EXHIBIT 99.2
Independent Engineer's Report by R. W. Beck, Inc.
INDEPENDENT ENGINEER'S REPORT
SOUTHERN POWER COMPANY
GENERATING FACILITIES
[R W BECK LOGO]
[THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY]
ANNEX A
INDEPENDENT ENGINEER'S REPORT
SOUTHERN POWER GENERATING FACILITIES
TABLE OF CONTENTS
PAGE
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INTRODUCTION................................................................................................... A-1
THE GENERATING FACILITIES...................................................................................... A-5
The Facility Sites.......................................................................................... A-6
The Dahlberg Facility Site............................................................................... A-6
The Franklin Facility Site............................................................................... A-6
The Harris Facility Site................................................................................. A-7
The McIntosh Facility Site............................................................................... A-7
The Stanton Facility Site................................................................................ A-7
The Wansley Facility Site................................................................................ A-8
Summary.................................................................................................. A-9
Description of the Facilities............................................................................... A-9
Off-Site Requirements....................................................................................... A-10
Fuel Supply.............................................................................................. A-10
Water Supply and Treatment............................................................................... A-11
Wastewater Disposal...................................................................................... A-13
Electrical Interconnection............................................................................... A-13
Review of Technologies...................................................................................... A-14
GE 7FA CT................................................................................................ A-14
GE 7EA CT................................................................................................ A-18
Summary.................................................................................................. A-18
Estimated Useful Life....................................................................................... A-19
Performance Tests and Guarantees............................................................................ A-19
Operating Programs and Procedures........................................................................... A-20
Operating History........................................................................................... A-22
Capacity and Heat Rate...................................................................................... A-22
The Dahlberg Facility.................................................................................... A-22
The Franklin Facility.................................................................................... A-23
The Harris Facility...................................................................................... A-23
The McIntosh Facility.................................................................................... A-24
The Stanton Facility..................................................................................... A-25
The Wansley Facility..................................................................................... A-25
Summary.................................................................................................. A-26
Availability................................................................................................ A-26
The Dahlberg Facility.................................................................................... A-26
The Franklin Facility.................................................................................... A-27
The Harris Facility...................................................................................... A-27
The McIntosh Facility.................................................................................... A-27
The Stanton Facility..................................................................................... A-27
The Wansley Facility..................................................................................... A-28
Summary.................................................................................................. A-28
Construction Status......................................................................................... A-28
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ANNEX A
INDEPENDENT ENGINEER'S REPORT
SOUTHERN POWER GENERATING FACILITIES
TABLE OF CONTENTS
(CONTINUED)
PAGE
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ENVIRONMENTAL ASSESSMENTS...................................................................................... A-29
Environmental Site Assessments.............................................................................. A-29
The Dahlberg Facility.................................................................................... A-29
The Franklin Facility.................................................................................... A-29
The Harris Facility...................................................................................... A-29
The McIntosh Facility.................................................................................... A-30
The Stanton Facility..................................................................................... A-30
The Wansley Facility..................................................................................... A-31
Summary.................................................................................................. A-32
Status of Permits and Approvals............................................................................. A-32
Regulatory Compliance....................................................................................... A-34
PROJECTED OPERATING RESULTS.................................................................................... A-35
Annual Operating Revenues................................................................................... A-36
Revenue from PPAs........................................................................................ A-36
Other Revenues from Electricity Sales.................................................................... A-39
Annual Operating Expenses................................................................................... A-40
Fuel Costs............................................................................................... A-40
Operating and Maintenance Costs.......................................................................... A-40
Purchased Power.......................................................................................... A-40
Emissions Allowances..................................................................................... A-41
General and Administrative and Other Expenses............................................................ A-41
Annual Interest............................................................................................. A-41
Interest Coverage........................................................................................... A-41
Sensitivity Analyses........................................................................................ A-41
Summary Comparison of Projected Operating Results........................................................... A-42
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS USED IN THE PROJECTION OF OPERATING RESULTS........................... A-42
CONCLUSIONS.................................................................................................... A-44
EXHIBITS
EXHIBIT A-1 Base Case Projected Operating Results........................................................ A-46
EXHIBIT A-2 Sensitivity A - Low Gas Market Price Scenario................................................ A-61
EXHIBIT A-3 Sensitivity B - High Gas Market Price Scenario............................................... A-64
EXHIBIT A-4 Sensitivity C - Capacity Overbuild Market Price Scenario..................................... A-67
EXHIBIT A-5 Sensitivity D - Reduced Output............................................................... A-70
EXHIBIT A-6 Sensitivity E - Reduced Availability......................................................... A-73
EXHIBIT A-7 Sensitivity F - Increased Heat Rate.......................................................... A-76
EXHIBIT A-8 Sensitivity G - Increased Operating Expenses................................................. A-79
Copyright (C) 2003 R. W. Beck, Inc.
All Rights Reserved
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[R W BECK LOGO]
June 30, 2003
Southern Power Company
270 Peachtree Street NW
Suite 2000
Atlanta, Georgia 30303
Subject: INDEPENDENT ENGINEER'S REPORT ON THE
SOUTHERN POWER GENERATING FACILITIES
Ladies and Gentlemen:
INTRODUCTION
Presented herein is the report (the "Report") of our review
and analyses of the generating facilities owned by Southern Power Company
("Southern Power"), a wholly-owned subsidiary of The Southern Company
("Southern"). [Redacted]
The generating facilities reviewed, totaling 6,024 megawatts
("MW")(net), are summarized in Table 1 and consist of the 810 MW (net) Dahlberg
simple-cycle power plant in operation near Athens, Georgia consisting of ten
units (the "Dahlberg Facility"); the 1,187 MW (net) Franklin (formerly known as
Goat Rock) combined-cycle power plant in Lee County, Alabama consisting of two
units ("Franklin 1" and "Franklin 2", and, collectively, the "Franklin
Facility"); the 1,242 MW (net) Harris (formerly known as Autaugaville)
combined-cycle power plant in Autauga County, Alabama consisting of two units
("Harris 1" and "Harris 2", and, collectively, the "Harris Facility"); the 1,240
MW (net) McIntosh combined-cycle power plant in Effingham, Georgia consisting of
two units ("McIntosh 10" and "McIntosh 11", and, collectively, the "McIntosh
Facility"); Southern Power's 65 percent ownership interest in the 633 MW (net)
Stanton combined-cycle power plant in Orlando, Florida (the "Stanton Facility");
and the 1,134 MW (net) Wansley combined-cycle power plant in Heard County,
Georgia consisting of two units ("Wansley 6" and "Wansley 7", and, collectively,
the "Wansley Facility" and, together with the Dahlberg, Franklin, Harris and
Stanton Facilities, the "Generating Facilities"). Dahlberg 1-8 have been
operational since May 2000. Dahlberg 9-10 have been operation since May 2001.
Franklin 1 entered into commercial operation on June 1, 2002 and Franklin 2 and
the Harris Facility entered into commercial operation on June 1, 2003. The
McIntosh Facility is under construction and is scheduled to enter into
commercial operation in June 1, 2005. The Stanton Facility is under construction
and is scheduled to enter into commercial operation on October 1, 2003. The
Wansley Facility entered into commercial operation on June 1, 2002.
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1801 California Street, Suite 2800 Denver, CO 80202 Phone (303) 299-5200 Fax
(303) 297-2811
FIGURE A-1
SOUTHERN POWER GENERATING FACILITIES
SITE LOCATIONS
[GRAPHIC]
A-2
Southern Power was formed to own, develop, construct and
acquire electric power generation facilities that provide power predominantly to
Southern's regulated utilities: Alabama Power Company ("Alabama Power"), Georgia
Power Company ("Georgia Power"); Gulf Power Company ("Gulf Power"); Mississippi
Power Company ("Mississippi Power"); and Savannah Electric and Power Company
("Savannah Electric"). The Generating Facilities sell power to these entities,
as well as to others, under the various terms of individual power purchase
agreements (collectively, the "PPAs"). Southern Power intends to continue to
derive at least 80 percent of operating cash flow under long-term power purchase
agreements.
Southern, through its subsidiary Southern Company Services,
Inc. ("SCS"), is overseeing the design, procurement, and construction of the
Generating Facilities, with the exception of units 1 through 8 at the Dahlberg
Facility, which were constructed and completed on a turnkey basis by GE Power
Systems, Inc. ("GE"). SCS has developed a standard design for combined-cycle
facilities ("CCs"). Certain of the Generating Facilities are based on SCS's
second generation standard design ("Gen 2") while others are based on their
third generation design ("Gen 3"). The combustion turbine generators ("CTs") for
the Generating Facilities are to be supplied by GE. To control the formation of
oxides of nitrogen ("NOX"), the CTs are equipped with dry low-NOX combustors.
Construction of the Generating Facilities is being funded
through a construction loan from a syndicate of commercial banks (the
"Commercial Construction Revolver") and the issuance of short-term indebtedness,
in addition to a subordinated loan and equity contribution from Southern
Company. Under the terms of the Commercial Construction Revolver, Southern is
guaranteeing the completion and the performance of the Generating Facilities.
The completion guarantee from Southern includes: (a) that Southern will cover
any construction cost over-runs and related interest expense; and (b) Southern
is obligated to repay the portion of the Commercial Construction Revolver
allocated to one of the Generating Facilities if such facility fails to achieve
completion or if the guaranteed capacity and heat rate are not achieved.
A portion of the output of the Dahlberg Facility is sold to
LG&E Energy Marketing, Inc. ("LEM") through December 31, 2004 under two
Purchased Power Agreements assigned to Southern Power by Georgia Power effective
July 31, 2001 (the "1998 LEM PPA" and the "1999 LEM PPA" and, collectively, the
"LEM PPAs"). The remainder of the output was previously being sold to Dynegy
Power Marketing under a Purchased Power Agreement dated March 2, 2000; however,
this power purchase agreement was terminated by Southern Power on May 21, 2003
[Redacted].
The output of the Franklin Facility will be sold to Georgia
Power through May 31, 2010 for Franklin 1 and May 31, 2011 for Franklin 2 under
the terms of a Power Purchase Agreement dated March 30, 2001 (the "Franklin
PPA").
The Harris 1 output will be sold through May 31, 2010 to
Alabama Power under the terms of a Power Purchase Agreement dated June 1, 2001
(the "Harris 1 PPA"). The Harris 2 output will be sold through May 31, 2019 to
Georgia Power under the terms of a Power Purchase Agreement dated August 6, 2001
(the "Harris 2 PPA" and, together with the Harris 1 PPA, the "Harris PPAs").
The output of the McIntosh Facility will be sold to Georgia
Power and Savannah Electric through May 31, 2020 under two Power Purchase
Agreements dated June 3, 2002 (the "McIntosh PPAs"). The McIntosh PPAs are still
subject to approval by the Federal Energy Regulatory Commission ("FERC").
Southern Power's share of the output of the Stanton Facility
will be sold to the Orlando Utilities Commission ("OUC"), Kissimmee Utility
Authority ("KUA"), and Florida Municipal Power Authority ("FMPA") through
October 31, 2013, assuming an effective date of October 1, 2003, under the terms
of three similar Power Purchase Agreements dated March 19, 2001 (the "Stanton
PPAs"). Southern Power is participating in the Stanton Facility with OUC, KUA
and FMPA through its subsidiary, Southern Company Florida, LLC ("Southern
Company Florida"), under the terms of a Construction and Ownership Participation
Agreement dated March 19, 2001 (the "Stanton Ownership Agreement").
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The output of the Wansley Facility will be sold to Georgia
Power and Savannah Electric through December 31, 2009 under two Contracts for
the Purchase of Firm Capacity and Energy dated July 31, 2001 (the "Wansley
PPAs").
Georgia Power operates and maintains the Dahlberg, Franklin,
and Wansley Facilities pursuant to the terms and conditions of an Amended
Operating Agreement dated January 18, 2002, with Southern Power. Alabama Power
will operate and maintain the Harris Facility pursuant to the terms and
conditions of an Operating Agreement with Southern Power dated June 30, 2001.
Savannah Electric will operate and maintain the McIntosh Facility pursuant to
the terms and conditions of an Operating Agreement with Southern Power effective
January 1, 2003. SCS, on behalf of Southern Company Florida, will operate and
maintain the Stanton Facility under the terms of a Service Agreement between
Southern Power and SCS dated January 10, 2001. Georgia Power, Alabama Power, and
Savannah Electric provide similar services for their respective utility power
generation facilities. Southern Power has entered into Long Term Service
Agreements ("LTSAs") with General Electric International, Inc. ("GEI") for the
maintenance and overhaul of the CTs at all the Generating Facilities and the
steam turbine generators ("STs") at Franklin 1 and the Wansley Facility.
A summary of general information related to the Generating
Facilities is presented in Table 1.
TABLE 1
SOUTHERN POWER GENERATING FACILITIES
GENERAL INFORMATION
TOTAL
CAPACITY COMMERCIAL
UNIT (MW) DISPATCH OPERATION TERM OF
FACILITY LOCATION FUEL TYPE TYPE (1) TYPE POWER PURCHASER DATE PPA
- ---------- ------------------ ------------ ---- -------- ----------- ------------------ ---------- -------
<c> <c>
Dahlberg Athens, GA Oil/ Natural CT 810 Peaking LEM (2) 5/00(3) 2004
Gas
Franklin 1 Lee County, AL Natural Gas CC 564 Intermediate Georgia Power 6/02 2010
Franklin 2 Lee County, AL Natural Gas CC 623 Intermediate Georgia Power 6/03 2011
Harris 1 Autauga County, AL Natural Gas CC 627 Intermediate Alabama Power 6/03 2010
Harris 2 Autauga County, AL Natural Gas CC 615 Intermediate Georgia Power 6/03 2019
McIntosh Effingham, GA Natural Gas CC 1,240 Intermediate Georgia Power/ 6/05 2020
Savannah Electric
Stanton Orlando, FL Oil/ Natural CC 411(4) Intermediate OUC/KUA/FMPA 10/03 2013
Gas
Wansley Heard County, GA Natural Gas CC 1,134 Intermediate Georgia Power/ 6/02 2009
Savannah Electric
-----
Total 6,024
- --------------------
(1) Represents guaranteed new and clean summer rating with duct firing and
steam injection (as described later in the Report), with the exception
of the Stanton Facility which is based on an average ambient
temperature of 70(Degree)F.
(2) Under the LEM PPAs, the contract capacity of 578 MW can be met by any
of the units.
(3) Commercial operation of Dahlberg 9-10 occurred in 2001.
(4) Represents Southern Power's 65 percent ownership interest in the
Stanton Facility.
During the preparation of this Report, we reviewed the various
agreements related to the construction, operation, maintenance and management of
the Generating Facilities to which Southern Power is a party. These agreements
and documents set forth the obligations of each of the parties with respect to
the construction, testing, operation, maintenance and management of the
Generating Facilities. As Independent Engineer, we have made no determination as
to the validity and enforceability of these agreements; however, for the
purposes of this Report, we have assumed these agreements will be fully
enforceable in accordance with their terms and that all parties will comply with
the provisions of their respective agreements.
In addition, we have reviewed: (1) the status of permits and
approvals and reviewed the status of permit compliance for the plants with
significant operating history; (2) geotechnical reports and environmental
assessment reports with respect to the sites of the Generating Facilities; (3)
the historic and projected levels of
A-4
production of the Generating Facilities; (4) the historic and projected
operating and maintenance expenses of the Generating Facilities; (5) the
projected revenues of the Generating Facilities; (6) historical operating
records of the Generating Facilities, and (7) operating programs and procedures.
Based on our review, we have prepared a projection of revenues and expenses of
the Generating Facilities and interest coverage ratios, which are attached as
Exhibits A-1 through A-8 to this Report (the "Projected Operating Results").
During the course of our review, we visited and made general
field observations of the Generating Facilities and the sites of the Generating
Facilities. The general field observations were visual, above-ground
examinations of selected areas which we deemed adequate to comment on the
existing condition of the sites but which were not in the level of detail
necessary to reveal conditions with respect to geological or environmental
conditions, the internal physical condition of any equipment, or the conformance
with agreements, codes, permits, rules, or regulation of any party having
jurisdiction with respect to the sites.
Following the terrorist attacks of September 11, 2001,
increased emphasis has been placed on addressing security measures for the
infrastructure systems and facilities in the United States. Terrorist activities
aimed at the Generating Facilities could interfere with the ability of Southern
Power to generate revenues. Additionally, terrorist activities have the
potential to affect organizations, other than Southern Power, that are critical
to the continuing operation of the Generating Facilities. We have not conducted
any independent evaluations or on-site reviews to ascertain the effectiveness of
the measures Southern Power has undertaken to address the security issues.
In developing the Projected Operating Results, we have relied
upon a report by PA Consulting, Inc. ("PA Consulting") [Redacted], for
projections of the Generating Facilities' electricity sales, market electricity
prices when the PPAs are not in effect, fuel costs, and emissions allowance
prices. We have not reviewed PA Consulting's methodology and approach in its
development of these projections but instead have based our reliance upon their
previous experience developing similar projections.
THE GENERATING FACILITIES
The Dahlberg Facility is an 810 MW peaking, simple-cycle
facility consisting of ten PG7121EA ("GE 7EA") CTs. The CTs are dual-fuel units
(natural gas and No. 2 fuel oil) and incorporate dry low-NOX technology to
control the formation of NOX.
The Franklin Facility is a 1,187 MW (net) combined-cycle power
plant consisting of two gas-fired electric generating plants. Franklin 1 is a
564 MW combined-cycle plant based on the SCS Gen 2 design, which incorporates
two GE PG7241FA ("GE 7FA") CTs, two Vogt-NEM ("Vogt") heat recovery steam
generators ("HRSGs"), and a GE ST. Franklin 1 includes duct firing
("full-pressure mode") and steam injection ("power augmentation") capabilities
to help increase power output when compared to normal base load operation.
Franklin 2 is a 623 MW combined-cycle plant based on the SCS Gen 3 design, which
incorporates two GE 7FA CTs, two Deltak HRSGs, and an Alstom Power, Inc.
("Alstom") ST. Franklin 2 also includes duct firing and steam injection
capabilities.
The Harris Facility is a 1,242 MW (net) combined-cycle power
plant consisting of two SCS Gen 3 gas-fired electric generating units, Harris 1
and 2, consisting of two GE 7FA CTs, two Deltak HRSGs, and an Alstom ST. Harris
1 is rated at 627 MW and Harris 2 is rated at 615 MW. The Harris Facility
includes duct firing and steam injection capabilities.
The McIntosh Facility is a 1,240 MW (net) combined-cycle power
plant consisting of two SCS Gen 3 gas-fired electric generating units, McIntosh
10 and 11, each rated at 620 MW and consisting of two dual-fuel (natural gas and
No. 2 fuel oil) GE 7FA CTs, two Deltak HRSGs, and an Alstom ST. The McIntosh
Facility includes duct firing and steam injection capabilities.
The Stanton Facility is a 633 MW (net) combined-cycle power
plant consisting of an SCS Gen 3 combined-cycle power generation plant
consisting of two dual-fuel (natural gas and No. 2 fuel oil) GE 7FA CTs, two
A-5
Deltak HRSGs, and an Alstom ST. Southern Power has a 65 percent ownership
interest in the Stanton Facility, or 411 MW. The Stanton Facility includes duct
firing and steam injection capabilities.
The Wansley Facility is a 1,134 MW (net) combined-cycle power
plant consisting of two 567 MW SCS Gen 2 combined-cycle power generation plants,
Wansley 6 and 7, each consisting of two GE 7FA CTs, two Vogt HRSGs, and a GE ST.
The Wansley Facility includes duct firing and steam injection capabilities.
TABLE 2
SOUTHERN POWER GENERATING FACILITIES
MAJOR EQUIPMENT AND CHARACTERISTICS
HEAT RATE
TOTAL CAPACITY (BTU/KWH)
FACILITY SCS DESIGN CT HRSG ST (MW) (1) (2)
-------- ---------- -- ---- -- -------------- ---------
Dahlberg N/A(3) GE 7EA N/A N/A 810(4) (4)
Franklin 1 Gen 2 GE 7FA Vogt GE 564 6,711
Franklin 2 Gen 3 GE 7FA Deltak Alstom 623 6,728
Harris Gen 3 GE 7FA Deltak Alstom 1,242 6,730
McIntosh Gen 3 GE 7FA Deltak Alstom 1,240 6,827
Stanton Gen 3 GE 7FA Deltak Alstom 411(5) 6,756
Wansley (6) Gen 2 GE 7FA Vogt GE 1,134 6,706
--------------------
(1) Represents new and clean summer rating guaranteed by Southern
with duct firing and steam injection, except for the Stanton
Facility which is based on an average ambient temperature of
70(Degree)F.
(2) Represents new and clean full-load heat rate guaranteed by
Southern in British thermal units per kilowatt-hour
("Btu/kWh") on a higher heating value basis.
(3) Dahlberg 1-8 were constructed on a turnkey basis by GE. The
design and construction of Dahlberg 9-10 was managed by SCS.
(4) Southern guarantee does not apply to the Dahlberg Facility.
(5) Represents Southern Power's 65 percent ownership interest in
the Stanton Facility.
(6) Southern guarantees the Wansley Facility as an individual
plant rather than separate units.
THE FACILITY SITES
THE DAHLBERG FACILITY SITE
The Dahlberg Facility is located on a continuous parcel of
land totaling approximately 270 acres in an unincorporated area of Jackson
County, in northeast Georgia, approximately 15 miles northwest of Athens,
Georgia, and approximately 65 miles northeast of Atlanta, Georgia (the "Dahlberg
Facility Site"). Highway access to the Dahlberg Facility Site is convenient over
national highways, state routes and city and county roads.
THE FRANKLIN FACILITY SITE
The Franklin Facility property is a continuous parcel of land
totaling 709 acres located in an unincorporated area of Lee County, in east
central Alabama near the Georgia border, approximately one mile west of the
Chattahoochee River, about 30 miles northwest of Columbus, Georgia and 10 miles
northeast of Auburn, Alabama (the "Franklin Facility Site"). Highway access to
the Franklin Facility Site is convenient over national highways, state routes
and city and county roads.
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THE HARRIS FACILITY SITE
The Harris Facility property is a contiguous piece of land
totaling 759 acres, located in Autauga County, Alabama, approximately three
miles west of Autaugaville, Alabama, and approximately 20 miles northwest of
Montgomery, Alabama (the "Harris Facility Site"). The Harris Facility Site is
located in an unincorporated area of Autauga County, in central Alabama directly
north of the Alabama River. Highway access to the Harris Facility Site is
convenient over national highways, state routes and county roads.
THE MCINTOSH FACILITY SITE
The McIntosh Facility is to be constructed on property
totaling approximately 58 acres in size located approximately 27 miles north of
Savannah, Georgia, near Rincon, Georgia on Old Augusta Highway three miles south
of Georgia Highway 275 (the "McIntosh Facility Site"). The McIntosh Facility
Site is located in Effingham County, Georgia. The McIntosh Facility Site is
located in an area zoned Industrial.
Highway access to the McIntosh Facility is convenient over
national highways, state routes and county roads. Heavy hauls to the McIntosh
Facility will be made via a rail spur currently servicing the existing Savannah
Electric facility located approximately one mile to the east of the McIntosh
Facility. Southern Power also noted that the Savannah Electric facility also has
capabilities to receive and offload equipment from an existing barge slip on the
Savannah River. Southern Power noted that agreements are in place with Savannah
Electric to utilize the rail spur and barge slip for receipt of the heavier
equipment.
Southern Geotech performed a subsurface investigation and
prepared a report titled "Reports of Geotechnical Investigation, Proposed Plant
McIntosh, Combined Cycle Units 10 & 11, Effingham County, Georgia" dated October
1, 2002 (the "McIntosh Geotechnical Report"). The McIntosh Geotechnical Report
included summaries of the investigation; compilation of select laboratory
results used for determination of engineering parameters, provided
recommendations for foundations and foundation systems, and provided guidance on
estimated settlement of foundations due to static and dynamic loading. Southern
Geotech performed subsurface investigations in February 2002 and January 2003
and conducted a pile test program in August 2002. The soil boring investigations
included dilatometer tests and test borings ranging in depth from approximately
51 feet to 92 feet below ground surface.
Based on their geotechnical analysis, Southern Geotech
recommended that pile foundations support the McIntosh Facility's more heavily
loaded equipment, including the STs, CTs, ST support steel, pipe racks, and
HRSGs. Southern Geotech further indicated that shallow foundations might be
considered for the storage tanks, cooling towers, transformers, electrical
buildings, the warehouse and administration building, and other miscellaneous
foundations.
The McIntosh Geotechnical Report does not include criteria for
site development, compaction, or surface water control nor did it provide
information relating to corrosion potential and resistivity of the soils.
However, Southern Power indicated that the specifications prepared for
construction include the necessary considerations for adequate site development.
At the time of our site visit, we noted that surface water control measures were
installed and finished subgrade had been achieved. The McIntosh Geotechnical
Report provides settlement estimates for the equipment to be installed on
shallow and deep foundations and a summary of pile testing conducted at the
McIntosh Facility Site in August 2002. Southern Power noted that the settlement
estimations reported in the McIntosh Geotechnical Report were deemed acceptable.
We note that the settlement estimations presented in the McIntosh Geotechnical
Report appear to be within the range we would expect for the given structures.
The McIntosh Geotechnical Report did not make foundation recommendations for the
structures located within the switchyard.
THE STANTON FACILITY SITE
The Stanton Facility is being constructed on property totaling
approximately 60 acres just north of the two existing Stanton Energy Center
("SEC") coal-burning units owned and operated by the OUC. The Stanton Facility
is located in Orange County, Florida, approximately 10 miles east of Orlando,
Florida (the "Stanton Facility
A-7
Site"). The Stanton Facility Site is located in an area zoned A-2 with a special
exemption consistent with that of the existing SEC.
Highway access to the Stanton Facility is convenient over
national highways, state routes and county roads. Southern Power reports that
upgrades to the existing access road will not be required to facilitate ingress
and egress to and from the Stanton Facility Site and the existing road should be
adequate to support delivery of the Stanton Facility's equipment not requiring
heavy haul facilities. Southern Power noted that delivery of the Stanton
Facility's heavy equipment is to be made via the existing rail spur that
services the SEC. Southern Power anticipates no additional improvements will be
required to the rail spur to facilitate delivery of the large equipment.
Southern Geotech performed a subsurface investigation and
prepared a report titled "Stanton Energy Center Combined Cycle Unit A Subsurface
Investigation Report" dated July 17, 2001 (the "Stanton Geotechnical Report").
The Stanton Geotechnical Report included summaries of the investigation;
compilation of select laboratory results used for compaction recommendations;
and provided recommendations for development work, foundations and foundation
systems, allowable bearing capacities for equipment foundations; and provided
guidance on estimated settlement of foundations due to static and dynamic
loading.
Based on their geotechnical analysis, Southern Geotech
recommends that pile foundations support the Stanton Facility's more heavily
loaded equipment, including the ST, CTs, and HRSGs. Southern Geotech further
recommends that piles in areas located proximate to the silty clay to soft
plastic clay layer (at approximately 52 feet to 74 feet below ground surface) be
founded on the deeper, very dense sand layer (at approximately 100 feet to 110
feet below ground surface according to the Stanton Geotechnical Report.)
Southern Geotech further indicated that shallow foundations may be considered
for the demineralized water storage tank, the fuel oil tank, the cooling tower,
the electrical building, transformers, the warehouse and administration
building, and other miscellaneous foundations.
The Stanton Geotechnical Report includes criteria for site
development, compaction, allowable bearing pressure, and surface and ground
water control. Southern Geotech also provided settlement estimates for the
equipment to be installed on shallow foundations. Information provided by
Southern Power noted that two additional borings and further evaluations of
settlement potential were conducted at the Stanton Facility. Results of this
further investigation and analysis yielded smaller settlement estimations for
the tanks and cooling tower. Southern Power noted that the settlement
estimations reported above were reviewed by and deemed acceptable to the tank
suppliers contingent upon proper construction practices. With respect to the
demineralized water storage tank, we note that the Stanton Geotechnical Report
states, based on their experience with similar tank structures, Southern Geotech
considers these magnitudes of settlement tolerable, provided the pipe
connections are properly accounted for. Finally, the remainder of the settlement
estimations presented in the Stanton Geotechnical Report appear to be within the
range we would expect for the given structures. We note that no foundation
recommendations were made for the structures located within the switchyard;
however, we understand that a detailed investigation has been completed for the
switchyard. Based on information from Southern Power, it is our understanding
that there are no additional foundation requirements for the switchyard
structures.
The Stanton Geotechnical Report did not provide
recommendations for additional geotechnical investigations prior to or during
the detailed design of the Stanton Facility nor did it provide information
relating to corrosion potential and resistivity of the soils. However,
subsequent investigations were conducted, including additional borings,
evaluations of soil corrosion potential, and resistivity testing. According to
Southern Power, no additional recommendations were made as a result of these
subsequent investigations.
THE WANSLEY FACILITY SITE
The Wansley Facility was constructed on land totaling
approximately 25 acres, located in Heard County, Georgia near Carrolton, Georgia
and approximately 30 miles southwest of Atlanta (the "Wansley Facility Site").
The Wansley Facility Site is located in an incorporated area of Heard County, in
western Georgia directly north of the Chattahoochee River. Highway access to the
Wansley Facility Site is convenient over national highways, state routes, and
county roads.
A-8
SUMMARY
Based on our review, we are of the opinion that, provided
Southern Power takes into account the recommendations in the geotechnical
reports by Southern Geotech, the sites for the Generating Facilities are
suitable for the construction and operation of the Generating Facilities.
DESCRIPTION OF THE FACILITIES
The following section describes the equipment and systems
either in place or proposed for the respective Generating Facilities. Our review
of the technical aspects of the equipment included in the Generating Facilities
is included in the section entitled "Review of Technology," presented later
herein.
The Franklin, Harris, McIntosh, Stanton and Wansley Facilities
are combined-cycle facilities. Each will incorporate GE 7FA CTs. The CTs are to
be base-mounted units equipped with dry low-NOX combustors to control the
formation of NOX emissions and an evaporative cooling system to improve
performance during the summer months. All units are single-fueled (natural gas)
with the exception of the Stanton Facility, which can also burn No. 2 oil, and
the McIntosh Facility, which can burn liquefied natural gas ("LNG") and No. 2
oil. Each CT is designed to deliver in the range of 172 to 176 MW of electric
power at 95(degree)F and approximately 45 percent relative humidity, with the
exception of the McIntosh Facility where the reference condition is 51 percent
relative humidity, at approximate site elevations and corresponding barometric
pressures with the inlet evaporative cooler and power augmentation operational.
An inlet air filtration system is provided to remove particles in the inlet
airstream. An inlet evaporative cooling system is provided to cool the inlet
airstream and improve CT performance. NOX emissions are guaranteed by GE to 9
parts per million volume, dry basis corrected to 15 percent oxygen ("ppmvd") at
the CT exhaust, over an ambient temperature range from 0(degree)F to
105(degree)F and over a range of 50 percent to 100 percent of base load by the
use of dry low-NOX combustors without power augmentation. With power
augmentation, NOX emissions are guaranteed by GE to 12 ppmvd at base load.
Carbon monoxide ("CO") emissions are guaranteed by GE to 9 ppmvd between base
load and 50 percent of base load without power augmentation for the Harris,
McIntosh, and Stanton Facilities when firing natural gas and, in the case of the
McIntosh Facility, LNG. With power augmentation, CO emissions are guaranteed by
GE to 15 ppmvd for the Franklin, Harris, McIntosh, Stanton, and Wansley
Facilities. The CT control and instrumentation system senses, computes, records
and displays pertinent CT operational information for use by plant operators and
control systems. It also provides protection to the CT against potentially
dangerous operating conditions.
The high-pressure ("HP") superheated steam from each HRSG will
be delivered to an ST to generate additional electricity. The STs for the
Franklin 2, Harris, McIntosh, and Stanton Facilities are combined, double flow
turbines, operating at 3,600 RPM, with reheat, and are single-shaft condensing
machines with separate HP, intermediate pressure ("IP"), and low pressure ("LP")
sections, and are each nominally rated at 282 MW. The STs for the Franklin 1 and
Wansley Facilities are reheat, multi-stage, axial exhausting condensing STs
suitable for sliding inlet pressure operation, and are each nominally rated at
190 MW. The manufacturers of the HRSGs and STs include Deltak, Vogt, Alstom, and
GE.
Exhaust gas from each CT is directed to an HRSG, where the
energy in the exhaust gas is converted into steam. HP steam is produced by the
HRSG and piped to the HP section of the ST. The HP steam is also piped to the CT
for power augmentation. The HP ST exhaust is combined with IP steam from the
HRSG and returned to the reheat section of the HRSG where it is reheated and
then returned to the IP/LP section of the ST. LP steam is produced by the HRSG
and supplied to the LP section of the turbine. There, the steam is further
expanded and exhausted to a surface condenser.
The CTs are equipped with dry low-NOX 2.6 ("DLN-2.6")
combustors for control of NOX emissions. Dry low-NOX technology premixes fuel
and air to provide a lean flame with a more uniform and lower burning
temperature than a conventional burner. Additionally, the dry low-NOX combustor
has a shorter, lower residence time flame. Both lower temperature and shorter
time contribute to NOX emissions equal to or lower than that achieved by
conventional steam and water injection.
A-9
Each HRSG is to be equipped with selective catalytic reduction
("SCR") to further reduce the NOX emissions from the CTs and the HRSG duct
burners. Anhydrous ammonia is vaporized and sprayed into the exhaust gas of the
CT in the HRSGs upstream of the SCR and reacts with the exhaust gas in the
presence of the catalyst to form nitrogen ("N2") and water vapor.
The Dahlberg Facility is designed to be an 810 MW nominal
simple-cycle power generation facility consisting of ten separate simple-cycle
units. The term "simple-cycle" refers to the Brayton cycle, in which hot
combustion gases are expanded through a gas turbine-generator. The major
equipment components of the Dahlberg Facility include ten GE PG 7121EA CTs and
other typical and necessary auxiliary equipment. In the simple-cycle
arrangement, natural gas is fired in the CT for production of power output. Hot
exhaust gas from each CT is passed through the exhaust ducting and out through
its own stack. The CTs do not use fuel gas heaters to preheat the natural gas
for performance enhancements.
The CTs are provided with inlet cooling using an evaporative
cooling system to improve performance during the summer months. As the CT is a
constant volume machine, it is subject to variation in output depending on the
density of the air, as affected by temperature and humidity. Output will
decrease in warm weather and will increase in cold weather. The CTs are base
mounted, dual fuel (natural gas and No. 2 fuel oil) units equipped with dry low
NOX-I ("DLN-I") combustors for dry control of NOX emissions when burning natural
gas and incorporate water injection for control of NOX emissions when burning
No. 2 distillate fuel oil.
Each CT is designed to deliver approximately 75 MW (nominal
base load) of electric power at 95(degree)F, 14.32 psia and 45 percent relative
humidity with evaporative cooling when burning natural gas. In the peak
operation mode, the output of each CT increases to 81 MW. Each CT burns natural
gas as its primary fuel and No. 2 distillate fuel oil as its backup fuel. An
inlet air filtration system is provided to remove particles in the inlet
airstream. Air inlet silencing features are included to control far field sound
levels.
NOX emissions are guaranteed to 9 ppmvd (at 95(degree)F, 14.32
psia, and 45 percent relative humidity) by the use of dry low-NOX combustors
while burning natural gas. NOX emissions while burning No. 2 distillate fuel oil
are guaranteed to 42 ppmvd (at 95(degree)F, 14.32 psia, and 45 percent relative
humidity) by the use of water injection. Operation on fuel oil is limited to no
more than 1,000 hours per year per turbine and only during times that natural
gas is unavailable.
The CTs are equipped with DLN-I combustors for control of NOX
emissions while burning natural gas. Traditional control for CTs was comprised
of water injection into the combustors to cool the flame and inhibit NOX
formation, whereas dry low-NOX technology premixes fuel and air to provide a
lean flame with a more uniform and lower burning temperature than a conventional
burner. Additionally, the dry low-NOX combustor has a shorter, lower residence
time flame. Both lower temperature and shorter time contribute to NOX emissions
equal to or lower than that achieved by conventional steam and water injection.
Control of NOX while burning No. 2 distillate fuel oil is performed by injection
of demineralized water into the combustion chamber.
OFF-SITE REQUIREMENTS
FUEL SUPPLY
The Dahlberg Facility is located approximately two miles east
of a pipeline owned by Transcontinental Gas Pipe Line Corporation ("Transco").
Georgia Power has constructed a 20-inch diameter by 2-mile lateral connecting to
the Transco line. Although Georgia Power has reimbursed Transco for the
construction of the tap facilities, Transco owns and operates these facilities.
Gas transportation service is supplied on a seasonal or daily basis through the
Transco line. The lateral is of sufficient capacity to support the ten
simple-cycle units at the Dahlberg Facility. In the event of an interruption in
natural gas, the Dahlberg Facility has a 3.6 million-gallon, No. 2 fuel oil
storage tank on the site. The tank is of sufficient capacity to operate all ten
units at base load for over 2 days.
Natural gas fuel for the Franklin Facility is delivered to the
Franklin Facility Site through a 20-inch pipeline lateral extending from the SNG
main line located approximately 5.5 miles south of the Franklin Facility Site.
A-10
Southern Power owns and operates the meter station which is located adjacent to
the pipeline tap location. SCS purchases natural gas from Gulf Coast for
delivery to the Franklin Facility.
The natural gas pipeline to the Harris Facility Site is 24
inches in diameter and approximately 12 miles in length. The pipeline was
constructed by Southern and runs parallel to the existing 500 kV power
transmission line. The pipeline ties into an existing pipeline owned and
operated by Southern Natural Gas ("SNG"), a wholly-owned subsidiary of El Paso
Corporation. SNG is not affiliated with Southern. SCS purchases natural gas from
Gulf Coast Natural Gas for delivery by SNG to the plant. A metering station
adjacent to the pipeline tap location and a gas conditioning station has been
constructed on site.
The natural gas pipeline to the McIntosh Facility is to be 16
inches in diameter and approximately 600 feet in length. The pipeline will tie
into an existing 16-inch pipeline that provides gas to the existing peaking
units located adjacent to the McIntosh Facility Site. The existing 16-inch
pipeline is a 5.2-mile lateral pipeline that is connected to a 24-inch pipeline
owned and operated by SNG. Savannah Electric will purchase natural gas from El
Paso Merchant Energy, L.P. for delivery by SNG to the plant. All the gas
delivered to the McIntosh Facility will be filtered, metered and reduced in
pressure at the gas conditioning area, located at the property boundary. The gas
will be preheated and flow through a final filter/separator prior to use in the
CTs.
The natural gas pipeline to the Stanton Facility is 16 inches
in diameter and approximately 5.2 miles in length. The pipeline ties into an
existing pipeline owned and operated by Florida Gas Transmission Company. All
the gas delivered to the Stanton Facility will be filtered, metered and reduced
in pressure at the gas conditioning area, located at the property boundary. The
gas will be preheated and flow through a final filter/separator prior to use in
the CTs. No. 2 oil is the standby fuel to permit operation in the event of an
interruption in the supply of natural gas. No. 2 oil is stored in a tank that
will hold approximately 1.7 million gallons of fuel. This is enough fuel for
approximately 2.5 days of operation with both CTs at full load output. The fuel
oil system includes three truck unloading stations, a storage tank, forwarding
pumps and filter.
The natural gas pipeline to the Wansley Facility is 30 inches
in diameter and is owned by Southern Power. The gas pipeline connects to the
existing Transco system located approximately 6.5 miles south of the Wansley
Facility. Southern Power is to reimburse Transco for the construction of the tap
and metering facilities and Transco will retain ownership and operation
responsibilities for the newly installed system in accordance with the
Interconnect, Reimbursement and Operating Agreement. SCS purchases Gulf Coast
natural gas supplies for delivery of the Wansley Facility's projected peak day
gas requirements.
Additionally, Southern Power has executed a gas storage
contract with Petal Gas Storage Company ("Petal"), to provide fuel storage for
all of the Generating Facilities except the McIntosh and Stanton Facilities.
This contract provides 700,000 million British thermal units ("MMBtu") per day
up to a total of 7,000,000 MMBtu for up to ten days if gas flow is interrupted.
WATER SUPPLY AND TREATMENT
The Jackson County Water and Sewage Authority (the "Water
Authority") supplies potable water for use by the Dahlberg Facility personnel
for drinking and sanitary purposes. The Dahlberg Facility is limited to a
maximum water take of 0.5 million gallons per day ("mgd") at a flow rate of 450
gallons per minute ("gpm") and a pressure of 100 psi until termination of the
contract on June 30, 2019. Upon completion of a new reservoir for Jackson
County, which has been completed and is expected to be in service by July 1,
2002, the Water Authority will be capable of providing a flow rate of 900 gpm.
Demineralized water is supplied by trailer-mounted mobile units through an
agreement with Ecolochem, Inc. ("Ecolochem"). Demineralized water is stored in a
2.4 million-gallon storage tank on-site. This storage capacity provides
approximately 1.4 days of full load operation while firing No. 2 fuel oil.
Primary water usage for the Franklin Facility is for the
cooling water system and steam cycle makeup. Major water usages during
continuous operation include: cooling tower blowdown, cooling tower evaporation,
CT evaporative cooler evaporation, CT evaporative cooler blowdown, HRSG
blowdown, CT on-line compressor wash water, and CT steam injection losses
(during power augmentation operations only). The cooling
A-11
water system has the greatest water need of all the systems. Raw water is taken
from the Chattahoochee River via an existing unused penstock located within the
Goat Rock Dam located approximately one mile east of the plant. Wastewater is
discharged in the tailrace of the same dam. Demineralized water for the Franklin
Facility is provided by Water & Power Technologies. The raw water needs of the
Franklin Facility are supplied through the existing Goat Rock Dam.
The water supply for the Harris Facility will be obtained from
two different locations. The primary source of process water is the Alabama
River located at the southern edge of the property and will be used for cooling
water, makeup water, and fire protection water. The second source of water will
be from a nearby municipal water supply system and will be the sole source for
the Harris Facility's potable and sanitary water needs. An on-site water
treatment system will prepare the river water for use by the plant. Primary uses
of the plant's process water will be for the cooling water system and steam
cycle makeup. Southern Power estimates a total water demand of approximately 9.5
mgd (which corresponds with the quantity of water Southern Power has applied for
withdrawal from the Alabama River), based on an annual average including plant
makeup water, for the two power blocks. Filtered water will be used for fire
protection purposes and the source for the Harris Facility's demineralized water
needs. Demineralized water will be used for on-line CT compressor wash water,
steam injection, and general steam cycle makeup. The Harris Facility will
include a 1.0 million-gallon demineralized water storage tank and a
300,000-gallon filtered water storage tank.
The McIntosh Facility will be supplied with raw water from the
existing Savannah Electric facility which is located approximately one mile
northeast from the McIntosh Facility. The raw water supply for McIntosh Facility
will be the Savannah River near the City of Savannah. Potable water is to be
supplied via an on-site well. Southern Power indicated that raw water is to be
delivered to the McIntosh Facility via a 30-inch supply line and will be stored
in an on-site storage tank. This water will subsequently be used for fire
protection, cooling water, and treated for process water. Although Southern
Power represents that Savannah Electric is to provide raw water to the McIntosh
Facility, we are not aware of any contractual requirement to do so. However,
Southern Power reported that the draft Memorandum of Operator Interface
Procedures dated January 1, 2003, is to be amended to obligate Savannah Electric
to provide specific water and wastewater services for the McIntosh Facility.
The raw water supply for the Stanton Facility cooling tower
makeup is to be pumped, via the installation of new raw water pumps, from OUC's
existing makeup pond located at the Stanton Facility Site to a distribution
system. Demineralized water will be used for on-line CT compressor wash water,
water injection during operation on No. 2 fuel oil, source for steam injection
(power augmentation), and general steam cycle makeup. Demineralized water is to
be provided by OUC from the demineralizer at the SEC coal unit. The SEC
demineralized water plant is to be expanded to accommodate the Stanton
Facility's anticipated demineralized water requirements. A 1.6 million-gallon
tank is to be constructed to provide the necessary storage requirements. Potable
water, which is to be used for domestic, washdown, and sanitary purposes, is to
be provided via an extension of the existing potable water system at the SEC,
which is supplied from a nearby municipal potable water system.
The water supply for the Wansley Facility is obtained from the
Plant Wansley reservoir located northeast of the Wansley Facility Site. A new
60-inch suction header has been installed at the existing reservoir to supply
water to the Wansley Facility via an expanded pumping station located at the toe
of the reservoir embankment approximately 2 miles northeast of the Wansley
Facility. As a result of the proximity of the reservoir to the Wansley Facility,
the need for an on-site raw water storage tank is eliminated. Southern Power
entered into a ten-year extended term agreement with Ecolochem to build, own,
operate, and maintain a water treatment facility for the Wansley Facility.
Ecolochem is to supply all water production, filtered and demineralized, for the
project. The water treatment system has been sized to accommodate water usage
requirements of the Wansley Facility. Two demineralized water storage tanks have
been constructed at the Wansley Facility, each one with storage capacity of a
million gallons. It should be noted that there are some discrepancies between
the water quality requirements set forth in the Wansley Facility LTSA and HRSG
contract with respect to total organic carbon ("TOC"). SCS noted that the TOC
levels cited for makeup water, feedwater, and steam purity are consistent with
industry standards and that TOC is to be removed from the system via HRSG
blowdown. Based on discussions with SCS, the anticipated TOC concentration in
the
A-12
make-up water, and the effects dilution will have on the overall TOC
concentration, it is our understanding that the anticipated TOC concentration
levels will satisfy the LTSA and HRSG water quality requirements.
WASTEWATER DISPOSAL
Treated wastewater will be conveyed from the Franklin Facility
Site to the tailrace of the Goat Rock Dam via a piping system installed along
the transmission tower corridor. The ultimate disposition of the treated
wastewater is the Chattahoochee River. Surface water will be channeled directly
to an on-site retention pond where it will be allowed time to settle and
equalize prior to discharge to the surrounding environment. Process wastewater
is pumped to the tailrace of the Goat Rock Dam for discharge. Southern Power
notes that while some dilution effects will be realized by the discharge to the
tailrace, a specifically-designed dilution system will not be included as part
of the wastewater system, which is consistent with the approved water discharge
permit for the Franklin Facility.
The Harris Facility's plant wastewater drains are to be pumped
to a wastewater holding pond. HRSG blowdown is to be drained by gravity to the
cooling tower basin along with ST start-up drain tank effluent. Wastewater
collected in drains throughout the plant that has the potential for containing
oil contamination will be collected and treated through an oil/water separator.
Surface water from storm events will be collected in an on-site retention pond
where it will be allowed to overflow to the Alabama River.
Process wastewater from the McIntosh Facility is to be
returned to the existing Savannah Electric facility for discharge to the
Savannah River through the outfall structure at the existing Savannah Electric
facility.
Plant wastewater drains at the Stanton Facility are collected
in sumps and pumped to a low volume sump, which drains to the SEC existing
recycle basin. HRSG blowdown is sent to the cooling tower basin. Wastewater
collected in drains throughout the plant that has the potential for containing
oil contamination will be collected and treated through an oil/water separator.
Surface water from storm events will be directed to the existing facilities at
the SEC.
Wastewater from the Wansley Facility is to be transferred to
the existing ash pond located approximately one mile directly north of the
plant. The wastewater will intermingle with the Plant Wansley wastewater
discharge in the ash pond. The ash pond was originally constructed to allow for
settling of fine particulates prior to discharge to the retention pond. From the
outlet of the ash pond, the wastewater gravity feeds to a retention pond located
south of the Wansley Facility Site where it overflows to the Chattahoochee
River. Surface water will be channeled directly to the retention pond and then
to the Chattahoochee River.
ELECTRICAL INTERCONNECTION
The Dahlberg 230 kV Switchyard consists of one bus with five
step-up transformer positions and one ongoing transmission line position. An
approximate one-mile, two-conductor 230 kV transmission line connects the
switchyard to Georgia Power's Center Substation.
The Franklin Facility is interconnected through the Goat Rock
230 kV Switchyard, which consists of a single bus, single breaker arrangement
with three transformer positions each for Franklin 1 and 2, and one transmission
line position. The Goat Rock 230 kV Switchyard is interconnected via a
transmission line to the Southern transmission system at the existing ring bus
arranged 230 kV Goat Rock Substation, located approximately 1.5 miles from the
Franklin Facility Site.
The Harris 1 230 kV plant switchyard is a single bus, single
breaker arrangement with three transformer positions and one transmission line
position. The Harris 2 500 kV plant switchyard is a single bus, single breaker
arrangement with three transformer positions and one transmission line position.
Short transmission lines for Harris 1 and 2 of approximately 0.15 and 0.5 miles
in length, respectively, are routed from the plant switchyards to new Alabama
Power 230 kV and 500 kV switchyards.
The 230 kV switchyard at the McIntosh Facility consists of two
230 kV collector buses connected to the West McIntosh substation, located
approximately 1,000 feet from the Facility Site. The West McIntosh 230 kV
A-13
Substation is connected to the West McIntosh 500 kV Substation, configured as
four-breaker ring bus, via two 500/230 kV autotransformers. The West McIntosh
230 kV Substation is also connected to the McIntosh 230 kV Substation via two
transmission lines. The West McIntosh 500 kV Substation has two transmission
exits, one to Vogtle and the other to Thalmann.
The 230 kV switchyard at the Stanton Facility consists of a
single bus, single breaker arrangement with three transformer positions for
generator step-up transformers and one transmission line position. The 230 kV
switchyard is to be interconnected to the OUC transmission system at the
existing bay, breaker-and-a-half, Stanton Substation No. 17, located
approximately one mile from the Stanton Facility Site.
The Wansley 500 kV Switchyard consists of a single bus, single
breaker arrangement with three transformer positions for Wansley 6, three
transformer positions for Wansley 7, and one transmission line position. The 500
kV switchyard is to be interconnected to the Georgia Power transmission system
at the existing four-bay, breaker-and-a-half Wansley 500 kV Switchyard, located
approximately one mile from the Wansley Facility Site.
An interconnection study for the McIntosh Facility was
conducted to analyze the load flow, stability, and short-circuit analysis of the
transmission system. As a result of the study, some system upgrades are
required. The necessary improvements are to be provided by Georgia Power and the
associated cost is to be reimbursed by Southern Power. Southern Power has also
entered into a 40-year interconnection agreements with Georgia Power for each of
the two McIntosh Facility power blocks. Based on the information outlined in the
interconnection study and execution of the interconnection agreements, the
McIntosh Facility should be able to interconnect to the transmission system and
deliver a net electrical output of 1,240 MW at the interconnection point.
Although a formal interconnection study was not conducted for
the Stanton Facility, OUC performed a series of studies to evaluate the impact
of interconnecting the Stanton Facility to the OUC 230-kV transmission system.
The studies performed included a short circuit study to identify system
improvements required for purposes of the interconnection and a study to
evaluate the capability of the transmission system to receive the output from
the Stanton Facility. The results of the short circuit study indicated that with
the Stanton Facility connected, the available fault current levels at the SEC
and several other OUC substations would equal or exceed the interrupting
capacity rating of the circuit breakers. As an alternative to replacing the
circuit breakers, OUC conducted a separate study to evaluate splitting the bus
of the modified OUC Stanton Substation. This would create two separate 230 kV
breaker-and-one-half substations tied together by breakers with one substation
connected to OUC's existing generation at the SEC site and the other connected
to the Stanton Facility. OUC has verbally committed that this work will be
completed prior to initial synchronization of the Stanton Facility. The study
performed to evaluate the capability of the OUC transmission system identified
only one upgrade that was required to an existing 230 kV transmission line. This
upgrade required the removal of several swing brackets on the steel structures
of the existing line. Southern Power has submitted a request for OUC to perform
a stability study to determine whether the integration of the Stanton Facility
causes any stability problems on the OUC system. OUC has indicated that it
intends to perform the stability study prior to initial synchronization of the
Stanton Facility. The stability impacts of the integration of the Stanton
Facility on the OUC transmission system will be determined by the stability
study.
REVIEW OF TECHNOLOGIES
The following section contains a discussion of our review of
the critical areas of the Generating Facilities' design and the ability of the
equipment and design to meet the projected performance, operating cost, and
environmental permit requirements. CT and ST technology has been used in
electrical generation and energy recovery for over four decades. The development
and operating histories of the specific models utilized by the Generating
Facilities are described herein to promote an understanding of the risks
associated with these models.
GE 7FA CT
The Franklin, Harris, McIntosh, Stanton and Wansley Facilities
utilize the GE Frame 7241FA CT (the "7241FA"), which represents the fourth
technology/operational improvement in the Frame 7F evolution since its
introduction to the market in June 1987. The Frame 7F engine design was based on
its successful predecessor, the
A-14
Frame 7E/EA, which has over 600 units installed and has accrued over 15 million
operating hours. While the Frame 7F/FA is considered mature technology with over
416 units installed, 4.1 million fired hours, and over 106,000 fired starts
fleet-wide, of the 324 7241FA units currently in operation as of February 2003,
the fleet leader has only accumulated approximately 22,300 fired hours and 650
fired starts.
The GE Frame 7F/FA CT, including the 7241FA, is a two-bearing
machine, using a single rotor comprised of a compressor and turbine sections
with cold end (compressor side) electric generator drive. Each section consists
of a series of discs or wheels and spacers held together with tie bolts. The
following discussion presents an overview of the technical development of the
7241FA and identifies the potential risks and risk mitigation strategies for
that model. This is followed by a description of serial issues that the 7F/FA
fleet has experienced or that GE is in the process of correcting in the last
three years, which have the potential to apply to the 7241FA and consequently
affect the Projected Operating Results ("Operational Issues").
TECHNICAL DEVELOPMENT
Since the market inception of the GE Frame 7F in 1987, there
have been five product offerings within the Frame 7F family, based on technology
or operational changes. The fourth of these is the 7241FA used by the Franklin,
Harris, McIntosh, Stanton, and Wansley Facilities. GE's approach to CT
development has traditionally followed the philosophy of evolution of designs,
by making incremental changes from one frame or model designation to the next.
Using this design philosophy in combination with component and full-scale engine
shop and field testing, GE is able to retain its previously designed products'
most successful attributes, while exercising the full performance capabilities
of its new design. It is through full-scale engine testing that GE was able to
recognize the potential of the Frame 7F/FA compressor and the impacts of raising
the firing temperature to its current level, each of which resulted in
developments incorporated into the 7241FA design.
PERFORMANCE CHARACTERISTICS
In general, GE has improved the performance of its engines
with airflow and firing temperature increases, as well as implementing
improvements in turbine cooling, and compressor and turbine sealing. Firing
temperature refers to rotor inlet temperature, which is experienced at the
upstream side of the row 1 turbine blades. GE also uses advances in material
technology throughout the entire CT to enable the performance improvements
sought, and to increase the engine reliability by employing materials that are
more robust at the temperatures and operational characteristics of the given
design. Table 3 compares the major operational characteristics and hours of
operation of the Frame 7F evolution through the 7241FA, as of February 2003.
TABLE 3
FRAME 7 F/FA
OPERATIONAL CHARACTERISTICS
7191F 7221FA 7231FA 7241FA
----- ------ ------ ------
ISO Output (MW) 150 159 167.8 171.7
ISO Heat Rate (HHV)(Btu/kWh) 10,950 10,535 10,400 10,380
Firing Temperature (Degree F) 2,300 2,350 2,400 2,420
Pressure Ratio 13.5:1 15.1:1 14.9:1 15.5:1
Units in Service (1) 16 44 30 220
Fleet Leader Operating Hours (1) 58,000+ 75,000+ 34,000+ 22,300+
Fleet Leader Commercial Operation Date 1991 1993 1997 1999
KEY FEATURES
The specific changes made to the 7231FA model design that
result in the 7241FA designation are the following: (1) firing temperature
increase from 2,400(degree)F to 2,420oF; (2) increase in compressor airflow and
pressure
A-15
ratio by modulating the compressor inlet guide vanes to a new position; (3) the
use of directionally solidified row one turbine blades; (4) new thermal barrier
coatings on the first stage turbine vanes and blades; and (5) the use of
improved cooling and sealing throughout the hot gas path.
In addition to changes (1) through (5) delineated above, GE
has modified the compressor section of all 7241FA CTs, which have been shipped
after September 12, 2000 (which include the CTs utilized by the Franklin,
Harris, , McIntosh, Stanton, and Wansley Facilities) by incorporating the
following features: (a) the outer diameters of the first five stages of
compressor blades have been flared to a slightly larger diameter, adding 0.35
inches to the radius of the first stage compressor blade, tapering to a zero
inch increase by the stage six blade; (b) the compressor casing and stage one
through stage five compressor vanes, also referred to in the industry as
diaphragms have been modified to accommodate the flaring in the first five
stages of compressor blading; and (c) the inlet casing (the casing upstream of
the compressor section's inlet guide vane) and the inlet guide vane aerodynamics
have been further optimized to reduce inlet aerodynamic losses. GE reports that
modifications (a), (b), and (c) have been made to increase commonality with the
GE 7251FB (GE's newest Frame 7F product offering). This allows GE to better
optimize its manufacturing production cycles. These modifications have not
resulted in a re-rating of the 7241FA's base thermodynamic performance, as
compared to the 7241FAs shipped prior to September 12, 2000. GE further reports
that modifications (a), (b), and (c) have been tested at full-speed-no-load at
its Greenville, South Carolina manufacturing facility, and have been
successfully operated in the field at many commercial facilities.
Though the 7241FA fleet leader has operated in excess of
22,300 fired hours, the effects of long-term operational issues related to most
of these changes have not yet been validated by field experience.
COMBUSTION SYSTEM
The Franklin, Harris, McIntosh, Stanton, and Wansley
Facilities utilize the GE DLN-2.6 combustion system as the primary emissions
control mechanism. The DLN-2.6 is the latest development in the GE low emissions
combustion technology, and the third major technology and operational change
made in the dry low-NOX evolution at GE. The DLN-2.6 is a can-annular design
(containing 14 individual combustor baskets and transition pieces on the
7241FA), which has six premixed fuel nozzles per combustor, five on the
periphery and one in the center. For the 7241FA, GE offers a standard NOX
guarantee of 9 ppmvd when firing natural gas fuel over a range of 50 percent to
100 percent of base load. The DLN-2.6 is an incremental technology improvement
over its predecessor the DLN-2.0, which lacks the sixth premixed fuel nozzle in
the center of each combustor. The DLN-2.0 design was first operated in
commercial service in February 1994, and the DLN-2.6 was placed into service in
March 1996. As of February 2003, GE reports over 480 units operating with its
dry low-NOX technology with over 5.2 million fired hours, of which 1,200,000
hours were on Frame 7F machines. DLN-2.6 in all its applications has accumulated
in excess of 1,600,000 fired hours. Of the DLN-2.6 systems currently operating
at 2,420(Degree)F, the nominal firing temperature of the 7241FA, the fleet
leader has in excess of 22,300 fired hours as of February 2003.
The sixth fuel nozzle in the center of the DLN-2.6 combustor
design was added to the DLN-2.0 design to allow 9 ppm NOX control from 100
percent down to 50 percent of base load, which was unachievable over that entire
range without the change. In addition, the DLN-2.6 operates over the entire load
range without the requirement of a diffusion flame, whereas the DLN-2.0 utilizes
a diffusion flame at low loads.
STEAM INJECTION FOR POWER AUGMENTATION
In addition to hardware changes that have resulted in the
7241FA CT, equipped with the DLN-2.6 combustion system, the GE 7FA Facilities
will utilize steam injection for power augmentation, which has not accrued
extensive usage by GE as an enhancement to the Frame 7F/FA based plants' net
facility output. Currently GE reports to have several 7241FA units, equipped
with the DLN-2.6 combustion system, operating with steam injection for power
augmentation, as well as several other Frame 7FA units (i.e., 7221FA and
7231FAs) operating with steam injection for power augmentation, equipped with
either DLN-2.0 or DLN-2.6 combustion systems (the latter of which GE reports is
very similar to the DLN-2.6 utilized in the 7241FA). GE has indicated that it
currently does not monitor detailed operating history such as fired hours and
steam injection rates on units that utilize steam injection for power
augmentation.
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GE offers a NOX guarantee of 12 ppm for the 7241FA, equipped
with the DLN-2.6 combustion system, where firing natural gas fuel during periods
when steam injection for power augmentation is utilized, rather than the 9 ppm
guarantee previously discussed. In addition, GE has issued a technical paper
(which is referenced in GE's Long Term Parts and Services Agreement for which
the Generating Facilities which incorporate the GE 7FA will participate) that
states an impact factor of 1.5 on actual maintenance operating hours at a
maximum allowable steam injection rate of 5 percent of CT inlet airflow in the
7241FA. However, the elevated impact factor is only applicable to a "wet
control" operating mode, which is the mode of power augmentation when the firing
temperature is held constant and not depressed. The other mode of operation is
referred to as the "dry control" mode where the firing temperature is reduced
and the maintenance impact factor is not affected. Southern Power reports that
the 7FA CTs utilized by the Generating Facilities operate or will operate in a
"dry control" mode.
OPERATIONAL ISSUES
In the last three years, GE Frame 7F/FA machines have
experienced certain operational issues or GE is in the process of correcting
prior issues, in its compressor and turbine sections for that frame. Some of
these issues are related to characteristics of the earlier Frame 7F/FA designs,
and GE reports that all 7241FA machines will include the appropriate changes to
prevent these issues from reoccurring on the 7241FAs utilized by the Franklin,
Harris, McIntosh, Stanton, and Wansley Facilities. A brief description of the
issues and the subsequent resolutions are given below.
Compressor Section. In the first quarter of 2001, failed
seventeenth stage diaphragms were discovered in two 7241FAs at one project,
while inspecting the CTs during a boroscope inspection following high vibration
levels in one of the CTs. GE reported that the root cause of the failure was
cracking due to high aerodynamic stresses caused by a flow separation downstream
of a recessed area in the diaphragm. GE explained that the recessed areas were
machined into the diaphragms for bolting the four seventeenth stage compressor
segments of the diaphragms together. GE further reported that the aerodynamic
stresses were exacerbated by high mass flows through the compressor at the site
where the cracking was found, as the cracking is believed to have occurred while
commissioning that plant during cold temperatures. GE reported that its
permanent remedy to this issue involves covering the bolt hole recession with a
blank of the same contour as the diaphragm to eliminate the aerodynamic
separation which GE reports excited the compressor diaphragms. GE reported that
its interim solution is to utilize inlet bleed heat at a higher ambient
temperature than it had employed for such heating prior to this issue being
encountered. Inlet bleed heating is the process of diverting intra-stage
compressor air to the compressor's inlet to blend the incoming cold ambient air
with the warmer compressor intra-stage air. GE believes that these remedies have
mitigated the flow separation issue that led to the high aerodynamic stresses,
and that similar issues should not occur on subsequent units that include these
remedies. Southern Power has reported that the CTs at the Franklin, Harris,
McIntosh, Stanton, and Wansley Facilities currently incorporate the software
changes necessary to bring the inlet bleed heat on at higher ambient
temperatures, and it plans on incorporating the hardware change described above
(the GE reported permanent remedy to this issue) at the first hot gas path
inspection for each unit.
In 2002 and 2003, GE submitted several Technical Information
Letters ("TILs") that discuss the susceptibility of the 7241FA's compressor
section to erosion, damage, and potentially part failure when exposed to liquid
water during operation. The CTs affected by these TILs are those that utilize
online water washing (to reduce the effects of compressor fouling), inlet
evaporative coolers, and/or inlet fogging. The Franklin, Harris, McIntosh,
Stanton, and Wansley Facilities each utilize inlet evaporative cooling and
intend to utilize online water washing, as required, to maintain higher levels
of thermodynamic performance during commercial operation. GE has recommended the
following in its TILs, as applicable to the Franklin, Harris, McIntosh, Stanton,
and Wansley Facilities: (i) increased inspection requirements and intervals for
the inlet evaporative cooling system; (ii) potentially ceasing the use of
evaporative cooling until modifications can be made to any affected row 0
compressor blading; and (iii) increased inspection intervals for the first few
compressor blade stages and potentially more frequent compressor maintenance
than originally anticipated by GE for those parts.
GE reported that if the evaporative coolers for its 7241FA
units are commissioned and maintained according to its recommendations, such
that no water carryover into the compressor section is allowed that blade
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erosion should not be a concern for this reason. GE further reported that after
a given unit operates for approximately 300 to 400 hours with the evaporative
coolers in use that it will recommend taking a mold of the row 0 compressor
blades to assess any erosion at that time and provided that GE finds little or
no erosion, it will permit unrestricted evaporative cooler operation going
forward. As related online water washing, GE has recommended certain
modifications to its online water washing system that it reports to have
verified reduced erosion to the row 0 compressor blades and has additionally
increased the effectiveness of the online water washing process. GE is still
recommending that molds be taken of the row 0 compressor blades after 100 hours
of cumulative online water washing to assess erosion of such blades (if any)
until such time as it can complete its ongoing water washing verification
program and permit longer inspection intervals. Southern Power reports that it
is aware of GE's recommendations for both its evaporative coolers and online
water washing and is working to maintain its evaporative coolers so that water
carryover is not a concern and is making all required modifications and
inspections of the water washing system and the row 0 compressor blades.
Turbine Section. The shroud tips of the row 2 turbine blades
are reported by GE to be susceptible to creep deformation that results in a slow
and progressive distortion of the blade shroud under operating loads and
temperatures. GE reports that it has issued instructions to users to grind
material off a tip seal or cutter tooth on the shroud and that if this action is
performed in the first 4,000 hours of operation that the blades should be able
to make the published life expectancy. The GE advisory further recommends a
borescope inspection be performed every 8,000 hours to inspect for creep
deformation of the row 2 turbine blades. GE reports that it has created an
alternate design of the row 2 turbine blade which reduces the mass of the
shroud, moves the tip seal to the center of the shroud, and improves the shroud
cooling to improve its creep life. Southern Power reports that it will make the
required modifications to the row 2 blades and that the improved blades will be
incorporated into the units as part of the normal parts replacement intervals.
GE 7EA CT
The Dahlberg Facility utilizes a GE 7EA CT set equipped with
dry low-NOX combustors. The 7EA is a 3,600-rpm heavy-duty CT with a 17-stage
axial flow compressor and a 3-stage power turbine designed to serve the 60 Hz
power generation needs for utility and industrial service.
TECHNOLOGY EVOLUTION
GE's approach to CT development is discussed in the GE 7FA CT
section of this Report. As mentioned in that section, over 600 GE Frame 7E/EA
units are in operation worldwide, and have accumulated over 15 million hours of
operation since the initial introduction in the 1970s. The 7EA product offering
first achieved commercial operation in the mid-1980s.
While the 7EA, an upgrade of the GE 7E CT, has evolved during
its approximate 20-year operating history, the base design of the current 7EA is
largely unchanged from its predecessors. Some of the key features utilized in
the current 7EA CT are a 2,035(Degree)F firing temperature, certain improved hot
gas path part alloys, better sealing, increased compressor massflow, and the use
of thermal barrier coatings.
Additionally, the Dahlberg Facility CTs utilize GE dry low-NOX
combustion technology. GE has reported that its GE 7EA dry low-NOX combustion
system has consistently achieved 9 ppmvd NOX control while operating on natural
gas at the nominal GE 7EA firing temperature of 2,035(degree)F.
SUMMARY
Based on our review, we are of the opinion that, based on GE's
previously demonstrated capability to address issues similar to those related to
the Frame 7FA described herein, the power generation technologies proposed for
the Generating Facilities are sound, proven methods of energy recovery. If
constructed, operated and maintained as proposed by Southern Power, the
Generating Facilities should be capable of meeting the requirements of the PPAs
and the currently applicable environmental permit requirements. Furthermore, all
off-site requirements of the
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Generating Facilities have been adequately provided for, including fuel supply,
water supply, wastewater disposal, and electrical interconnection.
In addition, the proposed method of design, construction,
operation, and maintenance of the Generating Facilities has been developed in
accordance with generally accepted industry practice and has taken into
consideration the current environmental, license and permit requirements that
the Generating Facilities must meet.
ESTIMATED USEFUL LIFE
We have reviewed the quality of equipment installed at the
Generating Facilities and the general plans for operating and maintaining the
Generating Facilities. Based on our review and provided that: (a) the units are
operated and maintained by the operators in accordance with the policies and
procedures as presented by Southern Power, (b) all required renewals and
replacements are made on a timely basis as the units age, and (c) gas and oil
burned by the units are within the expected range with respect to quantity and
quality, we are of the opinion that the Generating Facilities should have useful
lives of at least 20 years.
PERFORMANCE TESTS AND GUARANTEES
All of the Generating Facilities except the Dahlberg Facility
were or are being constructed under an owner construction management approach
rather than having a turnkey, engineer, procure, and construct ("EPC") type
contractor provide the respective services. Under the construction management
approach, Southern Power accepts more responsibility for ensuring that these
projects are engineered, designed, constructed, and commissioned properly. The
construction management approach also requires Southern Power to be more
responsible for contract interface issues and the associated impacts on project
cost and schedule. Under a traditional EPC contract, an owner of a project would
place all these responsibilities on the EPC contractor, which increases the
contract cost to account for the added risk exposure the contractor assumes.
Southern Power, through SCS, is assuming this responsibility for the performance
of the Franklin, Harris, McIntosh, Stanton, and the Wansley Facilities. A
description of the performance tests and Southern completion guarantees for
these units are presented below.
Table 4 indicates the performance guarantees provided by
Southern for Franklin 2 and the Harris, McIntosh, and Stanton Facilities, as set
forth in Credit Agreement for the Commercial Construction Revolver dated April
17, 2003 (the "Construction Revolver Credit Agreement"). Franklin 2 and the
Harris Facility declared commercial operation under their respective PPAs on
June 1, 2003. Southern Power reports that the Franklin 2 and Harris Facilities
have completed their initial net plant output tests under the Franklin and
Harris PPAs.
TABLE 4
SOUTHERN PERFORMANCE GUARANTEES
OUTPUT HEAT RATE
(MW)(1) (BTU/KWH)(2)
------- ------------
Franklin 2 (3) 615 6,728
Harris 1 (3) 618 6,730
Harris 2 (3) 618 6,730
McIntosh 620 6,827
Stanton 633(4) 6,756
--------------------
(1) Represents net output at summer peak conditions, except for
the Stanton Facility which is based on an average ambient
temperature of 70(Degree)F.
(2) Represents base mode heat rate guarantee on a higher heating
value basis and at rated conditions, based on site
characteristics.
(3) Recently entered into commercial operation. Initial net plant
output test complete.
(4) Represents full output of the Stanton Facility. Southern Power
owns 65 percent of the Stanton Facility.
A-19
As a result of Southern Power's construction management
approach to engineering, design, procurement and construction of the Generating
Facilities (instead of hiring a turnkey contractor), the only performance test
program to verify project output and heat rate are the performance tests
Southern Power is required to perform under the PPAs and the Construction
Revolver Credit Agreement. Under the terms of the Construction Revolver Credit
Agreement, the heat rate and output tests are to be conducted in accordance with
the guidelines established in the applicable American Society of Mechanical
Engineer's Power Test Codes, prudent utility practices, and routine operating
conditions.
Emissions testing is to be performed in accordance with the
air permit and CT and HRSG purchase agreements. Successful demonstration of
emissions with air permit requirements is part of achieving Substantial
Completion as defined in the Construction Revolver Credit Agreement. The
equipment manufacturers (GE, Deltak, and Vogt) offer certain emissions
guarantees for their respective equipment. These guarantees, in some cases, are
not consistent with the emission limits set forth in the air permits.
Notwithstanding the apparent inconsistencies in the guarantees, the design of
each of the Generating Facilities includes provision for the installation of an
oxidation catalyst should one be required to comply with air permit limits for
CO and volatile organic compounds ("VOCs").
The performance test program that Southern Power is to perform
includes a 7-day reliability test which is intended to demonstrate that the
facilities are capable of continuous, reliable operation at various load points.
The reliability test is to be conducted during a continuous 168-hour period
during which the relevant project shall, among other things, achieve an
equivalent availability factor of 97 percent, operate for at least 24 hours in
the Summer Peak Output mode for such project (providing ambient conditions allow
for such operation and, in any event, at least 6 continuous hours of operation
in that mode is required), and operate for an additional 100 hours in either the
"Base Mode Heat Rate" mode or the "Summer Peak Output" mode (or at a point
between these two operating modes). During the reliability test, the facility is
to be operated in accordance with prudent utility practice and all laws, permits
and regulations applicable to such project including all emissions requirements
imposed by the air permit.
The PPAs for the Franklin, Harris, and McIntosh Facilities
require the facilities to be capable of "producing energy and delivering same to
the Transmission System through the Interconnection Point on a reliable basis."
The PPAs do not address how Southern Power is to demonstrate a reliable basis
prior to entering into commercial operation. Based on discussions with Southern
Power, it is our understanding that SCS determines when a respective plant is
ready for commercial operation based on the success of the commissioning
program, CT and HRSG component tests, and overall plant performance tests.
Southern Power represented that once they have completed the commissioning
program, including the reliability test discussed above, that most of the
potential reliability problems should have been identified and corrected, and
that it should be able to produce and deliver energy to the transmission system
of the power purchaser on a reliable basis.
Individual CT, ST, and HRSG component tests are typically not
conducted on projects constructed using a turnkey approach. SCS has included
such tests in the respective equipment purchase orders/agreements. As such, the
commissioning program SCS is to perform on the facilities incorporates more
equipment testing than what is typically provided for on turnkey projects.
Based on our review, we are of the opinion that the
performance guarantees proposed for the Generating Facilities under
construction, if all the equipment contract guarantees are considered in their
entirety, are similar to the performance tests of turnkey projects with which we
are familiar.
OPERATING PROGRAMS AND PROCEDURES
SCS, on behalf of Southern Power, manages and provides
operations and maintenance services for the Generating Facilities. Georgia Power
provides operations and maintenance support staff to SCS for the Franklin,
Dahlberg, and Wansley Facilities pursuant to the terms and conditions of an
Operating Agreement with Southern Power, dated December 18, 2002. Savannah
Electric is to provide operations and maintenance support staff to SCS for the
McIntosh Facility pursuant to the terms and conditions of an Operating Agreement
with Southern Power, which is to be effective January 1, 2003. Alabama Power
provides operations and maintenance support staff to SCS for the Harris Facility
pursuant to the terms and conditions of an Operating Agreement with Southern
Power, dated
A-20
June 30, 2001. Georgia Power, Alabama Power, and Savannah Electric provide
similar services for their respective utility power generation facilities.
SCS is to provide operation and maintenance services for the
Stanton Facility on behalf of Southern Company Florida pursuant to the terms and
conditions of an Operating Agreement with the Stanton Participants. Southern
Company Florida acts as the OUC's, KUA's, and FMPA's agent for the operation and
maintenance of the Stanton Facility during the term of the Stanton PPAs.
Southern Power has entered into LTSAs with GE for the
maintenance and overhaul of the CTs and STs furnished by GE. The LTSA for the
Stanton Facility has been assigned to Southern Company Florida, a direct
wholly-owned subsidiary of Southern Power.
We have reviewed the general application of the various
operations and maintenance ("O&M") programs and procedures within the Generating
Facilities, including: preventive, corrective and predictive maintenance plans;
operating procedures; and maintenance procedures. We did not review all aspects
of these plans and procedures, but verified that all of the usual and necessary
plans, procedures and documentation normally required to operate a facility of
this type were in place. Following is a brief description of the key programs
and procedures in place at the Generating Facilities.
SCS utilizes computerized maintenance management systems at
the Generating Facilities. In addition to the computerized maintenance
management systems, major outages are scheduled by SCS in coordination with
Southern Power generating resource requirements.
The predictive maintenance program includes the capability for
SCS with the support of Georgia Power and Alabama Power personnel and local
contractors to perform common predictive maintenance functions such as vibration
analysis and trending, infrared thermography to sense hot spots in electrical
and other equipment, and lube oil sample analysis. The Generating Facilities are
also using SCS's centralized maintenance program in which key pieces of
equipment will be analyzed and specific maintenance plans developed for the most
efficient maintenance of the equipment.
SCS maintains an appropriate collection of operating,
maintenance and administrative procedures which have been developed in
coordination with Southern Power. These procedures include normal operating and
maintenance procedures, as well as emergency response procedures for operating
events or the exceedance of environmental limits.
SCS is in the process of implementing reliability and
performance monitoring programs at the Generating Facilities. Principle among
these programs are a reliability improvement program to determine the root cause
of equipment failures, a boiler tube failure reduction program, a boiler
waterwall tubing survey and inspection program, a high energy piping inspection
program, and a pulverizer maintenance and performance program.
The plant staffing is projected to consist of approximately 9,
24, 28, 30, 23, and 28 on-site personnel at the Dahlberg, Franklin, Harris,
McIntosh, Stanton, and Wansley Facilities, respectively. Staffing at the
Franklin and Stanton Facilities are shared with adjacent generating units. SCS
has utilized a multi-skilled craft concept for most operating and maintenance
positions. With this concept, each plant technician has both a primary skill and
a secondary skill, with levels of proficiency within each skill. Maintenance
disciplines are divided between mechanical and electrical/instruments/controls.
Major maintenance for the CTs and STs are scheduled on the
basis of factored hours with the exception of the Dahlberg Facility, which is
scheduled based on factored starts as recommended by the manufacturer. Major
maintenance scheduled on a factored hours basis is performed at approximately a
48,000- to 50,000-hour interval. Overhaul durations are typically 2 to 4 weeks,
depending upon the scope of work to be performed. In years when there is no
major maintenance scheduled for a unit, a one- to two-week "mini-outage" is
performed on the CTs, STs, generators, HRSGs and auxiliaries.
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Based on our review, we are of the opinion that, through the
experience of Southern Power, Alabama Power, Georgia Power, Savannah Electric or
other Southern Company subsidiaries, SCS has demonstrated the capability to
operate the Generating Facilities. The operating programs and procedures which
are proposed or currently in place for the Generating Facilities are consistent
with generally accepted practices in the industry, and SCS has incorporated
organizational structures that are comparable to other facilities using similar
technologies for a similar service.
OPERATING HISTORY
Dahlberg 1-8 have been in operation since May 2000 and
Dahlberg 9-10 have been in operation since May 2001. Franklin 1 and the Wansley
Facility declared commercial operation under their respective PPAs on June 1,
2002. A summary of certain operating data for the 12 months ending May 31, 2003
for these facilities is presented in Table 5. Franklin 2 and the Harris Facility
declared commercial operation under their respective PPAs on June 1, 2003. As
such, no operating results are available for these facilities.
TABLE 5
OPERATING HISTORY (1)
NET NET ACTUAL STARTS /
EAF GENERATION HEAT RATE CAPACITY ATTEMPTED
UNIT (%) (MWH) (BTU/KWH)(2) FACTOR (%)(3) STARTS
---- ------ ---------- ------------ ------------- ---------------
Dahlberg 1 99.24 25,247 11,829 3.57 59/59
Dahlberg 2 100.00 21,846 11,829 3.09 54/54
Dahlberg 3 97.74 33,060 11,829 4.67 68/68
Dahlberg 4 100.00 22,938 11,829 3.24 50/50
Dahlberg 5 98.67 29,839 11,829 4.22 66/66
Dahlberg 6 95.53 21,907 11,829 3.10 48/48
Dahlberg 7 99.09 25,100 11,829 3.55 54/54
Dahlberg 8 99.16 19,866 11,829 2.81 41/41
Dahlberg 9 96.46 27,456 11,829 3.88 57/57
Dahlberg 10 99.20 29,228 11,829 4.13 64/64
Franklin 1 81.37 1,399,133 7,348 30.08 17/17
Wansley 6 95.61 1,643,644 7,192 34.72 19/19
Wansley 7 95.36 1,652,011 7,192 34.80 25/25
--------------------
(1) From June 1, 2002 through May 31, 2003.
(2) On a Higher Heating Value ("HHV") basis. Fuel consumption
recorded on a total project basis.
(3) Based on a peak output rating of 81 MW per unit.
CAPACITY AND HEAT RATE
Each of the respective PPAs includes specific capacity
designation and testing criteria as described below. The capacity payments
included in the Projected Operating Results presented later herein are based
upon the contractual capacity requirements in the PPAs through their respective
terms. Based on these capacity values, PA Consulting has estimated the energy
generation and fuel consumption of the Generating Facilities based upon its
projection of seasonal operation at various load levels and modes of operation.
THE DAHLBERG FACILITY
Under the terms of the LEM PPAs, the Dahlberg Facility is
required to provide a total contract capacity of 577.5 MW during the summer
months and 646.8 MW when firing natural gas during the winter months. Energy
payments are based on a heat rate of 12,300 Btu/kWh during the summer months and
11,931 Btu/kWh when
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firing natural gas during the winter months. These output and heat rate values
are subject to degradation as set forth in the LEM PPAs.
Based on information provided by Southern Power, we have
estimated the long-term annual average capacity to be 399 MW for Dahlberg 1-5,
159 MW for Dahlberg 6-8, and 239 MW for Dahlberg 9-10. This estimate includes a
levelized allowance for long-term degradation.
Under the terms of the LEM PPAs, fuel is purchased by Southern
Power and reimbursed by LEM according to the summer and winter heat rate curves
in the LEM PPAs. Heat rate degradation is provided for in the LEM PPAs. Based on
information provided by Southern Power, we have estimated the long-term,
full-load heat rate, including a levelized allowance for long-term degradation,
to be 12,352 Btu/kWh for the Dahlberg Facility. For the purposes of the
Projected Operating Results, we have assumed that the heat rate of the Dahlberg
Facility will be in accordance with the heat rate curves in the LEM PPAs and no
heat rate penalties will be incurred or bonuses achieved.
THE FRANKLIN FACILITY
The monthly capacity payments under the Franklin PPA are based
on the "Designated Capacity" for that annual period. The Designated Capacity is
adjusted by a monthly capacity payment factor of 0.15 for the months of June
through September and 0.05 for all other months. The Designated Capacity is
defined as the output nominated by Southern Power at the reference conditions or
"Rated Conditions," which are 95(degree)F and 45 percent relative humidity. The
Demonstrated Capability was determined by test upon commercial operation as the
amount of capacity Franklin 1 and 2 are able to provide at each mode of
operation corrected to "Rated Conditions" of 95(degree)F and 45 percent relative
humidity: "normal mode", "full-pressure mode", and "full-pressure mode with
power augmentation". Southern Power cannot nominate more than the Demonstrated
Capability at "full-pressure mode with power augmentation" as the Designated
Capacity. As a result of the Demonstrated Capability tests performed pursuant to
the Franklin PPA, the Designated Capacity has been set at 564 MW for Franklin 1
and 623 MW for Franklin 2.
In the event that the Franklin Facility is unable to supply
the Designated Capability, Southern Power may supply the requested output from
alternate resources. The Demonstrated Capability will be determined prior to
degradation of the Franklin Facility; therefore, we have assumed that Southern
Power will nominate a Designated Capacity equal to the Demonstrated Capability
in full-pressure mode with power augmentation less allowances for
non-recoverable degradation, fouling, and other operational factors that make it
difficult to achieve tested values on a day-to-day basis. Based on information
provided by Southern Power, we have estimated the long-term Demonstrated
Capability to be 542 MW for Franklin 1 and 598 MW for Franklin 2. This estimate
includes a levelized allowance for long-term degradation.
Under the terms of the Franklin PPA, fuel is purchased by
Georgia Power. Southern Power guarantees summer and winter heat rate curves in
the Franklin PPA and will reimburse Georgia Power if these guarantees are not
met. The demonstrated normal-mode and full-pressure mode capabilities will
determine the breakpoints at which the heat rates will be applied to the various
operating modes. Heat rate degradation is provided for in the Franklin PPA. As a
result of the performance tests performed pursuant to the Franklin PPA, Franklin
1 demonstrated a net plant heat rate, corrected to Rated Conditions, of 6,780
Btu/kWh. Based on information provided by Southern Power, we have estimated the
long-term, full-load heat rate, including a levelized allowance for long-term
degradation, to be 6,949 Btu/kWh for Franklin 1 and 6,879 Btu/kWh for Franklin
2. For the purposes of the Projected Operating Results, we have assumed that the
heat rate of the Franklin Facility will be in accordance with the heat rate
curves in the Franklin PPA and no heat rate penalties will be incurred or
bonuses achieved.
THE HARRIS FACILITY
The monthly capacity payments under the Harris PPAs are based
on the "Designated Capacity" for that annual period. The Designated Capacity is
adjusted by a monthly capacity payment factor of 0.15 for the months of June
through September and 0.05 for all other months. The Designated Capacity is
defined as the output nominated by Southern Power at the reference conditions or
"Rated Conditions," which are 95(degree)F and 45 percent relative humidity. The
Demonstrated Capability is determined by test upon commercial operation as the
amount of capacity Harris 1 and
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2 are able to provide at each mode of operation corrected to "Rated Conditions"
of 95(degree)F and 45 percent relative humidity: "normal mode", "full-pressure
mode", and "full-pressure mode with power augmentation." Southern Power cannot
nominate more than the Demonstrated Capability at "full-pressure mode with power
augmentation" as the Designated Capacity. As a result of the Demonstrated
Capability tests performed pursuant to the Harris PPAs, the Designated
Capability has been set at 627 MW for Harris 1 and 615 MW for Harris 2.
In the event that the Harris Facility is unable to supply the
Designated Capability, Southern Power may supply the requested output from
alternate resources. The Demonstrated Capability will be determined prior to
degradation of the Harris Facility; therefore, we have assumed that Southern
Power will nominate a Designated Capacity equal to the Demonstrated Capability
in full-pressure mode with power augmentation less allowances for
non-recoverable degradation, fouling, and other operational factors that make it
difficult to achieve tested values on a day-to-day basis. Based on information
provided by Southern Power, we have estimated the long-term Demonstrated
Capability to be 602 MW for Harris 1 and 590 MW for Harris 2. This estimate
includes a levelized allowance for long-term degradation.
Under the terms of the Harris PPAs, fuel is purchased by
Alabama Power and Georgia Power. Southern Power guarantees summer and winter
heat rate curves in the Harris PPAs and will reimburse Alabama Power and Georgia
Power if these guarantees are not met. The demonstrated normal-mode and
full-pressure mode capabilities will determine the breakpoints at which the heat
rates will be applied to the various operating modes. Heat rate degradation is
provided for in the Harris PPAs. Based on information provided by Southern
Power, we have estimated the long-term, full-load heat rate, including a
levelized allowance for long-term degradation, to be 6,883 Btu/kWh for Harris 1
and 2. For the purposes of the Projected Operating Results, we have assumed that
the heat rate of the Harris Facility will be in accordance with the heat rate
curves in the Harris PPAs and no heat rate penalties will be incurred or bonuses
achieved.
THE MCINTOSH FACILITY
The monthly capacity payments under the McIntosh PPAs are
based on the "Designated Capacity" for that annual period. The Designated
Capacity is adjusted by a monthly capacity payment factor of 0.175 for the
months of June through September, 0.05 for the months of January and February,
and 0.033 for all other months. The Designated Capacity is defined as the output
nominated by Southern Power at the reference conditions or "Rated Conditions,"
which are 95(degree)F and 45 percent relative humidity. The Demonstrated
Capability is determined by test upon commercial operation as the amount of
capacity McIntosh 10 and 11 are able to provide at each mode of operation
corrected to "Rated Conditions" of 95(degree)F and 45 percent relative humidity:
"normal mode", "full-pressure mode", and "full-pressure mode with power
augmentation." Southern Power cannot nominate more than the Demonstrated
Capability at "full-pressure mode with power augmentation" as the Designated
Capacity.
All capacity testing will be adjusted to the Rated Conditions
using correction curves supplied by SCS. The Demonstrated Capability of the
McIntosh Facility will be measured by the installed metering system. No test
tolerances or measurement uncertainties are to be permitted. All auxiliary
equipment must be operated in a normal manner consistent with prudent utility
practices.
On the date of the capacity tests, Southern Power is to bring
the McIntosh Facility to maximum normal capability. The tests will be scheduled
between the weekday hours of 11:00 a.m. and 7:00 p.m. and will be conducted over
an eight consecutive hour period, or less, at the respective power purchaser's
request. The capacity test will establish the Demonstrated Capability and will
be based on the average demonstrated net hourly output, corrected to Rated
Conditions, by use of correction curves supplied by SCS. The Demonstrated
Capability of the unit will be the average net output over the test period
corrected to Rated Conditions.
In the event that the McIntosh Facility is unable to supply
the Designated Capability, Southern Power may supply the requested output from
alternate resources. The Demonstrated Capability will be determined prior to
degradation of the McIntosh Facility; therefore, we have assumed that Southern
Power will nominate a Designated Capacity equal to the Demonstrated Capability
in full-pressure mode with power augmentation less allowances for
non-recoverable degradation, fouling, and other operational factors that make it
difficult to achieve tested values on a
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day-to-day basis. Based on information provided by Southern Power, we have
estimated the long-term Demonstrated Capability to be 595 MW for McIntosh 10 and
595 MW for McIntosh 11. This estimate includes a levelized allowance for
long-term degradation.
Under the terms of the McIntosh PPAs, Georgia Power and
Savannah Electric are responsible for reimbursing Southern Power for the cost of
fuel consumed by the McIntosh Facility at the guaranteed summer and winter heat
rate curves in the McIntosh PPAs. The demonstrated normal-mode and full-pressure
mode capabilities will determine the breakpoints at which the heat rates will be
applied to the various operating modes. Heat rate degradation is provided for in
the McIntosh PPAs. Based on information provided by Southern Power, we have
estimated the long-term, full-load heat rate, including a levelized allowance
for long-term degradation, to be 6,894 Btu/kWh for McIntosh 10 and McIntosh 11.
For the purposes of the Projected Operating Results, we have assumed that the
heat rate of the McIntosh Facility will be in accordance with the heat rate
curves in the McIntosh PPAs and no heat rate penalties will be incurred or
bonuses achieved.
THE STANTON FACILITY
Under the terms of the Stanton PPAs, the capacity payment is
the product of the "Demonstrated Capability" times the Annual Capacity Charge.
The "Designated Capability" is defined as the net capacity of the project,
determined by a periodic capacity test, adjusted to 70(degree)F and 45 percent
relative humidity.
On the date of the capacity tests, Southern Power is to bring
the Stanton Facility to maximum normal capability. The tests will be scheduled
between the weekday hours of 11:00 a.m. and 7:00 p.m. and will be conducted over
an eight consecutive hour period, or less, at the respective power purchaser's
request. The capacity test will establish the Demonstrated Capability and will
be based on the average demonstrated net hourly output, corrected to Rated
Conditions, by use of correction curves supplied by SCS. The Demonstrated
Capability of the unit will be the average net output over the test period
corrected to Rated Conditions. Based on information provided by Southern Power,
we have estimated the long-term Demonstrated Capability to be 621 MW for the
Stanton Facility. This estimate is based on the output at an ambient temperature
of 70(degree)F and includes a levelized allowance for long-term degradation. The
long-term output at the average annual temperature, including an allowance for
degradation, is estimated to be 606 MW.
Under the terms of the Stanton PPAs, fuel is purchased by OUC
and reimbursed by the power purchasers at cost. The demonstrated normal-mode and
full-pressure mode capabilities will determine the breakpoints at which the heat
rates will be applied to the various operating modes. Heat rate degradation is
provided for in the Stanton PPAs. Based on information provided by Southern
Power, we have estimated the long-term, full-load heat rate, including a
levelized allowance for long-term degradation, to be 6,915 Btu/kWh for the
Stanton Facility. For the purposes of the Projected Operating Results, we have
assumed that the heat rate of the Stanton Facility will be in accordance with
the heat rate curves in the Stanton PPAs and no heat rate penalties will be
incurred or bonuses achieved.
THE WANSLEY FACILITY
The monthly capacity and fixed O&M payments under the Wansley
PPAs are based on the "Contract Capacity Rating" for that annual period. The
Contract Capacity Rating will be based on the actual demonstrated capability
following performance testing corrected to 95(degree)F and 45 percent relative
humidity. The Contract Capacity Rating is to be declared each year thereafter.
The capacity dedicated to Georgia Power is to be 82.33 percent of the Contract
Capacity Rating, with the remaining output dedicated to Savannah Electric. Also
to be declared is the minimum normal capability, the maximum normal capability,
over-pressure mode (similar to full-pressure mode on the other Generating
Facilities) capability and capability in over-pressure mode with power
augmentation. During the months of June through September, the capability in
over-pressure mode with power augmentation is not to be less than the Contract
Capacity Rating.
In the event that the Wansley Facility is unable to supply the
Contract Capacity Rating, Southern Power may supply the requested output from
alternate resources. The demonstrated capability will be determined prior
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to degradation of the Wansley Facility; therefore, we have assumed that Southern
Power will nominate a Contract Capacity Rating equal to the demonstrated
capability in over-pressure mode with power augmentation less allowances for
non-recoverable degradation, fouling, and other operational factors that make it
difficult to achieve tested values on a day-to-day basis. Based on information
provided by Southern Power, we have estimated the long-term Contract Capacity
Rating to be 1,089 MW for the Wansley Facility. This estimate includes a
levelized allowance for long-term degradation.
Under the terms of the Wansley PPAs, fuel is purchased by
Southern Power and reimbursed by Georgia Power and Savannah Electric according
to the summer and winter heat rate curves in the Wansley PPAs. Fuel payments are
based on the "Contract Heat Rate", which is based on the delivered output for
each unit in each hour. The Contract Heat Rate is determined pursuant to heat
rate curves included in the Wansley PPAs for normal operation with the actual
output to fall between the minimum normal capability and the maximum normal
capability. Summer (May through September) and winter (October through April)
heat rate curves are included which specify the heat rate at any given output.
If the output is between the maximum normal capability and the over-pressure
mode capability, the unit output is to be calculated assuming a 50 MW block at a
heat rate of 9,100 Btu per kWh, plus the remaining output calculated using the
heat rate curves. If the output is between the over-pressure mode capability and
the capability in over-pressure mode with power augmentation, the unit output is
to be calculated assuming a 25 MW block at a heat rate of 13,000 Btu per kWh
plus the 50 MW block of over-pressure output at 9,100 Btu per kWh plus the
remaining output using the heat rate curves. Power augmentation is not available
at temperatures below 59(degree)F and is limited to 1,000 hours per year. Based
on information provided by Southern Power, we have estimated the long-term,
full-load heat rate, including a levelized allowance for long-term degradation,
to be 6,890 Btu/kWh for Wansley 6 and 6,923 Btu/kWh for Wansley 7. For the
purposes of the Projected Operating Results, we have assumed that the heat rate
of the Wansley Facility will be in accordance with the heat rate curves in the
Wansley PPAs and no heat rate penalties will be incurred or bonuses achieved.
SUMMARY
Based on our review, we are of the opinion that, if operated
and maintained as currently proposed by the operators of the Generating
Facilities, the Generating Facilities should be capable of achieving the annual
average output in full-pressure mode with power augmentation and the average
annual net plant heat rates assumed in the Projected Operating Results. These
estimates include allowance for corrections to reference conditions and
long-term degradation of output and heat rate. These assumptions represent the
average long-term performance [Redacted]. There may be years when the actual
performance is above or below the average performance stipulated herein.
However, for the purpose of the Projected Operating Results, we have utilized
these average performance assumptions.
AVAILABILITY
A number of the PPAs include contractual availability
requirements which impact the level of capacity payments under those contracts,
as discussed below. In general, the definitions of contractual availability
exclude scheduled maintenance, which reduced the actual availability of the
Generating Facilities. We have performed an analysis of Southern Power's
proposed operations and maintenance plan through the operating agreements with
the respective operators, taking into consideration the planned outages, as well
as actual industry operating experience regarding forced outage rates as
reported by various major equipment vendors, plant operators, and industry
monitoring sources (including NERC Generating Availability Data System) selected
for applicability to the Generating Facilities.
THE DAHLBERG FACILITY
Under the terms of the LEM PPAs, Southern Power will receive
bonus payments in the event that the Dahlberg Facility achieves contract
availabilities in excess of certain levels. Southern Power can meet this
contract availability through energy from alternate resources. Southern Power
can earn an annual availability bonus for Dahlberg 1-5 ranging from $100,000 for
a contract availability of 98.6 percent to $1,000,000 for a contract
availability of 100 percent. Southern Power can earn an annual availability
bonus for Dahlberg 6-7 of $200,000 for a contract availability of 100 percent.
No bonus is available for Dahlberg 6-7 for contract availability levels below
100 percent.
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There are no minimum availability levels in the LEM PPAs. In the event that the
Dahlberg Facility is unable to meet the requirements of the LEM PPAs, Southern
Power must provide the requested energy from other resources.
THE FRANKLIN FACILITY
Under the terms of the Franklin PPA, an availability
adjustment is made to the amount paid for Designated Capacity. The adjustment
can result in either an increase or decrease in the capacity payments. The
availability adjustment is based upon a "Capacity Adjustment Factor" adjusted by
a factor of 0.15 for the months of June through September and 0.05 for all other
months. The Capacity Adjustment Factor is based on a contract availability
factor called the "Seasonal Availability Factor", which excludes scheduled
maintenance and allows Southern Power to replace the undelivered energy from
another resource. The Capacity Adjustment Factor results in a reduction in
capacity payments in the event that the Franklin 1 and 2 contract availabilities
are less than 96.5 percent. The capacity payments can increase by 1.0 to 3.5
percent of the annual capacity payments for a contract availability ranging from
96.5 to 99.5 percent. Southern Power can meet this contract availability through
energy from alternate resources.
THE HARRIS FACILITY
Under the terms of the Harris PPAs, an availability adjustment
is made to the amount paid for Designated Capacity. The adjustment can result in
either an increase or decrease in the capacity payments. The availability
adjustment is based upon a "Capacity Adjustment Factor" adjusted by a factor of
0.15 for the months of June through September and 0.05 for all other months. The
Capacity Adjustment Factor is based on a contract availability factor, called
the "Actual Demand Availability" in the Harris 1 PPA and the "Seasonal
Availability Factor" in the Harris 2 PPA, which excludes scheduled maintenance
and allows Southern Power to replace the undelivered energy from another
resource. The Capacity Adjustment Factor results in a reduction in capacity
payments in the event that the Harris 1 and 2 contract availability factors are
less than 96 and 96.5 percent, respectively. The capacity payments can be
increased by 1.5 to 4.0 percent of the annual capacity payments for a contract
availability ranging from 97.0 to 99.0 percent for Harris 1 and by 1.0 to 3.5
percent of the annual capacity payments for a contract availability ranging from
96.5 to 99.5 percent for Harris 2. Southern Power can meet these contract
availabilities through energy from alternate resources.
THE MCINTOSH FACILITY
Under the terms of the McIntosh PPAs, an availability
adjustment is made to the amount paid for the Contract Capacity Rating. The
adjustment can result in either an increase or decrease in the capacity
payments. The adjustment is based on a contract availability factor called the
"Seasonal Availability Factor", which excludes scheduled maintenance and allows
Southern Power to replace the undelivered energy from another resource. A
reduction in capacity payments results in the event that the Seasonal
Availability Factor is less than 96.0 percent. The capacity payments can
increase by 1.5 to 4.0 percent of the annual capacity payments for a contract
availability ranging from 96.0 to 99.0 percent. Southern Power can meet this
contract availability through energy from alternate resources.
THE STANTON FACILITY
Under the terms of the Stanton PPAs, an availability
adjustment is made to the amount paid for the Demonstrated Capacity. If the
availability of the Stanton Facility is less than the guaranteed availability,
capacity payments are reduced by the "Availability Damages". Availability
Damages are calculated as the difference between the actual availability and 97
percent times the sum of the capacity payment for the appropriate period,
adjusted by one-half for the off-peak period. The Stanton Facility will also be
entitled to an availability incentive payment of 3 percent of the peak period
capacity payments for a contract availability in excess of 99 percent and 1.5
percent of the off-peak capacity payments for an off-peak contract availability
in excess of 99 percent. The Stanton Facility will also be penalized by 2
percent of the peak period capacity payments for a peak contract availability of
95 percent and an additional 1 percent for each percentage of contract
availability less than 95 percent. The off-peak contract availability penalty is
1 percent of the off-peak capacity payments for an off-peak contract
availability of 95 percent and an additional 0.5 percent for each percentage of
off-peak contract availability less than 95 percent.
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THE WANSLEY FACILITY
Under the terms of the Wansley PPAs, an availability
adjustment is made to the amount paid for the Contract Capacity Rating. The
adjustment can result in either an increase or decrease in the capacity
payments. The adjustment is based on a contract availability factor called the
"Seasonal Availability Factor", which excludes scheduled maintenance and allows
Southern Power to replace the undelivered energy from another resource. A
reduction in capacity payments results in the event that the Seasonal
Availability Factor is less than 96.5 percent. The capacity payments can
increase by 1.0 to 3.5 percent of the annual capacity payments for a contract
availability ranging from 96.6 to 99.5 percent. Southern Power can meet this
contract availability through energy from alternate resources.
SUMMARY
Based on our review, we are of the opinion that the Generating
Facilities should be capable of achieving the required average annual contract
availabilities under the PPAs ranging from 96.5 to 97 percent, which exclude
scheduled maintenance and allow Southern Power to replace the undelivered energy
from another resource, and should also be capable of achieving an average annual
availability of 92 percent, which includes provision for forced and scheduled
maintenance. The stipulated availability factors represent the projected average
availabilities [Redacted]. There may be years when the actual availability
factors are above or below the average availability factors stipulated herein.
For the purpose of the Projected Operating Results, Southern
Power has assumed that it will provide energy from alternate resources in order
to achieve the contract availabilities required to obtain the maximum amount of
capacity payments under the PPAs.
CONSTRUCTION STATUS
We were provided summary schedules comprised of engineering,
procurement, construction, and turnover activities to support the assumed
commercial operations dates of the McIntosh and Stanton Facilities. In addition,
we have been provided an estimated cost to complete these facilities. The
estimated remaining construction cost of these facilities is expected to be
funded from the Commercial Construction Revolver and Southern equity.
Commercial operation of the Stanton Facility is currently
scheduled for October 1, 2003. According to SCS, overall construction was
approximately 98 percent complete as of June 1, 2003, and start-up and testing
are underway. First fire of the both CTs and steam piping blows have been
completed. The total construction cost is estimated by Southern Power to be $262
million, of which Southern Power's share is 65 percent.
Commercial operation of the McIntosh Facility is currently
scheduled for June 1, 2005. Construction began October 1, 2002, this included
site work, grading, and the installation of a barge ramp and access road. Piling
for both units is scheduled to be accomplished between April and August 2003.
Major foundation construction for the units is scheduled to begin in July 2003
and complete in early March 2004. Erection of the HRSGs is scheduled to begin in
October 2004 and approximately ten months has been estimated for the
installation of each HRSG. Installation of the CTGs is scheduled to begin in
November 2003 and completion is scheduled for September 2003. The McIntosh 10
STG installation is scheduled to begin in December 2003 and complete December
23, 2004. The McIntosh 11 STG installation is scheduled to begin March 2, 2004
and complete January 18, 2005. The GSU transformers are to be delivered to the
site on February 25, 2004. The station service energization is scheduled for May
3, 2004. Steam blows for McIntosh 10 and 11 are scheduled for November and
December 2004, respectively. Gas performance testing for McIntosh 10 is
scheduled to begin January 12, 2003 and McIntosh 11 gas performance testing is
scheduled to begin February 11, 2005. Commercial operation is scheduled for
McIntosh 10 and 11 on May 1, 2005 and June 1, 2005, respectively. The total
construction cost is estimated by Southern Power to be approximately $591
million.
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ENVIRONMENTAL ASSESSMENTS
ENVIRONMENTAL SITE ASSESSMENTS
THE DAHLBERG FACILITY
We have reviewed the "Environmental Property Assessment"
regarding the Dahlberg Facility Site completed August 4, 1997, by Georgia Power
and the "Phase I Environmental Site Assessment, Plant Dahlberg" dated April 20,
2001, prepared for SCS by URS Corporation ("URS"). The approximately 270-acre
subject property has historically been used for agricultural and silvicultural
activities. At the time of Georgia Power's 1997 assessment, the property was
undeveloped woodlands and farm fields, with some use for silvicultural
activities with an overhead electric transmission line traversing the property.
According to information provided by Southern Power, Dames & Moore's "Phase I
Environmental Survey, Wetland Delineations, and Threatened and Endangered
Species Survey" dated January 9, 1995, prepared for Georgia Power, Dames & Moore
did not identify any environmental concerns at the Dahlberg Facility regarding
site contamination during their 1995 investigation. During their 1997 site
visit, Georgia Power did not identify any signs of spills, stained soils, waste
disposal, chemical storage, tanks, drums, or other indicators of potential
site-contamination issues. At the time of URS's April 2001 site visit,
construction of eight CT units (and associated equipment and amenities) at the
Dahlberg Facility had been completed, and additional construction of Units 9 and
10 was near completion. Neither Georgia Power's nor URS's assessments identified
any potential impacts to the property from adjoining properties. As a result of
their 1997 investigation, Georgia Power concluded, "there were no significant
environmental concerns identified which would prohibit the purchase of the
property." During their April 2001 site visit, URS examined several areas of
fuel storage and use of other hazardous substances, but reported no soil stains
or other observable concerns associated with these areas. URS reported an
accidental release of 16,900 gallons of No. 2 fuel oil within the bermed area
for the 3.5 million-gallon fuel tank (as well as three other minor historical
fuel/hydraulic oil releases associated with plant construction and operations).
URS provided documentation that all of the spill areas had been cleaned-up and
contaminated soils had been disposed of at a permitted landfill. URS concluded
that their investigation revealed no on-site recognizable environmental
concerns.
THE FRANKLIN FACILITY
We have reviewed the "Environmental Property Assessment"
regarding the Franklin Facility Site completed August 31, 1998, by Alabama Power
and the "Phase I Environmental Site Assessment (Revised)" dated May 3, 2001,
prepared for Alabama Power by TTL, Inc. ("TTL"). The approximately 709-acre
subject property has historically been used for hunting and silvicultural
activities. At the time of Alabama Power's 1998 assessment, the property was
undeveloped timberland and fields, with prior land use for hunting and
silvicultural activities. During their 1998 site visit, Alabama Power did not
identify any signs of spills, stained soils, waste disposal, chemical storage,
tanks, drums, or other indicators of potential site-contamination issues. At the
time of TTL's April 2001 site visit, the subject property was undeveloped, with
the exception of power plant construction activity on the northeast corner of
the site. TTL observed an 8,000-gallon above-ground storage tank for diesel fuel
with no evidence of fuel releases, observed minor areas of debris that they
described as benign, and encountered a small on-site cemetery. TTL reported no
issues of concern associated with the power plant construction area. Neither
Alabama Power's nor TTL's assessments identified any potential impacts to the
property from adjoining properties. As a result of their 1998 investigation,
Alabama Power concluded, "there were no significant environmental concerns
identified, which would prohibit the purchase of the property." TTL's
conclusions did not indicate any issues of significant environmental concern for
the subject property.
THE HARRIS FACILITY
We have reviewed the following: (1) the "Environmental
Property Assessment" regarding the Harris Facility Site completed February 18,
2000, by Alabama Power; (2) the "Phase I Environmental Site Assessment
(Revised), Autaugaville Site" dated May 3, 2001, prepared for Alabama Power by
TTL; and (3) the "Phase I Environmental Site Assessment, Approximate 291.37-acre
Parcel" dated May 18, 2001, prepared for Alabama Power by TTL. These reports
cover the 467.66-acre and 291.37-acre contiguous parcels for the Harris
Facility, totaling approximately 759 acres. According to TTL, the subject
properties have been historically used for agricultural
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purposes and timber production. At the time of Alabama Power's February 2000
assessment, the properties were undeveloped farmland and wooded tracts. At the
time of TTL's April/May 2001 site visits, initial construction activities for
the Harris Facility had begun on the 468-acre parcel and construction of a
substation was underway on the 291-acre parcel. TTL observed temporary trailers
at the power plant construction site and above-ground storage tanks for diesel
fuel on both construction sites. TTL reported no spills or stained soils of
regulatory consequence associated with the fuel storage. During their site
reconnaissance of the two properties, TTL observed abandoned rusting vehicles,
several debris sites, abandoned houses/barn/sheds, and several former domestic
wells. Neither Alabama Power's nor TTL's assessments identified any potential
impacts to the Harris Facility Site from adjoining properties. Alabama Power
concluded that their assessment "revealed no environmental conditions which
would preclude the purchase of this property." With the exception of solid waste
disposal on various portions of the properties, TTL reported no other conditions
of potentially significant concern during their site reconnaissance. TTL
recommended: (1) properly abandoning the domestic wells (on the 291-acre parcel)
by filling them with cement and clay; (2) that debris/trash piles on the
468-acre property be removed and disposed of off-site, followed by sampling and
analysis of soil beneath the debris piles; (3) removal and off-site disposal of
Trash Area No. 1 from the 291-acre property, followed by soils sampling if
staining was observed during the removal process; and (4) citing the presence of
potentially hazardous materials such as oil containers, oil filters, and car
batteries, TTL recommended removal and off-site disposal of Trash Area No. 2
from the 291-acre property, followed by soil sampling to evaluate baseline
environmental conditions in this area. In accordance with their normal
practices, Alabama Power has reported their intent to abandon the aforementioned
domestic wells by filling the wells with appropriate materials. Further, Alabama
Power indicates that the various debris piles and trash areas will be removed
and evaluated for proper disposal, depending on the content of the piles. After
debris removal, Alabama Power plans to assess the areas and conduct soil
sampling and additional soil removal, as necessary, if such areas have been
severely impacted.
THE MCINTOSH FACILITY
We have prepared the "Phase I Environmental Site Assessment,
Property for the Proposed Plant McIntosh Combined Cycle Units 10 and 11", dated
June 9, 2003, regarding the approximately 58-acre McIntosh Facility Site.
Previous land use of the subject property has included growing timber and
agriculture, and the property previously contained isolated residential
structures. No previous spills or other environmental concerns have been
reported at the subject property. At the time of our April 29, 2003 site visit,
the property had been cleared of all trees and vegetation in preparation for
construction of the McIntosh Facility. We observed no evidence of spills, soil
staining, tanks, solid waste disposal, hazardous waste, or storage of chemicals
or hazardous materials during our site visit. Our interviews with personnel
familiar to the property, review of materials regarding the history of the
property, and review of state and Federal environmental databases did not reveal
any recognized environmental conditions or other environmental concerns
regarding the subject property.
THE STANTON FACILITY
We have reviewed the "Phase I Environmental Site Assessment,
Stanton Energy Plant" dated April 2001, prepared for OUC by Environmental
Consulting & Technology, Inc. ("ECT") and the "Limited Phase II Environmental
Site Assessment, Stanton Energy Center" dated June 29, 2001, prepared for OUC by
ECT. The environmental site assessments were conducted on a 7-acre portion of
the 60 acres leased to Southern Power Florida, OUC, and FMPA. According to ECT,
the 7-acre property has been used historically as a construction laydown yard
during construction of the adjacent SEC power plant and as a fueling facility
for fleet vehicles. At the time of their March-May 2001 site visits, the
property contained two small structures, a concrete foundation for a former
structure, an out-of-service electrical substation, and an active fueling
facility. Areas adjacent to the property included citrus groves to the north,
the SEC to the south, and OUC's fleet vehicle maintenance facility also located
to the south. ECT observed disposed sand blasting material on the south side of
the property; a storage building with discarded industrial batteries (with
evidence of the concrete floor stained by battery acid); a storage building at
the fueling facility containing five above-ground tanks for gasoline and diesel
(with no evidence of releases) and associated above-ground piping and fuel
dispenser; and several on-site piles of solid waste/construction debris
(containing concrete, scrap wood, steel glass piping, metal grating, and
miscellaneous railroad debris). With the exception of stained gravel beneath a
transformer (labeled non-PCB) at the out-of-service substation, ECT observed no
evidence of stained soils at the
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property. ECT concluded that their assessment revealed no evidence of recognized
environmental conditions except the aforementioned issues associated with
possible releases to soil or groundwater at the out-of-service substation, the
fueling facility, and discarded sand blasting material located on the property;
and the vehicle maintenance facility located south of the property. ECT
recommended removal of the solid waste/debris areas, sand blasting materials,
and discarded batteries (at the substation); and limited soil and groundwater
testing at the site. During May 2001, ECT collected a sample of the sand
blasting materials for laboratory analysis of metals by toxicity characteristic
leaching procedure ("TCLP") and conducted limited sampling of soil and
groundwater at the property including selected analyses of VOCs, polynuclear
aromatic hydrocarbons, ("PAHs"), total petroleum hydrocarbons, metals, and pH.
Soil and groundwater samples from four temporary monitoring wells were installed
near the battery storage building, in the sand blasting materials area, at the
fueling facility, and at the south property boundary bordering the OUC vehicle
maintenance facility. Metals were not detected in the TCLP sample of sand
blasting materials. Fuel related compounds were detected in soil associated with
the fueling facility and the south boundary sampling location (north of the
off-site vehicle maintenance facility), but none of the concentrations in any of
the soil samples exceeded the applicable cleanup standards promulgated by the
Florida Department of Environmental Protection ("FDEP"). Fuel related compounds
and metals were detected in groundwater samples associated with the sand
blasting area, the fueling facility, or the boundary sampling location, but none
of the concentrations in any of the samples exceeded the applicable cleanup
standards with the exception of one groundwater sample at the fueling facility.
Benzene at 2.2 parts per billion ("ppb") and total xylenes at 50 ppb exceeded
the FDEP regulatory standard for groundwater cleanup of 1 ppb and 20 ppb,
respectively at the fueling facility. Due to the elevated levels of benzene and
xylenes at the fueling facility, ECT recommended additional investigations
consisting of installation of piezometers (to determine groundwater flow
direction) and installation of permanent groundwater monitoring wells for
analysis of fuel related organic compounds. We have not reviewed any additional
reports regarding this issue and we have not received any documentation from
Southern Power addressing disposal of potentially contaminated groundwater from
dewatering activities. However, pursuant to the Stanton Ownership Agreement, OUC
is responsible for any pre-construction environmental issues.
The environmental site assessments were conducted on a 7-acre
portion of the 60 acres leased to Southern Power Florida, OUC, and FMPA.
Although we have not reviewed any environmental site assessments for the
remaining 53 acres of the 60-acre leased area, under the Stanton Ownership
Agreement, OUC is responsible for any pre-construction environmental issues that
would need to be addressed on the entire 60-acre leased area. If groundwater
remediation is ever required at the Stanton Facility Site in the future to
address the exceedances of groundwater contaminants identified by ECT's
investigations; such remediation activities would not likely significantly
impact the ability of the Stanton Facility to conduct normal operations.
THE WANSLEY FACILITY
We have reviewed the "Phase I Environmental Site Assessment"
dated April 20, 2001, prepared for SCS by URS and the "Plant Wansley Petroleum
Release and Remediation Summary" dated May 7, 2001, prepared for SCS by Williams
Environmental Services ("Williams"). According to URS, the Wansley Facility Site
and construction laydown area were previously used by Georgia Power as a support
and maintenance facility for Georgia Power operations. Prior to 1970, the
subject property was wooded and agricultural, and was reportedly occupied by
homesteads, a church, and several cemeteries. Development at the subject
property after 1970 included a railcar maintenance shop, a concrete plant, and
two warehouses. At the time of URS's April 2001 site visit, the Wansley Facility
was under construction, with demolition of historical structures either
completed, underway, or scheduled. Structural debris was in the process of being
removed subsequent to demolition of one of the warehouses. The coal-fired Units
1 and 2 of Plant Wansley are immediately adjacent to the Wansley Facility Site.
URS did not identify the existing coal-fired Plant Wansley or any other adjacent
areas as having any potential to impact the Wansley Facility Site. URS observed
several above-ground fuel storage tanks and 55-gallon drums on the subject
property, as well as storage areas for machinery, parts, and miscellaneous
equipment and materials. URS also observed staging areas for scrap wood and
waste construction materials, but did not observe any generation of hazardous
waste. URS noted that several temporary fuel storage tanks and drums were
without secondary containment. Southern Power has provided a lined secondary
containment storage area for the temporary fuel storage tanks that are being
used during construction.
A-31
URS identified two areas on the property with soil staining,
particularly in the vicinity of fuel tank and drum storage areas. URS
recommended excavation and disposal of the stained soils, followed by
confirmatory soil sampling. URS also recommended sediment sampling in a ditch,
which had potential to receive stormwater runoff from soil stained areas. In
April/May 2001, Williams was contracted to complete the soil excavations
recommended by URS. The two areas of soil staining (including a one-foot
perimeter buffer) identified by URS were excavated and disposed of off-site.
While we note that the soil sampling recommended by URS for the ditch was not
conducted, confirmatory soil sampling from the two excavated areas by Williams
indicated that removal of the contaminated soils was completed.
SUMMARY
In February 2003, Southern Power stated that there have been
no reportable spills or site contamination issues of concern at the Dahlberg,
Franklin, Harris, Stanton and Wansley Facility Sites since issuance of the 2001
environmental site assessments. Based on our Phase I environmental site
assessment for the McIntosh Facility, we did not identify any environmental
concerns related to site contamination issues. Because no updated ESAs of
previous or recent environmental investigations regarding the potential for site
contamination issues at the sites of the other Generating Facilities have been
provided for our review, we can offer no opinion with respect to potential site
contamination issues at the sites of the Dahlberg, Franklin, Harris, Stanton,
and Wansley Facilities, if any, or the potential for future remediation.
STATUS OF PERMITS AND APPROVALS
The Generating Facilities must be operated in accordance with
applicable environmental laws, regulations, policies, codes and standards. Table
6 identifies the key permits and approvals required for the operation of the
Generating Facilities. Based on our review, we are of the opinion that Southern
Power has identified the major permits and approvals necessary for the
construction and operation of the Generating Facilities. While all of the
required permits and approvals have not yet been obtained, we did not identify
any technical or engineering circumstance that would prevent the issuance of the
remaining permits and approvals. We note that the modification of the NPDES
Permit and the Surface Water Withdrawal Permit of the adjacent steam plant to
accommodate the McIntosh Facility have not yet been issued and are under review
by the Georgia Environmental Protection Division. As such, we have not reviewed
the conditions to be set forth in the permits.
TABLE 6
STATUS OF KEY PERMITS AND APPROVALS REQUIRED FOR OPERATION
DAHLBERG FRANKLIN HARRIS MCINTOSH STANTON WANSLEY
PERMIT/APPROVAL FACILITY FACILITY FACILITY FACILITY FACILITY FACILITY
- ------------------- ------------- --------------- -------------- ---------------- ------------- --------------
Air Construction Issued 8/9/99 Issued 4/10/00 Issued 1/8/01 Covered under Issued 9/21/01 Issued 7/28/00
Permits by Georgia by Alabama by ADEM; Prevention of by FDEP. by GEPD;
Environmental Department of reissued with Significant finalized
Protection Environmental "Harris" name Deterioration 11/6/00.
Division Management 7/26/02. Permit /Title
("GEPD"). ("ADEM"), V Part 70
revised 4/6/01. Operating Permit
for existing
plant issued
4/17/03.
Title IV Acid Rain Issued Issued 5/7/01 Application Covered under Application Issued 7/28/00
Permits 8/31/99 by by ADEM. submitted Prevention of deemed by GEPD;
GEPD. 12/14/00 to Significant complete finalized
ADEM. Deterioration 4/24/02. 11/6/00.
Application Permit /Title
re-submitted V Part 70
with "Harris" Operating
name 7/19/02; Permit for
permit pending existing
plant issued
4/17/03.
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TABLE 6
STATUS OF KEY PERMITS AND APPROVALS REQUIRED FOR OPERATION
DAHLBERG FRANKLIN HARRIS MCINTOSH STANTON WANSLEY
PERMIT/APPROVAL FACILITY FACILITY FACILITY FACILITY FACILITY FACILITY
- ------------------- ------------- --------------- -------------- ---------------- ------------- --------------
Title V Operating Application Application Application Covered under Application Issued 7/28/00
Permits submitted submitted ADEM to be Prevention of must be by GEPD;
3/5/01 to 11/20/02. submitted to Significant submitted finalized
GEPD; permit ADEM within Deterioration within 12 11/6/00;
pending. 12 months of Permit /Title months of the amended 2/4/02
the start of V Part 70 start of and 6/25/02.
operations. Operating operation;
Permit for application to
existing be submitted
plant issued after third
4/17/03. quarter 2003.
National Pollutant N/A Final NPDES Issued Application Not required. Issued 7/31/00
Discharge Permit issued 12/20/01; submitted by GEPD.
Elimination System 12/27/00 by effective 5/31/02;
("NPDES") Permits ADEM. 1/1/02. permit
for Wastewater issuance
Discharges expected 7/03.
Notice of Submitted Issued Issued Notice of Submitted to Submitted
Intent/General 8/11/00 to 12/17/99 by 12/1/00 by Intent filed FDEP 6/2/02. 8/10/00 to
Permits-Construction GEPD (only ADEM. ADEM. 9/30/02. GEPD.
Stormwater covers Units
Discharges 9 and 10).
Notice of Not required Notice of Not required Notice of Notice of Discharges to
Intent/NPDES for peaking Intent to be - stormwater Intent to be Intent to be existing
General plants. filed after discharges filed after filed after Wansley site
Permits-Operational completion of covered under completion of completion of retention pond.
Activities construction. NPDES construction. construction.
Stormwater Wastewater
Discharges Discharge
Permit.
Clean Water Act Wetlands Issued 1/12/00 Issued According to Issued 11/6/01 Issued 4/21/00
Section 404 Delineation for the 11/4/00 for Southern for the for gas line
Permits- Corps of Survey construction gas pipeline; Power's construction crossing
Engineers ("COE") 2/24/99. A of natural gas issued Assessment, of the river; also, a
Project pipeline. 12/20/00 for this is not substation Stream Buffer
Completion intake and required. expansion, the Variance from
Report was discharge electric GEPD was
submitted to structures. transmission issued 10/5/00
COE on line, and the for
7/20/01. gas pipeline. construction
of gas
pipeline.
A-33
TABLE 6
STATUS OF KEY PERMITS AND APPROVALS REQUIRED FOR OPERATION
DAHLBERG FRANKLIN HARRIS MCINTOSH STANTON WANSLEY
PERMIT/APPROVAL FACILITY FACILITY FACILITY FACILITY FACILITY FACILITY
- ------------------- ------------- --------------- -------------- ---------------- ------------- --------------
Water Withdrawal N/A Issued 4/30/00 Certificate Application Water to be Issued
Permits by GEPD to of Beneficial submitted provided by 10/31/00 by
withdraw water Use from the 5/31/02; OUC pursuant GEPD; petition
from Goat Rock Alabama permit to agreement filed against
Reservoir. Department of issuance OUC has with Permit;
Also, the Economic and expected 7/03. Orange County, appeals
Federal Energy Community Florida. hearing began
Regulatory Affairs to be OUC's plan is 7/16/01;
Commission obtained currently Administrative
issued prior to the under review Law Judge
approval on start of by St. John's issued an
10/10/00 to operations. River Water amended order
withdraw Southern Management 4/24/02.
additional Power District. Permit
water through submitted reissued in
an existing Declaration accordance
penstock in of Beneficial with
Goat Rock Dam. Use on Administrative
3/29/01. Order 5/22/02.
Federal Aviation Issued Issued 4/25/00. On 5/30/01, FAA review in Not required. Issued
Administration 7/15/99; FAA issued a progress. 12/12/00.
("FAA") Notice of extended determination
Construction or 7/19/00. that the
Alteration Permits stacks are
for Stacks not a hazard
to navigation.
Order of N/A N/A N/A N/A Issued 9/11/01 N/A
Certification by the State
of Florida
Siting Board.
Spill Prevention Finalized on Construction In place for To be Existing plan Prepared
Control and 9/27/00. plan revised oil flush as prepared to be amended 1/7/03.
Countermeasure and certified of 8/26/02; prior to the to include new
("SPCC") Plan 12/6/02; operational start of unit.
operational plan is being operation. Temporary plan
plan in place prepared. in place.
10/15/01.
REGULATORY COMPLIANCE
We note the following circumstances relative to compliance
with permits and approvals and other regulatory requirements that could have an
impact on future operations:
- In 1998, the United States Environmental Protection Agency ("USEPA")
promulgated the "NOX State Implementation Plan ("SIP") Call Rule" for the
purpose of controlling NOX, a precursor to ozone, and a pollutant of concern. As
required by the USEPA rules, Alabama and Georgia are subject to the NOX SIP
Call, which will impose NOX allowance obligations on certain emission sources.
The USEPA has approved Alabama's SIP that includes the Franklin and Harris
Facilities. As such, each facility will be required to obtain allowances to
cover annual NOX emissions starting in 2004. Calculations performed by the
Alabama Department of Environmental Management ("ADEM") propose 35 tons of NOX
allocations to each Harris Facility CT train for a total of 140 tons for the
four trains and 33 tons of NOX allocations to each Franklin Facility CT train
for a total of 264 tons for the eight trains (note there are two CT trains per
unit) for 2004 through 2006, with subsequent allocations recalculated every
three years (e.g., calculated in 2004 for the years 2007-2009). Based on the
March 3, 2000, decision by the U.S. Court of Appeals for the District of
Columbia Circuit ("Court"), certain portions of the USEPA rules that affect the
entire state of Georgia were remanded.
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The Court found that USEPA's modeling demonstrated that the entire state of
Georgia should not be included in the SIP Call. In response to the Court, the
USEPA proposed revisions to their rules to include a NOx budget for Georgia for
the northern portion of the state. Based on the USEPA proposed amended rules the
state is required to submit a SIP by no later than April 1, 2003 with a May 1,
2005 compliance date. As such, the Georgia Environmental Protection Division
("GEPD") has not yet amended Georgia's SIP. GEPD is still considering options
for revising their SIP and determining future allocations. It is anticipated
that the Dahlberg, McIntosh, and Wansley Facilities will be included within the
area that will be subject to the NOX SIP Call Rule. Since the manner in which
the NOX allocations will be structured has not been determined by GEPD, we are
unable to accurately estimate the likely number of allowances that may be
allocated to the Dahlberg and Wansley Facilities. The exact number of allowances
to be required in the future will depend on the utilization of the units in the
future and the finalization of the SIP. For the purposes of the Projected
Operating Results, we have assumed that the Generating Facilities would be
allocated allowances based on the Alabama SIP and no allowances were assumed for
the Dahlberg, McIntosh, and Wansley Facilities, all located in Georgia. The
future cost of NOX allowances will be market dependent and could be lower or
higher than the current values for such allowances. The allowance costs assumed
in the Projected Operating Results are presented later in this Report.
- The Generating Facilities are subject to Title IV of the Clean Air
Act (Acid Rain Provisions) whereby each unit must possess sulfur dioxide ("SO2")
allowances to cover its emissions beginning in 2000. The future cost of SO2
allowances will be market dependent and could be lower or higher than the
current values for such allowances. The exact number of allowances to be
required in the future will depend on the utilization of the units. The
allowance costs assumed in the Projected Operating Results are presented later
in this Report. Since the facilities will operate primarily on natural gas, the
actual cost for purchasing allowances should be relatively small. In addition,
since the facilities are operated on natural gas, they are not subject to the
NOX requirements under the Acid Rain Program.
- For the purpose of estimating NOX and SO2 allowance costs in the
Projected Operating Results, actual emissions testing results have been assumed
for the Dahlberg Facility, and air permit limits have been assumed for the other
Generating Facilities with no significant operating history. Based on firing
natural gas, a NOX emission level of 0.24 lb/MMBtu was used for the Dahlberg
Facility and 0.013 lb/MMBtu was assumed for the other Generating Facilities. An
SO2 emission level of 0.001 lb/MMBtu was assumed for all of the Generating
Facilities while firing natural gas.
- Southern Power has reported that there have been no Notices of
Violation issued by regulatory agencies against any of the Facilities.
- The modification of the NPDES Permit and the Surface Water Withdrawal
Permit of the adjacent steam plant to accommodate the McIntosh Project have not
yet been issued and are under review by the Georgia Environmental Protection
Division. As such, we have not reviewed the conditions to be set forth in the
permits.
- There are a number of potential future regulations that, if
promulgated, could increase capital expenditures and O&M costs at the Generating
Facilities. Such potential regulations include mercury control, particulate
matter of 2.5 microns or less ("PM2.5"), regional haze, regional visibility,
water intake structure regulations, and potential ratcheting of SO2 and NOX
allowances beyond 2009. The schedule and specific regulations to be promulgated
are not presently known; therefore, the impact of such potential regulations has
not been incorporated into the Projected Operating Results. Since the Generating
Facilities are primarily fired on natural gas, the impact of these potential
future regulations is not expected to be significant.
PROJECTED OPERATING RESULTS
We have reviewed the historical operating information,
estimates and projections of electrical generating capacity, fuel consumption,
and capital and operating costs of the Generating Facilities made available to
us by Southern Power. On the basis of such data, we have prepared the Projected
Operating Results. Southern Power will sell electricity generated from the
Generating Facilities to various entities primarily under the terms of the PPAs,
which vary in term. For the purposes of the Projected Operating Results, we have
assumed that all of the PPAs will
A-35
expire at the end of their respective initial terms and will not be renewed.
After expiration of the PPAs, Southern Power intends on entering into long-term
power purchase agreements at prices reflective of then-current market rates in
the Southeastern Electric Reliability Council ("SERC") and Florida Reliability
Coordinating Council ("FRCC") markets. For the purpose of the Projected
Operating Results, we have assumed that the prices under these long-term
contracts will be equivalent to the projected market prices for those markets as
projected by PA Consulting. PA Consulting was also responsible for providing
monthly dispatch hours, starts per month for each unit, monthly heat rates per
unit and projected natural gas prices. Expenses for the plants consist primarily
of the delivered costs of fuel, including transportation, as estimated by PA
Consulting, and operations and maintenance expenses, as estimated by Southern
Power. During the terms of the respective PPAs, the cost of fuel is reimbursed
by, or purchased directly by, the power purchasers. Emissions allowances are
also the responsibility of the power purchasers. [Redacted] Southern Power has
assumed that the Debt will be refinanced upon maturity. The Projected Operating
Results are presented for each calendar year beginning July 1, 2003 through
December 31, 2023 [Redacted]. Projected revenues and expenses have been set
forth in the Projected Operating Results presented in Exhibit A-1. The "Base
Case" Projected Operating Results have been prepared using assumptions and
considerations set forth in this Report and the footnotes to Exhibit A-1.
ANNUAL OPERATING REVENUES
REVENUE FROM PPAS
All of the Generating Facilities have PPAs that have various
terms and conditions. Several facilities have more than one PPA, as they apply
to specific units. Most of the PPAs provide payment for capacity, start-up
charges and variable O&M charges. The power purchasers and terms for each
individual PPA are presented in Table 7.
TABLE 7
POWER PURCHASE AGREEMENTS
TOTAL CONTRACT
POWER CAPACITY CAPACITY POTENTIAL
UNIT(S) PURCHASER(S) (MW)(1) (MW)(2) START DATE END DATE EXTENSION
- ---------- ---------------- -------- -------- --------------- ----------------- -----------------
Dahlberg LEM 797(3) 578(3) June 1, 2000 December 31, 2004 December 31, 2009
Franklin 1 Georgia Power 542 542(4) June 1, 2002 May 31, 2010 N/A
Franklin 2 Georgia Power 598 598(4) June 1, 2003 May 31, 2011 N/A
Harris 1 Alabama Power 602 602 June 1, 2003 May 31, 2010 N/A
Harris 2 Georgia Power 590 590 June 1, 2004 May 31, 2019 N/A
McIntosh Georgia Power 998 998 June 1, 2005 May 31, 2020(5) N/A
McIntosh Savannah Electric 192 192 June 1, 2005 May 31, 2020(5) N/A
Stanton OUC, KUA, FMPA 394(6) 404 October 1, 2003 October 31, 2013 October 31, 2033
Wansley Georgia Power 897 897 June 1, 2002 December 31, 2009 N/A
Wansley Savannah Electric 192 192 June 1, 2002 December 31, 2009 N/A
- ---------------
(1) Represents annual average output with duct firing and steam injection
with an allowance for long-term degradation.
(2) Represent annual capacity nomination assumed to be set at annual
average output including long-term degradation, except for the Stanton
Facility for which the contract capacity is based on an average ambient
temperature of 70(Degree)F.
(3) The contract capacity for the Dahlberg Facility can be met by any of
the units.
(4) Represents maximum contract output. Initial years of contract include
lower contract output.
(5) Assumes the extension of the fuel transportation agreement, as expected
by Southern Power.
(6) Represents Southern Power's 65 percent ownership interest. Lower than
contract capacity since the contract capacity is based on an average
ambient temperature of 70(Degree)F.
THE DAHLBERG FACILITY
Dahlberg 1 through 5 are currently in operation and are
realizing revenue under the terms of the 1998 LEM PPA. LEM has the right to
extend the term of this 1998 LEM PPA to December 31, 2009; however, we
A-36
have assumed for the purposes of the Projected Operating Results that this 1998
LEM PPA will expire December 31, 2004. Southern Power will receive revenues from
Dahlberg 1 through 5 for capacity, start-up and variable operations from LEM.
Start-up charges are paid under the 1998 LEM PPA for starts in excess of 750
over the initial term of the 1998 LEM PPA. Based on our discussion with Southern
Power and the review of the plant design and technology, we have assumed that
Southern Power will achieve its contract capacity of 412.5 MW by utilizing peak
firing and power from the other Dahlberg Facility units. Additional capacity
payments are available for contract availability above 98.6 percent. Southern
Power has indicated that it would provide energy from alternate resources in
order to receive the maximum capacity payment under the 1998 LEM PPA. We have
assumed the contract availability is equal to 100 percent based upon the
purchase of replacement energy from the market, resulting in additional capacity
payments of $1,000,000 per year.
Dahlberg 6 and 7 are currently in operation and are realizing
revenue under the terms of the 1999 LEM PPA. As with the 1998 LEM PPA, LEM has
the right to extend this contract; however, we have assumed for the purposes of
the Projected Operating Results that the 1999 LEM PPA will expire on December
31, 2004. Revenues from operations of these units include capacity payments,
start-up charges and variable operations payments. Based on our discussion with
Southern Power and the review of the plant design and technology, we have
assumed that Southern Power will achieve its contract capacity of 165 MW by
utilizing peak firing and power from the other Dahlberg Facility units.
Additional capacity payments are available for contract availability of 100
percent. Southern Power has indicated that it would provide energy from
alternate resources in order to receive the maximum capacity payment under the
1999 LEM PPA. We have assumed the contract availability is equal to 100 percent
based upon the purchase of replacement energy from the market, resulting in
additional capacity payments of $200,000 per year.
THE FRANKLIN FACILITY
The Franklin PPA includes provisions for selling capacity and
associated energy from Franklin 1 and Franklin 2 to Georgia Power. The agreement
expires May 31, 2010 for Franklin 1 and May 31, 2011 for Franklin 2. For
Franklin 1 and Franklin 2, the annual average projected capacities are 542 MW
and 598 MW, respectively. Average contract capacity values are 542 MW for
Franklin 1 and 400 MW through June 1, 2004 and 598 MW thereafter for Franklin 2.
The excess energy generation has been assumed to be sold to the market as
forward contracts and spot market sales, as discussed later herein. The annual
contract capacity price is fixed for the term of the Franklin PPA. These
capacity prices are weighted such that 60 percent of the payments occur in the
summer months. Additional capacity payments are available for contract
availability above 96.5 percent. Southern Power has indicated that it would
provide energy from alternate resources in order to receive the maximum capacity
payment under the Franklin PPA. We have assumed the contract availability is
equal to 99.5 percent based upon the purchase of replacement energy from the
market, resulting in an increase in capacity payments of 3.5 percent. Variable
O&M charges are indexed to the 1999 Gross Domestic Product - Implicit Price
Deflator ("GDP-IPD"). We have assumed the GDP-IPD will increase at 2.6 percent
from 2003. Start-up charges are per unit per start and are based upon the total
number of starts. Under the terms of the Franklin PPA, the start-up charges are
indexed to both the January 1, 1999 U.S. City Average Consumer Price Index for
All Urban Consumers ("CPI") and $2.25 per MMBtu as a base to the "Daily Price
Survey" midpoint as published in Gas Daily. For the purposes of the Projected
Operating Results, we have assumed that the CPI will escalate at 2.6 percent
after January 1, 2003 and the midpoint in the "Daily Price Survey" will be as
projected by PA Consulting in their delivered fuel forecast.
In addition, before initiation of the Franklin PPA as it
relates to Franklin 2, a portion of the output from Franklin 2 is to be sold to
third parties pursuant to contracts entered into by Southern Power. During the
remainder of 2003, net revenues associated with these third-party contract sales
will be approximately $1,823,000 based on the executed contracts as reported by
Southern Power.
THE HARRIS FACILITY
Harris 1 and 2 are to sell power under separate PPAs to
Alabama Power and Georgia Power with terms beginning on June 1, 2003 and June 1,
2004 and ending on May 31, 2010 and May 31, 2019, respectively. Prior to
commencement of the Harris 2 PPA, Southern Power has assumed that electricity
from Harris 2 will be sold on a
A-37
merchant basis at quantities and prices estimated by PA Consulting. Annual
average contract capacity is equal to 595 MW per unit. Monthly revenues are
generated from a capacity payment, which is adjusted by a monthly capacity
payment factor that is weighted such that 60 percent of the payment occurs
during the summer months. Additional capacity payments are available for
contract availability above 97.0 percent for Harris 1 and 96.5 percent for
Harris 2. Southern Power has indicated that it would provide energy from
alternate resources in order to receive the maximum capacity payment under the
Harris PPAs. We have assumed the contract availability is equal to 99.0 percent
for Harris 1 and 99.5 percent for Harris 2 based upon the purchase of
replacement energy from the market, resulting in additional capacity payments of
4.0 and 3.5 percent, respectively. Revenues are also generated from a variable
O&M charge indexed to the 1999 GDP-IPD. We have assumed that the GDP-IPD and all
inflation-related indices will increase at 2.6 percent from 2003. Start-up
charges are per unit per start and are based upon the total number of starts.
Under the terms of the Harris 1 and 2 PPAs, the start-up charges are indexed to
both the January 1, 1999 CPI and $2.25 per MMBtu as a base to the "Daily Price
Survey" midpoint as published in Gas Daily. For the purposes of the Projected
Operating Results, we have assumed that the CPI will escalate at 2.6 percent
after January 1, 2003 and the midpoint in the "Daily Price Survey" will be as
projected by PA Consulting in their delivered fuel forecast.
THE MCINTOSH FACILITY
The McIntosh PPAs include provisions for selling capacity and
associated energy generated by the McIntosh Facility to Georgia Power and
Savannah Electric. Under the terms of the McIntosh PPAs, energy sales start on
June 1, 2005 and expire May 31, 2020. If certain fuel agreements are not in
place for the final year of each of the McIntosh PPAs, that agreement may be
terminated in 2019. Southern Power anticipates an extension of the fuel
transportation agreement at the appropriate time and expects the term of each
McIntosh PPAs to be effective through May 31, 2020. Contract capacity and
associated energy from McIntosh are sold as blocks, each rated at from 550 to
685 MW. The contract capacity equals the projected annual average capacity.
Capacity pricing varies by month with 70 percent of the annual capacity payment
occurring during June-September and 30 percent occurring in the months
remaining. Additional capacity payments are available for contract availability
above 96.0 percent. Southern Power has indicated that it would provide energy
from alternate resources in order to receive the maximum capacity payment under
the McIntosh PPAs. We have assumed the contract availability is equal to 99.0
percent based upon the purchase of replacement energy from the market, resulting
in an increase in capacity payments of 4.0 percent. Start-up charges are paid
for starts in excess of 150 starts per year and are indexed to the 2001 CPI. We
have assumed that the CPI will increase at 2.6 percent from January 1, 2003.
Variable O&M payments are also indexed to the 2001 CPI.
THE STANTON FACILITY
Under the terms of the Stanton PPAs, 52 percent of the Stanton
Facility's generation is allocated to OUC, 6.5 percent of the generation is
allocated to KUA, and the remaining 6.5 percent is allocated to FMPA. Sale of
power under the Stanton PPAs commences upon commercial operation of the Stanton
Facility. For the purposes of the Projected Operating Results, we have assumed
that the Stanton PPAs will have an effective date of October 1, 2003 and will
expire on October 31, 2013. Each of the agreements has similar terms and
conditions. Southern Company Florida will receive capacity, energy and start
payments. OUC is the fuel agent and is responsible for the delivery of fuel. The
power purchasers will be obligated for the payment of fuel used to produce
energy.
OUC, KUA, and FMPA shall have the irrevocable right to jointly
reduce the total of their combined capacity nominations beginning with the sixth
contract year and ending with the tenth contract year. OUC, KUA, and FMPA can
reduce their nominations in 25 MW blocks; however, no reduction can total more
than 50 MW in any given year and 200 MW in the aggregate. The decrease in
capacity nominations will be effective through the initial term and any
subsequent extensions. For the purposes of the Projected Operating Results, we
have assumed that OUC, KUA, and FMPA will not elect to reduce their capacity
nominations.
The capacity payment during each month of the operating period
shall be an amount equal to the product of the purchasers' annual capacity
nomination multiplied by the annual capacity charge. The Stanton Facility will
also be entitled to an availability incentive payment of 3 percent of the peak
period capacity payments for a contract availability in excess of 99 percent and
1.5 percent of the off-peak capacity payments for an off-peak contract
A-38
availability in excess of 99 percent. The Stanton Facility will also be
penalized by 2 percent of the peak period capacity payments for a peak contract
availability of 95 percent and an additional 1 percent for each percentage of
contract availability less than 95 percent. The off-peak contract availability
penalty is 1 percent of the off-peak capacity payments for an off-peak contract
availability of 95 percent and an additional 0.5 percent for each percentage of
off-peak contract availability less than 95 percent. For the purpose of the
Projected Operating Results, we assumed an annual, peak, and off-peak contract
availability of 99.01 percent, based upon the purchase of replacement energy
from the market, resulting in additional capacity payments of 2.375 percent. The
capacity payment will increase or decrease by $0.42 per kW-year for every
$350,000 increase or decrease in "BOP Capital Cost Range" or "Fixed Amount" as
referenced in the Stanton Ownership Agreement. For the purposes of the Projected
Operating Results, we have assumed that there will be no increase or decrease in
the BOP Capital Cost Range and Fixed Amount.
The variable energy charge will consist of three components:
(1) a variable O&M charge; (2) an hourly variable O&M charge while firing
natural gas based on the annual capacity factor; and (3) an hourly variable O&M
charge while firing No. 2 oil of three times the corresponding rate while firing
natural gas. The annual capacity factor is defined as the annual scheduled hours
divided by the period hours minus the outage hours. Outage hours include both
the 58 hours of allowable scheduled maintenance and the total hours of forced
outages. Each component is indexed to the CPI for January 1, 2003, and
contractually escalated each January 1 at the rate of change in the CPI. For the
purposes of the Projected Operating Results, we have assumed that the rate of
change in the CPI will be 2.6 percent per year. The Stanton Facility will
receive the applicable variable O&M components and cost of fuel for any energy
delivered from an alternate resource.
The Stanton Facility will also receive a start charge for each
unit start over 65 starts. The start charges are indexed to the CPI for January
1, 2003 and contractually escalated each January 1 at the rate of change in the
CPI. For the purposes of the Projected Operating Results, we have assumed that
the rate of change in the CPI will be 2.6 percent per year.
THE WANSLEY FACILITY
The Wansley PPAs include provisions for selling capacity and
associated energy generated by the Wansley Facility to Georgia Power and
Savannah Electric. Under the terms of the Wansley PPAs, energy sales terminate
December 31, 2009. Contract capacity and associated energy from Wansley are sold
as blocks, each rated at 561.5 MW. The contract capacity equals the projected
annual average capacity. Capacity pricing varies by month with 60 percent of the
annual capacity payment occurring during June through September and 40 percent
occurring in the months remaining. Capacity pricing includes a capacity charge,
a fixed O&M charge and a transmission interconnection charge. Additional
capacity payments are available for contract availability above 96.6 percent.
Southern Power has indicated that it would provide energy from alternate
resources in order to receive the maximum capacity payment under the Wansley
PPAs. We have assumed the contract availability is equal to 99.5 percent based
upon the purchase of replacement energy from the market, resulting in an
increase in capacity payments of 3.5 percent. Start-up charges are paid for
starts in excess of 50 starts per year indexed to the 1999 GDP-IPD. We have
assumed that the GDP-IPD will increase at 2.6 percent from 2003. Variable O&M
payments are also indexed to the 1999 GDP-IPD.
OTHER REVENUES FROM ELECTRICITY SALES
Southern Power has assumed that a portion of the capacity and
associated energy from Franklin 1, Franklin 2, and Harris 2 will be sold into
the market before initiation of their respective PPAs. In addition, capacity of
the Dahlberg Facility above the requirements of the LEM PPAs is assumed to be
sold into the market. Market prices have been estimated by PA Consulting in 2001
dollars and have been adjusted for inflation. For the purposes of the Projected
Operating Results, the general inflation rate has been assumed to be 2.6 percent
per year. PA Consulting also provided monthly dispatch hours for each of these
facilities during this period.
After the expiration of the PPAs, Southern Power intends on
entering into long-term power purchase agreements representing at least 80
percent of its cash flow at prices reflective of then-current market rates. For
the purposes of the Projected Operating Results, we have utilized a projection
of market prices prepared by PA Consulting
A-39
as an estimate of those contract rates. Market prices include separate charges
for capacity and electricity sold into the SERC and FRCC markets, as estimated
by PA Consulting. PA Consulting also provided monthly dispatch hours for each of
the Generating Facilities.
ANNUAL OPERATING EXPENSES
FUEL COSTS
Substantially all of the commodity component of the fuel costs
associated with the terms of the respective PPAs are the obligation of the buyer
of the energy and have not been included in the Projected Operating Results as
expenses to Southern Power. Commodity fuel costs are incurred during periods of
market sales, either before the PPAs begin, after they expire, or at times when
annual average capacity is greater or less than contract capacity. Commodity
fuel cost projections have been estimated by PA Consulting based upon the
appropriate annual average heat rate for each unit, or group of units, for the
respective Generating Facility. For the purposes of the Projected Operating
Results, we have assumed fuel prices equal to the projections prepared by PA
Consulting in 2001 dollars and adjusted for inflation at the assumed rate of 2.6
percent per year.
Non-commodity fuel charges, related to transportation and
storage, are the obligation of the buyer of the energy during the term of the
PPAs. These costs are incurred by Southern Power after the expiration of the
PPAs. These charges have been estimated by Southern Power, as derived from their
fuel plans for the Franklin, Harris, McIntosh, and Wansley Facilities.
OPERATING AND MAINTENANCE COSTS
For the purposes of developing the Projected Operating
Results, operating and maintenance expenses for the Generating Facilities have
been estimated by Southern Power. These estimates include annual costs for
payroll, materials and supplies, outside services, including contractors, and
variable operating and maintenance expenses. All operation and maintenance
expenses have been provided in 2003 dollars and have been assumed to escalate at
the general rate of inflation. PA Consulting has projected that the Generating
Facilities will operate in the full-pressure mode with power augmentation over
the course of the year, resulting in additional water costs.
Major maintenance expenses were estimated by Southern Power
and include major maintenance, "recurring" capital expenditures, and LTSA
charges. These expenses vary annually and have been assumed to escalate with the
rate of inflation. Under the terms of the LTSAs, the cost of maintenance of the
Generating Facilities increases if the Generating Facilities are operated in
certain types of steam injection modes. The full-pressure mode with power
augmentation assumed by Southern Power is not classified by GEI as a type of
steam injection that would result in increased maintenance compared to base-load
operation. As such, we have assumed no impact on the LTSA charges due the
assumed mode of operation projected by PA Consulting.
We have reviewed the combined projection of operating and
maintenance expenses and major maintenance costs in comparison to the costs of
similar plants with which we are familiar. Based on our review, we are of the
opinion that Southern Power's estimates of the costs of operating and
maintaining the Generating Facilities, including provision for major
maintenance, are within the range of the costs of similar plants with which we
are familiar.
PURCHASED POWER
In order to maximize the capacity payments under the PPAs,
Southern Power has indicated that it will provide replacement energy from
alternate resources. We have assumed the replacement energy will be purchased
from the market. Purchased power has been assumed to be available at market
prices estimated by PA Consulting.
EMISSIONS ALLOWANCES
Southern Power has acquired or has been allocated the SO2 and
NOX allowances associated with the Generating Facilities. We have included the
cost of allowances as an additional operating expense for the Generating
A-40
Facilities. In the event that excess allowances are available for sale, we have
assumed that Southern Power will sell the allowances at market prices. The
deficit or excess of allowances has been estimated based on the assumed emission
rates as estimated by Southern Power, the capacity factors projected by PA
Consulting, and the allocated SO2 and NOX allowances. In the event of a
shortfall during the term of any of the various PPAs, the emissions allowance
expense would be the contractual obligation of the buyer of the electricity, but
excess allowances could be sold by Southern Power. For the purpose of the
Projected Operating Results, we have assumed market NOX emissions allowance
prices of $2,000 per ton in 2004, $1,700 per ton in 2005, and escalating
thereafter at the assumed rate of inflation. We have assumed market SO2
emissions allowance prices of $150 per ton in 2003, escalating thereafter at the
assumed rate of inflation.
GENERAL AND ADMINISTRATIVE AND OTHER EXPENSES
Southern Power has estimated certain general and
administrative costs which have been included in the Projected Operating
Results. These costs include, among other things, support services such as power
marketing, computer systems and services, human resources, and accounting. These
expenses have been assumed to increase at the general rate of inflation. In
addition, Southern Power has estimated other expenses, which have also been
included in the Projected Operating Results. Property taxes and insurance costs
have been estimated by Southern Power for 2003 and have been assumed to escalate
at the rate of inflation.
ANNUAL INTEREST
[Redacted]
INTEREST COVERAGE
Interest coverage has been calculated as the cash available
for debt service during the calendar year divided by interest on the Debt due on
July 15 of that calendar year and January 15 of the next calendar year. On the
basis of our studies and analyses of the Generating Facilities and the
assumptions set forth in this Report, we are of the opinion that, for the Base
Case Projected Operating Results, the projected revenues from the sale of
electricity are adequate to pay annual operating and maintenance expenses
(including major maintenance), fuel expense, and other operating expenses.
[Redacted] There is insufficient cash available after the payment of interest to
repay the entire principal due on the Debt upon maturity. Southern Power has
assumed that the Debt will be refinanced upon maturity. [Redacted]
SENSITIVITY ANALYSES
Due to the uncertainties necessarily inherent in relying on
assumptions and projections, it should be anticipated that certain circumstances
and events may differ from those assumed and described herein and that such will
affect the results of our Base Case Projected Operating Results for the
Generating Facilities. In order to demonstrate the impact of certain
circumstances on the Base Case Projected Operating Results, certain sensitivity
analyses have been developed. It should be noted that other examples could have
been considered and those presented are not intended to reflect the full extent
of possible impacts on the Generating Facilities. The sensitivities are not
presented in any particular order with regard to the likelihood of any case
actually occurring. In addition, no assurance can be given that all relevant
sensitivities have been presented, that the level of each sensitivity is the
appropriate level for testing purposes, or that only one (rather than a
combination of more than one) of such variations or sensitivities could impact
the Generating Facilities in the future.
These sensitivity analyses present the Projected Operating
Results assuming, respectively, that: (a) the market prices, energy sales, and
fuel prices are reduced according to the "Low Gas Price" scenario prepared by PA
Consulting; (b) the market prices, energy sales, and fuel prices are increased
according to the "High Gas Price" scenario prepared by PA Consulting; (c) the
market prices, energy sales, and fuel prices are reduced according to the
"Capacity Overbuild" case prepared by PA Consulting; (d) the output of the
Generating Facilities is reduced by 5 percent; (e) the availability of the
Generating Facilities is reduced by 5 percentage points; (f) the heat rates of
the Generating Facilities are 5 percent higher than that assumed in the Base
Case; and (g) the non-fuel related operating
A-41
expenses of the Generating Facilities are 10 percent higher than that assumed in
the Base Case. The sensitivity analyses are presented as Exhibits A-2 through
A-8 to this Report. For the purposes of sensitivity cases (a), (b) and (c), PA
Consulting has prepared additional projections of dispatch and market prices.
Based on discussions with PA Consulting, market sales and market prices have
been assumed to be the same as the Base Case for the purposes of sensitivity
cases (d), (e), (f) and (g).
SUMMARY COMPARISON OF PROJECTED OPERATING RESULTS
A summary of the interest coverages for the Base Case
Projected Operating Results and each sensitivity case is presented in Table 8.
TABLE 8
PROJECTED INTEREST COVERAGE (1)
BASE CASE SENSITIVITY CASES
A B C D E F G
------------ ------------ ------------ ------- ------------ --------- ---------
CAPACITY
YEAR LOW GAS HIGH GAS OVERBUILD INCREASED
ENDING MARKET PRICE MARKET PRICE MARKET PRICE REDUCED REDUCED INCREASED OPERATING
DEC 31, SCENARIO SCENARIO SCENARIO OUTPUT AVAILABILITY HEAT RATE EXPENSES
--------- ------------ ------------ ------------ ------- ------------ --------- ---------
2003(2) 3.76 3.74 3.76 3.76 3.55 3.63 3.46 3.63
2004 4.29 4.21 4.32 4.29 4.07 4.18 4.02 4.17
2005 4.25 4.13 4.34 4.30 4.02 4.12 3.96 4.13
2006 4.00 3.76 4.14 4.02 3.79 3.86 3.71 3.88
2007 3.81 3.46 3.98 3.82 3.59 3.64 3.51 3.68
2013 4.70 4.60 4.63 4.59 4.40 4.57 4.39 4.55
2018 4.65 4.79 4.47 4.71 4.36 4.56 4.40 4.52
2023 4.65 4.95 4.78 4.69 4.31 4.57 4.43 4.50
Minimum(3) 3.76 3.46 3.76 3.76 3.55 3.63 3.46 3.63
Average(4) 4.22 4.05 4.28 4.18 3.97 4.08 3.92 4.09
- ---------------
(1) Interest coverages assume the refinancing of the Debt upon maturity at
the same principal amounts and respective interest rates, as estimated
by the Representatives of the Initial Purchasers.
(2) Represents partial year beginning July 1.
(3) [Redacted]
(4) [Redacted]
PRINCIPAL CONSIDERATIONS AND ASSUMPTIONS
USED IN THE PROJECTION OF OPERATING RESULTS
In the preparation of this Report and the opinions that
follow, we have made certain assumptions with respect to conditions which may
exist or events which may occur in the future. While we believe these
assumptions to be reasonable for the purpose of this Report, they are dependent
upon future events, and actual conditions may differ from those assumed. In
addition, we have used and relied upon certain information provided to us by
sources which we believe to be reliable. While we believe the use of such
information and assumptions to be reasonable for the purposes of our Report, we
offer no other assurances thereto and some assumptions may vary significantly
due to unanticipated events and circumstances. To the extent that actual future
conditions differ from those assumed herein or provided to us by others, the
actual results will vary from those projected herein. This Report summarizes our
work up to the date of the Report. Thus, changed conditions occurring or
becoming known after such date could affect the material presented to the extent
of such changes.
The principal considerations and assumptions made by us in
developing the Base Case Projected Operating Results and the principal
information provided to us by others include the following:
1. As Independent Engineer, we have made no determination as
to the validity and enforceability of any contract, agreement, rule, or
regulation applicable to the Generating Facilities and their
operations. However, for purposes of this Report, we have assumed that
all such contracts, agreements, rules,
A-42
and regulations will be fully enforceable in accordance with their
terms and that all parties will comply with the provisions of their
respective agreements.
2. Our review of the design of the Generating Facilities
was based on information developed by SCS and Southern Power and
provided by Southern Power.
3. Southern Power, SCS, Georgia Power, Alabama Power, and
Savannah Electric and the operators will maintain the Generating
Facilities in accordance with good engineering practice, will perform
all required major maintenance in a timely manner, and will not operate
the equipment to cause it to exceed the equipment manufacturers'
recommended maximum ratings.
4. Southern Power, SCS, Georgia Power, Alabama Power, and
Savannah Electric will employ qualified and competent personnel and
will generally operate the Generating Facilities in a sound and
businesslike manner.
5. Inspections, overhauls, repairs and modifications are
planned for and conducted in accordance with manufacturers'
recommendations, and with special regard for the need to monitor
certain operating parameters to identify early signs of potential
problems.
6. All licenses, permits and approvals, and permit
modifications necessary to operate the Generating Facilities have been,
or will be, obtained on a timely basis and any changes in required
licenses, or permits and approvals will not require reduced operation
of, or increased costs to, the Generating Facilities.
7. The McIntosh PPAs will be approved by the FERC in a
timely manner.
8. The CPI, GDP-IPD, general inflation and all
inflation-related indices will increase at a rate of 2.6 percent per
year based on a March 10, 2003 projection prepared by Blue Chip
Economic Indicators.
9. The actual performance of the Generating Facilities in each
year will be equal to the long-term average estimates included in the
Projected Operating Results.
10. The Generating Facilities will sell the quantities of
electricity pursuant to the PPAs as projected by PA Consulting, at
prices determined in accordance with the relevant PPAs. After the term
of the PPAs, Southern Power will enter into long-term power purchase
agreements at prices equivalent to the market electricity prices
projected by PA Consulting in 2001 dollars and adjusted for assumed
inflation and will sell the quantities of electricity as projected by
PA Consulting.
11. The Franklin Facility will earn the revenue from
contract sales to third parties in 2003 as reported by Southern Power.
12. Certain of the Generating Facilities will achieve contract
availabilities under their respective PPAs sufficient to receive the
maximum capacity payments by purchasing additional energy from the
market at prices estimated by PA Consulting.
13. Except for during the term of the PPAs when the energy
purchaser is responsible for the cost of fuel, the cost of fuel will be
as projected by PA Consulting.
14. Southern Power will operate the Generating Facilities at
the load levels projected by PA Consulting, resulting in the annual
average heat rates assumed in the Projected Operating Results,
resulting in no additional fuel cost under the PPAs.
15. The non-fuel operating and maintenance expenses, including
the cost of major maintenance, will be consistent with the projection
provided by Southern Power in 2003 dollars, and will increase at the
assumed change in the general inflation rate, except for a portion of
the administrative and general expenses.
A-43
16. The assumed quantity of emissions allowances will be
allocated to Southern Power through the term of the Debt. The price of
NOX emissions allowances will be $2,000 per ton in 2004, $1,700 per ton
in 2005, and will escalate thereafter at the assumed rate of inflation.
The price of SO2 emissions allowances will be $150 per ton in 2003 and
will escalate thereafter at the assumed rate of inflation.
17. There will be no additional capital improvements to
the Generating Facilities other than those assumed in the Projected
Operating Results.
18. [Redacted]
CONCLUSIONS
Set forth below are the principal opinions we have reached
after our review of the Generating Facilities. For a complete understanding of
the estimates, assumptions, and calculations upon which these opinions are
based, the Report should be read in its entirety. On the basis of our review and
analyses of the Generating Facilities and the assumptions set forth in this
Report, we are of the opinion that:
1. Provided Southern Power takes into account the
recommendations in the geotechnical reports by Southern Geotech, the
sites for the Generating Facilities are suitable for the construction
and operation of the Generating Facilities.
2. Based on GE's previously demonstrated capability to address
issues similar to those related to the Frame 7FA described herein, the
power generation technologies proposed for the Generating Facilities
are sound, proven methods of energy recovery. If constructed, operated
and maintained as proposed by Southern Power, the Generating Facilities
should be capable of meeting the requirements of the PPAs and the
currently applicable environmental permit requirements. Furthermore,
all off-site requirements of the Generating Facilities have been
adequately provided for, including fuel supply, water supply,
wastewater disposal, and electrical interconnection.
3. The proposed method of design, construction, operation, and
maintenance of the Generating Facilities has been developed in
accordance with generally accepted industry practice and has taken into
consideration the current environmental, license and permit
requirements that the Generating Facilities must meet.
4. Based on our review and provided that: (a) the units are
operated and maintained by the operators in accordance with the
policies and procedures as presented by Southern Power, (b) all
required renewals and replacements are made on a timely basis as the
units age, and (c) gas and oil burned by the units are within the
expected range with respect to quantity and quality, the Generating
Facilities should have useful lives of at least 20 years.
5. The performance guarantees proposed for the Generating
Facilities under construction, if all the equipment contract guarantees
are considered in their entirety, are similar to the performance tests
of turnkey projects with which we are familiar.
6. Through the experience of Southern Power, Alabama Power,
Georgia Power, Savannah Electric or other Southern Company
subsidiaries, SCS has demonstrated the capability to operate the
Generating Facilities. The operating programs and procedures which are
proposed or currently in place for the Generating Facilities are
consistent with generally accepted practices in the industry, and SCS
has incorporated organizational structures that are comparable to other
facilities using similar technologies for a similar service.
7. The Generating Facilities should be capable of achieving
the annual average output in full-pressure mode with power augmentation
and the average annual net plant heat rates assumed in the Projected
Operating Results.
A-44
8. The Generating Facilities should be capable of achieving
the required average annual contract availabilities under the PPAs
ranging from 96.5 to 97 percent, which exclude scheduled maintenance
and allow Southern Power to replace the undelivered energy from another
resource, and should also be capable of achieving an average annual
availability of 92 percent, which includes provision for forced and
scheduled maintenance.
9. Based on our Phase I environmental site assessment for the
McIntosh Facility, we did not identify any environmental concerns
related to site contamination issues. Because no updated ESAs of
previous or recent environmental investigations regarding the potential
for site contamination issues at the sites of the other Generating
Facilities have been provided for our review, we can offer no opinion
with respect to potential site contamination issues at the sites of the
Dahlberg, Franklin, Harris, Stanton, and Wansley Facilities, if any, or
the potential for future remediation.
10. Southern Power has identified the major permits and
approvals necessary for the construction and operation of the
Generating Facilities. While all of the required permits and approvals
have not yet been obtained, we did not identify any technical or
engineering circumstance that would prevent the issuance of the
remaining permits and approvals. We note that the modification of the
NPDES Permit and the Surface Water Withdrawal Permit of the adjacent
steam plant to accommodate the McIntosh Facility have not yet been
issued and are under review by the Georgia Environmental Protection
Division. As such, we have not reviewed the conditions to be set forth
in the permits.
11. Southern Power's estimates of the costs of operating and
maintaining the Generating Facilities, including provision for major
maintenance, are within the range of the costs of similar plants with
which we are familiar.
12. For the Base Case Projected Operating Results, the
projected revenues from the sale of electricity are adequate to pay
annual operating and maintenance expenses (including major
maintenance), fuel expense, and other operating expenses. [Redacted]
There is insufficient cash available after the payment of interest to
repay the entire principal due on the Debt upon maturity. Southern
Power has assumed that the Debt will be refinanced upon maturity.
[Redacted]
Respectfully submitted,
R. W. BECK, INC.
A-45
EXHIBITS
EXHIBIT A-1 BASE CASE PROJECTED OPERATING RESULTS
A-46
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008
-------- -------- ------- ------- ------- -------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 31.3% 29.5% 31.7% 39.1% 43.8% 44.9%
Contract Energy Sales (GWh)(4) 5,943 11,442 16,544 20,333 22,763 23,315
Other Energy Sales (GWh)(4) 1,116 765 0 9 38 73
-------- -------- ------- ------- ------- -------
Total Energy Sales (GWh) 7,059 12,207 16,544 20,342 22,800 23,388
Fuel Consumption (BBtu) 48,697 92,948 124,247 152,609 168,579 172,934
Average Net Heat Rate (Btu/kWh)(5) 7,710 7,788 7,715 7,685 7,572 7,572
SO(2) Allowances Purchased (Tons)(6) 24 47 62 77 83 86
NO(X) Allowances Purchased (Tons)(7) 0 (70) 165 229 292 314
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 34.44 34.72 29.42 26.55 23.42 23.20
Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.18 16.83 19.29
Other Energy Price ($/MWh)(10) $ 52.82 48.71 0.00 67.31 68.32 65.64
Fuel Price ($/MMBtu)(11) $ 5.40 4.96 0.00 3.76 3.58 3.69
SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171
NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 16,645 34,138 0 0 0 0
Franklin (14) $ 85,818 109,905 116,396 120,196 122,832 124,145
Harris (14) $ 36,235 115,862 142,441 146,622 144,089 144,558
McIntosh $ 0 0 87,301 130,323 123,410 127,323
Stanton $ 10,374 45,040 44,420 45,276 45,484 45,836
Wansley $ 55,624 92,339 96,116 97,366 97,269 99,010
Other Electricity Revenues
Dahlberg $ 2,223 4,429 13,540 14,271 15,987 20,192
Franklin (14) $ 3,222 12,310 0 0 0 0
Harris $ 62,689 29,934 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
-------- -------- ------- ------- ------- -------
Total Operating Revenues $272,830 443,957 500,214 554,054 549,071 561,064
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 38 0 0 429 1,753 3,520
Franklin $ 1,318 8,423 0 0 0 0
Harris $ 45,315 21,309 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
Purchased Power (15) $ 43,081 13,258 20,974 22,153 24,224 25,754
Operations & Maintenance (16) $ 33,111 60,848 77,843 92,168 102,824 108,667
Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873
-------- -------- ------- ------- ------- -------
Total Operating Expenses $135,592 130,804 128,551 146,671 161,192 170,814
NET OPERATING REVENUES ($000) $137,238 313,154 371,663 407,383 387,879 390,250
ANNUAL INTEREST($000)(18) $ 36,531 73,063 87,463 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.76 4.29 4.25 4.00 3.81 3.83
2003-15 AVG INTEREST COVERAGE (20) 4.22
Year Ending December 31, 2009 2010 2011 2012 2013
------- ------- --------- --------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 43.6% 41.2% 42.3% 40.0% 36.5%
Contract Energy Sales (GWh)(4) 22,607 12,712 10,007 8,847 7,832
Other Energy Sales (GWh)(4) 86 8,491 11,721 11,674 10,804
------- ------- --------- --------- ---------
Total Energy Sales (GWh) 22,692 21,203 21,728 20,521 18,636
Fuel Consumption (BBtu) 167,909 159,487 162,653 154,397 141,954
Average Net Heat Rate (Btu/kWh)(5) 7,575 7,615 7,557 7,596 7,660
SO(2) Allowances Purchased (Tons)(6) 85 80 83 76 70
NO(X) Allowances Purchased (Tons)(7) 290 257 274 253 213
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 23.70 27.06 27.44 28.12 32.21
Other Capacity Price ($/MWh)(10) 36.69 46.49 58.16 62.97 67.71
Other Energy Price ($/MWh)(10) 67.93 45.84 47.51 49.19 50.06
Fuel Price ($/MMBtu)(11) 3.80 4.49 4.63 4.80 5.00
SO(2) Allowances ($/Ton)(12) 175 180 184 189 194
NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0
Franklin (14) 124,376 82,134 25,853 0 0
Harris (14) 144,040 89,115 74,485 74,217 74,430
McIntosh 121,774 126,117 127,802 127,964 138,295
Stanton 46,076 46,560 46,476 46,609 39,515
Wansley 99,498 0 0 0 0
Other Electricity Revenues
Dahlberg 35,052 40,321 53,484 55,407 56,286
Franklin (14) 0 81,488 225,938 271,958 260,111
Harris 0 104,379 167,795 164,181 167,052
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 9,790
Wansley 0 287,063 309,602 311,136 295,566
------- ------- --------- --------- ---------
Total Operating Revenues 570,816 857,177 1,031,435 1,051,472 1,041,045
OPERATING EXPENSES ($000)
Fuel
Dahlberg 4,242 2,569 5,267 3,711 1,718
Franklin 0 46,993 123,819 146,873 138,743
Harris 0 62,530 97,649 94,037 96,545
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 5,867
Wansley 0 176,261 182,099 180,998 169,780
Purchased Power (15) 25,204 13,054 10,511 10,282 5,270
Operations & Maintenance (16) 110,018 108,282 114,767 114,695 109,371
Administration and General (17) 33,364 33,872 34,386 34,924 35,465
------- ------- --------- --------- ---------
Total Operating Expenses 172,828 443,562 568,499 585,520 562,759
NET OPERATING REVENUES ($000) 397,987 413,615 462,936 465,952 478,286
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.91 4.06 4.54 4.57 4.70
2003-15 AVG INTEREST COVERAGE (20)
A-47
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018
---------- --------- --------- --------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 33.1% 31.3% 28.5% 26.3% 24.5%
Contract Energy Sales (GWh)(4) 6,352 6,051 5,629 5,115 4,738
Other Energy Sales (GWh)(4) 10,550 9,968 8,937 8,339 7,786
---------- --------- --------- --------- ---------
Total Energy Sales (GWh) 16,901 16,020 14,567 13,453 12,524
Fuel Consumption (BBtu) 130,059 123,431 113,265 105,067 98,368
Average Net Heat Rate (Btu/kWh)(5) 7,740 7,750 7,822 7,855 7,901
SO2 Allowances Purchased (Tons)(6) 66 62 57 52 49
NOX Allowances Purchased (Tons)(7) 174 143 102 81 68
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 34.12 35.99 39.32 43.28 46.20
Other Capacity Price ($/MWh)(10) $ 67.83 71.68 74.42 76.04 79.21
Other Energy Price ($/MWh)(10) $ 52.74 53.05 55.13 57.70 59.65
Fuel Price ($/MMBtu)(11) $ 5.34 5.53 5.79 6.03 6.21
SO2 Allowances ($/Ton)(12) $ 199 204 209 215 220
NOX Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 0 0 0 0 0
Franklin (14) $ 0 0 0 0 0
Harris (14) $ 75,619 76,488 75,534 74,859 75,898
McIntosh $ 141,097 141,329 145,813 146,477 143,008
Stanton $ 0 0 0 0 0
Wansley $ 0 0 0 0 0
Other Electricity Revenues
Dahlberg $ 55,353 56,856 58,471 59,764 62,426
Franklin (14) $ 250,895 236,471 229,122 221,854 222,225
Harris $ 154,761 155,722 149,400 149,374 150,355
McIntosh $ 0 0 0 0 0
Stanton $ 85,586 86,686 88,008 88,055 87,464
Wansley $ 282,582 281,329 266,973 267,947 260,555
---------- --------- --------- --------- ---------
Total Operating Revenues $1,045,893 1,034,881 1,013,321 1,008,330 1,001,931
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 1,229 291 0 0 0
Franklin $ 133,670 122,726 118,812 111,665 107,328
Harris $ 87,889 90,309 85,446 85,355 83,464
McIntosh $ 0 0 0 0 0
Stanton $ 51,374 51,636 52,163 51,430 51,765
Wansley $ 162,611 162,635 149,621 146,902 140,054
Purchased Power (15) $ 5,040 4,895 4,646 4,447 4,285
Operations & Maintenance (16) $ 105,991 109,381 103,618 102,295 102,455
Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416
---------- --------- --------- --------- ---------
Total Operating Expenses $ 583,827 578,475 551,492 539,886 527,767
NET OPERATING REVENUES ($000) $ 462,066 456,406 461,829 468,444 474,164
ANNUAL INTEREST($000)(18) $ 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.54 4.48 4.53 4.60 4.65
2003-15 AVG INTEREST COVERAGE (20) 4.22
Year Ending December 31, 2019 2020 2021 2022 2023
--------- --------- --------- --------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 22.8% 21.0% 20.2% 18.4% 18.4%
Contract Energy Sales (GWh)(4) 3,576 551 0 0 0
Other Energy Sales (GWh)(4) 8,061 10,107 10,274 9,375 9,375
--------- --------- --------- --------- ---------
Total Energy Sales (GWh) 11,638 10,657 10,274 9,375 9,375
Fuel Consumption (BBtu) 92,010 84,797 82,221 75,165 75,165
Average Net Heat Rate (Btu/kWh)(5) 7,928 7,957 8,003 8,018 8,018
SO2 Allowances Purchased (Tons)(6) 46 43 42 38 38
NOX Allowances Purchased (Tons)(7) 54 31 28 11 11
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 46.07 50.29 0.00 0.00 0.00
Other Capacity Price ($/MWh)(10) 83.11 84.87 87.74 89.36 91.68
Other Energy Price ($/MWh)(10) 62.83 64.45 66.02 67.65 69.40
Fuel Price ($/MMBtu)(11) 6.44 6.69 6.85 7.10 7.26
SO2 Allowances ($/Ton)(12) 226 232 238 244 251
NOX Allowances ($/Ton)(13) 2,435 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0
Franklin (14) 0 0 0 0 0
Harris (14) 16,327 0 0 0 0
McIntosh 148,445 27,698 0 0 0
Stanton 0 0 0 0 0
Wansley 0 0 0 0 0
Other Electricity Revenues
Dahlberg 65,796 67,299 69,661 70,940 72,784
Franklin (14) 219,581 208,898 213,547 197,972 203,119
Harris 243,589 285,657 282,765 283,337 290,702
McIntosh 0 217,143 279,817 259,961 266,720
Stanton 85,084 86,687 84,437 85,808 88,039
Wansley 260,275 257,924 257,133 254,567 261,186
--------- --------- --------- --------- ---------
Total Operating Revenues 1,039,097 1,151,306 1,187,360 1,152,585 1,182,550
OPERATING EXPENSES ($000)
Fuel
Dahlberg 0 0 0 0 0
Franklin 98,985 92,020 92,989 80,882 82,525
Harris 129,387 149,382 146,630 145,457 148,754
McIntosh 0 112,453 142,923 128,857 131,721
Stanton 49,421 51,114 49,309 50,143 51,047
Wansley 134,564 133,575 131,388 128,651 131,615
Purchased Power (15) 1,949 0 0 0 0
Operations & Maintenance (16) 100,654 100,077 105,674 100,368 120,978
Administration and General (17) 39,052 39,705 40,375 41,060 41,768
--------- --------- --------- --------- ---------
Total Operating Expenses 554,013 678,326 709,288 675,417 708,407
NET OPERATING REVENUES ($000) 485,084 472,980 478,072 477,168 474,143
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.76 4.64 4.69 4.68 4.65
2003-15 AVG INTEREST COVERAGE (20)
A-48
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008
--------- ------ ------ ------ ------ ------
DAHLBERG FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 797 797 797 797 797 797
Average Annual Contract Capacity (MW)(19) 578 578 0 0 0 0
Average Annual Other Capacity (MW)(19) 239 239 797 797 797 797
Capacity Factor (%)(3) 0.2% 0.0% 0.0% 0.1% 0.5% 1.1%
Energy Generation (GWh) 7 0 0 9 38 73
Contract Energy Sales (GWh) 6 0 0 0 0 0
Other Energy Sales (Purchases)(GWh) 1 0 0 9 38 73
Net Heat Rate (Btu/kWh)(5) 12,733 0 0 13,253 13,020 13,016
Contract Fuel Consumption (BBtu) 77 0 0 0 0 0
Other Fuel Consumption (BBtu) 9 0 0 114 490 955
SO2 Allowances Purchased (Tons)(6) 0 0 0 0 0 0
NOX Allowances Purchased (Tons)(7) 0 0 0 1 6 11
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $2,620.87 0.00 0.00 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) $ 9.09 18.52 16.99 17.18 16.83 19.29
Energy ($/MWh) $ 70.32 0.00 0.00 67.31 68.32 65.64
Fuel ($/MMBtu)(12) $ 4.19 0.00 0.00 3.76 3.58 3.69
SO2 Allowances ($/Ton)(13) $ 150 154 158 162 166 171
NOX Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836
OPERATING REVENUES ($000)
Contract Electricity Revenues $ 16,645 34,138 0 0 0 0
Other Electricity Revenues
Capacity Revenues $ 2,173 4,429 13,540 13,692 13,416 15,376
Energy Revenues $ 50 0 0 579 2,571 4,816
--------- ------ ------ ------ ------ ------
Total Operating Revenues $ 18,868 38,567 13,540 14,271 15,987 20,192
OPERATING EXPENSES ($000)(16)
Fuel Costs $ 38 0 0 429 1,753 3,520
Purchased Power $ 22 0 0 0 0 0
Operating and Maintenance $ 5,141 2,715 2,786 3,215 4,531 6,207
Administrative and General $ 2,605 5,268 5,323 5,378 5,435 5,496
--------- ------ ------ ------ ------ ------
Total Operating Expenses $ 11,939 8,754 8,899 10,105 13,778 18,535
NET OPERATING REVENUES ($000) $ 11,062 30,584 5,431 5,249 4,268 4,969
Year Ending December 31, 2009 2010 2011 2012 2013
------ ------ ------ ------ ------
DAHLBERG FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 797 797 797 797 797
Average Annual Contract Capacity (MW)(19) 0 0 0 0 0
Average Annual Other Capacity (MW)(19) 797 797 797 797 797
Capacity Factor (%)(3) 1.2% 0.7% 1.4% 1.0% 0.4%
Energy Generation (GWh) 86 50 100 69 31
Contract Energy Sales (GWh) 0 0 0 0 0
Other Energy Sales (Purchases)(GWh) 86 50 100 69 31
Net Heat Rate (Btu/kWh)(5) 13,063 13,115 13,070 12,991 13,042
Contract Fuel Consumption (BBtu) 0 0 0 0 0
Other Fuel Consumption (BBtu) 1,117 657 1,307 894 402
SO2 Allowances Purchased (Tons)(6) 1 0 1 0 0
NOX Allowances Purchased (Tons)(7) 13 8 15 11 5
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) 0.00 0.00 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) 36.69 46.49 58.16 62.97 67.51
Energy ($/MWh) 67.93 65.25 71.34 75.87 80.59
Fuel ($/MMBtu)(12) 3.80 3.91 4.03 4.15 4.28
SO2 Allowances ($/Ton)(13) 175 180 184 189 194
NOX Allowances ($/Ton)(14) 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues 0 0 0 0 0
Other Electricity Revenues
Capacity Revenues 29,243 37,052 46,350 50,186 53,802
Energy Revenues 5,809 3,269 7,134 5,221 2,484
------ ------ ------ ------ ------
Total Operating Revenues 35,052 40,321 53,484 55,407 56,286
OPERATING EXPENSES ($000)(16)
Fuel Costs 4,242 2,569 5,267 3,711 1,718
Purchased Power 0 0 0 0 0
Operating and Maintenance 6,917 5,468 7,957 8,451 4,948
Administrative and General 5,556 5,617 5,682 5,749 5,815
------ ------ ------ ------ ------
Total Operating Expenses 20,534 16,316 23,442 23,197 14,613
NET OPERATING REVENUES ($000) 18,337 26,667 34,578 37,496 43,805
A-49
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 2020
------- ------ ------ ------ ------ ------ ------
DAHLBERG FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 797 797 797 797 797 797 797
Average Annual Contract Capacity (MW)(19) 0 0 0 0 0 0 0
Average Annual Other Capacity (MW)(19) 797 797 797 797 797 797 797
Capacity Factor (%)(3) 0.3% 0.1% 0.0% 0.0% 0.0% 0.0% 0.0%
Energy Generation (GWh) 22 5 0 0 0 0 0
Contract Energy Sales (GWh) 0 0 0 0 0 0 0
Other Energy Sales (Purchases)(GWh) 22 5 0 0 0 0 0
Net Heat Rate (Btu/kWh)(5) 12,761 12,754 0 0 0 0 0
Contract Fuel Consumption (BBtu) 0 0 0 0 0 0 0
Other Fuel Consumption (BBtu) 279 64 0 0 0 0 0
SO2 Allowances Purchased (Tons)(6) 0 0 0 0 0 0 0
NOX Allowances Purchased (Tons)(7) 3 1 0 0 0 0 0
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) $ 67.11 70.80 73.36 74.99 78.33 82.55 84.44
Energy ($/MWh) $ 85.39 84.90 0.00 0.00 0.00 0.00 0.00
Fuel ($/MMBtu)(12) $ 4.40 4.53 0.00 0.00 0.00 0.00 0.00
SO2 Allowances ($/Ton)(13) $ 199 204 209 215 220 226 232
NOX Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435 2,498
OPERATING REVENUES ($000)
Contract Electricity Revenues $ 0 0 0 0 0 0 0
Other Electricity Revenues
Capacity Revenues $53,486 56,430 58,471 59,764 62,426 65,796 67,299
Energy Revenues $ 1,867 426 0 0 0 0 0
------- ------ ------ ------ ------ ------ ------
Total Operating Revenues $55,353 56,856 58,471 59,764 62,426 65,796 67,299
OPERATING EXPENSES ($000)(16)
Fuel Costs $ 1,229 291 0 0 0 0 0
Purchased Power $ 0 0 0 0 0 0 0
Operating and Maintenance $ 4,620 3,864 3,694 3,790 3,888 3,990 4,093
Administrative and General $ 5,883 5,954 6,027 6,102 6,180 6,257 6,338
------- ------ ------ ------ ------ ------ ------
Total Operating Expenses $13,566 11,312 10,748 10,944 11,145 11,351 11,562
NET OPERATING REVENUES ($000) $43,621 46,747 48,750 49,872 52,358 55,549 56,868
Year Ending December 31, 2021 2022 2023
------ ------ ------
DAHLBERG FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 797 797 797
Average Annual Contract Capacity (MW)(19) 0 0 0
Average Annual Other Capacity (MW)(19) 797 797 797
Capacity Factor (%)(3) 0.0% 0.0% 0.0%
Energy Generation (GWh) 0 0 0
Contract Energy Sales (GWh) 0 0 0
Other Energy Sales (Purchases)(GWh) 0 0 0
Net Heat Rate (Btu/kWh)(5) 0 0 0
Contract Fuel Consumption (BBtu) 0 0 0
Other Fuel Consumption (BBtu) 0 0 0
SO2 Allowances Purchased (Tons)(6) 0 0 0
NOX Allowances Purchased (Tons)(7) 0 0 0
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60
Contract Electricity ($/MWh) 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) 87.40 89.01 91.32
Energy ($/MWh) 0.00 0.00 0.00
Fuel ($/MMBtu)(12) 0.00 0.00 0.00
SO2 Allowances ($/Ton)(13) 238 244 251
NOX Allowances ($/Ton)(14) 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues 0 0 0
Other Electricity Revenues
Capacity Revenues 69,661 70,940 72,784
Energy Revenues 0 0 0
------ ------ ------
Total Operating Revenues 69,661 70,940 72,784
OPERATING EXPENSES ($000)(16)
Fuel Costs 0 0 0
Purchased Power 0 0 0
Operating and Maintenance 4,201 4,310 4,422
Administrative and General 6,420 6,503 6,592
------ ------ ------
Total Operating Expenses 11,779 11,999 12,230
NET OPERATING REVENUES ($000) 59,040 60,127 61,770
A-50
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008
------- -------- -------- -------- -------- --------
FRANKLIN FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,139 1,139 1,139 1,139 1,139 1,139
Average Annual Contract Capacity (MW) 942 1,090 1,139 1,139 1,139 1,139
Average Annual Other Capacity (MW) 99 82 0 0 0 0
Capacity Factor (%)(3) 35.3% 29.7% 32.2% 37.9% 45.6% 46.5%
Energy Generation (GWh) 1,761 2,965 3,217 3,781 4,552 4,644
Contract Energy Sales (GWh) 2,385 2,784 3,300 3,878 4,670 4,764
Other Energy Sales (Purchases)(GWh) 29 216 0 0 0 0
Net Heat Rate (Btu/kWh)(5) 7,567 7,913 7,854 7,818 7,687 7,658
Contract Fuel Consumption (BBtu) 13,102 21,767 25,270 29,556 34,993 35,565
Other Fuel Consumption (BBtu) 223 1,693 0 0 0 0
SO2 Allowances Purchased (Tons)(6) 7 12 13 15 17 18
NOX Allowances Purchased (Tons)(7) 0 (42) (34) (26) (9) (3)
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $ 35.99 39.48 35.27 30.99 26.30 26.06
Other Electricity
Capacity ($/kW-yr) $ 16.90 18.52 0.00 0.00 0.00 0.00
Energy ($/MWh) $ 54.10 50.00 0.00 0.00 0.00 0.00
Fuel ($/MMBtu)(12) $ 4.48 4.19 0.00 0.00 0.00 0.00
SO2 Allowances ($/Ton)(13) $ 150 154 158 162 166 171
NOX Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836
OPERATING REVENUES ($000)
Contract Electricity Revenues $85,818 109,905 116,396 120,196 122,832 124,145
Other Electricity Revenues
Capacity Revenues $ 1,670 1,525 0 0 0 0
Energy Revenues $ 1,552 10,785 0 0 0 0
------- -------- -------- -------- -------- --------
Total Operating Revenues $89,040 122,215 116,396 120,196 122,832 124,145
OPERATING EXPENSES ($000)(16)
Fuel Costs $ 1,318 8,423 0 0 0 0
Purchased Power $38,355 1,730 4,012 4,604 5,370 5,702
Operating and Maintenance $ 8,504 16,067 17,370 19,327 21,986 22,872
Administrative and General $ 4,317 8,715 8,800 8,888 8,978 9,069
------- -------- -------- -------- -------- --------
Total Operating Expenses $56,156 41,484 37,592 41,482 46,748 48,555
NET OPERATING REVENUES ($000) $36,547 87,280 86,214 87,377 86,498 86,502
Year Ending December 31, 2009 2010 2011 2012 2013
-------- -------- -------- -------- --------
FRANKLIN FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,139 1,139 1,139 1,139 1,139
Average Annual Contract Capacity (MW) 1,139 1,139 598 0 0
Average Annual Other Capacity (MW) 0 542 1,139 1,139 1,139
Capacity Factor (%)(3) 44.1% 41.6% 41.1% 38.6% 34.6%
Energy Generation (GWh) 4,398 4,147 4,101 3,850 3,453
Contract Energy Sales (GWh) 4,511 2,910 715 0 0
Other Energy Sales (Purchases)(GWh) 0 1,294 3,385 3,850 3,453
Net Heat Rate (Btu/kWh)(5) 7,690 7,791 7,694 7,748 7,821
Contract Fuel Consumption (BBtu) 33,820 22,131 5,485 0 0
Other Fuel Consumption (BBtu) 0 10,177 26,068 29,831 27,007
SO2 Allowances Purchased (Tons)(6) 17 16 16 15 14
NOX Allowances Purchased (Tons)(7) (12) (20) (20) (24) (34)
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) 27.57 28.23 36.14 0.00 0.00
Other Electricity
Capacity ($/kW-yr) 0.00 31.77 48.49 62.97 67.51
Energy ($/MWh) 0.00 49.66 50.42 52.00 53.05
Fuel ($/MMBtu)(12) 0.00 3.99 4.10 4.23 4.36
SO2 Allowances ($/Ton)(13) 175 180 184 189 194
NOX Allowances ($/Ton)(14) 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues 124,376 82,134 25,853 0 0
Other Electricity Revenues
Capacity Revenues 0 17,205 55,245 71,735 76,902
Energy Revenues 0 64,283 170,693 200,223 183,209
-------- -------- -------- -------- --------
Total Operating Revenues 124,376 163,622 251,791 271,958 260,111
OPERATING EXPENSES ($000)(16)
Fuel Costs 0 46,993 123,819 146,873 138,743
Purchased Power 5,524 2,822 0 0 0
Operating and Maintenance 22,725 22,479 22,919 22,751 22,052
Administrative and General 9,164 9,260 9,358 9,461 9,565
-------- -------- -------- -------- --------
Total Operating Expenses 48,076 91,882 166,589 189,317 179,943
NET OPERATING REVENUES ($000) 86,963 82,068 95,694 92,872 89,750
A-51
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019
--------- -------- -------- -------- -------- --------
FRANKLIN FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,139 1,139 1,139 1,139 1,139 1,139
Average Annual Contract Capacity (MW) 0 0 0 0 0 0
Average Annual Other Capacity (MW) 1,139 1,139 1,139 1,139 1,139 1,139
Capacity Factor (%)(3) 31.9% 27.7% 25.3% 22.8% 21.4% 19.0%
Energy Generation (GWh) 3,181 2,760 2,520 2,270 2,134 1,899
Contract Energy Sales (GWh) 0 0 0 0 0 0
Other Energy Sales (Purchases)(GWh) 3,181 2,760 2,520 2,270 2,134 1,899
Net Heat Rate (Btu/kWh)(5) 7,876 7,910 7,968 7,958 7,992 7,967
Contract Fuel Consumption (BBtu) 0 0 0 0 0 0
Other Fuel Consumption (BBtu) 25,054 21,832 20,082 18,068 17,052 15,130
SO2 Allowances Purchased (Tons)(6) 13 11 10 9 9 8
NOX Allowances Purchased (Tons)(7) (36) (45) (51) (59) (58) (62)
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) $ 67.11 70.80 73.36 74.99 78.33 82.55
Energy ($/MWh) $ 54.84 56.46 57.75 60.09 62.33 66.10
Fuel ($/MMBtu)(12) $ 4.48 4.62 4.80 5.01 5.20 5.38
SO2 Allowances ($/Ton)(13) $ 199 204 209 215 220 226
NOX Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435
OPERATING REVENUES ($000)
Contract Electricity Revenues $ 0 0 0 0 0 0
Other Electricity Revenues
Capacity Revenues $ 76,452 80,659 83,577 85,423 89,230 94,045
Energy Revenues $ 174,443 155,812 145,545 136,431 132,995 125,536
--------- -------- -------- -------- -------- --------
Total Operating Revenues $ 250,895 236,471 229,122 221,854 222,225 219,581
OPERATING EXPENSES ($000)(16)
Fuel Costs $ 133,670 122,726 118,812 111,665 107,328 98,985
Purchased Power $ 0 0 0 0 0 0
Operating and Maintenance $ 21,769 21,204 21,366 20,868 20,886 20,329
Administrative and General $ 9,672 9,782 9,894 10,008 10,128 10,249
--------- -------- -------- -------- -------- --------
Total Operating Expenses $ 174,344 162,479 158,921 150,827 146,459 137,049
NET OPERATING REVENUES ($000) $ 85,784 82,759 79,051 79,314 83,883 90,017
Year Ending December 31, 2020 2021 2022 2023
-------- -------- -------- --------
FRANKLIN FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,139 1,139 1,139 1,139
Average Annual Contract Capacity (MW) 0 0 0 0
Average Annual Other Capacity (MW) 1,139 1,139 1,139 1,139
Capacity Factor (%)(3) 16.5% 16.3% 13.3% 13.3%
Energy Generation (GWh) 1,651 1,631 1,330 1,330
Contract Energy Sales (GWh) 0 0 0 0
Other Energy Sales (Purchases)(GWh) 1,651 1,631 1,330 1,330
Net Heat Rate (Btu/kWh)(5) 8,004 8,033 8,065 8,065
Contract Fuel Consumption (BBtu) 0 0 0 0
Other Fuel Consumption (BBtu) 13,212 13,099 10,725 10,725
SO2 Allowances Purchased (Tons)(6) 7 7 5 5
NOX Allowances Purchased (Tons)(7) (71) (69) (77) (77)
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) 0.00 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) 84.44 87.40 89.01 91.32
Energy ($/MWh) 68.28 69.90 72.62 74.51
Fuel ($/MMBtu)(12) 5.63 5.75 5.89 6.05
SO2 Allowances ($/Ton)(13) 232 238 244 251
NOX Allowances ($/Ton)(14) 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues 0 0 0 0
Other Electricity Revenues
Capacity Revenues 96,194 99,571 101,398 104,034
Energy Revenues 112,704 113,976 96,574 99,085
-------- -------- -------- --------
Total Operating Revenues 208,898 213,547 197,972 203,119
OPERATING EXPENSES ($000)(16)
Fuel Costs 92,020 92,989 80,882 82,525
Purchased Power 0 0 0 0
Operating and Maintenance 19,770 20,183 19,360 19,862
Administrative and General 10,374 10,502 10,634 10,769
-------- -------- -------- --------
Total Operating Expenses 129,050 130,656 117,049 119,487
NET OPERATING REVENUES ($000) 86,734 89,873 87,096 89,963
A-52
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008
------- -------- -------- -------- ------- -------
HARRIS FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,192 1,192 1,192 1,192 1,192 1,192
Average Annual Contract Capacity (MW) 602 1,192 1,192 1,192 1,192 1,192
Average Annual Other Capacity (MW) 590 590 0 0 0 0
Capacity Factor (%)(3) 41.6% 37.7% 42.9% 49.0% 53.6% 55.1%
Energy Generation (GWh) 2,171 3,934 4,486 5,119 5,600 5,754
Contract Energy Sales (GWh) 1,107 3,428 4,589 5,238 5,729 5,887
Other Energy Sales (Purchases)(GWh) 1,086 549 0 0 0 0
Net Heat Rate (Btu/kWh)(5) 7,766 7,810 7,712 7,669 7,556 7,531
Contract Fuel Consumption (BBtu) 8,442 26,421 34,594 39,261 42,311 43,337
Other Fuel Consumption (BBtu) 8,418 4,301 0 0 0 0
SO2 Allowances Purchased (Tons)(6) 8 15 17 20 21 22
NOX Allowances Purchased (Tons)(7) 0 (28) (17) (6) 5 14
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $ 32.73 33.80 31.04 27.99 25.15 24.55
Other Electricity
Capacity ($/kW-yr) $ 9.09 5.87 0.00 0.00 0.00 0.00
Energy ($/MWh) $ 52.78 48.20 0.00 0.00 0.00 0.00
Fuel ($/MMBtu)(12) $ 4.48 4.18 0.00 0.00 0.00 0.00
SO2 Allowances ($/Ton)(13) $ 150 154 158 162 166 171
NOX Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836
OPERATING REVENUES ($000)
Contract Electricity Revenues $36,235 115,862 142,441 146,622 144,089 144,558
Other Electricity Revenues
Capacity Revenues $ 5,362 3,461 0 0 0 0
Energy Revenues $57,327 26,473 0 0 0 0
------- -------- -------- -------- ------- -------
Total Operating Revenues $98,924 145,796 142,441 146,622 144,089 144,558
OPERATING EXPENSES ($000)(16)
Fuel Costs $45,315 21,309 0 0 0 0
Purchased Power $ 1,175 2,058 4,779 5,248 5,638 6,029
Operating and Maintenance $ 8,960 17,603 19,545 21,750 23,491 24,525
Administrative and General $ 3,514 7,114 7,203 7,296 7,390 7,488
------- -------- -------- -------- ------- -------
Total Operating Expenses $63,540 56,915 41,760 46,125 49,551 51,742
NET OPERATING REVENUES ($000) $39,960 97,712 110,914 112,328 107,570 106,516
Year Ending December 31, 2009 2010 2011 2012 2013
------- -------- ------- -------- --------
HARRIS FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,192 1,192 1,192 1,192 1,192
Average Annual Contract Capacity (MW) 1,192 1,192 590 590 590
Average Annual Other Capacity (MW) 0 602 602 602 602
Capacity Factor (%)(3) 53.5% 49.8% 52.7% 49.5% 46.4%
Energy Generation (GWh) 5,589 5,199 5,509 5,171 4,842
Contract Energy Sales (GWh) 5,718 3,416 2,739 2,621 2,302
Other Energy Sales (Purchases)(GWh) 0 1,846 2,839 2,616 2,598
Net Heat Rate (Btu/kWh)(5) 7,532 7,566 7,507 7,540 7,596
Contract Fuel Consumption (BBtu) 42,094 25,381 20,116 19,270 17,133
Other Fuel Consumption (BBtu) 0 13,951 21,242 19,722 19,649
SO2 Allowances Purchased (Tons)(6) 21 20 21 19 18
NOX Allowances Purchased (Tons)(7) 4 (3) 2 (3) (10)
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) 25.19 26.09 27.19 28.31 32.33
Other Electricity
Capacity ($/kW-yr) 0.00 31.77 58.16 62.97 67.51
Energy ($/MWh) 0.00 46.17 46.77 48.27 48.66
Fuel ($/MMBtu)(12) 0.00 3.98 4.10 4.22 4.35
SO2 Allowances ($/Ton)(13) 175 180 184 189 194
NOX Allowances ($/Ton)(14) 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues 144,040 89,115 74,485 74,217 74,430
Other Electricity Revenues
Capacity Revenues 0 19,130 35,021 37,920 40,652
Energy Revenues 0 85,249 132,774 126,261 126,400
------- -------- ------- -------- --------
Total Operating Revenues 144,040 193,494 242,280 238,398 241,482
OPERATING EXPENSES ($000)(16)
Fuel Costs 0 62,530 97,649 94,037 96,545
Purchased Power 6,011 2,989 3,259 3,216 2,887
Operating and Maintenance 24,672 24,223 25,804 26,012 26,410
Administrative and General 7,587 7,690 7,795 7,904 8,013
------- -------- ------- -------- --------
Total Operating Expenses 51,934 110,608 148,770 145,563 148,573
NET OPERATING REVENUES ($000) 105,770 96,061 107,774 107,229 107,628
A-53
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019
--------- -------- -------- -------- -------- --------
HARRIS FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,192 1,192 1,192 1,192 1,192 1,192
Average Annual Contract Capacity (MW) 590 590 590 590 590 590
Average Annual Other Capacity (MW) 602 602 602 602 602 1,192
Capacity Factor (%)(3) 41.2% 40.9% 36.9% 34.0% 32.5% 30.0%
Energy Generation (GWh) 4,307 4,275 3,851 3,548 3,400 3,132
Contract Energy Sales (GWh) 2,145 2,119 1,928 1,720 1,656 495
Other Energy Sales (Purchases)(GWh) 2,216 2,209 1,972 1,871 1,785 2,637
Net Heat Rate (Btu/kWh)(5) 7,701 7,717 7,769 7,830 7,863 7,926
Contract Fuel Consumption (BBtu) 16,112 15,932 14,587 13,145 12,738 3,919
Other Fuel Consumption (BBtu) 17,061 17,057 15,334 14,632 13,993 20,902
SO2 Allowances Purchased (Tons)(6) 17 16 15 14 13 12
NOX Allowances Purchased (Tons)(7) (24) (29) (39) (45) (45) (53)
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $ 35.25 36.09 39.18 43.51 45.82 32.99
Other Electricity
Capacity ($/kW-yr) $ 67.11 70.80 73.36 74.99 78.33 69.62
Energy ($/MWh) $ 51.60 51.19 53.36 55.71 57.81 60.90
Fuel ($/MMBtu)(12) $ 4.49 4.62 4.81 5.02 5.22 5.45
SO2 Allowances ($/Ton)(13) $ 199 204 209 215 220 226
NOX Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435
OPERATING REVENUES ($000)
Contract Electricity Revenues $ 75,619 76,488 75,534 74,859 75,898 16,327
Other Electricity Revenues
Capacity Revenues $ 40,414 42,638 44,180 45,156 47,169 83,003
Energy Revenues $ 114,347 113,084 105,220 104,218 103,186 160,586
--------- -------- -------- -------- -------- --------
Total Operating Revenues $ 230,380 232,210 224,934 224,233 226,253 259,916
OPERATING EXPENSES ($000)(16)
Fuel Costs $ 87,889 90,309 85,446 85,355 83,464 129,387
Purchased Power $ 2,773 2,759 2,589 2,460 2,431 0
Operating and Maintenance $ 25,239 25,720 24,956 24,604 24,915 24,366
Administrative and General $ 8,126 8,242 8,361 8,486 8,611 8,740
--------- -------- -------- -------- -------- --------
Total Operating Expenses $ 137,641 140,846 134,405 133,528 132,157 174,575
NET OPERATING REVENUES ($000) $ 106,354 105,180 103,582 103,328 106,832 97,422
Year Ending December 31, 2020 2021 2022 2023
-------- -------- -------- --------
HARRIS FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,192 1,192 1,192 1,192
Average Annual Contract Capacity (MW) 0 0 0 0
Average Annual Other Capacity (MW) 1,192 1,192 1,192 1,192
Capacity Factor (%)(3) 27.9% 26.6% 25.5% 25.5%
Energy Generation (GWh) 2,919 2,775 2,662 2,662
Contract Energy Sales (GWh) 0 0 0 0
Other Energy Sales (Purchases)(GWh) 2,919 2,775 2,662 2,662
Net Heat Rate (Btu/kWh)(5) 7,912 7,955 7,996 7,996
Contract Fuel Consumption (BBtu) 0 0 0 0
Other Fuel Consumption (BBtu) 23,096 22,077 21,285 21,285
SO2 Allowances Purchased (Tons)(6) 12 11 11 11
NOX Allowances Purchased (Tons)(7) (54) (57) (58) (58)
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) 0.00 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) 84.44 87.40 89.01 91.32
Energy ($/MWh) 63.37 64.34 66.57 68.30
Fuel ($/MMBtu)(12) 5.66 5.80 5.96 6.11
SO2 Allowances ($/Ton)(13) 232 238 244 251
NOX Allowances ($/Ton)(14) 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues 0 0 0 0
Other Electricity Revenues
Capacity Revenues 100,678 104,212 106,125 108,883
Energy Revenues 184,979 178,553 177,212 181,819
-------- -------- -------- --------
Total Operating Revenues 285,657 282,765 283,337 290,702
OPERATING EXPENSES ($000)(16)
Fuel Costs 149,382 146,630 145,457 148,754
Purchased Power 0 0 0 0
Operating and Maintenance 24,303 24,454 24,580 25,219
Administrative and General 8,873 9,008 9,148 9,290
-------- -------- -------- --------
Total Operating Expenses 194,427 191,913 190,898 195,279
NET OPERATING REVENUES ($000) 103,100 102,673 104,153 107,440
A-54
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 2009
------- ----- ------ ------- ------- ------- -------
McINTOSH FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 0 0 1,190 1,190 1,190 1,190 1,190
Average Annual Contract Capacity (MW) 0 0 1,190 1,190 1,190 1,190 1,190
Average Annual Other Capacity (MW) 0 0 0 0 0 0 0
Capacity Factor (%)(3) 0.0% 0.0% 49.4% 46.8% 51.5% 52.6% 52.8%
Energy Generation (GWh) 0 0 3,005 4,877 5,371 5,484 5,500
Contract Energy Sales (GWh) 0 0 3,067 4,928 5,427 5,541 5,558
Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 0 0
Net Heat Rate (Btu/kWh)(5) 0 0 7,604 7,666 7,545 7,552 7,495
Contract Fuel Consumption (BBtu) 0 0 22,848 37,387 40,521 41,419 41,226
Other Fuel Consumption (BBtu) 0 0 0 0 0 0 0
SO2 Allowances Purchased (Tons)(6) 0 0 11 19 20 21 21
NOX Allowances Purchased (Tons)(7) 0 0 97 128 146 146 143
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $0.00 0.00 28.47 26.45 22.74 22.98 21.91
Other Electricity
Capacity ($/kW-yr) $0.00 0.00 0.00 0.00 0.00 0.00 0.00
Energy ($/MWh) $0.00 0.00 0.00 0.00 0.00 0.00 0.00
Fuel ($/MMBtu)(12) $0.00 0.00 0.00 0.00 0.00 0.00 0.00
SO2 Allowances ($/Ton)(13) $150 154 158 162 166 171 175
NOX Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836 1,884
OPERATING REVENUES ($000)
Contract Electricity Revenues $ 0 0 87,301 130,323 123,410 127,323 121,774
Other Electricity Revenues
Capacity Revenues $ 0 0 0 0 0 0 0
Energy Revenues $ 0 0 0 0 0 0 0
---- ----- ------ ------- ------- ------- -------
Total Operating Revenues $ 0 0 87,301 130,323 123,410 127,323 121,774
OPERATING EXPENSES ($000)(16)
Fuel Costs $ 0 0 0 0 0 0 0
Purchased Power $ 0 0 2,956 2,243 2,446 2,612 2,620
Operating and Maintenance $ 0 0 12,210 19,263 20,481 21,310 21,604
Administrative and General $ 0 0 2,428 4,266 4,378 4,490 4,604
---- ----- ------ ------- ------- ------- -------
Total Operating Expenses $ 0 0 24,916 36,591 38,835 40,471 40,926
NET OPERATING REVENUES ($000) $ 0 0 69,707 104,551 96,105 98,911 92,946
Year Ending December 31, 2010 2011 2012 2013
------- ------- ------- -------
McINTOSH FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,190 1,190 1,190 1,190
Average Annual Contract Capacity (MW) 1,190 1,190 1,190 1,190
Average Annual Other Capacity (MW) 0 0 0 0
Capacity Factor (%)(3) 48.1% 50.4% 48.2% 43.7%
Energy Generation (GWh) 5,011 5,257 5,023 4,558
Contract Energy Sales (GWh) 5,063 5,311 5,075 4,605
Other Energy Sales (Purchases)(GWh) 0 0 0 0
Net Heat Rate (Btu/kWh)(5) 7,559 7,520 7,526 7,647
Contract Fuel Consumption (BBtu) 37,876 39,531 37,803 34,853
Other Fuel Consumption (BBtu) 0 0 0 0
SO2 Allowances Purchased (Tons)(6) 19 20 19 17
NOX Allowances Purchased (Tons)(7) 133 137 135 125
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) 24.91 24.06 25.21 30.03
Other Electricity
Capacity ($/kW-yr) 0.00 0.00 0.00 0.00
Energy ($/MWh) 0.00 0.00 0.00 0.00
Fuel ($/MMBtu)(12) 0.00 0.00 0.00 0.00
SO2 Allowances ($/Ton)(13) 180 184 189 194
NOX Allowances ($/Ton)(14) 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues 126,117 127,802 127,964 138,295
Other Electricity Revenues
Capacity Revenues 0 0 0 0
Energy Revenues 0 0 0 0
------- ------- ------- -------
Total Operating Revenues 126,117 127,802 127,964 138,295
OPERATING EXPENSES ($000)(16)
Fuel Costs 0 0 0 0
Purchased Power 2,444 2,607 2,550 2,383
Operating and Maintenance 20,973 21,586 21,465 20,990
Administrative and General 4,726 4,844 4,970 5,096
------- ------- ------- -------
Total Operating Expenses 39,666 40,770 40,491 39,553
NET OPERATING REVENUES ($000) 97,974 98,765 98,979 109,826
A-55
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019
-------- ------- ------- ------- ------- -------
McINTOSH FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,190 1,190 1,190 1,190 1,190 1,190
Average Annual Contract Capacity (MW) 1,190 1,190 1,190 1,190 1,190 1,190
Average Annual Other Capacity (MW) 0 0 0 0 0 0
Capacity Factor (%)(3) 39.9% 37.3% 35.1% 32.2% 29.3% 29.3%
Energy Generation (GWh) 4,163 3,892 3,663 3,359 3,050 3,050
Contract Energy Sales (GWh) 4,206 3,932 3,702 3,394 3,082 3,082
Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 0
Net Heat Rate (Btu/kWh)(5) 7,718 7,746 7,800 7,841 7,880 7,900
Contract Fuel Consumption (BBtu) 32,127 30,144 28,573 26,340 24,031 24,092
Other Fuel Consumption (BBtu) 0 0 0 0 0 0
SO2 Allowances Purchased (Tons)(6) 16 15 14 13 12 12
NOX Allowances Purchased (Tons)(7) 114 105 98 95 87 89
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $ 33.54 35.94 39.39 43.15 46.41 48.17
Other Electricity
Capacity ($/kW-yr) $ 0.00 0.00 0.00 0.00 0.00 0.00
Energy ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00
Fuel ($/MMBtu)(12) $ 0.00 0.00 0.00 0.00 0.00 0.00
SO2 Allowances ($/Ton)(13) $ 199 204 209 215 220 226
NOX Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435
OPERATING REVENUES ($000)
Contract Electricity Revenues $141,097 141,329 145,813 146,477 143,008 148,445
Other Electricity Revenues
Capacity Revenues $ 0 0 0 0 0 0
Energy Revenues $ 0 0 0 0 0 0
-------- ------- ------- ------- ------- -------
Total Operating Revenues $141,097 141,329 145,813 146,477 143,008 148,445
OPERATING EXPENSES ($000)(16)
Fuel Costs $ 0 0 0 0 0 0
Purchased Power $ 2,267 2,136 2,057 1,987 1,854 1,949
Operating and Maintenance $ 20,484 24,214 20,566 20,126 20,071 20,081
Administrative and General $ 5,226 5,364 5,498 5,640 5,786 5,936
-------- ------- ------- ------- ------- -------
Total Operating Expenses $ 38,568 45,968 38,632 37,788 37,664 37,663
NET OPERATING REVENUES ($000) $113,120 109,615 117,692 118,724 115,297 120,479
Year Ending December 31, 2020 2021 2022 2023
------- ------- ------- -------
McINTOSH FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,190 1,190 1,190 1,190
Average Annual Contract Capacity (MW) 1,190 0 0 0
Average Annual Other Capacity (MW) 1,190 1,190 1,190 1,190
Capacity Factor (%)(3) 26.1% 25.8% 22.2% 22.2%
Energy Generation (GWh) 2,725 2,691 2,317 2,317
Contract Energy Sales (GWh) 551 0 0 0
Other Energy Sales (Purchases)(GWh) 2,175 2,691 2,317 2,317
Net Heat Rate (Btu/kWh)(5) 7,909 7,970 7,969 7,969
Contract Fuel Consumption (BBtu) 4,356 0 0 0
Other Fuel Consumption (BBtu) 17,199 21,450 18,464 18,464
SO2 Allowances Purchased (Tons)(6) 11 11 9 9
NOX Allowances Purchased (Tons)(7) 79 82 72 72
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) 50.29 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) 67.55 87.40 89.01 91.32
Energy ($/MWh) 62.89 65.32 66.48 68.21
Fuel ($/MMBtu)(12) 5.67 5.79 5.97 6.12
SO2 Allowances ($/Ton)(13) 232 238 244 251
NOX Allowances ($/Ton)(14) 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues 27,698 0 0 0
Other Electricity Revenues
Capacity Revenues 80,386 104,010 105,920 108,674
Energy Revenues 136,757 175,807 154,041 158,046
------- ------- ------- -------
Total Operating Revenues 244,841 279,817 259,961 266,720
OPERATING EXPENSES ($000)(16)
Fuel Costs 112,453 142,923 128,857 131,721
Purchased Power 0 0 0 0
Operating and Maintenance 19,870 24,739 19,685 38,198
Administrative and General 6,088 6,246 6,404 6,570
------- ------- ------- -------
Total Operating Expenses 147,888 188,009 164,033 203,812
NET OPERATING REVENUES ($000) 106,429 105,909 105,015 90,231
A-56
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
- ------------------------ ------- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
STANTON FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 394 394 394 394 394 394 394 394 394 394 394
Average Annual Contract Capacity (MW) 404 404 404 404 404 404 404 404 404 404 404
Average Annual Other Capacity (MW) 0 0 0 0 0 0 0 0 0 0 394
Capacity Factor(%)(3) 36.6% 41.5% 33.7% 38.9% 40.5% 40.5% 37.2% 35.8% 33.6% 31.1% 30.0%
Energy Generation (GWh) 315 1,433 1,162 1,343 1,399 1,398 1,283 1,236 1,159 1,074 1,036
Contract Energy Sales (GWh) 330 1,534 1,244 1,438 1,497 1,497 1,373 1,323 1,241 1,150 925
Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 0 0 0 0 0 112
Net Heat Rate (Btu/kWh)(5) 7,866 7,750 7,914 7,853 7,827 7,832 7,934 8,020 8,011 8,070 8,086
Contract Fuel Consumption (BBtu) 2,481 11,108 9,197 10,550 10,947 10,950 10,177 9,911 9,287 8,669 7,476
Other Fuel Consumption (BBtu) 0 0 0 0 0 0 0 0 0 0 904
SO(2) Allowances Purchased (Tons)(6) 1 6 5 5 5 5 5 5 5 4 4
NO(X) Allowances Purchased (Tons)(7) 0 0 0 0 0 0 0 0 0 0 0
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $ 31.45 29.35 35.70 31.48 30.38 30.62 33.55 35.19 37.45 40.53 42.74
Other Electricity
Capacity ($/kW-yr) $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 7.83
Energy ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 59.97
Fuel ($/MMBtu)(12) $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 4.65
SO(2) Allowances ($/Ton)(13) $ 150 154 158 162 166 171 175 180 184 189 194
NO(X) Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues $10,374 45,040 44,420 45,276 45,484 45,836 46,076 46,560 46,476 46,609 39,515
Other Electricity Revenues
Capacity Revenues $ 0 0 0 0 0 0 0 0 0 0 3,086
Energy Revenues $ 0 0 0 0 0 0 0 0 0 0 6,704
------- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Revenues $10,374 45,040 44,420 45,276 45,484 45,836 46,076 46,560 46,476 46,609 49,305
OPERATING EXPENSES ($000)(16)
Fuel Costs $ 0 0 0 0 0 0 0 0 0 0 5,867
Purchased Power $ 769 5,142 4,309 4,772 4,992 5,205 4,894 4,799 4,645 4,516 0
Operating and Maintenance $ 1,627 7,128 6,515 7,216 7,573 7,765 7,631 7,640 7,598 7,462 7,520
Administrative and General $ 588 2,379 2,409 2,439 2,470 2,502 2,535 2,568 2,602 2,637 2,674
------- ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Expenses $ 3,694 17,869 15,967 17,608 18,417 18,936 18,388 18,276 18,033 17,636 19,064
NET OPERATING REVENUES ($000) $ 7,390 30,392 31,187 30,848 30,450 30,364 31,015 31,553 31,631 31,994 33,244
A-57
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
- ------------------------ ------- ------ ------ ------ ------ ------ ------ ------ ------ ------
STANTON FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 394 394 394 394 394 394 394 394 394 394
Average Annual Contract Capacity (MW) 404 0 0 0 0 0 0 0 0 0
Average Annual Other Capacity (MW) 394 394 394 394 394 394 394 394 394 394
Capacity Factor (%)(3) 26.6% 26.1% 25.1% 23.7% 23.0% 20.4% 20.5% 18.8% 18.7% 18.7%
Energy Generation (GWh) 919 900 867 819 792 704 706 650 647 647
Contract Energy Sales (GWh) 0 0 0 0 0 0 0 0 0 0
Other Energy Sales (Purchases)(GWh) 919 900 867 819 792 704 706 650 647 647
Net Heat Rate (Btu/kWh)(5) 8,183 8,164 8,244 8,232 8,282 8,387 8,422 8,485 8,501 8,501
Contract Fuel Consumption (BBtu) 0 0 0 0 0 0 0 0 0 0
Other Fuel Consumption (BBtu) 7,522 7,352 7,147 6,745 6,563 5,905 5,944 5,514 5,500 5,500
SO(2) Allowances Purchased (Tons)(6) 4 4 4 3 3 3 3 3 3 3
NO(X) Allowances Purchased (Tons)(7) 0 0 0 0 0 0 0 0 0 0
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) $ 74.49 79.77 84.18 85.77 87.38 89.03 90.71 92.42 94.15 96.60
Energy ($/MWh) $ 61.18 61.36 63.26 66.22 66.93 71.03 72.18 73.90 75.29 77.25
Fuel ($/MMBtu)(12) $ 4.78 4.93 5.14 5.34 5.54 5.76 6.01 6.15 6.32 6.48
SO(2) Allowances ($/Ton)(13) $ 199 204 209 215 220 226 232 238 244 251
NO(X) Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues $ 0 0 0 0 0 0 0 0 0 0
Other Electricity Revenues
Capacity Revenues $29,351 31,429 33,167 33,792 34,427 35,078 35,740 36,412 37,096 38,060
Energy Revenues $56,235 55,257 54,841 54,263 53,037 50,006 50,947 48,025 48,712 49,979
------- ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Revenues $85,586 86,686 88,008 88,055 87,464 85,084 86,687 84,437 85,808 88,039
OPERATING EXPENSES ($000)(16)
Fuel Costs $51,374 51,636 52,163 51,430 51,765 49,421 51,114 49,309 50,143 51,047
Purchased Power $ 0 0 0 0 0 0 0 0 0 0
Operating and Maintenance $ 7,322 7,456 7,516 7,518 7,840 7,628 7,810 7,814 7,977 8,185
Administrative and General $ 2,711 2,749 2,788 2,828 2,869 2,912 2,955 2,999 3,045 3,092
------- ------ ------ ------ ------ ------ ------ ------ ------ ------
Total Operating Expenses $64,218 64,688 65,293 64,535 65,463 62,717 64,688 62,877 63,954 65,184
NET OPERATING REVENUES ($000) $24,179 24,845 25,540 26,279 24,990 25,123 24,808 24,314 24,642 25,715
A-58
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
- ------------------------ ------- ------ ------ ------ ------ ------ ------ ------- ------- ------- -------
WANSLEY FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,089 1,089 1,089 1,089 1,089 1,089 1,089 1,089 1,089 1,089 1,089
Average Annual Contract Capacity (MW) 1,089 1,089 1,089 1,089 1,089 1,089 1,089 0 0 0 0
Average Annual Other Capacity (MW) 0 0 0 0 0 0 0 1,089 1,089 1,089 1,089
Capacity Factor (%)(3) 43.2% 37.8% 44.4% 49.6% 55.6% 57.5% 55.7% 55.6% 56.6% 53.9% 48.3%
Energy Generation (GWh) 2,062 3,603 4,234 4,729 5,303 5,484 5,310 5,301 5,397 5,140 4,610
Contract Energy Sales (GWh) 2,115 3,696 4,343 4,851 5,440 5,625 5,446 0 0 0 0
Other Energy Sales (Purchases)(GWh) 0 0 0 0 0 0 0 5,301 5,397 5,140 4,610
Net Heat Rate (Btu/kWh)(5) 7,734 7,676 7,637 7,557 7,414 7,423 7,435 7,434 7,341 7,434 7,490
Contract Fuel Consumption (BBtu) 15,945 27,658 32,338 35,741 39,317 40,708 39,475 0 0 0 0
Other Fuel Consumption (BBtu) 0 0 0 0 0 0 0 39,403 39,617 38,208 34,530
SO(2) Allowances Purchased (Tons)(6) 8 14 16 18 20 20 20 20 20 19 17
NO(X) Allowances Purchased (Tons)(7) 0 0 119 132 144 146 142 139 140 134 127
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $ 26.30 24.98 22.13 20.07 17.88 17.60 18.27 0.00 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 46.49 58.16 62.97 67.51
Energy ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 44.60 45.63 47.19 48.16
Fuel ($/MMBtu)(12) $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 3.98 4.10 4.23 4.35
SO(2) Allowances ($/Ton)(13) $ 150 154 158 162 166 171 175 180 184 189 194
NO(X) Allowances ($/Ton)(14) $ 0 2,000 1,700 1,744 1,790 1,836 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues $55,624 92,339 96,116 97,366 97,269 99,010 99,498 0 0 0 0
Other Electricity Revenues
Capacity Revenues $ 0 0 0 0 0 0 0 50,631 63,337 68,580 73,520
Energy Revenues $ 0 0 0 0 0 0 0 236,432 246,265 242,556 222,046
------- ------ ------ ------ ------ ------ ------ ------- ------- ------- -------
Total Operating Revenues $55,624 92,339 96,116 97,366 97,269 99,010 99,498 287,063 309,602 311,136 295,566
OPERATING EXPENSES ($000)(16)
Fuel Costs $ 0 0 0 0 0 0 0 176,261 182,099 180,998 169,780
Purchased Power $ 2,760 4,328 4,918 5,286 5,778 6,206 6,155 0 0 0 0
Operating and Maintenance $ 8,880 17,335 19,416 21,396 24,762 25,988 26,471 27,499 28,904 28,554 27,450
Administrative and General $ 1,705 3,490 3,571 3,654 3,740 3,828 3,918 4,011 4,105 4,203 4,302
------- ------ ------ ------ ------ ------ ------ ------- ------- ------- -------
Total Operating Expenses $17,816 33,717 37,976 41,864 48,585 51,172 51,999 223,972 232,358 230,520 217,240
NET OPERATING REVENUES ($000) $42,279 67,186 68,211 67,030 62,989 62,988 62,954 79,292 94,494 97,380 94,033
A-59
EXHIBIT A-1
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
BASE CASE
Year Ending December 31, 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
- ------------------------- -------- ------- ------- ------- ------- ------- ------- ------- ------- -------
WANSLEY FACILITY
PERFORMANCE
Average Annual Capacity (MW)(2) 1,089 1,089 1,089 1,089 1,089 1,089 1,089 1,089 1,089 1,089
Average Annual Contract Capacity (MW) 0 0 0 0 0 0 0 0 0 0
Average Annual Other Capacity (MW) 1,089 1,089 1,089 1,089 1,089 1,089 1,089 1,089 1,089 1,089
Capacity Factor (%)(3) 44.1% 42.9% 37.5% 35.4% 32.2% 29.6% 27.8% 26.5% 25.4% 25.4%
Energy Generation (GWh) 4,212 4,094 3,578 3,379 3,075 2,821 2,656 2,527 2,419 2,419
Contract Energy Sales (GWh) 0 0 0 0 0 0 0 0 0 0
Other Energy Sales (Purchases)(GWh) 4,212 4,094 3,578 3,379 3,075 2,821 2,656 2,527 2,419 2,419
Net Heat Rate (Btu/kWh)(5) 7,575 7,584 7,698 7,736 7,801 7,819 7,902 7,948 7,933 7,933
Contract Fuel Consumption (BBtu) 0 0 0 0 0 0 0 0 0 0
Other Fuel Consumption (BBtu) 31,904 31,050 27,542 26,137 23,991 22,062 20,990 20,081 19,191 19,191
SO(2) Allowances Purchased (Tons)(6) 16 16 14 13 12 11 10 10 10 10
NO(X) Allowances Purchased (Tons)(7) 117 111 94 90 84 80 77 72 74 74
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity ($/MWh) $ 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00
Other Electricity
Capacity ($/kW-yr) $ 67.11 70.80 73.36 74.99 78.33 82.55 84.44 87.40 89.01 91.32
Energy ($/MWh) $ 49.74 49.88 52.28 55.14 56.99 60.38 62.47 64.09 65.16 66.86
Fuel ($/MMBtu)(12) $ 4.48 4.62 4.81 5.01 5.23 5.44 5.67 5.81 5.94 6.09
SO(2) Allowances ($/Ton)(13) $ 199 204 209 215 220 226 232 238 244 251
NO(X) Allowances ($/Ton)(14) $ 2,142 2,197 2,255 2,313 2,373 2,435 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues $ 0 0 0 0 0 0 0 0 0 0
Other Electricity Revenues
Capacity Revenues $ 73,090 77,112 79,901 81,667 85,306 89,910 91,964 95,192 96,939 99,459
Energy Revenues $209,492 204,217 187,072 186,280 175,249 170,365 165,960 161,941 157,628 161,727
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Revenues $282,582 281,329 266,973 267,947 260,555 260,275 257,924 257,133 254,567 261,186
OPERATING EXPENSES ($000)(16)
Fuel Costs $162,611 162,635 149,621 146,902 140,054 134,564 133,575 131,388 128,651 131,615
Purchased Power $ 0 0 0 0 0 0 0 0 0 0
Operating and Maintenance $ 26,558 26,924 25,520 25,389 24,855 24,260 24,231 24,283 24,456 25,092
Administrative and General $ 4,404 4,510 4,618 4,728 4,842 4,958 5,077 5,200 5,326 5,455
-------- ------- ------- ------- ------- ------- ------- ------- ------- -------
Total Operating Expenses $208,358 208,993 193,339 190,306 182,419 175,737 174,618 172,439 169,934 173,960
NET OPERATING REVENUES ($000) $ 89,008 87,260 87,215 90,928 90,805 96,493 95,042 96,262 96,134 99,024
A-60
FOOTNOTES TO EXHIBIT A-1
1. Represents six months for the year 2003.
2. Represents annual average capacity for the Generating Facilities,
including allowance for degradation. Reflects three months of operation
of the Stanton Facility in 2003 and seven months of operation of the
McIntosh Facility in 2005.
3. Represents annual weighted average capacity factors of the Generating
Facilities as projected by PA Consulting.
4. Energy sales both contractual and other are as projected by PA
Consulting. Other sales assumed to be representative of long-term
contracts Southern Power expects to enter into upon expiration of the
PPAs.
5. Weighted average annual heat rate calculated as the sum of total fuel
consumed by the Generating Facilities divided by the energy generated
by the Generating Facilities, as projected by PA Consulting.
6. SO(2) allowances that Southern Power will have to purchase or can sell
based on emission rates as provided by Southern Power and dispatch as
projected by PA Consulting. During the term of the PPAs, we have
assumed that any shortfall in emissions would be provided by the buyer
of the generation. Upon expiration of the PPAs, we have assumed that
Southern Power will purchase any allowances required or sell any excess
allowances.
7. NO(X) allowances that Southern Power will have to purchase or have the
ability to sell based on emission rates as provided by Southern Power
and dispatch as projected by PA Consulting. During the terms of the
PPAs, we have assumed that any shortfall in emissions would be provided
by the buyer of the generation. Upon expiration of the PPAs, we have
assumed that Southern Power will purchase any allowances required or
sell any excess allowances.
8. Rate of change in general inflation and various inflation related
escalators assumed to be 2.6 percent per year for the term of the Debt,
based on the March 10, 2003 projection prepared by Blue Chip Economic
Indicators.
9. Average contract electricity price calculated as the sum of the
electricity revenues under the PPAs divided by the total annual
contractual energy from the various PPAs.
10. Average other capacity and energy price calculated as the sum of the
other electricity revenues of the Generating Facilities divided by the
total energy or capacity sold as projected by PA Consulting in 2001
dollars and adjusted for inflation. Assumed to be equivalent to the
price of long-term contracts to be entered into by Southern Power upon
expiration of the PPAs. Shown as zero in years during which there are
no other capacity or energy sales.
11. Weighted average of fuel prices for the Generating Facilities
calculated as sum of the fuel expenses divided by the total fuel
consumed by the Generating Facilities as projected by PA Consulting in
2001 dollars and adjusted for inflation. Shown as zero in years during
which there are no fuel purchases.
12. Assumed to be $150 per ton in 2003 escalating thereafter at the assumed
rate of inflation.
13. Assumed to be $2,000 per ton in 2004, $1,700 per ton in 2005, and
escalating thereafter at the assumed rate of inflation.
14. Assumes contract sales to third parties in 2003 as reported by Southern
Power for the Franklin Facility prior to commencement of the Franklin
PPA and market energy sales as estimated by PA Consulting for Harris 2
prior to the commencement of the Harris 2 PPA.
15. In order to maximize the capacity payments under the PPAs, Southern
Power has indicated that it will provide replacement energy from
alternate sources. Purchases power has been assumed to be available at
the market prices projected by PA Consulting.
16. Operating and maintenance includes fixed and variable operations and
maintenance expense, the cost of emissions allowances, balance of plant
major maintenance costs, and LTSA expenses. These expenses have been
estimated by Southern Power and have been assumed to escalate at the
rate of inflation.
17. Administrative and general expenses include administrative expense,
insurance costs, property taxes and other costs. These expenses have
been estimated by Southern Power and have been assumed to escalate at
the rate of inflation.
18. [Redacted]
19. [Redacted]
20. [Redacted]
A-60
EXHIBIT A-2 SENSITIVITY A - LOW GAS MARKET PRICE SCENARIO
A-61
Exhibit A-2
Southern Power Company, Inc. Facilities
Projected Operating Results
Sensitivity A - Low Fuel Market Price Scenario
Year Ending
December 31, 2003(1) 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
-------- -------- ------- ------- ------- ------- ------- ------- --------- --------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average
Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802 5,802 5,802 5,802 5,802 5,802
Average Capacity
Factor (%)(3) 31.8% 32.9% 34.7% 43.0% 50.0% 51.0% 49.5% 48.4% 49.6% 46.2% 41.8%
Contract Energy
Sales (GWh)(4) 6,054 12,753 18,124 22,369 25,987 26,437 25,644 14,872 11,781 10,016 8,860
Other Energy
Sales (GWh)(4) 1,130 836 0 27 40 90 109 10,047 13,672 13,669 12,512
-------- -------- ------- ------- ------- ------- ------- ------- --------- --------- ---------
Total Energy
Sales (GWh) 7,184 13,589 18,124 22,396 26,027 26,527 25,753 24,919 25,453 23,685 21,371
Fuel
Consumption (BBtu) 49,603 101,938 134,077 165,254 187,783 191,932 186,593 182,980 186,449 174,575 160,355
Average Net Heat
Rate (Btu/kWh)(5) 7,711 7,672 7,600 7,557 7,389 7,408 7,418 7,433 7,395 7,440 7,545
SO(2) Allowances
Purchased (Tons)(6) 25 52 67 82 94 96 95 93 93 88 81
NO(X) Allowances
Purchased (Tons)(7) 0 (42) 225 292 369 381 355 344 353 320 279
COMMODITY PRICES
General
Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity
Price ($/MWh)(9) $ 33.32 30.94 26.46 23.26 19.50 19.47 20.05 21.91 21.36 23.08 26.66
Other Capacity
Price ($/MWh)(10) $ 16.91 19.42 16.99 17.40 17.17 19.58 39.76 46.38 58.63 64.47 66.77
Other Energy
Price ($/MWh)(10) $ 47.49 43.43 0.00 59.55 54.10 59.11 61.14 40.75 41.96 43.50 45.36
Fuel
Price ($/MMBtu)(11) $ 4.84 4.40 0.00 3.33 3.17 3.27 3.37 3.95 4.08 4.22 4.40
SO(2) Allowances
($/Ton)(12) $ 150 154 158 162 166 171 175 180 184 189 194
NO(X) Allowances
($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836 1,884 1,933 1,983 2,035 2,088
OPERATING
REVENUES ($000)
Contract
Electricity Revenues
Dahlberg $ 16,642 34,138 0 0 0 0 0 0 0 0 0
Franklin (14) $ 82,732 109,109 115,884 120,185 120,739 123,521 122,092 80,069 22,896 0 0
Harris (14) $ 36,278 114,049 139,098 141,041 133,219 135,058 134,504 86,468 69,543 69,333 72,923
McIntosh $ 0 0 85,224 118,096 111,889 113,347 113,135 112,887 112,308 115,168 123,656
Stanton $ 10,373 44,575 44,330 45,062 45,012 45,414 46,213 46,471 46,868 46,634 39,616
Wansley $ 55,671 92,742 95,085 95,959 95,871 97,265 98,288 0 0 0 0
Other
Electricity Revenues
Dahlberg $ 2,220 4,643 13,540 15,463 15,835 20,952 38,374 44,743 57,071 59,057 59,317
Franklin (14) $ 3,126 12,173 0 0 0 0 0 84,793 232,181 280,814 274,594
Harris $ 57,542 29,372 0 0 0 0 0 107,005 171,364 167,391 166,149
McIntosh $ 0 0 0 0 0 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0 0 0 0 0 9,915
Wansley $ 0 0 0 0 0 0 0 296,542 314,689 321,254 302,982
-------- -------- ------- ------- ------- ------- ------- ------- --------- --------- ---------
Total Operating
Revenues $264,584 440,801 493,161 535,806 522,565 535,557 552,606 858,978 1,026,920 1,059,651 1,049,152
OPERATING
EXPENSES ($000)
Fuel
Dahlberg $ 33 0 0 1,169 1,641 3,852 4,787 5,832 7,605 5,568 4,224
Franklin $ 1,236 8,103 0 0 0 0 0 47,471 124,826 148,146 143,651
Harris $ 41,244 20,381 0 0 0 0 0 62,360 97,978 92,810 92,031
McIntosh $ 0 0 0 0 0 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0 0 0 0 0 5,853
Wansley $ 0 0 0 0 0 0 0 177,437 181,835 182,555 169,083
Purchased Power (15) $ 39,344 13,039 20,417 21,329 23,977 25,653 25,217 13,499 10,958 10,453 5,389
Operations
& Maintenance (16) $ 33,305 64,562 82,086 98,189 111,764 118,231 120,453 125,129 129,666 126,028 124,883
Administration
and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873 33,364 33,872 34,386 34,924 35,465
-------- -------- ------- ------- ------- ------- ------- ------- --------- --------- ---------
Total Operating
Expenses $127,891 133,050 132,237 152,608 169,773 180,609 183,821 465,601 587,255 600,484 580,579
NET OPERATING
REVENUES ($000) $136,693 307,750 360,923 383,198 352,792 354,948 368,785 393,378 439,665 459,167 468,574
ANNUAL
INTEREST($000)(18) $ 36,531 73,063 87,463 101,863 101,863 101,863 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST
COVERAGE (19) 3.74 4.21 4.13 3.76 3.46 3.48 3.62 3.86 4.32 4.51 4.60
2003-15 AVG INTEREST
COVERAGE (20) 4.05
A-62
Exhibit A-2
Southern Power Company, Inc. Facilities
Projected Operating Results
Sensitivity A - Low Fuel Market Price Scenario
Year Ending
December 31, 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
- ----------------- ---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average
Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802 5,802 5,802 5,802 5,802
Average Capacity
Factor (%)(3) 38.9% 36.2% 32.1% 30.0% 28.5% 26.4% 24.1% 22.6% 21.5% 21.5%
Contract Energy
Sales (GWh)(4) 7,522 6,962 6,157 5,773 5,552 4,049 629 0 0 0
Other Energy
Sales (GWh)(4) 12,372 11,527 10,266 9,555 9,022 9,379 11,641 11,487 10,919 10,919
Total Energy
Sales (GWh) 19,893 18,489 16,423 15,328 14,574 13,428 12,270 11,487 10,919 10,919
Fuel
Consumption (BBtu) 149,925 140,040 126,140 118,353 113,040 104,994 96,881 91,272 86,883 86,883
Average Net Heat
Rate (Btu/kWh)(5) 7,580 7,618 7,726 7,766 7,802 7,840 7,896 7,945 7,957 7,957
SO(2) Allowances
Purchased (Tons)(6) 73 69 63 59 57 53 48 46 43 43
NO(X) Allowances
Purchased (Tons)(7) 245 212 164 130 114 103 64 57 47 47
COMMODITY PRICES
General
Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity
Price ($/MWh)(9) $ 26.78 28.92 34.69 36.93 39.66 40.25 44.69 0.00 0.00 0.00
Other Capacity
Price ($/MWh)(10) $ 68.74 72.86 74.82 77.65 82.06 84.68 86.16 87.74 89.36 91.68
Other Energy
Price ($/MWh)(10) $ 47.20 47.65 50.43 51.73 53.21 55.74 57.69 59.33 60.43 62.00
Fuel Price
($/MMBtu)(11) $ 4.69 4.86 5.10 5.31 5.46 5.67 5.89 6.07 6.24 6.37
SO(2) Allowances
($/Ton)(12) $ 199 204 209 215 220 226 232 238 244 251
NO(X) Allowances
($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435 2,498 2,563 2,630 2,698
OPERATING
REVENUES ($000)
Contract Electricity
Revenues
Dahlberg $ 0 0 0 0 0 0 0 0 0 0
Franklin (14) $ 0 0 0 0 0 0 0 0 0 0
Harris (14) $ 72,345 73,483 75,455 74,414 76,660 16,401 0 0 0 0
McIntosh $ 129,106 127,834 138,116 138,806 143,554 146,579 28,102 0 0 0
Stanton $ 0 0 0 0 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0 0 0 0 0
Other Electricity
Revenues
Dahlberg $ 57,896 59,465 60,736 61,843 64,942 67,709 69,103 69,683 70,940 72,784
Franklin (14) $ 262,420 250,941 239,089 230,686 231,792 230,042 215,531 220,156 202,691 207,961
Harris $ 159,844 158,443 153,603 150,128 153,100 245,144 292,093 285,628 287,713 295,192
McIntosh $ 0 0 0 0 0 0 221,487 276,155 267,296 274,246
Stanton $ 88,411 86,524 89,755 91,538 88,806 88,640 88,566 86,042 88,643 90,947
Wansley $ 291,865 286,945 275,388 272,348 271,391 266,018 264,221 252,991 260,978 267,763
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating
Revenues $1,061,887 1,043,635 1,032,142 1,019,763 1,030,245 1,060,533 1,179,103 1,190,655 1,178,261 1,208,893
OPERATING
EXPENSES ($000)
Fuel
Dahlberg $ 2,215 1,341 1,297 458 0 401 471 20 0 0
Franklin $ 135,391 128,282 119,272 113,497 108,708 104,220 93,729 96,113 82,574 84,261
Harris $ 88,410 88,622 84,287 83,324 82,547 126,063 150,243 145,923 146,140 149,455
McIntosh $ 0 0 0 0 0 0 112,354 137,421 132,151 135,100
Stanton $ 52,874 50,261 51,676 52,439 51,357 50,984 50,537 48,789 50,359 51,268
Wansley $ 162,937 160,016 148,545 145,328 142,477 135,835 134,330 125,305 130,498 133,510
Purchased Power (15) $ 5,303 5,003 4,705 4,439 4,423 1,976 0 0 0 0
Operations
& Maintenance (16) $ 118,504 115,360 111,908 110,260 114,456 124,837 106,269 105,320 106,268 109,258
Administration
and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052 39,705 40,375 41,060 41,768
---------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
Total Operating
Expenses $ 601,656 585,487 558,876 547,537 542,385 583,369 687,637 699,265 689,049 704,619
NET OPERATING
REVENUES ($000) $ 460,231 458,148 473,266 472,226 487,860 477,164 491,466 491,390 489,212 504,274
ANNUAL INTEREST
($000)(18)YV $ 101,863 101,863 101,863 101,863 101,863 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST
COVERAGE (19) 4.52 4.50 4.65 4.64 4.79 4.68 4.82 4.82 4.80 4.95
2003-15 AVG INTEREST
COVERAGE (20) 4.05
A-63
FOOTNOTES TO EXHIBIT A-2
The footnotes to Exhibit A-2 are the same as the footnotes for Exhibit A-1,
except:
3. Capacity factor as estimated by PA Consulting under its "Low Gas Price"
scenario.
10. As estimated by PA Consulting in its "Low Gas Price" scenario.
11. As estimated by PA Consulting in its "Low Gas Price" scenario.
A-63
EXHIBIT A-3 SENSITIVITY B - HIGH GAS MARKET PRICE SCENARIO
A-64
EXHIBIT A-3
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
SENSITIVITY B - HIGH FUEL MARKET PRICE SCENARIO
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008
---------- ---------- ---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 31.0% 27.7% 29.2% 35.8% 40.7% 41.9%
Contract Energy Sales (GWh)(4) 5,894 10,729 15,261 18,639 21,180 21,761
Other Energy Sales (GWh)(4) 1,103 721 0 1 25 54
---------- ---------- ---------- ---------- ---------- ----------
Total Energy Sales (GWh) 6,997 11,450 15,261 18,640 21,205 21,815
Fuel Consumption (BBtu) 48,291 87,948 115,730 141,456 158,669 163,034
Average Net Heat Rate (Btu/kWh)(5) 7,709 7,858 7,792 7,774 7,664 7,654
SO2 Allowances Purchased (Tons)(6) 24 44 57 70 78 81
NOX Allowances Purchased (Tons)(7) 0 (87) 114 168 253 272
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 35.23 37.11 32.25 29.42 25.85 25.45
Other Capacity Price ($/MWh)(10) $ 16.91 18.77 16.99 19.28 16.95 18.85
Other Energy Price ($/MWh)(10) $ 58.07 54.29 0.00 77.43 74.45 74.66
Fuel Price ($/MMBtu)(11) $ 5.95 5.52 0.00 4.17 3.98 4.10
SO2 Allowances ($/Ton)(12) $ 150 154 158 162 166 171
NOX Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 16,638 34,138 0 0 0 0
Franklin (14) $ 88,652 108,851 115,376 120,985 124,041 123,701
Harris (14) $ 36,148 116,316 145,693 149,122 147,086 148,231
McIntosh $ 0 0 90,332 135,335 132,400 135,677
Stanton $ 10,466 45,636 44,902 45,339 45,838 46,278
Wansley $ 55,734 93,179 95,904 97,532 98,104 99,920
Other Electricity Revenues
Dahlberg $ 2,235 4,488 13,540 15,479 15,377 19,089
Franklin (14) $ 3,546 13,062 0 0 0 0
Harris $ 67,478 31,120 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Revenues $ 280,897 446,790 505,747 563,792 562,846 572,896
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 42 0 0 75 1,295 2,910
Franklin $ 1,570 9,041 0 0 0 0
Harris $ 49,304 22,259 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
Purchased Power (15) $ 46,792 14,027 21,668 22,810 25,324 27,175
Operations & Maintenance (16) $ 33,001 58,717 74,736 87,203 97,949 103,330
Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Expenses $ 143,439 131,010 126,138 142,009 156,959 166,288
NET OPERATING REVENUES ($000) $ 137,458 315,780 379,609 421,784 405,887 406,609
ANNUAL INTEREST($000)(18) $ 36,531 73,063 87,463 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.76 4.32 4.34 4.14 3.98 3.99
2003-15 AVG INTEREST COVERAGE (20) 4.28
Year Ending December 31, 2009 2010 2011 2012 2013
--------- ---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 41.0% 37.5% 38.4% 36.4% 33.5%
Contract Energy Sales (GWh)(4) 21,255 11,821 9,189 8,141 7,330
Other Energy Sales (GWh)(4) 74 7,460 10,531 10,533 9,785
--------- ---------- ---------- ---------- ----------
Total Energy Sales (GWh) 21,329 19,281 19,719 18,674 17,115
Fuel Consumption (BBtu) 159,541 146,825 149,868 142,032 131,940
Average Net Heat Rate (Btu/kWh)(5) 7,658 7,712 7,674 7,681 7,753
SO2 Allowances Purchased (Tons)(6) 80 74 74 69 65
NOX Allowances Purchased (Tons)(7) 252 198 219 201 167
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 25.94 30.01 31.36 31.32 35.39
Other Capacity Price ($/MWh)(10) 29.83 45.82 54.61 60.52 64.84
Other Energy Price ($/MWh)(10) 85.76 51.60 53.06 54.50 55.68
Fuel Price ($/MMBtu)(11) 4.23 5.04 5.18 5.37 5.59
SO2 Allowances ($/Ton)(12) 175 180 184 189 194
NOX Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0
Franklin (14) 125,333 81,771 26,446 0 0
Harris (14) 148,570 91,202 76,143 75,343 75,602
McIntosh 131,497 135,112 139,245 132,778 144,149
Stanton 46,137 46,647 46,310 46,840 39,657
Wansley 99,767 0 0 0 0
Other Electricity Revenues
Dahlberg 30,104 37,549 49,907 51,355 53,722
Franklin (14) 0 81,608 223,846 267,121 255,957
Harris 0 107,545 166,117 166,614 165,580
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 10,080
Wansley 0 280,465 306,660 308,552 296,429
--------- ---------- ---------- ---------- ----------
Total Operating Revenues 581,408 861,899 1,034,674 1,048,603 1,041,176
OPERATING EXPENSES ($000)
Fuel
Dahlberg 4,080 775 4,877 2,218 1,485
Franklin 0 47,895 127,085 148,523 140,527
Harris 0 65,428 99,828 98,965 98,558
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 6,220
Wansley 0 173,932 186,007 184,902 176,282
Purchased Power (15) 26,832 13,433 10,735 10,604 5,431
Operations & Maintenance (16) 105,517 100,656 107,448 105,392 105,518
Administration and General (17) 33,364 33,872 34,386 34,924 35,465
--------- ---------- ---------- ---------- ----------
Total Operating Expenses 169,793 435,991 570,366 585,529 569,487
NET OPERATING REVENUES ($000) 411,615 425,908 464,308 463,073 471,689
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.04 4.18 4.56 4.55 4.63
2003-15 AVG INTEREST COVERAGE (20)
A-65
EXHIBIT A-3
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
SENSITIVITY B - HIGH FUEL MARKET PRICE SCENARIO
Year Ending December 31, 2014 2015 2016 2017 2018 2019
------- ---------- ---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 29.9% 27.6% 25.7% 23.9% 21.6% 20.5%
Contract Energy Sales (GWh)(4) 5,805 5,399 5,051 4,658 4,059 3,260
Other Energy Sales (GWh)(4) 9,503 8,687 8,093 7,580 6,978 7,191
------- ---------- ---------- ---------- ---------- ----------
Total Energy Sales (GWh) 15,308 14,086 13,144 12,238 11,037 10,451
Fuel Consumption (BBtu) 118,813 109,707 102,992 96,274 87,163 83,229
Average Net Heat Rate (Btu/kWh)(5) 7,806 7,835 7,883 7,913 7,943 7,986
SO2 Allowances Purchased (Tons)(6) 60 56 51 48 43 42
NOX Allowances Purchased (Tons)(7) 135 96 74 53 43 34
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 37.70 40.75 43.70 46.76 51.17 49.85
Other Capacity Price ($/MWh)(10) 67.86 68.95 71.80 74.57 77.90 78.67
Other Energy Price ($/MWh)(10) 57.81 59.38 61.10 63.25 65.69 69.89
Fuel Price ($/MMBtu)(11) 5.97 6.20 6.47 6.73 6.94 7.20
SO2 Allowances ($/Ton)(12) 199 204 209 215 220 226
NOX Allowances ($/Ton)(13) 2,142 2,197 2,255 2,313 2,373 2,435
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0 0
Franklin (14) 0 0 0 0 0 0
Harris (14) 76,189 75,949 75,626 74,376 73,063 16,026
McIntosh 142,671 144,038 145,113 143,433 134,634 146,494
Stanton 0 0 0 0 0 0
Wansley 0 0 0 0 0 0
Other Electricity Revenues
Dahlberg 54,445 54,216 56,270 58,466 61,268 61,924
Franklin (14) 246,117 230,727 227,466 217,254 214,230 212,743
Harris 152,410 151,244 148,916 146,806 145,134 238,972
McIntosh 0 0 0 0 0 0
Stanton 86,925 84,675 88,791 90,137 88,963 87,973
Wansley 282,383 272,278 261,721 266,698 262,088 249,231
------- ---------- ---------- ---------- ---------- ----------
Total Operating Revenues 041,140 1,013,127 1,003,903 997,170 979,380 1,013,363
OPERATING EXPENSES ($000)
Fuel
Dahlberg 746 0 0 0 0 0
Franklin 133,598 122,154 121,291 112,592 104,903 99,715
Harris 88,494 89,336 87,480 86,349 81,038 131,056
McIntosh 0 0 0 0 0 0
Stanton 53,255 51,458 54,236 54,288 54,338 52,517
Wansley 167,421 160,026 150,449 151,467 145,107 131,777
Purchased Power (15) 5,023 4,871 4,659 4,450 4,102 1,976
Operations & Maintenance (16) 100,460 98,045 102,019 97,914 96,443 95,782
Administration and General (17) 36,022 36,601 37,186 37,792 38,416 39,052
------- ---------- ---------- ---------- ---------- ----------
Total Operating Expenses 585,019 562,492 557,319 544,852 524,348 551,875
NET OPERATING REVENUES ($000) 456,121 450,635 446,584 452,318 455,032 461,488
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.48 4.42 4.38 4.44 4.47 4.53
2003-15 AVG INTEREST COVERAGE (20) 4.28
Year Ending December 31, 2020 2021 2022 2023
--------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 18.6% 17.4% 16.0% 16.0%
Contract Energy Sales (GWh)(4) 472 0 0 0
Other Energy Sales (GWh)(4) 8,986 8,819 8,145 8,145
--------- ---------- ---------- ----------
Total Energy Sales (GWh) 9,458 8,819 8,145 8,145
Fuel Consumption (BBtu) 75,749 70,859 65,626 65,626
Average Net Heat Rate (Btu/kWh)(5) 8,009 8,035 8,058 8,058
SO2 Allowances Purchased (Tons)(6) 38 36 33 33
NOX Allowances Purchased (Tons)(7) 11 2 (10) (10)
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 56.53 0.00 0.00 0.00
Other Capacity Price ($/MWh)(10) 80.18 86.61 89.36 91.68
Other Energy Price ($/MWh)(10) 72.01 73.29 75.12 77.07
Fuel Price ($/MMBtu)(11) 7.49 7.72 7.96 8.13
SO2 Allowances ($/Ton)(12) 232 238 244 251
NOX Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0
Franklin (14) 0 0 0 0
Harris (14) 0 0 0 0
McIntosh 26,677 0 0 0
Stanton 0 0 0 0
Wansley 0 0 0 0
Other Electricity Revenues
Dahlberg 63,288 68,689 70,940 72,784
Franklin (14) 196,652 204,281 186,701 191,555
Harris 288,563 276,406 282,400 289,741
McIntosh 207,099 271,060 257,909 264,615
Stanton 89,150 85,329 88,197 90,489
Wansley 248,571 243,037 244,102 250,448
--------- ---------- ---------- ----------
Total Operating Revenues 1,120,000 1,148,802 1,130,249 1,159,632
OPERATING EXPENSES ($000)
Fuel
Dahlberg 0 0 0 0
Franklin 88,464 88,534 74,531 76,009
Harris 157,176 145,028 146,093 149,407
McIntosh 108,944 139,304 128,723 131,583
Stanton 53,241 50,540 52,658 53,626
Wansley 131,272 123,315 120,472 123,224
Purchased Power (15) 0 0 0 0
Operations & Maintenance (16) 95,380 94,632 99,557 97,427
Administration and General (17) 39,705 40,375 41,060 41,768
--------- ---------- ---------- ----------
Total Operating Expenses 674,182 681,728 663,093 673,044
NET OPERATING REVENUES ($000) 445,818 467,074 467,156 486,588
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.38 4.59 4.59 4.78
2003-15 AVG INTEREST COVERAGE (20)
A-66
FOOTNOTES TO EXHIBIT A-3
The footnotes to Exhibit A-3 are the same as the footnotes for Exhibit A-1,
except:
3. Capacity factor as estimated by PA Consulting under its "High Gas Price"
scenario.
10. As estimated by PA Consulting in its "High Gas Price" scenario.
11. As estimated by PA Consulting in its "High Gas Price" scenario.
A-67
EXHIBIT A-4 SENSITIVITY C - CAPACITY OVERBUILD MARKET PRICE SCENARIO
A-68
EXHIBIT A-4
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
SENSITIVITY C - OVERBUILD PRICE SCENARIO
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008
---------- ---------- ---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 31.3% 29.5% 31.1% 38.8% 43.9% 38.4%
Contract Energy Sales (GWh)(4) 5,943 11,442 16,215 20,208 22,807 19,959
Other Energy Sales (GWh)(4) 1,116 765 0 0 37 7
---------- ---------- ---------- ---------- ---------- ----------
Total Energy Sales (GWh) 7,059 12,207 16,215 20,208 22,844 19,966
Fuel Consumption (BBtu) 48,697 92,948 122,228 151,604 168,896 148,972
Average Net Heat Rate (Btu/kWh)(5) 7,710 7,788 7,741 7,683 7,572 7,642
SO2 Allowances Purchased (Tons)(6) 24 47 61 76 83 74
NOX Allowances Purchased (Tons)(7) 0 (70) 163 225 291 244
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 34.44 34.72 30.16 26.72 23.45 26.70
Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.63 16.96 17.35
Other Energy Price ($/MWh)(10) $ 52.82 48.71 0.00 0.00 66.66 65.93
Fuel Price ($/MMBtu)(11) $ 5.40 4.96 0.00 0.00 3.58 3.68
SO2 Allowances ($/Ton)(12) $ 150 154 158 162 166 171
NOX Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 16,645 34,138 0 0 0 0
Franklin (14) $ 85,818 109,905 116,864 121,833 123,023 120,315
Harris (14) $ 36,235 115,862 145,327 147,411 144,218 145,291
McIntosh $ 0 0 86,915 129,170 125,233 123,445
Stanton $ 10,374 45,040 43,968 44,901 45,538 45,653
Wansley $ 55,624 92,339 95,909 96,611 96,728 98,123
Other Electricity Revenues
Dahlberg $ 2,223 4,429 13,540 14,054 15,955 14,280
Franklin (14) $ 3,222 12,310 0 0 0 0
Harris $ 62,689 29,934 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Revenues $ 272,830 443,957 502,523 553,980 550,695 547,107
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 38 0 0 0 1,703 320
Franklin $ 1,318 8,423 0 0 0 0
Harris $ 45,315 21,309 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
Purchased Power (15) $ 43,081 13,258 19,993 21,630 24,257 21,294
Operations & Maintenance (16) $ 33,111 60,848 76,502 91,134 102,869 96,902
Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Expenses $ 135,592 130,804 126,229 144,685 161,220 151,389
NET OPERATING REVENUES ($000) $ 137,238 313,154 376,294 409,295 389,474 395,718
ANNUAL INTEREST($000)(18) $ 36,531 73,063 87,463 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.76 4.29 4.30 4.02 3.82 3.88
2003-15 AVG INTEREST COVERAGE (20) 4.18
Year Ending December 31, 2009 2010 2011 2012 2013
---------- ---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 40.5% 40.7% 42.0% 40.5% 36.6%
Contract Energy Sales (GWh)(4) 21,060 12,696 10,076 8,979 7,888
Other Energy Sales (GWh)(4) 43 8,226 11,463 11,822 10,837
---------- ---------- ---------- ---------- ----------
Total Energy Sales (GWh) 21,102 20,921 21,538 20,801 18,725
Fuel Consumption (BBtu) 156,836 157,496 161,511 156,240 142,566
Average Net Heat Rate (Btu/kWh)(5) 7,611 7,623 7,573 7,584 7,657
SO2 Allowances Purchased (Tons)(6) 78 79 81 78 70
NOX Allowances Purchased (Tons)(7) 253 249 265 254 210
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 25.41 27.18 27.25 27.68 31.60
Other Capacity Price ($/MWh)(10) 17.85 38.56 52.83 59.99 64.27
Other Energy Price ($/MWh)(10) 69.99 46.54 47.88 49.26 50.52
Fuel Price ($/MMBtu)(11) 3.80 4.51 4.64 4.80 5.00
SO2 Allowances ($/Ton)(12) 175 180 184 189 194
NOX Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0
Franklin (14) 122,914 81,468 25,834 0 0
Harris (14) 141,730 89,903 74,058 74,605 74,384
McIntosh 125,711 127,005 127,834 126,963 135,346
Stanton 46,141 46,647 46,856 46,966 39,522
Wansley 98,651 0 0 0 0
Other Electricity Revenues
Dahlberg 17,215 32,898 47,667 53,336 53,927
Franklin (14) 0 79,572 219,335 270,606 259,187
Harris 0 101,590 163,069 164,372 165,570
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 10,071
Wansley 0 271,683 300,457 311,604 294,117
---------- ---------- ---------- ---------- ----------
Total Operating Revenues 552,362 830,766 1,005,110 1,048,452 1,032,124
OPERATING EXPENSES ($000)
Fuel
Dahlberg 2,104 1,728 4,033 3,958 1,881
Franklin 0 47,048 122,685 147,580 139,669
Harris 0 62,157 96,060 95,109 96,152
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 6,105
Wansley 0 169,700 179,467 182,875 170,179
Purchased Power (15) 23,555 13,267 10,842 10,639 5,323
Operations & Maintenance (16) 104,512 106,752 113,175 113,724 109,905
Administration and General (17) 33,364 33,872 34,386 34,924 35,465
---------- ---------- ---------- ---------- ----------
Total Operating Expenses 163,535 434,525 560,648 588,810 564,680
NET OPERATING REVENUES ($000) 388,827 396,241 444,462 459,642 467,444
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.82 3.89 4.36 4.51 4.59
2003-15 AVG INTEREST COVERAGE (20)
A-69
EXHIBIT A-4
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
SENSITIVITY C - OVERBUILD PRICE SCENARIO
Year Ending December 31, 2014 2015 2016 2017 2018 2019
---------- ---------- ---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 33.9% 32.4% 29.4% 27.1% 25.3% 23.9%
Contract Energy Sales (GWh)(4) 6,481 6,304 5,723 5,334 4,892 3,737
Other Energy Sales (GWh)(4) 10,835 10,245 9,282 8,539 8,056 8,425
---------- ---------- ---------- ---------- ---------- ----------
Total Energy Sales (GWh) 17,316 16,549 15,005 13,873 12,948 12,162
Fuel Consumption (BBtu) 132,821 127,318 116,328 108,217 101,615 96,084
Average Net Heat Rate (Btu/kWh)(5) 7,714 7,739 7,799 7,846 7,894 7,922
SO2 Allowances Purchased (Tons)(6) 66 64 57 54 51 48
NOX Allowances Purchased (Tons)(7) 178 152 109 89 74 61
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 33.19 34.67 38.57 41.41 45.39 45.44
Other Capacity Price ($/MWh)(10) $ 66.28 71.25 72.77 75.32 76.21 81.95
Other Energy Price ($/MWh)(10) $ 52.46 53.76 55.75 58.06 60.97 63.15
Fuel Price ($/MMBtu)(11) $ 5.32 5.51 5.76 6.01 6.18 6.41
SO2 Allowances ($/Ton)(12) $ 199 204 209 215 220 226
NOX Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 0 0 0 0 0 0
Franklin (14) $ 0 0 0 0 0 0
Harris (14) $ 75,450 77,027 75,351 75,843 76,119 16,480
McIntosh $ 139,658 141,559 145,378 145,058 145,936 153,321
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
Other Electricity Revenues
Dahlberg $ 54,403 56,996 57,404 59,126 59,776 65,654
Franklin (14) $ 251,434 244,668 235,064 223,922 227,582 226,082
Harris $ 155,698 159,658 150,527 151,764 154,296 249,581
McIntosh $ 0 0 0 0 0 0
Stanton $ 88,510 89,234 91,933 93,374 93,818 87,046
Wansley $ 284,959 286,766 275,169 270,485 262,170 266,344
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Revenues $1,050,112 1,055,908 1,030,826 1,019,572 1,019,697 1,064,508
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 1,388 494 127 0 0 420
Franklin $ 134,847 126,826 122,294 113,262 111,597 103,933
Harris $ 89,279 92,367 85,688 87,180 86,524 133,091
McIntosh $ 0 0 0 0 0 0
Stanton $ 54,357 53,416 54,924 54,679 55,105 51,633
Wansley $ 165,653 164,332 155,064 148,392 140,356 139,340
Purchased Power (15) $ 5,117 5,114 4,783 4,629 4,482 2,044
Operations & Maintenance (16) $ 107,871 110,658 105,305 103,746 103,888 103,122
Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Expenses $ 594,534 589,809 565,370 549,680 540,369 572,636
NET OPERATING REVENUES ($000) $ 455,578 466,099 465,456 469,892 479,328 491,872
ANNUAL INTEREST($000)(18) $ 101,863 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.47 4.58 4.57 4.61 4.71 4.83
2003-15 AVG INTEREST COVERAGE (20) 4.18
Year Ending December 31, 2020 2021 2022 2023
---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 21.9% 20.3% 18.9% 18.9%
Contract Energy Sales (GWh)(4) 578 0 0 0
Other Energy Sales (GWh)(4) 10,560 10,331 9,608 9,608
---------- ---------- ---------- ----------
Total Energy Sales (GWh) 11,139 10,331 9,608 9,608
Fuel Consumption (BBtu) 88,597 82,571 76,999 76,999
Average Net Heat Rate (Btu/kWh)(5) 7,954 7,993 8,014 8,014
SO2 Allowances Purchased (Tons)(6) 44 41 40 40
NOX Allowances Purchased (Tons)(7) 36 29 14 14
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 49.73 0.00 0.00 0.00
Other Capacity Price ($/MWh)(10) 83.70 87.74 89.36 91.68
Other Energy Price ($/MWh)(10) 65.07 66.58 67.56 69.32
Fuel Price ($/MMBtu)(11) 6.65 6.85 7.08 7.23
SO2 Allowances ($/Ton)(12) 232 238 244 251
NOX Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0
Franklin (14) 0 0 0 0
Harris (14) 0 0 0 0
McIntosh 28,769 0 0 0
Stanton 0 0 0 0
Wansley 0 0 0 0
Other Electricity Revenues
Dahlberg 66,598 69,810 70,940 72,784
Franklin (14) 217,435 214,425 201,267 206,499
Harris 294,043 287,085 282,661 290,009
McIntosh 224,041 278,217 266,722 273,657
Stanton 89,129 85,030 88,273 90,568
Wansley 261,609 262,273 257,694 264,394
---------- ---------- ---------- ----------
Total Operating Revenues 1,181,624 1,196,840 1,167,557 1,197,911
OPERATING EXPENSES ($000)
Fuel
Dahlberg 0 130 0 0
Franklin 97,875 92,882 83,218 84,922
Harris 154,417 148,753 144,910 148,193
McIntosh 117,489 140,173 134,904 137,925
Stanton 53,484 49,271 51,676 52,619
Wansley 135,525 134,385 130,400 133,409
Purchased Power (15) 0 0 0 0
Operations & Maintenance (16) 106,651 101,397 101,242 121,073
Administration and General (17) 39,705 40,375 41,060 41,768
---------- ---------- ---------- ----------
Total Operating Expenses 705,145 707,366 687,409 719,908
NET OPERATING REVENUES ($000) 476,478 489,474 480,148 478,003
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.68 4.81 4.71 4.69
2003-15 AVG INTEREST COVERAGE (20)
A-70
FOOTNOTES TO EXHIBIT A-4
The footnotes to Exhibit A-4 are the same as the footnotes for Exhibit A-1,
except:
3. Capacity factor as estimated by PA Consulting under its "Capacity
Overbuild" scenario.
10. As estimated by PA Consulting in its "Capacity Overbuild" scenario.
11. As estimated by PA Consulting in its "Capacity Overbuild" scenario.
A-71
EXHIBIT A-5 SENSITIVITY D - REDUCED OUTPUT
A-72
Exhibit A-5
Southern Power Company, Inc. Facilities
Projected Operating Results
Sensitivity D - Reduced Output
Year Ending December 31, 2003(1) 2004 2005 2006 2007 2008
---------- ---------- ---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 4,381 4,381 5,512 5,512 5,512 5,512
Average Capacity Factor (%)(3) 31.3% 29.5% 31.7% 39.1% 43.8% 44.9%
Contract Energy Sales (GWh)(4) 5,646 10,870 15,717 19,316 21,625 22,149
Other Energy Sales (GWh)(4) 1,057 727 0 8 36 70
---------- ---------- ---------- ---------- ---------- ----------
Total Energy Sales (GWh) 6,703 11,597 15,717 19,325 21,660 22,219
Fuel Consumption (BBtu) 46,239 88,302 118,036 144,978 160,151 164,289
Average Net Heat Rate (Btu/kWh)(5) 7,706 7,788 7,715 7,685 7,572 7,572
SO2 Allowances Purchased (Tons)(6) 23 44 58 73 80 82
NOX Allowances Purchased (Tons)(7) 0 (80) 144 203 264 285
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 34.75 35.09 29.62 26.77 23.58 23.37
Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.18 16.83 19.29
Other Energy Price ($/MWh)(10) $ 52.82 48.71 0.00 67.30 68.30 65.65
Fuel Price ($/MMBtu)(11) $ 5.44 5.00 0.00 3.77 3.58 3.69
SO2 Allowances ($/Ton)(12) $ 150 154 158 162 166 171
NOX Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 16,661 34,138 0 0 0 0
Franklin (14) $ 82,006 105,175 111,310 114,990 117,454 118,725
Harris (14) $ 34,533 110,822 136,468 140,516 137,881 138,291
McIntosh $ 0 0 83,379 125,292 118,280 122,148
Stanton $ 9,934 43,202 42,628 43,454 43,663 44,009
Wansley $ 53,066 88,102 91,761 92,911 92,704 94,380
Other Electricity Revenues
Dahlberg $ 2,111 4,207 12,862 13,557 15,186 19,184
Franklin (14) $ 2,899 11,695 0 0 0 0
Harris $ 59,555 28,437 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Revenues $ 260,765 425,778 478,408 530,720 525,168 536,737
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 38 0 0 407 1,663 3,346
Franklin $ 1,127 8,070 0 0 0 0
Harris $ 43,428 20,410 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
Purchased Power (15) $ 40,949 12,596 19,926 21,044 23,012 24,466
Operations & Maintenance (16) $ 32,920 60,457 77,328 91,518 102,071 107,865
Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Expenses $ 131,191 128,499 126,988 144,890 159,137 168,550
NET OPERATING REVENUES ($000) $ 129,574 297,280 351,419 385,830 366,031 368,187
ANNUAL INTEREST($000)(18) $ 36,531 73,063 87,463 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.55 4.07 4.02 3.79 3.59 3.61
2003-15 AVG INTEREST COVERAGE (20) 3.97
Year Ending December 31, 2009 2010 2011 2012 2013
---------- ---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,512 5,512 5,512 5,512 5,512
Average Capacity Factor (%)(3) 43.6% 41.2% 42.3% 40.0% 36.5%
Contract Energy Sales (GWh)(4) 21,476 12,076 9,507 8,404 7,441
Other Energy Sales (GWh)(4) 81 8,067 11,135 11,091 10,264
---------- ---------- ---------- ---------- ----------
Total Energy Sales (GWh) 21,557 20,143 20,642 19,495 17,704
Fuel Consumption (BBtu) 159,513 151,511 154,520 146,678 134,857
Average Net Heat Rate (Btu/kWh)(5) 7,575 7,615 7,557 7,596 7,661
SO2 Allowances Purchased (Tons)(6) 81 76 78 73 67
NOX Allowances Purchased (Tons)(7) 263 231 248 227 188
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 23.86 27.29 27.74 28.39 32.60
Other Capacity Price ($/MWh)(10) 36.69 46.49 58.16 62.97 67.71
Other Energy Price ($/MWh)(10) 67.93 45.84 47.51 49.19 50.06
Fuel Price ($/MMBtu)(11) 3.80 4.52 4.66 4.83 5.04
SO2 Allowances ($/Ton)(12) 175 180 184 189 194
NOX Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0
Franklin (14) 118,989 78,662 25,138 0 0
Harris (14) 137,776 85,194 71,287 71,025 71,295
McIntosh 116,572 120,978 122,596 122,774 133,166
Stanton 44,261 44,744 44,673 44,808 38,131
Wansley 94,871 0 0 0 0
Other Electricity Revenues
Dahlberg 33,298 38,305 50,809 52,639 53,471
Franklin (14) 0 77,414 214,642 258,359 247,106
Harris 0 99,160 159,405 155,972 158,699
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 9,301
Wansley 0 272,710 294,122 295,579 280,788
---------- ---------- ---------- ---------- ----------
Total Operating Revenues 545,767 817,167 982,672 1,001,156 991,957
OPERATING EXPENSES ($000)
Fuel
Dahlberg 4,029 2,440 4,997 3,525 1,634
Franklin 0 44,964 118,472 140,566 132,862
Harris 0 59,753 93,296 89,875 92,270
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 5,658
Wansley 0 168,425 173,971 172,927 162,266
Purchased Power (15) 23,942 12,401 9,986 9,767 5,007
Operations & Maintenance (16) 109,208 107,491 113,908 113,879 108,623
Administration and General (17) 33,364 33,872 34,386 34,924 35,465
---------- ---------- ---------- ---------- ----------
Total Operating Expenses 170,543 429,347 549,017 565,464 543,785
NET OPERATING REVENUES ($000) 375,224 387,820 433,655 435,693 448,171
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.68 3.81 4.26 4.28 4.40
2003-15 AVG INTEREST COVERAGE (20)
A-73
Exhibit A-5
Southern Power Company, Inc. Facilities
Projected Operating Results
Sensitivity D - Reduced Output
Year Ending December 31, 2014 2015 2016 2017 2018 2019
---------- ---------- ---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,512 5,512 5,512 5,512 5,512 5,512
Average Capacity Factor (%)(3) 33.1% 31.3% 28.5% 26.3% 24.5% 22.8%
Contract Energy Sales (GWh)(4) 6,034 5,749 5,348 4,859 4,501 3,398
Other Energy Sales (GWh)(4) 10,022 9,470 8,490 7,922 7,397 7,658
---------- ---------- ---------- ---------- ---------- ----------
Total Energy Sales (GWh) 16,056 15,219 13,838 12,781 11,898 11,056
Fuel Consumption (BBtu) 123,558 117,262 107,601 99,814 93,450 87,410
Average Net Heat Rate (Btu/kWh)(5) 7,740 7,750 7,822 7,855 7,901 7,928
SO2 Allowances Purchased (Tons)(6) 62 58 54 50 46 43
NOX Allowances Purchased (Tons)(7) 152 121 83 64 51 38
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 34.56 36.47 39.87 43.90 46.87 46.82
Other Capacity Price ($/MWh)(10) $ 67.83 71.68 74.42 76.04 79.21 83.11
Other Energy Price ($/MWh)(10) $ 52.74 53.05 55.13 57.70 59.65 62.83
Fuel Price ($/MMBtu)(11) $ 5.38 5.57 5.84 6.08 6.26 6.50
SO2 Allowances ($/Ton)(12) $ 199 204 209 215 220 226
NOX Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 0 0 0 0 0 0
Franklin (14) $ 0 0 0 0 0 0
Harris (14) $ 72,508 73,365 72,444 71,808 72,853 15,567
McIntosh $ 136,033 136,292 140,800 141,513 138,096 143,517
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
Other Electricity Revenues
Dahlberg $ 52,586 54,014 55,548 56,776 59,306 62,506
Franklin (14) $ 238,351 224,647 217,665 210,762 211,114 208,604
Harris $ 147,022 147,936 141,930 141,905 142,837 231,408
McIntosh $ 0 0 0 0 0 0
Stanton $ 81,307 82,352 83,608 83,651 83,090 80,830
Wansley $ 268,452 267,262 253,624 254,549 247,527 247,260
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Revenues $ 996,259 985,868 965,619 960,964 954,823 989,692
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 1,167 282 0 0 0 0
Franklin $ 128,064 117,685 113,992 107,140 102,900 94,921
Harris $ 84,056 86,370 81,756 81,686 79,808 123,696
McIntosh $ 0 0 0 0 0 0
Stanton $ 49,576 49,822 50,321 49,625 49,948 47,721
Wansley $ 155,459 155,462 142,996 140,350 133,782 128,569
Purchased Power (15) $ 4,788 4,651 4,413 4,225 4,070 1,852
Operations & Maintenance (16) $ 105,302 108,721 103,005 101,715 101,896 100,125
Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052
---------- ---------- ---------- ---------- ---------- ----------
Total Operating Expenses $ 564,434 559,595 533,669 522,533 510,821 535,936
NET OPERATING REVENUES ($000) $ 431,825 426,273 431,950 438,431 444,002 453,756
ANNUAL INTEREST($000)(18) $ 101,863 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.24 4.18 4.24 4.30 4.36 4.45
2003-15 AVG INTEREST COVERAGE (20) 3.97
Year Ending December 31, 2020 2021 2022 2023
---------- ---------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,512 5,512 5,512 5,512
Average Capacity Factor (%)(3) 21.0% 20.2% 18.4% 18.4%
Contract Energy Sales (GWh)(4) 523 0 0 0
Other Energy Sales (GWh)(4) 9,601 9,760 8,906 8,906
---------- ---------- ---------- ----------
Total Energy Sales (GWh) 10,124 9,760 8,906 8,906
Fuel Consumption (BBtu) 80,558 78,109 71,405 71,405
Average Net Heat Rate (Btu/kWh)(5) 7,957 8,003 8,018 8,018
SO2 Allowances Purchased (Tons)(6) 40 39 36 36
NOX Allowances Purchased (Tons)(7) 16 12 (2) (2)
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 51.14 0.00 0.00 0.00
Other Capacity Price ($/MWh)(10) 84.87 87.74 89.36 91.68
Other Energy Price ($/MWh)(10) 64.45 66.02 67.65 69.40
Fuel Price ($/MMBtu)(11) 6.75 6.90 7.16 7.32
SO2 Allowances ($/Ton)(12) 232 238 244 251
NOX Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0
Franklin (14) 0 0 0 0
Harris (14) 0 0 0 0
McIntosh 26,758 0 0 0
Stanton 0 0 0 0
Wansley 0 0 0 0
Other Electricity Revenues
Dahlberg 63,934 66,178 67,392 69,144
Franklin (14) 198,453 202,869 188,074 192,962
Harris 271,374 268,626 269,169 276,168
McIntosh 206,287 265,826 246,963 253,384
Stanton 82,352 80,216 81,518 83,637
Wansley 245,028 244,276 241,839 248,126
---------- ---------- ---------- ----------
Total Operating Revenues 1,094,186 1,127,991 1,094,955 1,123,421
OPERATING EXPENSES ($000)
Fuel
Dahlberg 0 0 0 0
Franklin 88,306 89,218 77,718 79,279
Harris 142,849 140,234 139,116 142,248
McIntosh 107,577 136,710 123,346 126,066
Stanton 49,330 47,612 48,406 49,264
Wansley 127,626 125,551 122,948 125,764
Purchased Power (15) 0 0 0 0
Operations & Maintenance (16) 99,569 105,169 99,893 120,492
Administration and General (17) 39,705 40,375 41,060 41,768
---------- ---------- ---------- ----------
Total Operating Expenses 654,962 684,868 652,486 684,881
NET OPERATING REVENUES ($000) 439,224 443,123 442,469 438,540
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.31 4.35 4.34 4.31
2003-15 AVG INTEREST COVERAGE (20)
A-74
FOOTNOTES TO EXHIBIT A-5
The footnotes to Exhibit A-5 are the same as the footnotes for Exhibit
A-1, except:
2. The output of the Generating Facilities is assumed to be 5 percent less
than that assumed in the Base Case.
A-75
EXHIBIT A-6 Sensitivity E - Reduced Availability
A-76
EXHIBIT A-6
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
SENSITIVITY E - REDUCED AVAILABILITY
YEAR ENDING DECEMBER 31, 2003(1) 2004 2005 2006 2007 2008
- ------------------------ --------- -------- ------- ------- ------- -------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 29.7% 28.0% 30.1% 37.1% 41.5% 42.6%
Contract Energy Sales (GWh)(4) 5,943 11,442 16,544 20,333 22,763 23,315
Other Energy Sales (GWh)(4) 1,011 587 0 8 36 70
--------- -------- ------- ------- ------- -------
Total Energy Sales (GWh) 6,954 12,029 16,544 20,341 22,799 23,384
Fuel Consumption (BBtu) 46,163 88,156 117,843 144,742 159,891 164,023
Average Net Heat Rate (Btu/kWh)(5) 7,706 7,788 7,715 7,685 7,572 7,572
SO(2) Allowances Purchased (Tons)(6) 23 44 58 73 80 82
NO(X) Allowances Purchased (Tons)(7) 0 (81) 142 203 263 284
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 35.75 35.98 30.99 28.04 24.81 24.63
Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.18 16.83 19.29
Other Energy Price ($/MWh)(10) $ 52.76 48.61 0.00 67.24 68.33 65.65
Fuel Price ($/MMBtu)(11) $ 5.42 5.00 0.00 3.77 3.58 3.69
SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171
NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 16,661 34,138 0 0 0 0
Franklin (14) $ 87,294 112,236 121,654 126,059 129,387 131,009
Harris (14) $ 38,188 119,384 149,633 154,398 152,007 152,927
McIntosh $ 0 0 92,105 137,730 130,987 135,325
Stanton $ 10,995 47,607 46,499 47,484 47,687 48,107
Wansley $ 59,305 98,298 102,845 104,437 104,629 106,880
Other Electricity Revenues
Dahlberg $ 2,220 4,429 13,540 14,241 15,857 19,948
Franklin (14) $ 578 8,148 0 0 0 0
Harris $ 59,734 25,371 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
--------- -------- ------- ------- ------- -------
Total Operating Revenues $ 274,975 449,611 526,276 584,349 580,554 594,196
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 38 0 0 407 1,663 3,346
Franklin $ (941) 5,218 0 0 0 0
Harris $ 43,370 17,782 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
Purchased Power (15) $ 54,681 34,276 60,040 68,226 74,847 79,728
Operations & Maintenance (16) $ 32,510 59,608 76,203 90,190 100,473 106,130
Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873
--------- -------- ------- ------- ------- -------
Total Operating Expenses $ 142,388 143,850 165,977 190,744 209,374 222,077
NET OPERATING REVENUES ($000) $ 132,588 305,760 360,298 393,605 371,180 372,119
ANNUAL INTEREST($000)(18) $ 36,531 73,063 87,463 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.63 4.18 4.12 3.86 3.64 3.65
2003-15 AVG INTEREST COVERAGE (20) 4.08
YEAR ENDING DECEMBER 31, 2009 2010 2011 2012 2013
- ------------------------ ------- ------- --------- --------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 41.4% 39.1% 40.2% 37.9% 34.6%
Contract Energy Sales (GWh)(4) 22,607 12,712 10,007 8,847 7,832
Other Energy Sales (GWh)(4) 81 7,976 11,080 11,073 10,199
------- ------- --------- --------- ---------
Total Energy Sales (GWh) 22,688 20,688 21,087 19,919 18,031
Fuel Consumption (BBtu) 159,253 151,266 154,268 146,438 134,639
Average Net Heat Rate (Btu/kWh)(5) 7,575 7,615 7,557 7,596 7,661
SO(2) Allowances Purchased (Tons)(6) 81 76 78 72 67
NO(X) Allowances Purchased (Tons)(7) 262 229 247 226 187
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 25.17 28.42 28.92 29.75 33.71
Other Capacity Price ($/MWh)(10) 36.69 46.49 58.16 62.97 67.71
Other Energy Price ($/MWh)(10) 67.92 45.82 47.50 49.19 50.01
Fuel Price ($/MMBtu)(11) 3.80 4.52 4.66 4.83 5.03
SO(2) Allowances ($/Ton)(12) 175 180 184 189 194
NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0
Franklin (14) 131,115 85,679 25,853 0 0
Harris (14) 152,418 92,958 78,739 78,414 78,276
McIntosh 129,972 133,886 136,160 136,194 146,116
Stanton 48,203 48,774 48,643 48,616 39,633
Wansley 107,349 0 0 0 0
Other Electricity Revenues
Dahlberg 34,756 40,155 53,123 55,143 56,160
Franklin (14) 0 76,580 215,281 261,637 250,668
Harris 0 97,886 160,951 157,673 160,536
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 6,586
Wansley 0 274,876 296,908 298,633 284,121
------- ------- --------- --------- ---------
Total Operating Revenues 603,813 850,794 1,015,658 1,036,310 1,022,096
OPERATING EXPENSES ($000)
Fuel
Dahlberg 4,025 2,440 4,997 3,521 1,634
Franklin 0 43,728 116,955 140,367 132,679
Harris 0 58,119 93,161 89,748 92,139
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 3,111
Wansley 0 168,183 173,721 172,677 162,036
Purchased Power (15) 78,500 40,280 33,325 32,638 22,842
Operations & Maintenance (16) 107,464 105,802 112,082 111,551 107,005
Administration and General (17) 33,364 33,872 34,386 34,924 35,465
------- ------- --------- --------- ---------
Total Operating Expenses 223,353 452,424 568,628 585,427 556,911
NET OPERATING REVENUES ($000) 380,460 398,370 447,030 450,883 465,184
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.74 3.91 4.39 4.43 4.57
2003-15 AVG INTEREST COVERAGE (20)
A-77
EXHIBIT A-6
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
SENSITIVITY E - REDUCED AVAILABILITY
YEAR ENDING DECEMBER 31, 2014 2015 2016 2017 2018 2019
- ------------------------ ---------- --------- ------- ------- ------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 31.4% 29.7% 27.0% 25.0% 23.2% 21.7%
Contract Energy Sales (GWh)(4) 6,352 6,051 5,629 5,115 4,738 3,576
Other Energy Sales (GWh)(4) 10,006 9,455 8,477 7,909 7,385 7,620
---------- --------- ------- ------- ------- ---------
Total Energy Sales (GWh) 16,358 15,506 14,106 13,024 12,123 11,197
Fuel Consumption (BBtu) 123,357 117,070 107,425 99,651 93,298 87,267
Average Net Heat Rate (Btu/kWh)(5) 7,740 7,750 7,822 7,855 7,901 7,928
SO(2) Allowances Purchased (Tons)(6) 62 58 54 49 46 43
NO(X) Allowances Purchased (Tons)(7) 152 121 83 64 50 37
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 35.88 37.81 41.22 45.27 48.29 47.96
Other Capacity Price ($/MWh)(10) $ 67.83 71.68 74.42 76.04 79.21 83.11
Other Energy Price ($/MWh)(10) $ 52.74 53.05 55.13 57.70 59.65 62.84
Fuel Price ($/MMBtu)(11) $ 5.38 5.58 5.84 6.08 6.26 6.50
SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220 226
NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373 2,435
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 0 0 0 0 0 0
Franklin (14) $ 0 0 0 0 0 0
Harris (14) $ 79,351 80,281 79,159 78,259 79,323 16,327
McIntosh $ 148,534 148,515 152,902 153,285 149,478 155,196
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
Other Electricity Revenues
Dahlberg $ 55,259 56,835 58,471 59,764 62,426 65,796
Franklin (14) $ 241,903 228,440 221,620 214,821 215,370 213,110
Harris $ 148,867 149,893 143,976 144,002 145,036 233,752
McIntosh $ 0 0 0 0 0 0
Stanton $ 82,687 83,838 85,181 85,258 84,730 82,506
Wansley $ 271,783 270,803 257,330 258,344 251,521 251,493
---------- --------- ------- ------- ------- ---------
Total Operating Revenues $1,028,384 1,018,605 998,639 993,733 987,884 1,018,180
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 1,167 277 0 0 0 0
Franklin $ 127,891 117,528 113,842 107,000 102,764 94,791
Harris $ 83,939 86,245 81,640 81,570 79,698 122,251
McIntosh $ 0 0 0 0 0 0
Stanton $ 49,518 49,768 50,265 49,571 49,893 47,669
Wansley $ 155,239 155,240 142,789 140,144 133,588 128,385
Purchased Power (15) $ 21,810 20,992 20,005 19,207 18,323 11,597
Operations & Maintenance (16) $ 103,820 107,274 101,347 100,409 100,247 98,758
Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416 39,052
---------- --------- ------- ------- ------- ---------
Total Operating Expenses $ 579,406 573,926 547,073 535,693 522,930 542,504
NET OPERATING REVENUES ($000) $ 448,978 444,679 451,566 458,040 464,954 475,676
ANNUAL INTEREST($000)(18) $ 101,863 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.41 4.37 4.43 4.50 4.56 4.67
2003-15 AVG INTEREST COVERAGE (20) 4.08
YEAR ENDING DECEMBER 31, 2020 2021 2022 2023
- ------------------------ --------- --------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 19.9% 19.2% 17.5% 17.5%
Contract Energy Sales (GWh)(4) 551 0 0 0
Other Energy Sales (GWh)(4) 9,557 9,744 8,892 8,892
--------- --------- ---------- ----------
Total Energy Sales (GWh) 10,108 9,744 8,892 8,892
Fuel Consumption (BBtu) 80,427 77,982 71,290 71,290
Average Net Heat Rate (Btu/kWh)(5) 7,957 8,003 8,018 8,018
SO(2) Allowances Purchased (Tons)(6) 40 39 36 36
NO(X) Allowances Purchased (Tons)(7) 16 12 (2) (2)
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 50.29 0.00 0.00 0.00
Other Capacity Price ($/MWh)(10) 84.87 87.74 89.36 91.68
Other Energy Price ($/MWh)(10) 64.45 66.02 67.65 69.40
Fuel Price ($/MMBtu)(11) 6.75 6.91 7.17 7.32
SO(2) Allowances ($/Ton)(12) 232 238 244 251
NO(X) Allowances ($/Ton)(13) 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0
Franklin (14) 0 0 0 0
Harris (14) 0 0 0 0
McIntosh 27,698 0 0 0
Stanton 0 0 0 0
Wansley 0 0 0 0
Other Electricity Revenues
Dahlberg 67,299 69,661 70,940 72,784
Franklin (14) 203,088 207,672 192,994 198,011
Harris 276,122 273,562 274,201 281,330
McIntosh 208,308 270,755 252,021 258,573
Stanton 84,061 81,962 83,297 85,463
Wansley 249,369 248,785 246,442 252,849
--------- --------- ---------- ----------
Total Operating Revenues 1,115,945 1,152,397 1,119,895 1,149,010
OPERATING EXPENSES ($000)
Fuel
Dahlberg 0 0 0 0
Franklin 88,189 89,109 77,629 79,188
Harris 142,645 140,032 138,920 142,047
McIntosh 105,948 136,518 123,179 125,895
Stanton 49,276 47,556 48,349 49,206
Wansley 127,445 125,371 122,770 125,581
Purchased Power (15) 0 0 0 0
Operations & Maintenance (16) 98,440 99,478 103,380 119,355
Administration and General (17) 39,705 40,375 41,060 41,768
--------- --------- ---------- ----------
Total Operating Expenses 651,648 678,438 655,286 683,039
NET OPERATING REVENUES ($000) 464,296 473,959 464,609 465,971
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.56 4.65 4.56 4.57
2003-15 AVG INTEREST COVERAGE (20)
A-78
FOOTNOTES TO EXHIBIT A-6
The footnotes to Exhibit A-6 are the same as the footnotes for Exhibit
A-1, except:
3. Availability of the Generating Facilities is assumed to be 5 percentage
points less than that assumed in the Base Case based on a 5 percentage
point increase in the forced outage rate for each of the Generating
Facilities, resulting in a reduction in the capacity factors for each
of the Generating Facilities such that annual generation is reduced by
5 percent from that assumed in the Base Case.
A-79
EXHIBIT A-7 Sensitivity F - Increased Heat Rate
A-80
EXHIBIT A-7
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
SENSITIVITY F - INCREASED HEAT RATE
YEAR ENDING DECEMBER 31, 2003(1) 2004 2005 2006 2007 2008
- ------------------------ -------- -------- ------- ------- ------- -------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 31.3% 29.5% 31.7% 39.1% 43.8% 44.9%
Contract Energy Sales (GWh)(4) 5,943 11,442 16,544 20,333 22,763 23,315
Other Energy Sales (GWh)(4) 1,116 765 0 9 38 73
-------- -------- ------- ------- ------- -------
Total Energy Sales (GWh) 7,059 12,207 16,544 20,342 22,800 23,388
Fuel Consumption (BBtu) 51,132 97,596 130,461 160,238 177,009 181,583
Average Net Heat Rate (Btu/kWh)(5) 8,096 8,177 8,101 8,069 7,951 7,951
SO(2) Allowances Purchased (Tons)(6) 25 49 65 82 88 92
NO(X) Allowances Purchased (Tons)(7) 0 (60) 187 254 319 344
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 34.44 34.72 29.42 26.55 23.42 23.20
Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.18 16.83 19.29
Other Energy Price ($/MWh)(10) $ 52.82 48.71 0.00 67.31 68.32 65.64
Fuel Price ($/MMBtu)(11) $ 6.35 7.84 0.00 251.15 63.23 35.96
SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171
NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 16,645 34,138 0 0 0 0
Franklin (14) $ 85,818 109,905 116,396 120,196 122,832 124,145
Harris (14) $ 36,235 115,862 142,441 146,622 144,089 144,558
McIntosh $ 0 0 87,301 130,323 123,410 127,323
Stanton $ 10,374 45,040 44,420 45,276 45,484 45,836
Wansley $ 55,624 92,339 96,116 97,366 97,269 99,010
Other Electricity Revenues
Dahlberg $ 2,223 4,429 13,540 14,271 15,987 20,192
Franklin (14) $ 3,222 12,310 0 0 0 0
Harris $ 62,689 29,934 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
-------- -------- ------- ------- ------- -------
Total Operating Revenues $272,830 443,957 500,214 554,054 549,071 561,064
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 58 0 0 448 1,839 3,697
Franklin $ 4,293 13,343 5,099 5,686 6,359 6,659
Harris $ 49,098 27,734 6,977 7,540 7,680 8,118
McIntosh $ 0 0 4,663 7,185 7,352 7,762
Stanton $ 613 2,464 1,964 2,168 2,135 2,203
Wansley $ 3,570 5,783 6,527 6,860 7,138 7,632
Purchased Power (15) $ 43,081 13,258 20,974 22,153 24,224 25,754
Operations & Maintenance (16) $ 33,111 60,868 77,862 92,184 102,830 108,674
Administration and General (17) $ 12,729 26,966 29,734 31,921 32,391 32,873
-------- -------- ------- ------- ------- -------
Total Operating Expenses $146,554 150,417 153,800 176,145 191,947 203,372
NET OPERATING REVENUES ($000) $126,276 293,540 346,414 377,909 357,125 357,692
ANNUAL INTEREST($000)(18) $ 36,531 73,063 87,463 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.46 4.02 3.96 3.71 3.51 3.51
2003-15 AVG INTEREST COVERAGE (20) 3.92
YEAR ENDING DECEMBER 31, 2009 2010 2011 2012 2013
- ------------------------ ------- ------- --------- --------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 43.6% 41.2% 42.3% 40.0% 36.5%
Contract Energy Sales (GWh)(4) 22,607 12,712 10,007 8,847 7,832
Other Energy Sales (GWh)(4) 86 8,491 11,721 11,674 10,804
------- ------- --------- --------- ---------
Total Energy Sales (GWh) 22,692 21,203 21,728 20,521 18,636
Fuel Consumption (BBtu) 176,303 167,459 170,785 162,118 149,052
Average Net Heat Rate (Btu/kWh)(5) 7,954 7,996 7,935 7,976 8,044
SO(2) Allowances Purchased (Tons)(6) 89 84 87 81 73
NO(X) Allowances Purchased (Tons)(7) 320 283 301 280 237
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 23.70 27.06 27.44 28.12 32.21
Other Capacity Price ($/MWh)(10) 36.69 46.49 58.16 62.97 67.71
Other Energy Price ($/MWh)(10) 67.93 45.84 47.51 49.19 50.06
Fuel Price ($/MMBtu)(11) 31.39 4.75 4.77 4.92 5.12
SO(2) Allowances ($/Ton)(12) 175 180 184 189 194
NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0
Franklin (14) 124,376 82,134 25,853 0 0
Harris (14) 144,040 89,115 74,485 74,217 74,430
McIntosh 121,774 126,117 127,802 127,964 138,295
Stanton 46,076 46,560 46,476 46,609 39,515
Wansley 99,498 0 0 0 0
Other Electricity Revenues
Dahlberg 35,052 40,321 53,484 55,407 56,286
Franklin (14) 0 81,488 225,938 271,958 260,111
Harris 0 104,379 167,795 164,181 167,052
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 9,790
Wansley 0 287,063 309,602 311,136 295,566
------- ------- --------- --------- ---------
Total Operating Revenues 570,816 857,177 1,031,435 1,051,472 1,041,045
OPERATING EXPENSES ($000)
Fuel
Dahlberg 4,450 2,695 5,524 3,897 1,804
Franklin 6,534 53,433 130,297 153,180 144,623
Harris 8,129 70,355 106,128 102,276 104,557
McIntosh 7,956 7,539 8,107 7,985 7,586
Stanton 2,107 2,119 2,038 1,958 7,814
Wansley 7,614 184,096 190,228 189,073 177,290
Purchased Power (15) 25,204 13,054 10,511 10,282 5,270
Operations & Maintenance (16) 110,030 108,315 114,804 114,734 109,409
Administration and General (17) 33,364 33,872 34,386 34,924 35,465
------- ------- --------- --------- ---------
Total Operating Expenses 205,389 475,477 602,023 618,309 593,818
NET OPERATING REVENUES ($000) 365,427 381,699 429,412 433,163 447,227
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.59 3.75 4.22 4.25 4.39
2003-15 AVG INTEREST COVERAGE (20)
A-81
EXHIBIT A-7
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
SENSITIVITY F - INCREASED HEAT RATE
YEAR ENDING DECEMBER 31, 2014 2015 2016 2017 2018
- ------------------------ ---------- --------- --------- --------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 33.1% 31.3% 28.5% 26.3% 24.5%
Contract Energy Sales (GWh)(4) 6,352 6,051 5,629 5,115 4,738
Other Energy Sales (GWh)(4) 10,550 9,968 8,937 8,339 7,786
---------- --------- --------- --------- ---------
Total Energy Sales (GWh) 16,901 16,020 14,567 13,453 12,524
Fuel Consumption (BBtu) 136,563 129,603 118,928 110,320 103,286
Average Net Heat Rate (Btu/kWh)(5) 8,127 8,138 8,213 8,248 8,296
SO(2) Allowances Purchased (Tons)(6) 68 64 60 56 52
NO(X) Allowances Purchased (Tons)(7) 196 162 121 99 86
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 34.12 35.99 39.32 43.28 46.20
Other Capacity Price ($/MWh)(10) $ 67.83 71.68 74.42 76.04 79.21
Other Energy Price ($/MWh)(10) $ 52.74 53.05 55.13 57.70 59.65
Fuel Price ($/MMBtu)(11) $ 5.42 5.62 5.89 6.13 6.31
SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220
NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 0 0 0 0 0
Franklin (14) $ 0 0 0 0 0
Harris (14) $ 75,619 76,488 75,534 74,859 75,898
McIntosh $ 141,097 141,329 145,813 146,477 143,008
Stanton $ 0 0 0 0 0
Wansley $ 0 0 0 0 0
Other Electricity Revenues
Dahlberg $ 55,353 56,856 58,471 59,764 62,426
Franklin (14) $ 250,895 236,471 229,122 221,854 222,225
Harris $ 154,761 155,722 149,400 149,374 150,355
McIntosh $ 0 0 0 0 0
Stanton $ 85,586 86,686 88,008 88,055 87,464
Wansley $ 282,582 281,329 266,973 267,947 260,555
---------- --------- --------- --------- ---------
Total Operating Revenues $1,045,893 1,034,881 1,013,321 1,008,330 1,001,931
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 1,290 308 0 0 0
Franklin $ 139,283 127,763 123,639 116,179 111,756
Harris $ 95,341 97,935 92,648 92,331 90,442
McIntosh $ 7,213 6,970 6,880 6,602 6,275
Stanton $ 53,172 53,444 53,999 53,230 53,583
Wansley $ 169,764 169,812 156,247 153,449 146,321
Purchased Power (15) $ 5,040 4,895 4,646 4,447 4,285
Operations & Maintenance (16) $ 106,027 109,415 103,650 102,325 102,485
Administration and General (17) $ 36,022 36,601 37,186 37,792 38,416
---------- --------- --------- --------- ---------
Total Operating Expenses $ 613,153 607,143 578,894 566,355 553,563
NET OPERATING REVENUES ($000) $ 432,740 427,738 434,427 441,975 448,368
ANNUAL INTEREST($000)(18) $ 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.25 4.20 4.26 4.34 4.40
2003-15 AVG INTEREST COVERAGE (20) 3.92
YEAR ENDING DECEMBER 31, 2019 2020 2021 2022 2023
- ------------------------ --------- --------- --------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 22.8% 21.0% 20.2% 18.4% 18.4%
Contract Energy Sales (GWh)(4) 3,576 551 0 0 0
Other Energy Sales (GWh)(4) 8,061 10,107 10,274 9,375 9,375
--------- --------- --------- ---------- ----------
Total Energy Sales (GWh) 11,638 10,657 10,274 9,375 9,375
Fuel Consumption (BBtu) 96,611 89,039 86,331 78,922 78,922
Average Net Heat Rate (Btu/kWh)(5) 8,324 8,355 8,403 8,419 8,419
SO(2) Allowances Purchased (Tons)(6) 49 44 44 40 40
NO(X) Allowances Purchased (Tons)(7) 70 45 43 25 25
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 46.07 50.29 0.00 0.00 0.00
Other Capacity Price ($/MWh)(10) 83.11 84.87 87.74 89.36 91.68
Other Energy Price ($/MWh)(10) 62.83 64.45 66.02 67.65 69.40
Fuel Price ($/MMBtu)(11) 6.51 6.66 6.80 7.05 7.21
SO(2) Allowances ($/Ton)(12) 226 232 238 244 251
NO(X) Allowances ($/Ton)(13) 2,435 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0
Franklin (14) 0 0 0 0 0
Harris (14) 16,327 0 0 0 0
McIntosh 148,445 27,698 0 0 0
Stanton 0 0 0 0 0
Wansley 0 0 0 0 0
Other Electricity Revenues
Dahlberg 65,796 67,299 69,661 70,940 72,784
Franklin (14) 219,581 208,898 213,547 197,972 203,119
Harris 243,589 285,657 282,765 283,337 290,702
McIntosh 0 217,143 279,817 259,961 266,720
Stanton 85,084 86,687 84,437 85,808 88,039
Wansley 260,275 257,924 257,133 254,567 261,186
--------- --------- --------- ---------- ----------
Total Operating Revenues 1,039,097 1,151,306 1,187,360 1,152,585 1,182,550
OPERATING EXPENSES ($000)
Fuel
Dahlberg 0 0 0 0 0
Franklin 103,055 95,739 96,750 84,041 85,766
Harris 136,152 155,922 153,038 151,803 155,265
McIntosh 6,542 118,570 149,130 134,357 137,364
Stanton 51,120 52,905 51,000 51,880 52,829
Wansley 140,559 139,518 137,224 134,347 137,459
Purchased Power (15) 1,949 0 0 0 0
Operations & Maintenance (16) 100,685 100,114 105,714 100,405 121,018
Administration and General (17) 39,052 39,705 40,375 41,060 41,768
--------- --------- --------- ---------- ----------
Total Operating Expenses 579,115 702,472 733,230 697,893 731,468
NET OPERATING REVENUES ($000) 459,982 448,833 454,130 454,692 451,082
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.52 4.41 4.46 4.46 4.43
2003-15 AVG INTEREST COVERAGE (20)
A-82
FOOTNOTES TO EXHIBIT A-7
The footnotes to Exhibit A-7 are the same as the footnotes for Exhibit
A-1, except:
5. Heat rate for each of the Generating Facilities is assumed to be 5
percent higher than that assumed in the Base Case.
A-83
EXHIBIT A-8 SENSITIVITY G - INCREASED OPERATING EXPENSES
A-84
EXHIBIT A-8
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
SENSITIVITY G - INCREASED OPERATING EXPENSES
YEAR ENDING DECEMBER 31, 2003(1) 2004 2005 2006 2007 2008
- ------------------------ -------- -------- ------- ------- ------- -------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 4,612 4,612 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 31.3% 29.5% 31.7% 39.1% 43.8% 44.9%
Contract Energy Sales (GWh)(4) 5,943 11,442 16,544 20,333 22,763 23,315
Other Energy Sales (GWh)(4) 1,116 765 0 9 38 73
-------- -------- ------- ------- ------- -------
Total Energy Sales (GWh) 7,059 12,207 16,544 20,342 22,800 23,388
Fuel Consumption (BBtu) 48,697 92,948 124,247 152,609 168,579 172,934
Average Net Heat Rate (Btu/kWh)(5) 7,710 7,788 7,715 7,685 7,572 7,572
SO(2) Allowances Purchased (Tons)(6) 24 47 62 77 83 86
NO(X) Allowances Purchased (Tons)(7) 0 (70) 165 229 292 314
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 34.44 34.72 29.42 26.55 23.42 23.20
Other Capacity Price ($/MWh)(10) $ 16.91 18.52 16.99 17.18 16.83 19.29
Other Energy Price ($/MWh)(10) $ 52.82 48.71 0.00 67.31 68.32 65.64
Fuel Price ($/MMBtu)(11) $ 5.40 4.96 0.00 3.76 3.58 3.69
SO(2) Allowances ($/Ton)(12) $ 150 154 158 162 166 171
NO(X) Allowances ($/Ton)(13) $ 0 2,000 1,700 1,744 1,790 1,836
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 16,645 34,138 0 0 0 0
Franklin (14) $ 85,818 109,905 116,396 120,196 122,832 124,145
Harris (14) $ 36,235 115,862 142,441 146,622 144,089 144,558
McIntosh $ 0 0 87,301 130,323 123,410 127,323
Stanton $ 10,374 45,040 44,420 45,276 45,484 45,836
Wansley $ 55,624 92,339 96,116 97,366 97,269 99,010
Other Electricity Revenues
Dahlberg $ 2,223 4,429 13,540 14,271 15,987 20,192
Franklin (14) $ 3,222 12,310 0 0 0 0
Harris $ 62,689 29,934 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
-------- -------- ------- ------- ------- -------
Total Operating Revenues $272,830 443,957 500,214 554,054 549,071 561,064
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 38 0 0 429 1,753 3,520
Franklin $ 1,318 8,423 0 0 0 0
Harris $ 45,315 21,309 0 0 0 0
McIntosh $ 0 0 0 0 0 0
Stanton $ 0 0 0 0 0 0
Wansley $ 0 0 0 0 0 0
Purchased Power (15) $ 43,081 13,258 20,974 22,153 24,224 25,754
Operations & Maintenance (16) $ 36,422 66,948 85,634 101,391 113,108 119,535
Administration and General (17) $ 14,001 29,661 32,704 35,113 35,629 36,156
-------- -------- ------- ------- ------- -------
Total Operating Expenses $140,175 139,599 139,312 159,086 174,714 184,965
NET OPERATING REVENUES ($000) $132,655 304,359 360,902 394,968 374,358 376,099
ANNUAL INTEREST($000)(18) $ 36,531 73,063 87,463 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.63 4.17 4.13 3.88 3.68 3.69
2003-15 AVG INTEREST COVERAGE (20) 4.09
YEAR ENDING DECEMBER 31, 2009 2010 2011 2012 2013
- ------------------------ ------- ------- --------- --------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 43.6% 41.2% 42.3% 40.0% 36.5%
Contract Energy Sales (GWh)(4) 22,607 12,712 10,007 8,847 7,832
Other Energy Sales (GWh)(4) 86 8,491 11,721 11,674 10,804
------- ------- --------- --------- ---------
Total Energy Sales (GWh) 22,692 21,203 21,728 20,521 18,636
Fuel Consumption (BBtu) 167,909 159,487 162,653 154,397 141,954
Average Net Heat Rate (Btu/kWh)(5) 7,575 7,615 7,557 7,596 7,660
SO(2) Allowances Purchased (Tons)(6) 85 80 83 76 70
NO(X) Allowances Purchased (Tons)(7) 290 257 274 253 213
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 23.70 27.06 27.44 28.12 32.21
Other Capacity Price ($/MWh)(10) 36.69 46.49 58.16 62.97 67.71
Other Energy Price ($/MWh)(10) 67.93 45.84 47.51 49.19 50.06
Fuel Price ($/MMBtu)(11) 3.80 4.49 4.63 4.80 5.00
SO(2) Allowances ($/Ton)(12) 175 180 184 189 194
NO(X) Allowances ($/Ton)(13) 1,884 1,933 1,983 2,035 2,088
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0
Franklin (14) 124,376 82,134 25,853 0 0
Harris (14) 144,040 89,115 74,485 74,217 74,430
McIntosh 121,774 126,117 127,802 127,964 138,295
Stanton 46,076 46,560 46,476 46,609 39,515
Wansley 99,498 0 0 0 0
Other Electricity Revenues
Dahlberg 35,052 40,321 53,484 55,407 56,286
Franklin (14) 0 81,488 225,938 271,958 260,111
Harris 0 104,379 167,795 164,181 167,052
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 9,790
Wansley 0 287,063 309,602 311,136 295,566
------- ------- --------- --------- ---------
Total Operating Revenues 570,816 857,177 1,031,435 1,051,472 1,041,045
OPERATING EXPENSES ($000)
Fuel
Dahlberg 4,242 2,569 5,267 3,711 1,718
Franklin 0 46,993 123,819 146,873 138,743
Harris 0 62,530 97,649 94,037 96,545
McIntosh 0 0 0 0 0
Stanton 0 0 0 0 5,867
Wansley 0 176,261 182,099 180,998 169,780
Purchased Power (15) 25,204 13,054 10,511 10,282 5,270
Operations & Maintenance (16) 121,025 119,087 126,214 126,137 120,289
Administration and General (17) 36,697 37,253 37,828 38,409 39,009
------- ------- --------- --------- ---------
Total Operating Expenses 187,168 457,748 583,387 600,448 577,221
NET OPERATING REVENUES ($000) 383,648 399,429 448,048 451,025 463,824
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 3.77 3.92 4.40 4.43 4.55
2003-15 AVG INTEREST COVERAGE (20)
A-85
EXHIBIT A-8
SOUTHERN POWER COMPANY, INC. FACILITIES
PROJECTED OPERATING RESULTS
SENSITIVITY G - INCREASED OPERATING EXPENSES
YEAR ENDING DECEMBER 31, 2014 2015 2016 2017 2018
- ------------------------ ---------- --------- --------- --------- ---------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 33.1% 31.3% 28.5% 26.3% 24.5%
Contract Energy Sales (GWh)(4) 6,352 6,051 5,629 5,115 4,738
Other Energy Sales (GWh)(4) 10,550 9,968 8,937 8,339 7,786
---------- --------- --------- --------- ---------
Total Energy Sales (GWh) 16,901 16,020 14,567 13,453 12,524
Fuel Consumption (BBtu) 130,059 123,431 113,265 105,067 98,368
Average Net Heat Rate (Btu/kWh)(5) 7,740 7,750 7,822 7,855 7,901
SO(2) Allowances Purchased (Tons)(6) 66 62 57 52 49
NO(X) Allowances Purchased (Tons)(7) 174 143 102 81 68
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) $ 34.12 35.99 39.32 43.28 46.20
Other Capacity Price ($/MWh)(10) $ 67.83 71.68 74.42 76.04 79.21
Other Energy Price ($/MWh)(10) $ 52.74 53.05 55.13 57.70 59.65
Fuel Price ($/MMBtu)(11) $ 5.34 5.53 5.79 6.03 6.21
SO(2) Allowances ($/Ton)(12) $ 199 204 209 215 220
NO(X) Allowances ($/Ton)(13) $ 2,142 2,197 2,255 2,313 2,373
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg $ 0 0 0 0 0
Franklin (14) $ 0 0 0 0 0
Harris (14) $ 75,619 76,488 75,534 74,859 75,898
McIntosh $ 141,097 141,329 145,813 146,477 143,008
Stanton $ 0 0 0 0 0
Wansley $ 0 0 0 0 0
Other Electricity Revenues
Dahlberg $ 55,353 56,856 58,471 59,764 62,426
Franklin (14) $ 250,895 236,471 229,122 221,854 222,225
Harris $ 154,761 155,722 149,400 149,374 150,355
McIntosh $ 0 0 0 0 0
Stanton $ 85,586 86,686 88,008 88,055 87,464
Wansley $ 282,582 281,329 266,973 267,947 260,555
---------- --------- --------- --------- ---------
Total Operating Revenues $1,045,893 1,034,881 1,013,321 1,008,330 1,001,931
OPERATING EXPENSES ($000)
Fuel
Dahlberg $ 1,229 291 0 0 0
Franklin $ 133,670 122,726 118,812 111,665 107,328
Harris $ 87,889 90,309 85,446 85,355 83,464
McIntosh $ 0 0 0 0 0
Stanton $ 51,374 51,636 52,163 51,430 51,765
Wansley $ 162,611 162,635 149,621 146,902 140,054
Purchased Power (15) $ 5,040 4,895 4,646 4,447 4,285
Operations & Maintenance (16) $ 116,579 120,305 113,973 112,527 112,707
Administration and General (17) $ 39,622 40,258 40,909 41,570 42,255
---------- --------- --------- --------- ---------
Total Operating Expenses $ 598,014 593,056 565,570 553,896 541,859
NET OPERATING REVENUES ($000) $ 447,879 441,825 447,751 454,434 460,072
ANNUAL INTEREST($000)(18) $ 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.40 4.34 4.40 4.46 4.52
2003-15 AVG INTEREST COVERAGE (20) 4.09
YEAR ENDING DECEMBER 31, 2019 2020 2021 2022 2023
- ------------------------ --------- --------- --------- ---------- ----------
CONSOLIDATED
PERFORMANCE
Annual Average Capacity (MW)(2) 5,802 5,802 5,802 5,802 5,802
Average Capacity Factor (%)(3) 22.8% 21.0% 20.2% 18.4% 18.4%
Contract Energy Sales (GWh)(4) 3,576 551 0 0 0
Other Energy Sales (GWh)(4) 8,061 10,107 10,274 9,375 9,375
--------- --------- --------- ---------- ----------
Total Energy Sales (GWh) 11,638 10,657 10,274 9,375 9,375
Fuel Consumption (BBtu) 92,010 84,797 82,221 75,165 75,165
Average Net Heat Rate (Btu/kWh)(5) 7,928 7,957 8,003 8,018 8,018
SO(2) Allowances Purchased (Tons)(6) 46 43 42 38 38
NO(X) Allowances Purchased (Tons)(7) 54 31 28 11 11
COMMODITY PRICES
General Inflation (%)(8) 2.60 2.60 2.60 2.60 2.60
Contract Electricity Price ($/MWh)(9) 46.07 50.29 0.00 0.00 0.00
Other Capacity Price ($/MWh)(10) 83.11 84.87 87.74 89.36 91.68
Other Energy Price ($/MWh)(10) 62.83 64.45 66.02 67.65 69.40
Fuel Price ($/MMBtu)(11) 6.44 6.69 6.85 7.10 7.26
SO(2) Allowances ($/Ton)(12) 226 232 238 244 251
NO(X) Allowances ($/Ton)(13) 2,435 2,498 2,563 2,630 2,698
OPERATING REVENUES ($000)
Contract Electricity Revenues
Dahlberg 0 0 0 0 0
Franklin (14) 0 0 0 0 0
Harris (14) 16,327 0 0 0 0
McIntosh 148,445 27,698 0 0 0
Stanton 0 0 0 0 0
Wansley 0 0 0 0 0
Other Electricity Revenues
Dahlberg 65,796 67,299 69,661 70,940 72,784
Franklin (14) 219,581 208,898 213,547 197,972 203,119
Harris 243,589 285,657 282,765 283,337 290,702
McIntosh 0 217,143 279,817 259,961 266,720
Stanton 85,084 86,687 84,437 85,808 88,039
Wansley 260,275 257,924 257,133 254,567 261,186
--------- --------- --------- ---------- ----------
Total Operating Revenues 1,039,097 1,151,306 1,187,360 1,152,585 1,182,550
OPERATING EXPENSES ($000)
Fuel
Dahlberg 0 0 0 0 0
Franklin 98,985 92,020 92,989 80,882 82,525
Harris 129,387 149,382 146,630 145,457 148,754
McIntosh 0 112,453 142,923 128,857 131,721
Stanton 49,421 51,114 49,309 50,143 51,047
Wansley 134,564 133,575 131,388 128,651 131,615
Purchased Power (15) 1,949 0 0 0 0
Operations & Maintenance (16) 110,731 110,080 116,235 110,399 133,070
Administration and General (17) 42,954 43,670 44,408 45,168 45,941
--------- --------- --------- ---------- ----------
Total Operating Expenses 567,992 692,293 723,881 689,556 724,673
NET OPERATING REVENUES ($000) 471,105 459,012 463,479 463,029 457,877
ANNUAL INTEREST($000)(18) 101,863 101,863 101,863 101,863 101,863
ANNUAL INTEREST COVERAGE (19) 4.62 4.51 4.55 4.55 4.50
2003-15 AVG INTEREST COVERAGE (20)
A-86
FOOTNOTES TO EXHIBIT A-8
The footnotes to Exhibit A-8 are the same as the footnotes for Exhibit
A-1, except:
16. Assumed to be 10 percent higher than that assumed in the Base Case,
with the exception of the cost of emissions allowances.
17. Assumed to be 10 percent higher than that assumed in the Base Case.
A-87