Johnson Testimony.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE INVESTIGATION)
OF THE CONTINUED REASONABLENESS OF)
CURRENT SIZE LIMITATIONS FOR PURPA) CASE NO. GNR-E-02-1
QF PUBLISHED RATE ELIGIBILITY )
(i.e., 1 MW) AND RESTRICTIONS ON )
CONTRACT LENGTH (i.e., 5 YEARS ) )
)

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

JAY K. JOHNSON

JOHNSON, DI 1
Idaho Power Company

Q. Please state your name and business address 1
for the record. 2
A. My name is Jay K. Johnson. My business 3
address is 303 Second Street, Suite 700 North, San 4
Francisco, California. 5
Q. By whom are you employed and in what 6
capacity? 7
A. I am Vice President and Area Manager for PB 8
Power, Inc. PB Power is a Parsons Brinckerhoff Company. 9
Parsons Brinkerhoff is a global engineering company with 10
over 250 offices and 9,200 employees. PB Power has 11
engineered more than 75,000 MW of power at over 300 sites 12
around the world. 13
Q. What is your educational and professional 14
background? 15
A. I received a Bachelor of Science Degree in 16
Mechanical Engineering from the University of California, 17
Berkeley in 1971. I am a professional engineer registered 18
in California, Connecticut and Arizona. A more detailed 19
description of PB Power’s experience and my professional 20
experience is attached to my testimony as Exhibit 101. 21
Q. What is the purpose of your testimony in 22
this proceeding? 23
JOHNSON, DI 2
Idaho Power Company

A. Several months ago Idaho Power requested 1
that PB Power prepare a report which would provide a 2
current estimate of the cost of constructing and operating 3
a state-of-the-art 250 MW combined cycle combustion turbine 4
sited in the vicinity of Boise, Idaho. They indicated that 5
they were concerned that some of the cost assumptions 6
currently used to compute their published avoided cost 7
rates were outdated and they wanted me to provide more 8
recent information. Included with my prefiled testimony as 9
Exhibit 102 is a copy of the report PB Power submitted to 10
Idaho Power in June of this year. The purpose of my 11
testimony is to sponsor Exhibit 102 and to explain why I 12
believe that the cost data presented in Exhibit 102 fairly 13
represents the fixed and variable (excluding fuel) costs 14
that Idaho Power would incur if it were to construct and 15
operate a 250 MW, base-loaded combined cycle combustion 16
turbine commencing operation in 2002. 17
Q. Could you please describe the specific CCCT 18
which forms the basis for the costs contained in Exhibit 19
102. 20
A. The plant configuration is assumed to be a 21
combined cycle plant using a single General Electric Frame 22
7FB combustion turbine generator and a single reheat steam 23
JOHNSON, DI 3
Idaho Power Company

turbine generator. The Frame 7FB represents GE’s latest 1
upgrade to the 7FA, which went into production in 1994. 2
The plant is configured with a three pressure HRSG and 3
includes reheat and combustion turbine inlet air 4
evaporative cooling to optimize plant performance. Air 5
emission control equipment includes an SCR and CO catalyst 6
to minimize NOx and CO emissions. The plant is designed 7
for a northern climate with the CTG and STG indoors. An 8
assumption was made that natural gas compression would be 9
required. Two 100% capacity gas compressors are included. 10
Because of regional concerns for water usage, two 11
cooling options were considered. The first was a 12
conventional multiple cell mechanical draft cooling tower. 13
This option provides the best overall plant performance at 14
the lowest price. The second option considered was an air 15
cooled condenser. This option minimizes water usage, but 16
at a higher capital cost and at a reduction in overall 17
plant performance. 18
The estimated capital cost of the facility 19
described above is as follows: 20
Cooling Tower Option: $173,500,000 21
Air Cooled Option: $181,400,000 22
Dividing each option by the annual average net power output 23
JOHNSON, DI 4
Idaho Power Company

results in the following cost per kilowatt in 2002 dollars: 1
Cooling Tower Option: $686/kW 2
Air Cooled Option: $729/kW 3
Q. Please describe how the estimated capital 4
cost of the facility described in your previous answer was 5
computed. 6
A. The capital cost estimate was prepared using 7
Thermoflow’s PEACE software and adjusting the equipment 8
pricing based upon pricing information obtained from recent 9
projects. The PEACE software uses the heat balance model 10
created in GTPRO as the basis of equipment sizing and then 11
applies cost factors for equipment pricing, labor, bulk 12
materials, equipment rental, construction supervision, 13
engineering, procurement, startup and plant commissioning. 14
In addition, “soft costs” were included for interest during 15
construction, legal and financing expenses, permitting, 16
insurance, bonds, spare parts, administrative expenses and 17
contingencies. An allowance was also included for the 18
natural gas pipeline interconnect and the electrical 19
transmission interconnect. 20
Excluded costs included land, land leases 21
and taxes as these costs may or may not be applicable. 22
Q. How did you determine the performance of the 23
JOHNSON, DI 5
Idaho Power Company

selected CCCT? 1
A. I prepared heat balances for the cycle using 2
the Thermoflow software, GTPRO. This software contains the 3
latest performance data on a wide range of combustion 4
turbines including GE’s Frame 7FB. The combustion turbine 5
performance is matched with an HRSG and a condensing steam 6
turbine to develop the power cycle. Site specific 7
meteorological data was obtained for the Boise area and 8
this data was used to predict the performance of this plant 9
configuration at this location. The annual average 10
temperature and humidity for the Boise area is 51F dry bulb 11
and 56% relative humidity. The site elevation was assumed 12
to be 2,842 ft above sea level. 13
Once the annual average heat rate was 14
calculated for each option, a degradation factor of 1.75% 15
was added to account for unrecoverable losses between 16
overhauls. The resulting annual average heat rates with 17
degradation applied are as follows: 18
Cooling Tower Option: 6,899 Btu/kwhr HHV 19
Air Cooled Option: 6,994 Btu/kwhr HHV 20
Q. How did you determine the annual O&M costs 21
for the facility? 22
A. Annual O&M costs were estimated using 23
JOHNSON, DI 6
Idaho Power Company

historical data from operating plants and by including the 1
cost of a long term maintenance contract (LTMC) for the 2
CTG. Cost data for the LTMC was obtained from GE. Costs 3
were included for the replacement of the SCR catalyst and 4
the CO catalyst as well as for consumables such as ammonia, 5
cooling tower chemicals and water treatment chemicals. The 6
plant was staffed for base load operation and allowance was 7
included for spare parts. 8
Q. Have you compared the estimated site-9
specific costs of the CCCT presented in Exhibit 102 with 10
cost estimates from other, more generic sources? 11
A. Yes, Idaho Power advised me that they had 12
utilized generic data from the U.S. Department of Energy’s 13
Annual Energy Outlook (AEO) in making resource cost 14
comparisons in their 2002 Integrated Resource Plan and 15
asked me to compare the costs presented in Exhibit 102 with 16
cost estimates made in the Annual Energy Outlook 2002. 17
Q. What was the outcome of that comparison? 18
A. The AEO 2002 report, Table 38, Cost and 19
Performance Characteristics of New Electric Generating 20
Technologies, indicates a cost of $435/kW for a 21
conventional gas/oil combined cycle plant in the 250 MW 22
size range. The report references several sources 23
JOHNSON, DI 7
Idaho Power Company

including various sources from industry, government and the 1
Department of Energy National Laboratories. The costs 2
provided were exclusive of interest charges, but there was 3
no specific listing as to the breakdown of the estimate. 4
This cost per kW compares closely with the $436/kW listed 5
in the Gas Turbine World (GTW) Handbook 1998-1999. Closer 6
review of the GTW figure indicates that the budget cost of 7
$436/kW is for a basic, no frills plant and does not 8
include soft costs such as interest during construction, 9
legal and financing expenses, permitting expenses, 10
insurance, bonds, spare parts, administrative expenses and 11
contingency allowance. In addition no allowances were 12
included for utility interconnects, buildings, pollution 13
control equipment, gas compression or a plant distributed 14
control system. 15
In order to arrive at an all-in cost per 16
kilowatt it is necessary to include all reasonable soft 17
costs, typical interconnect costs, site specific costs and 18
a contingency, which I did in our estimate. 19
The AEO 2002 Report includes a variable O&M 20
cost of .52 mills/kWh and a fixed O&M cost of $15.61/kW. 21
The estimated annual O&M cost, assuming 92% availability 22
and 250 MW net output is $4,950,000 per year. Our estimate 23
JOHNSON, DI 8
Idaho Power Company

for the variable O&M is 3.3 mills/kWh and the fixed O&M is 1
$9.50/kW. The estimated annual O&M cost is $9,020,000 per 2
year. 3
It is difficult to determine the cause of 4
the differences between the estimates, since the AEO Report 5
does not define how the O&M costs are calculated. However, 6
it should be noted that we have included a LTSC in our 7
estimate, which accounts for half the annual O&M cost and 8
we have included the replacement costs of the SCR and CO 9
catalysts, which may not have been accounted for in the AEO 10
Report. 11
Q. In your expert opinion are the cost 12
estimates contained in Exhibit 102 reasonable for a CCCT 13
sited in the Boise vicinity in 2002? 14
A. Yes. 15
Q. Does this conclude your direct testimony? 16
A. Yes, it does. 17