is an extremely odd
10          treatment in the model considering how the Company modeled the California-
11          Oregon-Border (“COB”) interconnection.
12   Q.     PLEASE EXPLAIN.
13   A.     In the WCA model, the Company recognizes COB as a liquid trading hub. Thus,
14          the costs of the interconnection are included, and the model buys and sells power
15          as appropriate to minimize cost.      However, when it comes to the PACE
16          interconnection, the Company completely ignores that it exists at all. It makes no
17          sense to include COB, while ignoring PACE as a potential market for surplus
18          PACW generation. Yet this is exactly what the Company has done in the WCA
19          model.
20   Q.     DISCUSS THE PATHS USED TO DELIVER POWER FROM PACW TO
21          PACE.
22   A.     As shown on the transmission topology map above, power may flow from PACW
23          to PACE by a variety of routes. For example, it could flow from Bridger to IPC
24          to Utah North, or from Bridger to Wyoming to Utah, or from Colstrip to Goshen
Docket Nos. UE-061546/UE-060817                                                Page 18
1          to Utah. These routes provide the opportunity for generation surplus to PACW
2          needs to be sold in PACE. There would also be the opportunity for arbitrage
3          between western markets (e.g., Mid-Columbia (“Mid-C”) or COB) and the
4          eastern market hubs (Palo Verde, SP15, and 4 Corners.)
5   Q.     EXPLAIN HOW THIS ARBITRAGE MIGHT WORK.
6   A.     In a situation where Mid-C has a lower market price than Palo Verde, for
7          example, the Company might purchase low cost generation from Mid-C, and,
8          allow some of it to be delivered to the east rather than delivering power from
9          Bridger to the west. In the east, generation that might have been used to serve
10          Utah loads, could then be used to sell into the Palo Verde market. While specific
11          transactions may or may not operate in precisely this manner, the Company has at
12          least five major market hubs, and can use the limited transmission and its
13          generation resources to perform a wide variety of transactions.13/
14   Q.     WOULD IT ACTUALLY BE NECESSARY TO ASSUME PACW POWER
15          WAS ACTUALLY SOLD DIRECTLY TO THE PACE MARKET HUBS?
16   A.     No. Power could simply be delivered from PACW to PACE. Because the three
17          hubs interconnected with PACE (Palo Verde, 4 Corners and SP 15) are all liquid
18          markets, they would influence (if not set) the market price for deliveries to PACE.
19          If the GRID model was set to allow PACW to sell power to PACE, similar to the
20          way PACW sells to COB, the GRID model could allow PACW to make sales at a
Such transactions fit directly into the Commission’s used and useful requirement that considers
whether a resource provides benefits to ratepayers in Washington either directly (e.g., the flow of
power from a resource to customers) and/or indirectly (e.g., reduction of costs to Washington
customers through exchange contracts or other quantifiable tangible or intangible benefits),
commensurate with its cost.
Docket Nos. UE-061546/UE-060817                                                            Page 19
1          price comparable to the prices at the Palo Verde, SP 15 and 4 Corners hubs,
2          subject to applicable transmission constraints.
3   Q.     DOES THE COMPANY NORMALLY MODEL SUCH OPPORTUNITIES
4          IN ITS FULL (PACW+PACE) GRID MODEL?
5   A.     Yes. In the recently completed Oregon general rate case, Mr. Widmer testified as
6          follows:
7                  Consistent with normalized ratemaking these values are captured
8                  on a deterministic basis by GRID. The system dispatch portion of
9                  the model is a linear program that optimizes the company&#39;s system
10                  based upon market prices, load requirements, resource
11                  characteristics, transmission availability including monetization of
12                  available transmission by buying energy in a lower priced market
13                  hub and reselling the energy in higher priced market hub and
14                  curtailing generation when lower cost market purchases are
15                  available.14/
16   Q.     DOES THIS OMISSION HAVE A SUBSTANTIAL IMPACT ON THE
17          COST OF POWER IN THE WCA MODEL?
18   A.     Yes. Based on the data contained in the WCA model, market prices in PACE
19          exceed those in PACW thousands of hours during the test year.                    In such
20          situations, the opportunity would exist for the Company to sell a limited amount
21          of surplus PACW generation to PACE. Though it happens less frequently, in
22          some cases, prices in PACE are lower than PACW prices. In such case, the
23          Company could purchase in the east and offset purchases in the west.
24   Q.     ARE THERE ANY OTHER IMPLICATIONS OF THIS?
25   A.     Yes. The Company excluded some of the Jim Bridger capacity in the WCA
26          model because a fraction of the Bridger generation is delivered to PACE. As a
27          result, the Company excludes 5% of the Bridger capacity from the model. This,
28          however, is not a reasonable basis for excluding Bridger’s cost and generation.
Re PacifiCorp, OPUC Docket No. UE 179, Exhibit PPL/506 at 5 (Widmer Rebuttal).
Randall J. Falkenberg Direct Testimony                                Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                      Page 20
1          As shown above, Bridger could deliver power to PACE, and it may be doing so,
2          simply to provide generation to that market when prices make such a transaction
3          favorable. It does not imply that 5% of Bridger’s capacity should be ignored
4          completely and assigned to the east. Rather, this is just another example of a
5          benefit of PACW resources not considered in the WCA model.
6   Q.     HAVE YOU QUANTIFIED THE IMPACT OF EXCLUDING THE
7          INTERCONNECTION BENEFITS FROM THE WCA MODEL?
8   A.     Yes. In Exhibit No.___(RJF-5) I present an analysis of the bias built into the
9          WCA model because it ignores the actual interconnections to PACE. This was
10          computed in two parts. First, I included the benefit of transactions not modeled in
11          the WCA GRID model that should have been included. Second, I reflect the
12          value of the reserve capacity PACW provides PACE for purposes of regulating
13          margin and quick start reserves. This approach is rather conservative because it
14          ignores more than $1 million in direct benefits that would result from full
15          inclusion of 100% of the Jim Bridger capacity in the WCA model.
16   Q.     HOW DID YOU ESTIMATE THE BENEFITS OF THE PACW-PACE
17          TRANSACTIONS EXCLUDED BY THE COMPANY?
18   A.     I compared the market price curves for Mid-C, to Palo Verde, SP15 and 4
19          Corners. When western prices were lower than eastern prices, and the Company
20          had generation to sell I modeled a sale transaction between west and east.
21          Because GRID already included the benefits of making such sales in the west, I
22          reflected only the added margin from the sale. I limited such sales to the transfer
23          capacities (to 415 MW based on Path C to Utah) shown on the transmission
Docket Nos. UE-061546/UE-060817                                                 Page 21
1          topology figure above. In other words, I limited my adjustments based on the real
2          world operational constraints of PacifiCorp’s system.
3                  In situations where PACE market prices were lower than PACW prices, I
4          modeled purchases. In this case, however, purchase transactions were limited to
5          only 104 MW, as shown on the transmission topology map above.
6                  This analysis identified potential savings for PACW customers from such
7          transactions of $5.7 million. This result is quite reasonable because the amount of
8          generation flowing from west to east in my model was less than the amount
9          shown by the Company in its recent GRID studies filed in Oregon as part of UE
10          179. It is important to make clear that in calculating my estimate of the benefits
11          associated with system integration, I focused on the only actual transmission
12          capabilities between the PACW and PACE.
13                  For the dynamic overlay benefits I used estimates derived by the Company
14          as part of its MSP process.15/
15   Wyodak and Johnson
16   Q.     WAS   THE   FAILURE   TO    MODEL    THE   PACW-PACE
17          INTERCONNECTIONS THE ONLY PROBLEM IN THE WCA MODEL?
18   A.     No. The Company also ignored the fact that the Wyoming resources, Dave
19          Johnson and Wyodak are used and useful for Washington.
20   Q.     EXPLAIN WHY JOHNSON AND WYODAK ARE USED AND USEFUL.
21   A.     These resources are obvious possibilities that the Company should have included.
22          First, Johnson and Wyodak were part of the pre-merger PP&amp;L system, and as
23          such, have had their costs included in Washington ratebase ever since they were
WUTC Docket No. UE-032065, Exh. No. 406C at 35-41 (PacifiCorp’s Response to OPUC Staff
DR No. 61 in OPUC Docket No. UM 1050).
Docket Nos. UE-061546/UE-060817                                                    Page 22
1          first installed. To my knowledge there has never been any order issued by the
2          WUTC specifically questioning whether these plants were used and useful. As
3          noted earlier, the Commission’s starting point in analysis of the cost structure for
4          Washington has always been the costs of the pre-merger PP&amp;L system.
5          Excluding these resources from Washington requires substantial justification by
6          the Company.
7                  Second, in all of the most recent Washington rate cases (UE-991832, UE-
8          032065, and UE-050684), the Company included these plants in ratebase and
9          sought recovery from retail consumers for their costs. There is no basis for
10          assuming that these facilities have not been included in Washington rates, or that
11          they were ever viewed as being anything but “used and useful.”
12                  Third, power from these resources is being delivered to PACW, based on
13          PacifiCorp’s various GRID studies, as filed in prior cases in Washington and
14          Oregon. I will elaborate on this point later. Even though the Commission does
15          not solely base its used and useful determination on the deliverability of power,
16          this is a pertinent point.16/ Exhibit No.___(RJF-6) shows results of PacifiCorp’s
17          GRID study developed for Docket UE-050684, illustrating that power from
18          Wyoming (Johnson and Wyodak) is indeed being delivered to Bridger, which is
19          located in PACW. This power in turn can be delivered from Bridger to any point
20          in the west, including Washington.
Indeed, as discussed earlier, the Commission considers whether a resource provides benefits to
ratepayers in Washington either directly (e.g., the flow of power from a resource to customers)
and/or indirectly (e.g., reduction of costs to Washington customers through exchange contracts or
other quantifiable tangible or intangible benefits), commensurate with its cost.
Randall J. Falkenberg Direct Testimony                                    Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                          Page 23
1                 Finally, these resources pass the Commission’s cost benefit test in that
2          they directly or indirectly provide benefits to Washington and their costs are more
3          than commensurate with the benefits provided. Indeed, the Johnson and Wyodak
4          plants are among the lowest cost resources on the system, and it appears the
5          Company simply excluded these facilities to penalize Washington for not
6          accepting the Revised Protocol method. I recommend a two-part adjustment
7          designed to deal with this problem.
8   Q.     PLEASE EXPLAIN PART 1.
9   A.     Exhibit No.___(RJF-7) shows my calculations. The first part of my proposed
10          adjustment would simply include the benefits of the energy already being
11          delivered from Johnson and Wyodak to Jim Bridger in the WCA model. This is
12          the minimum adjustment the Commission should consider. This amounts to
13          approximately 97 MW during the light load hours (“LLH”).             Because this
14          capacity is not available during on-peak hours, the associated fixed costs should
15          not be included in the capacity cost component of the WCA. Including the
16          Johnson and Wyodak generation during LLH would reduce PACW power costs
17          by $3.8 million, as shown in Exhibit No.___(RJF-7) and Table 1.
18   Q.     EXPLAIN PART 2 OF YOUR ADJUSTMENT.
19   A.     By ignoring the pre-merger PP&amp;L system, and instead limiting resources included
20          in the WCA model to PACW resources, the Company excluded these two very
21          low-cost plants.    Overall, these plants average cost per kWh produced is
22          approximately $21/MWh. This is nearly the same as the average cost of the
23          Colstrip and Bridger plants, which the Company included in the WCA model.
Docket Nos. UE-061546/UE-060817                                                 Page 24
1          Owing to their low cost, previous history of inclusion in rates, and deliverability
2          of power, there is no reason not to believe that the Wyodak and Johnson units are
3          used and useful for Washington.
4                  However, if the pre-merger PP&amp;L Wyoming plants are included in the
5          WCA model, then so should the eastern Wyoming (former PP&amp;L) loads served
6          by these plants. Once the Wyoming loads are included, the average variable
7          power costs for the former PP&amp;L system is reduced by $2.65/MWh from the level
8          the Company computed for PACW. Washington’s share of these savings (over
9          and above the savings in Part 1) is $8.2 million, and is shown on Table 1.
10   Q.     DO YOU NEED TO MAKE ANY ADJUSTMENTS TO THE FIXED COST
11          COMPONENTS OF THE WCA MODEL TO REFLECT THE INCLUSION
12          OF THESE TWO PLANTS?
13   A.     Ideally, one would. However, the average fixed cost per kWh for Johnson and
14          Wyodak is quite close to the level already built into the WCA for Bridger and
15          Colstrip, and is substantially lower than the average embedded cost for all PACW
16          resources.17/ As a result, it is likely that including the fixed costs in a more
17          encompassing model would further reduce the average cost for WCA resources,
18          producing a larger adjustment.
19   Q.     CAN ALL OF THE POWER GENERATED BY THE WYOMING UNITS
20          BE DELIVERED TO PACW?
21   A.     No. Transmission constraints limit deliverability (see the Transmission Topology
22          Map), although as shown in Exhibit No.___(RJF-6), substantial amounts of power
23          from Johnson and Wyodak are delivered to PACW. However, as discussed
24          above, the Commission does not rely solely on deliverability in its used and useful
I estimate this to be in excess of $40/MWh.
Docket Nos. UE-061546/UE-060817                                                 Page 25
1          test. By averaging in the eastern Wyoming loads and resources, the issue of
2          deliverability is not a problem.
3   Other PACE Resources
4   Q.     HAVE YOU CONSIDERED INCLUSION OF                                        OTHER   PACE
5          RESOURCES IN THE JURISIDICTIONAL MODEL?
6   A.     Yes. In my testimony in Docket No. UE-050684, I analyzed the deliverability of
7          power from other PACE resources.              The results showed that other PACE
8          resources were very unlikely to deliver any significant amount of power to
9          PACW. Similar GRID runs from recent cases appear to confirm this conclusion.
10          Therefore, I do not propose that other PACE resources be included in Washington
11          rates.
12   Jurisdictional Allocation Factor
13   Q.     ARE THERE OTHER PROBLEMS WITH THE WCA MODEL?
14   A.     Yes. In the model, the fixed costs of production plants (generally referred to as
15          demand-related costs) are allocated to jurisdictions on the basis of the Control
16          Area Energy West (“CAEW”) allocation factor. Traditionally, the Company has
17          used a Control Area Generation West (“CAGW”) (75% demand (coincident peak)
18          and 25% energy) weighting as the basis for allocation of production demand
19          costs. This is the allocation method built into the Revised Protocol method and to
20          my knowledge has been used by the Company in all recent cases in Washington
21          and other states. The Company does not justify the use of the CAEW on the basis
22          of cost causation, but rather on the basis of simplicity.18/ Because Washington has
23          a higher load factor than other states, this approach results in higher costs being
Exh. No.___(RJF-12) at 7 (PacifiCorp’s Response to ICNU DR No. 1.39).
Randall J. Falkenberg Direct Testimony                                 Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                       Page 26
1          allocated to the state. The Company’s use of the CAEW method is not cost
2          justified, and appears to simply be an opportunistic approach designed to increase
3          Washington revenue requirements.           I recommend the Commission reject the
4          CAEW allocation factor and return to the traditional 75/25 demand/energy
5          jurisdictional allocation factor.
6   Loss Factors
7   Q.     DO YOU AGREE WITH THE LOSS FACTORS USED BY THE
8          COMPANY IN THE WCA MODEL?
9   A.     No. Based on the data provided the by Company,19/ the forecasted losses used in
10          the WCA and GRID models is 10.95%. However, historical losses for the most
11          five recent fiscal years were only 10.107%.             Because the test year revenue
12          requirements should reflect normalized load levels, they should also reflect
13          normalized losses. Because the loss factors for Washington are overstated in both
14          the WCA model and in GRID, the allocation of costs to Washington is overstated.
15          Further, the net power costs on a PACW basis are also overstated because losses
16          for all three states included in the model are overstated as well.               Based on
17          PacifiCorp’s 1st Supplemental Response to ICNU DR No. 2.6, using the historical
18          loss factors reduces revenue requirements by the amount shown on Table 1.20/ I
19          recommend the Commission adopt this loss level if it adopts the WCA method.
See Exh. No.___(RJF-12) at 1-5 (PacifiCorp’s Response to ICNU DR No. 1.6).
See Exh. No.___(RJF-12) at 9-12 (PacifiCorp’s 1st Supp. Response to ICNU DR No. 2.6).
Randall J. Falkenberg Direct Testimony                                  Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                        Page 27
1   PACE Regulation/Reserve Modeling Adjustments
2   Q.     DOES THE WCA MODEL EXCLUDE ALL OF THE COST RELATED
3          TO SERVING PACE?
4   A.     No, it appears there is an error in the GRID model which requires PACW to
5          provide regulating margins for PACE. This is the current operational practice
6          used by the Company, and has been modeled in GRID for many years. The
7          Company included PACE regulating margins in the WCA version of GRID.
8          Logically, the model should include both the cost and revenues associated with
9          providing this service. Because I am including the dynamic overlay benefits,
10          discussed above, I do not recommend that the Commission remove the costs of
11          providing operating reserves to PACE in the model.
12                            III.    NET POWER COST ISSUES
13   Q.     WHAT ARE “NET POWER COSTS” AND WHY ARE                                        THEY
14          IMPORTANT TO THIS PROCEEDING?
15   A.     Net power costs are the variable production costs related to fuel and purchased
16          power expenses, net of power sales revenue.           Net power costs comprise a
17          substantial portion of the overall revenue requirement and therefore are a
18          significant component of PacifiCorp’s proposed base rates.
19   Q.     PLEASE DISTINGQUISH BETWEEN NET POWER COST ISSUES AND
20          ISSUES RELATED TO THE WCA MODEL.
21   A.     The WCA model issues discussed above relate to the allocation of production
22          costs (both fixed and variable) within the PacifiCorp system. The issues do not
23          necessarily impact the total system level of costs, but rather the allocation of those
24          costs to the Washington jurisdiction. In contrast, net power cost issues arise from
25          modeling assumptions, input data, or logic in the GRID model that would exist
Randall J. Falkenberg Direct Testimony                             Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                   Page 28
1          irrespective of the jurisdictional allocation method used.21/ Thus, these issues
2          affect the overall level of variable system costs, and to the extent they are
3          changed, Washington’s overall allocated costs would change as well.
4                               Short-Term Transaction Modeling
5   Q.     DESCRIBE THE SHORT-TERM TRANSACTIONS MODELED IN GRID.
6   A.     There are two types of short-term transactions modeled in GRID. Short-term firm
7          (“STF”) transactions are firm purchased sales contracts with a term less than one
8          year. GRID does not forecast or simulate such transactions. They are just a fixed
9          input with pre-determined energy volumes and prices.22/
10                  Secondary balancing transactions (hour-to-hour trades) are simulated in
11          GRID. The model either sells or purchases this product at prices based on the
12          input market forward price curve as needed to balance the system.
13   Q.     DO YOU AGREE WITH THE STF MODELING METHODOLOGY?
14   A.     No.    There are some serious problems with PacifiCorp’s GRID modeling
15          approach. First, the Company included only the trades that it had arranged as of
16          the time it filed its case in October 2006. By itself, this is quite problematic
17          because many additional transactions will be arranged after the filing date and
18          during the test year. Even if the Company performed an update of the GRID
19          study, many short-term firm trades will occur during the FY 2007 test year, days
20          or only hours ahead of their actual delivery. Because the Company attempts to
21          minimize its costs, it will naturally attempt to make profits on short-term trades
However, the impact of such issues on Washington could vary significantly, depending on the
allocation method used.
The model accounts for such transactions rather than simulate them. No matter what else changes
in the model, the short-term firm transactions will remain constant in GRID.
Randall J. Falkenberg Direct Testimony                                   Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                         Page 29
1          wherever possible and reduce costs by achieving a better system balance. As a
2          result, the volumes of short-term firm transactions will be understated in GRID,
3          and net power costs will likely be overstated. Second, the Company has not
4          demonstrated these short-term firm transactions are needed to serve Washington,
5          or produce benefits commensurate with their costs. Because many of the sales
6          transactions modeled are below market (and because there is a preponderance of
7          sales compared to purchases) these transactions are demonstrably detrimental to
8          Washington ratepayers.
9   Q.     ARE YOU ABLE TO DEMONSTRATE THIS USING GRID?
10   A.     Yes.   I performed GRID runs where all short-term firm transactions were
11          removed from the model. This study resulted in a substantial reduction to net
12          power costs. As a result, it is clear that the short-term firm transactions included
13          by the Company in the model failed to provide benefits commensurate with cost
14          to Washington ratepayers. This being the case, the Commission should disallow
15          recovery of these costs.
16   Q.     ARE THERE OTHER REASONS THE COMMISSION SHOULD MAKE
17          THIS DISALLOWANCE?
18   A.     Yes. First, we are left with an obvious question of prudence. It is quite difficult
19          to understand why the Company would end up in such an unfavorable position
20          vis-&#224;-vis the market for its short-term firm sales. It appears the Company made
21          transactions well in advance of the time necessary, with the net effect being to
22          place the Company in a position of betting on a decline in market prices, which
23          never materialized.
Docket Nos. UE-061546/UE-060817                                                 Page 30
1                   Second, while it is possible that the Company may be able to make
2          profitable trades in the future to offset the additional costs of the below-market
3          sales, it will not be possible to reflect all of the short-term firm transactions in the
4          test year because trades that actually take place in the rate effective period will not
5          be reflected in the model, even if an update is performed. This means that the
6          additional benefits of a better balancing of the system and the numerous profit
7          opportunities that the Company’s traders will strive to exploit in the months ahead
8          will not be reflected in rates.          Consequently, the test year is biased against
9          ratepayers.23/
10                   Third, for purposes of establishing permanent, normalized rates, it is
11          unrealistic to assume that unanticipated market fluctuations will always work
12          against the Company. In normal conditions, the Company will likely make as
13          many (if not more) above-market sales as it does below-market ones. Likewise,
14          under normal conditions, the Company will make as many below-market
15          purchases as it does above-market purchases. Over time, the forward price curves
16          will move in various directions, and the Company will likely find as many
17          circumstances where it is above market as below. This being the case, it is
18          unrealistic to assume that normalized rates should reflect a preponderance of
19          below-market transactions.
Under some types of PCAMs, it is possible that the Company could address this problem.
However, it is not clear that the Company proposes to include its actual short-term transactions in
its PCAM, nor would it be desirable to so, unless there is a way to test whether the Company’s
actual short-term transactions are used and useful.
Docket Nos. UE-061546/UE-060817                                                            Page 31
1   Q.     COULD PACIFICORP’S PROPOSED PCAM ADDRESS THIS ISSUE?
2   A.     I will discuss the PCAM in more detail later. However, the proposed PCAM
3          would not provide an equitable solution for two reasons.          First, it is not
4          completely clear whether or how the Company proposes to incorporate all actual
5          STF transactions in its update process. Mr. Widmer’s testimony is rather vague
6          on this point.24/ Second, assuming the Company is able to reduce cost by a more
7          refined balancing of the system, the deadband and sharing mechanism would
8          allocate some of the benefits to the Company, everything else being equal.
9   Q.     HOW DO YOU PROPOSE THE COMMISSION ADDRESS THIS ISSUE?
10   A.     I recommend that the Commission remove all short-term firm transactions from
11          GRID.     From a modeling perspective, this will result in secondary balancing
12          transactions taking the place of short-term firm purchases and sales in GRID.
13          This will price 100% of system balancing requirements at the forward curve price
14          used in the model. While the Company might argue that this is unrealistic, in fact,
15          under the Company modeling, much of the system’s balancing requirements are
16          already priced based on the forward curve (via the modeling of secondary
17          balancing transactions) because the balancing transaction volumes in the model
18          are well above historical levels. Table 1 shows the impact of this adjustment.
19                          Long-Term Contract Modeling In GRID
20   Q.     DOES GRID MODEL LONG-TERM POWER CONTRACTS?
21   A.     Yes. The Company includes the costs and energy produced by all of its long-term
22          contracts in GRID, along with its thermal generation resources in order to project
Exh. No.___(MTW-1T) at 30.
Docket Nos. UE-061546/UE-060817                                                 Page 32
1          normalized net power costs. I will discuss issues related to PacifiCorp’s long-
2          term contracts in the following sections of my testimony.
3   Sacramento Municipal Utility District (“SMUD”) Contract
4   Q.     DISCUSS THE           CIRCUMSTANCES            UNDERLYING           THE      SMUD
5          CONTRACT.
6   A.     This is a 30-year contract with a price that is far below market. This issue has
7          never been decided by the WUTC, because prior Washington cases were either
8          settled or the overall requested rate increase was rejected. Ironically, the history
9          of the Company’s proposed treatment of this contract in prior Washington cases
10          was based on prior decisions made by the UPSC, not the WUTC.
11                 In 2001, the UPSC required a revenue imputation for PacifiCorp’s
12          contract with SMUD on the basis that the prices in the SMUD contract were
13          unreasonably low.     In its Final Order in Docket No. 01-035-01, the UPSC
14          summarized the history of this issue:
15                 As in the immediately preceding general rate case for this
16                 Company, Docket No. 99-035-10, this Commission is asked to
17                 impute revenues to a 1987 long-term firm wholesale contract with
18                 SMUD to counter the contract’s adverse impact on the net power
19                 cost portion of jurisdictional revenue requirement. In that Docket,
20                 the Commission did order imputation because the contract
21                 obligated the Company to serve SMUD at $16.85 per MWh at the
22                 time it was entered, a rate much below the then-current rate for
23                 power. In addition, SMUD paid the Company $94 million at the
24                 outset of the contract that it retained and was not used to benefit
25                 ratepayers. Nor was this the first time the imputation had been
26                 made. In connection therewith, both here and in other PacifiCorp
27                 jurisdictions, a contract with Southern California Edison (SCE)
28                 entered at about the same time for $42 per MWh had been
29                 considered an appropriate benchmark for imputation.            The
30                 evidence in Docket No. 99-035-10 showed that the SCE contract
31                 had been renegotiated to a rate of $37 per MWh due to structural
32                 changes in the wholesale market. In other words, the Commission
33                 recognized that wholesale prices, which had fallen, were now on a
Docket Nos. UE-061546/UE-060817                                                   Page 33
1                  different path. This, and the fact that the renegotiation was closer
2                  in time to the test period, persuaded the Commission to select the
3                  $37 rate as the basis for imputation, a rate indicating how such a
4                  contract might perform over time.25/
5   Q.     HAS THE COMPANY MADE AN ADJUSTMENT TO ITS TEST YEAR
6          TO REFLECT THE SMUD CONTRACT REVENUE IMPUTATION IN
7          THIS AND OTHER JURISDICTIONS AS WELL?
8   A.     Yes. Since the above referenced 2001 Utah case, the Company has used the
9          $37/MWh price for imputation of revenue in all jurisdictions. However, the
10          WUTC has never decided that the $37/MWh was a reasonable price in a contested
11          proceeding, as discussed above.          There are three important reasons why the
12          WUTC should address this issue now.
13                  First, this issue gains significance under a Washington specific allocation
14          method, and the treatment approved should reflect the policies of the WUTC, not
15          the UPSC.
16                  Second, wholesale power prices have continued to increase since the
17          adoption of the Utah order in the 2001 case. Indeed, the SCE contract that was
18          the basis for the $37/MWh was renegotiated and the most recent contract prices
19          have been much higher. Consequently, the $37/MWh is no longer reasonable or
20          compensatory, even compared to the SCE contract.
21                  Finally, and even more significant, the SCE contract terminated in
22          September 2006. Originally, the SCE contract was a 20-year contract. Because
23          the SCE contract was selected by the UPSC as a prudent benchmark contract
24          contemporaneous to the SMUD contract (actually, the SCE contract post dates the
25          SMUD contract), there is no longer any basis for the $37/MWh price.
Re PacifiCorp, UPSC Docket No. 01-035-01, Report and Order at 24-25 (Sept. 10, 2001).
Docket Nos. UE-061546/UE-060817                                                        Page 34
1          Consequently, the Commission should decide on the proper basis for handling this
2          issue for the remaining 10 years of the SMUD contract, even if it believes that the
3          SCE contract was a reasonable benchmark in the past.
4   Q.     WOULD IT BE REASONABLE TO USE THE CONTRACTUAL PRICE?
5   A.     No. The contractual price (approximately $18.5/MWh in recent months) is far
6          below market and is simply not compensatory.
7   Q.     WOULD IT BE APPROPRIATE TO USE THE $37/MWH PRICE?
8   A.     No. This price is substantially below the current market, and below even the most
9          recent renegotiated price of the SCE contract of $60/MWh. The SMUD contract
10          is primarily for on-peak power, so ratepayers are clearly subsidizing the contract
11          even at $37/MWh.
12   Q.     WHAT IS YOUR RECOMMENDATION?
13   A.     I recommend the Commission find the SMUD contract was not prudent and not
14          used and useful. Removing the contract from GRID substantially reduces net
15          power costs. As a result, the contract costs far outweigh the benefits. Given the
16          imprudence of the original transaction, this is a proper treatment.
17                 Should the Commission believe the historical treatment tied to the SCE
18          contract worthy of consideration, I recommend that the Commission assume that,
19          like the SCE contract, the SMUD contract would have terminated after 20 years.
20          As a result, I would remove the SMUD contract from the GRID power cost study.
21          This is equitable because, after the adoption of the $37/MWh price several years
22          ago, the contract has been subsidized by ratepayers due to its below-market price.
23          Because the Company obtained a benefit from use of the SCE contract as a
Docket Nos. UE-061546/UE-060817                                                  Page 35
1          pricing benchmark, it should now be required to assume all of the risks associated
2          with the limited term of the SCE contract. Under either approach, the SMUD
3          contract should be removed from GRID, reducing net power costs by the amount
4          shown on Table 1.
5   Centralia Sale/TransAlta Contract
6   Q.     EXPLAIN WHY YOU BELIEVE THE CENTRALIA SALE IS AN
7          IMPORTANT ISSUE IN THIS PROCEEDING.
8   A.     Before the sale of the Centralia plant, PACW had far more native capacity
9          available than it does at present. While the Centralia sale case (Docket Nos. UE-
10          991255, UE-991262, and UE-991409) primarily dealt with the question of the
11          public interest of the sale and the allocation of the gain, it did not specifically
12          address rate case treatment of all Centralia related costs. As all of PacifiCorp’s
13          prior base rate cases occur after the sales have been either settled or rejected by
14          the WUTC, there is no WUTC precedent on the matter of Centralia rate case
15          treatment. Important issues related to the risks and rewards of the sale have yet to
16          be addressed by the Commission. Now, owing to the use of the WCA method,
17          Centralia takes on far greater significance than in the past.       Centralia now
18          represents a very large “missing piece” of the PACW supply puzzle that the
19          Commission should carefully consider for not only this case, but for the cases in
20          the years ahead.
21   Q.     HOW DOES THE CENTRALIA SALE IMPACT PACIFICORP’S NET
22          POWER COSTS IN THE WCA MODEL?
23   A.     The Centralia sale has contributed substantially to the Company’s need to
24          increase purchased power expenses. Without the Centralia sale, the Company
Docket Nos. UE-061546/UE-060817                                                 Page 36
1          would have had more than enough energy to meet its native system requirements
2          with low-cost coal and hydro generation.
3   Q.     DID SOME OF THE PARTIES RAISE OBJECTIONS TO THE SALE IN
4          THE CENTRALIA PROCEEDING?
5   A.     Yes. Based on the Order in the Centralia sale proceeding it is quite apparent that
6          both Staff and Public Counsel were concerned about the risks resulting from this
7          sale, including greater exposure to wholesale market risks. ICNU also advocated
8          a “no harm” standard be applied.26/
9                  Indeed, even the Company’s own quantitative risk analysis showed that
10          Centralia would have a positive Advantage Over Market (“AOM”) in the
11          projections presented in that case. This means even the Company recognized the
12          likelihood that customers would be worse off as a result of the sale. In the end,
13          the Company made a decision to increase its wholesale market risk, despite the
14          knowledge of those risks and concerns and objections voiced by the parties to that
15          case.
16   Q.     HOW DID THE COMMISSION ADDRESS THESE CONCERNS?
17   A.     In recognition of this controversy, the Commission stated that neither the
18          customers nor the shareholders will bear all of the risks associated with the sale.
19          Instead the Commission adopted a policy that stated “risk should follow reward”
20          and “benefit should follow burden.”
21                  In general the Commission relies on the broad principle that
22                  reward should follow risk and benefit should follow burden. In
23                  this particular transaction, both ratepayers and shareholders have
24                  and will incur risks and burdens. In addition to the financial risks
25                  and burdens borne by ratepayers, shareholders bear legislative and
Re Avista Corp., WUTC Docket Nos. UE-991255, UE-991262, and UE-991409, Second Supp.
Order at &#182;&#182; 21, 25, 26 (Mar. 6, 2000).
Docket Nos. UE-061546/UE-060817                                                   Page 37
1                   market risks, and additionally bear the regulatory burden of prudently
2                   managing their resources, which multiple ownership can make
3                   difficult. As both shareholders and ratepayers have incurred risks and
4                   burdens, both should also share in the benefits of the sale. The
5                   remaining gain is thus one of the benefits, which, when considered
6                   with other benefits and burdens, must be fairly allocated.27/
7                                                   ***
8                   Given the risks and burdens borne by the ratepayers and shareholders,
9                   and given the other benefits they stand to gain from the sale, we find
10                   that it is fair in this case to allocate the appreciation between
11                   ratepayers and shareholders. When we apply the principles of
12                   Democratic Central to the facts of this case, we conclude that one
13                   half of the appreciation should go to shareholders, and one half to
14                   ratepayers.28/
15                   In reaching this decision, the Commission enunciated a policy that would
16          share the gain on the sale equally between customers and shareholders, while at
17          the same time sharing the risks (most notably market risk.) In the case at hand,
18          the Company has conveniently ignored this fact, and instead proposes to place the
19          entire risk of higher power market prices on the customer. Since the Company
20          retained half of the gain from the sale, under the principle that risk should follow
21          reward, it should bear half of the risk. Under these circumstances it is not
22          reasonable to shield the Company from all of the risks of its controversial
23          decision to sell the plant.
24   Q.     DID THE COMPANY OBTAIN SUFFICIENT ENERGY FROM THE
25          TRANSALTA BUYBACKS TO REPLACE CENTRALIA?
26   A.     No. The Company obtained only enough energy from the buybacks to replace
27          74% of the Centralia generation for the test year. Given that the Company was
28          well aware at the time of the sale that there was certainly substantial market risk
Id. at &#182; 84 (emphasis added).
Id. at &#182; 86.
Docket Nos. UE-061546/UE-060817                                                    Page 38
1          associated with the transaction, its decision to replace only part of the generation
2          for the plant was questionable to say the least. This shortfall resulted in an
3          increase in purchased power costs of nearly $16 million on a PACW basis and
4          approximately $3.6 million for Washington under the WCA model. Even more
5          significant is the fact that after June 2007, the TransAlta buybacks terminate and
6          the Company will be left without any permanent supply to replace the Centralia
7          generation. This contract termination will result in additional costs per year of
8          $45 million for PACW, and, under the WCA method, added costs of $10 million
9          per year for Washington. The Company assumes customers should bear 100% of
10          these added costs.    This is not a reasonable rate treatment in light of the
11          Commission’s principle that risk should follow reward.
12   Q.     HOW DO YOU RECOMMEND THE COMMISSION ADDRESS THIS
13          ISSUE?
14   A.     As discussed above, the Commission decided to give the Company the
15          opportunity to make the sale, and also apportioned 50% of any associated gain to
16          the Company. Under these circumstances, it is unreasonable to saddle ratepayers
17          with all of the risks that have resulted from the sale. Unless the Commission
18          apportions some of the costs of the unreplaced power to the Company, the
19          ratepayers will have been given 50% of the gain on the sale, but bear 100% of the
20          risks. As a result, I recommend that 50% of the cost associated with additional
21          replacement power costs for Centralia be allocated to the Company.             This
22          adjustment reduces the requested claim by the amount shown on Table 1. Unless
23          this adjustment is made, an unreasonable shifting of the risks of the Centralia sale
24          between the Company and ratepayers will occur.
Docket Nos. UE-061546/UE-060817                                                 Page 39
1   Q.     HAVE OTHER COMMISSIONS ADDRESSED THE SAME ISSUE IN
2          THE PAST?
3   A.     Yes. In Wyoming Docket No. 20000-ER-02-184, both the Consumer Advocate
4          Staff and Wyoming Industrial Energy Consumers (“WIEC”) proposed a similar
5          adjustment. The facts were essentially the same in the Wyoming case, because
6          the Wyoming Public Service Commission (“WPSC”) allocated 36% of the
7          Centralia gain to the Company.29/ In its final order in Docket No. 20000-ER-02-
8          184, the WPSC noted that PacifiCorp agreed in concept with the adjustment
9          (though disputed the calculation of the disallowance).30/ The WPSC stated that it
10          ultimately accepted the adjustment as part of the basis for the decision to deny
11          PacifiCorp the requested rate increase to pay for excess power costs during the
12          2001 power crisis.31/ Given this background, the Commission can be confident it
13          is on firm footing in making the adjustment related to this issue shown on Table 1.
14   GP Camus Contract
15   Q.     DO YOU AGREE WITH PACIFICORP’S MODELING OF THE GP
16          CAMAS COGENERATION PROJECT?
17   A.     No. The Company has overstated the generation purchased from this project
18          compared to recent actual data. It is apparent that the generation from this project
19          has declined steadily for the past several years. Because this reduction appears to
20          be continuing, I trended its generation for the four-year period ending March
21          2007. This adjustment reduces net power costs by the amount shown in Table 1.
This was an issue I first raised in a prior Wyoming docket that was addressed by the Consumer
Advocate staff and another witness in Docket No. 20000-ER-02-184.
Re PacifiCorp, WPSC Docket No. 20000-184-ER-02, Final Order at &#182; 192(b) (Mar. 6, 2003).
Id. at &#182; 206.
Docket Nos. UE-061546/UE-060817                                                        Page 40
1                                      Modeling Adjustment
2   Hydro Modeling
3   Q.     DISCUSS THE SIGNIFICANCE OF HYDROELECTRIC RESOURCES
4          TO PACW’S POWER SUPPLY COSTS.
5   A.     Hydro resources supply 30% of the PACW system load. As a result, modeling of
6          all aspects of hydro generation is critical to the development of sound estimates of
7          normalized net power costs for the Company.            A critical element in the
8          determination of net power costs is the proper technique for normalization of
9          hydro generation. There are a number of issues surrounding this topic, the most
10          important being the selection of a proper set of water years for use in simulating
11          PacifiCorp’s power costs.
12   Q.     PLEASE EXPLAIN               THE     CONCEPT         OF     “WATER         YEAR”
13          SIMULATIONS.
14   A.     The annual supply of hydro electric energy is a function of snowpack, snowmelt,
15          run off, and precipitation in the mountains surrounding the river systems that host
16          the dams operated by PacifiCorp and other regional utilities. As a result, the
17          availability of hydro generation is largely a matter of weather and geological
18          factors. Because weather is subject to fluctuation over time, hydro generation
19          varies substantially from year to year. For this reason, it is important to develop
20          power supply cost estimates that reflect the variations in hydro generation over
21          time. This has typically been done by hydro-dependent utilities through use of
22          simulation models that estimate power supply costs as a function of available
23          hydro generation and many other inputs. The most common approach has been to
24          simulate historical water conditions over a large number of years, averaging the
Docket Nos. UE-061546/UE-060817                                                 Page 41
1          final results of the individual water year scenarios. This methodology develops
2          an “expected value” power supply cost.
3   Q.     DOES USE OF MULTIPLE WATER YEAR SCENARIOS GIVE RISE TO
4          ANY SPECIAL ISSUES FOR COMPANIES SUCH AS PACIFICORP?
5   A.     Yes. As early as the 1970s, multiple water year scenarios were used by utilities in
6          Washington to estimate power supply costs for rate case purposes.32/                   The
7          question of how many, and which, water years provide a reasonable simulation
8          has been an issue in many previous proceedings before the WUTC. For the past
9          several cases, PacifiCorp has proposed a 40-water-year simulation. However, in
10          the 2004 case, some important modifications to that method were proposed by the
11          WUTC Staff, and later adopted by the Company and the Commission as part of a
12          contested settlement.
13   Q.     DISCUSS THE 2004 PACIFICORP CASE.
14   A.     In Docket No. UE-032065, PacifiCorp filed its request using a 40-water-year
15          study (1939-1978); based on existing precedent for that Company. However,
16          Staff witness Buckley recommended use of a 40-year “filtered water” study,
17          where “extraordinary” water years (those more than one standard deviation
18          beyond the mean annual generation) were excluded. Mr. Buckley’s basis for this
19          proposal rested on the fact that utilities would request deferrals or Power Cost
20          Adjustment mechanisms (“PCAs”) in situations where abnormal or extreme hydro
21          conditions occurred:
I recall this from my employment with Puget Sound Power and Light in the late 1970s.
Docket Nos. UE-061546/UE-060817                                                         Page 42
1          Q.      Why does Staff propose a different methodology at this time
2                  for this PacifiCorp?
3          A.      Two factors led Staff to conclude that an alternative approach is
4                  appropriate. The first is the recent, very real tendency for the
5                  regulated electric utilities to request rate relief when higher than
6                  expected actual power supply expenses occur due to “unforeseen”
7                  events. Bad water-years and their effect on actual power supply
8                  costs have been cited as one of the unforeseen events.
9                                               ***
10                  Two of the three regulated electric utilities now have some form of
11                  power cost adjustment mechanism. A Washington islanding or
12                  stand-alone approach may include some form of hydro adjustment
13                  to address the variability in generation from hydro resources in the
14                  Western Control Area. Such a hydro adjustment would address the
15                  more significant variations in water conditions throughout the
16                  region. It is therefore unnecessary, and even incorrect, to include
17                  the power supply costs associated with all water year conditions in
18                  the determination of the base power supply costs when a hydro
19                  adjustment mechanism exists. The effects on power supply
20                  expense of water years above or below some level can be
21                  addressed in the mechanism.
22                                               ***
23                  There is no need to burden Washington customers with rates
24                  designed to recover long-term extremes in power supply costs due
25                  to stream flow variations. In the event an extreme year occurs that
26                  adversely affects power costs between now and the next general
27                  rate case, the Company can make a filing to recover those costs.
28                  The adoption of this water year methodology is also appropriate
29                  under any scenario.        Whether through a hydro adjustment
30                  mechanism or [through] a separate filing requesting relief from
31                  drought conditions, it may be in the best interests of customers to
32                  see the cost effects of stream flow variations. Embedding the
33                  effects of the more extreme stream flow conditions is tantamount to
34                  paying an insurance premium and then hoping the Company will
35                  have sufficient funds to pay the claim.33/
WUTC v. PacifiCorp, WUTC Docket No. UE-032065, Exh. No. 581 at 124-27 (Buckley Direct)
Docket Nos. UE-061546/UE-060817                                                    Page 43
1   Q.     DID THE COMMISSION ACCEPT STAFF’S PROPOSAL IN THE
2          PACIFICORP CASE?
3   A.     Yes. However, the PacifiCorp case resulted in a contested settlement between
4          Staff and the Company.       In the stipulation, the Company agreed to Staff’s
5          proposed hydro normalization adjustment. While this stipulation was opposed by
6          ICNU and Public Counsel, to my knowledge, no party opposed the hydro
7          normalization adjustment.      Appendix B to the stipulation document in the
8          PacifiCorp case clearly identified the fact that “extraordinary” hydro years were
9          excluded from the normalization.
10   Q.     SHOULD THE COMMISSION EXCLUDE EXTRAORDINARY WATER
11          YEARS FROM THE NORMALIZATION PROCEDURE AS MR.
12          BUCKLEY RECOMMENDED IN DOCKET NO. UE-032065?
13   A.     Yes.    Mr. Buckley’s proposal was a sensible recommendation given the
14          Commission’s current regulatory policies and practices as applied to PacifiCorp.
15          Indeed, because the Company has already requested a PCAM in this and prior
16          cases, and the Company was granted the right to defer costs related to a hydro
17          deficit in Docket No. UE-050684, Mr. Buckley’s proposal is even more
18          appropriate in this case than it was in 2004.
19   Q.     EXPLAIN THE NEXUS BETWEEN DEFERRALS OF EXCESSIVE
20          POWER COSTS AND THE HYDRO NORMALIZATION TECHNIQUE.
21   A.     Putting aside, for the moment, the issue of the PCAM, the option of a utility being
22          allowed to defer excess power costs in extreme event water years (e.g., a drought)
23          necessitates the exclusion of such water years in the hydro normalization
24          procedure to eliminate a potential problem of double recovery.
Docket Nos. UE-061546/UE-060817                                                 Page 44
1   Q.     CAN YOU PROVIDE AN EXAMPLE TO ILLUSTRATE THIS?
2   A.     Table 2 presents a hypothetical example to explain this problem. In the example,
3          the utility uses a power cost model to compute normalized power costs on the
4          basis of five different hydro generation scenarios. The table shows a hypothetical
5          company that has an average of 500 megawatts (“MWs”) of hydro, and
6          replacement power costs $30/MWh. It shows that under normalized ratemaking
7          customers are charged $100 million per year as the average cost of power based
8          on average hydro over a five-year period (simplified from the 40 years actually
9          used). Over five years, the results would all average out and customers would pay
10          the total actual cost of power supply costs, $500 million. The $500 million figure
11          includes both good and bad hydro years. The normalized cost of $100 million is
12          lower than the cost of power in below average hydro years, but higher than the
13          cost of power in good hydro years. By using the average value, a “premium” is
14          built into the normalized cost of power in good years that provides a form of
15          “insurance” against bad hydro years.
16                 Assume now that year five is the worst hydro year and the utility requests
17          a deferral to allow it to ultimately recover the additional power costs.          If
18          regulators allow the Company to have a deferral in a bad hydro year, they get the
19          benefit of the “premium” built in during the good years, and then effectively
20          charge the actual cost in year five. Under this scenario, ratepayers pay the
21          normalized cost of power ($100 million) for the first four years and the actual cost
22          of power in year five. The total cost of power to customers in that scenario is
Docket Nos. UE-061546/UE-060817                                                 Page 45
1           $526 million, resulting in an overcharge to customers of $26 million over the five-
2           year period.
Example of Overcollection Problem
Hydro                                      Normalized          Ratepayer
Ratepayer           Cost with
Year         Average MW            NPC-M$              Cost            Deferral Y 5
1               600                 73.7             100.0               100.0
2               550                 86.9             100.0               100.0
3               500                100.0             100.0               100.0
4               450                113.1             100.0               100.0
5               400                126.3             100.0               126.3
Average             500              100.0              100.0
Total Ratepayer Cost                      500.0            500.0                526.3
Overcollection           26.3
3                  In the example above, the higher than normal costs of a bad hydro year
4           ($26 million) are averaged into rates every year. However, instead of getting a
5           “free pass” when the bad hydro year actually arrives, customers are now required
6           to pay for bad hydro conditions as well. When above normal hydro conditions
7           occur, customers pay the normalized cost and the company keeps the savings.
8           When below normal hydro conditions occur, the company requests a change to
9           the rules of the game and asks for a deferral to recover its total cost. This is a
10           “heads I win, tails you lose” type of hydro normalization process.
11   Q.      GIVEN THE PROBLEM ILLUSTRATED ABOVE, WHY WOULD
12           REGULATORS ALLOW DEFERRALS IN POOR HYDRO YEARS?
13   A.      While regulators may be concerned about the inequity illustrated above, the
14           reality is that financial exigencies may force the Commission to approve a
15           deferral. This illustrates the problem alluded to by Mr. Buckley in the testimony
Docket Nos. UE-061546/UE-060817                                                  Page 46
1          quoted above stating that customers pay the “insurance premium” hoping the
2          Company will be able to “honor the claim.”
3   Q.     WHAT IS THE IMPACT OF USING THE “FILTERED WATER”
4          METHODOLOGY IN THIS CASE?
5   A.     Exhibit No.___(RJF-8) shows the GRID model power cost results based on the
6          filtered and non-filtered approach. Mr. Buckley’s approach, using PacifiCorp’s
7          40 years of water data would result in power supply costs substantially less than
8          the Company non-filtered proposal. I recommend the Commission adopt this
9          adjustment, reducing power costs by the amount shown on Table 1. I will also tie
10          this treatment into my alternative to PacifiCorp’s PCAM proposal to be discussed
11          later.
12   Thermal Deration Factors
13   Q.     EXPLAIN THE SIGNIFICANCE OF THERMAL DERATION FACTORS
14          IN GRID.
15   A.     In GRID, thermal deration factors (also called outage rates) control the amount of
16          generation available from thermal units. The more energy available, the lower net
17          power costs. If a generator has an average outage rate of 5%, GRID assumes a
18          thermal deration factor of 95%. This means that only 95% of the unit’s capacity
19          is available to produce energy.      The remaining capacity is assumed to be
20          permanently on outage. The Company uses a compilation of outages over the
21          most recent 48-month historical period (April 2002 to March 2006) to compute
22          the deration factors for its thermal plants. The purpose of using 48 months is to
23          “normalize” or smooth out variations that might affect a single year.
Docket Nos. UE-061546/UE-060817                                                 Page 47
1   Q.     HOW DOES THE COMPANY MODEL UNPLANNED OUTAGE RATES
2          IN GRID?
3   A.     The Company computes a different unplanned outage rate for each month based
4          on the 48-month rolling average. This procedure marks a significant departure
5          from the modeling methods used by the Company for the past ten years or more.
6          In the past, the Company assumed that unplanned outages would occur with the
7          same probability every month of the year.       In this case, the Company now
8          assumes outage rates will vary by month.
9   Q.     IS THIS AN INDUSTRY STANDARD PRACTICE?
10   A.     Most definitely not. PacifiCorp’s approach is quite unusual and certainly not
11          industry standard. While I am aware that a few utilities have briefly experimented
12          with modeling seasonal outage rates, the vast majority of utilities assume a
13          constant outage rate throughout the year. The primary reason for this is that there
14          are few physical factors affecting thermal power plant operation that would result
15          in outage rates varying on a monthly or seasonal basis.        There is really no
16          engineering basis to assume a generating unit would be more reliable in January
17          than July, for example.
18                  Further, unplanned outages are quite random by nature, and use of
19          monthly statistics can produce very misleading results. For example, a unit could
20          be out the entire month of May, resulting in a 100% outage rate for that month.
21          Assuming the unit had a 10% outage rate otherwise, the Company’s method
22          would assume that every May, there was a 32.5%34/ chance the plant would be out
23          of service, but only a 10% likelihood for the remaining eleven months. Rolling a
(100+3*10)/4.
Docket Nos. UE-061546/UE-060817                                                 Page 48
1          single “bad month” into the overall 48-month average would produce a 48-month
2          outage rate of 11.875%35/ overall. I submit that a single outage rate of 11.875%
3          every month is more realistic than assuming a 32.5% outage rate each May and a
4          10% outage rate every other month.
5   Q.     CAN YOU PROVIDE A SIMPLE ANALOGY THAT EXPLAINS THE
6          FALLACY OF THE COMPANY’S APPROACH?
7   A.     Yes. The Company’s approach is similar to assuming that because a random
8          event occurred in a particular month in the past, it would likely occur at the same
9          time in the future. For example, if my car broke down on in February 2006, it
10          would likely break down again in February 2007. However, this is superstition,
11          not logic. It is analogous to fearing that something “bad” might happen every
12          Friday the 13th!
13   Q.     DOES THE COMPANY’S APPROACH MAKE SENSE WITHIN THE
14          CONTEXT OF NORMALIZATION?
15   A.     No.    The use of monthly outage rates defeats the purpose of a 48-month
16          normalization period. In effect, the Company has replaced 48 months of data
17          with four months of data for each individual month. However, mere statistical
18          variations are such that four single months of data will be far too variable to
19          “normalize” outage rates. If monthly outage rates are used, then a much longer
20          period of time should also be employed.
21   Q.     DO YOU HAVE AN EXHIBIT THAT FURTHER ILLUSTRATES THE
22          FALLACY OF PACIFICORP’S APPROACH?
23   A.     Yes.   Exhibit No.___(RJF-9) shows an analysis of the outage rates for Jim
24          Bridger Units 1-4. Because these units are all of the same size, fuel type, location
(47*10+100)/48.
Docket Nos. UE-061546/UE-060817                                                 Page 49
1          and similar designs, one would expect that if the monthly outage rate modeling
2          made sense, there should be some correlation between their monthly outage rates.
3          In other words, if there are causal factors that result in a definite monthly pattern
4          of outages, it should affect all units at the station in a comparable manner.
5          However, the exhibit shows there really is no discernable pattern in the monthly
6          outages of these units. Indeed, there is no statistically significant correlation
7          between the monthly outage rates of these units. It is apparent from the figure
8          that the monthly variations about the mean amount to nothing more than
9          “statistical noise” or “random chance.” This strongly suggests there is no basis,
10          other than superstition, underlying the Company’s proposal to apply this novel
11          monthly outage rate modeling technique.
12   Q.     DOES THE MONTHLY OUTAGE RATE MODELING INCREASE NET
13          POWER COSTS IN GRID?
14   A.     Yes. Given the lack of a sound engineering basis or common sense argument
15          underlying this approach and the lack of any statistical support for it, I am forced
16          to conclude this is little more than “numerology.” It certainly appears this is a
17          one-sided adjustment proposed by the Company for no purpose other than to
18          increase power cost estimates. I recommend that the Commission reject the
19          monthly modeling of outage rates and reduce net power costs by the amount
20          shown on Table 1.
Docket Nos. UE-061546/UE-060817                                                  Page 50
1   Thermal Ramping
2   Q.     DO YOU RECOMMEND THE COMMISSION ACCEPT THE THERMAL
3          RAMPING ADJUSTMENT CONTAINED IN THE GRID STUDY?
4   A.     No. This adjustment was proposed by the Company ostensibly to better represent
5          the operation of thermal units. PacifiCorp has adopted this technique in several
6          recent cases in other states, motivated by a dubious assumption that GRID was
7          producing an excess of coal-fired generation.36/ To address the ramping issue,
8          PacifiCorp creates “phantom outages,” inflating its outage rates. However, all of
9          the Company’s recent cases in Oregon, Utah, Washington and Wyoming have
10          been settled (at least regarding this issue) or dismissed, so there is no regulatory
11          decision in any state supporting this technique.
12   Q.     IS MODELING OF THERMAL RAMPING IN THE MANNER USED BY
13          THE COMPANY STANDARD INDUSTRY PRACTICE?
14   A.     No. Again, based on my nearly thirty years’ experience in working with various
15          production cost models, this approach is extremely unusual and contrary to
16          standard industry practice.      The North American Energy Reliability Council
17          (“NERC”) publishes a standard formula for computation of forced outage rates,
18          and the approach proposed by the Company is inconsistent with the NERC
19          formula.
20   Q.     ARE YOU AWARE OF ANY INSTANCE WHERE A UTILITY
21          PROPOSED TO INCLUDE ENERGY LOST DUE TO RAMPING IN THE
22          OUTAGE RATES USED IN A POWER COST MODEL?
23   A.     There is only one other case that I am aware of. In Oregon Docket No. UE 139,
24          Portland General Electric Company (“PGE”) proposed a similar modification to
Re PacifiCorp, OPUC Docket No. UE 170, Exhibit PPL/604 at 2 (Supp. Direct Testimony of
Mark Widmer).
Docket Nos. UE-061546/UE-060817                                                       Page 51
1          outage rates for the Colstrip plant to solve a similar assumed problem of
2          generation from its model exceeding actual generation (“lost generation”). In that
3          case, the Commission flatly rejected the PGE proposal:
4                 ICNU disapproves of PGE’s calculations in modeling planned
5                 outages for the Colstrip plant. ICNU notes that the [NERC] has
6                 promulgated a standard equation to estimate the forced outage rate
7                 of a particular plant. In estimating the forced outage rate for
8                 Colstrip, however, PGE modified NERC’s standard equation by
9                 substituting the plant’s capacity factor (CF) for its equivalent
10                 availability factor (EAF). ICNU contends that PGE’s deviation
11                 from standard industry practice is unjustified and arbitrarily
12                 inflates PGE’s net variable power cost estimate by $1.5 million.
13                 PGE explains it made the adjustment because it obtains less energy
14                 from Colstrip than one should expect from the plant’s EAF. PGE
15                 highlights that it has normally received 1 to 4 percent less
16                 generation—based on the plant’s CF—than would be expected—
17                 given the plant’s EAF. To account for this, PGE assigns the
18                 “missing generation” to unplanned outages. PGE has not identified
19                 any specific reason why the generation at Colstrip has fallen short
20                 of potential levels, but speculates that up or down ramping periods,
21                 generation variances including minor forced derations, or
22                 transmission pathway deratings may be responsible.
23                 While it appears that an aberration exists in PGE’s system that
24                 prevents the company from obtaining expected generation levels
25                 from the Colstrip plant, we are not convinced that creating
26                 “phantom outages” is the appropriate solution. First, PGE’s
27                 proposed adjustment violates standard industry practice and is
28                 contrary to the company’s own forecasting methods that it uses for
29                 other plants. Second, PGE’s adjustment fails to account for the fact
30                 that a plant’s CF, by definition, will never exceed its EAF, even
31                 those that run continuously.
32                 We are also troubled by PGE’s decision to make this adjustment
33                 despite the fact that it is unable to identify the source of the
34                 generation shortfall or to quantify its effect. If the loss of energy
35                 from Colstrip is due to minor forced derations as PGE speculates,
36                 the company should be able to modify Monet to capture these
37                 derations.
Docket Nos. UE-061546/UE-060817                                                 Page 52
1                  For these reasons, we disagree with PGE’s adjustment to a
2                  standard industry equation used to compute forced outage rates
3                  when outages have nothing to do with the alleged problem.37/
4    Q.    WHAT IS YOUR RECOMMENDATION?
5   A.     I recommend the Commission reject the ramping adjustment, reducing net power
6          costs by the amount shown on Table 1.
7   Regulating Margin Requirements
8   Q.     DO YOU AGREE WITH PACIFICORP’S MODELING OF REGULATING
9          MARGIN REQUIREMENTS IN GRID?
10   A.     No. The Company now assumes an increase in the maximum regulating margin
11          requirements from 125 MW used in Docket No. UE-050684 to 225 MW. The
12          Company provides no justification for this changed assumption in its testimony.
13          Based on discussions I had with PacifiCorp’s operating personnel at a technical
14          conference in November 2004, the Company’s actual maximum west regulating
15          margin is only 125 MW. The Company used this assumption for many years in
16          GRID, but recently proposed this change. The change was made in Oregon in UE
17          179, and was opposed by ICNU in that case. The changed assumption was not
18          supported by a change in system operations, but rather a flawed new methodology
19          used by the Company to develop the inputs. UE 179 was settled, so there is no
20          precedent surrounding this issue. I recommend the Commission reverse this data
21          change resulting in a reduction to net power costs by the amount shown on
22          Table 1.
Re PGE, OPUC Docket No. UE 139, Order No. 02-772 at 23-24 (internal footnotes omitted).
Docket Nos. UE-061546/UE-060817                                                       Page 53
1                                         V.    PCAM
2   Q.     WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?
3   A.     I address the issues raised by PacifiCorp’s request for approval of its already
4          defined PCAM. I am not testifying for Public Counsel on this issue because
5          Public Counsel is sponsoring a witness to specifically address the PCAM.
6          Specifically, I show why the arguments the Company uses in support of its
7          proposal are unpersuasive. I also identify a number of problems and flaws in the
8          PCAM proposal. I recommend that the Commission reject the proposed PCAM
9          and present an alternative concept the Commission should adopt, if it decides to
10          implement a PCAM at this time.
11   Q.     PLEASE SUMMARIZE YOUR PCAM TESTIMONY.
12   A.     I have concluded as follows:
13          1. There are serious design flaws in the proposed PCAM. The proposed PCAM
14             does not address the objections to a PCAM expressed by the Commission in
15             Docket No. UE-050684.
17          2. The proposed PCAM does not use actual short-term power costs, but instead
18             uses hypothetical “pseudo-actual costs” based on GRID model runs rather
19             than actual data. Because PacifiCorp has also failed to produce a reasonable
20             jurisdictional allocation methodology, its PCAM proposal is unsupportable.
22          3. The PCAM proposal does not provide protection against extreme or unusual
23             events, but rather allows substantial recovery of certain kinds of ordinary cost
24             increases.
26          4. PacifiCorp has not demonstrated that a PCAM is needed. The PCAM
27             proposal is poorly explained and not adequately justified in PacifiCorp’s
28             testimony. The Company fails to address many problems inherent in its
29             PCAM concept.
31          5. Owing to the looming expiration of the TransAlta contract, the PCAM really
32             amounts to a $5 million rate increase in disguise.
Docket Nos. UE-061546/UE-060817                                                 Page 54
1          6. While I recommend against it, if the Commission decides to adopt a PCAM, I
2             propose a more reasonable alternative to the Commission.
3   Problems in the PCAM Proposal
4   Q.     SHOULD PACIFICORP’S               PCAM       BE    AUTHORIZED         BY    THE
5          COMMISSION?
6   A.     No. The PacifiCorp proposal is flawed, poorly justified, and places Washington
7          ratepayers at a substantial disadvantage vis-&#224;-vis the Company and customers in
8          other states. Adoption of the proposed PCAM would be a questionable policy
9          decision at this time. Further, pass through mechanisms reduce incentives for
10          efficiency and increase the overall regulatory burden.
11   Q.     DOES THE COMPANY HAVE A PCAM IN ITS TWO LARGEST
12          STATES, OREGON AND UTAH?
13   A.     No. The Company proposed a PCAM in both states, but later withdrew its
14          request. Adoption of a PCAM would require Washington ratepayers to assume
15          risks not shared by customers in the Company’s two largest jurisdictions.
16   Q.     ARE THERE IMPORTANT DEFECTS IN THE PCAM PROPOSAL?
17   A.     Yes. There are practical drawbacks and many policy issues raised by the PCAM
18          proposal. Below I identify the major components of my analysis of the problems
19          with the PacifiCorp proposal:
20                        Failure to address the Commission’s concerns as expressed in
21                         Docket No. UE-050684;
22                        Use of GRID model runs instead of actual short-term costs;
23                        Lack of a reasonable jurisdictional allocation method that would
24                         facilitate computation of actual costs to be included in the PCAM;
25                        Lack of an appropriate deadband and sharing mechanism;
Docket Nos. UE-061546/UE-060817                                                Page 55
1                        Lack of justification/need for a PCAM; and
2                        Likelihood of a built in rate increase in 2007.
3          1.     Failure to Address Commission Concerns in Docket No. UE-050684.
4   Q.     DOES PACIFICORP’S PROPOSED PCAM ADDRESS THE CONCERNS
5          THAT LEAD THE COMMISSION TO REJECT ITS PCAM PROPOSAL
6          IN DOCKET NO. UE-050684?
7   A.     No. While the Company does address a few of the Commission’s concerns (in a
8          rather self-serving manner) it did not address the Commission’s most pressing
9          concerns. In Docket No. UE-050684, the Commission cited three particularly
10          important issues in its rejection of the proposed PCAM:
11                 In sum, we reject the proposed PCAM for three reasons: 1) It
12                 should focus on short-term costs subject to market volatility or
13                 other extraordinary events that are beyond the Company’s control,
14                 and should not include costs for new generation; 2) The 90/10
15                 sharing band and the absence of a deadband do not adequately
16                 balance risks and benefits between shareholders and ratepayers,
17                 and; 3) An acceptable allocation methodology is a prerequisite to
18                 establishing a PCAM.38/
19                 PacifiCorp’s new proposal continues to fail all three counts. First, it does
20          not focus on actual short-term costs, but instead relies on hypothetical “pseudo-
21          actual” costs. Second, it fails to use a reasonable deadband, and for power cost
22          variances in excess of $7.4 million it adopts the same 90/10 sharing already
23          rejected by the Commission. Finally, as discussed earlier, the Company has failed
24          to develop a reasonable allocation methodology. Indeed, the most compelling
25          argument against PacifiCorp’s WCA methodology is that the Company contends
26          it cannot even compute the actual costs to be applied to Washington. I will
27          elaborate on each of these points in the following sections of this testimony.
WUTC Docket No. UE-050684, Order No. 04 at &#182; 99.
Docket Nos. UE-061546/UE-060817                                                  Page 56
1          2.      Use of the GRID Model for Actual Costs/Jurisdictional Allocation
2   Q.     IS THE PROPOSED PCAM BASED ON ACTUAL SHORT-TERM
3          COSTS?
4   A.     No, and this fact illustrates a major problem with the proposed WCA
5          jurisdictional allocation methodology. Rather than develop a PCAM that applies
6          to actual short-term costs, the Company instead proposes to manufacture pseudo-
7          actual costs by use of GRID model runs.
8   Q.     WHY DOESN’T THE COMPANY USE ACTUAL SHORT-TERM COSTS
9          IN THE PROPOSED PCAM?
10   A.     It seems quite apparent that the reason for this is that, under the WCA
11          methodology, the Company has developed no technique for separating WCA
12          power costs from system power costs.39/ As a result, the Company falls back on
13          its truncated (PACW only) GRID model to provide a dispatch of western
14          resources on a stand-alone basis. A fundamental problem is that without some
15          form of actual cost to compare the model against, there is no basis for assuming
16          the model provides realistic results. Indeed, the model could be off by tens of
17          millions of dollars for PACW, but there is no way to determine whether it is
18          accurate or not.      As shown earlier, on the basis of my approximations, this
19          problem indeed exists. My actual cost analysis shows the Company’s model has
20          greatly overstated actual PACW power costs. As a result, it is not useful for
21          purposes of developing a PCAM and should not be used by the Commission for
22          such purposes.
See Exh. No.___(RJF-12) at 6 (PacifiCorp’s Response to ICNU DR No. 1.27). In this response,
the Company admits that it has not developed actual power costs for PACW. In its Response to
ICNU DR No. 1.48, the Company admits that it has not developed any analysis of historical costs
that would have been recovered under the PCAM. Exh. No.___(RJF-12) at 8.
Docket Nos. UE-061546/UE-060817                                                         Page 57
1   Q.     HOW DOES THE COMPANY PROPOSE TO COMPUTE THE PSEUDO-
2          ACTUAL COSTS IN THE PCAM?
3   A.     While this is a very important issue, Mr. Widmer is quite vague on the matter. On
4          page 30 of his testimony he provides a terse explanation, indicating that “actual
5          market prices for electricity and natural gas, fuel costs, hydro generation, retail
6          loads, forced outages, planned maintenance” and certain new wholesale
7          transactions will be input into the GRID model.40/ The new model results will
8          then be compared to the projections used in setting rates. Based on the difference
9          between these two GRID runs, the Company would then produce its annual
10          PCAM update.
11   Q.     IS THIS A REASONABLE PROCEDURE?
12   A.     No. The resulting numbers are neither actual costs, nor are they projections. In
13          my experience, the great majority of regulatory commissions use actual costs in
14          PCAM-type procedures. While Oregon has used forward-looking projections (for
15          PGE and PacifiCorp) as part of an annual power cost update process, this is not
16          the same as using a model as a substitute for actual costs in PCAM. I am not
17          aware of any state that uses a model fed with a veritable witches’ brew of both
18          actual and projected data to develop power cost adjustments on an annual basis.
19          Indeed, when offered a mechanism of this very sort (in the form of a settlement
20          between the OPUC Staff and PGE in Oregon Docket No. UE 165/UM 1187), the
21          Oregon Commission rejected the proposal out of hand.41/
Re PGE, OPUC Docket Nos. UE 165 and UM 1187, Order No. 05-1261 (Dec. 21, 2005).
Docket Nos. UE-061546/UE-060817                                                    Page 58
1   Q.     WHAT IS THE FUNDAMENTAL PROBLEM WITH THE PCAM
2          PROPOSAL?
3   A.     Ratepayers should either be charged normalized projected costs (developed in a
4          rate case allowing all parties due process sufficient to test the assumptions) or
5          verifiable actual costs (subject to a sufficient audit). A combination of some
6          actual and some projected data plugged into an untested (and ever changing)
7          model would be a unique and highly questionable regulatory experiment.
8   Q.     DO YOU HAVE ANY SPECIFIC CONCERNS REGARDING THE
9          ACTUAL COST COMPONENTS THE COMPANY PROPOSES TO
10          MODEL IN THE PCAM?
11   A.     Yes. First, the Company proposes to reflect “actual market prices” for natural gas
12          and electricity.   However, Mr. Widmer’s testimony does not provide any
13          explanation as to how this data will be applied or from where it will come. For
14          example, Mr. Widmer refers to actual market prices for COB and Mid-C being
15          used in the model, but he does not indicate whether these would be published
16          indices, or actual prices paid by the Company.42/ Further, market prices vary
17          constantly. The Company does not specify whether it will use hourly prices in the
18          model, or generate hourly prices from day-ahead prices, for example. This issue
19          turned out to be a major complication in the above referenced PGE case and
20          required substantial changes to the model to accept the data.
21                 Second, PacifiCorp’s only gas-fired generator in PACW (Hermiston) has a
22          long-term contract. There is no reason why actual gas market prices should be
23          used in the model, since the Company is not actually paying market prices for its
Exh. No.___(MTW-1T) at 31.
Docket Nos. UE-061546/UE-060817                                                 Page 59
1          gas. Use of actual market gas prices would most certainly result in over-recovery
2          of the Company’s gas costs.
3                 Third, the Company proposes to use actual forced outage rates and hydro
4          generation in the model. However, the Company does not specify whether the
5          model will be required to run with the actual outages as they occur, or will use
6          annual or monthly averages. This gives the Company a lot of flexibility tailoring
7          these inputs to achieve results it deems desirable. With respect to hydro, the
8          Company does not indicate whether it will use actual hourly, weekly, or monthly
9          hydro generation in the model. If it does not use the actual dispatch sequence, it
10          is unclear how it will develop the hourly figures used in the model.
11                 Finally, the Company proposes to exclude some (but not all) “new”
12          resources. This would include replacement contracts, or even contract extensions.
13          For example, as discussed above, the TransAlta contract expires in June 2007.
14          Under the Company proposal, even if the contract was extended with the same
15          quantities and pricing provisions, the resource would be removed from the model
16          and priced at the then current market. This would produce a substantial increase
17          in net power costs in the GRID model, even though that would not be true for the
18          Company’s actual costs. Likewise, if a highly unfavorable sales contract (i.e.
19          SMUD) were to be terminated, the Company would continue charging customers
20          as though it continued indefinitely.
21                 While the Commission did express concern about including “new
22          resources” in a PCAM in its order in Docket No. UE-050684, it did not even
23          suggest that contract extensions or new sales should be ignored. My reading of
Docket Nos. UE-061546/UE-060817                                                 Page 60
1          the Commission’s order on this point was that it did not want the PCAM to serve
2          as a substitute for a general rate case when the Company obtained a long-term
3          contract for a major new plant (e.g. a new combined cycle plant such as
4          Hermiston), not that it intended to allow the Company to charge market prices
5          every time a contract expired. Because the Company has the flexibility to decide
6          when rate cases are filed, allowing the Company such latitude in excluding
7          contracts and sales is most certainly subject to abuse. The Company would be
8          able to avoid rate cases in cases where favorable transactions were entered into
9          (or unfavorable ones ended), and file rate cases in the opposite set of
10          circumstances.
11                  In the end, the biggest problem with the PacifiCorp proposal is that, owing
12          to the lack of a reasonable jurisdictional cost allocation method, the Company has
13          not developed a PCAM based on actual costs.43/ Instead the Company proposes a
14          PCAM that deals with manufactured pseudo-actual costs that are neither the
15          actual short-term costs usually applied in a PCAM, nor are they the normalized
16          costs used in setting base rates. The result is likely to be a PCAM the Company is
17          able to exploit for its gain at ratepayers’ expense.
18          3.      Deadband and Sharing Mechanism
19   Q.     DESCRIBE THE DEAD BAND AND SHARING MECHANISM IN THE
20          PCAM PROPOSAL.
21   A.     PacifiCorp proposes a deadband of plus or minus $3.0 million dollars, with 60/40
22          (customer/company) sharing for variances between plus or minus $3.0 and $7.4
Alternatively, perhaps the Company analyzed this issue, as did I, and came to the conclusions that
the model overstates PACW power costs.
Randall J. Falkenberg Direct Testimony                                     Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                           Page 61
1          million. For all larger variances, the Company proposes to allocate 90% of power
2          cost variances to customers and 10% to shareholders.
3   Q.     IS THIS A REASONABLE SHARING MECHANISM?
4   A.     No. For any power cost variance greater than $7.4 million, 90% of the costs are
5          assigned to the customer. This is unfortunate, because the Commission already
6          rejected the 90/10 sharing mechanism in Docket No. UE-050684, as discussed
7          above. The Company’s latest proposal is only slightly different. Once again, the
8          Company pays mere lip service to the Commission’s requirements and comes
9          back with a self-serving proposal.
10   Q.     HOW DOES THE                 COMPANY         SUPPORT          THIS    SHARING
11          MECHNANISM?
12   A.     The Company justifies its PCAM on the basis that it is similar to the current
13          Avista Energy Recovery Mechanism (“ERM”). However, the Company ignored
14          the fact that the surrounding circumstances for Avista and PacifiCorp are quite
15          different. First, the current Avista mechanism was the result of a unanimous
16          stipulation of the parties to Docket No. UE-060181 that grew out of another
17          unanimous stipulation of the parties to Docket No. UE-011595. The earlier case
18          resulted from the fallout of the 2001 western power crisis, which cost Avista’s
19          debt its investment grade status.    Even in 2006, Avista still had a below
20          investment grade credit rating. Parties to the case, including both ICNU and
21          Public Counsel were well aware of the need to take steps (including use of a
22          PCAM) to address this problem. PacifiCorp’s reliance on Avista is misplaced
23          because Avista’s ERM is the result of an agreement among the parties, and a
24          company with far less favorable financial circumstances.
Docket Nos. UE-061546/UE-060817                                                  Page 62
1                 Second, Avista is far more susceptible to power cost risks than PacifiCorp,
2          because “PacifiCorp is less reliant on hydroelectric power than Avista and PSE,
3          which may suggest a differently structured PCAM.”44/
4                 Ironically, even though PacifiCorp has less need for a PCAM, and better
5          ability to absorb power cost risks, the Company proposes a narrower deadband,
6          and a less favorable sharing mechanism. While Avista’s deadband is $4 million,
7          the Company proposes only $3 million. Where Avista has a 50/50 sharing from
8          $4 to $10 million, PacifiCorp proposes 60/40 from $3 to $7.4 million. In every
9          respect, PacifiCorp’s proposed PCAM is less adequate than Avista’s ERM, even
10          though a PCAM for PacifiCorp should be less favorable to shareholders than
11          Avista’s ERM.
12   Justification/Need for a PCAM
13   Q.     HOW DOES THE COMPANY JUSTIFY ITS REQUEST FOR A PCAM?
14   A.     The total Company justification for the PCAM amounts to one page in the
15          testimony presented by Ms. Kelly45/ and eight pages from Mr. Widmer.46/ The
16          Company supports the proposed PCAM as follows: 1) a PCAM is needed due to
17          power cost volatility; and 2) other utilities in Washington have a PCAM. Neither
18          witness presents any real evidence concerning the actual need for a PCAM.
19   Q.     THE FIRST JUSTIFICATION FOR THE PCAM CONCERNS POWER
20          COST VOLATILITY. PLEASE COMMENT.
21   A.     The discussion in Mr. Widmer’s testimony is very broad and general. There is no
22          specific evidence presented to establish that the current level of power cost
WUTC Docket No. UE-050684, Order No. 04 at &#182; 93.
Exhibit No.___(ALK-1T) at 11-12.
Exh. No.___(MTW-1T) at 26-34.
Docket Nos. UE-061546/UE-060817                                                Page 63
1          volatility poses a serious problem for the Company. In fact, as discussed above,
2          Mr. Widmer does not even present actual PACW data demonstrating that
3          volatility is a problem. Instead, he relies on Exhibit No.___(MTW-4) which
4          merely shows assumed cost impacts due to varying hydro levels. Again, the
5          Company does not even claim to have actual PACW power costs, so there is no
6          way of telling what its actual power cost volatility really is.
7                  Even granting the existence of power cost volatility due to hydro
8          variability, there is no explanation provided by either Ms. Kelly or Mr. Widmer as
9          to why it is preferable to saddle ratepayers with power cost risks. A PCAM does
10          not make the risk of power cost volatility go away. It merely allocates that risk to
11          ratepayers instead of shareholders. It is not universally accepted that this is the
12          most appropriate means of dealing with such risks. For example, in one of
13          PacifiCorp’s recent proceedings in Oregon, OPUC Staff witness Mr. Maury
14          Galbraith recently testified against assigning such risks to ratepayers: “It is much
15          more efficient to have the financial market diversify [Net Variable Power Cost]
16          risk, than to allocate the risk to customers and have them bear it.”47/ As discussed
17          above, in both Oregon and Utah, the Company has recently requested
18          comprehensive PCAMs and then agreed to withdraw those requests as part of rate
19          case settlements. At present, the Company has no comprehensive PCAM request
20          pending in either state.
Re PacifiCorp, OPUC Docket No. UE 173, Exhibit Staff/100 at 7, 22-23 (Galbraith Direct).
Docket Nos. UE-061546/UE-060817                                                         Page 64
1   Q.     THE SECOND ARGUMENT ADVANCED IN SUPPORT OF THE PCAM
2          IS THAT OTHER UTILITIES IN WASHINGTON HAVE ONE. PLEASE
3          COMMENT.
4   A.     While true, this seems more like the kind of argument one hears in relation to
5          setting a child’s weekly allowance than a well thought out justification. However,
6          the Company failed to address some important facts. First, both the Avista and
7          PSE PCAM mechanisms were initially adopted via settlement agreements among
8          parties to 2001 rate cases of both companies. These PCAM mechanisms were
9          adopted with the support of ratepayer representatives at the time and not over
10          their objections.     Second, both Avista and PSE were in serious financial
11          difficulties when the PCAMs were first implemented.                Indeed, the WUTC
12          adopted those PCAMs as tools for restoring the financial health of both
13          companies.48/ At that time, PSE’s bond rating was BBB by Standard &amp; Poor’s and
14          Baa1 by Moody’s with a negative outlook by both credit rating agencies 49/ and
15          Avista had lost it investment grade status.50/ PacifiCorp alleges no such financial
16          hardship at this time, and there is no unanimous stipulation indicating support of
17          other parties for its PCAM in this case. As a result, the comparison to Avista and
18          PSE is simply unwarranted.
19   Q.     CAN YOU PROVIDE ANY EVIDENCE THAT ADDRESSES THE ISSUE
20          OF POWER COST VOLATILITY?
21   A.     Yes. Exhibit No.___(RJF-10) shows results of my analysis of GRID model
22          results, showing sensitivity of PacifiCorp’s PACW power costs to changes in
23          hydro levels, natural gas prices, coal prices, and wholesale market prices. This
WUTC v. Avista Corp., WUTC Docket No. UE-011595, Fifth Supp. Order at &#182; 6 (June 18, 2002).
WUTC v. PSE, WUTC Docket No. UE-011570, Direct Testimony of Samuel Hadaway at 3.
WUTC Docket No. UE-011595, Fifth Supp. Order at &#182; 7.
Docket Nos. UE-061546/UE-060817                                                      Page 65
1          analysis illustrates that under current circumstances, the Company has very little
2          sensitivity to any factor other than hydro generation.
3   Q.     PLEASE EXPLAIN.
4   A.     The analysis shows that a one standard deviation change in hydro generation
5          levels results in an $8.6 million change in power costs to Washington, using the
6          GRID and WCA models. This amounts to approximately 210 basis points for its
7          ROE. While this is a moderate amount of sensitivity, it should occur, on average
8          no more than once every three years. However, half the time, the hydro variance
9          will be positive, meaning that only one in six years would the Company see a
10          hydro deficit sufficient to cause a 210 basis point (or more) reduction in earnings.
11          I believe hydro variations less than this amount should be absorbed by the
12          Company.51/ Given the Commission’s comments in the final order in Docket No.
13          UE-050684 indicating a PCAM should focus on short-term costs subject to
14          market volatility, or other extraordinary events beyond the Company’s control,52/
15          I suggest the Commission agree.
16   Q.     EXPLAIN YOUR CONCLUSIONS REGARDING THE SENSTIVITY OF
17          PACIFICORP’S PACW POWER COSTS TO A 10% CHANGE IN
18          NATURAL GAS AND COAL MARKET PRICES.
19   A.     The exhibit shows a range equal to zero on the low end, and 10% of the annual
20          expense on the high end. The results show a range of 0 to 68 basis points as the
21          impact of a 10% increase in coal market prices, and 0 to 27 basis points for a 10%
22          increase in gas market prices.
The Public Utility Commission of Oregon relied on a standard of 250 basis points for setting the
deadband in PacifiCorp’s 2001 excess power cost case, Docket No. UM 995.
Docket Nos. UE-061546/UE-060817                                                          Page 66
1                 The Company purchases natural gas for Hermiston and coal for Bridger
2          and Colstrip under long-term contracts. The Hermiston gas contract has shown
3          little escalation and is far below current market prices. Likewise, coal prices are
4          far more stable than overall power market prices or natural gas costs. Thus, I do
5          not believe that the Company has any significant exposure to short-term market
6          price variations for either gas or coal. These costs certainly do not fall into the
7          category of costs that are beyond the Company’s control. While the underlying
8          costs may change as contracts expire or pricing terms change, there is no reason
9          such costs cannot be addressed in a base rate case.
10   Q.     ARE PACIFICORP’S PACW POWER COSTS SENSTIVE TO CHANGES
11          IN WHOLESALE MARKET PRICES?
12   A.     No. In fact, the two are negatively correlated, based on the GRID model runs I
13          have performed. Because the Company tends to purchase in advance of its need,
14          its short-term firm contract prices would not necessarily change if market prices
15          changed. Based on the GRID model run, a 10% increase in balancing market
16          prices alone results in a decrease in PACW net power costs equal to 21 basis
17          points. If one assumes that all short-term (balancing and firm) prices increase by
18          10%, the Company would experience an 87 basis point reduction in costs.
19   Q.     EXPLAIN THE IMPLICATIONS OF THIS NEGATIVE CORRELATION.
20   A.     These results occur because the Company sells more power than it buys in
21          PACW. Thus, the Company is well insulated from increases in market prices. It
22          can even benefit from such price increases.           Given this very low level of
23          sensitivity to market prices, overall, I see no basis for considering wholesale
24          market price volatility a problem for the Company.
Docket Nos. UE-061546/UE-060817                                                   Page 67
1   Q.     WHAT FACTORS WOULD CAUSE INCREASES IN PACW POWER
2          COSTS?
3   A.     The factors that can drive power costs to increase are the very items that neither
4          the Commission, nor the Company, consider suitable for adjustment clause
5          treatment. A one percent change in loads results in a 55 basis point change in
6          cost. However, sales increases also result in increased margins for the Company
7          offsetting the impact. As a result, the Company includes an adjustment in its
8          PCAM to remove the impact of load changes. The Commission has recognized
9          this issue in the Avista PCAM as well, and uses a comparable adjustment to
10          reverse the impacts of load growth from the ERM. Load growth is far better
11          addressed in a base rate case when new resources are required to serve that
12          growth than in a PCAM.
13   Q.     WHAT OTHER FACTORS DRIVE THE COMPANY’S POWER COSTS?
14   A.     Other factors which would certainly impact power costs include new resources
15          needed to address load growth or the expiration of existing contracts.        For
16          example, the expiration of the TransAlta contract in June 2007 will cause a $45
17          million increase (247 basis points) in PACW power costs according to the GRID
18          model. Under the Company’s PCAM proposal this will amount to a $5 million
19          net increase to Washington, everything else being equal. If the Commission
20          approves the PCAM, it really amounts to approving an additional $5 million
21          automatic rate increase.
22                 Again, the Commission has already stated new resources should not be
23          part of the PCAM. Likewise, termination of a contract such as TransAlta should
24          be considered in the context of a full rate case, to insure the Company has
Docket Nos. UE-061546/UE-060817                                                Page 68
1          prudently planned for replacement power. A PCAM would automatically pass
2          through market purchases as the sole source of replacement power.
3   Q.     DO OUTAGES AFFECT PACIFICORP’S POWER COSTS?
4   A.     As in the case of the Hunter outage in 2001, major plant outages could cause an
5          increase in power costs on a temporary basis. However, it would be inappropriate
6          to simply allow pass-through recovery of the cost of major outages without any
7          review of the reasons for the outage or prudence of the associated costs. Again,
8          even the Company recognized this by including a provision for major outages in
9          its proposal.
10   Q.     WHAT IS YOUR CONCLUSION REGARDING THIS SENSITIVITY
11          ANALYSIS?
12   A.     PacifiCorp does not need the PCAM it proposes because it does not suffer from
13          substantial power cost variability.    While various factors do impact the
14          Company’s power costs, in the end, the only factor driving PacifiCorp’s power
15          cost volatility that is arguably appropriate for a PCAM is hydro. I will address
16          this issue next.
17   Alternative PCAM
18   Q.     ASSUMING THE COMMISSION WISHES TO IMPLEMENT A
19          MECHANISM TO ADDRESS THIS PROBLEM, DO YOU HAVE A
20          PROPOSAL?
21   A.     Yes.   In that case, I would recommend implementation of a “Hydro Hedge
22          PCAM” to simulate a hypothetical hedge agreement between PacifiCorp and its
23          Washington ratepayers. The concept is that ratepayers would be the counterparty
24          to a hedge (much like the Aquila hedge the Company used in prior years).
Docket Nos. UE-061546/UE-060817                                               Page 69
1                   Under this proposal, ratepayers would compensate the Company for a
2          specific dollar amount in the event of poor hydro conditions. The hedge would
3          only be implemented when power costs departed from normal or average
4          conditions by more than one standard deviation from the mean. This approach
5          would be consistent with the “filtered water” methodology discussed above in the
6          power cost modeling section of this testimony.
7                   However, if the Commission adopts this proposal, I recommend that the
8          Commission require the Company to pay ratepayers a “premium” for being the
9          counter party in this hedge with the Company. The level of the premium should
10          equal the reduction to PacifiCorp’s overall cost of capital that occurs as a result of
11          implementing this PCAM. Mr. Gorman has estimated this amount to be $1.2
12          million based on PacifiCorp’s current return on equity.
13   Q.     IS A PREMIUM OF THIS SORT A REASONABLE FEATURE OF THIS
14          HYPOTHETICAL “HYDRO HEDGE” TARIFF?
15   A.     Certainly. PacifiCorp would normally expect to pay a counterparty to enter into
16          such a hedge. For example, PacifiCorp paid Aquila $1.75 million per year as a
17          premium to enter into a hydro hedge over the past several years. I see no reason
18          why ratepayers should assume the risks of a hedge arrangement but not be
19          afforded a fair premium for doing so. Further, the level of the proposed premium
20          is consistent with the Commission’s order in Docket No. UE-050684.53/
“Ratepayers should receive the benefit of a reduction in cost of capital, as a power cost adjustment
introduces rate instability for ratepayers and earnings stability for stockholders[.]” WUTC Docket
No. UE-050684, Order No. 04 at &#182; 91.
Randall J. Falkenberg Direct Testimony                                       Exhibit No.___(RJF-1T)
Docket Nos. UE-061546/UE-060817                                                             Page 70
1   Q.     ARE THERE ANY OTHER ADVANTAGES OF THIS PROPOSAL?
2   A.     Yes.   This proposal would not require determination of PacifiCorp’s actual
3          PACW power costs.       It would deal only with the Washington share of the
4          variances due to hydro costs. These would be allocated to the State on the basis
5          of the CAEW factor. Thus, it sidesteps the jurisdictional allocation problem and
6          deals only with normalized costs, rather than hypothetical actual costs.
7                 Further, it is far more tractable to analyze the impact of a change in cost
8          due to hydro, the issue of PACW costs, overall. Recall that in Docket No.
9          UE-050684, the Commission determined it was possible to develop a deferral for
10          PacifiCorp’s hydro deficit. The same concept would be applied here, except that
11          GRID runs would be used to develop an a priori allocation of hydro cost
12          variances.
13   Q.     DESCRIBE THE STATISTICAL ANALYSIS OF PACIFICORP’S HYDRO
14          GENERATION AND POWER COSTS YOU HAVE PERFORMED TO
15          ILLUSTRATE THE WORKINGS OF THE HYDRO HEDGE TARIFF.
16   A.     Exhibit No.___(RJF-11) shows the analysis underlying the Hydro Hedge PCAM.
17          The proposed Hydro Hedge PCAM would not result in any payments of credits
18          (other than the premium) if the hydro costs impact was less than one standard
19          deviation from the mean.      The proposal would then use a sharing of 50/50
20          between the Company and customers for variations less than two standard
21          deviations, and 85/15 customer/company beyond that. The exhibit shows the
22          payments and credits that would result depending on the actual annual level of
23          hydro generation.
Docket Nos. UE-061546/UE-060817                                                 Page 71
1   Q.     WHAT ARE THE ADVANTAGES OF THIS APPROACH?
2   A.     First, it addresses only costs that are not controllable by the company, related to
3          short-term weather variations. This was one of the guiding principles espoused
4          by the Commission in the Docket No. UE-050684. This approach defines up
5          front the level of risks assumed by customers and limits them to a known amount.
6          Risks are limited to hydro variations, which we all agree are beyond PacifiCorp’s
7          control. Under the Company’s proposed PCAM, there is virtually no limit to the
8          amount and scope of risk that ratepayers assume. I believe it is very unlikely that
9          PacifiCorp could find a counterparty that would hedge unlimited risks and risks of
10          virtually any kind.    Ratepayers should not be required to provide a hedge
11          completely out of line with what is available in the commercial market.
12                 Second, this approach is equitable because it provides a known treatment
13          of hydro cost variations, consistent with the use of the filtered water approach for
14          setting base rates. Third, by use of the sharing bands indicated, the Company will
15          retain incentives to minimize costs, and costs placed on ratepayers will be limited.
16          Finally, ratepayers are not exposed to unlimited cost increases in the case of
17          extremely bad hydro conditions, nor is the Company exposed to unlimited refunds
18          in the case of extremely good hydro conditions.
19   Q.     DOES THIS CONCLUDE YOUR TESTIMONY?
20   A.     Yes.
Docket Nos. UE-061546/UE-060817                                                 Page 72
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