ML20137N970
| ML20137N970 | |
| Person / Time | |
|---|---|
| Site: | Beaver Valley, Davis Besse, Perry, 05000000 |
| Issue date: | 01/31/1986 |
| From: | Silberg J CLEVELAND ELECTRIC ILLUMINATING CO., DUQUESNE LIGHT CO., SHAW, PITTMAN, POTTS & TROWBRIDGE, TOLEDO EDISON CO. |
| To: | Harold Denton Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 8602040304 | |
| Download: ML20137N970 (84) | |
Text
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,a SHAw, PITTMAN, PoTTs & TROWBRIDGE A PARTNE RSMip OF PROF ESSiON A L CORPORATIONS 1800 M STRE ET, N W.
WASHINGTON. D. C. 20036 T E L E copiE R e 202' 122 ose & e22-nee Tra '
es rees ism..wt A* wsn i caste'SHAwtAw" T E L E PMON E J AY E. S i L B E R G, P C.
8 202 r e22-ce3 January 31, 1986 F;r. Harold R. Denton, Director Office of Nuclear Reactor Regulation U.
S.
Nuclear Regulatory Commiesion Washington, D. C.
20555 Re:
Cleveland Electric Illuminating Company (Perry Nuclear Power Plant, Units 1 and 2)
Docket Nos. 50-440 and 50-441 Duquesne Light Company (Beaver Valley Power Station, Unit 2)
Docket No. 50-412 Toledo Edison Company (Davis-Besse Nuclear Power Plant)
Docket No. 50-346
Dear Sir:
My letters of August 14, 1985, November 13, 1985, and January 8, 1986 transmitted to you documents (Form U-1, Amendments 1 and 2 to Form U-1, and Form S-4) that had been filed with the Securities and Exchange Commission in connection with the proposed affiliation between The Cleveland Electric Illuminating Company and The Toledo Edison Company.
Enclosed for your information are Amendments 3 and 4 to Form U-l which were recently filed with the SEC to provide additional information concerning the proposed affiliation.
y truly a rs, v) e v
~
[a E
Silberg 8602040304hg{0346 (C un el for Cleveland Electric PDR ADOCK PDR I luminating Company, M
Duquesne Light Company, and Toledo Edison Company JES:L g
Enclosure 1
File No. 70-7149 SECURITIES AND EXCHANGE COMMISSION Washington, D. C.
20549 AMENDMENT NO. 3 to FORM U-l l
APPLICATION UNDER THE PUBLIC UTILITY HOLDING COMPANY ACT OP 1935 CENTERIOR ENERGY CORPORATION (formerly North Holding Company) c/o Squire, Sanders & Dempsey 1800 Huntington Building Cleveland, Ohio 44115
(
(Name of company filing this statement 2
and address of principal executive offices)
/
None Name of top registered holding company parent of each applicant or declarant)
Paul M. Smart, Secretary arid Treasurer Centerior Energy Corporation 300 Madison Avenue Toledo, Ohio 43652 (Name and address of agent for service) l The Commission is requested to mail copies of all orders, notices and communications to:
1 James J.
Maiwurm, Esq.
Gerry D. Osterland, Esq.
i Squire, Sanders & Dempsey Jones, Day, Reavis 1201 Pennsylvania Avenue, N.W.
& Pogue Washington, D.
C.
20004 2300 LTV Center 202-626-6826 2001 Ross Avenue l
Dallas, Texas 75201 l
214-969-3722 l
l L
Centerior Energy Corporation ("Centerior")
is filing this Amendment No. 3 to its Form U-1 Application (file no. 70-7149) for the purpose of pro-viding additional information and filing additional exhibits.
ITEM 1.
Description of Transaction.
The_following additional information is furnished in response to that portion of Section 10(b)(2) of The Public Utility Holding Company Act of 1935 (the "Act") which provides that:
"If the requirements of subsection (f) are satisfied, the Commission shall approve the acquisition unless the Commis-sion finds that --
(2) In case of the acquisition of securities
, the consideration,
. to whomsoever paid, to be given, direct-ly or indirectly, in connection with such acquisition is not reasonable or does not bear a fair relation to the sums invested in or to earning capacity of
. the utility assets underlying the securities to be acquired..
Throughout the period of the negotiation of the affiliation trans-action, The Cleveland Electric Illuminating Company ("CEI") was represented by and was receiving the advice and assistance of its investment banker, Morgan Stanley & Co. Incorporated (" Morgan Stanley").
During this same period The Toledo Edison Company ("TE") was represented by and was receiving the advice and assistance of its investment banker, Merrill Lynch Capital Markets
("Merrill Lynch").
At an early stage in the discussions between CEI and TE, an under-standing was reached to the effect that, if a transaction were to go forward, it would be on the basis of:
1.
The establishment of a holding company (Centerior was ultimately established as the holding company pursuant to this understanding).
2.
A merger transaction whereby all of the outstanding common stock of CEI would become owned by Centerior (thereby making CEI a wholly-owned r
subsidiary of Centerior), and the interests of the existing common stock owners of CEI would be converted into common stock ownership of Centerior.
3.
A merger transaction whereby all of the outstanding common stock of TE would become owned by Centerior (thereby making TE a wholly-owned sub-sidiary of Centerior), and the interests of the existing common stock owners of TE would be converted into common stock ownership of Centerior.
4.
As a result of the foregoing, immediately upon consummation of the transactions, the only holders of common shares of Centerior would be those former owners of common shares of CEI and TE whose shares were converted into shares of Centerior.
Within the structural framework so established, the negotiations between the parties focused upon the appropriate exchange ratios, i.e. the number of shares of Centerior common stock to be issued for each share of CEI and the number of shares of Centerior common stock to be issued for each share of TE.
The studies by the management of both companies, and by their respec-tive investment bankers, thus focused upon those factors deemed to be relevant to exchange ratios.
. Morgan Stanley studies on behalf of CEI focused upon the following areas:
1.
The history of the market value of the common stock of CEI in the trading market; the history of the market value of the common stock of TE in the trading market; the ratio of the trading market value of each CEI share to the trading market value of each TE share, and the trend of such ratio.
Over the period of approximately 4 1/2 years, there was a gradual increase in the market value relationship of a CEI common share to a TE common share. On June 21, 1985, (the last trading day for which market value information was -
available prior to agreement being reached on an exchange ratio), each CEI share was worth 118% of the value of each TE share.
Considered over a some-what longer period of trading activity (one week average, two week average and four week average), the market value relationships were about the same, rang-ing from 116% to 118% as the value of each CEI share in relation to each TE share.
2.
Relative book value per common share was also studied. The unadjusted book value of TE shares was greater than the unadjusted book value of CEI shares. For the latest period studied, the unadjusted book value of each CEI share was 89% of the unadjusted book value of each TE share.
3.
An extensive study was undertaken to resolve the significant difference between market and book ratios.
This study was aimed at deriving en adjusted book value per share for each company (sometimes called
" recoverable net assets per share" and sometimes called " tangible book value per share"). The adjustments were intended to reflect a range of possible values depending on various accounting differences between the companies,
possible future discounting which may be required by the proposed revisions to the Financial Accounting Standards #71, and to recognize the market-place's perception of possible disallowances of investment in incomplete nuclear facilities not yet included in the companies' rate base.
Such adjustments,
prepared under various assumptions, reduced the book value per share of TE to a lower amount than the comparably adjusted book value of CEI.
4.
Consideration was also given to the historical relationship of earnings per share of the two companies, and the trends of such earnings per share. For the most recent period, the earnings per share of CEI were 96% of the earnings per share of TE.
However, the historical trend of the relative carnings per share had been for CEI earnings per share to improve in relation to the TE earnings per share.
~ _
5.
Studies were also undertaken of the relative dividends per share of the two companies.
For the most recent period studied, the dividend rate per share of the two compcnies was identical, but the historical trend had shown an increase in the ratio of CEI dividends per share to the dividends per share of TE.
6.
Studies were undertaken of the relative cash flow per share.
For the most recent period studied, the cash flow per share of CEI was 156% of the cash flow per share of TE.
The historical trend had shown a gradual incraase in the cash flow per share of CEI in relation to TE.
7.
Study was undertaken, using selected exchange ratios, to deter-mined the potential impact of selected exchange ratios upon market value, staced book value, adjusted book value (sometimes called recoverable net assets per share and sometimes called tangible book value per share), histori-cal earnings per share and cash flow per share.
Just as Morgan Stanley, on behalf of CEI, studied various financial relationships, so also did Merrill Lynch, on behalf of TE, study various financial relationships.
For this purpose Merrill Lynch studied and reported to TE management with respect to:
1.
Historical operating data of TE (called "Tophat" in the studies).
2.
Historical cash flow data of TE.
3.
Historical selected financial ratios of TE.
4 Historical operating data of CEI (called " Chapeau" in the studies).
5.
Historical cash flow data of CEI.
6.
Historical selected financial ratios of CEI.
7.
Summary operating statistics of the two companies, including pro forma combined operating statistics.
8.
Summary power plant data with respect to the two companies.
9.
Impact of the proposed transaction upon the book value, earnings per share, cash. flow per share, dividend and dividend yield, and certain assumptions as to market value prices, based upon the proposed transaction.
10.
Relative contribution of the two companies to the net property, plant and equipment; total common equity; net income applicable per common share; allowance for funds used during construction applicable to common stock equity; and operating cash flow.
11.
Relative stock market trading values per share of TE and CEI stock, for historical periods and for current petiods, were also studied.
This study, as did the study of the same subject mattet by Morgan Stanley, on behalf of CEI, showed:
(a) A CEI share value equal to 118% of a TE share on June 21, 1985.
(b) A range during calendar year 1985 whereby CEI shares were in the range of 103% to 122% of the value of a YE share, depending upon the trading period.
12.
Studies were also made, for comparative purposes, with respect to celected comparable companies, showing selected financial data and market value data of CEI and TE in comparison to these other companfra.
Negotiations then took place between CEI and TE against the back-ground of agreement between the parties as to the structural form of a trans-action, as set forth above, and with the benefit of the analysis provided by their respective investment bankers, including the analyses listed above.
These negotiations were handled in part through direct discussions between the chief executive officers of CEI and TE, and were handled in part through dis-cussions between the respective investment banking firms.
5-
The exchange ratio initially proposed by TE suggested that the unadjusted book value of the respective companies should form the foundation for the exchange ratio. CEI found that basis for exchange unacceptable, and rejected it.
The exchange ratio initially proposed by CEI suggested that the mar-ket value of the common shares of the respective companies on the date of agreement should form the foundation for the exchange ratio. TE found that basis for exchange unacceptable, and rejected it.
Negotiations continued, and in due course, through the process of negotiation and compromise, an exchange ratio of 1.11 shares of Centerior for each CEI common share, and one share of Centerior for each TE common share, was agreed upon.
This agreed upon exchange ratio has the effect of valuing each CEI common share at 111% of the value of each TE common share.
The respective investment banking firms then tested the agreed upon exchange ratio against the standards set forth above.
Morgan Stanley and Merrill Lynch were each requested to study and confirm that they could give opinions to the Board of Directors of CEI and TE, respectively, that the pro-posed affiliation, at the agreed upon exchange ratio, was fair to the common 1
shareholders of the respective companies from a financial point of itew.
Each of the respective investment banking firms confirmed, af ter study that they were able to furnish such opinions.
The opinions of such firms (as set forth in the merger proxy statements of CEI and TE, filed with the Securities and Exchange Commission as part of Registration Statement on Form S-4, Registra-tion No. 2-99531) were heretofore filed, in connection with Amendment No. I to the Centerior filing on Form U-1, and were identified therein as Exhibits L and M.
For convenience purposes, such opinion letters are refiled herewith, maintaining the identification as Exhibits L and M...-
Also filed herewith, as Exhibits Y and Z are the study reports of Morgan Stanley and Merrill Lynch, respectively, to the 13ards of Directors of CEI and TE, each dated June 25, 1985.
These reports set forth the studies of such firms testing the agreed upon exchange ratio against the standards set forth above. In each case, for the purpose of this filing, such reports have been abridged to eliminate information containing forecasts for future operat-i log periods, because it is deemed inappropriate to include information as to forecasted future operating results of CEI, TE and Centerior in a public record.
As is readily apparent, the agreed upon exchange ratio, while not directly tying exactly to any other specific financial ratio (such as relative book value, adjusted or unadjusted; relative market value; relative earnings per share; or relative dividends per share) bears a closer relationship to relative market value than it does to any other ratio.
Centerior believes that the agreed upon exchange ratio constitutes consideration to the common shareholders of CEI and TE that is reasonable and bears a fair relation to the sums invested in and to the earning capacity of the utility assets of CEI and TE.
Furthermore, Centerior telieves that there is nothing in the record of this proceeding, and there is no basis for a credible assertion to the
)
effect that, the consideration to the common shareholders of CEI and TE in l
this proposed affiliation transaction:
1.
Is not reasonable, or 2.
Does not bear a fair relation to the sums invested in or the earning capacity of the utility assets of CEI and TE.
On November 26, 1985, at separate meetings of the shareholders of CEI and T8, the proposed affiliation transaction was approved by the following voting margins: -- _
~
1.
63,485,215 common shares of CEI voted in favor of the trans-cetion, constituting an approval ratio of 96.5% of the shares that voted on the transaction.
2.
32,206,402 common shares of TE voted in favor of the transaction, constituting an approval ratio of 96.6% of the shares that voted on the trans-cetion.
ITEM 3.
Applicable Statutory Provisions.
The following additional information is furnished in response to that portion of Section 10(c)(2) of the Act which provides that:
"Notwithstanding the provisions of subsection (b),
the Commission shall not approve --
(2) the acquisition of securities.
of a public utility unless the Commission finds that such acquisition will serve the public interest by tending towards the economical and the efficient development of an integrated public utility system knthatconnection,referenceisalsomadetoSection2(a)(29)ofthe Act which provides that:
"When used in this title, unless the context otherwise requires --
(29) ' Integrated public utility system' means --
(A) As applied to electric utility companies, a system consisting of one or more units of generat-ing plants and/or transmission lines and/or dis-tributing facilities, whose utility assets, whether owned by one or more electric utility companies, are physically interconnected or capa-ble of physical interconnection and which under normal conditions may be economically operated as a single interconnected and coordinated system confined in its operations to a single area or region, in one or more states, not so large as to impair (considering the state of the art and the area or region affected) the advantages of local-3 ized management, efficient operation, and the effectiveness of regulation; l
Integrated Operation of The Centerior Power System
Background
For many years the managements of CEi and TE have aggressively pur-sued the goals of improved reliability and lower cost to the customer through coordination with other electric systems.
Examples of-actions taken include construction of high-capacity extra-high-voltage (345 kV) interconnections with other systems. These include interconnections between the CEI system and General Public Utilities (GPU) system in 1966 and between the TE system and The Michigan Power Pool system beginning in 1970.
Both CEI (in 1963) and TE (in 1969) have constructed major 345 kV interconnections with Ohio Power, a i
member of the American Electric Powe r (AEP) system. More recently, in 1968 through 1970, CEI developed with Ohio Edison (CE) a series of projects which included construction of a 600 MW generating unit on each system under a nutual back-up arrangement for those units and two 345 kV interconnactions between the systems.
A result of these coordinated projects was the development of significant portions of a 345 kV network in northern Ohio.
In 1967 CEI and TE joined with OE and Duquesne Light Company (DL) in a Memorandum of Understanding concerning the formation of The Central Area Power Coordination Group. The purposes of that agreement were to " coordinate the installation of generation and transmission capacity on the systems of the parties in order to enable each party, on an equitable basis, to:
1.
Further the reliability of bulk power supply through assurance of:
(a) An adequate reserve capacity level with reserve capacity coordination.
(b) An adequate transmicsion network.
2.
Take advantage of such economies of scale as will be available.".
Among other things, the Memorandum of Understanding provided for the construction of certain generation and transmission facilities, provided the basis for committing additional generation and transmission facilities, estab-lished the ownership and the basis for financial responsibility of each facil-ity and committed to development of definitive agreements covering the construction, operation and maintenance of such facilities.
Specifically the Memorandum of Understanding provided for the con-struction of four major generating units as follows:
Generating Unit Committents in CAPCO Memorandum of Understanding Ultimate Nominal Constructor Ownership (MW) l Designation Capacity (Operator)
Location CEI DL DE TE Sammis 7 625 MW OE Ohio River 195 430 Eastlake 5 625 MW CEI Lake Erie 430 195 Beaver Valley 1
800 MW DL Ohio River 380 420 Davis-Besse 800 MW TE Site to be 380 420 selected In addition, the Memorandum of Understanding committed what was con-sidered a "back bone" 345 kV transmission system. This back bone system was considered necessary not only to make available to the owners of the jointly committed generating units their capacity in units located outside of their service territory, but to provide for the various transactions between the parties essential to attaining the goal of reliability and economy. This back bone system is shown on Exhibit A which was Exhibit A of the Memorandum of Understanding. This Exhibit shows, specifically, a 345 kV line from the substation labeled " Beaver" to a location identified as "TE Site", later known as Davis-Besse.
It also shows that the "back bone" (Required CAPC0 Group EHV i
_ to _
Transmission Facilities) extends to locations within each of the parties' service areas (Lemoyne in TE territory, Juniper in CEI territory, Star in OE territory and Ewing in DL territory).
This back bone ultimately came to be designated as consisting of "CAPCO Lines" and "50% CAPCO Lines".
The Memorandum of Understanding also includes specific desigr * 'on of the investment responsibility for the facilities of the "back bone" system.
This system consisted not only of 345 kV transmission lines but an appropriate allocation of 345 kV substation facilities.
The general basis for sharing investmen't responsibility, not only in the "back bone" system, but in lines subsequently agreed to be required, is that each company should carry respon-sibility in proportion to its share of the peak load of the group.
The investment responsibility for the "back bone" eystem considered all of the facilities as a group and a share of the total investment was determined for l
each party. OE chose to undertake total financial responsibility for certain facilities that existed at the time.
These facilities are the Sammis-Star (North) line, the Star-Beaver line and its share of the Star-Juf.per line.
Financial responsibility for these facilities basically fulfilled OE's share i
of the total financial responsibility and so the responsibility for tne remaining back bone facilities was shared by only CEI, DL and TE.
As a result the responsibility for the Beaver-Davis Besse line is shared 48% CEI, 32% DL and 20% TE.
Responsibility for construction of CAPCO lines and subsequent ownership rests with the company in whose service area the facility resides.
Similarly, operational responsibility for operation and maintenar.ce rests in the owning company.
The Memorandum of Understanding provides that appropriate payments be made to the owner of a CAPC0 facility to cover annual fixed charges based upon levelized factors of cost of money, Federal income taxes, depreciation, insur-.
?
ance and appropriate state and local taxes. Operation and maintenance costs are allocated on the same basis as investment responsibility and paid to the party incurring such costs.
In November 1971 the parties signed, efteetive as of September 14, 1967 (the date of the Memorandum of Understandin.u), the CAPC0 Transmission Facilities Agreement, heretofore filed in connectic3 with Amendment No. I to the Centerior filing on Form U-1, and identified therein as Exhibit O.
The purpose of this Agreement is to " provide for the instsitation on the system of the Parties an adequate transmission network, and the operation and mainte-nance thereof, which will 1) permit the utilization by the parties of their various capacity entitlements in generating units fram time to time as pro-vided for pursuant to the CAPCO Basic Generating Agreement among the parties, (Writer's note: A CAPC0 Basic Generating Agreement has never been executed but the parties have proceeded under the Memorandum of Understanding as if it were a Basic Generating Agreement), 2) pe rmit the Parties to meet their obli-gations to each other as provided for pursuant to the CAPCO Basic Operating Agreement, 3) provide a means for more effective coordination with other systems, power pools and coordination groups, 4) provide a high degree of operating flexibility under a wide range of contingencies with respect to the foregoing, and 5) achieve an equitable sharing of tha resulting benefits and responsibilities including investment responsibilities, operation and mainte-nance expenses."
The CAPC0 Transmission Facilities Agreement has no termination date except by mutual agreement of all parties.
Important provisions of this Agreement are Article 5 and 6.07.
Article 5 covers Individual Transmission q
facilities, which is defined as bulk power transmission facilities of the parties other than CAPCO lines.
This article provides that Individual Trans- - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _
mission facilities are mutually available for the purposes of the CAPCO Trans-mission Facilities agreement, which includes activit.fes pursuant to the CAPCO Operating Agreement. This section also provides that if the use by others of Individual Transmission facilities of a party 'esterially interfere (s)" with the owning party's use of such facilities, the matter shall be considered by the CAPCO Executive Committee to determine what action should be taken to eliminate the interference.
Similiarly, Section 6.07 provides that CAPCO lines shall also be available for individual use of the parties, provided that material interference does not result, and as in the case of Individual Transmission, the Executive Committee shall determine the action to be taken in the event of laterferente.
Subsequent to the execution of the Memorandum of Understanding, the CAPCO Parties committed a number of additional generating units an' transmis-sion facilities. The generating units so-committed are:
Subsequent Generating Unit Coumitments Ultimate Constructor Ownership (MW)
Designation Capacity (Operator)
Location CEI DL OE' TE Mansfield 1 780 MW PP Ohio River 51 228 501 Mansfield 2 780 MW PP Ohio River 223 62 360 135 Mansfield 3 800 MW PP Ohio River 196 110 335 159 Beaver Valley 2
833 MW DL Ohio River 204 114 349 166 Perry 1 1205 MW CEI Lake Erie 375 165 425 240 East of Cleveland Perry 2 900 MW TE Lake Erie Class Davis Besse Each Erie County 1100 MW OE Lake Erie 1.
PP - Pennsylvania Power Company, an Af filiate of OE 2.
Construction Suspended t
1&2 Each OE Erie County OE Service Area During this same period, a number of additional 345 kV transmission facilities were committed. Exhibit BB shows the 345 kV transmission system in Northern Ohio as it existed as of December 31, 1985. Many of the lines shown on Exhibit BB that have been added since the cowaitments of the Memorandum of Understanding are CAPC3 and 50% CAPC0 lines while others are Individual Lines.
Taken altogether these lines, along with facilities of others, form an exten-sive extra high voltage network supported by a network of individually owned lower voltage transmission lines.
In January 1975 the CAPCO Basic Operating Agreement was executed.
Thic Agreement was extensively amended in September 1980 and remains in effect in that form with minor subsequent Amendments. This Agreement was heretcfore filed in connection with Amendment No. I to the Centerior filing of Form U-1, and was identifiad therein as Exhibit Q.
The purposes of this Agreement are "to provide for the coordinated operation of the systems of the Parties, so as to 1) provide for the utilization by each of the Parties of facilities hereto-fore provided for by the Parties;
- 2) provide a degree of mutual support; 3) provide for capacity and energy transactions by and among the Parties; 4) permit coordination of the operation of the systems of the Parties; and 5) achieve an equitable sharing of the responsibilities, risks and expenses and of the resulting benefits of coordinated operation of the systems of the 4
Parties."
One of the provisions of the Basic Operating Agreement, Article 4, established the CAPCO Coordinating Office in Massillon, Ohio. A principal 3.
Projects Terminated __________ _
function of the Office is "To
- collect, record and disseminate operating information as may be assig ted by the Operating Committee."
In addition to outlining principles of interconnected operation, the Basic Operating Agreement contains Service Schedules, each of which provides the characteristics and cost basis for a specific class of interconnection transactions. The following Service Schedules are currently in ef fect:
Schedule A CAPCO Back-Up Power Schedule B Short Term Power Schedule C Non Displacement Power Sched.d.e D Economy Power Schedule E Unit Power Schedule G Emergency Power Schedule H Transmission of Non-CAPCO Power Schedule I Replacement Power Schedule F identifies the codponents of "Out-of-Pocket" cost and is not a Service Schedule as such.
I l
The CAPCO Transmission Facilities Agreement and the Basic Operating Agreement are complementary.
The Transmission Agreement not only establishes the facilities but also the basis for cost-sharing necessary to establish the rights, privileges, and responsibilities of the parties for use of the trans-mission system to execute the transactions provided for in the Basic Operating Agreement.
The CAPCO 345 kV network is substantial, consist.'ng of many miles of circuits costing millions of dollars.
The sharing of investment responsibil-ity is also a major undertaking. For example, in 1985, CEI paid to the other CAPCO systems about $6.5 million representing its share of the fixed charges, operation and maintenance for CAPCO lines owned by other systems. Each of the __
CAPCO systems, in turn, made similar payments to the others.
In return, each enjoys the right to conduct coordinated transactions among themselves accord-ing to the Basic Operating Agreement over the physically interconnected system. Again, these rights are not subject to termination except by mutual agreement of all CAPCO parties.
Transmission Facilities The service area of CEI is in northeast Ohio and that of TE in north-west Ohio.
Between these areas lies a portion of the OE service area.
Although this service area of OE is interposed, it is physically intercon-nected by 345 kV interconnecting lines extending from CEI's Ave.n Lake power plant and TE's Davis-Besse powe r plant.
Each of these power plants is electrically integrated into the system of the respective Operating Company.
Exhibit CC shows details of physical ownership and the agreed basis for sharing financial responsibility of transmission facilities which connect CEI and TE.
While the Davis-Besse to Beaver 345 kV line and #2 Avon-Beaver line are CAPC0 facilities whose financial responsibility is shated in the percentages shown, the #1 Avon-Beaver 345 kV line is a bi-lateral interconnec-tion between CEI and OE and as such is an Individual Transmission facility.
As is customary with bi-lateral interconnections, the ownership of #1 Avon-Beaver is divided by sections.
Financial responsibility follows ownership in this case, but ownership of a section of an interconnection entitles each party to use of the entire length of the line.
Similarly, assumption of the assigned financial responsibility for CAPCO and 50% CAPCO lines affords the physical interconnections which entitles one to use the entire network of CAPCO, 50% CAPC0 and Individual Transmission lines, subject to the provisions of the CAPCO Transmission Facilities Agreement and the CAPC0 Basic Operating Agreement.
16 -
The CAPCO Transmission Facilities Agreement provides for use of the CAPCO and Individual facilities by the individual CAPCO systems, for their individual purposes. As stated above, such use is subject to the limitation that it not result in " material interference" with uses of the CAPC0 Group and Individual facility owners (Sections 5.04 and 6.07).
One method for determin-ing whether " material interference" is likely to exist is to simulate system operation over a range of circumstances and examine the relationships of specific facility electrical loading to the electrical rating or capability of those facilities. Some technical studies were undertaken to determine if the proposed ir.tegration and coordination of CEI and TE bulk power operations would approach " material interference."
Exhibits DD and EE summarize the studies of the transmission that were reviewed.
Based on an ample margin between facility loading levels and l
l i
facility ratings it can be concluded that for a range of operating conditions l
ranging from normal to extreme emergency conditions, the integration of CEI 1
and TE operations will not result in " material interference" with 03's use of its transmission facilities.
Exhibit DD, which is labeled Case 1, represents essentially normal peak load period conditions.
Shown on the diagram, for each 345 kV line, is the electrical loading, expressed in megavolt-ampere (MVA) with an arrow show-ing direction of power flow.
In addition, the two numbers below the loading are the electrical ratings of the 345 kV line and its terminal equipment expressed in hVA for summer normal and summer emergency conditions.
In paren-theses, for each line, the loading is expressed as a percentage of the normal and emergency ratings.
This power flow transcription depicts peak 1985 summer flows on the CAPCO lines between TE and CEI.
For the purpose of this analy-sis, the Davis-Besse operating unit is assumed to be in service (880 HW) and _ - _ _ _ _ _ _ _ _
TE is transferring 452 MW to CEI (CEI's share of Davis-3 esse). The CAPCO 345 kV lines between CEI and TE are lightly loaded and large transmission system margins for additional transfers between TE and CEI exist. The heaviest loaded line is the Davis-Besse to Lemoyne 345 kV line which is loaded to 53%
of its normal and 43% of its emergency rating.
The loading of this line is primarily a function of the Davis-Besse Unit output.
Exhibit EE shows the results of a study of higher level power trans-fer between CEI and TE.
For each 345 kV line asstuned to be in operation a loading expressed in MVA, with power flow direction indication is shown.
In addition, since this study is predicated on the operational outage of the 343 kV connections between Beaver and Davis-Besse the loadings on the underlying 138 kV transmission are also shown on Exhibit EE.
Summer normal and emergency ratings are also shown for each 138 kV transmission line. This powe.r-flow transcription is a " worst TE-CEI transfer case scenario" developed to stress the transmission system between TE and CEI.
All of the TE system generation is out of service and the entire TE load of 1400 MW is supplied from the CEI system.
In addition, the Beaver to Davis-Besse 345 kV CAPCO Line is taken out of service to stress the underlying 138 kV transmission system.
No loading problems exist on the 345kV or underlying 138 kV system for this transfer condition, and every line has a significant margin between its loading level and its rating.
Transfers from TE to CEI do not stress the transmission system as severely as the illustrated CEI to TF t ansfer condition because TE to CEI power transfers counterflow the normal 138 kV system flows. Also, the maximum power TE has available to transfer to CEI is only 600 MW (based on existing TE load and generating capability). _ _ _.
The transmission system is under continuous study to detect the development of conditions which compromise reliability. Appraisals and other studies of the northern Ohio area have indicated that the area is not now nor is it expected to be under tight transmission conditions and that ample margin cxist. The studies cited above show the ability of CEI and TE to undertake further coordination and integration of their facilities utilizing the physi-t cal interconnections that exist.
The margins shown by these studies are eufficient to undertake any and all transactions envisicoc.d or remotely possible as a part of the economic coordinated operation of the CEI and TE l
eystems.
Integrated and Coordinated Operation i
Interconnected, electrically parallel operation of the alternating-current bulk power systems of North America is governed by the laws of physics, by contractual arrangements entered into by various combinations of participants and by voluntarily following guidelines established by the indus-try.
These guidelines are recorded in the Reliability Criteria for Intercon-nected Systems Operation of the North American Reliability Council.
Control of electrical energy production and the necessary instantane-ous matching of production output to consumer requirements is achieved by the subdivision of the interconnected grid into Energy Control Areas.
In general, an Energy Control Area consists of a group of generating units together with a group of electric energy consumers.
Instantaneous matching of supply with demand is achieved by monitoring the instantaneous utsmatch of supply and demand, thereby generating a control signal for adjustment of generation out-put.
This mismatch is detected as tha instantaneous energy flow into or out of an Energy Control Area with respect to the remaining interconnected net-work. This mismatch, called Area Control Error, must recognize the possible,.
existence of an intentional net flow inta or out of an Energy Control Area.
Such an intentional net flow would be the result of Scheduled Interchange.
Energy Control Areas in the United States of ten are coincident with a utility's ownership of generating facilities and the utility's customer ser-vice area. In some cases Energy Control Areas include generating facilities i
owned by more than one utility, in other cases facilities of a single utility might be split between two or more energy Control Areas. An example of the latter includes Carolina Power & Light which is an integrated utility with two geographically remote Energy Control Areas.
Other examples of utility opera-tions split between two or more Energy Control Areas are utilities which share ownership of generating units.
In CAPCO, CEI owns 470 MW of generating capa-city in the OE system Energy Control Ares, 445 MW in the TE Energy Control Area, 305 MW in the Pennsylvania-New Jersey-Maryland Interconnection Energy Control Area and when Beaver Valley #2 unit is in operation, 204 MW in the DL Energy Control Area. Access to the output of these generating units located in the Energy Control Areas is achieved by arranging scheduled Interchange with the appropriate Energy Control Area.
Significant contributions to economy and reliability have been attained in the United States through the coordination of operations between Energy Control Areas. The limit to the attainment of economy lies in the extent to which the managements of Energy Contrcl Areas share goals, proce-dures, management systems and corporate culture.
There is a need to be assured that all costs of undertaking a system operation transaction to the benefit of another system are fully recognized and covered, and subject to an equitable sharing of benefits.
It is important that cost accounting schemes supporting operation coordination be at least compatible and that agreement exists between parties as to the appropriateness of cost components and the.
basis for their establishment.
Achieving totally integrated and coordinated operation also can involve undertaking frequent and small changes in operating status for the benefit of others. Closeness of management goals would promote such transactions. At arms length, unaffiliated managements would be more inclined to undertage each transaction on ite own merits, while affiliated managements are able to integrate the costs and benefits of several phases of operations.
The customccs of the CAPC0 systems have b2nefited from coordination of bulk power operations.
The generation dispatching function of each of the systems is responsible for optimizing the utilization of the capacity resources et its disposal.
Each system carries out this responsibility by establishing a program for maintenance of its facilities, by designating which of its available generating units to deploy for each peak period, including its share of jointiv-owned capacity, by allocating the instantaneous load of l
its customers among its generating units operating at the time and by contact-ing the other CAPCO systems and other systems with whom it might be intercon-nected to explore and exploit opportunities for coordination by means of Scheduled Interchange transactions.
The CAPCO Coordinating Of fice fills a useful function in this pro-cess, acting in its capacity as an information and record center.
Instead of each owner of a jointly-owned unit contacting every operating company sharing ownership of such unit to arrange scheduled output and the resultant Scheduled Interchange, the CAPC0 Coordinating Office gathers and collates these requests and supplies the desired net total unit loading to the operators of the jointly-owned unit and also provides Net Scheduled Interchange data to all parties.
In the process, this data is recorded for later use by the Operating Party in assigning responsibility for fuel cons umed and for accounting for.
transmission losses. Transactions between pairs of CAPCO parties pursuant to Schedules of the CAPCO Basic Operating Agreement are arranged by the parties l
involved. When such a transaction is agreed upon it is executed by parties by modifying their Ne. t Scheduled Interchange.
Each transaction is reported before-the-fact to the CAPCO Coordinating Office. This information keeps all of the CAPCO systems informed of the use of the CAPCO network and is used to establish balances in the CAPC0 transmission loss banking system.
The operations of CEI and TE have had some level of coordination under the system outlined above. Corporate affiliation will result in changes in many of the procedures currently employed and will result in savings to the combined group of customers of the companies.
The overall operational objec-tive or Centerior's system operations will be to attain the lowest overall i
cost for the combined group of customers.
CEI and TE will each individually be regulsted by the Public Utility Commission of Ohio (PUCO). Accordingly the benefits of such operation will be realized by customers of the two operatir.g companies in accordance with the orders of the PUCO.
Because existing agree-ments, specifically the CAPC0 Transmission Facilities Agreement and the Basic Operating Agreement, are sufficient to achieve the degree of integration envisioned, coordinated and integrated operation of the CEI and TE facilities under Centerior direction will be implemented under the provisions of those agreements.
A number of areas of benefits resulting from integrated and coordi-nated operation of the bulk power facilities of CEI and TE are described in Exhibit C of the first amendment to the U-1.
The following will describe the proposed method of operation and relate it to the benefits achieved by econom-ical and efficient interconnected and coordinated cperation of the facilities of CEI and TE.
Section I of Exhibit C :o the first amendment to the U-l des-.
cribed seven areas from which the full integration and coordination on the basis of a single system will produce benefits to the customer by affiliation.
Much of this coordination will be the responsibility of the Centerior System Engineering and Operations function. This function will have as an objective attainment of lowest overall cost to the consumer of the use of the generating facilities of the two operating companies.
1 A Ccnterior-administered function which will contribute to economic operation as a single interconnected and coordinated r.ystem will be a coordi-nated maintenance schedule for the generating units of the two operating com-panies. The present practice is for each operating company to develop a schedule for maintenance outages of generating units based on the analysis of its own requirements, costs and benefits.
Coordination between CEI and TE has heretofore been associated mainly with those generating units in which both operating companies have an ownership interest, principally Davis-Besse.
Coordinated maintenance under Centerior will be achieved by the participation l
of the operating companies in identifying generating unit maintenance require-Eents and plans as well as the costs and benefits of each planned outage with interaction of Centerior System Engineering and Operations and the operating companies to arrive at a Centerior-optimized naintenance schedule. This optimized overall schedule can be expected to minimize costs by taking advan-tage of the larger system, and thus more effectively mold maintenance into the valleys of the combined annual load curve.
It is expected to result in lower costs of energy during outage by coordination between the needs of the operat-ing companies and by more effective utilization of maintenance energy banking arrangements that exist with outside systems.
Each day, before the daily load curve begins to rise, the dispatching staffs of CEI and TE each estimate the peak load for that day and, considering. _ - _. _ _ _ _ _ -.
th9 capability of the capacity resources expected to be available to meet that peak, make a determination as to which generating unitc to commit to service for that day to meet the peak.
Following affiliation, it is planned that the dispatching staffs of each operating company will forecast the daily pcak load for their respective areas, communicate with power olant operators in their areas and by interactions under Centerior purview develop an integrated unir commitment for the upcM:ing peak period. This process will result in optimiz-ing of unit start-up costs as well as miniaize physical stress on power plant equipment by reductions in start-ups and shut downs for some equipment.
CEI is a majority owner of the Seneca Pumped Storage Plant.
This plant which operatea on a weekly storage cycle requires a relatively longer term for optimization of its characteristics.
The ability to coordinate, through Centerior, the availabilicy of larger amounts of lower-cust off-peak energy can reduce the dispatching cost of Seneca on-peak generation, thereby reducing total energy costs to its customers.
As explained in Exhibit C of the first amendment to the U-1 it is anticipated that full coordination of off-peak resources and on-peak requirements can produce annual fuel savings of about $1 million.
Similar benefits are expected to accrue through a more fully opti-mized response coordinated through Centerior to unexpected or unusual system conditions such as sudden forced outage of generating units, periods with a significant accumulation of forced outages or of unanticipated higher loads.
A major reduction in production costs achieved through economical operation an an interconnected and coordinated system will occur as a result of hour-to-hour loading of individual generating units that are in operation.
Although CEI and TE will continue to operate as two energy control areas, conducting operations by Scheduled Interchange between them pursuant to the _ _ _ _ _ _ _ _ _ _ _ _ _ _ _.
Schedules of the CAPCO Basic Operating Agreement, certain differences in oper-stin procedures will be introduced. Among these changes will be the revision by both companies of their practices in pricing transactions with each other.
In order to insure optimum dispatch of the capacity of TE and CEI, pricing of these transactions will be the lowest of any interchange transaction.
In practice this will place transactions between the parties at the lowest incre-rental cost following supply of the respective area load and ahead of all other interconnection transactions with other parties.
Another change will involve arranging economy, split savings transactions with each other if any diffferential exists between incremental production costs rather than ignoring potential interchange if the differential is less than 3 or 4 mills per kilo-watthour as is now the case. As reported in Exhibit C of the first amendment to the U-1 it is expected that this change of practice will result in a saving i
in fuel cost of about $2 million per year.
This will result in the two operating systems operating at essentially equal incremental cost. Trans-actions with outside systems will thca be arranged to achieve overall economy for the combined system.
As explained earlier, these kinds of changes in practice are feasible to the extent that interests of the managements of the two operating companies are congruent as in an affiliated arrangement.
1 Initially it is planned to achieve coordination through existing j
1 dispatching organizations under the oversight and direction of Centerior, utilizing existing CAPCO Basic Operating Agreement Schedules.
It is fully anticipated that all savings currently envisioned in coordinated operation of the two operating companies, whether quantified at this time or not, can be realized by this mode of operation.
Changes in organization, facilities or other arrangements will be considered and adopted only if there is a high degree of certainty that they will result in still further coordination, integration and economic operation...
Complete integration and coordination of generating capacity resource ultimately will influence total capacity requirements as system load grows.
As is well known, an increased system size has relatively lower overall capac-ity requirements. Based on some preliminary probability studies described in the Exhibit C to the first amendment of the U-1, it is estimated.that this integration can be expected to result in the deferral by two years, of capac-ity additions that might be contemplated individually.
If, as outlined in Exhibit C, future additions might be 300 MW class coal-fired units the present value of savings in fixed charges could reach $300 million through the year 2000 or levelized savings of $53.4 million per year over the period 1986-2000.
Overall, it is expected that significant near-term as well as long range savings will accrue to the customers of CEI and TE through increasingly coordinated economic operation of their interconnected systems. The provi-sions of the CAPCO Basic Operating Agreement and the CAPCO Transmission Agree-ment make this possible and the planning of specific changes in procedures and staffing to achieve these benefits is underway.
The affiliation transaction is necessary to cause these benefits to be realized.
Summary and Conclusion The generating plants and transmission lines of CEI and TE clearly are physically interconnected.
Upon consummation of the affiliation trans-action that is the subject matter of this application, the generating plants and transmission linea of CEI and TE will, under normal conditions, be operated as a single interconnected and coordinated system. The facilities of CEI and TE are confined to a single area or region. That region, upon consum-mation of the affiliation transaction, will not be so large as to impair the advantages of localized management, efficient operation, and the effectiveness of regulation. _. _ _
Different people might have different opinions as to the specific amount of savings that will be realized by a particular item of change in operations of TE and CEI that will be brought about by the affiliation trans-cetion. However, without regard to such differences of opinion, there is no doubt about the ultimate conclusion of fact - namely - THE PROPOSED AFFILIA-TION TRANSACTION THAT IS THE SUBJECT MATTER OF THIS APPLICATION WILL SERVE THE PUBLIC INTEREST BY TENDING TOWARD THE ECONOMICAL AND EFFICIENT DEVELOPMENT OF AN INTEGRATED PUBLIC UTILITY SYSTEM.
ITEM 6.
Exhibits and Financial Statements.
Exhibit L Morgan Stanley Letter Exhibit M Merrill Lynch Letter Exhibit Y Morgan Stanley Report to the CEI Board of Directors dated June 25, 1985 Exhibit Z Merrill Lynch Report to the TE Board of Directors dated June 25, 1985 Exhibit AA CAPCO Backbone Transmission System Exhibit BB Chart of 345 kV Transmission System in Northern Ohio Exhibit CC Chart of Physical Ownership and Agreed Upon Basis for Sharing Financial Responsibility for Transmission Facilities Exhibit DD Transmission Line Usage in Relation to Capacity Under Normal Operating Conditions Exhibit EE Transmission Line Usage in Relation to Capacity Under Outage Operating Conditions
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SIGNATURE i
Pursuant to the requirements of the Public Utility Holding Company Act of 1935, the undersigned company has duly caused this statement (or amendment) to be signed on its behalf by the undersigned thereunto duly authorized.
CENTERIOR ENERGY CORPORATION By:
/s/
Robert M. Ginn President and Chief Executive Officer Date:
January 24, 1986 I
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APPENDLX II EXHIBIT L MORGAN STANLEY MORGAV STAVLEY & CO.
INCORPORATED.
1231 AVENUE OF THE AMERICAS NEW YORK NEW YORK 10020 October 4,1985 Board of Directors The Cleveland Electric Illuminating Company The Bluminating Building 55 Public Square Cleveland, Ohio 44113
Dear Sister and Gentlemen:
The Cleveland Electric Illuminating Company ("CEI"), The Toledo Edison Company (" Toledo Edison") and Centerior Energy Corporation, a newly formed Ohio corporation ("Centerior"), have catered into an agreement pursuant to which CEI and Toledo Edison will become wholly owned subsidiaries of Centerior. The terms of the proposed transaction are set forth in an Agreement and Plan of Reorgammation, dated June 25,1985, as amended (the " Agreement"), among CEI, Toledo Edison and Centerior, which appears as Appendix I to the Joint Proxy Statement / Prospectus dated October 4,1985 of Centerior, CEI and Toledo Edison (the " Proxy Statement") relating to the transaction. The Agreement provides, among other things, that each outstanding share of CEI Ccmmon Stock will be converted into 1.11 shares of Centerior Common Stock, and each share of Tcledo Edison Common Stock will be converted into one share of Centerior Common Stock (together, th) " Exchange Ratios"). You have asked us whether, in our opinion, the Exchange Ratios are fair to the Common Stockholders of CEI from a financial point of view.
For purposes of this opinion and in connection with our review of the proposed transaction, we hava studied, among other things, the pro forma percentage of Common Stockholders' Equity of Ccnterior which would be owned by present Common Stockholders of CEI. We have reviewed certain publicly available information with respect to CEI and Toledo Edison including, among other things, the historical earnings, cash flows, dividends and book values, both in the aggregate and on a per share basis, as well as the current capitalization of CEI and Toledo Edison. We have studied th9 consolidated financial statements of CEI and Toledo Edison for recent years and interim periods i
to date and certain other relevant financial and operating data for CEI and Toledo Edison available from published sources. We have analyzed published :nformation regarding certain other compara-bla clectric utilities and have compared the operations of CEI and Toledo Edison to these companies i
firam a financial point of view. We have reviewed certain internal financial and operating data, including Anancial projections, provided to us by CEI and Toledo Edison. We have had discussior.s l
regarding the businesses, prospects, facilities and certain assets of CEI and Toledo Edison with l-certain members of their respective managements. We have reviewed and analyzed the ongoing commitments of CEI and Toledo Edison for construction and operation of nuclear power facilities, i
l as members of the Central Area Power Coordinating Group ("CAPCO"). We hm analyzed the pro forma effect of the proposed transaction on CEI's Common Stockholders with respect to prospective earnings, dividends, cash flows and book values, both in the aggregate and on a per share basis. We
{
hava also analyzed the prospectiw pro forma credit statistics of Centerior.
We have reviewed the terms of the Agreement and, to the limited extent publicly available, of l
certain comparable business combinations. We have also reviewed certain market price, trading j
volume and dividend data for CEI Common Stock and Toledo Edison Common Stock from 1978 to date. We have made such other studies and analyses as we deemed necessary.
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i In arriving at our opinion expressed herein, we have taken into account certain strategic benefits arising from the combination as expressed to us by the senior management of CEI. Such benefits include, but are not limited to, the prospects for rationalization of operations and generating
)
capacity among the two companies; diversification of service territory; and economies of future generating capacity additions.
We have read the Proxy Statsment and relied on the information contained therein. We have not undertaken any independent verification of the accuracy or completeness of any information concerning CEI or Toledo Edison which has been furnished to us or other data which we have considered in our review and, for the purposes of the opinion set forth below, have relied upon and assumed the accuracy and completeness of all such information and data.
As you are aware, Morgan Stanley has from time to time rendered various investment banking services to Toledo Edison.
Based on the foregoing, we are of the opinion that the Exchange Ratios are fair to the Common Stockholders of CEI from a financial point of view.
Very truly yours, MOncAN STANLEY & CO. INCORPORATED By: /s/ PETER L. KELLNER Peter L. Kellner Managing Director 4
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APPENDIX III Morrill Lynch Capital Markets inv siment Banking Division one uter:y Raza Te:ecnoce f
165 Broacway 212.637 7455 New York. New Yorx 10080 October 4,1985
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Board of Directors The Tcledo Edison Company Edison Plaza 300 Madison Avenue Tiledo, Ohio 43652 Genti; men:
You have asked us to rander our opinion as to the fairness, from a financial point of view, to the common shareholders of The Toledo Edison Company (" Toledo") of the exchange ratios (the
" Exchange Ratios"), as described in the following paragraph, in a proposed reorganization (the
" Reorganization") as set forth in an Agreement and Plan of Reorganization, dated June 25,1985, as amended (the " Agreement"), among Toledo, The Cleveland Electric Illuminating Company
("CEI") and Centerior Energy Corporation ("Centerior"), a newly formed Ohio corporation.
The Agreement provides, among other things, that Toledo and CEI will become wholly owned subsidiaries of Centerior. Holders of Toledo common stock will be entitled to receive 1.00 share of C2nterior common stock in exchange for each share of Toledo common stock and holders of CEI common stock will be entitled to receive 1.11 shares of Centerior common stock in exchange for each share of CEI common stock. The Agreement establishes the aforesaid fixed Exchange Ratios without any limitations.
In developing our opinion, we have, among other things:
(1) Reviewed the Annual Reports, Forms 10-K and certain other public financial information of Tcledo and CEI for the five years ended December 31,1984; (2) Reviewed the quarterly reports on Form 10-Q of Toledo and CEI for the quarters ended March 31,1985 and June 30,1985; (3) Reviewed certain internal historical and projected financial and operating data provided to us by Toledo and CEI; t
(4) Discussed with the managements of each of Toledo and CEI the operations and future business prospects foreach company; (5) Reviewed the trading activity for Toledo and CEI common stocks, and considered the historical and current market prices of each and their relationship to each other; (6) Reviewed and analyzed the status of current and anticipated future commitments of Toledo and CEI for construction and operation of n clear power facilities as members of the Central Area Fcw2r Coordinating Group ("CAPCO");
(7) Compared the financial performanco and nt.ancial condition of Toledo and CEI with those of c;rtain publicly traded utilities which we deemed to be reasonably similar to Toledo and CEI; (8) Considered the relative contributions of each company on a pro forma historical and projected basis to the combined net income applicable to common stock, book value of common equity, operating cash flow and fixed assets of Centerior; 1
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I (9) Considered the pro forma historical and projected per shtre scrnings, cr.ch flow end divi-dends of Centerior shares to be exchanged for Toledo and CEI shares; (10) Compared the combination ofToledo and CEI with certain other mergers and cequisitior.1 l
which we deemed to have certain characteristics reasonably similar to certain characteristics of the t-proposed transaction; and (11) Reviewed thejoint Proxy Statement dated October 4,1985 in connection with the proposed Reorganwation.
In arriving at our opinion, we also have considered such other factors as we deemed appropriate.
In preparing our opinion, we have relied upon Toledo and CEI'vith respect to the accuracy and completeness of the financial and other information respectively rrovided by each company. We have neither independently verified such information, nor made an mdependent evaluation of any l
of the assets of Toledo or of CEL Based upon the foregoing, it is our opinion that the Exchange Ratios contemplated in the proposed Reorganization are fair, from a financial point of view, to the common shareholders of Toledo.
Very truly yours, MERRILL LYNCH CAPITAL MARKETS Mem11 Lynch. Pierce. Fenner & Smith Incorporated By: /s/ ROBERT A. KING Managing Director e
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E.UlIBIT Y PROJECT ERIE Presentation to the Board of Directors June 25,1935 l
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9 PROJECT ERIE Presentation to the Board of Directors June 25,1935 Table of Contents Page I.
Draft Fairness Opinion 1
II.
Fifty Largest Utilities by Book Value 3
III.
Stock Price Ratios 4
IV.
Recoverable Net Assets 7
V.
Alternative Bases for Exchange Ratios 11 VI.
Valuation Matrix 12 16 VII.
Merger Analysis - Reference Case 27 VI!!.
Merger Analysis - Worst Case l
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D R A F_T_
p]_24/85 i
i
,1935 (Date of Proxy)
Board of Directors The Cleveland Electric illuminating Company The Illuminating Building 55 Public Square Cleveland, Ohio 44113 Sister and Centlemen:
J The Cleveland Electric illuminating Company (" Cleveland"), The Toledo Edison Company (" Toledo") and North Holding Company, a newly formed Ohio Corporation (" Holding"), have entered into an agreement pursuant to which Cleveland and Toledo will become wholly-owned subsidiaries of Holding. The terms of the proposed transaction are set forth in an Agreement and Plan of Reorganiza-tion and Merger, dated June _,1985 (the " Agreement"), among Cleveland, Toledo and Mciding, which appears as Annex I to the Joint Proxy Statement-Prospectus of Cleveland and Toledo (the " Proxy Statement") relating to dated the transaction. The Agreement provides, among other things, that each outstand-shares of Holding ing share of Cleveland Common Stock will be converted into Common Stock and each share of Toledo Common Stock will be converted into shares of Holding Common Stock (together, the " Exchange Rat.ios"). You have asked us whether, in our opinion, the Exchange Ratios are fair to the Common Stockholders of Cleveland from a financial point of view.
For purposes of this opinion and in connection with' our review of the proposed transaction, we have studied, among other things, the pro forma percent-age of Common Stockholders' Equity of Holding which would be owned by present We have reviewed certain publicly available Common Stockholders of Cleveland.
information with respect to Cleveland and Toledo including, among other things, the historical earnings, cash flows, dividends, and book values, both in the aggregate and on a per share basis, as well as the current capitalization of We have studied the consolidated financial statements of Cleveland and Toledo.
Cleveland and Toledo for recent years and interim periods to date and certain other relevant financial and operating data for Cleveland and Toledo available from publisned sources. We have analyzed published information regarding certain other comparable electric utilities and have compared the operations of Cleveland We have reviewed i
and Toledo to these companies from a financial point of view.
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certain internal financial and operating data provided to us by Cleveland and Toledo and have had discussions regarding the businesses, prospects, facilities and certain assets of Cleveland and Toledo with certain members of their respective managements.
We have reviewed and analyzed the ongoing commitments of Cleveland and Toledo for construction and operation of nuclear power facilities, as members of the Central Area Power Coordinating Group ("CAPCO").
We hav.-
cnalyzed the pro forma effect of the proposed transaction on Cleveland's Common Stockhold-rs with respect to prospective earnings, dividends, cash flows and book values, both in the aggregate and on a per share basis, as well as the pro forma effect of the proposed transaction on Cleveland's credit statistics.
We have reviewed the terms of the Agreement and, to the limited extent publicly'available, of certain comparable business combinations.
We have also reviewed certain market price, trading volume and dividend data for Cleveland Common Stock and Toledo Common Stock from 1973 to date.
We have made such other studies and analyses as we deemed necessary.
In arriving at our opinion expressed herein, we have taken into account certain strategic benefits arising from the combination as expressed to us by the senior management cf Cleveland. Such benefits include, but are not limited to, the prospects for rationalization of operations and generating capacity among'the two companies; diversification of service territory; and economies of future generating capacity additions.
1 We have read the Proxy Statement and relied on the information contained therein. We have not undertaken any independent verification of the accuracy er completeness of any information concerning Cleveland or Toledo which has been furnished to us by either of them or other data which we have considered in our review and have relied upon and assumed the accuracy and completeness of all such information and data.
As you are aware, Morgan Stanley has from time to time rendered various investment banking services to Toledo.
Based on the foregoing, we are of the opinion that the Exchange Ratios are fair to the Common Stockholders of Cleveland from a financial point of view.
Very truly yours, MORGAN STANLEY & CO. INCORPORATED By:
PROJECT ERIE Fif ty Largest Utilities by Market Value Company Market Value rompary Market Value 1 Pacific GRE 6338.2 26 Alleg. Power 1678.9 2 So. Calif. Edison 5738.9 2T Clevete.d Electric 1550.5 3 Com. Edison 5410.5 28 San Diego GEE 1534.1 6 Southern company 5282.3 29 No. States Power 1502.3 5 Consolidated Edison 4660.1 30 Potomac Electric 1486.5 0 American Electric power 4433.8 31 Illinois Power 1430.T T T mes Utititles 3632.6 32 Gulf States Utilities 1428.8 8 Pselle Service EEG
- 3461.3 33 NJ. State EAG 1367.0 9 Duke Power 3401.3 34 Utah Power and Lt.
1338.3 10 fPt Grotp 2986.4 35 Wlsconsin Electric 12T2.T 11 Houston Ind.
274T.6 36 fIoride Progress 1251.5 12 Dominion Resources 2766.2 37 P.S. of Colorado 1174.6 13 C:Iddle south utitittles 2648.3 38 New England Electric 1133.3 14 Detroit Edison 2451.3 39 sCAMA Corp.
1093.0 15 Philadelphia Electric 2394.0 40 Duquesne Light 1068.8 13 Cer. tral & S.W.
2341.0 41 oklahoma G1E 1005.8 17 Clegra Mohawk 2322.4 42 Long Island Lt.
895.5 Ca eINED EAST AND W ST 2220.2 43 TECO Energy 876.7 IS Penn. Power and Lt.
1965.3 44 No. Indiana P.s.
808.1 17 Caro. Power ord Lt.
1916.2 45 Delmarva PEL TTT.3 20 Union Electric 1883.9 46 Dayton Power and Lt.
118.4 21 Ohio Edison 1848.8 47 Cincinnati GSE 672.3 22 Arizona Ptblic sve.
1823.3 48 Toledo Edison 669.T 23 Pacificorp.
1807.7 49 soston Edison 647.6 24 tiltimore G8E 1773.9 50 Consumers Power 594.4 25 Northeast utilities 1737.8 NOTE: Market Value as of June 6, 1985.
MORGAN STANILY
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N st E*st XR Jan 1980 17.373 13.625 0.90 Feb 16.123 14.373 0.89 Mar 13.373 14.300 0.94 i
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May 19.123 17.230 0.90 Jun 20.173 17.730 0.87 Jul 19.230 16.373 0.83 Aug 17.623 16.623 0.94 Sep 18.300 16.123 0.87 Oct 16.373 14.300 0.89 Nov 13.300 14.123 0.91 i
Dec 13.873 14 623 0.92 Jan 1981 16.123 14.730 0.91 Feb 16.123 14.625 0.91 Mar D.123 13.623 0.91 Apr 13.873 14.373 0.91 May 16.623 14.873 0.89 Jun 17.230 16.000 0.93 f
Jul 16.230 14.373 0.88 Aug 16.123 14.230 0.88 Sep 13.873 14.250 0.90 Oct 13.623 14.123 0.90 Nov 17.123 16.000 0.93 Dec 16.300 16.000 0.97 Jan 1982 13.873 13.123 0.93 Feb 16.373 16 000 0.98 Mar 17.373 16.750 0.96 Apr 17.873 17.230 0.97 May 17.623 17.230 0.98 Jun 11.000 16.250 0.90 Jul 16.230 13.300 0.93 Aug 18.873 18.000 0.93 Sep 19.230 18.123 0.94 Oct 19.300 18.373 0.94 Nov 20.123 18.730 0.93 Dec 21.000 19.730 0.94 Jan 1983 21.123 19.230 0.91 Feb 21.373 20.123 0.94 Mar 21.873 20,873 0.93 Apr 21.000 19.873 0.93 May 21.300 20.123 0.94 Jun 20.623 20.623 1.00 Jul 19.730 19.)00 0.96 Ay, 20.750 19.373 0.93 Sep 21.750 11.230 0.98 Oct 21,000 20.873 0.99 Nov 19.230 19.230 1.00 Dec 18 400 18.623 1.03 Jan 1984 17.730 17.373 0.98 Feb 17.87) 17.300 0.98 Mar 17.873 17.37f 0.97 Apr 14.000 14.000 1.00 May
!$.750 13.300 0.98 Jun 13.123 13.750 1.04 Jul 13.750 14.750 1.07 Aug 13.000 16.000 1.07 Sep 17.373 18.000 1.04 Oct 17.373 18.730 1.08 Nov 18.000 19.625 1.09 Dec 18.873 19.300 1.03 Jan 1983 17.373 18.873 1.09 Feb 18.230 19.873 1.09 Mar 18.373 20.873 1.14 i
Apr 18.123 20.873 1.13 l
May 17.750 21.373 1.20 3un 21 19.000 22.373 1.18 l
n -n n-n.n mu
...g-L... r. s v..
(411 $1816 E46% $31'!483e E4I6I If44.4Si k.e'4}el nest East E I sete i ee.
4 sees ast;;
l'!
!!.141 21.2!
- l.112 ~
1:
16.1.1
.v. h 1.Ils
!?
14.375 n.!?:
1.11:
li Is.59v ev.ist I. lit 15 II.$d 21.v0v 1.10:
1.13:
42 16.250 h.5 5 1.14.
21
- 15. 75 29.7!v 1.12i 24 It.21e 21.ww 1.151 2!
18.250 2v.071 1.144 26 It.500 21.we 1.!!!
1.141 24 10.250 20.875 1.144
- v 16.
- 21 2v.t73 1.152 R4.
I 11.900 20.7h 1.113 2
17.75v
- C. lv 1.15:
3 17.750 20.h0 1.!!!
l.112 1.44:
a 17.s23 2v.;75 1.lis 7
17.B?$ 20.!?!
!.140 6
17.he
- 29. 71 1.164 i
17.!ve 2,.371 1.!ts l':
- 17. W 26.* t-1.l*l
- .!!i 1.111 1.14:
!?.500 IJ. 10
- 1. !!:-
14
!*.Se iv..at 1.11:
15 11.h0 2..ai!
1.175 16 17.7:e 21.12' l.19v 17 IE. h 22.vW l.242
- . i's 1.1:4
- .l!!
iv.
II.2b el.15v 1.15 21 li. d 21.vw 1.11:
22 li. :5'e 41.vw 1.si 23 17.75) 29.20 1.16; la li.s25 2v.c21 1.!*v 1.125
- .i '
a.ls:
?
27 17.s25 2v.2:5 1.l!"
di 17.sl5 20.2t!
- 1. th 24 17.t2 2v.750 1.177 IC 13.375 41.115 1.41e 31 17.750 21.37 1.204 1 174 1.l**
!.173.
he 17.1.5 21.??i 1.1,n 4
11.275 21.5t e
!.M3 1
16.2 5 41.12t 1.111 18.250 21.a25 1.165 7
1t.250 2:.625
!.Iis 1.Ili 1.li.
- 1. It..
10 16.099 21.t;!
1.hl 16.900 21.625 1.2vl 12 11.0v9 21.75v 1.hi 1;
16.121 21.uS 1.191 14 19.375 21.s25
.177 1.!!6 1.191 1.114 17 IB.75v
~1.7tv
- .lsv 4
18 19.250 10.125 1.141 15 19.25v 22.17!
1.lai 20 19.500 22.375 1.147 2:
11.vw 24.375 1.173
!.159 1.176 1.150 22 19.125 22.5%
1.176 Average 16.096 21.091 1.16s
l PROJECT ERIE calculation of Recoverable Net Assets (SMillions except per share)
East West 12/31/84 3/31/85 12/31/84 3/31/85
'aported Co==en Equity
$1,592.8 $1,577.3
$814.0
$889.4
,dditions:
Tax Reserves--Cancelled Projects 18.3 18.0 12.6 12.3 RacGrves to be Reversed 8.1 8.1 Unn=ortized ITC 265.4 266.1 48.9 54.4 Una=ortized TET Proceeds 22.6 22.3 DafGrred Taxes-Accel. Depr.
197.1 229.5 122.1 122.7 toccvarable-Net Assets
$1,352.1 $1,334.3
$504.4
$575.0
=c
============
- $mmon Shares Outstanding at End of Period (000) 74,040 75,138 34,258 37,670 tccovarable Net Assets Per Share S18.26
$17.76
$14.72
$15.26
====================
42=D3 Book Value Per Share
$21.51
$20.99
$23.76
$23.61 LNA 20 Percent of Book Value 84.9%
84.6%
62.0%
64.7%
Emplied Exchange Ratio (Wact Shares ~ per East Share) 1.240 1.163
---,========
I
- e:
Excludes Perry 1 cnd Seaver Vallay 2 Disallowancos.
PROJECT ERIE Calculation of Reccvtrable Net Assets
($ Millions except per share)
East West 12/31/84 3/31/85 12/31/84 3/31/85 ppartcd Co==en Equity
$1,592.S $1,577.3
$814.0 5889.4 dditions:
Tax R3 serves--Cancelled Projects 18.3 18.0 12.8 12.3 R300:ves to be Reversed 8.1 S.1 Una=ortized ITC 265.4 266.1 48.9 54.4 Unn=ortized TBT Proceeds 22.6 22.3 DafGrred Taxes-Accel. Depr.
197.1 229.5 122.1 122.7 I
i l
c5verable-Net Assets
$1,618.7 $1,604.0 S707.3
$781.9
====
o===
=======n c==en Shares Outstanding at End of Period (000) 74,040 75,158 34,258 37,670 ccovCrable Net Assets Per Share
$21.86 S21.35
$20.65 S20.76
==
====,w
==
=st Book Value Per Share S21.51
$20.99 S23.76
$23.61 h:AGDPercentofBookValue 101.6%
101.7%
86.9%
-87.9%
mplicd Exchange Ratio (W30t Shares per East Share) 1.059 1.029 i
PROJECT ERIE 5,
Alternativt Bases for Euchrnet R$tia Earmiacs eer $5a e Book Value per 55are Dividenes 55a*, (2)
Sest East X R (1) west East x R (1)
Sest East X R (1)
Latist 12 mes.
$ 3.73
$ 3.61 0.96x
$23.61 ( 3) (21.00 0.39x
$2.52
$2.52 1.00m 1984 3.70 3.64 0.93 23.76 21.51 0.91 2.52 2.43 0.96 1933 3.50 3.23 0.94 24.12 20.79 0.86 2.46 2.31 0.94 1932 3.13 3.01 0.95 23.33 19.86 0.84 2.38 2.19 0.92 1931 2.77 2.52 0.91 23.46 19.63 0.34 2.30 2.*8 0.90 1980 2.56 2.26 0.33 23.77 19.72 0.33 2.20 2.00 0.91 1979 2.65 2.42 0.91 24.15 19.33 0.82 2.20 1.92 0.17 1973 2.73 2.20 (3) 0.79 24.29 19.69 0.81 2.14
- .14 0.86 1977 2.95 2.91 (4) 0.99 24.02 19.57 0.11 2.12 1.76 0.33 1976 2.32 2.38 0.34 22.35 13.04 0.79 2.12 1.71 0.31 1975 3.29 2.11 0.64 22.39 17.25 0.77 2.06 1.65 0.80 C.C.R. 1975-34 1.3%
4.8%
0.4%
1.9%
- 2. 2%
- 4. 4%
1050-34 12.4 12.9 0.3 2.3 3.4 5.1 Cash Flow per Share Market Value per Share (4)
Tantible Book value Per Share t est East X R (1) 4est East X R (1) 4est East XR (1)
Lat:st 12 mos.
$ 2.36
$ 3.67 1.56x
$19.250 (5) $22.125 (5) 1.15x
$15.26 (3) $17.76 1.16x 18.100 (6) 20.000 (6) 1.10 20.76 (7)
- 21. 35 (7) 1.03
!!T6 2.52 3.61 1.43 17.250 17.750 1.03 14.72 18.26 1.24 20.65 (7) 21.3 6 (7) 1.06 1933 2.36 4.38 1.53 20.875 20.000 0.96 1932 3.23 3.98 1.23 13.625 17.875 0.96 1981 3.66 3.52 0.96 16.500 14.625 0.39 1980 3.96 2.97 0.75 17.250 15.750 0.91 1979 3.97 3.14 0.79 19.875 17.750 0.39 1973 4.42 3.33 0.75 23.375 19.750 0.84 1977 1.68 4.47 2.66 1976 2.52 2.50 0.99 1975 3.92 3.79 0.97
- C.C.R.1975-84 (0.2)%
!.8%
1930-84 (10.9) 6.3 2.4%
5.7%
NOTE:
(1) Exchange Ratios ("XR") are presented as the number of TED shares to be paid per CVX share.
(2) West's next ex-dividend date is expected to be 7/3/35.
East's next ex-dividend date is cxpected to be 7/17/85.
(3) Adjusted for 3.0 mi!! ion common snare o!!ering on 4/4/85.
-(4) Estimated median trading price in period, except where r.oted.
I (5) Closing price at 6/13/85, (6) Estimated median trading price for period 1/1/85 to 6/18/85.
(7) Excludes Perry 1 and 3eaver Valley 2 disallowances.
l i
PR2 JECT ERIE aslative Valuation Matrix - West Perspective Implied Ratio of Implied Price to:
X increase (Decrease) In:
'tive Price per en9e West Market 3/31/85 3/31/85 1984 L12 1985E 1984 L12 3/31/85 3/31/85 1984 L12 1985E 1984 L12 lo Shire Value Book Ten. Book EPS EPS EPS CFPS CfPS Wook Ten. Book EPS EPS EPS CFPS CFPS l....................................................................................................................
1.20 18.65 98.1%
79.0%
89.8%
5.04 4.93 5.48 T.40 7.90
-18.3%
10.1%
13.0%
14.7%
-15.3%
13.9%
21.2%
1.19 18.80 99.0%
79.6%
90.6%
5.08 4.97 5.53 7.46 7.97 17.8%
9.6%
-12.4%
14.1%
14.8%
14.6%
22.0%
1.18 18.96 99.8%
80.3%
91.3%
5.12 5.02 5.58 7.52 8.03
-17.3%
-9.0%
11.9%
-13.6%
14.3%
15.3%
22.7%
1.17 19.12 100.7%
81.0%
92.1%
5.17 5.06 5.62 7.59 8.10
-16.8%
8.5%
11.4%
-13.11
-13.8%
16.0%
23.5%
1.16 19.29 101.5%
81.T1 92.9%
5.21 5.10 5.67 7.65 8.17
-16.3%
-7.9%
10.8%
-12.6%
13.3%
16.7%
24.2%
1.15 19.46 102.4%
82.4%
93.7%
5.26 5.15 5.72 7.72 8.24
-15.8%
7.4%
-10.3%
12.0%
-12.7%
17.4%
25.0%
1.14 19.63 103.3%
83.1%
94.5%
5.30 5.19 5.77 7.79 8.32 15.3%
-6.8%
-9.7%
11.5%
-12.2%
18.2%
25.8%
1.13 19.80 104.2%
83.9%
95.4%
5.35 5.24 5.82 7.86 8.39
-14.8%
6.2%
9.1%
10.9%
-t1.7%
18.9%
26.6%
1.12 19.98 105.1%
84.6%
96.2%
5.40 5.29 5.88 7.93 8.47 14.2%
5.6%
-8.6%
10.4%
-11.1%
19.7%
27.3%
1.11 20.16 106.1%
85.4%
97.1%
5.45 5.33 5.93 8.00 8.54 13.7%
5.1%
-8.0%
9.8%
-10.6%
20.4%
28.2%
1.10 20.34 107.1%
86.2%
98.01 5.50 5.38 5.98 8.07 8.62 13.2%
-4.5%
T.4%
9.2%
-10.0%
21.2%
29.0%
1.09 20.53 108.01 86.9%
98.9%
5.55 5.43 6.04 8.15 8.70 12.6%
3.9%
6.8% '
-8.6%
-9.4%
22.0%
29.8%
1.08 20.72 109.0%
87.7%
99.8%
5.60 5.48 6.09 8.22 8.78
-12 1%
-3.3%
-6.2%
8.1%
8.8%
22.8%
30.6%
1.07 20.91 110.1%
88.6%
100.7%
5.65 5.53 6.15 8.30 S.86
-11.5%
-2.6%
5.6%
T.5%
-8.3%
23.5%
31.5%
1.06 21.11 111.1%
89.4%
101.7%
5.70 5.58 6.21 8.38 8.94 11.0%
-2.0%
5.0%
6.9%
7.7%
24.4%
32.3%
1.05 21.31 112.2%
90.3%
102.6%
5.76 5.64 6.27 8.46 9.03
-10.4%
-1.4%
4.4%
-6.2%
7.1%
25.2%
33.2%
1.04 21.51 113.2%
91.1%
103.6%
5.81 5.69 6.33 8.54 9.12 9.8%
0.8%
3.T%
5.6%
6.5%
26.0%
34.1%
1.03 21.T2 114.3%
92.0%
104.6%
5.8T 5.75 6.39 8.62 9.20
-9.2%
0.11
-3.1%
5.0%
5.8%
26.8%
35.0%
1.02 21.94 115.5%
92.9%
105.7%
5.93 5.80 6.45 8.70 9.30 8.6%
0.6%
2.4%
4.4%
-5.2%
27.71 35.9%
1.01 22.15 116.6%
93.8%
106.7%
5.99 5.86 6.52 8.T9 9.39 8.0%
1.2%
1.8%
3.7%
-4.6%
28.6%
36.8%
1.00 22.38 117.8%
94.8%
107.8%
6.05 5.92 6.58 8.88 9.48 7.4%
1.9%
1.1%
3.1%
-3.9%
29.4%
37.7%
.110RGatN ST1NI.EY
PROJECT ERIE Ratetive Valuation Matrix - East Perspective Imptied Ratio of Implied Price to:
1 Increase (Decrease) in:
Stiv2 Prics per lange East Market 3/31/85 3/31/85 1984 L12 1985E 1984 L12 3/31/85 3/31/85 1984 L12 1985E 1984 L12 la Share Value Book inn. Book EP3 EPS EPS CfPS CFPS Book len. Book EPS EPS EPS
,CIPS CfPS 1.20 22.80 101.9%
108.6%
106.8%
6.26 6.32 7.13 6.32 6.21 10.3%
4.9%
6.2%
7.2%
8.0%
4.6%
6.4%
1.19 22.61 101.1%
107.T%
105.9%
6.21 6.26 7.07 6.26 6.16 10.0%
4.7%
5.9%
7.0%
7.7%
4.8%
-6.7%
1.18 22.42 100.2%
106.8%
105.0%
6.16 6.21 7.01 6.21 6.11 9.8%
4.4%
5.7%
6.7%
7.4%
-5.0%
-6.9%
1.17 22.23 99.4%
105.9%
104.1%
6.11 6.16 6.95 6.16 6.06 9.5%
4.1%
5.4%
6.5%
7.2%
-5.2%
T.1%
1.16 22.04 98.5%
105.0%
103.2%
6.05 6.11 6.89 6.11 6.01 9.2%
3.9%
5.2%
6.2%
6.9%
5.5%
- T.3%
1.15 21.85' 97.7%
104.1%
102.31 6.00 6.05 6.83 6.05 5.95 8.9%
3.6%
4.9%
5.9%
6.6%
-5.7%
T.6%
1.14 21.66 96.8%
103.2%
101.5%
5.95 6.00 6.7T 6.00 5.90 8.6%
3.3%
4.6%
5.7%
6.3%
6.0%
T.8%
1.13 21.47 96.0%
102.3%
100.6%
5.90 5.95 6.71 5.95 5.85 8.3%
3.0%
4.4%
5.4%
6.11 6.2%
-8.0%
1.12 21.28 95.1%
101.4%
99.TX 5,85 5.89 6.65 5.89 5.80 8.0%
2.8%
4.1%
5.1%
5.8%
6.4%
-8.3%
1.11 21.09 94.3%
100.5%
98.8%
5.79 5.84 6.59 5.84 5.75 T.T1 2.5%
3.8%
4.8%
5.5%
-6.TX 8,5%
1.10 20.90 93.4%
99.6%
97.9%
5.74 5.79 6.53 5.T9 5.69 7.4%
2.2%
3.5%
4.6%
5.2%
6.9%
-8.8%
1.09 20.71 92.6%
98.7%
97.0%
5.69 5.74 6.47 5.74 5.64 7.1%
1.9%
3.3%
4.3%
4.9%
7.2%
9.0%
1.08 20.52 91.71 97.8%
96,1%
5.64 5.68 6.41 5.68 5.59 6.8%
1.6%
3.0%
4.0%
4.6%
7.5%
-9.3%
1.07 20.33 90.9%
96.9%
95.2%
5.59 5.63 6.35 5.63 5.54 6.5%
1.3%
2.7%
3.7%
4.3%
-T.T1
-9.5%
1.06 20.14 90.0%
96.0%
94.3%
5.53 5.58 6.29 5.58 5.49 6.2%
1.0%
2.4%
3.4%
4.0%
-8.0%
9.8%
1.05 19.95 89.2%
95.0%
93.4%
5.48 5.53 6.23 5.53 5.44 5.9%
0.T%
2.1%
3.1%
3.T%
8.3%
10.1%
1.04 19.76 88.31 94.1%
92.6%
5.43 5.47 6.18 5.4T 5.38 5.5%
0.4%
1.8%
2.8%
3.4%
8.51 10.3%
1.03 19.57 87.5%
93.2%
91.7%
5.38 5.42 6.12 5.42 5.33 5.2%
0.1%
1.5%
2.5%
3.01
-8.8%
-10.6%
1.02 19.38 86.6%
92.3%
90.8%
5.32 5.37 6.06 5.3T 5.28 4.9%
0.3%
1.2%
2.1%
2.7%
-9.11
-10.9%
1.01 19.19 85.8%
91.4%
89.9%
5.27 5.32 6.00 5.12 5.23 4.5%
-0.6%
0.8%
1.8%
2.4%
-9.4%
-11.1%
1.00 19.00 84.9%
90.5%
89.0%
5.22 5.26 5.94 5.26 5.1g 4.2%
-0.9%
0.5%
1.5%
2.1%
-9.6%
11.4%
.110RGAN STANILY
West per Erst Isplied
.lctive R;titive Prico per implied Prcjected 1986 khangeEnchs. ige West Erst Dividend 1986 Dividend Pick @
West Value of Value of Total Percent Percent -- -
la R tio share West East Value Owned Owned West East West East 1.20 0.833
$18.65
$702.4 S1,681.2 $2,383.6 29.5%
70.5%
$2.56 53.07 1.6%
15.1E 1.19 0.840 18.80 708.3 1,681.2 2,389.5 29.6%
70.4%
2.56 3.05 1.6%
14.1%
1.18 0.847 18.96 714.3 1,681.2 2,395.5 29.8%
70.2%
2.56 3.02 1.6%
13.1%
1.17 0.855 19.12 720.4 1,681.2 2,401.6 30.0%
70.0%
2.56 3.00 1.6%
12.2%
1.16 0.862 19.29.
726.6 1,681.2 2,407.8 30.2%
69.8%
2.56 2.97 1.6%
11.2%
.1.13 0.8 70 19.46 732.9 1,681.2 2,414.1 30.4%
69.6%
2.56 2.94 1.6%
10.3%
1.14 0.877 19.63 739.4 1,681.2 2,420.6 30.5%
69.5%
2.56 2.92 1.6%
9.3%
1.13 0.885 19.80 745.9 1,681.2 2,427.1 30.7%
69.3%
2.56 2.89 1.6%
8.3%
'1.12 0.873 19.98 752.6 1,681.2 2,433.8 30.9%
69.1%
2.56 2.87 1.6%
7.4%
1.11 C.901 20.16 759.3 1,681.2 2,440.6 31.1%
68.9%
2.56 2.84 1.6%
6.4%
1.10 0.909 20.34 766.2 1,681.2 2,447.5 31.3%
68.7%
2.56 2.82 1.6%
5.5%
1.09 0.917 20.53 773.3 1,681.2 2.454.5 31.5%
68.5%
2.56 2.79 1.6%
4.5%
1.08 0.926 20.72 780.4 1,681.2 2,461.6 31.7%
68.3%
2.56 2.76 1.6%
3.6%
1.07 0.935 20.91 78 7. 7 1,681.2 2,468.9 31.9%
68.1%
2.56 2.74 1.6%
2.6%
0.06 0.943 21.11 795 2 1,681.2 2,476.4 32.1%
67.9%
2.56 2.71 1.6%
1.6%
.05 0.952 21.31 802.7 1.681.2 2,183.9 32.3%
67.7%
2.36 2.69 1.6%
0.7%
.04 0.962 21.51 810.4 1,681.2 2,491.7 32.5%
67.5%
2.56 2.66 1.6%
0.3%
.03 0.971 21.72 818.3 1,681.2 2,499.5 32.7%
67.3%
2.56 2.64 1.6%
1.2%
.02 0.980 21.94 826.3 1,681.2 2,507.6 33.0%
67.0%
2.56 2.61 1.6%
2.2%
'. 01 0.990 22.15 834.5 1,681.2 2,515.7 33.2%
66.8%
2.56 2.59 1.6%
3.2%
000 1.000 22.38 842.9 1,681.2 2,524.1 33.4%
66.6%
2.56 2.56 1.6%
4.1%
AIURGAN.TTANI.EY
PROJECT ERIE R;t:tiva V tuation Matrix ASStmPliONS e
m East West ock Prico 6/21/85 22.375 19.00 x>k V:Lue 12/31/84 21.51 23.76 ok V;tue 3/31/85 20.99 23.61 in. Mook V:Lue 12/31/84 21.81 20.65 in. Book V tue 3/31/85 21.35 20.76 "S 1984 3.64 3.70
>s L12 (3/31/85) 3.61 3.78
)$ 1985E 3.20 3.40 lPS 1984 3.61 2.52 FPS L12 (3/31/85) 3.67 2.36 vg. Conn. Shares 1984 68.191 32.014 vg. Couns. Shares L12 70.411 33.164 vg. Come. Shares 1985E 76.391 37.387 aminon Shirts Out 12/31/84 74.040 34.258 aminon Sh:rcs out 3/31/85 75.135 37.670 936 Dividend (Standalone) 2.67 2.52 ents incre:se to West 0.04 MURGAN STANILY
n ENIIBir g PROJECT TOPHAT l
l-PRESENTATION TO THE BOARD OF DIRECTORS l
4 I
l June 25,1985
C PROJECT TOPHAT PRESENTATION TO THE BOARD OF DIRECTORS TABLE OF CONTENTS PAGE SECTION A TOPHAT AND CHAPEAU HISTORICAL DATA 1-10 1.
Historical Operating Data - Tophat 1
2.
Historical Cash Flow Data - Tophat 2
3.
Historical Selected Financial 3
Ratios - Tophat 4.
Historical Operating Data - Chapeau 4
5.
Historical Cash Flow Data - Chapeau 5
6.
Historical Selected Financial 6
Ratios - Chapeau 7.
Spmmary Shareholder Profiles 7
1 8.
Cross Ow'nership of Common Stock 8
?.
Summary Operating Statistics 9
103 Summary Power Plant Data 10 SECTION B TOPHAT AND CHAPEAU PROJECTED DATA 11-18 1.
Projected Income Statement Data -
11 Tophat 2.
Projected Cash Flow Data -
12 Tophat 3.
Projected Capitalization Data -
13 Tophat 4.
Projected Selected Financial Ratios -
14 Tophat 5.
Projected Selected Income Statement 15 Data - Chapeau 6.
Projected Cash Flow Data - Chapeau 16 7.
Projected Capitalizaticn Data -
17 Chapeau 8.
Projected Selected Financial 18 Ratios - Chapeau
{
l SECTION C PRO FORMA ANALYSIS AND SELECTED 19-33 MARKET DATA 1.
Key Financial Terms of the Proposed 19 Merger of Tophat and Chapeau 2.
Share Price Statistics for Tophat 20 and Chapeau at Current and Imputed j
Market Prices
\\
PROJECT TOPHAT PRESENTATION TO THE BOARD OF DIRECTORS TABLE OF CONTENTS PAGE 3.
Pro Forma Impact Per Share on 21 Tophat Shareholders 4.
Pro Forma Impact Per Share on 22 Chapeau Shareholders 5.
Historical Relative Contribution 23 Analysis 6.
Projected Relative Contribution
~24 Analysis 7.
Combined Income Statement Data 25 8.
Combined Cash Flow Data 26 9.
Combined Capitalization Data 27 10.
Graphs of Monthly Stock Price 28-30 Performance of Chapeau and Tophat 11.
Daily and Weekly Stock Prices for 31-33 Chapeau and Tophat SECTION D UTILITY INDUSTRY COMPARABLE DATA 34-40 1.
Financial Data of Selected 34 Comparable Companies 2.
Ranking of Financial Data of 35 Selected Comparable Companies 3.
Market Data of Selected Comparable 36 Companies 4'
Ranking of Market Data of Selected 37 Comparable Companies 5.
Graphs of Monthly Stock Price 38-40 Performance Comparison l
PH03f CI 10Ph4I Historic:t Operating Dat3 - 10 Pit 41 (5000's)
Compound f or the f or fiscal Year inded December 31 Growth Rata three Months inded for the Iwelve Months E nded 19PO 1981 1982 1983 1984 1983-1984 3/ 31/8 4 3/ 31/8 5 3/ 31/8 5 cting Revenues 1491,868 5442,284 1488,725 5504.616 1551.000 8.2 s
$140,037
$151,608 1562,877 ost of Operitions (a) 237,5t5 229,845 247,330 254,745 277,000 3.9 67.763 75,090 284,327
- s Prefit 164,253 212,t39 234.395 249,871 274,000 F 3.6 22.274 76,538 278,550
.ther Oper: ting E spenses (b) 60.521 68,607 80,099 77.944 84.000 8.5 20,986 21,218 84,232 r:'tig Pr: fit 103.732 143,832 154,296 171,927 190,000 16.3 51,288 55,300 194,318 E3dl latercst (spense (c) 70,866 86.310 94,713 108,612 140,000 18.6 31.341 39,088 147.747 used During Construction 43,591 47.989 71.211 96,028 128,000 30.9 27.775 37,545 137.770 illowanca f or f unds lther incune (f apense), Net 879 8.852 3,017 1,817 8.000 73.7 1,064 3.057 9,993
-Tan incame 77,336 114,363 13l,811 160,960 186,000 24.5 48,786 56,814 194,334 ncome Irsas (8enefit) 10,158 31.126 26.277 32,616 32,000 33.2 10.203 9.138 31,714
. Incune (itss) 67,178 83.237 C05,534 128,344 154,000 23.0 38,583 47,676 162,6?0 f errid and Pref erence Stock 18,021 23,542 26,221 30.l29 35,000 18.1 7.82 6 80,230 37,401 lividend flequirements on Pre-
$37
$1?5,219
..... 446 118 1119.000*
24.7 5 530,157
...... 215 alngs Avillible for Common Stock 549,157 159,695 179,313 rrage Sharss Dutstanding (Ikousands) 19,201 21,507 24,842 28,000 32.1 62 29,892 33,031 33,164 cxings Per Share 12.56 12.77 13.18
%3.50
$3.70 9.6 5 11.0 1 88.13
%). 78 l
) Inci des costs for generation, energs purchased, depreciation and amortisation.
) Includes maintenance and ta.es, other than federal incoaw t eses.
) Including interest capitalizeJ.
rrill Lynct Capitil Markets PROJfCI 10PitAl Historical Cash flow Data 10PitAl (000's) for the for fiscal Year inded December 31 Ihree Months inded for the Iwelve Months in1ed 1980 1981 1982 1983 1984 3/31/84 3/31/85 3/31/85 at I;come
$67.178 583,237 1105,534 1828,344 5154,000 538.583 147.676 1162,C ?0 Liss: Pref erred Dtvidends 18,021 23.542 26,221 30.1 29 35,000 7,8 ?6 10.230 37.404 riuoC 43.591 47.989 11.211 96,028 128.000 27,775 37,545 137.770 Plys: Depr ec iation 26,002 43,427 43.838 51.000 50.000 13.964 13.159 49,195 Def 7rred lanes 29,056 13.295 13.380 19.000 19,000 2.063 15 16,952 Defirred IIC (12,697) 9.466 13.394 9,000 9,000 4.400 5.488 10,088 otil Operating Cash flow Truf pr8M 71D.TI
' DIN..7 169,000 lIU...M IiT.TW TUJ.. AT ommon Dtv6dends Paid 142.297 149,466 159.302 168,880 580.640 118.905 521,822
$87.920 perd t ing C sh f low /
l Common Disidends Pa6d 1.13 a 1.57 a 1.33 a 1,18 a 0.86 a 1.24 a 0.85 a 0.72 a lharzteng Cash flow Per Share 12.50 1 3.62 13.47 12.90 12.15 10.78 10.56 51.92 _
PROMCI 10fteAt Histortcti Selected financtil maties - 10 Peel At or At or for the fiscal Veers faded Decenter 31 for the 12162nths Ended 1980 1981 1982 1981 1984 3/31/05 Coverage and Capitalization pation Pre-lan laterest Coverage (a}
l.9 a 2.1 a 2.2 a 2.2 a 2.0 a 2.0 a Operating Cash flou(b)/ tong-tern Debt 0.1 0.1 0.1 0.8 0.8 0.8 Net langible Assets (c)/ tong-lere Debt 2.3 2.4 2.4 2.4 2.6 2.5 Operating Cash fle (bl/ Preferred Slvidends 266.0 330.9 300.2 269.5 19 7.1 170.3 Operating Cash Ila.(b)/ Comma Dividends Paid 113.3 157.5 132.7 117.9 85.6
??.4 lotal Debt (d)/ Shareholders' Espity (e) 116.0 s 104.6 5 105.7 5 100.5 1 103.2 1 IM.2 s lotal Debt (d)/fotal Capitalliation (f) 5 7..'
53.3 ~
53.0 50.9 53.0 54.6 Profitability Ratios Return on Average lotal Capitallration (g) 5.1 s 5.6 5 6.4 5 6.8 s 7.2 5 7.4 s Return on Average Commun Equity (h) 10.8 11.6 13.6 14.7 15.6 16.0 Return on Average lotal Assets (l) 4.2 4.7 5.3 5.7 5.8 5.9 AfU0C (j) as a s of net incase 64.9 s 57.7 s 67.5 5 74.0 s 83.8 s 84.5 s 4
utility Plant Rat tos (WIP as s of Shareholders' Equity 108.35 819.45 142.4s 156.3s tel.trs 176.3s CWIP as s Net Plant e CWIP 34.45 39.4s 46.25 52.0s 59.11 59.6s h
l (a) Pre tas income elus interest empense minus allowance for borrowed funds used during construct ton minus unranitted earn 6ajs of wconsolidated af fil64tes divided by total laterest incurred.
1 (b) Net incane less f referred dividends and AfuGC plus depreciation empense, def erred teses /ad deferred 11C.
(c) Iotal assets less deferred charges.
(d) the total of snort-term and long-term debt.
(e) lhe total of preferred and pref erence stock and cannon shareholders' equity.
(f) Including long term dett.
4 tion.
(g) Net incune divided by everage year-to year total cap 6 tall:
(h
)
larnings available for cr-* Stock d6vided by average year-to year connon equity.
(l'j Net incane divided by average year-to year total assets.
(jl Allouance for f unds used during construct ton..
Norrfli lynch Capiti.I Narkets PROJE C1 10PHAI Historical Operating Data - CMPfAU (5000's)
Campound for ahe f or Fiscal year inded December 31 Crowth Sete ihree Months Inded for the fuelve honths inded 1980 1981 1982 19L3 1964 1980-1984 3/31/84 3/31/85 3/31/85
- Operiting Revenues 5893,566
$1.012.930 ll,100,578 11.210.316 11.215.353 8.0 s
$298.597
$316.357 51,233,113 Cost of Operations (a) 552,789 586,078 584,669 609.612 599,249 2.0 140,386 164.463 623,326 I Grsss Pr: fit 340.777 426,852 523.902 600.704 616,104 16.0 158,211 151,894 609.787 Other Operating t apenses (b) 148,688 166,573 188.593 214.912 222,638 10.6 54,888 54,278 222.028 Operating Profit 192,089 260,279 335,309 385,792 393.466 19.6 103,323 97.616 387.759 lotal Intsrest f apense (c) 112.623 146,712 144,072 152,974 180,864 12.6 39.928 50.195 191.131 Allowance for f unds Usid During Construction 65,924 83.000 104,336 114.542 171,606 27.0 37.518 50,338 184,426 Other income (tapense). Net 21,561 26.742 19,773 27.096 38.779 15.8 7.578 11,369 42,570
- Prs Its Income 166,957 223.309 315,346 373.456 4?2.987 26.2 108.498 109.128 423,624 Income Ittes (Senefit) 27.612 51,450 84.128 104.139 131,355 47,7 28.036 20,229 123,548 Net income Itoss) 139,345 174,859 231,218 269.317 291,632 20.3 80.455 88,899 300.076 Olvidend Aequiraments on Pre-ferrtd and Preference Stock 27.711 34,917 38,2 95 38.426 43,353 II.8 10,900 10.415 42,u68 4
...... 634 5136,942
$192,923 1230,891 12 48,2 79 22.l s 569,555 178
..... 48 4 1257,208
!artings Avtilable for rcamon 5:ock 1111 4
Aver 49e Shares Outstanding (thousands) 46.289 51.055 64.775 65.158 74,0 40 65.693 74.576 74,308
! tarr.ings Per Share
$2.26 52.52 53.01
$1.28 13.64 12.7 2 50.9 4 50.91 13.61 (t) Incl 1 des costs for generation, energy purchased, depreciation and amortirat ton.
(b) includes maintenance and ta.es. Other than federal laceme lases.
(c) f acluding lat erest capitalized.
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POSNCI 10ftl4i Cistorict) Selected finance:I Ratios - CmM AN At or At or for the fiscal Years Inded Decee6er 31.
for the
!? Months Iaded 1980 1981 1982 1983 1984 3/ 31/9 5 Coverage and Capitallration Ratlos Pre-las Interest Coverage (a) 2.1 a 2.2 a 2.8 a 3.1 a 2.9 a 2.8 a Operating Cash flou(b)/ tong-lers Debt
/ tong-lers Debt 0.1 0.2 0.2 0.2 0.2 0.2 set langible Assets (c)
- 2. 5 2.5 2.6 2.7 2.6 2.6 Operating Cash flow (b)/ Preferred Olvidends 507.6 524.6 645.7 779.9 566.1 570.1 Operating Cash flou(b)/ Common Dividends Paid 164.9 184,8 198.1 206.6 149.0 143.1 lotal Debt (d)/ Shareholders' Iquity (e) 109.5 3 101.7 s 93.2 5 87.9 I 96.2 5 97.7 3 l
I lotal Debt (d)/lotal Capitallration (f) 56.0 52.6 49.6 47.9 49.9 50.5 Profitability Ratlos Return on Average total Capitalliatio (g) 5.4 5 6.0 3 7.2 5 7.7 3 8.0 5 8.3 5 Return on Average Connon Iquity (h) 11.3 12.6 15.3 16.1 16.8
~17.4 Return on Average lotal Assets (1) 4.3 4.0 5.7 6.0 6.3 6.4 AIUDC (j) as a s of Net income
$2.6 5 53.3 5 49.9 5 46.6 s 58.8 5 62.0 s utility Plant Ratios CWIP as 5 of Shareholders' fquity 88.95 98.45 104.85 119.35 132.75 140.4s CWIP as s Net Plant e CWIP 30.5 33.0 38.6 43.3 50.0 49.9 (a) Pre-tas incune plus interest empense minus allowance for borrowed funds used during construction minus unranitted earnings of unconsolidated affiliates divided by total laterest incurred.
(b) Net incme less preferred dividends and AluGC plus depreciation empense, def erred tones and deferred !!C.
(c l total assets less deferred charges.
(J i lhe total of short-tena and long tenn debt.
(el lhe total of preferred and pref erence stock and coanon shareholders' equity.
(f I including long term debt.
(g l met income d6vided by average year-to year total capitalization.
in) larmings available for common stock divided by average year-to year connun equity.
i) Net incune divided by everage year-to year total assets.
i 1)) Allowance for funds used duri.ig construct ion.
(
PROJECT TOPHAT Summary Shareholder Profiles Tophat Chapeau Number Number Insiders (a) 34,700 0.091%
113,588 0.151%
Institutions (b)
Bank Trust Portfolios 1,627,051 4.282 7,692,910 10.235 Insurance Companies 787,363 2.072 3,527,423 4.693 Investment Companies 735,500 1.936 1,612,085 2.145 31,200 0.042 College Endowments Total Institutions 3,149,914 8.291 12,863,618 17.114 Other 34,809,731 91.618 62,188,632 82.735 TOTAL SHARES OUTSTANDING (c) 37,994,345 100.000%
75,165,838 100.000%
(a) As of March 18, 1985 for Tophat and as of March 14, 1985 for Chapeau.
Ssurce:
Proxy Statements of respective companies for 1985 annual shareholders' m;etings.
l (b) As of December 31, 1984.
Source:
Vicker's Investment Guide, 4th Quarter.
(c) As of April 30, 1985 for Tophat and May 7,1985 for Chapeau.
Sr.urce: March 31,1985 quarterly reports of respective companies.
f -
Cro:2 Ownar hip cf Comm;n Stock Bank Trust Portfolios:(a)
Tophat Shares Chapeau Shares Number _
Number 1,100 0.048%
13,720 0.018%
8 Araerican Bank & Trust - Pennsylvania American National Chicago 52,000 0.137 118,550 0.158 Bank of New England 87,265 0.230 496,577 0.661 Hankers Trust 189,635 0.499 204,465 0.272 First Pennsylvania Corp.
72,505 0.191 260,830 0.347 South Carolina National 22,401 0.059 21,250 0.028 Wells Fargo 97,558 0.257 211,620 0.282 l
539,464 1.420 1,327,012 1.765 Insurance Companies:(a)
Aetna Insurance 100,000 0.263 26,400 0.035 American National Insurance 42,000 0.111 60,000 0.080 Equitable Life 553,$00 1.457 32,500 0.043 695,500 1.831 118,900 0.158 Investment Companies:(a)
ABT Utility Inc.
90,000 0.237 140,385 0.187 ADV Fund, Inc.
18,000 0.047 17,000 0.023 Fidelity Equity - Income 271,800 0.715 186,100 0.248 Fidelity Magellan Fund, Inc.
126,700 0.333 271,700 0.361 506,500 1.332 615,185 0.818 TOTAL 1,741,464 4.583%
2,061,097 2.742%
TOTAL SilARES OUTSTANDING 37,904,345 100.000%
75,165,838 100.000%
(a)
As of December 31, 1984.
Source:
Vicker's investment Guide, 4th Quarter. _
PROJECT TOPHAT Summary Operating Statistics At or For the Fiscal Year Ended December 31, 1984 i
Pro Forma l
Tophat Chapeau Combined Tctal Customers 271,723 714,768 986,491 KWH Sales by Customer (000's)
Residential 1,958,000 4,446,352 6,404,352 Commercial 1,398,000 4.396,395 5,794,395 Industrial 3,444,000 7,997,000 11,441,000 Other 745,000 433,310 1,178,310 Total 7,545,000 17,273,057 24,818,057 KWH Sales by Customer as a %
cf Total Electricity Sales i
Residential 25.95%
25.74%
25.81%'
Commercial 18.53 25.45 23.35 Industrial 45.65 46.30 46.10
.Other 9.87 2.51 4.74 Total T55 6%
IUD".7%
IITU.T%
Rrridential Sales Data Average KWH per Customer 8,045 6,646 7,019 Average Revenue per Customer
$709.00
$563.60
$602.36 Average Revenue per KWH
$0.0881
$0.0848
$0.0858 Electricity Production Scurces:
Nuclear 28.75%
13.00%
17.73%
Fossu 71.25 87.00 82.21 Total 100.00%
100.00%
100.00%
Nst Received from Others as % of Net Generated 9.89%
13.54%
12.43%
BTU per KWH of Net Output 10,193 10,416 10,348 Full Cost Per Millon BTU
$1.73
$1.63
$1.66
_ _ -f1- -
Summiry Pr.w:r Plant Dits
~
(An cf 12/31/84)
Utility Plant ($MM)
Ch;psiu Tophrt l
Pl nt in Service
$2,909 67.4%
$1,391 54.6%
Less Depreciation Reserve 799 18.5 365 14.3 Nat Plant in Service 2,110 48.9 1,026 TlCf Construction Work in Progress 2,209 51.1 1,520 59.7 Total
$4,319 100.0%
$2,546 100.0%
Construction Costs Through Drcember 1984 ($MM's) g g
Ownership Ownership PY1
$ 990 31,11%
$ 642 19.91%
BV2 630 24.47%
515 19.91%
PY2 340 31.11%
222 19,91%
i Total
$1,960
,$1,379 Estimated Cost to Complete ($MM's)
)
PY1
$ 236 154 BV2 300 253 PY2 N.A.
N.A.
p l
Total
$ 530
$' 407 Generating Capacity-MW (12/31/84) 4,439 1,718 Total Power Plant Investment ($MM's)
$1,676
$ 892 Power Plant Investment /KW
$ 378
$ 519 i
i Estimated Power Plant investment /KW After PY1 in Service (1/1/86)
$ 600
$ 860 After BV2 in Service (1/1/S8)
$ 760
$1,160 I
CWIP/ Book Value 140.4%(a) 176.3%(a)
CWIP/ Net Plant + CWIP 49.9%(a) 59.6%(a)
(a)
As of March 31, 1985. ------.- ----------- - _ _
j
PROJECT TOPHAT 4
KEY FINANCIAL TERMS OF THE PROPOSED MERGER OF TOPIIAT AND CHAPEAU o
Each Tophat common share will be exchanged for 1 common share of the Pro Forma Combined Entity ("Newco").
o Each Chapeau common share will be exchanged for 1.11 common shares of Newco.
o Newco is expectad to pay annual dividends of $2.56 per share.
Quarterly payments at such annualized rate will commence in the first dividend period following the closing of the merger.
m PROJECT 70PHAT SH ARE PRICE ST ATISTICS FOR 70PH AT AND CH APE AU AT CURRENT AND IMPUTED M AarET PRICES 1
J Pro Forma Share PMce Statisttes at Exchange Ratios of one Newco $ hare per o1d Tophat Share and 1.11 Newco Shares per old Chapeau $ hare:
C urrent Share Price Statistics
$19.69 120.48 121.33
$22.26 A. 70PH AT(a)
Book Value Per Share
$23.41
$23.41
$23.41
$23.41
$23.41 Earnings Per Share
$ 3.78
$ 3.78
$ 3.78 5 3.79 5 3.78 Cash Flow Per Share
$ 1.92 5 1.92 1 1.92
$ 1.32 1 1.92 Dividend
$ 2.52
$ 2.56
$ 2.56
$ 2.56 1 2.56 Yield 12.9%
13.0%
12.5%
12.0%
11.51 Current or taputed Price
$19.00
$19.69
$20.48
$21.33 522.26 Current or Imputed Price /
1.00m 1.04x 1.08x 1.12x 1.17x Current Market Price Current or Imputed Price /
0,81x 0.84x 0.88x 0.91x 0.95x Book Value Per Share Current or Imputed Price /
5.03*
5.21x 5.42x
.5.64x 5.89x Earnirgs Per Share Current or Imputed Price /
9.90x 10.25x 10.67x 11.11x 11.59 Cash Flow fer Share
- 8. CH APEAU Book Value Per Share
$20.91
$20.91
$20.91
$20.91
$20.91 Earnings Per Share
$ 3.61 5 3.61
$ 3.61
$ 3.61
$ 3.51 Cash Flow Per Share
$ 3.29 1 3.29 5 3.29
$ 3.29 5 3.29 Dividend 5 2.52
$ 2.84
$ 2.84
$ 2.84
$ 2.84 Yteld I'.35 13.01 12.5%
12.0%
11.55 Current or imputed Prtee
$22.38
$21.85
$22.73
$21.67
$24.70 Received (b)
Current or Imputed Price Received /
1.00m
.58x 1.02x 1.06x' 1.10x Current Martet Price Current or Imputed Prd e Received /
1.07x 1.04x 1.09x 1.13x 1.18x Book Value Per Share Current or Imputed Price Received /
6.20x 6.05 6.30x 6.56:
6.84x Earnings Per Share Current c' Imputed Price Received /
6.80s 6.64x 6.91x 7.19x 7.51x Cash Flow Per Share (a) All Per Share Data is d or for the twelve mor.ths enosd March 31, 1865. Current Market Prices are as of June 21, 1285.
(b) Imputed Prfce Received by Chapeau shareholders is 1.11x taputed Pewco Price.
. s l
i
FROJECT TOPHAT H!storical s
]
Relative Contribution Analyala Ownership cf Pro Forma Company by Forsser Holdera Assuming an Exchange Ratio of One Newco Share for Bach Tophet Share and 1.11 Newco Sharea for Each Chapeau Share:
Tophet Holdera 3.'.29%
Chapeau Holders SS.'ill Relative Contribution At or Rr the Flacal Yeara l
Ending Dece nher 31, y
- 19E3, 1984 1940 1981 1982 Net Property, Plant and Equipment Contribution of Tophet 36.26%
35.93%
36.01%
36.76%
37.09%
Contribution of Chapeau
$3.74%
44.01%
63.90% '
63.24%
$2.91%
Total Common Equity Contribution of Tophet 34.42%
35.43%
33.46%
34.57%
33.82%
Contribation of Chapeau 65.50%
64.57%
66.54%
65.43%
66.18%
Net income Appilceble to Common Stock contribution cf Tophet 28.10%
33.18%
31.64%
32.07%
32.40%
Contributawn of Chapeau 71.90%
$6.82%
$8.s3%
$7.93%
67.60%
Net income Applicable to Common Stock - AFUDC Contribution of Tophet 9.17%
25.566 9.55%
0.00%
(13.30)t Contributbn of Chapeau 90.83%
74.42%
94.45%
100.00%
113.30%
4 Total Operating Cash Flow l
Contribution of Tophet 23.85%
32.04%
25.74%
22.23%
21.95%
Contribution of Chapeau 76.15%
67.96%
74.26%
77.77%
78.05%
i 9
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PROJECT TOPHAT Weekly Stock Prices - CHAPEAU / TOPHAT (6/25/84 - 6/21/85)
Topnat/
Cnapeau/
Date TOPHAT CHAPEAU Chapeau Tophat 12-Apr-85 18.00 21.13 0.85 1.17 19-Apr-85 18.50 21.00 0.88 1.84 26-Apr-65 18.50 21.00 0.88 1.14 03-May-05 17.75 20.50 0.87 1.15 to-May-85 17.50 20.50 0.85 1,.17 17-May-85 18.00 22.00 0.82 1.22 24-May-85 17.63 20.63 0.85 1.17 31-May-85 17.75 21.38 0.83-e.20 07-Jun-85 18.25 21.63 0.84 1.18 14-Jun-85 18.38 21.63 0.85 1.18 21-Jun-85 19.00 22.38 0.85 1.88 9
=
^
PROJECT TOPHAI Daily Stock Prices - CHAPEAU / TOPHAT (6/1/85 - 6/21/85)
Tophat/
Chapeau /
Date TOPHAT CHAPEAU Chapeau Tophat 03-Jun-85 517.88
$21.38 0.84 1.20 04-Jun,95 17.88 21.50 0.83 l.20 05-Jun-85 18.25 21.13 0.86 1.16 06*Jun-85 18.25 2i'.G3 0.84 1.18 07-Jun-85 18.25 28.63 0.84 1.18 10-Jun-85 18.00 21.63 0.83 1.20 ll-Jun-85 18.00 21.63 0.83 1.20 82-Jun-85 18.00 21.75 0.83 1.28 13-Jun-85 18.13 21.63 0.84 1.19 14-Jun-85 18.38 21.63 0.8G l.18 17-Jun-85 18,75 21.75 0.86 1.16 18-Jua-85 19.25 22.33 0.07 1.15 19-J u.. -8 5 19.25 22.38 0.66 1.16 2*"t-J un-8 5 19.50 2 2. 3 C-D.87 I.IS 21-Jun-85 19.00 22.38 0.85 1.18
+
PROJECT T0PHAT Financial Data of Selected Comparable Companies (At or for the 12 Months Ended March 31, 1955)
ComparableCompanies(a)
Chapeau Tophat High Operations Low Mean AFUDC as 1 of Net laceae 62.01 84.51 128.11 39.21 68.45 Return on Averate Total Capitalization (b) 8.31 7.31 12.8%
5.51 7.8%
Return on Aveeage Cossen Equity (c) 17.4 15.0 28.2 12.3 17.1 Return on Average Total Assets (d) 6.4 5.9 9.8 4.3 6.2 Operating Cash Flow (e)/Coanon Dividends Paid 143.01 72.01 268.8%
24.65 136.31 8reakdown of Total Capitallration 1 Long-Term Debt 48.31 50.01 1 Preferred Stock 11.2 15.0 1 Commen Stock 40.5 35.0 Total 100.01 100.01 Construction Work in Progress /
Book Value 140.41 176.37 225.9%
7.61 J26.11 Construction Work in Progress /
Net Plant Plus Construction Work in Progress 49.9%
59.6%
64.71 3.11 42.71 (a) Comparable companies include The Cincinnatti Gas & Electric Company, The Dayton Power and Light Co., The Detroit Edison Company, Duquesne Light Company. Illinois Power Company, Kansas City Power & Light Company, Kansas Gas 8 Electric Company, New York State Electric 8 Gas Corporation, Niagara Mohawk Power Corporation.
Ohio Edison Company and Philadelphia Electric Company.
(b? Net income divided by average year-to-year capitalization.
(cJ Net income less preferred dividend requirement divided by average year-to-year cosmon equity.
(dh Net income divided by average year-to-year total assets.
(ej Net income less AFUDC and preferred dividends plus deferred taxes, deferred ITC and depreciation. -
PROKCI 10plei Banking of Finarcial Bata of selectcc Compar.bla Companies Return on Average Total Capitaliaation Bekra on Average - Equity arturn on Average Total Assets afl2C as a Percent cf net Income r
Cie Edison Co.
12.8 5 Die Edison Co.
28.2
- mio Ediso6 Co.
1.88 mio Edison Co.
!28.1 8 Ransas City Puner 8 Lipt Co.
11 Detroit Edison Co.
21.1 gansas City Pw 8 Lipt Co.
7.5 sansa Eas 8 Electric Co.
115.4 DepEM
- 8. 3 Kansas City Pouer 8 Lipt Co.
21.8 OmPEm
- 6. 4 10ple!
84.5 Illinois Powr Co.
7.6 DGFEli!
17.4 Niagara hamh somer Corp.
L3 Ransas City Puner 8 Light Co.
30.0 Ciagara pamh powr Corp.
7.6 tilinois Power Co.
16.4 New York State Electric 3 Eas Corp.
L2 Philadelphia Electric Co.
72.1 kw Vosk State Electric 8 645 Corp.
7.6 New York State Electric 4 Gas Corp.
15.1 Illpois Puurr Co.
6.1 Betroit Edison Co.
68.4
- Ihe Ciacinnats Sas 8 Electric Co.
- 7. 4 The Ciminnati Sas 8 Electric Co.
lit sansas Gas & Eintric Co.
LI DePEm 62.8
- 10REI 7.3 Niagara pad Power Corp.
11 2 Ihe Cincinnati Gas 8 Eintric Co.
'11 F arrin Power Co.
54.4 Kansas Eas 8 Electric Co.
7.1 Ransas E45 8 Eintric Co.
til 10 Ret 11 Swivesse List r.
51.3 o
, Detrset Edison Co.
L1 Philadelpi. " <tric Co.
15.8 The Dayton Pomer 8 Light Co.
- 5. 7 the Dayton Power 8 Lipt Co.
%.8 8hiladelphia Electric Co.
6.1 10RE7 15.8 Philadelphia Elertric Co.
14 Waagara pamk Power Corp.
46.6
' The Dayton Pomer 8 List Co.
- 6. 6 The f
- ght Co.
13.5 Detroit Edison Co.
- 4. 7 The Caprinnati Eas 8 Electric Co.
44.8 DwluesteListCo.
15 Buge 12.3 Dwivesse List to,
- 4. 3 New York State E!ectric 8 545 Corp.
31.2 Median
- 7. 4 Median 15.8 Median 6.1 Ordnan
[2.8 kan 7.8 Mean 17.1 Mean 6.2 Mean 68.4 Operating Cash-flow / Common Pividerds DilP/guoh value
~ 0ilp/ttrt Plant plus Glp Eansas City Powe 8 Light Co.
268.8 1 lilinois P=er Co.
225.1 s Kansas Eas & Electric Co.
64.7 s the Bayton Pomer 8 Light Co.
220.8 Eaasas Caly Pmer 8 Lipt Co.
180.0 tilinois Towr Co.
62.7 The Ciscenr.ati G.6 8 Eintric Co.
299.3 10 461 17L3 Ransas C6ty Pomer 8 '.ight Co.
68.4 Kansas Gas 8 Electric Co.
294.7 Kansas Gas 8 Tlectric Co.
173.7 10PtEl 51 6 054tm 143.0 mio Edison Co.
157.3 Philadelphia Electric En.
52.0 Waagara pamh Puurr Corp.
118 6 Philadelphia Eintric Co.
152.2 mio Edison Co.
51.5 Dwavesne I aght Co.
141 0 Detroit Edison [o.
145.8 DSPEW 411 mio Edison Co.
Ifl. 0 OSRM 140.4 Detroit Edison Co.
42.8 Philadelpia Electric Co.
103.5 Duqwsne Light Co.
142.3 Duqueste Light Co.
34.3 lilinois Powr Co.
181.5 The Dayton Pumer 8 Light Co.
70.4 The 04yten Puwe 8 Light Co.
34.4 New York State Electric 8 Sas Corp.
E.4 Nro York State Eintric 8 Gas Corp.
12 lire York State Electric 8 Eas 22.6 TORET
- 72. 0 The Circinnati Sas 8 Electric Co.
58.1 The Circinnati Eas 8 Electric 20.1 Detroit Edison Co, 24.6 Niagara uash Puer Corp.
F.6 Niagara past Puer Corp.
3.1 Median 181 0 Median 145.8 Median 411 Mean 136.3 Mean 126.1 Mean 42.7 PROJECT TOPIIAT Market Data of Selected Comparable Companies (a)
Comparable Companies Chapeau Tophat
~~Illgh Low Mean rnings Per Share Price to Earnings 6.0x 4.9x 8.1x 4.7x 6.4x Price to [ Earnings - AFUDC]
18.6x NM 71.9x 10.3x 20.1x Price to Average 5-Year Earnings 7.4x 5.8x 8.7x
.5.8x 7.2x Price to Peak 5-Year Earnings 5.9x 5.0x 7.8x 4.8x 6.2x 5-Year EPS Growth 12.7%
9.6%
13.2%
0.8%
7.8%
ice to Cash Flow Multiple 6.5x 9.6x 17.9x 3.3x 6.2x ice to Book Value Multiple 1.03x 0.78x 1.10x 0.78x 0.95x vidends Current Dividend Yield 11.7%
13.7%
14.8%
0.1%
11.7%
5-Ye:r Average Dividend Yield 13.0%
13.3%
14.0%
9.9%
12.5%
Current Dividend Payout Ratio (as a % of Net income) 70.6%
70.2%
94.1%
51.1%
74.3%
' Current Dividend Payout Ratio (ca a % of Operating Cash Flow) 71.7%
138.1%
406.5%
37.2%
105.7%
5-Year Average Dividend Payout Ratio (as a % of Net Income) 76.2%
75.9%
94.0%
59.2%
77.3%
5-Year Dividend Growth 5.0%
3.5%
7.2%
1.1%
4.2%
) Comparable companies include The Cincinnati Gas & Electric Company, The Dayton Power and Light Co., The Detroit Edicon Company, Duquesne Light Company, lilinois Power Comapny, Kansas City Power & Light Company, Kans:s Gas & Electric Company, New York State Electric & Gas Corporation, Niagara Mohawk Power Corporation, Ohio Edison Company and Philadelphia Electric Company. Market Prices as of 6/14/85. Operating Data For The 12 Months Ended 3/31/85.
y---
g price /Ernings prac:/ Sverage 3-Vew Earnings pract/ ped 5-Vee Earnings 5-Ver Ep6 Grouth 84t3 Ihe Sayton powr 8 Lept Co.
8.1 s Betroit Edison Co.
- 8. 7 s Betroit Edison Co.
7.85 Die Edison Co.
11 2 s Betreat Edison Co.
7.8 km Vork State Electric 8 Ess Corp.
8.5 Buque~ Lipt Co.
7.4 081011 12.7 Suqwsne Lipt Co.
7.5 Buquesne Lipt Co.
Le New Vor6 State Electric 4 Eas Corp.
7.3 hasas City our 8 lipt Co.
11.4 p
hrw fork State Electric 8 Eas Corp.
7.1 Iltagara Itohad peer Corp.
7.1 Niagra ikAd puur Corp.
7.8 linagara IkAd pour Corp.
18.8 the C;ncannati Eas 8 Electric Co.
L1 The Barton pour 8 Lipt Co.
7.7 The Barton puer 4 Light Co.
L6 10RAI 1.6 haagara lhAamh peer Corp.
- 6. 7 lilinois pour Co.
- 7. 7 tiliress powr Co.
L3 Illinois pour Co.
La Illinois peer Co.
LE DeKAl 7.4 hio Edison Co.
L8 lire Vert State Electric 4 Eas Corp.
- 8. 8 DePLAl LS hio Edison Co.
7.3 DeKW 11 fhiladelpia Electric Co.
- 7. 8 Ris Edison Co.
il The Cincinnati Eas & Electric Co.
6.8 h Cancirmati Eas 8 Electric Co.
5.1 Betrost Edison Co.
5.1 Rusa Eas 8 Electric Co.
17 Philadelpia Electric Co.
L3 llansa Eas 8 Electric Co.
16 Buquesne Lapt Co.
it Philadelphia Electric Co.
15 Kansas City poner 8 Lept Co.
L2 Philadelphia Electric Co.
15 The Barton bor 8 Light Co.
- 4. 4 10RGI il 10461 5.8 10 Ret it the Cancinnati Eas 8 Electric Co.
2.2 hasa City poner 8
- ight Co.
- 4. 7 hasas Eas 8 Electric Co.
18 Eansas City uer 8 Laght Co.
- 4. 8 Kansas Gas 8 Electric Co.
- 0. 8 p
nedian L6 median
- 7. 4 Mian LO lendian LG mean L4 nean 7.2 nean L2 neah
- 7. 8 prire/ Cash Flas price /Buc6 value Current Davidend vield 5-Vear brage envidend vield Illinois poner Co.
17.1 Itm Vart State Electric 8 Eas Corp.
l.10 e Ntadelphia Electric Co.
14.8 8 he [d son Co.
14.8 8 Ransa En 8 Electric Co.
18.3 litanois poner Co.
l.07 10Rei.
11 7 1he Cincimat Eas 8 Electric Co.
ILS ILRet 1.6 DSPtstl 1.83 Eansa Eas 8 Electric Co.
117 Buquesne Light Co.
13.7 DePEml L5 Niassa ikAd Puer Corp.
l.82 Sugeste Light Co.
12.6 10R6!
113 hm Vork State Electric 8 Eas Corp.
4.1 Buquesne Lipt Co.
l.01 hio Edison Co.
12.5 The Sarton puuse 8 Light Co.
Ili Kansas City powr 8 Lipt Co.
4.1 Betroit Ediaan Co.
l.01 The Cincinnati Eas 8 Electric Co.
12.4 DeRAI ILS Niagara IkAn peer Corp.
a.6 Ihe Bayton pour 8 Light Co.
9.14 DeMal 11.7 Sutroit Edison Co.
12.1 Buqwsre L6ght Co.
- 4. 4 Gaio Edasan Co.
8.14 Ransa C:ly our 8 Lsght Co.
- 10. 1 hasas Gas 8 Electric Co.
12.4 p
Betroit Edison Co.
11 hasas Gas 8 thetric Co.
8.10 h Bayton Puer 8 Light Co.
18.8 kre Vart State Electric 8 Eas Corp.
12.0 The Cincinnat Eds 8 Electric Co.
11 hasas City her 8 Light Co.
0.84 Niagara Ikhamh fuer Corp.
18.5 philadelphia Electric Co.
II 8 philadelphia Electric Co.
16 blate?pelia Electric Co.
- 9. H Betroit Edinan Co.
- 1. 7 lhagara ikAmA puer Corp.
18.7 Can Edison Co.
3.5 h Cincinnati Eas 8 Electric Co.
0.83 liianons pumer Co.
13 lilinois paw Co.
18.6 The Bayton puur 8 Light Co.
3.3 10Rai 8.78 nye Vorb State Electric 4 Eas Corp.
- 1. 8 Eansa City uur 4 Light Co.
1.1 p
Maan
- 4. 6 nedaan 0.14 Maan 18.7 lhedaan 12.1 nean L2 nran 0.15 nean 11.7 nean 12.5 Current Divideral payout 5-Yes Sverage Bavidend payout 5 Ves Savidend Granth price /(Esmings - NTalCI Buqwsne Light Co.
14.8 5 Buquesne lapt Co.
14.8 5 Niagara shed peer Carp.
7.25 Betroit Edison Co.
78.1 :
h Sayton pumer 8 Lipt Co.
GLi Siin Edison Co.
81.5 hou varh State Electric 8 Eas Corp.
L1 Sito Edison Co.
3L5 h Cancinnatt Eas 8 Electric Co.
GLI philadelphia Electric Co.
86.8 Eansas City puer 4 inght Co.
L8 shiladelphia Electric Co.
37.2 philadelphia Electric Co.
81.5 entroit Edison Co.
H.2 bladelphia Electric Co.
- 5. 8 h Sayton peer 8 Light Co.
24.3 Eansas Gas & Electric Co.
T7.6.
The Cancinnati Eas 8 Electric Co.
417 der 41 is OGRAI IL E Betroit Edison Co.
75.7 The Bayton poner 8 Light Co.
80.1 litsauas powr Co.
- 4. 7 Suqwsne light Co.
18.6 Ces Edison Co.
14.0 DeKal E2 Mansas Eas 8 Electric Co.
- 4. 7 tilinoas peer Co.
11 5 tsagara 8kAM peer Corp.
78.7 10 Rat 75.1 h Sartan peer 8 tight Co.
15 lisa6.ra 8kaamh pumer Corp.
13.5 DeRAI
- 70. 6 Kansas Eat 8 Electric Co.
12.1 IOnst 15 lem Vwt State Electric 8 Eas Corp.
12.5 TORGI 70.2 Niagara lhaamh pmur Corp.
- 78. 7 Suquesne Lipt Co.
14 Ihe Cincinnale Eas 8 Electric Co.
10.3 lirm var 6 State Elsctric 4 Eas Corp.
64.7 thu Varh $ tate Electric 4 Een Corp.
6L 4 Ihe Carrianats Eat 8 Electric Co
- 1. 7 Kansas City pumer 8 Lipt Co.
ifl Illinois peer Co.
61.8 tilenons pour Co.
6LS Betroit Edison Co.
l.2 Kan6as Gas 4 Electric Co.
Ici sansa City puner 8 Lept to.
St.1 p
Bansas City uner 8 Lipt Co.
51.2 Sie Edison Ca
- 1. 8 Tome!
sol Inrdian
- 74. 8 median E2 liedman
- 4. 7 lbdian IL6 8tran
- 74. 3 laran 77.3 laran 4.2 8tran 20.1.,
TOPHAT/ CHAPEAU / COMPOSITE
~
1 Year Monthly Stock Price Performance 150-140 -
130 -
g J
t
/~
120 -
/
110 -
. (
100
/
90 Jun-85 Jun-84 Composite DJul Chapeau Tophat TOPHAT/ CHAP 3AU/ COMPOSITE 2 Year Monthly Stock Price Performance 120 -
110 -
/
l 100
/
Bu -
70 -
60
.........i...........
Jun-83 Jun-84 Jun-85 Tophot Composite DJul Chapeau _
TOPHAT/ CHAPEAU /COMPOSIT3 5 Year Monthly Stock Price Performance 140 -
130 -
120 -
110 -
100 -
90 -
t 80 -
70 -
60 -
Jun-80 Jun-81 Jun-82 Jun-83 Jun-84 Jun-85 Tophot Composite DJUl Chqpeau i
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TE - 05 1
Company owncrship shares of lines are indicated by approximate mileage.
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Percent company investment responsibilities are shown for CAPCo lines Do-Beaver: Av-eenver s2).
CAPCO 345 KV LINES 3.
A portion of substation f ac!!!tles are also *CAPCO" and have associated BETWEEN TE AND CEI ir.dividual company investment responsibilities.
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