TEL (503) 241-7242 FAX (503) 241-8160 mail@dvclaw.com
Suite 400
333 S.W. Taylor
Portland, OR 97204
December 9, 2005
Via Electronic and US Mail
Public Utility Commission
Attn: Filing Center
550 Capitol St. NE #215
P.O. Box 2148
Salem OR 97308-2148
Re: In the Matter of PUBLIC UTILITY COMMISSION OF OREGON
Staff’s Investigation Related to Electric Utility Purchases from
Qualifying Facilities.
Docket No. UM 1129
Dear Filing Center:
Enclosed please find an original and six copies of the Direct Testimony of
Randall Falkenberg on behalf of the Industrial Customers of Northwest Utilities in the
above-captioned docket.
Please return one file-stamped copy of the document in the self-addressed,
stamped envelope provided. Thank you for your assistance.
Sincerely yours,
/s/ Christian Griffen
Christian W. Griffen
Enclosures
cc: Service List 
BEFORE THE PUBLIC UTILITY COMMISSION
OF OREGON
UM 1129
In the Matter of the
PUBLIC UTILITY COMMISSION OF
OREGON
Staff’s Investigation Related to Electric Utility
Purchases from Qualifying Facilities.
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DIRECT TESTIMONY OF
RANDALL J. FALKENBERG
ON BEHALF OF
THE INDUSTRIAL CUSTOMERS OF NORTHWEST UTILITIES
December 9, 2005
ICNU/200
Falkenberg/1
1 Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
2 A. Randall J. Falkenberg, PMB 362, 8351 Roswell Road, Sandy Springs, Georgia
3 30350.
4 Q. WHAT IS YOUR OCCUPATION AND BY WHOM ARE YOU
5 EMPLOYED?
6 A. I am a utility rate and planning consultant holding the position of President and
7 Principal with the firm of RFI Consulting, Inc. (“RFI”). I am appearing in this
8 proceeding as a witness for the Industrial Customers of Northwest Utilities
9 (“ICNU”).
10 Q. PLEASE BRIEFLY DESCRIBE THE NATURE OF THE CONSULTING
11 SERVICES PROVIDED BY RFI.
12 A. RFI provides consulting services in the electric utility industry. The firm provides
13 expertise in electric restructuring, system planning, load forecasting, financial
14 analysis, cost of service, revenue requirements, rate design, and fuel cost recovery
15 issues.
16 I. QUALIFICATIONS
17 Q. PLEASE DESCRIBE YOUR EDUCATION AND PROFESSIONAL
18 EXPERIENCE.
19 A. Exhibit ICNU/201 describes my education and experience within the utility
20 industry. I have more than 25 years of experience in the industry. I have worked
21 for utilities, both as an employee and as a consultant, and as a consultant to major
22 corporations, state and federal governmental agencies, and public service
23 commissions. I have been directly involved in a large number of rate cases and
24 regulatory proceedings concerning the economics, rate treatment, and prudence of
25 nuclear and non-nuclear generating plants.
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1 During my employment with EBASCO Services in the late 1970s, I developed
2 probabilistic production cost and reliability models used in studies for 20 utilities.
3 I personally directed a number of marginal and avoided cost studies performed for
4 compliance with the Public Utility Regulatory Policies Act of 1978 (“PURPA”).
5 I also participated in a wide variety of consulting projects in the rate, planning,
6 and forecasting areas.
7 In 1982, I accepted the position of Senior Consultant with Energy
8 Management Associates (“EMA”). At EMA, I trained and consulted with
9 planners and financial analysts at several utilities using the PROMOD III and
10 PROSCREEN II planning models.
11 In 1984, I was a founder of J. Kennedy and Associates, Inc. (“Kennedy”).
12 At that firm, I was responsible for consulting engagements in the areas of
13 generation planning, reliability analysis, market price forecasting, stranded cost
14 evaluation, and the rate treatment of new capacity additions. I presented expert
15 testimony on these and other matters in more than 100 cases before the Federal
16 Energy Regulatory Commission (“FERC”) and state regulatory commissions and
17 courts in Arkansas, California, Connecticut, Florida, Georgia, Kentucky,
18 Louisiana, Maryland, Michigan, Minnesota, New Mexico, New York, North
19 Carolina, Ohio, Oregon, Pennsylvania, Texas, Utah, West Virginia, and
20 Wyoming. Included in Exhibit ICNU/201 is a list of my appearances.
21 In January 2000, I founded RFI Consulting, Inc. with a comparable
22 practice to the one I directed at Kennedy.
ICNU/200
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1 Q. HAVE YOU PREVIOUSLY FILED TESTIMONY IN ANY OREGON
2 PUBLIC UTILITY COMMISSION PROCEEDINGS?
3 A. Yes. I have filed testimony in seven PacifiCorp proceedings in Oregon: UE 111 in
4 2000, UE 116 in 2001, UE 134 in 2002 and 2003, UM 995 in 2002, UM 1050 in
5 2004, and UE 170 and UE 173 in 2005. In those cases, I addressed issues related
6 to power cost modeling, power cost deferrals, prudence of new resources, multi-
7 state jurisdictional allocation and a Power Cost Adjustment Mechanism
8 (“PCAM”). I also filed testimony in six Portland General Electric Company
9 (“PGE”) cases: UE 137 and UE 139 in 2002, UE 149 in 2003, UE 161 in 2004,
10 and UE 165/UM 1187 and UE 172 in 2005. In those cases I addressed PGE’s
11 Resource Valuation Mechanism (“RVM”), PGE’s request for a PCAM, and
12 PGE’s proposed Hydro Generation Adjustment (“HGA”) tariff.
13 II. INTRODUCTION AND SUMMARY
14 Q. WHAT IS THE PURPOSE OF THIS TESTIMONY?
15 A. I address PacifiCorp’s compliance filing. Specifically, I discuss issues related to
16 PacifiCorp’s proposed avoided costs tariffs and the calculation of the
17 deficiency/sufficiency period.
18 Q. PLEASE SUMMARIZE YOUR TESTIMONY.
19 A. My recommendations are as follows:
20 1. PacifiCorp’s deficiency/sufficiency calculation is overly complex, and does
21 not reflect the methodologies employed by the Company in its Integrated
22 Resource Plan (“IRP”). The calculation should only consider the annual
23 summer peak, not average energy or the winter peak. The decision to add
24 capacity in the IRP is driven by meeting the annual peak. Based on the
25 summer peak demand, PacifiCorp is deficient in 2005 and beyond.
26 Consequently, prices in Schedule 37 should be based on the cost of a
27 combined cycle plant starting in 2005.
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1 2. I propose that PacifiCorp’s gas-indexed pricing option for Schedule 37 be
2 modified to include an indexed price during the sufficiency period. I propose
3 to specify a Non-Index Cost (“NIC”) representing capacity and market based
4 heat rates applied to the actual Opal gas index prices to determine the avoided
5 cost payment rate for Qualifying Facilities (“QFs”) that opt for the gas-index
6 options. This approach provides a gas indexed rate and identifies the market
7 value of capacity during the sufficiency period, in accordance with
8 Commission Order No. 05-584.
9 3. I present exhibits that detail the specific cost components of PacifiCorp’s
10 avoided costs. This information is necessary for large QFs that are required to
11 negotiate specific QF contracts with the utilities.
12 Sufficiency/Deficiency Period
13 Q. EXPLAIN HOW PACIFICORP DETERMINES WHETHER IT IS IN A
14 RESOURCE SUFFICIENT OR RESOURCE DEFICIENT PERIOD.
15 A. Exhibit ICNU/202 is a copy of PacifiCorp’s load and resource balance
16 calculation. In this analysis, the Company compares available resources to load
17 requirements for average megawatts (i.e., energy), and during the winter and
18 summer peak period. If the Company is sufficient (i.e., if resources exceed loads)
19 for two of the three periods, then the Company considers itself resource sufficient.
20 Currently, the Company’s calculation shows that it is deficient for the summer
21 peak, but sufficient for the winter peak and for energy. Consequently, the
22 Company does not consider itself deficient until 2010. For this reason, the
23 Company proposes to offer only the fixed “market based” rates until the end of
24 2009. In 2010, the Company proposes to begin paying QFs avoided costs based
25 on the proxy cost of a new combined cycle plant.
26 Q. WHAT IS THE BASIS FOR THESE CALCULATIONS?
27 A. The loads and resource data is taken from PacifiCorp’s GRID model runs used to
28 develop avoided costs. For the summer peak, for example, the Company 
ICNU/200
Falkenberg/5
1 computes available resources based on GRID model simulations of capacity
2 available at the time of the summer peak. The Company also includes
3 requirements for long-term and short-term purchases and sales and for operating
4 reserves in these calculations.
5 For average energy, the model determines whether a surplus or deficit
6 exists based on comparison of the annual energy requirement to the GRID
7 simulation of energy production for its various resources.
8 Q. IS THIS A REASONABLE METHOD FOR DETERMINING THE LOAD
9 AND RESOURCE BALANCE OF THE COMPANY?
10 A. This approach bears little resemblance to standard industry practice, is
11 inconsistent with the IRP, and differs substantially from the method used by the
12 Company in its last avoided cost determination.
13 Q. DO THE RESULTS OF THIS APPROACH SEEM REASONABLE?
14 A. No. At a very high level, it seems counter intuitive that the Company can be
15 capacity sufficient when its own figures show it is unable to cover the summer
16 peak demand for the next five years. Further, the Company is actively building
17 new capacity, acquiring new resources, engaging in substantial short-term
18 purchases, and has been doing so for some time. This is not the picture of a
19 company that has a five-year surplus of capacity. Rather, these are all indicators
20 of a company that is short on capacity resources.
21 A major part of the problem is that the Company really considers it
22 irrelevant whether it can meet the summer peak, so long as it can meet the winter
23 peak and annual energy requirements. However, it is generally a fact that a utility 
ICNU/200
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1 that can meet its annual (summer) peak, will also have enough capacity to meet its
2 lesser seasonal (winter) peaks and annual energy requirements.
3 Generally capacity ratings of units are lower in the summer than in the
4 winter, and seasonal peaks, or average energy requirements, are much lower than
5 annual peak requirements. In effect, PacifiCorp requires a dire capacity shortfall
6 to exist (such that it cannot meet peak demands in the both the summer and
7 winter) before it considers itself “deficient.”
8 Q. WHAT IS STANDARD INDUSTRY PRACTICE?
9 A. Typically utilities determine capacity adequacy by examination of the annual
10 system peak, ensuring a reasonable provision for reserves. As a general rule,
11 utilities require sufficient capacity to meet the annual peak demand plus a reserve
12 margin of 15%. This is the approach used by PacifiCorp in its IRP, as is shown
13 on Exhibit ICNU/203 at Falkenberg/3.
14 Q. HOW DOES THIS DIFFER FROM PACIFICORP’S AVOIDED COST
15 APPROACH?
16 A. Aside from ignoring the summer peak, the Company also uses a non-standard
17 approach to compute reserves and capacity available from its resources. In using
18 the GRID model results for available capacity, the Company is using capacity
19 derated for forced outages, and would even exclude capacity on planned
20 maintenance, should any be expected to occur at that time. The Company adds to
21 that amount of operating reserve and load regulation requirements based on
22 GRID’s simulation of North American Electric Reliability Council (“NERC”)
23 requirements.
ICNU/200
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1 This approach confuses planning reserves with operating reserves.
2 Planning reserve requirements encompass not only the need to cover capacity on
3 outages and operating reserves, but also a component for load forecast uncertainty
4 over a period of years. Operating reserves normally encompass only enough load
5 uncertainty for operations during a typical day, and thus provide a much lower
6 provision for load uncertainty.
7 Q. ARE THERE ANY OTHER PROBLEMS ASSOCIATED WITH THE
8 COMPANY’S USE OF GRID?
9 A. Yes. For the average energy calculation, GRID is completely unsuitable. The
10 reason is that GRID simulates the operation of units based on projected market
11 conditions. Gas-fired units do not run fully loaded throughout the year in GRID,
12 so the amount of energy produced by such units may greatly understate the
13 amount of energy potentially available. Ironically, if market prices were
14 projected to drop, the amount of energy available from gas units would decline in
15 GRID. Thus, a drop in market prices could paradoxically result in the appearance
16 of an energy deficiency in the GRID model because balancing energy would be
17 lower in cost than running its own gas units. While I do not believe energy
18 sufficiency is a major issue for the Company, the method used to perform the
calculation is highly suspect.1/
19
20 Q. ARE THERE OTHER PROBLEMS WITH THE PACIFICORP
21 ANALYSIS?
22 A. The Company also includes short-term firm purchases and sales in the analysis.
23 This is troubling for two reasons. First, the Company has no obligation to make

1/
For a utility with a more substantial reliance on hydro, or very high load factors, energy
sufficiency may be an issue that should be considered. However, PacifiCorp obtains a very small
amount of its annual requirements from hydro and does not have high annual load factors.
ICNU/200
Falkenberg/8
1 short-term firm sales. Thus, short-term firm sales do not represent load
2 requirements that the Company has a long-term obligation to plan for. Second,
3 PacifiCorp is constantly changing its short-term firm position. Thus, the forecast
4 of short-term contracts is likely to be very unrealistic and unsuitable for planning
5 purposes.
6 Q. EARLIER YOU MENTIONED THAT PACIFICORP DID NOT USE THE
7 SAME METHODOLOGY FOR DETERMING ITS SUFFICIENCY OR
8 DEFICIENCY AS WHEN IT SET ITS AVOIDED COSTS IN 2001. HOW
9 DOES THE 2005 METHOD DIFFER FROM THE 2001 METHOD?
10 A. There are two important differences. First, PacifiCorp used a 12% planning
11 reserve margin, rather than its operating reserve and regulation requirements in its
12 2001 calculation. Second, the Company did not include short-term firm
13 purchases or sales in 2001.
14 Q. WHAT IS YOUR RECOMMENDATION?
15 A. I recommend the Commission determine that based on the summer peak,
16 PacifiCorp is not resource sufficient in 2005, and as a result, use proxy pricing
17 based on the avoided Combined Cycle Combustion Turbine instead of the fixed
18 price option. Note that if the Commission adopts this proposal it would moot
19 ICNU’s proposal related to gas market pricing during the sufficiency period,
20 discussed above. Should the Commission adopt a later deficiency date, the gas
21 market pricing option discussed earlier should be implemented during the
22 sufficiency period.
23 Gas Index Pricing
24 Q. DID THE COMMISSION REQUIRE UTILITIES TO OFFER A GAS
25 INDEXED RATE IN ORDER NO. 05-584?
26 A. Yes. The Commission stated as follows:
ICNU/200
Falkenberg/9
1 All three electric utilities shall offer the same three pricing options,
2 as follows: (1) the Fixed Price Method; (2) the Deadband Method;
3 and (3) the Gas Market Method. We adopt each of these
4 methodologies, as defined by Staff. We delegate implementation
5 decisions to each utility but direct each utility to work with Staff,
6 as appropriate, to develop implementation tariffs and standard
7 contract rates, terms and conditions.
8 Re Staff’s Investigation Relating to Electric Utility Purchases from Qualifying
9 Facilities, OPUC Docket No. UM 1129, Order No. 05-584 at 34-35 (May 13,
10 2005) (“Order No. 05-584”).
11 Q. HAS PACIFICORP OFFERED THE GAS MARKET METHOD AND
12 DEADBAND PRICING OPTIONS IN SCHEDULE 37?
13 A. Yes. PacifiCorp has offered both options. However, these rate options are not
14 indexed to gas prices during the sufficiency period (2005 to 2009). Consequently,
15 QFs have only the fixed price option for the first five years. ICNU believes it
16 would be appropriate to also offer the gas market indexed rates during the
17 sufficiency period.
18 Q. DID STAFF DEFINE THE GAS MARKET INDEX PRICING METHODS
19 TO APPLY ONLY DURING THE DEFICIENCY PERIOD?
20 A. That is not obvious from the Staff testimony filed in Phase 1. In reviewing the
21 testimony of Staff witness Steve Chriss earlier in this proceeding, I did not find
22 any discussion indicating that the gas indexed option should apply only during the
23 deficiency period. Thus, Staff’s intentions on this matter in Phase I were not
24 completely clear from the filed testimony. Consequently, I believe the
25 Commission should decide this issue in this phase of the proceeding. Based on
26 the above-quoted passage, it is clear that the Commission’s intention was to
27 provide QFs gas market pricing options. If the rates are only indexed to gas
ICNU/200
Falkenberg/10
1 during the deficiency period, then PacifiCorp’s rates approved by the Commission
2 in this proceeding may not have an effective gas index pricing option for five
3 years.
4 Q. ARE THERE OTHER REASONS WHY THE COMMISSION SHOULD
5 ADDRESS THIS ISSUE?
6 A. Yes. The Commission left two issues open for further review in this phase of the
7 proceeding. First, the Commission invited parties to further elucidate the issue of
the market value of capacity during the sufficiency period.2/
8 Second, the
9 Commission encouraged the parties to develop a market indexed pricing option
for PacifiCorp.3/
10 Both of these areas of inquiry can be further developed through
11 proper development of a gas indexed rate. Finally, the Commission directed that
12 the details of the gas-indexed rate would be a subject for this phase of the
13 proceeding.
14 Q. EXPLAIN HOW THE GAS MARKET INDEX ISSUE IS TIED TO THE
15 ISSUE OF THE MARKET VALUE OF CAPACITY.
16 A. The wholesale market price for power is largely determined by two factors: the
17 underlying market value of capacity and the price of natural gas. This occurs
18 because natural gas is frequently the marginal fuel during the High Load Hour
19 (“HLH”) period. Thus, variations in gas prices will naturally result in increases in
20 wholesale power prices. Further, the market places a premium upon capacity as it
21 becomes deficit, increasing its cost over the value of marginal gas-fired

2/
“To the extent that a party can provide evidence regarding the market pricing of capacity,
however, we remain open to reconsideration of this decision in the next phase of this proceeding.”
Order No. 05-584 at 28.
3/
“We direct PacifiCorp, however, to work with Staff to evaluate whether it would be appropriate to
develop an indexed pricing option and encourage either Staff or PacifiCorp to offer an indexed
pricing option for PacifiCorp in the second phase of this proceeding.” Id. at 35.
ICNU/200
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1 generation in the market. Conversely, if capacity is surplus, then the marginal
2 cost of generation will track gas prices more closely. When capacity is short, then
3 the cost of power in the market will increase well above the variable cost of
4 marginal gas-fired energy.
5 Q. DO YOU HAVE ANY EVIDENCE THAT DEMONSTRATES THIS
6 POINT?
7 A. Yes. Exhibit ICNU/204 presents a graph showing the comparison of market
8 prices for power (HLH) based on PacifiCorp’s CG27 forward curve, and the cost
9 of natural gas, translated to cents per kilowatt hour (“kWh”) by use of a market
10 heat rate. The heat rate was determined based on the average cost of energy
11 during the Low Load Hour (“LLH”). This was chosen because it is unlikely that
12 LLH power would contain a substantial capacity component.
13 The chart shows that the market price for HLH power tracks gas prices.
14 The correlation coefficient p=.66. This is substantial and indicates statistically
15 significant correlation of electric prices and the gas market index. However,
16 during the summer peak months (July through September) and during the winter
17 peak months (December through February) a premium over the underlying gas
18 price is present in the HLH power price. During the late spring “fish flush”
19 month (which generally occurs in May and June), hydro generation is maximized,
20 thus resulting in a negative capacity premium. As a result, the difference between
21 monthly HLH power prices and the underlying cost of marginal gas-fired
22 generation can be seen to follow a predictable seasonal pattern that follows the
23 need for capacity in the market place.
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1 Q. HOW DOES DEVELOPMENT OF A GAS MARKET INDEX DURING
2 THE SUFFICIENCY PERIOD FURTHER THE COMMISSION’S GOAL
3 OF DEVELOPING A MARKET INDEXED RATE FOR PACIFICORP?
4 A. While a gas market index rate is not exactly the same as a wholesale power
5 market index type rate, it would be a means of addressing the same concerns as
6 those that might motivate the Commission to propose a wholesale market index.
7 One problem with fixed price rates is that underlying gas and power prices can
8 move substantially in a very short period of time. Recent experience concerning
9 the hurricanes in the Gulf of Mexico shows that short-term effects can be
10 substantial. Regulators would understandably be reluctant to update forecasts in
11 response to such events. Then again, ignoring such substantial price movements
12 may also result in inequitable and inefficient rates. Thus, a fixed price rate leaves
13 the Commission with the dilemma of when to update rates, and when to leave
14 them alone. Because gas and electric prices generally move in tandem, use of a
15 gas market index rate would provide a means of avoiding the need for updates to
16 avoided costs between the Commission’s ordinary two-year cycle when economic
17 conditions change.
18 Further, a gas price index could give gas-fired QFs a better price signal, as
19 they would have a better sense of their prospects for supplying generation to
20 PacifiCorp, irrespective of the movements in gas prices.
21 Q. WHAT ARE THE SPECIFICS OF ICNU’S GAS MARKET RATE
22 PROPOSAL?
23 A. Exhibit ICNU/205 presents the specifics of this proposal. ICNU proposes to
24 develop the Actual Gas Price Used (“AGPU”) as the actual gas market index
25 price (Opal) times an annual heat rate, as shown on the table. The Non-Index 
ICNU/200
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1 Costs (“NIC”) is also shown on the table. Over the 5 year sufficiency period, the
2 market heat rate would average 7,849 btu/kWh, while the NIC would average
3 $1.04 cents per kWh.
4 Q. HOW WERE THE PRICE COMPONENTS DEVELOPED?
5 A. These price components were developed directly from PacifiCorp’s fixed prices
6 during the sufficiency period and the Company CG27 gas price forecast. The
7 LLH market price was assumed to have no capacity component, and was used to
8 calibrate the annual market heat rate. The NIC, computed as the difference
9 between the LLH and HLH fixed prices, can reasonably be assumed to represent
10 the market value of capacity during the sufficiency period. The NIC would only
11 apply to HLH kWhs actually generated. Thus, this pricing method would
12 compensate QFs for generation based on energy provided during the HLH via the
13 NIC, and gas-fired generation during all hours based on the implicit market heat
14 rate. If PacifiCorp’s gas price forecast is perfectly realized, the prices developed
15 under this option will equal PacifiCorp’s fixed prices for the period 2005 to 2009.
16 Q. WOULD IT BE POSSIBLE TO DEVELOP A PRICING FORMAT THAT
17 PROVIDED MORE TARGETED PRICE SIGNALS?
18 A. Certainly, and ICNU would not object to a reasonable refinement of this analysis.
19 However, PacifiCorp’s fixed prices are not differentiated by month or season. For
20 that reason I do not further differentiate these rates either. ICNU is willing to
21 explore other options on this issue, so long as a gas market based rate is available
22 during the sufficiency period.
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1 Q. ASIDE FROM REDUCING THE NEED FOR INTERIM UPDATES, ARE
2 THERE OTHER ADVANTAGES TO THIS PROPOSAL?
3 A. Certainly. A gas market based rate will provide a more equitable result between
4 customers and QFs. It should be fairly clear by now that gas and electric prices
5 are quite volatile. Forecasts can easily become “obsolete” just a few months after
6 they have been prepared. By offering a price that indexes to natural gas, the
7 Commission can be more confident that customers will not be overcharged if gas
8 prices drop, nor will QFs be underpaid if gas prices go up.
9 Avoided Cost Components
10 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?
11 A. In this section I present certain exhibits to document the methodology and
12 assumptions used by PacifiCorp in computing the avoided cost based prices for
13 Schedule 37. This information is important for large QFs that will be required to
14 negotiate specific QF contracts with the Company. The starting point for these
15 negotiations is always the Commission’s published tariff. In the past, there has
16 been a lack of clarity concerning the actual assumptions and method used by the
17 Company to compute avoided costs, which has created problems in the
18 negotiations for large QFs. The exhibits I present are intended to address this
19 problem.
20 Q. DESCRIBE THESE EXHIBITS.
21 A. Exhibit ICNU/206 presents a series of data request answers (ICNU Set 6, Data
22 Request Nos. 1-4 and 8-15) that document some of PacifiCorp’s basic
23 assumptions concerning avoided costs. These responses show how the Company
24 defines the inputs for natural gas and wholesale power prices, points of delivery
ICNU/200
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1 and other assumptions. Exhibit ICNU/207 documents the assumptions used by
2 the Company in the deficiency period, while Exhibit ICNU/208 provides the same
3 for the sufficiency period.
4 Q. DO YOU PROPOSE SIMILAR EXHIBITS FOR IDAHO POWER AND
5 PORTLAND GENERAL ELECTRIC COMPANY (“PGE”)?
6 A. No. I did not perform the analysis. However, such information may be necessary
7 for large QFs that wish to enter into QF contracts with Idaho Power or PGE. I
8 recommend that both Idaho Power and PGE file such information in their rebuttal
9 testimony.
10 Revised Protocol
11 Q. ICNU AND WEYERHAEUSER RAISED THE ISSUE OF WHETHER
12 PACIFICORP’S AVOIDED COST FILING WAS CONSISTENT WITH
13 THE REVISED PROTOCOL. DOES YOUR TESTIMONY ADDRESS
14 THIS ISSUE?
15 A. Yes. Under the Revised Protocol, costs associated with payments to QFs that
16 exceed the cost of a comparable market resource are allocated on a situs rather
17 than system basis. Because avoided costs are determined in each state at a
18 different time, there may be a disparity in each state’s avoided cost rates. To
19 ensure that these differences are not confused as being due to Oregon paying
20 above avoided costs, the Commission should find that the prices determined in
21 this proceeding are equal to those of a comparable market resource, as defined in
22 the Revised Protocol. As a result, there should be no basis for a situs allocation of
23 QF costs for rates based on Oregon’s standard tariff. The Commission’s finding
24 should not impact its review of the prudence of any specific resource acquisitions.
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1 Q. PACIFICORP HAS PROPOSED DEFERRING THIS ISSUE UNTIL THE
2 TIME THE COMPANY SEEKS COST RECOVERY. DO YOU THINK IT
3 IS APPROPRIATE TO POSTPONE CONSIDERATION OF THIS ISSUE?
4 A. No. ICNU continues to believe that it would be more appropriate to address this
5 issue outside of a rate proceeding in which the revenue requirement impacts
6 regarding the cost recovery of the QF resources may guide some parties’ positions
7 on this issue. In addition, ICNU believes that all the parties will benefit from an
8 expedited resolution of this issue.
9 Q. DO YOU HAVE ANYTHING ELSE TO ADD?
10 A. Yes. My testimony only addresses a limited number of issues. However, silence
11 on any particular issue does not imply ICNU is in agreement with the utility
12 proposals. ICNU may address additional issues in its post-hearing brief or in
13 rebuttal testimony.
14 Q. DOES THIS CONCLUDE YOUR TESTIMONY?
15 A. Yes.
ICNU/201
Randall Falkenberg Qualifications
ICNU/201
Falkenberg/1

RFI CONSULTING, INC.
QUALIFICATIONS OF RANDALL J. FALKENBERG, PRESIDENT

EDUCATIONAL BACKGROUND
I received my Bachelor of Science degree with Honors in Physics and a minor in mathematics from Indiana
University. I received a Master of Science degree in Physics from the University of Minnesota. My thesis
research was in nuclear theory. At Minnesota I also did graduate work in engineering economics and
econometrics. I have completed advanced study in power system reliability analysis.
PROFESSIONAL EXPERIENCE
After graduating from the University of Minnesota in 1977, I was employed by Minnesota Power as a Rate
Engineer. I designed and coordinated the Company's first load research program. I also performed load studies
used in cost-of-service studies and assisted in rate design activities.
In 1978, I accepted the position of Research Analyst in the Marketing and Rates department of Puget Sound
Power and Light Company. In that position, I prepared the two-year sales and revenue forecasts used in the
Company's budgeting activities and developed methods to perform both near- and long-term load forecasting
studies.
In 1979, I accepted the position of Consultant in the Utility Rate Department of Ebasco Service Inc. In 1980, I
was promoted to Senior Consultant in the Energy Management Services Department. At Ebasco I performed
and assisted in numerous studies in the areas of cost of service, load research, and utility planning. In
particular, I was involved in studies concerning analysis of excess capacity, evaluation of the planning
activities of a major utility on behalf of its public service commission, development of a methodology for
computing avoided costs and cogeneration rates, long-term electricity price forecasts, and cost allocation
studies.
At Ebasco, I specialized in the development of computer models used to simulate utility production costs,
system reliability, and load patterns. I was the principal author of production costing software used by eighteen
utility clients and public service commissions for evaluation of marginal costs, avoided costs and production
costing analysis. I assisted over a dozen utilities in the performance of marginal and avoided cost studies
related to the PURPA of 1978. In this capacity, I worked with utility planners and rate specialists in
quantifying the rate and cost impact of generation expansion alternatives. This activity included estimating
carrying costs, O&M expenses, and capital cost estimates for future generation.
In 1982 I accepted the position of Senior Consultant with Energy Management Associates, Inc. and was
promoted to Lead Consultant in June 1983. At EMA I trained and consulted with planners and financial
ICNU/201
Falkenberg/2

RFI CONSULTING, INC.
QUALIFICATIONS OF RANDALL J. FALKENBERG, PRESIDENT

analysts at several utilities in applications of the PROMOD and PROSCREEN planning models. I assisted
planners in applications of these models to the preparation of studies evaluating the revenue requirements and
financial impact of generation expansion alternatives, alternate load growth patterns and alternate regulatory
treatments of new baseload generation. I also assisted in EMA's educational seminars where utility personnel
were trained in aspects of production cost modeling and other modern techniques of generation planning.
I became a Principal in Kennedy and Associates in 1984. Since then I have performed numerous economic
studies and analyses of the expansion plans of several utilities. I have testified on several occasions regarding
plant cancellation, power system reliability, phase-in of new generating plants, and the proper rate treatment of
new generating capacity. In addition, I have been involved in many projects over the past several years
concerning the modeling of market prices in various regional power markets.
In January 2000, I founded RFI Consulting, Inc. whose practice is comparable to that of my former firm, J.
Kennedy and Associates, Inc.
The testimony that I present is based on widely accepted industry standard techniques and methodologies, and
unless otherwise noted relies upon information obtained in discovery or other publicly available information
sources of the type frequently cited and relied upon by electric utility industry experts. All of the analyses that
I perform are consistent with my education, training and experience in the utility industry. Should the source
of any information presented in my testimony be unclear to the reader, it will be provided it upon request by
calling me at 770-379-0505.
PAPERS AND PRESENTATIONS
Mid-America Regulatory Commissioners Conference - June 1984: "Nuclear Plant Rate
Shock - Is Phase-In the Answer"
Electric Consumers Resource Council - Annual Seminar, September 1986: "Rate Shock,
Excess Capacity and Phase-in"
The Metallurgical Society - Annual Convention, February 1987: "The Impact of Electric
Pricing Trends on the Aluminum Industry"
Public Utilities Fortnightly - "Future Electricity Supply Adequacy: The Sky Is Not Falling"
 What Others Think, January 5, 1989 Issue
Public Utilities Fortnightly - "PoolCo and Market Dominance", December 1995 Issue
ICNU/201
Falkenberg/3

RFI CONSULTING, INC.
QUALIFICATIONS OF RANDALL J. FALKENBERG, PRESIDENT

APPEARANCES
3/84 8924 KY Airco Carbide Louisville CWIP in rate base.
Gas & Electric
5/84 830470- FL Florida Industrial Fla. Power Corp. Phase-in of coal unit, fuel
EI Power Users Group savings basis, cost
allocation.
10/84 89-07-R CT Connecticut Ind. Connecticut Excess capacity.
Energy Consumers Light & Power
11/84 R-842651 PA Lehigh Valley Pennsylvania Phase-in of nuclear unit.
 Power Committee Power & Light Co.
2/85 I-840381 PA Phila. Area Ind. Philadelphia Economics of
cancellation of Energy Users' Group Electric Co. nuclear generating units.
3/85 Case No. KY Kentucky Industrial Louisville Gas Economics of cancelling fossil
9243 Utility Consumers & Electric Co. generating units.
3/85 R-842632 PA West Penn West Penn Power Economics of pumped storage
Power Industrial Co. generating units, optimal
 Intervenors res. margin, excess capacity.
3/85 3498-U GA Georgia Public Georgia Power Co. Nuclear unit cancellation,
 Service Commission load and energy forecasting,
 Staff generation economics.
5/85 84-768- WV West Virginia Monongahela Power Economics - pumped storage
E-42T Multiple Co. generating units, reserve
Intervenors margin, excess capacity.
7/85 E-7, NC Carolina Industrial Duke Power Co. Nuclear economics, fuel cost
SUB 391 Group for Fair projections.
Utility Rates
7/85 9299 KY Kentucky Union Light, Heat Interruptible rate design.
Industrial Utility & Power Co.
Consumers
8/85 84-249-U AR Arkansas Electric Arkansas Power & Prudence review.
Energy Consumers Light Co.
1/86 85-09-12 CT Connecticut Ind. Connecticut Light Excess capacity, financial
 Energy Consumers & Power Co. impact of phase-in nuclear
plant.
1/86 R-850152 PA Philadelphia Area Philadelphia Phase-in and economics of
Industrial Energy Electric Co. nuclear plant.
Users' Group
2/86 R-850220 PA West Penn Power West Penn Power Optimal reserve margins,
 Industrial prudence, off-system sales
Intervenors guarantee plan.
5/86 86-081- WV West Virginia Energy Monongahela Power Generation planning study ,
E-GI Users' Group Co. economics prudence of a pumped
storage hydroelectric unit.
5/86 3554-U GA Attorney General & Georgia Power Co. Cancellation of nuclear
 Georgia Public plant.
ICNU/201
Falkenberg/4

RFI CONSULTING, INC.
Expert Testimony Appearances
of
Randall J. Falkenberg

Date Case Jurisdict. Party Utility Subject
Service Commission
Staff
9/86 29327/28 NY Occidental Chemical Niagara Mohawk Avoided cost, production
 Corp. Power Co. cost models.
9/86 E7- NC NC Industrial Duke Power Co. Incentive fuel adjustment
Sub 408 Energy Committee clause.
12/86 9437/ KY Attorney General Big Rivers Elect. Power system reliability
613 of Kentucky Corp. analysis, rate treatment of
excess capacity.
5/87 86-524- WV West Virginia Energy Monongahela Power Economics and rate treatment
E-SC Users' Group of Bath County pumped storage
County Pumped Storage Plant.
6/87 U-17282 LA Louisiana Gulf States Prudence of River Bend
 Public Service Utilities Nuclear Plant.
Commission Staff
6/87 PUC-87- MN Eveleth Mines Minnesota Power/ Sale of generating
013-RD & USX Corp. Northern States unit and reliability
E002/E-015 Power requirements.
-PA-86-722
7/87 Docket KY Attorney General Big Rivers Elec. Financial workout plan for
9885 of Kentucky Corp. Big Rivers.
8/87 3673-U GA Georgia Public Georgia Power Co. Nuclear plant prudence audit,
Service Commission Vogtle buyback expenses.
Staff
10/87 R-850220 PA WPP Industrial West Penn Power Need for power and economics,
Intervenors County Pumped Storage Plant
10/87 870220-EI FL Occidental Chemical Fla. Power Corp. Cost allocation methods and
interruptible rate design.
10/87 870220-EI FL Occidental Chemical Fla. Power Corp. Nuclear plant performance.
1/88 Case No. KY Kentucky Industrial Louisville Gas & Review of the current status
9934 Utility Consumers Electric Co. of Trimble County Unit 1.
3/88 870189-EI FL Occidental Chemical Fla. Power Corp. Methodology for evaluating
 Corp. interruptible load.
5/88 Case No. KY National Southwire Big Rivers Elec. Debt restructuring
10217 Aluminum Co., Corp. agreement.
ALCAN Alum Co.
7/88 Case No. LA Louisiana Public Gulf States Prudence of River Bend
325224 Div. I Service Commission Utilities Nuclear Plant.
 19th Staff
Judicial
District
10/88 3780-U GA Georgia Public Atlanta Gas Light Weather normalization gas
Service Commission Co. sales and revenues.
Staff
10/88 3799-U GA Georgia Public United Cities Gas Weather normalization of gas
Service Commission Co. sales and revenues.
Staff
ICNU/201
Falkenberg/5

RFI CONSULTING, INC.
Expert Testimony Appearances
of
Randall J. Falkenberg

Date Case Jurisdict. Party Utility Subject
12/88 88-171- OH Ohio Industrial Toledo Edison Co., Power system reliability
EL-AIR Energy Consumers Cleveland Electric reserve margin.
88-170- OH Illuminating Co.
EL-AIR
1/89 I-880052 PA Philadelphia Area Philadelphia Nuclear plant outage,
Industrial Energy Electric Co. replacement fuel cost
Users' Group recovery.
2/89 10300 KY Green River Steel K Kentucky Util. Contract termination clause
and interruptible rates.
3/89 P-870216 PA Armco Advanced West Penn Power Reserve margin, avoided
283/284/286 Materials Corp., costs.
Allegheny Ludlum Corp.
5/89 3741-U GA Georgia Public Georgia Power Co. Prudence of fuel procurement.
Service Commission
Staff
8/89 3840-U GA Georgia Public Georgia Power Co. Need and economics coal &
Service Commission nuclear capacity, power system
Staff planning.
10/89 2087 NM Attorney General of Public Service Co. Power system planning,
 New Mexico of New Mexico economic and reliability
analysis, nuclear planning,
prudence.
10/89 89-128-U AR Arkansas Electric Arkansas Power Economic impact of asset
 Energy Consumers Light Co. transfer and stipulation and
settlement agreement.
11/89 R-891364 PA Philadelphia Area Philadelphia Sale/leaseback nuclear plant,
Industrial Energy Electric Co. excess capacity, phase-in
Users' Group delay imprudence.
1/90 U-17282 LA Louisiana Public Gulf States Sale/leaseback nuclear power
Service Commission Utilities plant.
 Staff
4/90 89-1001- OH Industrial Energy Ohio Edison Co. Power supply reliability,
EL-AIR Consumers excess capacity adjustment.
4/90 N/A N.O. New Orleans New Orleans Public Municipalization of investorBusiness
Counsel Service Co. owned utility, generation
planning & reliability
7/90 3723-U GA Georgia Public Atlanta Gas Light Weather normalization
Service Commission Co. adjustment rider.
 Staff
9/90 8278 MD Maryland Industrial Baltimore Gas & Revenue requirements gas &
Group Electric Co. electric, CWIP in rate base.
9/90 90-158 KY Kentucky Industrial Louisville Gas & Power system planning study.
Utility Consumers Electric Co.
12/90 U-9346 MI Association of Consumers Power DSM Policy Issues.
Businesses Advocating
Tariff Equity (ABATE)
5/91 3979-U GA Georgia Public Georgia Power Co. DSM, load forecasting
Service Commission and IRP.
ICNU/201
Falkenberg/6

RFI CONSULTING, INC.
Expert Testimony Appearances
of
Randall J. Falkenberg

Date Case Jurisdict. Party Utility Subject
Staff
7/91 9945 TX Office of Public El Paso Electric Power system planning,
Utility Counsel Co. quantification of damages
of imprudence,
environmental cost of
electricity
8/91 4007-U GA Georgia Public Georgia Power Co. Integrated resource planning,
Service Commission regulatory risk assessment.
Staff
11/91 10200 TX Office of Public Texas-New Mexico Imprudence disallowance.
 Utility Counsel Power Co.
12/91 U-17282 LA Louisiana Public Gulf States Year-end sales and customer
Service Commission Utilities adjustment, jurisdictional
Staff allocation.
1/92 89-783- WVA West Virginia Monongahela Power Avoided cost, reserve margin,
E-C Energy Users Group Co. power plant economics.
3/92 91-370 KY Newport Steel Co. Union Light, Heat Interruptible rates, design,
& Power Co. cost allocation.
5/92 91890 FL Occidental Chemical Fla. Power Corp. Incentive regulation,
Corp. jurisdictional separation,
interruptible rate design.
6/92 4131-U GA Georgia Textile Georgia Power Co. Integrated resource planning,
Manufacturers Assn. DSM.
9/92 920324 FL Florida Industrial Tampa Electric Co. Cost allocation, interruptible
 Power Users Group rates decoupling and DSM.
10/92 4132-U GA Georgia Textile Georgia Power Co. Residential conservation
Manufacturers Assn. program certification.
10/92 11000 TX Office of Public Houston Lighting Certification of utility
Utility Counsel and Power Co. cogeneration project.
11/92 U-19904 LA Louisiana Public Entergy/Gulf Production cost savings
Service Commission States Utilities from merger.
Staff (Direct)
11/92 8469 MD Westvaco Corp. Potomac Edison Co. Cost allocation, revenue
distribution.
11/92 920606 FL Florida Industrial Statewide Decoupling, demand-side
Power Users Group Rulemaking management, conservation,
Performance incentives.
12/92 R-009 PA Armco Advanced West Penn Power Energy allocation of
22378 Materials production costs.
1/93 8179 MD Eastalco Aluminum/ Potomac Edison Co. Economics of QF vs. combined
 Westvaco Corp. cycle power plant.
2/93 92-E-0814 NY Occidental Chemical Niagara Mohawk Special rates, wheeling.
88-E-081 Corp. Power Corp.
3/93 U-19904 LA Louisiana Public Entergy/Gulf Production cost savings from
Service Commission States Utilities merger.
Staff (Surrebuttal)
ICNU/201
Falkenberg/7

RFI CONSULTING, INC.
Expert Testimony Appearances
of
Randall J. Falkenberg

Date Case Jurisdict. Party Utility Subject
4/93 EC92 FERC Louisiana Public Gulf States GSU Merger prodcution cost
21000 Service Commission Utilities/Entergy savings
ER92-806-000 Staff
6/93 930055-EU FL Florida Industrial Statewide Stockholder incentives for
Power Users' Group Rulemaking off-system sales.
9/93 92-490, KY Kentucky Industrial Big Rivers Elec. Prudence of fuel procurement
92-490A, Utility Customers Corp. decisions.
90-360-C & Attorney General
9/93 4152-U GA Georgia Textile Georgia Power Co. Cost allocation of pollution
Manufacturers Assn. control equipment.
4/94 E-015/ MN Large Power Minn. Power Co. Analysis of revenue req.
GR-94-001 Intervenors and cost allocation issues.
4/94 93-465 KY Kentucky Industrial Kentucky Utilities Review and critique proposed
Utility Customers environmental surcharge.
4/94 4895-U GA Georgia Textile Georgia Power Co Purchased power agreement
 Manufacturers Assn. and fuel adjustment clause.
4/94 E-015/ MN Large Power Minnesota Power Rev. requirements, incentive
GR-94-001 Intervenors Light Co. compensation.
7/94 94-0035- WV West Virginia Monongahela Power Revenue annualization, ROE
 E-42T Energy Users' Co. performance bonus, and cost
Group allocation.
8/94 8652 MD Westvaco Corp. Potomac Edison Co. Revenue requirements, ROE
performance bonus, and
revenue distribution.
1/95 94-332 KY Kentucky Industrial Louisville Gas Environmental surcharge.
Utility Customers & Electric Company
1/95 94-996- OH Industrial Energy Ohio Power Company Cost-of-service, rate design,
EL-AIR Users of Ohio demand allocation of power
3/95 E999-CI MN Large Power Minnesota Public Environmental Costs
Intervenor Utilities Comm. Of electricity
4/95 95-060 KY Kentucky Industrial Kentucky Utilities Six month review of
Utility Customers Company CAAA surcharge.
11/95 I-940032 PA The Industrial Statewide - Direct Access vs. Poolco,
Energy Consumers of all utilities market power.
Pennsylvania
11/95 95-455 KY Kentucky Industrial Kentucky Utilities Clean Air Act Surcharge,
12/95 95-455 KY Kentucky Industrial Louisville Gas Clean Air Act Compliance
Utility Customers & Electric Company Surcharge.
6/96 960409-EI FL Florida Industrial Tampa Electric Co. Polk County Power Plant
Power Users Group Rate Treatment Issues.
3/97 R-973877 PA PAIEUG. PECO Energy Stranded Costs & Market
Prices.
3/97 970096-EQ FL FIPUG Fla. Power Corp. Buyout of QF Contract
ICNU/201
Falkenberg/8

RFI CONSULTING, INC.
Expert Testimony Appearances
of
Randall J. Falkenberg

Date Case Jurisdict. Party Utility Subject
6/97 R-973593 PA PAIEUG PECO Energy Market Prices, Stranded
Cost
7/97 R-973594 PA PPLICA PP&L Market Prices, Stranded
Cost
8/97 96-360-U AR AEEC Entergy Ark. Inc. Market Prices and Stranded
Costs, Cost Allocation,
Rate Design
10/97 6739-U GA GPSC Staff Georgia Power Planning Prudence of Pumped
Storage Power Plant

10/97 R-974008 PA MIEUG Metropolitan Ed. Market Prices, Stranded
R-974009 PICA PENELEC Costs
11/97 R-973981 PA WPII West Penn Power Market Prices, Stranded
 Costs
11/97 R-974104 PA DII Duquesne Light Co. Market Prices, Stranded
 Costs
2/98 APSC 97451 AR AEEC Generic Docket Regulated vs. Market Rates,
 97452 Rate Unbundling, Timetable
 97454 for Competition.
7/98 APSC 87-166 AR AEEC Entergy Ark. Inc. Nuclear decommissioning
cost estimates & rate
treatment.
9/98 97-035-01 UT DPS and CCS PacifiCorp Net Power Cost Stipulation,
Production Cost Model Audit
12/98 19270 TX OPC HL&P Reliability, Load Forecasting
4/99 19512 TX OPC SPS Fuel Reconciliation
4/99 99-02-05 CT CIEC CL&P Stranded Costs, Market Prices
4/99 99-03-04 CT CIEC UI Stranded Costs, Market Prices
6/99 20290 TX OPC CP&L Fuel Reconciliation
7/99 99-03-36 CT CIEC CL&P Interim Nuclear Recovery
7/99 98-0453 WV WVEUG AEP & APS Stranded Costs, Market Prices
12/99 21111 TX OPC EGSI Fuel Reconciliation
2/00 99-035-01 UT CCS PacifiCorp Net Power Costs, Production
Cost Modeling Issues
5/00 99-1658 OH AK Steel CG&E Stranded Costs, Market Prices
6/00 UE-111 OR ICNU PacifiCorp Net Power Costs, Production
Cost Modeling Issues
9/00 22355 TX OPC Reliant Energy Stranded cost
10/00 22350 TX OPC TXU Electric Stranded cost
10/00 99-263-U AR Tyson Foods SW Elec. Coop Cost of Service
12/00 99-250-U AR Tyson Foods Ozarks Elec. Coop Cost of Service
01/01 00-099-U AR Tyson Foods SWEPCO Rate Unbundling
ICNU/201
Falkenberg/9

RFI CONSULTING, INC.
Expert Testimony Appearances
of
Randall J. Falkenberg

Date Case Jurisdict. Party Utility Subject
02/01 99-255-U AR Tyson Foods Ark. Valley Coop Rate Unbundling
03/01 UE-116 OR ICNU PacifiCorp Net Power Costs
6/01 01-035-01 UT DPS and CCS PacifiCorp Net Power Costs
7/01 A.01-03-026 CA Roseburg FP PacifiCorp Net Power Costs
7/01 23550 TX OPC EGSI Fuel Reconciliation
7/01 23950 TX OPC Reliant Energy Price to beat fuel factor
8/01 24195 TX OPC CP&L Price to beat fuel factor
8/01 24335 TX OPC WTU Price to beat fuel factor
9/01 24449 TX OPC SWEPCO Price to beat fuel factor
10/01 20000-EP WY WIEC PacifiCorp Power Cost Adjustment
01-167 Excess Power Costs
2/02 UM-995 OR ICNU PacifiCorp Cost of Hydro Deficit
2/02 00-01-37 UT CCS PacifiCorp Certification of Peaking
Plant
4/02 00-035-23 UT CCS PacifiCorp Cost of Plant Outage, Excess
 Power Cost Stipulation.
4/02 01-084/296 AR AEEC Entergy Arkansas Recovery of Ice Storm Costs
5/02 25802 TX OPC TXU Energy Escalation of Fuel Factor
5/02 25840 TX OPC Reliant Energy Escalation of Fuel Factor
5/02 25873 TX OPC Mutual Energy CPL Escalation of Fuel Factor
5/02 25874 TX OPC Mutual Energy WTU Escalation of Fuel Factor
5/02 25885 TX OPC First Choice Escalation of Fuel Factor
7/02 UE-139 OR ICNU Portland General Power Cost Modeling
8/02 UE-137 OP ICNU Portland General Power Cost Adjustment Clause
10/02 RPU-02-03 IA Maytag, et al Interstate P&L Hourly Cost of Service Model
11/02 20000-Er WY WIEC PacifiCorp Net Power Costs,
02-184 Deferred Excess Power Cost
12/02 26933 TX OPC Reliant Energy Escalation of Fuel Factor
12/02 26195 TX OPC Centerpoint Energy Fuel Reconciliation
1/03 27167 TX OPC First Choice Escalation of Fuel Factor
1/03 UE-134 OR ICNU PacifiCorp West Valley CT Lease payment
1/03 27167 TX OPC First Choice Escalation of Fuel Factor
1/03 26186 TX OPC SPS Fuel Reconciliation
2/03 UE-02417 WA ICNU PacifiCorp Rate Plan Stipulation,
Deferred Power Costs
ICNU/201
Falkenberg/10

RFI CONSULTING, INC.
Expert Testimony Appearances
of
Randall J. Falkenberg

Date Case Jurisdict. Party Utility Subject
2/03 27320 TX OPC Reliant Energy Escalation of Fuel Factor
2/03 27281 TX OPC TXU Energy Escalation of Fuel Factor
2/03 27376 TX OPC CPL Retail Energy Escalation of Fuel Factor
2/03 27377 TX OPC WTU Retail Energy Escalation of Fuel Factor
3/03 27390 TX OPC First Choice Escalation of Fuel Factor
4/03 27511 TX OPC First Choice Escalation of Fuel Factor
4/03 27035 TX OPC AEP Texas Central Fuel Reconciliation
05/03 03-028-U AR AEEC Entergy Ark., Inc. Power Sales Transaction
7/03 UE-149 OR ICNU Portland General Power Cost Modeling
8/03 28191 TX OPC TXU Energy Escalation of Fuel Factor
11/03 20000-ER WY WIEC PacifiCorp Net Power Costs
-03-198
2/04 03-035-29 UT CCS PacifiCorp Certification of CCCT Power
Plant, RFP and Bid Evaluation
6/04 29526 TX OPC Centerpoint Stranded cost true-up.
6/04 UE-161 OR ICNU Portland General Power Cost Modeling
7/04 UM-1050 OR ICNU PacifiCorp Jurisdictional Allocation
10/04 15392-U GA Calpine Georgia Power/ Fair Market Value of Combined
15392-U SEPCO Cycle Power Plant
12/04 04-035-42 UT CCS PacifiCorp Net power costs
02/05 UE-165 OP ICNU Portland General Hydro Adjustment Clause
05/05 UE-170 OR ICNU PacifiCorp Power Cost Modeling
7/05 UE-172 OR ICNU Portland General Power Cost Modeling
08/05 UE-173 OR ICNU PacifiCorp Power Cost Adjustment
8/05 UE-050482 WA ICNU Avista Power Cost modeling,
 Energy Recovery Mechanism
8/05 31056 TX OPC AEP Texas Central Stranded cost true-up.
11/05 UE-05684 WA ICNU PacifiCorp Power Cost modeling,
 Jurisdictional Allocation, PCA
ICNU/202
PacifiCorp’s Load and Resource
Balance Calculation
Exhibit ICNU/202
PacifiCorp Load and Resource Balance
Loads and Resources
Calendar Years 2005 through 2010
2005 2006 2007 2008 2009 2010
aMW
Net Load 6,324 6,509 6,669 6,827 6,991 7,129
Long Term Sales 562 498 359 331 261 226
Short Term Firm Sales 1,536 819 556 37 - -
Total Requirements 8,422 7,827 7,585 7,195 7,252 7,355
Long Term Purchases 1,483 1,493 1,346 933 923 837
Short Term Firm Purchase 1,066 225 28 - 14 -
Thermal Generation 5,563 5,779 6,003 6,102 6,087 6,008
Other Generation 502 536 541 536 528 526
Reserves (163) (136) (238) (231) (233) (331)
Total Resources after Reserves 8,451 7,898 7,680 7,340 7,319 7,040
Surplus / (Deficit) 29 71 95 146 66 (315)
Percent Surplus / (Deficit) 0.3% 0.9% 1.2% 2.0% 0.9% -4.3%
Peak (Summer) August July July July July July
Net Load 8,430 8,841 9,094 9,424 9,718 10,072
Long Term Sales 844 839 556 518 409 373
Short Term Firm Sales 969 475 312 37 - -
Total Requirements 10,244 10,154 9,962 9,979 10,127 10,445
Long Term Purchases 2,089 1,957 1,648 1,473 1,482 1,391
Short Term Firm Purchase 1,025 575 200 - 100 -
Thermal Generation 6,478 6,697 7,193 7,009 7,009 7,009
Other Generation 645 639 639 630 621 616
Reserves (553) (577) (935) (889) (889) (977)
Total Resources after Reserves 9,683 9,290 8,745 8,223 8,323 8,039
Surplus / (Deficit) (561) (864) (1,217) (1,756) (1,804) (2,406)
Percent Surplus / (Deficit) -5.5% -8.5% -12.2% -17.6% -17.8% -23.0%
Peak (December)
Net Load 7,771 8,027 8,247 8,457 8,651 8,909
Long Term Sales 817 503 500 465 356 320
Short Term Firm Sales 944 1,100 312 37 - -
Total Requirements 9,532 9,630 9,060 8,960 9,007 9,230
Long Term Purchases 2,516 2,542 2,149 2,370 2,317 2,284
Short Term Firm Purchase 513 300 - - - -
Thermal Generation 6,537 6,768 7,303 7,113 7,113 7,113
Other Generation 880 857 893 885 885 879
Reserves (523) (576) (937) (895) (891) (982)
Total Resources after Reserves 9,923 9,892 9,408 9,473 9,424 9,294
Surplus / (Deficit) 391 261 349 513 416 65
Percent Surplus / (Deficit) 4.1% 2.7% 3.8% 5.7% 4.6% 0.7%
ljh Ore Commission Approved - AC Study (8.9.2005).xls ( Table 1 ) 11/15/2005 2:29 PM
ICNU/203
Excerpt of PacifiCorp’s
Integrated Resource Plan






ICNU/204
Comparison of Market Gas and
Electric Prices
Exhibit ICNU/204: Market Gas vs. Electric Prices
$0
$90
$80
$70
$60
$50
$40
$30
$20
$10
Jun-05
Aug-05
Oct-05
Dec-05
Feb-06
Apr-06
Jun-06
Aug-06
Oct-06
Dec-06
Feb-07
Apr-07
Jun-07
Aug-07
Oct-07
Dec-07
Feb-08
Apr-08
Jun-08
Aug-08
Oct-08
Dec-08
Feb-09
Apr-09
Jun-09
Aug-09
Oct-09
Dec-09
H
W
M/ $
Power, p = .66
Gas at 7,849 Heat Rate
ICNU/205
Gas Index Avoided Cost Rate
 Exhibit ICNU/205
Gas Index Avoided Cost Rate
 Heat Rate in BTU/KWH
=============$/MWH========== Opal Index Heat
Year HLH LLH Capacity (NIC) $/MMBTU Rate
2005 71.27 59.81 11.45 7.18 8,326
2006 63.58 52.69 10.89 6.96 7,571
2007 59.59 48.73 10.86 6.38 7,636
2008 55.79 46.34 9.45 5.90 7,853
2009 52.60 43.31 9.29 5.51 7,859
Avg. 60.57 50.18 10.39 6.39 7,849
ICNU/206
Excerpt of PacifiCorp’s Response to
ICNU’s Sixth Set of Data Requests












ICNU/207
PacifiCorp Pricing Methodology and Input
Exhibit ICNU/207
Documentation of PacifiCorp Pricing Methodology and Inputs
Brief Explanation of PacifiCorp's Avoided Cost Rates
Sufficiency Period: 2005-2009; Deficiency Period : Post 2009
During the sufficiency period, avoided costs are the hub weighted average market price.
In the deficiency period, avoided costs equal the capital and energy cost of a new (Eastern) CCCT.
= (CC Capital Cost)* Payment Factor + O&M+ Heat Rate* Gas Price
Capital Costs are largely allocated to the on peak period. Set to be recoverable if the QF has the same
Capacity Factor (CF) as the PacifiCorp plant. The capital and O&M costs are indexed with inflation.
The fixed rate uses PacifiCorp's gas forecast, while the indexed rate uses the actual gas market index.
The banded indexed rate is designed to vary with market but has ceilings and floors within 10% of
PacifiCorp's forecast.
Sources, Inputs and Assumptions
SCCT Statistics MW Percent Cap Cost Fixed Var Heat Rate
Greenfield Intercooled Aero SCCT 87 100% 590 8.11 7.21 8,907
(Used only for split between on and off peak capacity rate. Very little is off peak.)
CCCT Statistics (Utah S Mona) MW Percent Cap Cost Fixed
Brownfield CCCT (Dry Cooling 2x1) 420 80% 682 6.01
Brownfield CCCT Duct Firing for Dry Cooling 105 2x1 20% 207 4.28
Capacity Weighted 525 100% 587 5.66
(Used to establish capacity payment in deficiency period.)
CCCT Statistics (Utah S Mona) MW CF aMW Percent Var Heat Rate
Brownfield CCCT (Dry Cooling 2x1) 420 56% 235 93% 5.50 7,462
Brownfield CCCT Duct Firing for Dry Cooling 105 2x1 16% 17 7% 3.06 9,512
Energy Weighted 525 48% 252 100% 5.34 7,599
(Used to establish energy rate in deficiency period.) Rounded 7,600
SCCT CCCT
8.98% 7.93% Payment Factor - IRP Table C.28 (January 2005)
16% 48% Capacity Factor - IRP Table C.28 (January 2005)
84.2% Capacity Factor - On-peak 48% / 57% (percent of hours on-peak)
8,907 7,600 Heat Rate in btu/kWh - IRP Table C.27 (January 2005)
2.02% 2004-2010 Inflation Rate - 2004 IRP, Appendix C, Table C.1
2.94% 2011-2020 Inflation Rate - 2004 IRP, Appendix C, Table C.1
3.48% 2021-2030 Inflation Rate - 2004 IRP, Appendix C, Table C.1
(Used to index rate components to inflation.)
ICNU/208
PacifiCorp Sufficiency Period Fixed Prices
Exhibit ICNU/208
Documentation of PacifiCorp Sufficiency Period Fixed Prices
Sufficiency Period Fixed Rate Calculation
The fixed price during the sufficiency period equals the hub-weighted average price for each
month based on PacifiCorp's forward curves for three hubs - Mid Columbia, COB and Palo Verde.
The hub weights vary monthly based on PacifiCorp's GRID model study, which increases supply
in Oregon by 50 MW around the clock. The weights are computed by the Company based
on the differences in purchases and sales at each market "bubble" modeled in GRID. The forward
prices are defined by the Company as shown in the attached data responses. Annual fixed
prices are the average of the monthly hub weighted prices. These prices do not include or provide any
allowance for losses, transmission costs or other factors. The prices used are based on PacifiCorp's March 31,
2005 forward price curve CG27 as documented in the IRP. The forward prices used and the
montly weighted average are shown below.
FPC FPC FPC FPC FPC FPC Weighted average
ELEC ELEC ELEC ELEC ELEC ELEC Weighted by the
COB N-S COB N-S PV PV MID-C MID-C Difference in system
balancing transactions
Between GRID runs
Wtd Average
Forward Prices
Start End HLH LLH HLH LLH HLH LLH HLH LLH
06/01/05 07/01/05 $68.25 $55.50 $73.25 $47.00 $63.25 $54.25 $64.99 $53.90
07/01/05 08/01/05 $79.75 $64.10 $87.00 $55.34 $74.25 $63.75 $75.11 $62.99
08/01/05 09/01/05 $83.74 $66.69 $88.00 $55.88 $79.00 $65.25 $80.09 $64.86
09/01/05 10/01/05 $75.76 $63.46 $77.00 $51.54 $71.00 $60.75 $72.03 $60.61
10/01/05 11/01/05 $69.60 $57.34 $68.60 $51.39 $66.00 $55.34 $66.26 $55.57
11/01/05 12/01/05 $71.78 $60.39 $69.30 $53.25 $67.50 $58.91 $68.40 $58.87
12/01/05 01/01/06 $76.85 $65.27 $72.10 $55.11 $72.00 $64.26 $72.02 $61.90
01/01/06 02/01/06 $77.48 $68.58 $75.71 $55.64 $74.03 $66.07 $74.38 $62.14
02/01/06 03/01/06 $76.74 $63.50 $74.24 $54.04 $71.91 $63.60 $72.37 $60.44
03/01/06 04/01/06 $69.29 $58.42 $70.56 $51.36 $65.57 $55.58 $65.95 $55.07
04/01/06 05/01/06 $59.40 $50.00 $58.59 $41.90 $54.88 $47.60 $55.13 $47.08
05/01/06 06/01/06 $53.35 $41.15 $60.48 $42.75 $47.04 $40.08 $47.07 $40.66
06/01/06 07/01/06 $52.25 $41.60 $68.67 $43.61 $46.06 $37.58 $49.97 $38.92
07/01/06 08/01/06 $71.05 $55.58 $84.09 $52.28 $61.20 $53.91 $63.70 $54.45
08/01/06 09/01/06 $76.18 $61.43 $85.31 $52.79 $73.44 $58.45 $74.07 $58.95
09/01/06 10/01/06 $72.52 $58.50 $74.34 $48.69 $69.36 $57.89 $70.21 $58.01
10/01/06 11/01/06 $64.44 $51.00 $64.19 $46.80 $59.97 $49.06 $60.02 $49.16
11/01/06 12/01/06 $66.45 $53.71 $64.85 $49.24 $61.86 $52.22 $62.60 $52.28
12/01/06 01/01/07 $71.15 $58.05 $67.47 $50.70 $67.54 $56.97 $67.53 $55.16
01/01/07 02/01/07 $71.76 $61.83 $71.59 $50.96 $67.99 $59.12 $68.30 $55.41
02/01/07 03/01/07 $71.07 $57.25 $70.20 $49.49 $66.05 $56.91 $66.35 $54.33
03/01/07 04/01/07 $64.17 $52.67 $66.72 $47.04 $60.22 $49.73 $60.51 $49.63
04/01/07 05/01/07 $56.43 $48.31 $56.73 $41.72 $53.99 $45.89 $54.29 $45.58
05/01/07 06/01/07 $50.68 $39.76 $58.56 $39.29 $42.09 $38.64 $43.00 $38.96
06/01/07 07/01/07 $49.64 $40.19 $66.49 $40.50 $41.18 $36.23 $41.72 $37.35
07/01/07 08/01/07 $67.66 $51.08 $80.47 $49.28 $57.83 $48.69 $63.91 $49.68
08/01/07 09/01/07 $72.54 $56.93 $81.64 $49.79 $69.39 $52.79 $71.28 $54.20
09/01/07 10/01/07 $69.05 $54.00 $71.14 $45.69 $65.54 $52.28 $66.53 $52.97
10/01/07 11/01/07 $60.96 $46.50 $61.86 $43.80 $56.29 $45.80 $56.57 $45.87
11/01/07 12/01/07 $62.87 $49.21 $62.49 $46.24 $58.07 $48.76 $59.01 $48.80
12/01/07 01/01/08 $67.31 $53.55 $65.02 $47.70 $63.40 $53.19 $63.58 $51.98
COB Palo Verde Mid-Columbia
Forward Prices Forward Prices Forward Prices
This curve represents
PacifiCorp's Official
Base Case Market Curve
CG27. It is a blend of
the 03-31-05 forward
market curve and Midas
curve CG27, which was
completed on 03-18-05.
Exhibit ICNU/208
Documentation of PacifiCorp Sufficiency Period Fixed Prices
01/01/08 02/01/08 $66.76 $59.08 $67.84 $47.71 $63.24 $56.12 $63.68 $53.67
02/01/08 03/01/08 $66.07 $54.50 $66.45 $46.24 $61.30 $53.91 $61.58 $52.94
03/01/08 04/01/08 $59.17 $49.92 $62.97 $43.79 $55.47 $46.73 $55.86 $48.13
04/01/08 05/01/08 $51.43 $45.56 $52.98 $38.47 $49.24 $42.89 $49.47 $43.89
05/01/08 06/01/08 $45.68 $37.01 $54.81 $36.04 $37.34 $35.64 $38.83 $36.44
06/01/08 07/01/08 $44.64 $37.44 $62.74 $37.25 $36.43 $33.23 $40.64 $34.56
07/01/08 08/01/08 $62.66 $48.33 $76.72 $46.03 $53.08 $45.69 $62.96 $46.63
08/01/08 09/01/08 $67.54 $54.18 $77.89 $46.54 $64.64 $49.79 $67.95 $51.54
09/01/08 10/01/08 $64.05 $51.25 $67.39 $42.44 $60.79 $49.28 $62.27 $50.11
10/01/08 11/01/08 $55.96 $43.75 $58.11 $40.55 $51.54 $42.80 $53.14 $43.18
11/01/08 12/01/08 $57.87 $46.46 $58.74 $42.99 $53.32 $45.76 $54.02 $46.03
12/01/08 01/01/09 $62.31 $50.80 $61.27 $44.45 $58.65 $50.19 $59.09 $48.94
01/01/09 02/01/09 $63.26 $55.83 $64.59 $45.46 $59.99 $53.12 $60.84 $50.79
02/01/09 03/01/09 $62.57 $51.25 $63.20 $43.99 $58.05 $50.91 $58.48 $49.77
03/01/09 04/01/09 $55.67 $46.67 $59.72 $41.54 $52.22 $43.73 $52.51 $44.94
04/01/09 05/01/09 $47.93 $42.31 $49.73 $36.22 $45.99 $39.89 $46.19 $40.85
05/01/09 06/01/09 $42.18 $33.76 $51.56 $33.79 $34.09 $32.64 $35.82 $33.18
06/01/09 07/01/09 $41.14 $34.19 $59.49 $35.00 $33.18 $30.23 $38.40 $31.91
07/01/09 08/01/09 $59.16 $45.08 $73.47 $43.78 $49.83 $42.69 $59.32 $43.74
08/01/09 09/01/09 $64.04 $50.93 $74.64 $44.29 $61.39 $46.79 $64.04 $48.45
09/01/09 10/01/09 $60.55 $48.00 $64.14 $40.19 $57.54 $46.28 $58.91 $46.99
10/01/09 11/01/09 $52.46 $40.50 $54.86 $38.30 $48.29 $39.80 $49.99 $40.14
11/01/09 12/01/09 $54.37 $43.21 $55.49 $40.74 $50.07 $42.76 $50.70 $42.91
12/01/09 01/01/10 $58.81 $47.55 $58.02 $42.20 $55.40 $47.19 $55.99 $46.05
PAGE 1 – CERTIFICATE OF SERVICE
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that I have this day served the Direct Testimony of
Randall Falkenberg on behalf of the Industrial Customers of Northwest Utilities upon the
parties, shown below, on the official service list by causing the foregoing document to be
deposited, postage-prepaid, in the U.S. Mail, or by service via electronic mail to those
parties who waived paper service.
DATED at Portland, Oregon, this 9th day of December, 2005.
DAVISON VAN CLEVE, P.C.
/s/ Christian Griffen
Christian W. Griffen
SARAH J ADAMS LIEN
STOEL RIVES LLP
900 SW FIFTH AVE - STE 2600
PORTLAND OR 97204-1268
sjadamslien@stoel.com
MARK ALBERT
VULCAN POWER COMPANY
1183 NW WALL ST STE G
BEND OR 97701
malbert@vulcanpower.com
RANDY ALLPHIN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
rallphin@idahopower.com
MICK BARANKO
DOUGLAS COUNTY FOREST PRODUCTS
PO BOX 848
WINCHESTER OR 97495
mick@dcfp.com
R THOMAS BEACH
CROSSBORDER ENERGY
2560 NINTH ST - STE 316
BERKELEY CA 94710
tomb@crossborderenergy.com
LAURA BEANE
PACIFICORP
825 MULTNOMAH STE 800
PORTLAND OR 97232-2153
laura.beane@pacificorp.com
KARL BOKENKAMP
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
kbokenkamp@idahopower.com
LOWREY R BROWN
CITIZENS' UTILITY BOARD OF OREGON
610 SW BROADWAY - STE 308
PORTLAND OR 97205
lowrey@oregoncub.org
JOANNE M BUTLER
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
jbutler@idahopower.com
BRIAN COLE
SYMBIOTICS, LLC
PO BOX 1088
BAKER CITY OR 97814
bc@orbisgroup.org
PAGE 2 – CERTIFICATE OF SERVICE
BRUCE CRAIG
ASCENTERGY CORP
440 BENMAR DR STE 2230
HOUSTON TX 77060
bcraig@asc-co.com
RANDY CROCKET
D R JOHNSON LUMBER COMPANY
PO BOX 66
RIDDLE OR 97469
randyc@drjlumber.com
CHRIS CROWLEY
COLUMBIA ENERGY PARTNERS
100 E 19TH STE 400
VANCOUVER WA 98663
ccrowley@columbiaep.com
DATA REQUEST RESPONSE CENTER
PACIFICORP
825 NE MULTNOMAH - STE 800
PORTLAND OR 97232
datarequest@pacificorp.com
CAREL DE WINKEL
OREGON DEPARTMENT OF ENERGY
625 MARION STREET NE
SALEM OR 97301
carel.dewinkel@state.or.us
CRAIG DEHART
MIDDLEFORK IRRIGATION DISTRICT
PO BOX 291
PARKDALE OR 97041
mfidcraig@hoodriverelectric.net
ELIZABETH DICKSON
HURLEY, LYNCH & RE, PC
825 NE MULTNOMAH - STE 800
BEND OR 97702
eadickson@hlr-law.com
JASON EISDORFER
CITIZENS' UTILITY BOARD OF OREGON
610 SW BROADWAY STE 308
PORTLAND OR 97205
jason@oregoncub.org
JOHN M ERIKSSON
STOEL RIVES LLP
900 SW FIFTH AVE - STE 2600
PORTLAND OR 97204-1268
jmeriksson@stoel.com
J RICHARD GEORGE
PORTLAND GENERAL ELECTRIC COMPANY
121 SW SALMON ST
PORTLAND OR 97204
richard.george@pgn.com
JOHN R GALE
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
rgale@idahopower.com
DAVID HAWK
J R SIMPLOT COMPANY
PO BOX 27
BOISE ID 83707
david.hawk@simplot.com
THOMAS M GRIM
CABLE HUSTON BENEDICT ET AL
1001 SW FIFTH AVE STE 2000
PORTLAND OR 97204-1136
tgrim@chbh.com
BARTON L KLINE
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
bkline@idahopower.com
STEVEN C JOHNSON
CENTRAL OREGON IRRIGATION DISTRICT
2598 NORTH HIGHWAY 97
REDMOND OR 97756
stevej@coid.org
MONICA B MOEN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
mmoen@idahopower.com
ALAN MEYER
WEYERHAEUSER COMPANY
698 12TH ST - STE 220
SALEM OR 97301-4010
alan.meyer@weyerhaeuser.com
JANET L PREWITT
DEPARTMENT OF JUSTICE
1162 COURT ST NE
SALEM OR 97301-4096
janet.prewitt@doj.state.or.us
PAGE 3 – CERTIFICATE OF SERVICE
THOMAS H NELSON
THOMAS H NELSON & ASSOCIATES
825 NE MULTNOMAH STE 925
PORTLAND OR 97232
nelson@thnelson.com
PGE-OPUC FILINGS RATES & REGULATORY
AFFAIRS
PORTLAND GENERAL ELECTRIC COMPANY
121 SW SALMON ST 1WTC0702
PORTLAND OR 97204
pge.opuc.filings@pgn.com
LISA F RACKNER
ATER WYNNE LLP
222 SW COLUMBIA ST STE 1800
PORTLAND OR 97201-6618
lfr@aterwynne.com
PETER J RICHARDSON
RICHARDSON & O'LEARY
PO BOX 7218
BOISE ID 83707
peter@richardsonandoleary.com
DON READING
BEN JOHNSON ASSOCIATES
6070 HILL ROAD
BOISE ID 83703
dreading@mindspring.com
LISA C SCHWARTZ
PUBLIC UTILITY COMMISSION OF OREGON
PO BOX 2148
SALEM OR 97308-2148
lisa.c.schwartz@state.or.us
MARK TALLMAN
PACIFICORP
825 MULTNOMAH STE 800
PORTLAND OR 97232-2153
mark.tallman@pacificorp.com
MICHAEL T WEIRICH
DEPARTMENT OF JUSTICE
REGULATED UTILITY & BUSINESS SECTION
1162 COURT ST NE
SALEM OR 97301-4096
michael.weirich@state.or.us
BRUCE A WITTMANN
WEYERHAEUSER
MAILSTOP: CH 1K32
PO BOX 9777
FEDERAL WAY WA 98063-9777
bruce.wittmann@weyerhaeuser.com
LINDA K WILLIAMS
KAFOURY & MCDOUGAL
10266 SW LANCASTER RD
PORTLAND OR 97219-6305
linda@lindawilliams.net
MICHAEL YOUNGBLOOD
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707
myoungblood@idahopower.com
PAUL WOODIN
WESTERN WIND POWER
282 LARGENT LN
GOLDENDALE WA 98620-3519
pwoodin@gorge.net
 davido.extraxim@gmail.com