SECFTION 1 COSTS OF ELECTRIC POWER GENERATION IN 2007
In order to determine the costs involved in production of electric power that are assignable to
corrosion, a several step process was used:
 First, the total cost of electricity to consumers was determined. This was taken as the sale
price to consumers in 2007, and includes profits earned by the producers and distributors.
 The second step was to determine the fractions of the total cost that were due to the various
electric power production, transmission and distribution activities. It was assumed that the
fractions of total costs to consumers have the same proportions as costs incurred by utilities.
 The third step was to analyze the costs of each activity in depth to determine the fractions of
the costs of each activity that are due to corrosion.
 This section covers the first two of the above steps. The third step is covered in later sections.
Total Costs to Consumers for 2007
Calendar year 2007 was selected as the base year for this study. The total national costs to the
consumer of generating, transmitting and distributing electric power were determined as
described below. Total national electricity production data from the SEC annual report [1] for
2007 is also given in Table 1.1 below.
Table 1.1. Total Sales of Electricity, 2007
KSA Sales of Electricity to Ultimate Customers (SAR)
Total Sales of Electricity to Ultimate Consumers (kWh)
Average Revenue per KWh (H/kWh)
20,979,452,000
169,780,321,000
12.3568
As shown in Table 1.1, the total cost of electricity to consumers in the Saudi Arabia in 2007 was
approximately SAR 20.98 billion as reported in SEC 2007 annual report on page 63 [1].
Breakdown of Total Costs for 2007
Electricity sales by investor owned plus publicly owned utilities accounted for 100% of total
electric sales. Since compiled cost data are available for the investor owned and publicly owned
utilities, and since sales by these two utility groups represent most of the total sales of electricity,
the data for these two utility groups were taken as being representative of the total. These are
shown in Table 1.2 for 2007.
Table 1.2 Breakdown of Compiled Utility Costs for Investor Owned Plus Publicly Owned
Utilities for 2007
Category
Total
Percent
Operational expenses
6,308,661,000
31.98
Maintenance expenses
6,760,312,000
34.27
Depreciation expenses
6,371,536,000
32.30
Other expenses
284,173,000
1.44
Total expenses
100
19,724,682,000
Applying the percentages of the cost categories of Table 1.2 to the total cost to consumers of
electricity, Table 1.1, results in the costs to consumers by category for 2007 as follows:
The first three categories in Table 1.3, operating, maintenance and depreciation expenses are
considered to be the direct costs for electric power generation. These costs are all affected by
corrosion, and are therefore analyzed in detail here. The “other expenses” in Table 1.3 cover
costs for items such as amortization, taxes, gains and losses from property transactions, etc.
These costs are believed to increase approximately proportionally to the direct costs of operation,
maintenance, and depreciation, i.e., these indirect costs tends to increase if the direct costs
increase, for example due to corrosion. For this reason, these indirect costs are considered to be
essentially taxes on the direct costs that are affected by corrosion in the same way as the direct
costs, and are distributed proportionally to those direct costs, with the results shown in Table 1.4.
Table 1.3. Costs to consumers by major category, 2007
Category
Total
Percentages
Operational expenses
6,709,981,466
31.98
Maintenance expenses
7,190,363,886
34.27
Depriciation expenses
6,776,856,209
32.30
Other expenses
302,250,440
1.44
Total expenses
20,979,452,000
100.00
Table 1.4. Adjusted Costs to Consumers, by Major Category in 2007
Category
Total
Adjusted
Percentages
Operational expenses
6,808,065,089
32.45
Maintenance expenses
7,295,469,533
34.77
Depreciation expenses
6,875,917,378
32.77
Total expenses
20,979,452,000
100.00
The total generation capacity of SEC power plants was 32,957MW in 2007. The contribution of
different type of generation capacities and respective percentage contributions are summarized in
Table 1.4-1. The major contribution of power generation is from gas turbines which accounted
alone for 51.53% in year 2007.
Table 1.4-1. Breakdown of power generation by generation type for 2007, [1].
Generation type
Steam
Gas
Combined cycle
Diesel
Total
Installed
capacity (MW) Percentages
12,651
38.39
16,984
51.53
2,385
7.24
937
2.84
32,957
100.00
Breakdown of O&M Costs by Facility or Function
To allow detailed analysis of operating, maintenance and depreciation costs, these costs need to
be broken down by type of facility or function. The breakdowns for O&M costs from
government reports are used, as shown in Table 1.5.
Table 1.5. Adjusted Costs to Consumers, by Major Category in 2007
Generation type
Percent*
Cost
Adjusted
Percent**
Steam power plants
38.39
5,144,655,422
29.15
Gas turbine plants
51.53
6,906,713,120
39.14
Diesel power plants
7.24
969,884,055
5.50
Combined cycle power plants
2.84
381,040,402
2.16
Nuclear power plants
0
0.00
Hydraulic power plants
0
0.00
Other power supply expenses
215,650,000
1.22
Transmission
313,224,000
1.78
Distribution
3,540,919,000
20.07
Others (Customer accounts,
sales, administration, etc.)
174,105,000
0.99
Total
100.00
17,646,191,000
*This is based on total generation capacity for 2007 i.e. 32,957MW
** This is based on total cost of distribution, generation, transmission, fuel, and others
Two adjustments were made to the data in Table 1.5:
 Essentially all of the “Other Power Supply Expenses” listed in Table 1.5 are due to purchased
power. The type of generation involved in this purchased power is not indicated.
 It is assumed that electricity involved in power purchases was generated by the same fraction
of modes as shown for the listed generation types, and the costs in “Other Power Supply
Expenses” are distributed to the other generation modes in proportion to their listed value.
 The costs in the “Other” category are essentially a service charge applied to the costs of the
direct functions, and will increase as the direct costs increase. Accordingly, the costs in the
“Other” category were distributed to the direct generation, transmission and distribution
functions in proportion to their listed value. The adjusted results are shown in Table 1.6.
Table 1.6. Adjusted Costs to Consumers, by Major Category in 2007
Generation type
Cost
Percentages
Steam power plants
5,279,525,754
29.92
Gas turbine plants
7,087,776,888
40.17
Diesel power plants
995,310,167
5.64
Combined cycle power
plants
391,029,613
2.22
Nuclear power plants
0.00
Hydraulic power plants
0.00
Transmission
316,345,199
1.79
Distribution
3,576,203,379
20.27
Total
17,646,191,000
100.00
The above table shows the fractions of reported utility O&M costs for electricity generation,
transmission and distribution for 2007. When these fractions are applied to the O&M costs from
Table 1.4, O&M costs to consumers are developed, as shown in Table 1.7. The total O&M cost
of about SAR 20.979 billion is broken down by type of facility or function. The largest fraction
of 40.17% of the cost is attributed to gas turbine generation or approximately SAR 8.427 billion.
The second largest fraction of the O&M cost is attributed to steam power plant generation at
29.92% or SAR 6.277 billion.
Table 1.7. Operation and Maintenance Costs to Consumers in 2007 Broken Down by Type
of Facility or Function.
Generation type
Cost
Percentages
Steam power plants
6,276,796,910
29.92
Gas turbine plants
8,426,615,976
40.17
Diesel power plants
1,183,318,365
5.64
Combined cycle power
plants
464,892,791
2.22
Nuclear power plants
0.00
Hydraulic power plants
0.00
Transmission
376,100,935
1.79
Distribution
4,251,727,023
20.27
Total
20,979,452,000
100.00
SECTION 2 CORROSION COST ESTIMATES FOR FOSSIL FUEL BASED POWER
GENERATION
In this section, the cost due to corrosion related to fossil fuel based power plants will be
calculated using the operation and maintenance costs and the costs due to lost production, if the
data is available for the latter option.
2.1
Corrosion Costs due to Operation and Maintenance (O&M) Costs
The total industry O&M cost to consumers for generating electricity by steam power for the year
2007 was SAR 6,276,796,910 as given in Table 1.7 above. This represented 29.92% of the total
O&M cost of electricity to consumers for all generating, transmission, distribution and support
facilities. In order to determine the sources of these steam power costs, including the fractions
due to corrosion, the following approach has been used followed.
 O&M costs for major steam power plants in Saudi Arabia has to be evaluated in detail as per
the questionnaire given in Appendix-A.
 This study will determine the total costs for the major operating and maintenance cost
categories used by the Electricity and Cogeneration Regulatory Authority (ECRA) of Saudi
Arabia.
 For each of these O&M costs, the fraction that was attributable to corrosion has to be
determined.
 The total costs, and the corrosion fractions, as shown in Table A-1 in Appendix A will be
determined once the data is made available.
In order to complete the present corrosion cost estimation exercise, the percent of O&M costs
attributed to corrosion was taken from the EPRI report [2, Table 5-1, P. F-34] for Duke Power
stations as being a reasonable estimate for the nation as a whole. On this basis, the O&M cost to
consumers due to corrosion for fossil fired steam power stations for 2007 was 0.042 x
6,276,796,910 = SAR263,625,470.
2.2
Corrosion Costs due to Loss of Production Costs
Corrosion costs due to forced lost of production will be analyzed as per the procedure given in
EPRI report [2], as given below:
 An attempt is being made by the project team to carry out a detailed analysis of the operating
and outage records to determine the total number of hours of lost production in 2007 at
largest steam power stations and also the fraction of these hours that were due to corrosion.
The questionnaire prepared based on the guide lines provided in EPRI report [2, Table 8-1,
Appendix-G, P. G-40] is included in Appendix A as Table A-2.
 As per the EPRI report [2, Table 8-1 in Appendix G] the lost production during the year was
10.4% of the total possible generation of 51,158,400 MWe-hr for the five stations which they
considered for their analysis, and that the lost production due to corrosion was 3.6%
(corrosion accounted for about 34.5% of the lost production).
 As per EPRI report [2], the cost of lost production due to having to generate electricity using
more expensive methods was estimated using a typical value of $13/MWe-hr for the lowest
heat rate stations, and $7/MWe-hr for medium heat rate stations, or an average of about
$10/MWe-hr for the five largest Duke Power stations.
 In the present case the cost electricity generation of 55SAR/MWh is used. The outage
percentage is taken as 10.4% and corrosion cost as 3.6% as mentioned above. This results in
a total cost for lost production from all the steam power stations of SAR55 x 169,780,321 x
0.3891 x 0.104 = SAR377,871,911 due to all causes, and SAR55 x 169,780,321 x 0.3891 x
0.036 = SAR130,801,816 due to corrosion. Here the number 38.91% correspond to the
generation contribution through steam power plants (Table 4-1 above). Hence the percent
contribution of corrosion with respect to total steam power generation was found to be
34.615%.
Table 2.1. Summary of Corrosion Costs to Consumers for Steam Power
Item
Total O&M Cost, Percent due to
Cost due to
(SAR)
Corrosion, (%) Corrosion, (SAR)
Total
Fossil
Steam
6,276,796,910
4.2
263,625,470
Power O&M
Costs to Consumers
Cost due to Lost
377,871,911
34.62
130,801,816
Production, at
SAR55/MWe-hr
Total
Fossil
Steam
6,654,668,821
5.93
394,427,286
Power O&M
Costs to Consumers,
Including
Costs of Lost Production
SECTION 3 SOURCES OF HIGH CORROSION COSTS
The most significant sources of corrosion costs for fossil fuel fired steam power plants are
identified in Table 5-1 of Appendix F. These sources are listed in Table 4-2 below, with the
corrosion fractions of Appendix F applied to the industry as a whole. The most significant cost
items from
Tables 4-1 and 4-2 are discussed below.
Table 4-2
Main Fossil (Coal) Steam Power O&M Corrosion Related Costs
Activity Percent of
Budget
Percent
Corrosion
Percent
Plants
Corrosion Cost to
Nation
Reasons for Corrosion Costs
Fossil Fuel 82.21 2 100 $1,934,303,125 The corrosion problems that can be caused by aggressive
chemical species in coal
require that cleaner, more expensive sources of fuel be used or that the coal be
processed to remove impurities.
Maintenance of Boiler Plant 5.22 30 100 $1,842,305,494 Corrosion of boiler tubes is a major
cause of boiler plant maintenance. Corrosion of
precipitators and FGD equipment are also major causes of high corrosion costs.
Maintenance of Electric Plant 2.32 15 100 $409,401,221 Corrosion of items such as condenser
and other heat exchanger tubes and of
turbine blades leads to high costs.
Maintenance Supervision and
Engineering
1.62 15 100 $285,874,990 Maintenance supervision and engineering have to deal with the
corrosion problems
that occur in the plant, e.g., boiler tube corrosion.
Steam Expenses 2.46 7.5 100 $217,053,234 Chemistry effort is required to control corrosion in
the boiler and auxiliary systems.
Maintenance of Structures 0.54 10 100 $63,527,776 Corrosion and corrosion prevention
activities (e.g., maintenance of protective
coatings) are important causes of costs regarding the maintenance of structures.
Electric Expenses 1.53 3 100 $53,998,609 The corrosion costs in this category include costs for
circulating water treatment
chemicals that are used to reduce corrosion, increased costs of lubricants
associated with their anti-corrosion properties, operating practices directed at
minimizing corrosion.
Misc. Steam Power Expense 1.98 2 100 $46,587,035 Corrosion costs in this category include the
increased costs of transportation caused
by corrosion, and the cost of R&D associated with corrosion.
Maintenance of Miscellaneous Steam
Plant
0.25 15 100 $44,116,511 Corrosion leads to problems, and the need for maintenance, of most
mechanical
and electrical equipment.
Operations, Supervision and Engineering 1.8 2 100 $43,057,715 Operations, supervision and
engineering have to deal with corrosion problems as
they occur, which mainly are due to the aggressive chemicals in the coal.
Total Enumerated Costs $4,940,225,710
Steam Power O&M Cost to Consumers: $117,644,029,000
4-3
Fuel
Causes. The main cause of the high indirect corrosion costs associated with the use of crude oil
as fuel is the potential for problems due to impurities in the crude oil such as sulfur and chlorine.
These impurities can cause corrosion and similar problems in many areas of the power plant and
to the environment. The presence of these aggressive species leads to many indirect corrosion
costs, such as the use of crude oil from higher cost sources with lower impurity levels,
preprocessing of crude oil to remove impurities, and use of cleanup equipment such as
precipitators and flue gas desulfurization equipment. The aggressive species also add to direct
corrosion costs of power plant equipment, as covered later under other items.
Avoidable Costs. It appears that the only practical approaches for reducing the high corrosion
costs associated with impurities in crude oil is to develop improved and less costly methods for
cleaning the crude oil, or to utilize alternate ways of burning crude oil that make dealing with the
impurities less costly.
Maintenance of Boiler Plant
Causes. There are two main causes of high corrosion costs associated with maintenance of the
boiler plant. The first cause is costs associated with the aggressive nature of the chemicals in the
crude oil. These aggressive species lead to corrosion of boiler tubes, precipitators, flue gas
desulfurization equipment, and ash handling equipment. The second main cause of high
corrosion costs is associated with water/steam side corrosion, which affects boiler tubes,
turbines, condensers, piping and heat exchangers.
Avoidable Costs. It appears that the high corrosion costs associated with crude oil could be
reduced by one or the other or a combination of several possible routes: selection of more
corrosion resistant materials, control of plant conditions to reduce the aggressiveness of the
conditions (e.g., temperatures and water chemistry), and preprocessing or pre-treatment of the
crude oil to reduce the rate of ingress and concentration of aggressive chemicals. Some of the
high costs associated with water/steam side corrosion are potentially avoidable by improved
water chemistry and material selection.
Lost Production
Causes. A main cause of the high corrosion costs associated with lost production are outages
associated with boiler tube failures. Corrosion of other equipment, such as flue gas
desulfurization equipment, is also important.
Avoidable Costs. It appears that continued improvements in selection of materials for boiler
tubes, development of remedial approaches such as use of weld overlays and changes in burner
design, and control of water chemistry, have the potential for significantly reducing the costs of
lost production.
REFERENCES
1. Annual report Saudi Electricity Company, Riyadh, 2007.
2. Cost of Corrosion in Electric Power Sector, Final Report-1004662, October 2001, EPRI 3412
Hillview Avenue, Palo Alto, California 94304, PO Box 10412, Palo Alto, California 94303 •
USA, askepri@epri.com, www.epri.com
Keywords
Corrosion Economics Costs Electric power generation Transmission Distribution
Sixteen cost categories are defined in Part 101 (Reference #3) for the fossil stations, of which
fourteen apply to major utilities. This list and the specific definitions are well covered in Chapter
3 and are not discussed in this Chapter. In addition to the information on the fourteen cost
categories, other financial and general information is available, most of which is typically
construction related information. Some of this information is included in Table 5-1 for the coal
burning fossil stations and in Table 5-2 for the natural gas burning fossil stations. These
additional cost categories or general information categories include:
1. Type of Plant
2. Construction start date
3. Construction end date
4. Installed MW-e capacity
5. Time connected to grid
6. Average number of employees
7. Net Generation – MW-hrs
8. Land and land rights cost
9. Cost of structures and improvements
10. Equipment costs
11. Roads, Railroads and bridges
12. Cost per kW-e installed
13. Primary fuel type
14. Total annual expenses per net kW-hr
15. Average heat rate
Fossil, Hydro and Gas Turbine O&M Costs
In addition to these additional categories, several categories of general information or financial
information were added in Table 5-1 and Table 5-2 as calculated values. These calculated values
used information reported in the FERC data (Reference #2) to develop other information
categories of interest. These calculated value categories are:
1. Fuel expense per net KW-hr
2. Fuel expense as percent of total production expenses
3. Unit utilization percentage (hours connected to grid versus total hours)
4. Maximum annual power possible in MW-hrs (based on name plate rating)
5. Capacity factor in percent
Eight separate stations are listed in Table 5-1 as predominately coal burning stations while six
separate stations are listed in Table 5-2 as predominately natural gas burning stations. The 1998
FERC report for Duke Power Company included data on 21 separate hydro stations, which are
listed in Table 5-3. Two of the 21 hydro stations are operated as pumped storage sites.
As discussed in Chapter 2, the hydro stations have a separate set of definitions designed to better
report their operating parameters. 13 cost categories are discussed in Chapter 3, of which 11
apply to the Duke Power hydro stations since Duke Power is defined as a major utility. Table 5-3
lists the financial data for each of these 21 hydro stations for each of the 11 applicable cost
categories defined in Part 101 (Reference #3). These 11 cost categories are listed under
production expenses in Table 5-3.
As with the fossil station FERC data, additional financial and general information was listed for
the hydro stations. The information selected for inclusion in Table 5-3 was:
1. Type of Plant
2. Construction start date
3. Construction end date
4. Installed MW-e capacity
5. Time connected to grid
6. Average number of employees
7. Net Generation – MW-hrs
8. Land and land rights cost
9. Cost of structures and improvements
Fossil, Hydro and Gas Turbine O&M Costs
10. Cost of reservoirs, dams and waterways
11. Equipment costs
12. Roads, Railroads and bridges
13. Cost per KW-e installed
14. Primary fuel type
15. Total annual expenses per net KW-hr
In addition to these categories for the hydro stations, calculated value lines of general
information or financial information were added in Table 5-3. These calculated values used
information reported in the FERC data (Reference #2) to develop other information categories of
interest. These calculated value categories are:
1. Unit utilization (time connected to the grid)
2. Max possible power generation (MW-hrs)
3. Capacity Factor, %
4. Pumped Storage Efficiency (for the two pumped storage units)
Since the cost categories are well defined in Part 101 (Reference #3) as discussed in Chapter #2,
and highly regulated by the FERC, the information listed in the FERC Form No. 1 data
(Reference #2) should be considered accurate with low uncertainty. Compared to the uncertainty
of the percentage corrosion related evaluations completed in this report, the uncertainty
associated with the financial data from the FERC reports should be minimal.
The comparison of the Duke Power information should be directly applicable to the rest of the
utilities in the United States if other design, operational and maintenance differences are
identified and addressed. These differences could include but should not be limited to differences
in fuel type or quality, differences in condenser cooling water sources, original design of the
stations, proximity to fuel sources, age of the stations, significant capital upgrades for older
stations, number of maintenance employees for upkeep of site, political influences, etc. Some of
these differences are measurable with known, quantifiable adjustment methods while other
differences are more subjective and difficult to analyze. Cost of financing (ability to borrow
money) can also be a factor in the cost of operating a power generation station.
APPLICATION OF DEFINITIONS AND EVALUATIONS TO DUKE POWER
EXPENSES
For the overall application of the Duke Power corrosion related O&M expenses to the remainder
of the Power Generation Industry for 1998, three key inputs are needed to complete the
evaluation and provide reasonable assurance that the uncertainty of the extrapolation effort is
minimized. The three key inputs are:
1. Well defined industry cost categories
2. Reliable and detailed O&M cost data gathered by the cost categories for Duke Power and for
the Industry
3. Completed evaluations of the impact of corrosion on the Duke Power O&M budgets
With the industry cost categories discussed in Chapter 2, the O&M cost data from FERC Form
No. 1 Reports addressed in Chapter 3 and the evaluations of percent corrosion related completed
in Chapter 4, the only step remaining in the process is to complete the applications of the
definitions and evaluations into a roll up process. This roll up process is completed in this
chapter and documented in Tables 5-1, 5-2 and 5-3 as previously discussed.
The percent avoidable values and the percent uncertainty values are based on engineering
judgment of the SME’s interviewed in the completion of this report.
Fossil Power Generation Results – Natural Gas Stations
Table 5-2 includes the roll up information for the six fossil stations that use natural gas as the
predominant fuel source. These six stations include:
1. Lee Steam Station
2. Dan River Steam Station
3. Buck Steam Station
4. Riverbend Steam Station
5. Buzzard Roost Combustion Turbine Station
6. Lincoln Combustion Turbine Station
Four of these combustion turbine stations share sites with the coal burning stations by the same
name. The generic site O&M expenses have been distributed accordingly to the two categories as
required by FERC data reporting guidelines.
Fossil, Hydro and Gas Turbine O&M Costs
As seen in Table 5-2, the predominant cost category in the overall O&M budget is fuel at 83.0%
of the overall budget. The predominate cost category for impact of corrosion on the O&M budget
is also fuel at 2.0 %corrosion related but representing 49.8 % of the overall total for corrosion
related cost categories. The other significant cost category impacting the percent corrosion
related is Maintenance of electric plant at 35.8 %. Based on the roll up data presented in Table 52, of the overall 1998 Department O&M Budget of $37,159,000 reported for the six combustion
turbine stations in this station grouping, $1,239,000 or 3.3 %is evaluated to be corrosion related.
Of this amount, $78,000 or 6.3 % is considered avoidable. This represents 0.21 % of the total
station budget.
The predominate factor in the overall station budget for this station grouping is the cost of fuel
which ranges from a high of 88.9 %at the Lincoln Combustion Station to a low of 49.5 % at the
Lee Combustion Station. The system average is 83.0 %, which is heavily influenced by the
newest and largest combustion turbine site, Lincoln.