ML20071P799
| ML20071P799 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 08/01/1994 |
| From: | Horn G NEBRASKA PUBLIC POWER DISTRICT |
| To: | Dinitz I NRC |
| References | |
| NSD940702, NUDOCS 9408100177 | |
| Download: ML20071P799 (97) | |
Text
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COOPER NUCLEAR ST ATION P.o. BOX 98. 0HoWNVILLE. NEBRASKA 68321 Nebraska Public Power District "L%Wh*"
l NSD940702 August 1, 1994 U. S. Nuclear Regulatory Commission Attn:
Mr. Ira Dinitz Mail Stop 12-E-4 Washington, DC 20555
Subject:
Licensee Guarantees of Payment of Deferred Premiums Cooper Nuclear Station NRC Dock No.20-298.
DPR-46 Gentlemen:
In accordance with the requirements of 10 CFR Part 140.21, relative to deferred insurance premiums, the hebraska Public Power District submits the following information whir.h, we believe, demonatrates our ability to obtain funds in the amount of $10 million for payment. of such premiums within the specified three month period.
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The Nebraska Public Power District has renewed a Credit Agreement, which is included as an enclosure, with the American National Bank and Trust Company of Chicago, which indicates that said bank will lend the District funds, not to exceed $5 million as specifically required to pay public liability claims arising from nuclear incidents.
This Credit Agreement is valift through July 31, 1995, at which time the District will submit the appropriate documentation to verify the guarantee requirements for the following year.
Midwest Power Systems, under the terms c f a power purchase contract, has acknowledged its respeasibility to assume 50 percent of the retrospective premium requirement.s in an amount not to exceed $5 million in one year. Midwest Power Systems has chosen to utilize the type of guarantee defined in 10 CFR 140.21 (e). Therefore, as enclosures to this letter, we are submitting the following documents in support of 50 percent of the required $10 million premium.
1.
Midwest Power Systems. Inc.
1993 Annual Report to the Securities and Exchange Commission - Form 10-K 2.
Five Year Financial Forecast dated November, 1993 for Midwest Resources, the holding company of Midwest Power Syste.1s.
We believe that the enclosed information is sufficient to demonstrate our ability to generate the necessary funds required by the deferred premium; however, should you th M 940810d1NhhkO801 N
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U. S. Nuclasr Regulatory Commission August 1, 1994 Page 2 require additional information, please do not hesitate to contact me.
Si erel,
t llorn ice resident - Nuclear
- jw Enclosure cc:
U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555 U. S. Nuclear Regulatory Commission w/o enclosure Regional Office - Region IV Arlington, TX NRC Senior Resident Inspector Cooper Nuclear Station w/o enclosure
CREDIT AGREEMENT CREDIT AGREEMENT, dated as of August 1, 1994, between NEBRASKA PUBLIC POWER DISTRICT (herein called the " District") and AMERICAN NATIONAL BANK AND TRUST COMPANY OF CHICAGO (herein called the " Bank").
The District desires to provide for future borrowings, and the Bank is willing to commit to lend to the District, upon the terms and conditions herein set forth, the aggregate sum of up to
$5,000,000, in such installments and at such times as hereinafter provided, to be evidenced by notes of the District therefor.
In consideration of the foregoing and the covenants and conditions herein contained, the parties thereto agree as fol-lows:
1.
Definitions.
The following terms shall, for all purposes of this credit Agreement, have the following meanings:
"Act" shall mean the Public Power and Irrigation District Law, constituting Article 6 of Chapter 70 of the Revised Statutes of Nebraska, as amended and supplemented.
" Electric Resolution" shall mean the resolution enti-tied " Electric System Revenue Bond Resolution" adopted by the Board of Directors of the District on August 22, 1968, as sup-plemented or amended in accordance with the terms thereof.
" Electric System Bonds" shall mean Electric System Revenue Bonds of the District authorized to be issued under the E
Electric Resolution.
" Electric System General Reserve Fund" shall mean the Electric System General Reserve Fund established in Sect. ion 502 of the Electric Resolution.
" Loans" shall mean the loans provided for in this Credit Agreement.
" Note or Notes" shall mean any note or notes, as the case may be, issued pursuant to this credit Agreement by the District to evidence any Loan.
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" Note Resolution" shall mean the resolution of the District entitled " Resolution Authorizing $5,000,000 Bank Credit
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of 1994," adopted July 8, 1994 authorizing the issuance of the Notes and authorizing the execution and delivery of this Credit Agreement, a true and correct copy of which resolution is annexed hereto as Annex A.
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2.
Commitment to Lend.
The Bank hereby agrees, upon the terms and conditions herein set forth, to make one or more Loans to the District, in accordance with the provisions of this Credit Agreement, on or before July 31, 1995 in an aggregate principal up to, but not exceeding $5,000,000, each Loan to be in the principal amount of not less than $250,000.
3.
Borrowinos.
The District shall give the Bank at least two (2) days prior notice of the date and amount of each borrowing hereunder.
Each borrowing pursuant thereto shall take place at the principal office of the Bank at LaSalle and Washington Streets, Chicago, Illinois.
Not later than 11:00 a.m.
on the date of each borrowing, the Bank shall, subject to the terms of this Credit Agreement, make available tu the District, Federal Reserve or other immediately available funds in the prin-cipal amount being borrowed, upon delivery to the Bank of a Note in such principal amount.
4.
The Notes.
Each Note shall be designated as
" Electric System Note, Series NRC of 1994," shall be payable to the order of American National Bank and Trust Company of Chicago, shall be dated the date of its delivery, shall be payable one year from its date of issue (subject to optional prepayment as proirided in Section 8 hereof), and shall bear interest (payable on the first day of each January, April, July and October) on the anpaid principal amount thereof from its date fluctuating at the rate per annum equal to 87% of the rate of interest announced or published publicly from time to time by the Bank as its base rate or equivalent rate of interest.
Such interest rate shall be com-puted on the basis of a 365/366-day year.
The Notes shall be executed on behalf of the District by the manual signature of its Chairman, Vice Chairman, President, Treasurer or Assistant Treasurer and its corporate seal shall be affixed, imprinted, engraved or otherwise repro-l duced thereon and attested by the manual signature ~of its Secretary or any Assistant Secretary and shall'lxa otherwise in substantially the form annexed hereto as Annex B.
5.
Commitment Fee.
The District shall pay to the Bank as a commitment fee contemporaneously with the execution of this Credit Agreement the sum of $5,000.
6.
Tax Indemnification.
(i)
The parties intend that~the Bank shall receive in respect of the Notes amounts equal to the principal thereof and interest thereon as provided hereunder, when due, without deductions, penalties, charges, or withholdings as a result of the imposition of any federal income or similar federal tax imposed on the Bank as a holder of any of the notes (collec-tively " Taxes"). _
l Any such Taxes shall be paid by the District.
The District will pay the Bank the amounts necessary such that the net amount of the principal and interest received and retained by the Bank is not less than the amount payable under this Agreement had such Taxes not been imposed.
If, notwithstanding the previous two sentences, the Bank pays any such Taxes, the Bank will furnish to the District official tax receipts or evidence of payment of all such Taxes and the District will promptly reimburse the Bank therefor.
(ii)
If the Internal Revenue Code of 1986, as amended, (the " Code"), or any other federal income tax law, rule, regula-tion, or governmental interpretation thereof hereafter enacted, adopted or issued, other than any such change mentioned in (iii) i below, when affecting the Bank as a holder of the Notes or com-l pliance by the Bank as a holder of the Notes with such, (a) subjects the Bank to any tax, duty, charge, or i
withholding due on the principal of or interest on the Notes or changes the basis of taxation of payments to the Bank in respect of the principal of or interest on the Notes, in-cluding, without limitation, the effect of any limitation on i
the deductibility of interest on the funds obtained to purchase or carry the Notes; or (b) imposes any other condition or circumstance the result of which is to increase the cost to the Bank of pur-chasing, funding or carrying the Notes, or reduces any amount receivable by the Bank in connection with the prin-cipal of or interest on the Notes or requires the Bank to make any payment calculated by reference to the amount of the Notes or interest received by it in an amount deemed material by the Bank; then, within thirty days of demand by the Bank, the District shall pay the Bank an amount'.which will be equal, on'an after-tax basis to the Bank.(taking into account any taxes payable by the Bank on such amount), to (a) that portion of such increased cost 1
incurred or (b) the amount or reduction in an amount received which the Bank determines is attributable to purchasing, funding i
or carrying the Notes to the extent of the principal amount thereof outstanding from time to time.
The effer.t of any such increased cost which is imposed on the Bank ganerally may be allocated to the Notes on any reasonable basis in the discretion of the Bank.
(iii)
If at any time or times while the Bank is the Holder of the Notes there is a change in the maximum marginal tax rate (the " Tax Rate") at which the Bank could be taxed for fed-eral income tax purposes, the interest rate on the Notes shall be
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decreased (in the case of a decrease in the Tax Rate) to an in-terest rate equal to the product of (1) the interest rate on the Notes in effect immediately prior to a change in the Tax Rate times (2) a fraction (expressed in decimals) the numerator of which is the number one (1) minus the applicable Tax Rate after such change and the denominator of which is the number one (1) minus the Tax Rate which had been in effect prior to such change in the Tax Rate.
(iv)
Notwithstanding any of the other provisions of this Agreement, if the District has paid the additional amount specified in (ii) and (iii) above, the District shall not be obligated to pay or reimburse the Bank for any tax on the income of the Bank to the extent that such income tax is attributable to the inclusion in the gross income of the Bank for federal tax purposes of interest on the Notes as if such interest had been timely reported and timely paid.
7.
Conditions Precedent to Loans.
The Bank shall not be obligated to make any loan unless at the date specified for the making thereof the District delivers to the Bank:
(a)
The opinion of the General Counsel to the District, dat.ed as of such date, to the effect that:
(i)
There is no litigation pending in any court, either State or Federal, questioning the creation, or-ganization or existence of the District or the validity of this Credit Agreement or the Note being issued to evidence such Loan; and (ii)
The District has the power to borrow the amount being loaned; to execute and deliver this Credit Agreement; to evidence the Loans by its Notes to be made and delivered in accordance herewith, and to per-form and observe all of the terms andsconditions of this credit Agreement on its part to be performed and observed; and (b)
A certificate of the Chairman, President, Treasurer or Assistant Treasurer of the District, dated as of such date,.to the effect that the representations and warranties of the District contained in Section 15 of this Credit Agreement are true and correct as of such date; and (c)
A certificate of.the Chairman'or President or Treasurer or Assistant' Treasurer of the District, dated as of such date, setting forth the aggregate amount of bonds and notes of the District that will be outstanding immedi-ately after the issuance of the note then being issued and stating that no default has occurred in the payment of prin-cipal of or interest on any indebtedness for borrowed money
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i of the District which remains unsecured; and (d)
The opinion of Mudge Rose Guthrie Alexander &
Ferdon, Bond Counsel to the District, dated as of such date, substantially in the form annexed thereto as Annex C; (e)
A certificate as to Arbitrage, dated as of such date, in accordance with the provisions of the Code; and (f) Such additional certificates, instruments and other documents as the Bank or its counsel may deem necessary to effect good delivery of the Note being delivered on such date or evidence the due performance by the District of the conditions precedent hereunder.
8.
Optional Precavnent.
The District may prepay any Note as a whole or in part, at any time or from time to time, without penalty or premium, by paying to the Bank all or part of the principal amount of the Note to be prepaid, together with the unpaid interest accrued on the amount of principal so prepaid to the date of such prepayment.
Each prepayment of a Note shall be made on such date and in such principal amount as shall be spec-ified by the District in a written notice delivered to the Bank not less than 10 days prior thereto.
Notice having been given as aforesaid, the principal amount of the Note stated in such notice or the whole thereof, as the case may be, shall become due and payable on the prepayment date stated in such notice, together with interest accrued and unpaid to the prepayment date on the principal amount then being paid; and the amount of principal and interest then due and payable shall be paid (i) in case the l
entire unpaid balance of the principal of any Note is to be paid, l
upon presentation and surrender of such Note to the District or its representative at the principal office of the Bank, and (ii) in case only part of the unpaid balance of principal of any Note is to be paid, upon presentation of such Note at the principal office of the Bank for notation thereon by the Bank of the amount of principal and interest on such Note then paid.
If on the prepayment date moneys for the payment of the principal amount to be prepaid on such Note together with interest to the' prepayment date on such principal amount, shall have been paid to the Bank as above provided and if notice of prepayment shall have been given to the Bank as above provided, then from and after the prepayment date interest on such principal amount of such Note shall cease to accrue.
If said moneys shall not have been so paid on the prepayment date, such principal amount of such Note shall. continue to bear interest until payment thereof at the rate provided for in Section 4 of this Credit Agreement.
9.
Application of Note Proceeds.
The proceeds of the Notes shall be used to pay amounts required to be paid by the l
District as a result of one or more nuclear incidents, as pro-vided in the Price-Anderson Act, as amendec (Pub.
L.94-197, as i i e
i amended and as compiled in 42 U.S.C.
Section 2210 and pertinent subsections of 42 U.S.C.
Section 2014, as amended) and certain regulations of the Nuclear Regulatory Commission (10 C.F.R. Part 140, as amended in particular by 42 Fed. Reg. 46-54 (January 3, 1977)) or any act or regulation supplemental thereto or amenda-tory thereof.
10.
Payment.
The obligation to pay the principal of and interest on the Notes and the other amounts payable hereunder j
is a special obligation of the District payable solely from such i
amounts in the Electric System General Reserve Fund as may be available therefor under the District's bond resolutions then outstanding; provided, however, that such obligation to pay the principal of and interest on the Notes and the other amounts payable hereunder from amounts in the Electric System General Reserve Fund shall be subject and subordinated in all respects to the pledge of the Revenues (as defined in the Electric Resolution), moneys, securities and funds created by the Electric Resolution and, provided, further, that the obligation to pay the principal of and interest on the Notes and the other amounts payable hereunder from amounts in the Electric System General Reserve Fund shall be subject and subordinated to any payments which shall at any time be required to be made from Electric j
System General Reserve Fund pursuant to Section 713 of the District's Power Supply System Revenue Bond Resolution, adopted by the Board of Directors of the District on September 29, 1972, as supplemented and amended in accordance with the terms thereof.
The District shall duly and punctually pay or cause to be paid from the Electric System General Reserve Fund, in Federal Reserve or other immediately available funds, the principal of the Notes, I
the interest thereon and the other amounts payable hereunder at the dates and place and in the manner provided herein and in the Notes according to the true intent and meaning thereof.
If the principal of the Notes becomes due and payable on a Saturday or Sunday or a day which is a Bank holiday, such payment shall be made'on the next succeeding Bank business day and the extension of time for payment shall be included in computing interest in connection with such payment.
11.
All of the Bank's rights and remedies under this Credit Agreement are cumulative and non-exclusive.
The acceptance by the Bank of any partial payment made hereunder after the time when any of District's Loans become due and payable will not establish a custom, or waive any rights of the Bank to enforce prompt payment thereof.
The Bank's failure to require strict performance by the District of any provision,of
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this Credit Agreement shall not waive, affect or diminish any right of the Bank thereafter to demand strict compliance and j
performance therewith.
Any waiver of an event of default i
hereunder shall not suspend, waive or affect any other event of default hereunder.
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Rate Covenant.
The District covenants and agrees with the Bank that so long as any credit shall be available here-under or any Note or interest thereon is unpaid it shall comply for the benefit of the Bank with requirements of Section 712 of the Electric Resolution.
j 13.
Reaative Covenants of the District.
The District, if and so long as credit shall be available hereunder or any Note i
or interest thereon is unpaid, will not alter, amend or repeal the Note Resolution, or take any action impairing the authority thereby or hereby given with respect to the issuance and payment of the Notes.
14.
Tax Covenant.
In order to maintain the exclusion from gross income for purposes of federal income taxation of 4
interest on the Notes, the District shall comply with the pro-visions of the Code applicable to the Notes, including without limitation the provisions of the Code which prescribe yield and other limits within which the proceeds of the Notes and other amounts are to be invested and require that certain investment earnings on the foregoing be rebated on a periodic basis to the
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Treasury Department of the United States of America.
The District shall not take any action or fail to take any action, which would cause the Notes to be " Arbitrage Bonds" within the meaning of Section 148(a) of the Code.
15.
Representations and Warranties.
The District rep-resents and warrants that:
l (a)
The District has the power to borrow the amount provided for in this Credit Agreement; to execute and de-liver this credit Agreement; to evidence the Loans by its Notes to be made and delivered in accordance with the pro-visions hereof and to perform and observe all of the terms and conditions of this Credit Agreement on its part to be performed and observed;'
(b)
The making and performance by the District of this Credit Agreement will not violate any provision of the Act, or any bond or note resolution of the District, or any regulation, order or decree of any court, and will not result in a breach of any of the terms of the petition for creation, as amended, of the District or any agreement or instrument to which the District is a party or by which the District is bound; and (c)
The District, by adoption of the Note Resolution has duly authorized the borrowing of the amount provided for in this Credit Agreement, the execution and delivery of this Credit Agreement, and the making and delivery of the Notes to the Bank as herein provided; and to that end the District warrants that it will take all action and will do all things. -
which it is authorized by law to take and to do in order to fulfill all covenants on its part to be performed and to provide for and to assure payment of the Loans as herein provided.
16.
Acceleration of Due Date Upon Default.
If one or more of the following events of default shall occur and be continuing:
(a)
Default shall occur and be continuing in the pay-ment when due of any principal or interest on any Note; (b)
Any representation or warranty made herein or pur-j suant hereto shall prove to be untrue in any material respect; (c)
Default shall occur in the performance of any of the other covenants or agreements of the District contained herein, and the act or omission creating such default shall i
continue for a period of 30 days after written notice there-of shall have been given to the District; or j
(d)
Default shall be made in the payment of the prin-cipal of or interest on any Electric System Bonds when due, and as a result of such default, the maturity of such Bonds is accelerated; J
then, and in any such event, the Bank shall have the right to declare the principal of and all interest then accrued on all Notes to be due and payable immediately, and upon such declara-tion the Notes and the interest accrued thereon shall become due and payable, anything in this credit Agreement or in the Notes contained to the contrary notwithstanding.
17.
Defeasance.
If the District shall pay or cause to be paid, or there shall'otherwise be paid, to the Bank the prin-cipal of and interest on the Notes at the times n'nd in the manner stipulated herein, then the covenants, agreements and other obligations of the District hereunder shall thereupon cease, terminate and become void and be discharged and satisfied.
I' moneys sufficient to pay the principal amount of the Notes and interest thereon until maturity or a date fixed for repayment shall have been paid to the Bank for application to such purpose, the Notes and the interest thereon shall be deemed to have been paid within the meaning and with the effect expressed in this Section.
Amounts so set aside and held may be invested in obli-gations of, or guaranteed by, the United States of America, provided, however, that said obligations shall mature not later than the maturity date of the Notes.
All earnings from such investments shall be paid over to the District, as received, free and clear of any trust, lien or pledge.
18.
Notices.
All notices under this Credit Agreement shall be in writing and written notices shall be deemed to have been duly given if delivered or mailed by registered mail, in the case of the District, at Box 499, Columbus, Nebraska 68601, Attention:
President, and in the case of the Bank, at its prin-cipal office at LaSalle and Washington Streets, Chicago, Illinois 60690, Attention:
Steven H.
Abbey.
19.
Counterparts.
This Credit Agreement may be exe-cuted in any number of counterparts, and all such counterparts executed and delivered, each as an original, shall constitute but one and the same instrument.
IN WITNESS WHEREOF, the District and the Bank have caused this Credit Agreement to be duly signed on their respec-tive behalf by their officers thereunto duly authorized, all as of the date and year first above written.
NEBRASKA PUBLIC POWER DISTRICT (SEAL]
By Treasurer Attest:
b Assistant Secretary AMERICAN NATIONAL BANK AND TRUST COMPANY OF CHICAGO
[Sy! " OFFICIAL SEAL" ll aya,,,_____,,___,___.,,
ll BARBARA A. 'MULCAHY l;
BY l> NOTARY PU!LIC, STATE OF ILUNOIS ;
^
Vice President l(,tjy Commissjon Exnyes 06l,06/98,;{
Attest:
/
M4A6w / Ab e
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ANNEX A Resolution Authorizina $5,000,000 Bank Credit of 1994 Be it Resolved, by the Board of Directors of Nebraska Public Power District, as follows:
Section 1.
Pursuant to the Public Power and Irrigation District Law, Article 6 of Chapter 70 of the Revised Statutes oi Nebraska, as amended and supplement *
(herein called the "Act"),
called the " District")
Nebraska Public Power District (herc o
shall be authorized to enter into a credit agreement (herein called the " Credit Agreement") for one or more loans in an aggre-gate principal amount up to, but not exceeding, $5,000,000 from American National Bank and Trust Company of Chicago (herein called the " Bank") in substantially the form submitted at this meeting, to which shall be annexed, as Annex A, a copy of this resolution adopted by the District.
Each loan shall be made in the principal amount of not less than $250,000 on any date on or before July 31, 1995; provided that the District shall give the Bank two (2) days prior notice of the date and amount of each borrowing and shall be evidenced by an Electric System Note, Series NRC of 1994 (herein called a " Note"; all Notes made under the Credit Agreement are herein collectively called the " Notes")
of the District in the aggregate principal amount of each loan, which Note shall be issued and delivered by the District to the Bank in the principal amount and on the date of the loan evi-denced thereby.
Each Note shall be payable to the order of the Bank from the sources set out in Section 10 of the Credit Agreement, shall be dated the date of its delivery, shall be payable one year from its date of issue (subject to optional pre-payment as a whole or in part, at any time or from time to time, without penalty or premium, as provided in the Credit Agreement) and shall bear interest (payable on the first day of each January, April, July and October and upon maturity) on the unpaid principal amount thereof from its date fluctuating at the rate per annum equal to 87% of the rate of interest announced or published publicly from time to time by the Bank as its base rate or equivalent rate of interest.
Interest is to be computed on the basis of a 365/366-day year.
Each Note shall be in substantially the form set forth in Annex B to the Credit Agreement.
Section 2.
The proceeds of the Notes shall be applied by the District to the purpose and in the manner provided in Section 9 of the Credit Agreement.
Section 3.
The President, any Vice President, the Treasurer, and the Assistant Treasurer of the District are each hereby authorized to execute the Credit Agreement and the Secretary, or any Assistant Secretary, are each hereby authorized to affix the seal of the District on the Credit Agreement.
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Section 4.
The Chairman, Vice Chairman, President, Treasurer or Assistant Treasurer of the District are each hereby authorized to execute the Notes by manual signature and the Secretary or any Assistant Secretary are each hereby authorized to cause the seal of the District to be affixed, imprinted, en-graved or otherwise reproduced on the Notes and to attest the Any of the foregoing officers are hereby authorized to same.
deliver the executed Notes in accordance with the provisions of the Credit Agreement.
Section 5.
The Chairman, Vice Chairman, President, Treasurer or Assistant Treasurer of the District and the Secretary or any Assistant Secretary are, and each of them hereby is authorized to do and perform all things and to execute all papers in the name of the District or otherwise, as they deem advisable, and to make all payments, necessary or convenient in their respective opinions, to the end that the District may carry out the objects of this resolution and its obligations under the terms of the Credit Agreement and of the Notes.
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ANNEX B (FORM OF NOTE)
NEBRASKA PUBLIC POWER DISTRICT ELECTRIC SYSTEM NOTE, SERIES NRC OF 199_
No.
FOR VALUE RECEIVED, the undersigned, NEBRASKA PUBLIC POWER DISTRICT (the " District"), a public corporation and polit-ical subdivision organized and existing under and by virtue of the laws of the State of Nebraska, hereby promises to pay to the order of American National Bank and Trust Company of Chicago (the 19 upon presentation and sur-
" Bank") on render of this Note at the principal office of the Bank, the principal sum of Dollars ($
),
in lawful money of the United States of America, and to pay interest (payable on 19 and quarterly there-after on the first day of each January, April, July and October and upon maturity) on said principal sum at said office in like money from the date hereof fluctuating at the rate per annum equal to 87% of the rate of interest announced or published publicly from time to time by the Bank as its base rate or equivalent rate of interest.
Such interest shall be computed on the basis of a 365/366-day year.
This Note is a special obligation of the District and is one of a duly authorized issue of notes of the District (the " Notes")
issued and to be issued under and pursuant to the Public Power and Irrigation District Law of Nebraska, as amended and supple-mented (herein called the "Act"), and under and pursuant to a resolution of the District, adopted July 8, 1994, entitled Resolution Authorizing $5,000,000 Bank Credit of 1994 (the " Note Resolution"), and under and pursuant to a Credit Agreement (the
" Credit Agreement"), dated as of August 1, 1994 by and between the District and the Bank.
The obligation to pay the principal of and interest on this Note is a special obligation of the District payable solely from such amounts in the Electric System General Reserve Fund (as de-fined in the Credit Agreement) as may be available therefor under the District's Bond resolutions then outstanding; provided, how-ever, that such obligation to pay the principal of and interest on this Note from the Electric System General Reserve Fund is subject and subordinated in all respects to the pledge of the revenues, moneys, securities and funds created by the Electric Resolution (as defined in the Credit Agreement); and, provided, further, that the obligation to pay the principal of and interest on this Note from the Electric System General Reserve Fund is subject and subordinated to any payments which shall at any time be required to be made from the Electric System General Reserve Fund pursuant to Section 713 of the District's Power Supply B-1
System Revenue Bond Resolution, adopted by the Board of Directors of the' District on September 29, 1972, as supplemented and amended in accordance with the terms thereof.
This Note is subject to the terms and conditions contained in the Note Resolution and the Credit Agreement, copies of which are on file at the principal office of the District, and refer-ence is made thereto for.a complete statement of such terms and conditions.
The District shall have the right to prepay this Note as a whole or in part, at any time or from time to time, without pen-alty or premium, in accordance with the terms of the Credit Agreement.
The prepayment date and the principal amount of the Note to be prepaid shall be specified by the District in a written notice to the Bank not less than 10 days prior to any prepayment.
If on the prepayment date moneys for the payment of the principal amount of this Note to be prepaid, together with interest to the prepayment date on such principal amount, shall have been paid to the Bank as above provided, then from and after the prepayment date interest on such principal amount of this Note shall cease to accrue.
If said moneys shall not have been so paid on the prepayment date, such principal amount of this Note shall continue to bear interest as provided above until payment thereof.
This Note is not an obligation of the State of Nebraska and the Act provides that the State of Nebraska shall never pledge its credit or funds, or any part thereof, for the payment or settlement of any indebtedness whatsoever of the District.
IN WITNESS WHEREOF, Nebraska Public Power District has caused this Note to be signed in its name and on its behalf by its President or Treasurer or Assistant Treasurer, and its offi-cial seal to be hereunto affixed and attested by its Secretary or any Assistant Secretary, as of day of 19__.
NEBRASKA PUBLIC POWER DISTRICT By Treasurer
[ SEAL]
Attest:
Assistant Secretary B-2 e
ANNEX C 19__
Nebraska Public Power District Columbus, Nebraska American National Bank and Trust Company of Chicago Chicago, Illinois Gentlemen:
We have examined the record of proceedings relating to the issuance of the $
Electric System Note, Series NRC of 1993, No.
dated 19__
(the " Note"),
of Nebraska Public Power District (the " District"), a body cor-porate and politic, constituting a public corporation and polit-ical subdivision of the State of Nebraska.
The Note is issued under and pursuant to Chapter 70, Article 6,
of the Revised Statutes of the State of Nebraska, as amended (the "Act"), and under and pursuant to a Credit Agreement (the
" Credit Agreement"), between the District and American National Bank and Trust Company of Chicago (the " Bank"), dated as of August 1, 1994, authorized by a resolution (the " Note Resolution") of the District adopted on July 8, 1994 and entitled
" Resolution Authorizing $5,000,000 Bank Credit of 1994."
The Note is payable to the order of the Bank, matures on 19__
(subject to prepayment in accordance with the terms of the Credit Agreement), and bears interest (payable on 19__ and quarterly thereafter on the first day of January, April, July and October and upon maturity) from its date fluctuating at the rate per annum equal to 87% of the rate of interest announced or published publicly from time to time by the Bank as its base rate or equivalent rate of interest.
Such interest rate shall be computed on the basis of a 365/366-day year.
The obligation to pay the principal of and interest on the Note is a special obligation of the District payable solely from such amounts in the Electric System General Reserve Fund (as de-fined in the Credit Agreement) as may be available therefor under the District's bond resolutions then outstanding; provided, how-ever, that such obligation to pay the principal of and interest on the Note from the Electric System Reserve Fund is subject and subordinated in all respects to the pledge of the revenues, moneys, securities and funds created by the Electric Resolution (as defined in the Credit Agreement; and provided, further, that the obligation to pay the principal of and interest on the Note i
from the Electric System General Reserve Fund is subject and subordinated to any payments which shall at any time be required C-1
to be made from the Electric System General Reserve Fund pursuant to Section 713 of the District's Power Supply System Revenue Bond Resolution, adopted by the Board of Directors of the District on September 9, 1972, as supplemented and amended in accordance with the terms thereof.
We are of the opinion that:
1.
The District is duly created and validity existing under the provisions of the Act, with power to adopt the Note Resolution, to enter into the Credit Agreement, to issue the Note thereunder and to make and perform the covenants contained in the credit Agreement.
2.
The Note Resolution has been duly adopted by the District, is in full force and effect and is valid and binding on the District and enforceable in accordance with its terms, and the Credit Agreement has been duly authorized and executed by the District, is in full force and effect, is valid and binding upon the District and enforceable in accordance with its terms.
3.
The Note has been duly authorized and issued by the District in accordance with law and in accordance with the Note Resolution and the Credit Agreement, and is a valid binding and direct obligation of the District enforceable in accordance with its terms and entitled to the benefit of the Act and of the Credit Agreement.
4.
The Internal Revenue Code of 1986 as amended (the
" Code") sets forth certain requirements which must be met sub-sequent to the issuance and delivery of the Note for interest thereon to be and remain excluded from gross income for purposes of federal income taxation.
Noncompliance with such requirements may cause interest on the Note to be included in gross income retroactive to the date of issue of the Note.
The District has covenanted to comply with such requirements.
In our opinion, under existing law, and assuming compliance with the aforementioned covenant, interest on the Note is ex-cluded from gross income for federal and State of Nebraska income tax purposes.
The Note is not a "specified private activity bond" within the meaning of Section 57(a) (5) of the Code and, therefore, the interest of the Note will not be treated as a preference item for purposes of computing the federal alternative minimum tax imposed by Section 55 of the Code.
However, we note a portion of the interest on the Note owned by corporations may be subject to the federal alternative minimum tax, which is based in part on adjusted current earnings.
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Except as stated in the preceding two paragraphs, we express no opinion as to any federal or state tax consequences of the I
ownership of, receipt of interest on, or disposition of the Note.
The opinions contained in paragraphs 2 and 3 above are qualified to the extent that the enforceability of the Note Resolution, the credit Agreement and the Note, respectively, may be limited by any applicable bankruptcy, moratorium or similar laws relating to the enforcement of creditors' rights.
We have examined the Note, as executed, and, in our opinion, the form of said Note and its execution are regular and proper.
Very truly yours, 4
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10 K (Mark One)
[x] Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
[ Fee Required]
For the fiscal year ended December 31.1993 OR
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
[No Fee Required]
For the transition period from to Commission file number 1-12582 MIDWEST POWER SYSTEMS INC.
(Exact name of registrant as specified in its charter)
IOWA 42-1375614 (State or other jurisdiction of (I.R.S. Employer incorporation or organization)
Identification No.)
666 Grand Ave.. P.O. Box 657. Des Moines. Towa 50303 (Address of principal executive offices)
(Zip Code)
Registrant's telephone number, including area code 515-281-2900 Securities registered pursuant to Section 12(b) of the Act:
i
$1.7375 Cumulative Preferred Stock. Without Par Value (Title of Class)
Securities registered pursuant to Section 12(g) of the Act:
$3.30 Cumulative Preferred Stock, Without Par Value
$3.75 Cumulative Preferred Stock, Without Par Value
$3.90 Cumulative Preferred Stock, Without Par Value
$4.20 Cumulative Preferred Stock, Without Par Value
$4.35 Cumulative Preferred Stock, Without Par Value
$4.40 Cumulative Preferred Stock, Without Par Value
$4.80 Cumulative Preferred Stock. Without Par Value (Title of Class)
]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shoner period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part 111 of this Form 10-K or any amendment to this Form 10-K [X].
The aggregate market value of voting stock held by non-affiliates of the registrant was $0 as of March 22,1994, when 1,000 shares of common stock, without par value, were outstanding.
J MIDWEST POWER SYSTEMS LNC.
1993 Form 10-K Annual Repon TABLE OF CONTENTS Pace Pani Ite m 1 Business General Development of Business..
3 Financial Infonnation About Industry Segments..
3 Narrative Description of Business..
3 General 3
Capital Expenditures and Financing 3
Regulation........................
4 Environmental Matters.............
4 Employees 5
Electric Operations.............
6 Natural Gas Operations 8
Ite m 2 Propenies...
10 Ite m 3 Legal Proceedings..........
10 Ite m 4 Results of Votes of Security Holders...
10 Pan II Ite m 5 Market for the Registrant's Common Equity and Related Stockholder Matters.......................
11 Ite m 6 Selected Financial Data 11 Ite m 7 Management's Discussion and Analysis of Financial Condition and Results of Operations........
I1 Ite m 8 Financial Statements and Supplementary Data I1 Ite m 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...........
I1 Pan III Item 10 Directors and Executive Officers of the Registrant...
12 Itera 11 Executive Compensation.
14 Item 12 Security Ownership of Cenain Beneficial Owners and Managem ent.......................................
20 Item 13 Cenain Relationships and Related Transactions......
21 Pan IV Exhibi s, Financial Statement Schedules, and Item 14 t
Repons on Form 8-K..
22 Signatures 73 Exhibits Index 74 l
PART I l
l ITEM 1. BUSINESS (a) General Development of Business Midwest Power Systems Inc. (MPS or Company), an Iowa corporation, is the wholly owned utility subsidiary of Midwest Resources Inc. (Midwest Resources or MWR). On July 22,1992, Iowa Power Inc. (IPR) and Iowa Public Service Company (IPS) merged into and with MPS. IPS and IPR were previously the utility subsidiaries of Midwest Energy Company (MWE) and Iowa Resources Inc. (IOR), respectively. On November 7,1990, IOR and MWE merged into Midwest Resources, a newly created holding company.
(b) Financial Information About Industry Segments See Part IV, Item 14. " Exhibits, Financial Statement Schedules and Reports on Form 8-K", Note (3) of Notes to Consolidated Financial Statements for financial information about industry segments.
(c) Narrative Description of Business GENERAL MPS is an Iowa corporation which operates an electric division, Midwest Power, and a natural gas division.
Midwest Gas. MPS is a regulated utility that holds franchises to operate in various municipalities and has tenitorial protection in other areas granted by state regulatory commissions. CBEC Railway Inc., an Iowa corporation formed in 1990, is a wholly owned subsidiary of MPS that was organized to own and operate rail facilities for the transponation of coal. CBEC Railway Inc. has not commenced operations.
CAPITAL EXPENDITURES AND FINANCLNG The Company made gross utility propeny additions of $624 million during the period January 1,1989, to December 31,1993, of which $57 million was for Cooper capital improvements,5452 was for electric plant, $109 million was for gas plant and $6 million was for common plant. Utility propeny retirements during the same period amounted to $89 million, of which $64 million was applicable to electric plant, $23 million to gas plant and $2 million to common plant.
The Company's sources of capital are pmvided from funds generated intemally and various extemal sources such as commercial paper, bank lines of credit, and other debt and equity secunties.
On January 1,1993, a new MPS indenture became effective. During 1993 the Company embarked on a plan to refinance and redeem a significant portion of the long-term debt issued by MPS' predecessor companies, IPS and IPR. As a result of the restructuring, the Company was able to eliminate the IPR indenture and only $11 million of long-term debt remains outstanding subject to the IPS indenture. No further bond issuances will be made under the IPS and IPR indentures. The MPS indenture is less restrictive than either of the two previous indentures. At December 31,1993, approximately $981 million of additional general mortgage bonds could have been issued in compliance with the MPS indenture. -
I
)
)
MPS currently has authority from the Federal Energy Regulatory Commission (FERC) to issue (i) before July 1995, short-term debt in the form of commercial paper, bank notes, and notes to MWR or affiliated companies of up to $250 million; (ii) $118 million of long-term debt in the form of general mortgage bonds and pollution control revenue bonds; and (iii) 515 million of preferred stock.
REGULATION MWR is exempt from the Public Utility Holding Company Act of 1935. MWR's exemption is based upon its filing with the Securities and Exchange Commission (SEC) in November 1990, an Initial Statement by Holding Company Pursuant to Regulation 250.2 of the Public Utility Holding Company Act of 1935. MWR maintains its exemption by filing a Form U-3A-2 with the SEC cach year.
MPS is a public utility within the meaning of the Federal Power Act and a natural gas company within the meaning of the Natural Gas Act. Therefore,it is subject to regulation by FERC in regard to numerous activities, including the issuance of securities, accounting policies and practices, sales for resale rates and the establishment and regulation of electric interconnections and transmission services. For the year ended December 31,1993, approximately 11.7 percent of the total electric revenues were sales for resale and subject to FERC regulation.
Natural gas revenues are not subject to FERC regulation.
MPS is subject to regulation by the Iowa Utilities Board (IUB) and the South Dakota Pubhc Utilities Commission (SDPUC) as to electric and gas retail rates and service. Iowa law authorizes the IUB to suspend new rates for up to ten months beyond the date ofinitial filing. During the interim period of rate proceedings, statutory authority in Iowa allows for interim rate increases, subject to refund, starting no later than 90 days from the initial filing date. South Drkota law authorizes the SDPUC to suspend new rates for up to six months during the pendency of rate proceedings, however, the rates are permitted to be implemented after six months subject to refund pending a final order in the proceeding.
In addition, Iowa law requires that a cenificate of convenience and necessity be obtained from 'he IUB prior to construction of a proposed electric generation station with a total capacity of 25 or more megawatts. Need for the station must be established and approval of the proposed site obtained before a certificate can be issued.
MPS' electric and gas operations are conducted under franchises (expiring in various years from 1994 to 2018), permits and licenses obtained from state and local authorities. Franchises for the largest communities served by the Company extend to the year 2000 and beyond.
MPS has entered into a long-term power purchase contract with Nebraska Public Power District under which it purchases one-half of the output of Cooper Nuclear Station (Cooper). Operations of Cooper are subject to regulation by the Nuclear Regulatory Commission (NRC). Refer to " Regulatory Environment" in " Management's Discussion and Analysis of Financial Condition and Results of Operations" included in Pan IV Item 14, for discussion of recent NRC actions.
ENVIRONMENTAL MA'ITERS The Company is subject to numerous legislative and regulatory environmental protection requirements involving air and water pollution, was';., management, hazardous chemical use, noise abatement, land use and aesthetics.
Essentially all utility generating units are subject to the provisions of the Clean Air Act Amendments of 1900 which address continuous emission monitoring, permit requirements and fees and emission of toxic substances.
The Company estimates capital costs of approximately $3 million and increased annual operations and maintenance expense of approximately $2 million for compliance with these provisions. By the year 2000, some Company l
coal-fired generating units will be required to install controls to reduce emissions cf nitrogen oxides. The Company's present estimate of the costs of these controls is $33 million.
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4 The United States Environmental Protection Agency and the Iowa Department of Natural Resources have detennined that contaminated wastes remaining at cenain decommissioned manufactured gas plant (MGP) facilities may pose a threat to the public health or the environment if such contaminants are in sufficient quantities and at such concentrations as to warrant remedial action. The Company could be involved in up to 22 such sites. The Company's present estimate of probable remediation costs at these sites is $15.5 miilion. The Company's current gas rates in Iowa provide recovery for MGP costs of $3.1 million on an annual basis.
As a user of polychlorinated biphenyls (PCBs), the Company is subject to govemmental regulations penaining to the use, handling and proper disposal of PCBs. The Company is aware of three PCB sites in which it may be involved. The Company anticipates recovery of any material expenditures from other responsible panies and i
through rates.
For further information relating to the Company's Environmental Matters, reference is made to Pan IV, Item 14, Note (2)(b) of Notes to Consolidated Financial Statements.
EMPLOYEES On February 14,1994, the Company had 2,832 full-time employees and 76 pan-time and temporary employees for a total of 2,908 employees. Of that total,1,553 were union employees.
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ELECTRIC OPERATIONS Midwest Power has been engaged in the generation, purchase, transmission, distribution and sale of electric energy, serving 420,000 customers in 327 communities in Iowa and six communities in southeastern South Dakota.
Generation Midwest Power's owned electric generating facilities are all located in Iowa. The net accredited generating capacity, along with the panicipation purchases and sales, net, and firm purchases and sales, net, are shown for summer 1993 accreditation.
Percent Accredited Generating Plant Ownershin Fuel Caoability OcW)
Steam Electric Generating Plants:
George Neal Station Unit No. I 100.0 Coal 135,000 Unit No. 2 100.0 Coal 300,000 Unit No. 3 43.0 Coal 221,450 Unit No. 4 40.6 Coal 247,500 Ottumwa Unit 33.5 Coal 237,180 Louisa Unit 45.0 Coal 292,500 Council Bluffs Energy Center Unit No. I 100.0 Coal 46,000 Unit No. 2 100.0 Coal 88,000 Unit No. 3 46.7 Coal 315.230 1.882.860 Combustion Turbines:
Parr - 2 units 100.0 Gas / Oil 27,100 Electrifarm - 3 units 100.0 Gas / Oil 186,100 River Hills Energy Center - 8 units 100.0 Gas / Oil 127,200 Sycamore Energy Center - 2 units 100.0 Gas / Oil 148,000 Pleasant Hill - 2 units 100.0 Oil 70.140 558.540 Nuclear Capacity Purchase:
Cooper Nuclear Station (1)
Nuclear 389.000 Net Accredited Generating Capacity 2,830,400 Add: Participation Purchases and Sales. Net (74,000)
Firm Purchases and Sales, Net 63.250 Adjusted Net Accredited Generating Capability 2.819,650 (1) Cooper Nuclear Station is owned by Nebraska Public Power District and the amount shown is Midwest Power's entitlement (50 percent) of Cooper's accredited capacity under a power purchase agreement extending to the year 2004. (Refer to Notes (1)(g) and (2)(a) of Notes to Consolidated Financial Statements included in Part IV. Item 14.)
l The annual hourly peak demand occurs during the summer period, principally as a result of air conditioning use. Midwest Power's highest hourly peak demand in 1993 was 2,205 megawatts (MW) in August,57 MW less than Midwest Power's record of 2,262 MW set in 1988 and 246 MW above the 1992 peak demand of 1,959 MW. )
Midwest Power is interconnected with certain Iowa and neighboring utilities and is one of 43 utilities involved in an elecuic power pooling agreement known as the Mid-Continent Area Power Pool (MAPP).
The purpose of MAPP is to coordinate the planning, construction and operation of generation and transmission facilities, including the purchase and sale of power and energy among members. In addition, Midwest Power and two other lowa investor-owned utiLiles are panners in ENEREX, a general pannership.
ENEREX coordinates the purchase and sale of electric energy among the partners and handles the daily unit commitment function.
The transmission lines of Midwest Power, operating from 34,500 to 345,000 volts, totaled 3,591 circuit miles at December 31,1993.
in October 1992 the National Energy Policy Act (NEPA) was signed into law. NEPA, which allows all electric generators to transpon wholesale power across utilities' transmission facilities, will promote competition in the wholesale electric market. The increasingly competitive environment brings with it an increase in risk. The Company is currently evaluating the law and its impact on Midwest Power. Refer to the " Regulatory Envimnment" section of" Management's Discussion and Analysis of Financial Condition and Results of Operations" in Pan IV, Item 14, of this filing.
Generation by coal, nuclear, oil and natural gas as a percent of Midwest Power's total net generation of electricity dunng each of the last three calendar years and the average cost to the Company of those fuels are as follows:
All Fuels Year
% of Generation Average Cost Ended Coal Nuclear Gas / Oil (Mills per kWh) 1993 84 15 1
9.5 1992 75 24 1
9.1 1991 79 20 1
10.0 Fuel Supply Midwest Power has contracts and commitments providing for the fumishing of coal in quantities which are adequate, in the opinion of management, absent circumstances not now foreseen. Costs of coal are subject to price adjustments under the existing contracts. All of the Company's wholesale sales (which am pan of sales for resale) and retail sales of electricity am subject to energy adjustment clauses.
Approximately 50 percent of Midwest Power's coal needs for 1994 are expected to be met by coal delivered under its five major coal supply contracts. The balance will be met with coal purchased on the spot market.
Midwest Power's five major coal supply contracts under which deliveries are currently being received are as follows:
Year in Which Contracted Annual Contract Exnires Tonnace (1) 1994 292,000-439,000 (2) 1998 730,000-893,000 1999 760,000-921,000 (3) 2001 360,000-633,000 (3) 2003 621,000-887,000 (3)
(1)
Company's share only where contract penains to jointly owned unit.
(2)
Option to extend for 2 years.
(3)
Tonnage varies per specified annual contract amounts.
7
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i Midwest Power has contracts with rail shippers providing for the delivery of coal to its generating stations.
Recently, utilities in the Midwest, including Midwest Power, have been experiencing delays in the delivery of coal from rail shippen. While the Company has been working with shippers. such delays, which have been caused by the 1993 summer floods, cold winter weather and other factors relating to the shippers' capabilities to deliver coal within specified delivery schedules have resulted in lower than normal stockpiles at certain of Midwest Power's generating facilities. The Company does not anticipate any adverse impact to its firm customers although it has reduced its ac:ivities in the bulk sales market.
Natural gas and oil are used for peak demand electric generation and for standby purposes. These sources are in adequate supply and available to meet the Company's needs.
Approximately 30 percent of the fuel in the core at Cooper Nuclear Station must be replaced every 18 months.
For additional information concerning electric operations, see "Unaudited Utility Statistics", in Pan IV.
Item 14, of this filing.
NATURAL GAS OPERATIONS Midwest Gas has been engaged in the pmcurement, transportation, and distribution of natural gas for utilities and end-use customers primarily in the Midwest. With the implementation of FERC Orders 636, 636A and 636B (Order 636 or Orders) related to the regulation of natural gas intestate pipeline companies on November 1,1993, Midwest Gas began operating in a more competitive environment. Midwest Gas now has complete responsibility for natural gas procurement, transponation and storage, a responsibility which had previously resided with Midwest Gas' interstate pipeline suppliers. These Orders directly impact the operations, revenues and costs of local distribution companies (LDCs), including Midwest Gas, and create new opponunities.
On August 31,1993, Midwest Gas acquired the South Dakota distribution properties of Minnegasco, a division of Arkla, Inc., and Minnegasco acquired Midwest Gas' Minnesota distribution propenies. Refer to
" Midwest Gas Operations" in " Management's Discussion and Analysis of Financial Condition and Results of Operations", included in Pan IV, Item 14, of this filing for more discussion of the exchange. As of December 31, 1993, Midwest Gas was distributing natural gas at retail to 342,000 customers in 204 communities in Iowa,27 communities in South Dakota and 2 communities in Nebraska. Midwest Gas distributes the natural gas thmugh 10,378 miles of distribution mains and services. During the 1993-94 l
heating season, the Midwest Gas firm peak day sendout was 539,000 MMBtu. Refer to "Unaudited Utility Statistics" in Pan IV, Item 14, for additional information related to Midwest Gas' natural gas operations.
Refer to " Regulatory Environment" in " Management's Discussion and Analysis of Financial Condition and
(
Results of Operations" included in Pan IV, Item 14, for funher discussion of the impact of Order 636.
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J Fuel Supply and Capacity With the implementation of FERC Order 636, Midwest Gas purchases the majority of its supplies either directly from producers or from third-pany marketers. Midwest Gas uses a geographicaUy diverse supply ponfolio with varying terms to ensure system reliability. The term and geographic mix of contracted supplies are shown in the following table:
Long-Term Shon-Term Spot Market (More Than 1 Year)
(Less Than 1 Year)
(Daily /Monthlv)
4%
36 %
63 %
Canada 29 %
4%
2%
35 %
Other 2%
2%
Total 52 %
8,%
40%
100 %
In preparation for the increased supply responsibilities under Order 636, Midwest Gas increased its natural gas inventory for the 1993-94 heating season. In the future, Midwest Gas will be able to mom accurately determine its natural gas needs for operating under the rules of Order 636 via improved telemetering techniques and after it and other involved panies gair, experience in the new environment.
Midwest Gas maintains contracts for transportation capacity from three pipelines: Nonhem Natural Gas Company (NNG), Natural Gas Pipeline Co. of America (Natural), and ANR Pipeline Company (ANR).
Contracts with NNG provide delivery of 183,000 MMBtu per day of 12-month firm transpon service and 131.100 MMBtu per day of seasonal firm transpon service to meet winter peak demands. Contracts on a firm delivery basis with Natural are 60,700 MMBru per day of finn transpon service and 18,800 MMBru per day of transportation and storage service during peak periods. Contracts with ANR provide for delivery of 6,600 MMBtu per day of firm transport service.
In addition Midwest Gas also contracts for storage gas supplies. This storage gas is available primarily during the heating season and is delivered on either a firm or intermptible tmnsponation contract. The following table shows the quantities of storage gas supplies available from each storage provider:
Storage Total Storage Maximum Daily Provider (MMBtu)
Withdrawal (MMBlu)
NNG 6,000,000 139,000 Natural 3,048,500 36,700 ANR 359,900 4,800 Richfield 1,325,000 21,200 In order to meet peak day gas demand during winter months, two liquefied natural gas plants enable the liquefaction and storage of gas during off peak months for use during the heating season and provide additional maximum daily delivery capacity of 69,600 MMBtu. In addition,5 propane-air gas peak shaving plants, of which 4 are located in Iowa and 1 in South Dakota, have 81,300 MMBtu maximum daily delivery capacity.
Natural gas distribution facilities located in the Midwest experience significant seasonal demands. Sales during the spring and summer months are traditionally lower than the fall and winter heating season. These,
seasonal swings in demand msult in additional availability of firm pipeline capacity during cenain pans of the year. Midwest Gas has entered into numerous buy / sell arrangements which allow it to market its available firm capacity during these periods. FERC also established a " capacity brokering" mechanism under Order 636, which gives LDCs an opponunity to broker any unused capacities for various terms.
A purchased gas adjustment clause, which exists in all jurisdictions, permits rates charged to a majority of Midwest Gas' customers to be adjusted as natural gas transponation and supply costs change.
9
4 ITEM 2. PROPERTIES Reference is made to item 1 (c) " Electric Operations" and " Natural Gas Operations" of this filing conceming the propenies of the Company.
It is the opinion of management that the principal depreciable utility propenies owned by the Company are in good operating condition and well maintained.
The Mortgage and Deed of Trust of IPS as amended and supplemented constitutes a first mongage lien on substantially all of the propenies owned by the Company suuject only to excepted encumbrances. The MPS Ceneral Mongage Indenture and Deed of Trust dated January 1,1993, constitutes a junior lien on all of the Company's electric propenies located in Iowa subject to the IPS indenture and a first lien on all remaining and new electric propenies in Iowa. It will become a first lien on all lowa electric propenies when the remaining $11 million of long-term debt outstanding issued under the IPS indenture is retired.
ITEM 3. LEGAL PROCEEDINGS The Company and its subsidiaries have no material legal pmceedings except for the following:
Environmental Maners, Reference is made to item 1(c), " Environmental Matters," and to Pan IV, item 14, Note (2)(b) of Notes to Consolidated Financial Statements.
ITEM 4. RESULTS OF VOTES OF SECURITY HOLDERS No matters were submitted to a vote of the Company's security holders during the founh quaner of 1993.
i.-.
4 PART II ITEM 5. MARKET FOR TIIE REGISTRANT'S COMMON EOUITY AND RELATED STOCKHOLDER MATTERS Market Infonnation and Dividends:
The Company's outstanding common stock is held entirely by its parent company, MWR, and is not publicly traded. The annual total of quanctly common stock cash dividends declared by the Company to MWR in 1993 and 1992 were $63,551,000 and $73,944,000, respectively.
ITEM 6. SF.LECTED FINANCIAL DATA Reference is made to Pan IV of this repon.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCI AL CONDITION AND RESULTS OF OPERATIONS Reference is made to Pan IV of this repen.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA For the information required by Item 8 for the Company, including the (i) Consolidated Statements of Income, (ii) Consolidated Statements of Cash Flows, (iii) Consolidated Balance Sheets, (iv) Consolidated Statements of Capitalization, (v) Consolidated Statements of Retained Earnings, (vi) Notes to Consolidated Financial Statements and (vii) Report ofIndependent Public Accountants, reference is made to Pan IV of this repon.
ITEM 9. CIIANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCI AL DISCLOSURE None.
PART III 4
ITEM 10. DfRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information concerning the directors and executive officers of the Company is as follows:
(a)
Identification Served Present in Present Served as Name
. Age Position Position Since Director Since Russell E. Christiansen 58 Chainnan, President and 1992 1992 Chief Executive Officer Richard C. Engle 59 Executive Vice President, Midwest 1992 1992 Power-Generation and Transmission and Director Lynn K. Vorbrich 55 Executive Vice President Midwest 1992 1992 Power-Distribution and Director Philip G. Lindner 50 Group Vice Pitsident-1992 1992 Administrative Services and Director Beverly A. Wharton 40 Group Vice President.
1992 1992 Midwest Gas and Director John A. Rasmussen, Jr.
48 Vice President and General Counsel 1992 i
James R. Bull 52 Vice President 1992 James J. Howard 51 Vice President 1992 Lester A. Juon 55 Vice President 1992 l
- Robert L. Lester 52 Vice President 1993 l
Paul J. Leighton 40 Secretary and Assistant Treasurer 1992 J. Sue Rozema 41 Treasurer and Assistant Secretary 1992 Larry M. Smith 38 Controller 1972 Each director and executive officer serves an annual term of office. Officers are elected annually by the Board of Directors. There are no family relationships between the foregoing executive officers and directors of the Company, nor any arrangements or understandings between any director or officer and any other person pursuant to which the director / officer was elected.
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I (b) Business Experience Durine the Last Five Years and Directorshios Russell E. Christiansen Chairman and Chief Executive Officer of MWR since 1992, President since.
1990 and Vice Chairman and Chief Operating Officer of MWR fmm 1990 to 1992. Chainnan and Chief Executive Officer of MWE from 1986 to 1990 and Presic'ent from 1985 to 1990. Chairman, President and Chief Executive Officer of MPS since 1992. Chairman and Chief Executive Officer of IPS from 1986 to 1992 and Chainnan and Chief Executive Officer of IPR from 1990 to 1992.
Director of Norwest Bank lowa, N.A.
1 Richard C. Engle Executive Vice President of MPS since 1992. President and Chief Operating -
Officer of IPS from 1990 to 1992, Senior Vice President and Chief Operating i
Officer from 1987 to 1990.
Lynn K. Vorbrich Executive Vice President of MPS since 1992. President and Chief Operating Officer ofIPR from 1989 to 1992. Executive Vice President ofIPR from 1986 to 1989.
Philip G. Lindner Group Vice President of MPS since 1992. Senior Vice President ofIPR from 1990 to 1992. Vice President of IPR in 1989. Prior to joining IPR in 1989, Mr. Lindner served as Vice President and Chief Financial Officer for MacNeal Hospital from 1987 to 1989, i
Beverly A. Wharton Group Vice President of MPS since 1992. Senior Vice President of IPS from -
1988 to 1992. Vice President from 1985 to 1988 and Secretary from 1984 to i
1988.
Each of the officers not also serving as a director has been employed by the Company or one of its-predecessors. IPS or IPR, for more than five years in various officer capacities except for LarTy M. Smith.
Mr. Smith has served as Controller of MPS since 1992. He was Controller ofIPS from 1990 to 1992 and j
Controller of MWE in 1990. From 1985 to 1990 he was Manager of Corporate Accounting for MWE and i
was the acting Controller from 1988 to 1990.
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e ITEM 11. EXECUTIVE COMPENSATION The following table sets fonh the compensation for services in all capacities to MWR and its subsidiaries for the fiscal years ended December 31,1993,1992 and 1991, of those persons who wem, at December 31,1993. (i) the chief executive officer and (ii) the other four most highly compensated executive officers of the Company (" named executive officers"). Portions of the compensation shown in the following table is recovered from affiliate companies for services rendered to them by the named executive officers or through the sharing of costs through the MWR corporate allocation.
Summary Compensation Table
_ Annual Compensation Name and Principal Other Annual All Other Position Year Salarv($)
Bonus ($)(1)
Comnensation($)
Russell E. Christiansen 1993 383,333 39,105 5,310 40,048(2)
Chairman, President and 1992 380,000 0
0 38,570 Chief Executive Officer 1991 360,000 60,000 0 29,980 Richard C. Engle
'993 225,000 23,017 0 25,238(3)
Executive Vice President 1992 224,000 0
4,583 24,201 1991 212.000 31,800 0 18,583 Lynn K. Vorbrich 1993 228,446 23,422 0 17,586(4)
Executive Vice President 1992 232,061 0
4,510 16,947 1991 211,492 31,800 0 14,978 Philip G. Lindner 1993 154,808 17,969 0 13,870(5)
Gmup Vice President 1992 155,446 0
3,413 9,923 1991 142,662 19,200 0 11,744 Beverly A. Whanon 1993 152,500 14,875 0 12,598(6)
Gmup Vice President 1992 136,000 0
2,132 9,835 1991 122,000 16,400 0 11,186 (1) Amounts shown for 1993 represent pan of the estimated total incentive compensation award, which cannot be presently determined. The balance of the actual award will be paid in 1994 at such time as l
definitive corporate performance measures are calculated. See the Management Development Committee Repon on Executive Compensation staning on page 15 for a discussion of the 1993 bonus.
(2) Consists of $15,000 as director fees, $22,050 for supplemental life insurance and a contribution by the Company of $2,998 to a defined contribution plan.
i l
(3) Consists of $8,000 as director fees, $14,240 for supplemental life insurance and a contribution by the Company of $2,998 to a defined contribution plan.
(4) Consists of $8,000 as director fees,58,000 for supplemental life insurance and a contribution by the Company of $1,586 to a defined contribution plan. i
(5) Consists of $8,000 as daector fees,53,685 for supplemental life insurance and a contribution by the Company of $2,185 to a defined contribution plan.
(6) Consists of $8,000 as director fees, $1,600 for supplemental life insurance and a contribution by the Company of $2,998 to a defined contribution plan.
MANAGEMENT DEVELOPMENT COMMITTEE REPORT ON EXECUTIVE COMPENSATION The Management Development Committee (Committee) of the MWR Board of Directors (Board of Directors) has fumished the following report on executive compensation. This committee, along with the MWR Board of Directors as a whole, determines compensation for officers of the parent company and affiliates. The term " Company" refers to MWR in this report.
The Management Development Committee is comprised of directors who are not current or former officers or employees of the Company or any ofits subsidiaries. The Committee has the following responsibilities:
1.
Review the performance of senior management, including the Chief Executive Officer.
2.
Review compensation, benefits, pension plans and other forms of indirect compensation for officers and senior managerial employees.
- 3. Consider the needs for succession planning and adequacy of plans to assure continuity of the Company's management.
4.
Review, approve and recommend to the Board of Directors and administer various incentive compensation plans, including annual and long-term plans.
The Company has a compensation policy which is designed to compensate management with salary, incentives and benefits at levels generally competitive with comparative utility companies and general industry. Comparative utility companies consist of those that are members of utility industry associations, some of which may also be included in the published industry index referenced in the shareholder return performance graph. Incentive plans and performance review pmcesses are intended to encourage and reward outstanding performance. The compensation policy and the goals set for incentive plans are designed to benefit shareholders and customers as well as to attract and retain highly qualified and capable executives.
In addition, the policy for establishing incentive compensation plans is intended to place a portion, ranging fmm appmximately one-founh to one-half, of total compensation at risk.
The Committee annually reviews executive compensation in December of each year for the purpose of determining base salaries for the next year. As part of its review, the Committee evaluates overall corporate performance, including eamings, comparative utility and general industry compensation levels and salary recommendations made by the Chief Executive Officer of the Company. The Committee then recommends base salaries to the Board of Directors. In January of each year, the Committee sets targets and goals for the annual and long term incentive compensation plans for that year. In the second and third quarters of each year, the Committee evaluates the attainment of targets and goals under these plans for the preceding year and determines the level ofincentive awards,if any. Exceptionalindividual performance may be additionally rewarded under the noncash bonus award plan.
Base Salaries The base salary for the named executive officers is determined by reference to the base salary paid to their respective peers at other comparable utility companies, industry and national surveys and performance judgments as to the past and expected future contributions of the individual executives. As a general guideline, base salaries for the named executive officers are targeted at the utility industry average for comparative companies as determined through compensation surveys prepared by utility industry associations.
In evaluating the performance of the named executive officers, the Committee considers their individual contributions in achieving operating and management efficiencies, applicable business unit performance and individual performance. The Committee also condders aang.a:ent's commitment to the long term growth of the Company by focusing on the strategic opponunities of the utility and nonutility businesses and developing plans to implement these strategies. Such strategic opponunities include those resulting from deregulation of certain aspects of the natural gas and electric utility businesses and the focusing of the nonutility businesses on the Company's core suengths.
In December 1992, the Comminee reviewed with Mr. Christiansen the performance of each of the named executive officers during 1992 and the base salary adjustments recommended by Mr. Christiansen. In accordance with the recommendation of Mr. Christiansen, the Committee recommended to the Board of I
Directors that the named executive officers, including Mr. Christiansen, not receive a base salary adjustment for 1993 as a result of the Company not meeting its corporate perfonnance goals for 1992, as discussed below under Annual Incentive Compensation, with the exception of Mrs. Whanon who received an adjustment due to a change in responsibilities and outstanding individual performance. The Board of Directors concurred with the recommendations of the Committee.
l In October 1993, the Committee recommended to the Board of Directors that base salary adjustments for 6
l the named executive officers for 1994 be made effective November 1,1993, in recognition of the Company's significantly improved fmancial performance through the end of the third quaner and the expected year end
(
results. Individual adjustments ranging from two and seven-tenths percent to ten percent were determined using the criteria discussed above. The Committee independently reviewed the perfonnance of Mr.
Christiansen during 1993 and recommended to the Board of Directors that he receive a 1994 base salary adjustment of frve percent in recognition of his contribution in leading the Company and its combined j
operations to greater operating and management efficiencies and significantly improved financial performance.
The Board of Directors concraed with the recommendations of the Committee.
AnnualIncentive Comperation The Company adopted a Key Executive AnnualIncentive Compensation Plan for key employees, including the named executive officers, effective in 1992. Individual awards under this plan are based on the achievemen'. of specific individual, business unit and corpomte performance goals which are revised annually.
For Mr. Chistiansen, seventy-five percent of his award is based on overall corporate goals and twenty-five percent on individual goals. For the other named executive officers with operations responsibilities, fony percent of their awartis are based on achieving business unit goals, fony percent on overall corporate goals and twenty percent on individual goals. For the other named executive officers with staff responsibilities, sixty percent of their awards are based on overall corporate goals and fony percent on individual goals.
Corporate performance goals consist of a shareholder measure of targeted eamings growth with a minimum eamings level to be achieved before any awards may be made and a customer measure of electric and gas rate performance as compared to other specific utility companies. Business unit goals consist of unit operations and maintenance cost measures and utility customer service measures, including service reliability and responsiveness to customer needs. Individual goals are developed by cach of the other named executive officers and reviewed by the Chief Executive Officer. The achievement of the corporate performance and business unit goals is indexed on a sliding scale basis. As the goal is achieved and then exceeded, the index scales up. A target award of twenty-eight percent of annual base salary will be made to the other named executive officers upon achievement of one hundred percent of the established goals with a maximum award of forty-two percent if the established goals are exceeded as determined by the index. The Chief Executive Officer is eligible for a target award of thiny-five percent and a maximum award of fifty-two and one-half i
l percent. Up to one-half of the award is paid in cash and the remainder in performance shares. Each performance share has a value equal to one share of the Company's Common Stock. The specific goals are not included herein because they are believed to represent confidential business information. No awards were made for 1992 performance since the corporate perfonnance goals were not achieved. In December 1993, 1
I l l l
l
annual incentive awards wem made to Mr. Christiansen and the other named executive officers in the amounts shown on the Summary Compensation Table due to the achievement of the corporate performance and business unit goals. The amounts shown represent,in the case of Mr. Christiansen, fifty percent of the cash ponion of the estimated total incentive award, and in the case of the other named executive officers, seventy-five percent of the cash ponion of the estimated total incentive award. The balance of the cash ponion of the award will be paid in 1994 and the deferred portion of the award will be credited to the respective panicipant's plan account after definitive corporate performance measures are calculated.
l Long-Term incentive Compensation A Long-Temi incentive Compensation Plan was also adopted by the Company for the named executive officers, effective in 1992. Individual awards under this plan are based on the achievement of cenain corporate performance goals during each three year performance cycle, with the first cycle consisting of the yean; 1990 through 1992 and the last cycle years 1994 through 1996. The two goals which must be met each year under the plan are the annual growth in corporate camings per share and the retum on shareholder equity. The target for each goal for the current year of the cycle is determined in January by tne Committee.
The camings per share goal is weighted at seventy-five percent with the retum on equity goal weighted at j
twenty-five percent. Target awards range from seven and one-half percent to twenty-five percent of annual
}
base salary with maximum awards ranging from twelve and one-half percent to thiny-seven and one-half percent if the goals are exceeded. The Chief Executive Officer is eligible for awards at the twenty-five percent / thirty-seven and one-half percent levels. Cash awards are paid at the end.of a performance cycle.
The specific goals are not included herein because they are believed to represent confidential business information. No awards were made for the cycles ending December 31,1992, or December 31,1993, since the corporate performance goals for each cycle were not achieved.
Noncash Bonus Awards The Company has adopted a noncash bonus award plan for cenain officers of the Company. Individual 1
awards are made in performance shares and paid in cash at the earlier of retirement, death, disability or involuntary termination without cause. Awards are made at the discretion of the Board of Directors upon recommendation by the Committee in recognition of exceptional performance. No awanis were made under this plan for plan yevs 1992 or 1993.
RETIREMENT PLANS The Midwest Power Systems Inc. Salaried Employees' Retirement Plan (" Midwest Power Retirement Plan") provides for payment of fixed pension benefits to persons who retire after a specified age and number of years of service, based on average annual salary during the five highest paid consecutive years out of the last ten years prior to retirement. For Messrs. Christiansen and Engle and Mrs. Whanon, benefits for service prior to January 1,1992, are determined as provided by a predecessor retirement plan using the final average pay method, based on the employee's highest five years' eamings. Messrs. Christiansen, Engle, Vorbrich and Lindner and Mrs. Whanon are participants in the Midwest Power Retirement Plan and are credited with 34,29,21,4 and 17 years of service, respectively.
The Company maintains an unfunded Supplemental Retirement Plan (" Supplemental Plan") to provide additional retirement benefits to cenain officers, as determined by the Board of Directors. Messrs.
Christiansen. Engle, Vorbrich and Lindner are participants in the Supplemental Pian. Pan A of the Supplementa! Plan provides retirement benefits up to sixty-five percent of a panicipant's highest annual salary during the five years piior to retirement reduced by the panicipant's Midwest Power Retirement Plan benefit.
The percentage applied is based on years of credited service. A panicipant who elects early retirement is entitled to reduced benefits under the plan. A survivor benefit is payable to a surviving spouse. Pan B of the plan provides that an additional one hundred-fifty percent of annual salary is to be paid out to panicipants at the rate of ten percent per year over fifteen years, except in the event of a participant's death, in which event the unpaid balance would be paid to the participant's beneficiary or estate. Benefits from the Supplemental Plan will be paid out of general corporate funds. Deferred compensation is considered part of the salary covered by the Supplemental Plan.
The table below shows the estimated aggregate annual benefits payable (for the first 15 years of retirement) under the Supplemental Plan and the Midwest Power Retirement Plan. The amounts exclude Social Security and are based on a straight life annuity and retirement at age 65. Amounts shown are calculated on the basis of credited service. Federallaw limits the amount of benefits payable to an individual through the Midwest Power Retirement Plan and benefits exceeding such limitation are payable under the Supplemental Plan.
Estimated Annual Benefit Years of Service Highest Annual Salary in Five
' Years Prior to 25 or Retirement 10 15 20 More
$150,000
$ 90,000
$ 97,500
$105,000
$112,500 200,000 120,000 130,000 140,000 150,000 250,000 150,000 162,500 175,000 187,500 300,000 180,000 195,000 210,000 225,000 350,000 210,000 227,500 245,000 262,500 400,000 240,000 260,000 280,000 300,000 450,000 270,000 292,500 315,000 337,500 500,000 300,000 325,000 350,000 375,000 Mrs. Whanon is a panicipant in the Midwest Resources Inc. Supplemental Executive Retirement Plan i
l
(" Midwest Supplemental Plan"), a nonqualified plan for cenain executives of the Company and its l
subsidiaries, as determined by the Board of Directors. The Midwest Supplemental Plan pmvides a l
participant, upon retirement at age 65 with thirty or more years of service, an annual retirement benefit equal to sixty percent of the participant's final average annual camings which is defined as the average of salary plus bonus for the five highest consecutive years during the participant's employment with the Company.
A panicipant who elects early retirement is entitled to reduced benefits under the plan. Payment of the retirement benefit will be made in the same manner as payments are elected by the participant under the Midwest Power Retirement Plan. This benefit will be reduced by the amount of the panicipant's regular retirement benefit. Benefits may be paid to surviving spouses depending on the payment method selected.
Benefits to panicipants will be paid out of general corporate funds. Deferred compensation is considered pan of the salary covered by the Midwest Supplemental Plan.
The table below shows the estimated aggregate benefits payable under the Midwest Supplemental Plan and the Midwest Power Retirement Plan. The amounts exclude Social Security and are based on normal retirement at age 65. Federal law limits the amount of benefits payable to an individual through the Midwest Power Retirement Plan and benefits exceeding such limitation are payable under the Midwest Supplemental Plan.
6 1 l
Estimated Annual Benefit Years of Service Highest Average 30 or Total Eamines 15 20 25 More
$150,000
$ 67,500
$ 75,000
$ 82,500
$ 90,000 200,000 90,000 100.000 110,000 120,000 250,000 112,500 125,000 137,500 150,000 300,000 135,000 150,000 165,000 180,000 350,000 157,500 175,000 192,500 210,000 400,000 180,000 200,000 220,000 240,000 450,000 202,500 225,000 247,500 270,000 500,000 225,000 250,000 275,000 300,000 DIRECTORS' COMPENSATION Directors each receive an annual fee of $8,000. No meeting fees are paid, in addition Mr. Christiansen j
receives an annual amount of $7,000 from MWR as director fees for service on the MWR Board of Directors.
Directon have the opponunity to make an election prior to the commencement of any year to defer a portion or all of their compensation received for service as a director pursuant to the Midwest Resources Inc. Board of Directors Deferred Compensation Plan. Amounts previously deferred under predecessor companies' defined compensation plans will be distributed in accordance with each such plan's respective provisions upon a director's termination of service as a director.
t 4.
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND M ANAG MWR owns 100 percent of the 1,000 shares of MPS' common stock, without par value, which were outstanding on February 25,1994.
The following table sets fonh information conceming each class of MWR's and MPS' equity securities 25, 1994, by each of MPS' directors and which were owned of record or beneficially held on Febnmry nominees for election as directors, the chief executive officer and the four other most highly compensated executive officers and, as a group, by such persons and other executive officers. The number of shares owned by any director or nominee, or by all directors and executive officers of MPS as a group, did not exceed one percent of MWR shares outstanding on February 25,1994.
Name of Director Amount and Nature of Title of Class or Identity of Group Beneficial Ownershin (1)
Midwest Resources common Russell E. Christiansen I1,761(2) stock, without par value Midwest Resources common Richard C. Engle 8,288(3)
Stock, without par value Midwest Resources common Philip G. Lindner 1,266(4) stock, without par value Midwest Resources common Lynn K. Vorbrich 3,674(5) stock, without par value Midwest Resources common Beverly A. Wharton 3,248(6) stock, without par value Midwest Resources common 13 directors and officers, 61,888(7) stock, without par value as a group Beneficial ownership of each of the shares of Common Stock listed in the foregoing table is (1) comprised of either sole voting power and sole investment power, unless otherwise noted.
Includes 6,377 shares held in a defined contribution plan as of December 31,1993, and 5,276 (2) shares beneficially owned by Mr. Quistiansen and his spouse.
Includes 6,490 shares held in a defined contribution plan as of December 31,1993, and 1,170 (3) shares beneficially owned by Mr. Engle's spouse and 628 shares beneficially owned by Mr. Engle and his spouse.
Includes 128 shares held in a defined contribution plan as of December 31,1993, and 1,138 shares (4) owned beneficially by Mr. Lindner and his spouse.
includes 1,465 shares held in a defined contribution plan as of December 31,1993, and 242 shares (5) beneficially owned by Mr. Vortrich and his spouse...
(6) Includes 1,058 shares held in a defined contribution plan as of December 31,1993, and 1,831 shares beneficially owned by Mrs. Whanon and her spouse and 359 shares beneficially owned in a custodial account for a minor child.
(7) lacludes shares held in defined contribution plans as of December 31,1993, and shares beneficially owned jointly with and individually by family members.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Reference is made to Pan IV, Item 14, Note (15) of Notes to Consolidated Financial Statements for a summary of affiliated transactions.
1 l
PART IV ITEM 14. EXHIBITS. FINANCIAL STATEMENT SCHEDULES. AND REPORTS ON FORM 8 K (a)1. Financial Statements (included herein)
Pace No.
Selected Consolidated Financial Data.......
24 Management's Discussion and Analysis of Financial Condition and Results of Operations 25 Consolidated Statements of Income For the Year Ended December 31,1993,1992 and 1991 34 Consolidated Statements of Cash Flows For the Year Ended December 31,1993,1992 and 1991 35 Consolidated Balance Sheets As of December 31,1993 and 1992...............
36 Consolidated Statements of Capitalization As of December 31,1993 and 1992.......
38 Consolidated Statements of Retained Eamings For the Year Ended December 31,1993,1992 and 1991.........
39 Notes to Consolidated Financial Statements 40 Management's Responsibility For Financial Sta'ements 56 Report of Independent Public Accountants..........
57 Unaudited Utility Statistics.........
58 i
(a)2. Financial Statement Schedules (included herein)
The following schedules should be read in conjunction with the aforementioned financial statements.
For the Year Ended December 31,1993,1992, and 1991 -
Page No.
Amourts Receivable from Related Panies, Underwriters, Promoters and Employees Other Than Related Parties (Schedule 11) 61 Consolidated Property, Plant and Equipment (Schedule V)......
64 Consolidated Accumulated Depreciation. Depletion and Amonization of Propeny, Plant and Equipment (Schedule VI).......
67 Consolidated Valuation and Qualifying Accounts (Schedule VIli)....
70 Consolidated Shon-Term Borrowings (Schedule IX).....
71 Consolidated Supplementary income Statement Information (Schedule X) 72 Other schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
l 22-
4 1
(a)3. Exhibits See Exhibits Index on page 74.
(b) Reports on Form 8.K None.
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MIDWEST POWER SYSTEMS INC.
SELECTED CONSOLIDATED FINANCIAL DATA (1) and (2) 1993 1992 1991 1990 1989 For the year ended December 31 (000)
Operating revenues............
S 996,545 $ 923,180 S 929,813 $ 876,943 $ 899,119 Operating income......
132,397 112,971 137,646 135,814 141,174 Earnings on common stock (3) 83,503 46,944 72,082 75,072 82,474 As of December 31 Total assets (000)............
2.384,454 2,231,585 2,233.083 2,130,738 2,090,050 Capirah7:ition ($ Millions-%)
Common stock equity..................
$655-46% $636-45% $664-45% $624-45% $61845%
30-2 %
30-2 %
30-2 %
Cumulative redeemable preferred stock Cumulative non-redeemable prefened stock...
90- 6% ~
54-4 %
54-4 %
54-4 %
54-4 %
Long-term debt (excluding cunent matunties) 678-48 % 727-51 %
741-49 %
666-49 %
676 49%
Liability under power purchase contract (000)...
5151,485 $146,150
$150,838
$159,293
$167,282 (1) In July 199210wa Public Service Company and Iowa Power Inc. merged into and with Midwest Power Systems Inc.
The data included in this statement is presented as if the companies were merged as of the earliest penod shown and reflects the historical recorded amounts of the predecessor companies. Refer to Note (1)(a) of Notes to Consolidated Financial Statements.
(2) The Company exclumged its Minnesota gas propenies for Minnegasco's South Dakota gas propenies and cash during 1993. 7he Company sold certain other assets during 1989. The income from these transactions is reflected in earmngs.
(3) Eammgs per average common share and dividends on common stock per share are not applicable to MPS as a wholly-owned subsidiary.
24
i MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion of the financial condition and results of operations of Midwest Power Systems Inc. (MPS or Company) is intended to provide readers of the financial statements included in this annual repon with an understanding of material changes in the Company's financial condition and results of operations between the periods presented.
MPS is the principal subsidiary of Midwest Resources Inc. (MWR), a holding company formed in November 1990 through the merger of two utility holding companies. MPS maintains two operating divisions: Midwest Power and Midwest Gas.
The Company's results of operations are significantly influenced by weather conditions, general economic conditions in the Company's utility service territory and rate regulation. The Company is allowed current recovery from most ofits customers for fuel and power purchased costs, including the fuel ponion of Cooper Nuclear Station Power Purchased, through an energy adjustment clause and for gas purchased costs through a purchased gas adjustment clause. Thus, as the cost of fuel used to serve those customers fluctuates, revenues fluctuate accordingly, with no impact on camings.
RESULTS OF OPERATIONS Eaminos:
Eamings on Common Stock (Earnings on Common) for 1993 was substantially improved compared to Eamings on Common for 1992. Eamings on Common for 1993 was $83.5 million compared to $46.9 million for 1992 and $72.1 million for 1991.
Two factors explain $34.5 million of the $36.6 million increase in Earnmgs on Common for 1993.
Greatly improved weather conditions resulted in an increase of approximately $23 million compared to 1992, and an exchange of gas service territories produced an $11.5 million after-tax gain. Though still below normal, the 1993 weather resulted in greater use per customer than the unusually mild weather in 1992. On August 31,1993, Midwest Gas and Minnegasco exchanged gas service territories. Miruiegasco received the Midwest Gas Minnesota seivice tenitory, which serves over 79,000 customers, and Midwest Gas received the Minnegasco South Dakota service territory, which serves over 46,000 customers, and a
)
538 million cash payment.
A reduction in interest expense reflects the impact of the Company's debt refinancing activities and resulted in an improvement to Eamings on Common of $2.6 million. Also contributing to the increase in Eamings on Common compared to 1992 was a $1.5 million reduction of the 1992 Eamings on Common due to recognition of a loss on the sale of propeny. Continued realization of merger savings
)
also helped to increase the 1993 camings.
New federal income tax legislation which increased the rate by one percentage point retroactive to January 1,1993, resulted in $1 million of additional income tax expense in the third quaner and income taxes recorded at the higher tax rate for the remainder of the year.
In July, the Company's utility service territory experienced record flooding. Tne flooding damaged five of the Company's substations and disrupted service at two others. Costs of restoring service lost during the flooding are reflected in the 1993 results. While revenues were reduced somewhat due to the flooding, the Company has not calculated a specific effect on revenues. Damage to the Company's utility i
facilities totalled $5 million, most of which is expected to be covered by insurance. As a result there was not, and will not be, a significant impact on the Company's overall financial results.
Eamings on Common for 1992 decreased $25.2 million compared to Eamings on Common for 1991.
The unusually mild weather during 1992 and warmer than normal weather in the summer of 1991 resulted in an $18.4 million reduction in Eamings on Common between the years. The loss recognition discussed above and an adjustment for previously deferred demand-side management costs accounted for $2.6 million of the decrease, i
The following table provides a summary of the Eamings on Common contribution of each of the business segments discussed in the following pages.
Analysis of Earnings on Common 1993 1992 1991 (In Millions)
Midwest Power...............
$60.2
$39.9
$65.2 Midwest Gas.......
23.3 7.0 6.9 Eamings on Common.....
$83.5
$46.9
$72.1 Further details of the variations in Eamings on Common and changes in the line items on the Consolidated Statements of Income are discussed below.
Midwest Power Operations:
Weather conditions which were closer to normal in the Company's service territory accounted for nearly $20 million of the improvement in Eammgs on Common for Midwest Power.
Revenues Electric Revenue Increase l
(Decrease) from Prior Year 1993 1992 l
(In Millions) t Sales volumes........
$ 36.8
$(27.2)
Rates.....
7.7 5.1 Cost per unit of energy.
0.5 (2.7)
Sales for resale and other...
(4 0) 10.9 Total revenue variance..
S 41.0 5(13.9)
Weather fluctuation in the Company's electric utility service territory was the primary cause of the variations in Electric Operating Revenues. As shown in the table above, improved sales volumes contributed $36.8 million to the 541.0 million increase in revenues for 1993 compared to 1992. Weather that was more favorable to the electric utility industry helped to increase use per customer. Temperatures, l
measured in cooling degree days, were 31.0 percent warmer than during the 1992 cooling season. Use l
per customer for residential customers, the highest margin customers, increased 8.4 percent, and total retail l
electric sales increased 7.3 percent in 1993. The unusually mild cooling season in 1992 and an above normal cooling season in 1991 resulted in a reduction of sales volumes in 1992 compared to 1991.
l Temperatures were 51.7 percent cooler in 1992 than those in the 1991 cooling season. As a result, sales l
to all retail customers decreased 3.3 percent due mostly to a decrease in sales to n sidential customers of 9.1 percent. The milder temperatures and some conservation due to demand-side management (DSM) programs resulted in a 9.9 percent decrease in the 1992 resiantial use per customer. As shown in the table, the decrease in retail sales volumes in 1992 reduced the Company's revenues by $27.2 million compared to 1991. l
The impact of two rate cases settled during 1992 is reflected in the $7.7 million and the $5.1 million increases in revenues due to rate-related factors for 1993 and 1992, respectively.
An extended outage at Cooper Nuclear Station (Cooper) and increased retail sales volumes for the Company impacted the amount of energy available for sales for resale sales in 1993. (Cooper is a nuclear facility from which the Company purchases 50 percent of the energy output.) Sales for resale sales volumes in 1993 decreased 21.0 percent compared to 1992. Revenues from sales for resale sales decreased $8.5 million in 1993 compared to 1992 but remained above the 1991 amount. In 1992, sales for resale sales volumes increased 14.9 percent compared to 1991. The increase offset the 1992 decrease in retail sales and resulted in a 2.7 percent increase in total sales of electricity for 1992. The increase in sales for resale sales in 1992 was due to increased opportunities for sales for resale, increased availability of Company-generated energy due to lower retail sales and the impact of a bulk-power sales agreement effective in June 1991.
Expenses Fuel for Generation increased $9.7 million, or 9.5 percent, in 1993 compared to 1992. Generation at Company-owned facilities increased 10.9 percent in order to meet the greater generation needs as a result of increased sales volumes. Fuel for Generation decreased 6.4 percent in 1992 due to a 5.8 percent decrease in the average fuel cost per kWh generated. Lower retail sales reduced the need for the Company's higher cost plants during 1992, which helped to decrease the overall cost of fuel.
Power Purchased decreased $4.2 million in 1993 but increased $11.0 million in 1992 due mostly to the use and replacement of a nuclear energy power reserve that is used during maintenance and refueling outages at Cooper.
Cooper Nuclear Station Power Purchased decreased 0.5 percent in 1993 because of a $6.4 million decrease in fuel costs and a $5.9 million increase in Cooper operations and maintenance costs. The decicase in fuel costs was due to the extended maintenance and refueling outage in 1993. In 1992, Cooper Nuclear Station Power Purchased increased $13.8 million, or 19.0 percent. This was due to an
$11.4 million increase in opemtions and maintenance expenses and a $2.4 million increase in fuel costs.
Since Cooper did not have a refueling outage in 1992, more fuel was used than in 1991. The fuel costs for Cooper are recovered in revenues thmugh the energy adjusunent clause.
Other Operating Expenses increased only 1.6 percent and 1.2 percent in 1993 and 1992, respectively, due in pan to the impact of merger savings. In 1993, moderate increases in various general expenses contributed to the increase. A decrease in power production operating expenses helped to offset the increases in Other Operating Expenses. In 1992, the Company recorded a $1.1 million adjustment for DSM costs previously deferred. General increases in other operating expenses were panially offset by a decrease in costs related to the 1991 carly retirement and severance plan.
A $3.8 million increase in Maintenance expenses for 1993 compared to 1992 was mostly attributable to the timing of generating plant maintenance and general plant maintenance. Maintenance expenses in 1992 increased $2.4 million due to an increase in overhead distribution and transmission costs, including tree trimming expenses.
Depreciation and Amortization increases were due to an increase in depreciable plant. Generai Taxes decreased $3.7 million in 1993 and increased $0.5 million in 1992 due mostly to the change in pmperty assessment values. 5
Other, Net, for electric operations increased in 1993 due to the $2.5 million recognition of a loss on the sale of pmpeny in 1992, which also decreased Other, Net, compared to 1991. Allowance for funds used during construction (AFUDC) decreased $1.1 million for 1993 compared to 1992, due primarily to a reduced rate.
Midwest Gas Operations:
The $11.5 million after-tax gain resulting from the gas service territory exchange was the primary cause of the significant increase in Eamings on Common for the gas operations compared to 1992. The
$11.5 million gain reflects the impact of settlement adjustments at year-end.
As a result of the exchange,1993 results of operations wem impacted by the change in number of customers, rates, expenses and other factors. The discussion of the various components of results of operations includes the impacts of the exchange. The reduced pmperty and customer base will impact the Company's futum results of operations through lower gas revenues and decreases in cenain expenses.
Revenues for the year 1992 were approximately $33 million and $56 million for the South Dakota and Minnesota service territories, respectively.
Revenues Gas Revenue Increase (Decrease) from Prior Year 1993 1992 (In Millions)
Sales volumes
$ 17.4
$(12.2)
Rates 0.3 8.3 Cost per unit of gas purchased.
6.4 12.4 Transponation and other...
8.2 (1.0)
Total revenue variance.....
$ 32.3
$ 7.5 Unusually mild weather during the 1992 heating season had a major influence on the fluctuation in revenues between the years 1993,1992 and 1991. Gas Operating Revenues in 1993 were $323 million greater than those reponed in 1992. Temperatures, especially during the first quaner of 1993, were much more favorable to the gas operations. Measured in heating degree days, temperatures in 1993 were 13.7 percent colder than the unusually mild temperatures in 1992. Of the $17.4 million sales volumes increase reflected in the table, $20.7 million was due to a higher use per customer mostly as a result of the substantialincrease in heating degree days. A decrease in customers panially offset the use per customer increase. Total retail sales of natural gas increased 5.9 percent compared to 1992. The mild temperatures in 1992 were 4.3 percent warmer than during 1991. As a result, use per customer remained below the 1991 levels and decreased revenues by $17.6 million. A growth in' customers helped to offset that decrease and resulted in the $12.2 million net decrease due to sales volumes reflected in the table. Total retail sales of natural gas in 1992 decreased 5.4 percent compared to 1991.
An increase in the cost per unit of gas purchased resulted in $6.4 million and $12.4 million increases in revenues for 1993 and 1992, respectively, thmugh the purchased gas adjustment clause. This component has no impact on Eamings on Common because it is offset by a corresponding cost per unit increase in Gas Purchased for Resale. An increase in overall rates due in pan to interim and final rate increases in two gas rate cases yielded an $8.3 million increase in revenues in 1992 compared to 1991. - -
Expenses i
Gas Purchased for Resale increased $23.6 million for 1993 compared to 1992 and $3.8 million for 1992 compared to 1991. The increase in the cost per unit of gas contributed to the increases for 1993 and 1992. The increase in natural gas sales volumes resulted in a furthe: increase in 1993 Gas Purchased for J
Resale while the depressed 1992 sales volumes partially offset the increase due to the cost per unit of gas in 1992.
Other Operating Expenses increased $1.2 million and $4.0 million in 1993 and 1992, respectively. The most significant factor impacting Other Operating Expenses was the cost of manufactured gas plant (MGP) site remediation (refer to the " Environmental" section of Management's Discussion and Analysis). MGP site remediation expenses decreased $2.3 million in 1993 and increased $3.9 million in 1992. A majority of the fluctuation was due to the write-off of previously deferred MGP site remediation costs in 1992. The decrease in MGP site remediation costs in 1993 was offset by increases in expenses for gas distribution.
customer accounts, and rent. Other factors contributing to the 1992 variation were increases in health insurance and pension expenses and a $0.7 million adjustment for DSM costs previously deferred. Panially offsetting the increases in 1992 were decreases in various other expenses, in part due to merger savings.
Maintenance expenses decreased $0.9 million and $0.3 million in 1993 and 1992, respectively, due primarily to decreases in gas distribution expense and, in 1992, an increase in new construction.
Other, Net, on the Consolidated Statements of Income includes the $18.5 million pretax gain related to the exchange of gas service territories, and Non-operating Income Taxes reflects the related income taxes. For 1992 Other, Net, reflects a $1.4 million recovery of MGP site remediation costs through a settlement with a third pany during 1992.
LIQUIDITY AND CAPITAL RESOURCES The Company has available to it a variety of sources of liquidity and capital resources, both intemal and extemal. These resources provide funds required for current operations, debt retirement, dividends, construction expenditures and other capital requirements.
Material sources ofliquidity at December 31,1993, included current assets of $243 million and bank lines of credit of $167 million. The Company has authority fmm the Federal Energy Regulatory Commission (FERC) to issue before July 1995 shon-tenn debt in the form of commercial paper and bank notes amounting to $250 million.
Consolidated cash capital expenditures, including Cooper capital improvements but excluding allowance for funds used during construction, were $164.0 million for 1993. Of the total, $141.6 million were for electric operations, $22.0 million were for gas operations and $0.4 million were for other. The Company's management annually reviews long-range capital expenditure needs. Based upon such a review, the Company has planned cash capital expenditures of $164 million for 1994. The Company expects that $137 million of the 1994 planned expenditures will be for electric operations and $27 million will be for gas operations. Planned cash capital expenditures for the years 1995 through 1998 are $744 million. The repowering project discussed below is not included in the planned cash capital expenditures, in addition, approximately $81 million is projected for long-term debt maturities and sinking fund requirements for the years 1994 through 1998.
The Company anticipates approximately 70 percent of capital requirements for 1994 through 1998 will be met with intemal sources of capital in 1994 the Company plans to issue long-term debt to meet a ponion of the capital requirement needs and to replace shon-term debt..
1
^
In a continuing effon to reduce costs and to take advantage of lower interest rates, the Company modified its capital structure during 1993. The most significant change was the refinancing and redemption of its long-term debt issued by its predecessor companies, Iowa Public Service Company (IPS) and Iowa j
Power Inc. (IPR). By refinancing a majority of its long-term debt, the Company was able to restructure i
the timing of its debt maturities and reduce the overall cost of debt As of December 31,1993, $629 million of the long-term debt issued by IPS and IPR had been replaced by new long-term debt. In 1
addition the Company used the cash proceeds from the gas service territory exchange to redeem $35.5 million of IPS and IPR first mongage bonds. In November 1993 the Company issued $60 million of
$1.7375 Series preferred stock to replace $13 million of first mongage bonds and $23 million of higher cost preferred stock, as well a.s reduce shon-term debt balances and provide for other general corporate purposes. The restructuring reduced the cost of debt by over $3 million in 1993 and extended the average life of long-term debt from 10.7 to 16.6 years. The new debt was issued under a single, modemized indenture which allows more flexibility for the Company's capital resources. As a result of the restructuring activities, the IPR indenture has been eliminated and one bond series for $11 million remains outstanding subject to the IPS indenture. The Company has all regulatory approval necessary to issue an additional $118 million of long-tenn debt and an additional $15 million of pmferred stock.
As of December 31,1993, the Company had approximately $1.055 billion of unbonded bondable propeny and $190 million of retired prior lien bonds, the combination of which entitles it tn issue approximately $981 million of mongage bonds under the MPS indenture.
The Company's access to external capital and its cost of capital are influenced by the credit ratings of its securities. The Company's credit ratings as of the end of Jariuary 1994 are shown in the table below. The ratings reflect only the views of such rating agencies, and each rating should be evaluated independently of any other rating Generally, rating agencies base their ratings on information fumished to them by the issuing company and on investigation, studies and assumptions by the rating agencies.
There is no assurance that any panicular rating will continue for any given period of time or that it will not be changed or withdrawn entirely if i'1 the judgment of the rating agency circumstances so warrant.
Such ratings are not a recommendation to buy, sell or hold securities.
Moody's investors Standard Service
& Poor's Mongage Bonds A2 A+
Preferred Stocks a3 A
Commercial Paper P-1 Al
)
The following is a summary of the meanings of the ratings shown above and the relative rank of the Company's rating within each agency's classification system.
Moody's top four mongage bond ratings (Aaa, Aa, A and Baa) are generally considered " investment grade." Obligations which are rated "A" possess many favorable investment atuibutes and are considered as upper medium grade obligations. Factors giving security to principal and interest are considered adequate but elements may be present which suggest a susceptibility to impairment sometime in the future.
A numerical modifier ranks the security within the category with a "1" indicating the high end, a "2" indicating the midrange and a "3" indicating the low end of the category. Standard & Poor's top four mongage bond ratings (AAA, AA, A and BBB) are considered " investment grade". Debt rated "A" has a strong capacity to pay interest and repay principal although it is somewhat more susceptible to the adverse effects of changes in economic conditions than debt in higher rated categories. A plus (+) or -
I i
minus (-) sign may be used after Standard & Poor's ratings to designate the relative position of a credit within the rating category.
Ratings of preferred stocks are an indication of a company's ability to pay the preferred dividend and any sinking fund obligations on a timely basis. Moody's top four prefermd stock ratings (aaa, aa, a and l
baa) are generally considered " investment grade". Moody's "a" rating is considered to be an upper medium grade prefened stock. Eamings and asset protection are expected to be maintained at adequate levels in the foreseeable future. Standard & Poor's top four preferred stock ratings (AAA, AA, A and BBB) are considered " investment grade" Standard & Poor's "A" rating indicates adequate eamings and asset protection.
Moody's top three commercial paper ratings (P-1, P-2 and P-3) are generally considered " investment j
grade". Issuers rated "P-1" have a superior ability for repayment of senior shon-term debt obligations and repayment ability is often evidenced by a conservative structure, broad margins in eamings coverage of iixed financial charges and well established access to a range of financial markets and assured sources of j
altemate liquidity. Standard & Poor's commercial paper ratings are a current assessment of the likelihood of timely payment of debt having an original maturity less than 365 days. The top truee Standard &
Poor's commercial paper ratings (A1, A2 and A3) are considered " investment grade". Issues rated "Al" indicate that the degree of safety regarding timely payment is either overwhelming or very strong. Those issues determined to possess overwhelming safety am denoted with a plus (+) sign designation.'
i REGULATORY ENVIRONMENT Legislation enacted in Iowa in 1990 requires electric and gas utilities to spend 2 percent and 1.5 percent, respectively, of their annual Iowa jurisdictional revenues on demand-side management (DSM) activities. The Company has filed a $22.7 million request with the Iowa Utilities Board (IUB) for the recovery of some of the costs incurred during the period July 1990 to December 1992, as well as lost revenues and other related components. Hearings in the case began in late January 1994. Once a final order is issued, the allowed recovery would occur over a four-year period. The filing includes $13.5 million of the deferred DSM costs, including carrying costs, on the Company's Consolidated Balance Sheet as of December 31,1993. The Company will make periodic filings, as early as this year, for other DSM costs incurred and for future activities.
Other than the DSM filing, the Company currently has no rate case proceedings in progress. Electric services are being provided to customers in Iowa under the separate tariffs of IPS and IPR. The Company is working on the merging of electric tariffs and expects to file a future request with the IUB to establish j
one electric tariff for MPS in Iowa. In the rate filing, the Company will seek recovery of postretirement health care and life insurance costs on an accrual basis, which the IUB has ruled that it would permit if the Company extemally funds these costs. On January 1,1993, the Company adopted FAS 106, which is the accounting standard requiring accrual basis recognition of such postretirement benefit costs. The adoption of FAS 106 cunently has a minimal impact on the Company's Eamings on Common since the Company is deferring most of the costs above the " pay-as-you-go" amount until recovery on an accrual basis is established in a rate proceeding. Refer to Note (14) for further discussion of the impact of FAS 106 cn the Company.
The FERC issued orders, collectively Order 636, which have significantly changed the operations and regulatory requirements for interstate pipeline companies. These changes directly impact local distribution companies (LDCs), including Midwest Gas, by requiring LDCs to assume responsibility for the pmcurement, transponation and storage of natural gas. In preparation for the increased supply responsibilities under Order 636, the Company increased ns natural gas inventory to ensure an adequate supply of natural gas to meet customer needs. On November 1,1993. Order 636 became effective for two.
of the interstate pipelines serving the Company, including its major supplier. Pipeline transition costs resulting fmm the implementation of Order 636 will be paid to pipelines over the next five years. The Company's Consolidated Balance Sheet as of December 31,1993, includes a $42 million liability and regulatory asset recorded for the directly billed ponion of its transition costs. Although the additional transition costs to be collected through pipeline demand and commodity rates have not been determined, they are not expected to exceed $32 million. Order 636 also mandates a change in the pipeline rate design. The mandated change will increase fixed charges paid to pipelines by Midwest Gas and would amount to a permanent increase in retail rates of approximately one percent. The Company anticipates that under current regulatory conditions it will recover costs related to Order 636 thmugh the purchased gas adjustment clause. Midwest Gas will have other opponurities to reduce the cost of gas from: (1) pipeline cost of service reductions, (2) pipeline merchant servict reductions, and (3) market-based cost of gas. These reductions am expected to offset a major ponion of the gas cost increases. The Company continues to update assessments of the impacts of Order 636 as information becomes available. The actual impacts will depend to some degree on the outcome of the pipelines' experience from operating under new rules.
In 1992, the National Energy Policy Act (NEPA) was signed into law, nis law promotes competition in the wholesale electric power market The FERC has throughout 1993 taken action to establish mies and policies in compliance with provisions of the NEPA. The Company has been active in providing recommendations to the FERC in an effort to shape new transmission policies in ways that will best serve the interest of its customers and shareholders. The increasingly competitive environment brings with it an increase in risk and, according to rating agencies, possible changes in the utility securities markets.
In 1993 the Company completed an analysis of the NEPA and, based on factors such as generating costs, concluded that it is in a good position to react to the increased competition and to take advantage of opponunities now available. However, until the Company has operated in the new environment for some time, the nature and extent of its impact on the Company cannot be determined.
The Nuclear Regulatory Commission (NRC) placed Cooper on its " Declining Trend Plant" list in late January,1994. This action by the NRC is intended to identify plants with a declining safety performance record so that licensees may take appropriate remedial action on a timely basis to avoid a funher decline.
Nebraska Public Power District (NPPD) has developed a plan to address the NRC's concems and is currently implementing the plan. The Company has increased its oversight functions at Cooper accordingly. Although the costs of implementing the NPPD plan has not been determined, the Company does not expect its share of such costs will have a material adverse impact upon the financial position or results of operations of the Company. The costs to be incuned by NPPD to remove Cooper from the
" Declining Trend Plant" list may change as NPPD implements the plan and receives NRC comments on these actions over the upcoming year.
GENERATING CAPACITY The Company has an agreement with the Department of Er.ergy for a repowering project of the Company's Des Moines Energy Center to demonstrate a developing coal-buming technology believed to be substantially cleaner and more efficient than technologies now in use. As a result of the need for funher component testing by the technology supplier, the Company and other involved panies have agreed to an extension for the repowering project.
De Company's current forecast of capacity requirements indicates that it will have capacity deficiencies for the remainder of the 1990s. These deficiencies are expected to be met by additional new non-base load facilitics, opponune purchases of capacity or facilities or a combination thereof. The MWR P,oard of Directors approved a shon-term capacity purchase and the constmetion of a combustion turbine at one of the Company's generating sites. The Company is in the process of obtaining the necessary - _ _ - _ _ _.
=
d approvals to construct an 80-megawatt combustion turbine generator near Des Moines and plans to have it operational by June 1,1994. Costs of constructing the generator are included in 1993 and planned 1994 capital expenditures. Any potential capacity option will be evaluated based on its cost and potential for minimizing the Company's long-term power supply costs.
The Company's current fuel mix for installed capacity is 66 percent coal,20 percent oil and gas and 14 percent nuclear.
ENVIRONMENTAL The Company is currently involved in a number of environmental issues including manufactured gas plant site remediation, polychlorinated biphenyls and provisions of the Clean Air Act Amendments of 1990. Please refer to Note (2)(b) for a discussion of the handling of these environmental issues.
SUPPLY CONTRACTS The Company maintains contracts for delivery of capacity from each of the thme pipelines serving its natural gas distribution system. The majority of the long-term contracts with natural gas pipelines have been renegotiated for three-to five-year tenns. The Company has secured adequate supplies of natural gas for the 1993/1994 heating season. The Company estimates that its peak day requirements will be met with the following: 1) contracted third-party direct purchases,2) stored gas, and 3) peak shaving facilities which are maintained to assure a reliable supply of gas during peak periods. In addition, the Company will displace a portion of these supplies with spot gas purchases if it is cost-effective to the customer.
The above supply arrangements an: expected to be viable options for meeting gas requirements for future extended periods.
The Company also maintains coal contracts requiring the purchase of three million tons per year. The
)
contracts expire between 1994 and 2003. The Company estimates 50 percent of its coal requirements for j
1994 will be met by coal purchased under these contracts and the remainder by coal purchased on the spot market.
I )
1 j
1 MIDWEST POWER SYSTEMS INC.
CONSOLIDATED STATEMENTS OF INCOME Year Ended December 31 1993 1992 1991 (In Thousands) 1 I
OPERATING REVENUES Electric.......
$664,377 5623.360
$637,222 Gas..
332,168 299,820 292,291 Other................
300 Total.
996.545 923.180 929.813 OPERATING EXPENSES Fuel for generation....................
111,138 101,468 108,400 Power purchased..............................
32,268 36,434 25,466 Cooper Nuclear Station power purchased.............
85,987 86,455 72,659 Gas purchased for resale.........................
224,337 200,780 196,979 Other operati'3 expenses........................
159,812 156.901 151.678 Maintenance.................................
57,077 54,233 52,140 Depreciation and amomzation.....................
89,805 86,190 82,475 General taxes...............................
59,837 63,652 62,199 Current income taxes...........................
36,890 19,894 35,873 Deferred income taxes 10,751 8,019 8,142 Investment tax credit..........................
(3.754)
(3.817)
(3.844)
Total...........
864.148 810.209 792.167 OPERATING INCOME..
132397 112.971 137.646 OTHER INCOME Allowance for equity funds.......................
1,213 124 Interest and dividend income...........
1,511 772 877 Non-operatmg income taxes...........
(7,868) 35 (176)
Other, net.....................
18.921 (1.729)
(405)
Total.
12.564 291 420 INCOME BEFORE FDJ.D CHARGES............
144.961 113.262 138.066 FIXED CHARGES Interest on long. term debt........................
56,171 61,440 55,520 Other interest charges...........................
3,122 2,230 8,002 Allowance for borrowed funds (1.207)
(1.058)
(2.899)
Total 58.086 62.612 60.623 NET INCOME...........
86,875 50,650 77,443 Preferred stock dividends........................
3372 3.706 5361 EARNINGS ON COMMON STOCK..............
$ 83.503
$ 46.944 5 72.082 i
The accompanying notes we an integral pan of these statements.
34
MIDWEST POWER SYSTEMS INC.
CONSOLIDATED STATEMENTS OF CASil FLOWS Year Ended December 31 1993 1992 1991 (In Thousands)
NET CASil FLOWS FROM OPERATING ACTIVITIES Net income.............
S 86,875 5 50,650 5 77,443 1
Adjustments to recancile net income to net cash provided:
Depreciation and amomzation.
89.805 86,190 82,475 Amortization of advances for nuclear fuel and capitalimprovements I1,412 11,971 9,599 Net increase (decrease) in deferred income taxes and investment tax credit...
(401) 2.939
~ 2,955 Allowance for equity funds (1,213)
(124)
Non. cash change in deferred assets........
(3,197) 13.066 3,297 Gain on sale of assets...
(18,485)
Amonization of unbilled revenues (1,657)
Cash flows resulting from changes in working capital, net of effects from exchange of assets...............
24,254 574 15,592 Other (5.855) 4.590 (9.025)
Net cash provided.
184.408 168.767 180.555 NET CASH FLOWS FROM INVESTING ACTIVITIES Utility plant capital expenditures (144,584) (103,791)
(101,212)
Cooper Nuclear Station capital improvement advances...................
(3,540)
(10,855)
(14,297)
Other capital expenditures...............................
(387)
(197) 292 Deferred demand side management expenditures...................
(16.671)
(7.934)
(7,476)
Allowance for equity funds 1,213 124 Proceeds fmm sale of assets......
38,000 4,000 Net cash from investments.
2.200 2.098 12 Net cash used (124.982) (119.466)
(118.557)
NET CASH FLOWS FROM FINANCING ACTIVITIES Dividends paid on common stock...................................
(63,551)
(73,944)
(78,200)
Long-term debt proceeds, net of issuance cost........
623,080 125,000 Retirement of long-term debt, net of reacquisition cost..................... (720,729)
(1,940)
(57,202)
Dividends paid on preferred stock..............
(3,372)
(3,706)
(5,361)
Reacquisition of preferred stock, net of reacquisitbn cost (23,256)
(31,583)
(4)
Issuance of preferred stock, net of issuance expense...
58,262 Contribution from parent 56,795 Net increase (decrease) in notes payable.
71.700 58.100 (101.900)
Net cash used (57.866)
(53.073)
(60.872)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS..
1,560 (3,772) 1,126 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.
4.7],7 7.989 6.863 CASH AND CASH EQUIVALENTS AT END OF YEAR S 5,777 5 4,217 5 7.989 The accompanying notes are an integral part of these statements.
35-
r MIDWEST POWER SYSTEMS INC.
CONSOLIDATED BALANCE SHEETS ASSETS As of December 31 1993 1992 (In 'Ihontandt)
UTILITY PLANT Electric..............................................
$2,293,770
$2,183,094 352,009 354,671 Gas...............................................
21361 19.456 Plant acquisition adjustment Gross plant, including consuuction work in progress of $87,736 and $33,416, respectively.................
2,667,140 2,557,221 Less accumulated depreciation and amorriration.................
1.056.251 978.442 Utility plant, net...................................
1.610.889 1.578.779 l
OTHER PROPERTY AND INVESTMENTS Property, net of accumulated depreciation and amortnarian.....................................
2,497 2,170 investments...........................................
26.950 28.914 Total...........................................
29.447 31.084 POWER PURCHASE CONTRACT Productive capacity.....................................
151,485 146,150 Advances for capital improvements, net of aa:umulated amoruzauon of $83.651 and $72.239, respectively..............
97.158
%.996 Total...........................................
248.643 243.146 CURRENT ASSETS Cash and cash equivalents.................................
5,777 4,217 Receivables, less reserves of $875 and $1,151, respectively.........
128,090 133,414 Receivables from affihmied companies........................
37,579 37,654 i
- Electnc pmduction fuel, at average cost.......................
19,831 25,149 l
Natural gas and propane in storage, at average cost...............
28,466 18,367 Materials and supplies, at average cost........................
15,393
-13,663 Prepayments and other...................................
7.585 8.256 Total...........................................
242.721 240.720 DEFERRED CHARGES AND OTHER,.....................
252.754 137.856 TOTAL ASS ETS......................................
j2384.454
$L211481 The accompanying notes are an integral part of these statements... -
NUDWEST POWER SYSTEMS INC.
CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILITIES As of December 31 1993 1992 (In Thousands)
CAPITAI.IZATION Common stock equity..................................
S 655,152 3 635,823 Cumulative nonredeemable preferred stock...................
90.042 54.413 Long-term debt (excluding current maturities)...................
677.506 726.611 Total..........................................
1.422.700 1.416.847 POWER PURCH ASE CONTRACT........................
140.655 138.081 CURRENT LIABILITIES Notes payable.........................................
129,800 58,100 Current portion of long-term debt 1,506 14.219 Current portion of power purebase contract.....................
10,830 8.065 Accounts payable............
75,678 69,171 Accounts payable to affihatM companies......................
2,696 5,125 Interest accrued.......
18,585 16,475 Taxes accrued.........................................
82,560 65,667 Other.......
21.002 19388 Total........
342.657 256.210 RESERVES, CREDITS AND OTHER LIABILITIES Deferred income taxes...................................
331,568 314,541 Investment tax credit..
65,374 70,283 Other...............................................
81.500 35.619 Total.........
478.442 420.443 l
TOTAL CAPITALIZATION AND LIABILITIES..............
52,384,454
$2.231.585 The accompanying notes are an integm! part of these statements.
4 l
MIDWEST POWER SYSTEMS INC.
1 OF 2 CONSOLIDATED STATEMENTS OF CAPITALIZATION As of December 31 1993 1992 (In 'Ihousands).
COMMON STOCK EQUITY Common stock, no par, 100.000.000 shares authonzed, 1.000 shares outstanding............................
S 462,150 3 462,274 Retained earnings...................................
193.002 173.549 Total...........
655.152 46.1 %
635.823 44.9 %
PREFERRED STOCK; without par value; 10,000,000 shares authorized:
Cumulative acrossaable -
$330 Series,49,632 and 49,643 shares, respectively........
4,%3 4,964
$3.75 Series, 38,320 shares.........................
3,832 3,832 33.90 Series, 32,636 shares..........................
3,263 3.263
$4.20 Series, 47.369 shares..........................
4,737 4,737
$435 Series, 49,950 shares..........................
4,995 4,995
$4.40 Series, 50,000 shan:s..........................
5,000 5,000
$4.80 Series, 49,898 shares..........................
4,990 4,990
$1.7375 Series 2,400,000 and zero shares, respectively......
58,262
$7.64 Series, zero and 66,135 shares, respectively..........
6,614
$8.08 Series, zero and 48,786 shares, respectively..........
4,879
$832 Series, zero and 71,525 shares, respectively..........
7,045
$8.52 Series. zero and 40,944 shares, respectively..........
4.094 Total......................................
90.042 6.3%
54.413
,,Mi LONG-TERM DEBT Mortgage bonds:
6 1/4% Series, due 1998............................
75,000 6 3/4% Series, due 2000............................
75,000 7 1/8% Series, due 2003............................
100,000 7% Series, due 2003...............................
100,000 7 3/8% Series due, 2008............................
75,000 8 % Series due, 2022...............................
50,000 8 1/8% Series due, 2023............................
100,000 8 1/4% Series, due 1996............................
80,000 8 1/4% Series, due 1996............................
50,000 8 3/8% Series, due 1997............................
50.000 6 5/8% Series, due 1998............................
13,125 9% Series, due 2000...............................
25,000 9% Series, due 2000...............................
12,900 7 5/8% Series, due 2001............................
13.350 8% Series, due 2001...............................
15,000 7 3/8% Series, due 2002............................
17,000 l
8.15% Series, due 2003............................
75,000 8 2/10% Series, due 2003...........................
50,000 u
8 3/4% Series. due 2006............................
29,203 l
9% Series, duc 2006...............................
25,000 8% Series, due 2007...............................
25,000 8 1/4% Series, due 2007............................
29,400 8 3/4% Series, due 2008............................
25,000 10 1/2% Series, due 2018...........................
70,000 The accompanying notes are an integral part of these statements.
-38 l
m
MIDWEST POWER SYSTEMS INC.
2OF2 CONSOLIDATED STATEMENTS OF CAPITA 13ZATION As of December 31 1993 1992 (In Rousands)
LONG-TERM DEBT (CONTINUED)
Po"ution control revenue bonds:
- .15% to 5.75% Series, due periodically through 2003........
S 8.276 5 14.860 4 4/10% Series, due 2013 (secur:d by first mortgage bonds)....
11,000 11,000 Louisa County. Iowa. floating 3043y municipal bond rate, d ue 2015..................................
23,900 23,900 5.95% Series, due 2023 (secured by general mortgage bonds) 29.030 Floating weekly pollution control revenue bond rate, due 2023 (sectued by general mortgage bonds)............
28.295 61/4% Series, due 1997 through 2006 (secured by first mortgage bonds).....................
18,000 5 9/10% Series, due 1997 through 2007 (secured by fhst mortgage bonds)....
18,000 9 3/4% Se:(:s, due 1999 (secured by first mortgage bonds).....
6,400 61/2% Series, due 2003 (secured by first mortgage bonds).....
9.900 Notes:
9% to 15% Series, due annually through 1996..............
44 79 8 3/4% Series, due 2002.............................
240 240 6 4/10% Series, due 2003 through 2007..................
2.000 2,000 i
91/2% Series, due annually through 2009.................
944 9 7/8% Series, due monthly through 2011.................
13,480 i
Obligation under capital lease.........................
3.512 4.720 Unamortized bond discount...........................
(3.791)
(1.890)
Total.......................................
677.506 47.6 %
726.611.513%
[
TOTAL........................................
51.422.700 100.0 %
S1.416.847 100.0 %
o i
i CONSOLIDATED STATEMENTS OF RETAINED EARNINGS Year Ended December 31 1993 1992 1991 (In Housands)
[
B EGINNING OF YEAR.......................
$173.549 5201,408 5207.526 Earnings or, common stock.......................
83.503 46,944 72,082 Dividends on common stock......................
63,551 73.944 78,200 Loss en reacquisition of preferred stock..............
499 R59 END O F YEAR..............................
S193.002 5173.549 5201.408 t
The accompanying notes are an integral part of these statements.
l a
e NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1)
SUMMARY
OF SIGNIFICANT ACCOUNTING POLICIES:
(a) Basis of Consolidation:
Midwest Power Systems Inc. (Company or MPS) is a wholly owned public utility subsidiary of Midwest Resources Inc. (MWR). The consolidated financial statements include the accounts of MPS and its wholly owned subsidiary, CBEC Railway Inc. MPS provides electric and gas utility services thmugh its two operating divisions: Midwest Power and Midwest Gas. All significant intercompany transactions have been eliminated fmm the consolidated financial statements.
On July 22,1992, Iowa Power Inc. (IPR) and Iowa Public Service Company (IPS), also wholly owned subsidiaries of MWR, merged with and into MPS. The Company accounted for the merger under a method which combines the assets, liabilities and ownership intemst at their existing recorded amounts.
(b) Rate Regulation:
The Company's utility operations are subject to rate regulation by the Iowa Utilities Board (IUB),
the South Dakota Public Utilities Commission and the Federal Energy Regulatory Commission (FERC).
The financial statements of the Company att based on generally accepted accounting principles, which give recognition to the ratemaking and accounting practices of these agencies.
(c) Regulatory Assets:
MPS is subject to the provisions of Statement of Financial Accounting Standards 71 " Accounting for the Effects of Certain Types of Regulation." Regulatory assets represent probable future revenue to MPS associated with certain incurred costs as these costs are recovered thmugh the ratemaking process.
The following regulatory assets were reflected in the Consolidated Balance Sheets as of December 31 (in thousands):
1993 1992 Deferred income taxes S 78,368
$ 63,166 FERC Order 636 transition costs...
41,918 Debi refinancing costs...........
39,224 7,649 Energy efficiency costs 36,601 17,690 Environmental costs..
15,502 14,001 Plant costs.....
12,805 15,240 Postretirement benefit costs 9,126 Nuclear plant outage costs........
8,237 203 Other.....
10.733 12.056 Total
$252.514
$130.005 The Company uses an asset and liability approach for financial accounting and reporting for income taxes. Because of rate regulation, regulatory assets are also recorded. For additional information regarding deferred income taxes, FERC Order 636 transition costs, envimnmental costs and postretirement benefit costs see notes 13,2(d),2(b) and 14, respectively.
1 I
(d) Revenue Recognition Revenues are recorded based on service rendered to the end of the month. Accmed unbilled revenues are $45.833,000 and $45,948.000 at December 31,1993 and 1992, respectively, and are included in Receivables on the Consolidated Balance Sheets.
The majority of the Company's electric and gas revenues are subject to adjustment clauses. These clauses allow the Company to adjust the amounts charged for electric and gas service as the costs of gas purchases, fuel for generation or purchased power change. The costs recovered in revenues through use of the adjustment clauses are charged to expense in the same period.
(e) Depreciation and Amortization:
The Company's provisions for depreciation am based on straight-line composite rates.
The average depreciation rates for the years ended December 31 were as follows:
1993 1992 1991 Midwest Power 3.6%
3.6%
3.6%
Midwest Gas 3.8%
3.9%
3.9%
Utility plant is stated at original cost which includes overheads, administrative costs and an allowance for funds used during construction.
The cost of repairs and minor replacements is charged to maintenance expense. Propeny additions and major propeny replacements are charged to plant accounts. The cost of depreciable units of utility plant retired or disposed of in the normal course of business is eliminated from the utility plant accounts and such cost. plus net removal cost, is charged to accumulated depreciation.
(f) Consolidated Statements of Cash Flows:
The Company considers all cash and highly liquid debt instruments purchased with a remaining maturity of thme months or less to be cash and cash equivalents for purposes of the Consolidated Statements of Cash Flows.
Cash paid for interest and income taxes for the years ended December 31 was as follows (in thousands):
1993 1992 1991 Interest paid, net of amounts capitalized..
$ 52,834
$ 60,711
$ 59,259 Income taxes paid..
$ 32,629
$ 29,105
$ 31,858
! i
Net cash provided (used) from changes in working capital amounts was as follows (in thousands):
1993 1992 1991 Receivables........
$ 5,324
$ (9,831)
$ (4,863)
Receivables from affiliated....
75 18,465 12.126 Inventories......
(6,511)
(6,248)
(160)
Prepayments and other current assets...
671 (832)
(1,932)
Accounts payable..
6,507 (8.129) 3,956 Accounts payable affiliates.
(2,429) 2,451 1,642 Interest accmed..
2,110 (40)
(611)
Taxes accrued...........
16,893 (3,625) 8,846 Other current liabilities 1.614 8.363 (3.412)
Total....................
$ 24.254 5
574
$ 15.592 The Company entered into the following non-cash transactions: a 1993 exchange of MPS' Minnesota gas properties for Minnegasco's South Dakota gas properties recorded by the Company at
$31,713,000, and $38,000,000 cash: and recognized liabilities of $55,318,000 and recorded the related regulatory and other assets.
(g) Accounting for Long-Term Power Purchase Contract:
Under a long-term power purchase contract with Nebraska Public Power District (NPPD), expiring in 2004, the Company purchases one-half of the output of the 778-megawatt Cooper Nuclear Station (Cooper). The Consolidated Balance Sheets include a liability for the Company's fixed obligation to pay 50 percent of NPPD's Nuclear Facility Revenue Bonds and other fixed liabilities. A like amount representing the Company's right to purchase power is shown as an asset.
The debt amortization component of the Company's payments to NPPD was $9,861,000,
$5,854,000 and $8,455,000 and the net interest component was $5,678,000, $7,391,000 and $6,600,000 each for the years 1993,1992 and 1991, respectively. Minimum payments of the power purchase contract obligation are $ 10,830,000, $12,180,000, $13,041,000, $13,652,000 and $14,313,000 for 1994,1995,1996, 1997 and 1998,. :spectively.
Capital improvement costs for new property, including carrying costs, are being deferred, amortized and recovered in rates over the term of the NPPD contract. Capital improvement costs for propeny replacements, including carrying costs, are being deferred, amortized and recovered in rates over a five-year period.
1 All costs the Company incurs in relation to its long-term power purchase contract with NPPD are included in Cooper Nuclear Station Power Purchased on the Consolidated Statements of Income.
(2) COMMITMENTS AND CONTINGENCIES:
(a) Long Term Power Purchase Contract:
Payments to NPPD cover one-half of the fixed and operating costs of Cooper (excluding depreciation but including debt service) and the Company's share of nuclear fuel cost (including nuclear l
~
fuel disposal) based on energy delivered. The debt service ponion on a monthly basis is approximately
$1.4 million for 1994 and is not contingent upon the plant being in service.
NPPD has filed a decommissioning plan with the Nuclear Regulatory Commission (NRC) and
)
established an extemal trust for nuclear decommissioning funds. NPPD believes that the funding amount required by regulation understates the expected cost to decommission Cooper. Based on a site-specific study that includes decontamination, dismantling and site restoration costs, the Company's share of expected Cooper decommissioning costs is $158.3 million, in 1988 dollars. This site-specific estimate is being used as the basis for decommissioning funding. For purposes of developing a decommissioning funding plan, NPPD assumes decommissioning costs will escalate at an annual rate of six percent. Based on this assumption, the Company's share of expected decommissioning costs is $218.2 million in 1993 dollars. The funding plan assumes decommissioning will start in 2004, the currently anticipated plant shutdown date.
During 1993, the Company contributed $8.9 million toward funding Cooper decommissioning. The decommissioning costs are being recognized over the expected service life of the i
plant and are included in the Company's service rates. As of December 31,1993, the Company's share of funds set aside by NPPD in intemal and extemal accounts for decommissioning was $27.3 million.
In addition, the funding plan also assumes various funds and reserves currently held to satisfy NPPD Bond Resolution requirements will be available for plant decommissioning costs after the bonds are retired in early 2004.
The Company maintains financial protection against catastrophic loss associated with this obligation through a combination of insurance purchased by NPPD, insurance purchased directly by the Company, and the mandatory industry-wide loss funding mechanism afforded under the Price-Anderson Amendments Act of 1988. The coverage falls into three categories: nuclear liability, pmpeny coverage and workers compensation.
NPPD purchases nuclear liability insurance in the maximum available amount of $200 million.
In accordance with the Price-Anderson Amendments Act of 1988, excess liability pmtection above that amount is provided by a mandatory industry-wide program under which the owners of nuclear generating facilities could be assessed for liability incurred due to a serious nuclear incident at any commercial nuclear reactor in the United States. Currently, the Company's maximum potential share of such an assessment is $39.6 million per incident, payable in installments not to exceed $5 million annually.
The propeny coverage provides for several items which include decontamination of the facility, disposal of the decontaminated material, business interruption, debt service, replacement power and premature decommissioning. NPPD purchases primary and excess propeny insurance for Cooper in the amount of $1.3 billion, and the Company purchases $700 million of excess propeny coverage directly from an industry-mutual insurance company. The combination of these coverages pmtects the Company for its 50 percent obligation in the event of a loss totalling $2.7 billion, which is the maximum amount of insurance coverage currently available to the Company. Additionally, the Company directly purchases extra expense / business interruption coverage to cover the cost of replacement power and/or other continuing costs in the event of a covered accidental outage at Cooper. The coverages purchased directly by the Company contain provisions for retrospective premium assessments should two or more full policy-limit losses occur in one policy year. Currently, the maximum retrospective amounts that could be assessed against the Company total $7 million.
The workers compensation coverage is an industry-wide policy with an aggregate limit of $200 million for the nuclear industry as a whole, in effect to cover ton cla'ms of workers as a result of radiation exposum on or after January 1,1988. The Company's share of a maximum potential share of a retrospective assessment under this program is $1.5 million.
j l
(b) Environmental Matters:
The United States Environmental Protection Agency (EPA) and the Iowa Department of Natural Resources (IDNR) have determined that contaminated wastes remaining at certain decommissioned manufactured gas plant (MGP) facilities may pose a threat to the public health or the environment if such contaminants are in sufficient quantities and at such concentrations as to warrant remedial action. The Company could be involved, as a potentially responsible party (PRP), in up to 22 such sites.
The Company and other PRPs have entered into a Consent Decree with the EPA for remediation at one site and have entered into an Administrative Order to conduct a removal action at a second site.
The Company and IDNR have entered into Consent Orders to investigate and conduct response action at two additional sites. The Company proposes to conduct limited site investigations at most of the remaining sites. The outcome of the Company and environmental agency investigations will be an important factor with respect to any remedial action.
The Company's present estimate of probable remediation costs is $15.5 million. This estimate has been recorded as a liability and a regulatory asset for future recovery through the regulatory process.
Beginning in September 1992, the Company's gas rates in Iowa provide recovery for MGP costs of $3.1 million on an annual basis. The Company is pursuing recovery of the response costs from other potentially responsible parties and its insurance carriers.
The estimate of probable remediation costs is established on a site specific basis. The costs are accumulated in a three-step process, First, a determination is made as to whether the Company has any potential legal liability for the site. If it does, the costs of performing a preliminary investigation are accrued. Once the investigation is completed and it is determined remedial action is required, the best estimate of remediation is accrued. If necessary, the estimate is revised when a consent order is issued.
The estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial action and changes in technology relating to remedial altematives. The Company estimates it will take up to 15 years to resolve the MGP remediation issues.
As a user of polychlorinated biphenyls (PCBs), the Company is subject to govemmental regulations pertaining to the use, handling and proper disposal of PCBs. The Company is involved as one of several parties in a cleanup at one site at which the cleanup activity began in 1986 and is anticipated to be complete within two years. The Company and other PRPs have made contributions to a trust fund that should be adequate to complete the cleanup required. The Company also entered into a Consent Decree and Consent Orders with the EPA and other PRPs at two other sites. Payments were made in 1993 to settle the Company's financial obligation at both sites. The likelihood of additional material expense from these sites is remote.
The Company's coal-fired generating units are minimally affected by the Phase I provisions of the Clean Air Act Amendments of 1990 (CAA). These generating units currently meet the new CAA sulfur dioxide emission rate standards by buming low-sulfur Wyoming coal. Additional emission rate reductions will not be required to achieve compliance. The Company estimates that sufficient emission allowances have been allocated on a system-wide basis for its units to operate at the capacity factors needed to meet system energy requirements. By the year 2000, some Company coal-fired generating units.
e will be required to install controls to reduce emissions of nitrogen oxides. The Company's present estimate of the costs of these controls is $33 million. Essentially all utility generating units are subject to CAA provisions which address continuous emission monitoring, pennit requirements and fees, and emission of toxic substances. The Company estimates capital costs of appmximately $3 million and increased annual operations and maintenance expense of approximately $2 million for compliance with these provisions.
It is management's opinion that the ultimate resolution of the envirorunental matters will not have a material adverse impact upon the financial position or results of operations of the Company.
(c) Capital Expenditures:
The Company's capital expenditures, including Cooper capital improvements, deferred demand side management expenditures and allowances for funds, are estimated to be $166,142,000 for 1994.
(d) Coal and Natural Gas Contract Commitments:
Midwest Power has entered into coal supply contracts for its fossil fueled generating stations. The contracts, with expiration dates ranging from 1994 through 2003, require minimum payments of
$20,424,000, $19,447,000, $19,659,000, $19,439,000 and $19,679,000 for the years 1994, 1995, 1996, 1997 and 1998, respectively, and $43,864,000 for the years thereafter. The Company expects to supplement these coal contracts with spot market purchases to fulfdl its future fossil fuel needs.
Midwest Gas has entered into various natural gas supply and transportation contracts with expiration dates ranging from 1994 through 2008. The minimum commitment under these contracts is
$62.889,000, $49,610,000, $45,638,000, $34,585,000 and $7,319,000 for the years 1994,1995,1996,1997 and 1998, respectively, and $17,680,000 for the years thereafter. During 1993, FERC Order 636 became effective, requiring interstate pipelines to restructure their services. The pipelines will secover the transition costs related to Order 636 from the local distribution companies. The Company has reconied a $41.9 million liability and regulatory asset for the transition costs related to its largest natural gas transportation provider.
(3) SEGMENTS OF BUSINESS:
For the year ended December 31 1993 1992 1991 Operating Revenues:
(in Thousands)
Electric......................
$ 664,377
$ 623,360
$ 637,222 Gas......
332,168 299,820 292,291 Other.
300
$ 996.545
$ 923.180
$ 929,813 Operating Expenses:
Electric........................
$ 552,640
$ 526,070
$ 515,967 G as..........
311,508 284,139 276.036 164 Other 5 864,148
$ 810,209
$ 792,167 Operating Income:
Electric.....
$ 111,737
$ 97,290
$ 121,255 Gas.......
20,660 15,681 16,255 Other..........
136
$ 132.397
$ 112.971
$ 137,646 Depreciation and Amortization Expense:
Electric.......
$ 77,065 74,305
$ 71,238 G as.................
12.740 11.885 11.237
$ 89,805 86,190
$ 82.475 Capital Expenditures:
Electric........................
$ 142,769 99,308
$ 101,999 Gas......
22,026 23,272 20,986 O ther.........................
387 197 (292)
(
$ 165.182
$ 122.777
$ 122.693 l
I Identifiable Assets as of December 31:
Electric............
$1,636,235
$1,589,990
$1,598,212 Gas.
286,688 288,870 262.425 1,922.923 1.878.860 1.860.637 Corporate assets..
461.531 352.725 372.446
$2.384,454
$2,231,585
$2,233,083 Identifiable assets are all assets that are used directly in the Company's operations of each segment. Corporate assets are principally investments, cash and cash equivalents, receivables, prepayments and defened charges.
l l
-46
(4) FAIR VALUE OF FINANCIAL INSTRUMENTS:
The following table presents the carrying value and the estimated fair value of financial instruments included in the Consolidated Balance Sheets as of December 31 (in thousands):
1993 1992 Carrying Fair Carrying Fair Amount Value Amount Value Long-term debt and current maturities.
$678,151
$712,034
$736,950 $767,205 Preferred stock..
90,N2 79,003 54,413 38,779 The carrying amount of current assets and current liabilities approximates the fair value because of the shon maturity of these financial instmments.
The fair value of investments is estimated based on the quoted market prices for those or similar investments, where available. Cenain investments with carrying values of $26.9 million and $28.8 million as of December 31,1993 and 1992, respectively, are excluded from the amounts shown because a reasonable estimate of fair value could not be made without incurring excessive costs. These investments consist primarily of the noncurrent ponion of an investment representing all the issued preferred stock of an untraded company which is carried at $25.2 million and $27.4 million as of December 31,1993 and 1992, respectively. The terms of this preferred stock provide that no dividends will be paid and require
$2.2 million to be redeemed annually each February 1 through 2002, $3.9 million in 2003 and $3.8 million in 20N.
The fair values of long-term debt and preferred stock are estimated based on the quoted market prices of those or similar issues, where available. For those issues where no quoted market prices are available, the fair value is estimated based on current rates available to the Company for debt or preferred stock with similar remaining maturities.
(5) PREFERRED STOCK:
In 1992, the Company redeemed all 300,000 outstanding shares of the $7.35 Series Preferred Stock for the price of $105.201 per share. A $1.6 million loss on the reacquisition of the series was charged to Retained Eamings and Paid-in Capital.
On November 17,1993, the Company issued 2,400.000 shares of $1.7375 Series No Par Value Preferred Stock with a stated value of $25 per share. Net proceeds from the issuance were $58.3 million.
On December 10,1993, the Company redeemed all the outstanding shares of cenain series of Cumulative Nonredeemable No Par Preferred Stock as follows: 66,135 shares of $7.64; 48,786 shares of
$8.08; 71,525 shares of $8.32; and 40,944 shares of $8.52. The combined recorded value of the redeemed series was $22.6 million. The total cost of the transaction included a $623,000 premium, of which
$124,000 was charged against Paid-in Capital and $499,000 was charged against Retained Eamings.
In addition to the transactions above, the Company redeemed 11,482 and 44 shares of various series of preferred nock during 1993,1992 and 1991, respectively.
The total outstanding preferred stock of $90.0 million may be redeemed at the option of the Company at prices which, in the aggregate, total $96.8 million. The aggregate total the holders of preferred stock are entitled to upon involuntary be.nkmptcy is $91.8 million plus accrued dividends.
Annual dividend requirements for preferred stock outstanding at December 31,1993, total $5,481,000.
(6) COMMON STOCK:
Common stock outstanding changed during the years ended December 31 as shown in the table below (in thousands):
l 1993 1992 1991 Amount Shares Amount Shares
- Amount Shares
- Balance, beginning of year... $462,274 1,000 $462,948 1,000
$405,639 1,000 l
Changes due to:
1 Contribution from parent.....
57,308 Gain (loss) on reacquisition of preferred stock....
(124)
(674) 1 Balance, end of year........ $462,150 1,000 $462,274 1,000
$462,948 1,000
- Shares are based upon the conversion of the total outstanding shares of common stock ofIPR and IPS into 50 shares each of MPS plus 900 shares of MPS common stock outstanding at the time of the merger.
(7) SIIORT-TERM BORROWING:
i l
Interim financing of working capital needs and the construction program may be obtained from the sale of commercial paper or shon-term borrowing from banks. The Company's shon-term notes payable consisted of commercial paper borrowings of $129,800,000 and $58,100,000 at December 31, 1993 and 1992, respectively. The Company had bank lines of credit of $167,500,000 at December 31, 1993. These lines are used to suppon commercial paper and bank bormwings. The average interest rate on the commercial paper and bank borrowings was 3.25 percent for 1993 and 3.75 percent for 1992.
(8) LONG-TERM DEBT:
he Company's sinking fund requirements and maturities oflong-term debt for 1994,1995,1996, 1997 and 1998 are $1,506,000, $998,000, $532,000, $2,522,000 and $75,124,000, respectively.
Substantially all the Company's electric utility propeny is pledged. _ _ _ _ _ - _ _ _ _ _ _ _ _ - _ - _ _ _ _. _ _ _ _
(9) INVESTMENTS:
Investments include the following amounts as of December 31 (in thousands):
1993 1992 Preferred stocks....
$ 25.205 5 27.392 Equity method investments.............
81 81 Other..
1.664 1.441 Total..................
$ 26.950 5 28.914 (10) CONCENTRATION OF CREDIT RISK:
Midwest Power pmvides electric service to 420.000 customers in 327 lowa communities and six communities in southeastern South Dakota. Midwest Gas pmvides natural gas service to 342.000 customers in 204 lowa,27 South Dakota and two Nebraska communities. Midwest Power and Midwest Gas grant unsecured credit to customers, substantially all of whom are local businesses and residents.
(11) OTIIER INCOME:
Included in Allowance for Equity Funds and Allowance for Borrowed Funds are allowances for funds used during constmetion and accrued on advances for capital improvernents and other capital expenditures for the years ended December 31 as follows (in thousands).
1993 1992 1991 Allowance for equity funds:
Used during construction................
$ 835
$ 37 Accrued on advances for capital improvements 409_
65 (31) 22 Accrued on other capital expenditures.......
Allowance for borrowed funds:
Used during construction........
790 614 1,638 Accrued on advances for capital improvements 417 409 994 Accrued on other capital expenditures 35 267 (12) JOINTLY OWNED UTILITY PLANT:
Underjoint plant ownership agreements with other utilities, the Company had undivided interests at December 31,1993, in jointly owned generating plants as shown in the table below.
The dollar amounts below represent the Company's share in each jointly owned unit. Each participant has provided financing for its share of each unit. Operating Expenses on the Consolidated Statements of Income include the Company's share of the expenses of these units.
Neal Neal Council Ottumwa Louisa Unit Unit Bluffs Unit Unit No.3 No.4 Unit No.3 No.1 No.1 (Dollars in millions, except capital cost per kW)
Utility plant in service S 67.1 S156.5 5168.6 5130.6
$270.9 Year placed in service....
1975 1979 1978 1981 1983 Accumulated depreciation..
S 36.2 5 68.9 5 76.2 5 50.7
$ 89.7 Unit capacity-MW 515 624 675 708 650 Percent ownership.......
43.0%
40.6%
46.7%
33.5 %
45.0 %
Capital cost per kW......
S 303 5 618
$ 535 5 551 S 926 (13) INCOME TAX EXPENSE:
The Company adopted Financial Accounting Standard 109 " Accounting for Income Taxes" (FAS 109) in January 1993. The Company adopted FAS 109 on a restatement basis which resulted in a decrease to retained eamings of $10.807,000, as of the earliest period shown, with no material effect on net income during the periods presented. Because of rate n:gulation, additional net regulatory assets were also recorded on a restatement basis.
Income tax expense from continuing operations was as follows for the years ended December 31 (in thousands):
1993 1992 1991 Current Federal 540,297
$16,129
$28,792 S tate..........................
11.859 4.993 8.600 52.156 21.122 37.392 Deferred Federal 4,992 7,112 7,339 S tate..........................
(484)
(356)
(540) 4.508 6.756 6.799 Investment tax credit amortization.......
(4.909)
(3.817)
(3.844)
To tal..........................
$51.755
$24,061
$40.347 F
Included in Deferred Income Taxes and Prepayments and Other on the Consolidated Balance Sheets as of December 31 are deferred tax assets and deferred tax liabilities as follows (in thousands):
1993 1992 Deferred Tax Assets i
Related to:
Investment tax credits..
S 46.509 5 48,257 Other 2.652 4.463 Total..
S 49.161 5 52.720 Deferred Tax Liabilities Related to:
Depreciable Propeny
$362,176
$356,555 Other....
28.084 20.660 Total
$390,260
$377.215 The following table is a reconciliation between the effective income tax rate, before preferred stock dividends, indicated by the Consolidated Statements ofIncome and the statutory federalincome tax rate for the years ended December 31:
1993 1992 1991 Effective federal and state income tax rate 37 %
32 %
34 %
State income tax, net of federal income tax benefit......
(5)
(4)
(4)
Amortization ofinvestment tax credit.
4 5
3 Other m
1 1
Statutory federal income tax rate.
35 %
34 %
34 %
MWR files a consolidated income tax retum. The current and deferred income tax expenses reflected by MPS are the amounts that would have been recorded by the Company had it filed its own income tax retum. The tax-related balances between MPS and MWR, as recorded by MPS, are a receivable of $1,076,000 and a payable of $2,712,000 at December 31,1993 and 1992, respectively.
(14) RETIREMENT PLANS:
i The following disclosures are the totals for MPS and nonutility affiliates, of v/hi'6 MPS represents approximately 96 percent of the payroll costs covered under these plans. No detailed segregation of the data is available by subsidian. MPS data is shown in summary only, i
The Company has non-contributory defined benefit pension plans covering substantially all
{
employees. The benefit formulas are based on each employee's years of service and individual camings.
l i
The Company generally uses the aggregate actuarial cost method to determine annual funding requirements. Under this method, there is no unfunded prior service cost. The excess of the present value of projected benefits over plan assets is funded as a level percentage of covered payroll. The utility has been allowed to recover funding contributions in rates.
l G
4 Net periodic pension cost includes the following components for the years ended December 31 (in thousands):
1993 1992 1991 Service cost-benefit camed during the period.
S 7.857 5 6,776 5 6,445 Interest cost on projected benefit obligation..
14,951 13,701 11.137 Decrease in pension costs from actual retum on assets (5,140)
(8,912)
(32,283)
Net amortization and defemd..
(10,787)
(7,388) 17,732 Regulatory recognition of incurred cost.
(1.114) 911 999 MPS and affiliates net periodic pension cost.
S 5.767 5 5.088 5 4,030 MPS net periodic pension cost S 5.418 5 4.930 S 3,262 Assumptions used were:
Discount rate 7.25 %
8.00 %
8.50%
Rate of increase in compensation levels....
5.50%
5.50%
5.50%
Expected long-term rate of retum on assets..
9.00 %
9.00 %
9.00%
The plan assets are stated at fair market value and are comprised of insurance contracts, federal govemment debt and corporate equity securities. The following table presents the plans' funding status and amounts recognized in the Company's Consolidated Balance Sheets as of December 31 (in thousands):
1993 1992 Actuarial present value of benefit obligations:
Vested benefit obligation
$(143,449)
$(121,547)
Nonvested benefit obligation................
(12.016)
(7.156)
Accumulated benefit obligation..............
(155,465)
(128,703)
Provision for future pay increases.
(64.249)
(50.728)
Pmjected benefit obligation.................
(219,714)
(179,431)
Plan assets at fair value.....................
176.719 176.323 Projected benefit obligation greater than plan assets.............................
(42,995)
(3,108)
Unrecognized prior service cost...............
14,100 12,998 Unrecognized net loss...........
38,180 2,825 Unrecognized net transition asset..............
(16,408)
(17,865)
Other.
(10.102)
(3.473)
Pension liability recognized from total MPS and affiliate plans..
S (17,225)
$ (8.623)
Pension contribution in excess of cost included in Deferred Charges and Other in the MPS Consolidated Balance Sheets................
S 7.086 S 8.353 In addition to defined benefit pension plans, the Company provides certain health care and life insurance benefits for retired employees. Under the current plan, substantially all of the Company's employees may become eligible for these benefits if they reach retirement age while working for the Company. However, the Company retains the right to change these benefits anytime at its discretion..
e
The Company adopted Financial Accounting Standard 106 " Employers Accounting for Postretirement Benefits Other Than Pensions" (FAS 106)in January 1993. For its Iowa utility operations, the Company is deferring the difference between the FAS 106 costs and the " pay-as-you-go" costs in anticipation of recovery of these costs in future rate proceedings. The IUB issued an order in January 1993, allowing recovery of extemally funded FAS 106 costs. An IUB order allows utilities to defer the difference between the FAS 106 accrual and the " pay-as-you-go" method for up to three years. Therefore, the adoption of the standard has a minimal effect on current period eamings.
Net periodic postretirement benefit cost includes the following components for the year ended December 31 (in thousands):
1993 Service cost camed during the period 5 1.778 Interest cost 7,583 Decrease in benefit costs from actual retum on plan assets.
(462)
Amonization of unrecognized transition obligation.......
4.767 Other 287 Regulatory recognition of incurred cost.............
(9.12J.)
MPS and affiliates net periodic postretirement benefit cost S 4.827 MPS net periodic postretirement benefit cost..
$ 4.661 The Company has established two extemal trust funds to meet its expected obligation. The trust funds' assets are comprised primarily of guaranteed investment accounts. A reconciliation of the funded status of the plan to the amounts realized as of December 31 is presented below (in thousands):
1993 Accumulated postretirement benefit obligation:
Retirees
$(68,797)
Active employees..
(48,843)
Plan assets at fair value 10,082 Unrecognized transition obligation..
90.579 Unrecognized net loss.
16.979 Net postretirement benefit liability recognized in the Consolidated Balance Sheets of MWR and MPS 5
For purposes of calculating the postrctirement benefit obligation it is assumed that health care costs for covered individuals prior to age 65 will increase by 14.0 percent in 1994, and that the rate of increase thereafter will decline to 5.5 percent over a ten-year period. Health care costs for covered individuals age 65 and older are assumed to increase by 11.0 percent in 1994, and the rate of increase thereafter will decline to 5.5 percent over a seven-year period. The weighted average discount rate used in detennining the accumulated postretirement benefit obligation was 7.25 percent at December 31,1993. The expected long-term rate of retum on plan assets was 9.0 percent and 6.2 percent after taxes for the union plan and salaried plan, respectively.
If the assumed health care trend rate used to measure the expected cost of benefits covered by the plan was increased by one percent, the total service and interest cost would increase by $1.323.000 and the accumulated postretirement benefit obligation would increase by $11.119.000.
l 53-
e a
Recently introduced legislation has pmposed national health care reform. The Company can not determine at this time what reforms will be made or their impact on the Company.
(15) AFFILIATED COMPANY TRANSACTIONS:
The companies identified as affiliates, other than the parent company, are wholly owned subsidiaries of MWR. The basis for these charges is provided for in service agreements between MPS and the parent company or its affiliates. In the opinion of management, the expenses between entities are fair and reasonable.
MPS' parent company incurs cenain administrative and general expenses which are of general benefit to all of its subsidiaries, including treasury, legal, shareholder relations and accounting functions.
MPS' share of such expenses was $6,807,000, $4,930,000 and $4,382,000 for 1993,1992 and 1991, respectively.
MPS is reimbursed for charges incurred on behalf of its parent company and other affiliated companies. The amount of such expenses were $7,796,000,56,810,000 and $5,529,000 for 1993.1992 and 1991, respectively. The majority of these reimbursed expenses were for employee wages and benefits, insurance, building rental, computer costs, admim}strative services and travel expense.
MPS leases office facilities and other propenies from affiliates and total lease payments were
$599,000, $577,000 and $2,324,000 for 1993,1992 and 1991, respectively. On December 31,1991, MPS assumed ownership of the Sioux City office building which had previously been leased from an affiliate.
As a result of the transfer, MPS assumed notes payable in the amount of $13,928,000.
MPS leases unit trains from an affiliate for the transportation of coal to MPS generating stations.
Unit train costs, including maintenance, were $2,941,000, $2,933,000 and $3,825,000 for 1993,1992, and 1991, respectively.
MPS leases other transportation equipment fmm an affiliate. MPS' lease costs were $235,000,
$281,000 and $671,000 for 1993,1992 and 1991, respectively.
MPS received interest income on cash invested with affiliates and interest expense was allocated to MPS from the parent. MPS recorded net affiliate company interest expense of $130,000 and $175,000 for 1992 and 1991, respectively.
MPS accepted assignment of accounts receivable owned by MWR to its diversified businesses subsidiary of $22,609,000 and $45,000,000 in 1992 and 1991, respectively. MPS collected $18,586,000 and $12,067,000 of the receivables during 1992 and 1991, respectively.
During 1993, MPS sold natural gas to an affiliate. MPS' cost of gas and margin related to these transactions were $505,000 and $58,000, respectively. MPS purchased natural gas from an affiliate during 1993. MPS' costs from these transactions were $198,000, in addition, MPS and an affiliate engaged in natural gas buy / sell transactions during 1993. MPS' transportation cost and margin related to these transactions were $398,000 and $197,000, respectively.
(16) UNAUDITED QUARTERLY OPERATING RESULTS:
Earnings on Operating Operating Common Revenues Income Stock (In Thousands) 1993 ist Quarter
$ 296,254 5 43,646
$ 27,128 2nd Quaner 212,152 24,915 9,534 3rd Quaner.
233,982 38,953 34,876 4th Quaner......
254,157 24,883 11,965 1992 1st Quaner
$ 251.163
$ 32,650
$ 16,365 2nd Quarter..
196,657 18,429 3,584 3rd Quaner.......
211,946 30.736 12,330 4th Quaner..
263,414 31,156 14,665
MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The Company's management is responsible for the presentation of the accompanying financial statements, which have been prepared in conformity with generally accepted accounting principles and I
include amounts based on informed estimates and judgments of management.
l Management maintains intemal accounting controls which it believes are adequate to pmvide reasonable assurance that assets are safeguarded, transactions are executed in accordance with management authorization and financial records are reliable for preparing the financial statements. Intemal accounting controls are supponed by written policies and procedures, a staff of intemal auditors who conduct compmhensive intemal audits and the selection and training of qualified personnel.
The Midwest Resources Inc. Board of Directors, through its Audit Committee comprised entirely of outside directors, meets periodically with management, intemal auditors and the Company's independent public accountants to discuss auditing, intemal control and financial reporting matters. To ensum their independence, both the intemal auditors and independent public accountants have full and free access to the Audit Committee.
The independent public accountants, Arthur Andersen & Co., are engaged to audit the Company's financial statements in accordance with generally accepted auditing standards.
R. E. Christiansen l
Chairman, President and Chief Executive Officer
(
4 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To Midwest Power Systems Inc.:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Midwest Power Systems Inc. (an Iowa corporation and wholly-owned subsidiary of Midwest Resources Inc.) and subsidiades as of December 31,1993 and 1992, and the related consolidated statements of income, retained eamings and cash flows for each of the three years in the period ended December 31,1993. These financial statements and the schedules n:ferred to below are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the firancial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes ass:ssing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Midwest Power Systems Inc. and subsidiaries as of December 31,1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31,1993, in confonnity with generally accepted accounting principles.
As explained in Note 13 to the consolidated financial statements, the Company has given retroactive effect to the change in accounting for income taxes. As explained in Note 14 to the consolidated financial statements, effective January 1,1993, the Company changed its method of j
accounting for postretirement benefits other than pensions.
l Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index of financial statement schedules (Item 14(a) 2) are presented for purposes of complying with the Securities and Exchange Commission's rules and are not pan of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
Chicago, Illinois January 28,1994 Arthur Andersen & Co.
1 I
UNAUDITED MIDWEST POWER STATISTICS For the year ended December 31 1993 1992 1991 1990 1989 Revenues (000)
Residential.
S 271,577 5 244,295 5 267,178 5 253,937 5 240,513
' Small general service.
149,283 150,319 152,870 145,547 150.256 Large general service.
109,151 111,674 111,694 111,822 120,456 Other..................
56.590 30.839 32.434 30341 32.661 Subtotal 586,601 537,127 564,176 541,647 543.886 Sales for resale..............
77.776 86.233 73N6 69320 68309 Total S 664377 5 623.360 S 637,222 S 610.967 5 612,195 Sales (000 kWh)
Residential.................
3.236,929 2,956,489 3,252,828 3,025,089 3,013,384 Small general service......
2,598,178 2,617,781 2,667.210 2,489,279 2,354.375 Large general service...
2,858,381 2,937,041 2,881,832 2.938,581 2,819,734 Other.....................
811.688 347371 354.719 356.787 370361 S ubtotal..................
9,505,176 8,858,682 9.156.589 8,809.736 8,557,854 Sales for resale..
4.018.919 5.085.508 4.424.222 4.239.471 4.027.660 Total....................
13.524,095 13.944,190 13.580.811 13D*9.207 12.585.514 Energy (000 kWh)
Generated...
10,819,740 9.753,806 9,814,754 9.306,590 8,444,290 Purchased.................
3.255.636 4.973.069 4.549.152 5.503326 4.843.178 14.075376 14.726,875 14 363.906 14.809.916 13.287.468 Customers (year-end)
Residential........
363,305 360,048 356,076 353.490
'350,464 Small general service..........
48,314 51,407 50,923 50,593 49,858 Large general service....
671 759 769 751 759 Other..................
7.978
_ _. _ 4.494 4389 4.252 4.067 Subtotal........
420,268 416,708 412,157 409,086 405.148 Sales for resale..............
54 79 85 84 88 Total..................
420322 416.787 412,242 409,170 405,236 Average Annual Use Per Residential Customer Revenue...............
S751.04 568235
$753.09 5721.95 5689.35 KWh..........
8,952 8,258 9,169 8,600 8,637 Average number of res'dential customers..
361,603 358,018 354,774 351,739 348,896 Revenues as a Percent of Total Residential.................
40.9 %
39.2 %
41.9 %
41.6%
393 %
Small general service..
22.5 24.1 24.0 23.8 24.5 Large general service..........
16.4 17.9 17.5 18 3 19.7 Other...
8.5 5.0 51 5.0 53 Subtotal...........
883 86.2 88.5 88.7 88.8 Sales for resale 11.7 13.8 11.5 11.3 11.2 Total....................
100.0 %
100.0 %
_ 100.0 %
100.0 %
100.0 %
Sales as a Percent of Total Residential.................
23.9 %
21.2 %
24.0 %
23.2 %
23.9 %
Small general service........
19.2 18.8 19.6 19.1 18.7 Large general service..........
21.2 21.0 21.2 22.5 22.4 Other.....................
6.0 2.5 2.6 2.7 3.0 Subtotal...........
703 63.5 67.4 67.5 68.0 Sales for resale....
29.7 36.5 32.6 32.5 32.0 Total.................
100.0 %
100.0 %
100.0 %
100.0 %
100.0 %
58-
UNAUDITED MIDWEST GAS STATISTICS 1 OF 2 For the year ended December 31 1993 1992 1991 1990 1989 Revenues (')00)
Residential..
S 200,247 5 183,262 S 176.649 5 158.653 5 169,392 Small general service 91.127 81,689 78,233 70,749 78,493 Large general service..
23.654 29,170 30,680 30,139 32,702 Sales for resale 5,346 8.164 3.017 4.078 4.662 4.483 Other Subtotal...
328,538 297,138 289.M 0 2M,203 285,070
)
3.630 2.682 2.651 1.414 1.492 Gas Transported Total..
S 332.168 S 299.820 5 292.291 S 265.617 5 286.562
)
f Throughput (000 MMBtu)
Sales Residential.
36,129 33,161 34,750 31,413 34,621 Small general service..
20,517 18,829 19,300 18,N2 20,179 Large general service 6,118 8,303 9,187 9,493 11,594 Sales for resale.
2,619 Other.......
1.559 463 1.014 490 478 66,942 60,756 64,251 59,438 66,872 Total sales Gas transported........................
14.439 12.421 10.993 '
9.688 12.844 Total..
81.381 73,177 75.244 69,126 79.716 Supply (000 MMBtu)
Gas from peakmg facilities j
LP gas 13 15 4
28 24 LNG gas....
256 277 421 473 1,978 Natural gas purchased...
78,945 69,062 75,887 65,291 67,750 Total gas receipts.
69 38 39 63 52 Methane gas purchased.
79,283 69,392 76,351 65,855 69,804 Less Company use, deliveries to LNG and storage 13.886 7.597 443 5.447 2.119 Supply available for retail sales 65,397 61,795 75,908 60,408 67,685 Sales for resale purchases 2.619 68.016 61.795 75.908 60,408 67,685 Total.........
Customers (year end)
Residential...............
306,507 334,789 327,313 321,119 312,446 Commercial 34,607 34,706 34,261
't3,998 33,104 Industrial.
750 906 940 944 1,044 Sales for resale...
4 S ubtotal....................
341.868 370,401 362,514 356,061 346,594 Gas Transported.........
84 72 59 56 47 Total.
341.952 370.473 362,573 356,117 346.641 Average Annual Use Per Residential Customer Revenue.
S 614.58 5 555.29 5 546.16 5 502.57
$546.53 MMBtu 111 100 107 100 112 Average number of residential customers 325,825 330,027 323,437 315,682 309,941
UNAUDITED MIDWEST GAS STATISTICS 2OF2 For the year ended December 31 1993 1992 1991 1990 1989 Degree Days Actual 7.314 6.434 6,724 6,439 7.420 Normal 7.054 7,101 7.268 7.268 7.251 Percent colder (warmer) than normal 3.7 (9.4)
(7.5)
(11.4) 2.3 Revenues as a Percent of Total Residential............
60.3 %
61.1 %
60.4 %
59.7 %
59.1 %
Small general service........
27.4 27.3 26.8 26.6 27.4 Large general service...........
7.1 9.7 10.5 11.4 11.4 Sales for resale 1.6 Other......................
2.5 1.0 1.4 1.8 1.6 Subtotal.
98.9 99.1 99.1 99.5 99.5 Gas Transponed......
1.1 0.9 0.9 0.5 0.5 Total..........
100.0 %
100.0 %
100.0 %
100.0 %
I00.0 %
Sales as a Percent of Total (Excluding Gas Transported)
Residential.................
54.0 %
54.6 %
54.1 %
52.8%
51.8%
Small general service....................
30.6 31.0 30.0 30.4 30.2 Large general service.......
9.2 13.7 14.3 16.0 17.3 Sales for resale........................
3.9 Other...............................
2.3 0.7 1.6 0.8 0.7 Total.
100.0 %
100.0 %
100.0 %
100.0 %
100.0 %
Cost per MMBtu.
S 3.35 S 3.30 S 3.07 5 3.05 L2y l
1 _
SCHEDULE Il MIDWEST POWER SYSTEMS INC.
AMOUNTS RECEIVABLE FROM RELATED PARTIES, UNDERWRITERS, PROMOTERS AND EMPLOYEES OTHER THAN RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31,1993 (In Thousands)
Column A Column B Column C Column D Column E Balance at Deductions Balance at Beginning Amounts Amounts End of Year of Year Additions Colfected Written Off Current Not Cunent Accounts Receivable Midwest Resources inc..
537,398 5 4,018 5 4,300 5
537,116 S
Midwest Capital Group,Inc..
58 1,245 1,171 132 Other Related Parties......
198 9.190 9.057 331 Total
$37,654
$14,453
$14,528 5
$37.579 S
~..
I i
i SCHEDULE II MIDWEST POWER SYSTEMS INC.
AMOUNTS RECEIVABLE FROM RELATED PARTIES, UNDERWRITERS, PROMOTERS AND EMPLOYEES OTHER THAN RELATED PARTIES FOR THE YEAR ENDED DECEMLER 31,1992 (In Thousands) f Column A Column B Column C Column D Column E Balance at Deductions Balance at Beginning Amounts Amounts End of h of Year Additions Collected Written Off Current Not Caoent Accounts Receivable i
Midwest Resources Inc......
533,662 526,238 (1) $22,502(2) 5 537,398 Midwest Capital Group, Inc...
22,155 (21,595)(1) 502 58 Other Related Parties.......
302 2.167 2.271 J
Total.................
$56.119
$ 6,810 M
S
$37.654 S
I (1) Includes the transfer of 522,609 receivable from Midwest Capiut! Group, Inc. to Midwest Resources Inc.
j (2) Includes $18.586 collected on the receivable transferred from Midwest Capital Group, Inc.
s I
+
h i
l,
i
?
SCHEDULE 11 MIDWEST POWER SYSTEMS INC.
AMOUNTS RECEIVABLE FROM RELATED PARTIES, UNDERWRITERS, PROMOTERS AND EMPLOYEES OTHER THAN RELATED PARTIES FOR THE YEAR ENDED DECEMBER 31,1991 (In Housands)
Column A Column B Column C Column D Column E Balance at Deductions Balanze at Beginning Amounts Amoun:s End of Year of Year Additions Collected Written Off Current Not Current Accounts Receivable Midwest Resources Inc.
S 192 548,148 (1) 514,678 (2) 5 533,662 S
Midwest Capital Group. Inc..
67,731 (44,197)(1) 1.379 (3) 22,155 Other Related Parties..
322 1.578 1.598 302 Total.........
S68.245 S 5,529 517.655 S
556,119 5
(1) Includes the transfer of $45,000 receivable from Midwest Capital Group, Inc. to Midwest Resources Inc.
(2) Includes $12,067 collected on the receivable transferred from Midwest Capital Group,Inc.
(3) Includes a non-cash settlement of $128 for the IPS corporate headquarters building.
O SCHEDULE V MIDWEST POWER SYSTEMS INC.
CONSOLIDATED PROPERTY. PLANT AND EQUIPME. T V
FOR THE YEAR ENDED DECEMBER 31.1993 (In Thousands)
Column A Column B Column C Column D Column E Column F Retirements Balance at or Sale at Other Balance Beginning Addidons Original Charges at Close Classification of Year at Cost Cost (Credits) of Year (Note 2)
(Note 3)
ELECTRIC PLANT:
Electric plant in service intangibles.
5 12,808 5
671 5
3 5
5 13.472 Produedon Steam 912.377 1.784 1.663 (190) 912.308 Other 84,683 175 42 84,816 Transmission.
273.698 5.071 1.390 63 277.442 Distribudon.
614.535 23.399 2J58 224 635.800 General plant..
124.053 2.228 523 (1.278) 124.480 Completed. not unitized.....
103.913 33.832 (554) 138.299 Total electric plant in service 2.126.063 67.160 5.425 (1.181) 2.186.617 Electric plant in service under capital lease..
10.544 198 10.346 Experimental plant...........
53
$3 Plant held for future use..
18.151 3.942 (651) 13.558 Construction work in progress...
28.283 54.913 83.1 %
Total electric plant..
2.183.004 122.073 9.565 (1.832) 2.293.770 GAS PLANT
- Gas plant in service Intangib!cs..............
4,607 86 (109) 4.584 Production.
6.744 144 7
(1.582) 5.299 Other storage.
17.335 376 25 543 18.229 Distribution.....
258.823 12.844 1.067 (17.249) 253.351 General plant...
51.526 2.428 1.398 2.681
$5.237 Completed, not urutized..
9.502 2.830 (10)
(2.574) 9.768 Total gas plant in service...
348.537 18.708 2.487 (18.290) 346,468 Gas plant in service under capital lease 997 997 Plant acquisidon adjustment 19.456 1.905 21.361 Plant held for future use.
4 4
Construction work in progress....
5,133 584 (1,177) 4.540 Total gas plant..
374.127 19.292 2.487 (17.562) 373.370 Total utility plant..
32.557.221 5141.365
_$ 12.052 5 (19.394) 52.667.140 OTHER PHYSICAL PROPERTY 5
2.174 5
332 5
4 5
5 2,502 NOTES:
(1)
See Notes (le). (8) and (12) of Notes to Consolidated Financial Statements.
+
(2)
The reserve for unlity plant depreciadon has been charged with the amount indicated on Schedule VJ for the year ended December 31.1993.
(3)
Other Charges (Credits) includes the net effect of the gas property exchange.
64
i SCHEDULEV MIDWEST POWER SYSTEMS INC.
)
CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31.1992 (In Thousands)
Column A Column B Column C Column D Column E Column F Retirements Balance at or Sale at Other Balance Beginning Additions Original Charges at Close Classi5 cation of Year at Cost Cost (Credits) of Year (Note 2)
(Note 3)
)
ELECTRIC PLANT:
Electric plant in service
)
Intangibles....
S 6.434 5
457 5
1 5 5.914 5 12.804 1
Production l
Steam 909.470 3.153 696 450 912.377 1
Other.....
84,751 78 10 84,683 Transmission 271.666 5.257 3.226 1
273.698 Distribution......
581.036 38.018 4.516 (3) 614.535 General plant.......
95.918 6,619 3.773 25.289 124.053 Completed, not unitized..
78.216 27.674 1.390 (587) 103.913
)
Total electric plant in service 2.027,491 81.178 13.680 31.074 2.126.063 Electric plaat in service under capital lease.
10.449 41 136 10.544 Experimenuti plant..
33 20 53 Plant held for future use................
23.234 4.404 (67.9) 18.151 Construction work in progress.
26.490 498 1.295 28.283 Total electric plant.
2.087.697 81.676 18.125 31.846 2.183.094 l
GAS PLANT Gas plant in service intangibles..
1.584 19 3,004 4.607 Production.
6.743 1
6.744 Other storage.....
17.331 4
17.335 Distribution 242,927 17.266 1.378 8
258,823 General plant...
23.685 1.466 86 26.461 51.526 1
Completed, not unitized.
9.526 195 219 9.502 Total gas plant in service 301.796 18.951 1.683 29.473 348.537 Gas plant in service under capital lease 997 997 Plant acquisition adjustment 19,456 19.456 Plant held for future use,.
4 4
Consuuction work in progress.
2,242 2.891 5.133 Total gas plant.
324.495 21.842 1.683 29.473 374.127 COMMON PLANT:
Common plant in service 61.619 (2.840)
(1.326)
(60,105)
Construction work in progress.
932 400 (1.332)
Total common plant.
62.551 (2.440)
(1.326)
(61.437)
Total utility plant..
$2.474.743
$ 101.078 5 18.482 5 (118)
$2.557.221 UTHER PHYSICAL PROPERTY 5
2.565 186 5
416
$ (161) 5 2.174 NOTES:
(1)
See Notes (le). (8) and (12) of Notes to Consolidated Financial Statements.
(2)
The reserve for utility plant depreciation has been charged with the amount indicated on Schedule VI for the year ended December 31.1992.
(3)
Utility Plant previously classified as Common Plant was transferred to Electric Plant and Gas Plant during 1992.
65
o SCHEDULE V MIDWEST POWER SYSTEMS INC.
CONSOLIDATED PROPERTY. PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31.1991 (In Thousands)
Column A Column B Column C Column D Column E Column F Retirements Balance at or Sale at Other Balance Beginning Additions Original Charges at Close Classification of Year at Cost Cost (Credits) of Year (Note 2)
ELECTRIC PLANT.
Electric plant in service intangibles.
1.320 5 1.287 5
6 S
3.833 5
6/ 34 Production Steam 896.179 16.169 2.880 2
909,470 Other 49.931 34.842 22 84,751 Transmission 263.033 10.012 1.336 (43) 271,666 Distribution..........
549.890 35.729 4.562 (21) 581.036 General plant...
97.797 9.554 7.637 (3.796) 95.918 l
Completed not unitized..
94.646 (18.G18)
(1.618) 78.216 l
Total electric plant in service 1.952.796 89,545 14.825 (25) 2.027.491 i
Electric plant in service under capital lease..
6.984 3.465 10.449 Experimental plant.
33 33 Plant held for funire use.
23.358 124 23.234 Construction work in progress..
37.840 (11.350) 26.490 Total electric plant.
2.021.011 78.195 14.940 3.440 2.087.697 GAS PLANT.
Gas plant in service Intangibles..
1.326 259 2
1 1.584 Production..
6,288 447 4
12 6.743 Other storage...
16.208 1.224 77 (24) 17.331 Distribution......
216.613 27.402 1.088 242.927 General plant....
20.252 4.040 648 41 23.685 Completed, not unitized.......
19.846 (10.304) 16 9.526 Total gas plant in service 280.533 23.068 1.835 30 301.796 Gas plant in service under capital lease 997 997 Plant acquisition adjustment 19.456 19.456 Plant held for future use.
4 4
Construction work in progress..
6.503 (4.261) 2.242 Total gas plant.
307.493 18.R07 1.835 30 324.495 COMMON PIANT.
Common plant in service.
44.283 4.763 2,840 15.413 (3) 61.619 Common plant in service under capital lease..
15.400 (15.400)(3)
Construction work in progress...
2,783 (1.851) 932 Total common plant.
62.466 2.912 2.840 13 62.551 Total utility plant...
52.390.970
$ 99.914 5 19.624 S 3,483 52.474,743 OTHER PHYSICAL PROPERTY.........
S 6.589 5
(219) 4,323 518 5
2.M5, NOTES:
(1)
See Notes (le). (8) and (12) of Notes to Consolidated Financial Statements.
(2)
The reserve for utility plant depeciation has been charged with the amount indicated on Schedule VI for the year l
ended December 31,1991. The difference represents the sale of land and other property not fully depreciated.
1 (3)
MPS assumed ownership of property which was previously recorded as Propeny Under Capital Lease.
66 l
SCHEDULE VI MIDWEST POWER SYSTEMS LNC.
CONSOLIDATED ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31,1993 (In Thousands)
Column A Column B Column C Column D Column E Column F Retirements Balance at Additions Charged to Cost of Adjustments Balance at Beginning Other At Original Removal or and Close Description of Year income Accounts Cost Salvage. Net Transfers,,,pf Yppr (Notes 1&2) (Note 3) (Note 4)
(Note 5)
UTILITY PLANT:
Electric plant..............
$873,194 5 74.516 5 4,469 5 9,565 5 3,314 S
(54) $939,246 Gas plant 100,708 12.041 1,194 2,487 (95) 2,008 113,559 Plant acquisition adjustment.
4340 699 (1.793) 3.446 Total udlity plant accumulated depreciadon and amortization. S 978,442 6 87,256 5 5,663 S 12.052 5 3.219 5
161 $1.056.251 OTHER PHYSICAL PROPERTY S 4
S I $
S S
S
-S S
NOTES:
(1)
See Footnote 1(c) of Notes to Consolidated Financial Statements for the basis of the provisions for depreciation.
(2)
Depreciadon and a srtization as shown on the Consolidated Statements ofIncome and the Consolidated Statements of Cash Flows includes $2.548 of amortization of deferred charges.
(3)
Represents provisions for depreciation of work equipment and other miscellaneous equipment of the Company which are charFed to clearing accounts and apportioned therefrom, together with other expenses, to various accone (4)
See Note (2) to Schedule V..ar the year ended December 31,1993.
(5)
Adjustments and Transfers includes the net effect of the gas property exchange.
1 1
1....
SCHEDULE VI MIDWEST POWER SYSTEMS INC.
CONSOLID ATED ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31,1992 (In "Ihousands)
Column A Column B Column C Column D Column E Column F Retirements Balance at Additions Charged to Cost of Adjustments Balance at Beginning Other At Original Removal or and Close Description of Year Income Accounts Cost Salvace. Net Transfers of Year (Notes 1&2) (Note 3) (Note 4)
UTILITY PLANT:
Electric plant.
5809,938 5 70.832 S 3,253 S 18,125 5 2,492 5 9,788 $873,194 Gas plant 84,098 10,457 1,466 1,683 369 6,739 100,708 Plant acquisition adjustment 3,892 648 4,540 Common plant..
15.551 2.599 '
100 (l.326)
- (148)
(19.724)
Total utility plant accurnulated depreciation and amortization. $913 479 5 84,536 5 4,819
$18.4R2 5 2,713 S (3,197) $978.442 OTI-ER PHYSICAL PROPERTY S
4 S
S S
S S
- S 4
NOTES:
(1)
See Footnote 1(c) of Notes to Consolidated Financial Statements for the basis of the provisions for depreciation.
(2)
Depreciation and amortization as shown on the Consolidated S tatements ofIncome and the Consolidated Statements of Cash Flows includes S1,654 of amortization of deferred charges.
(3)
Represents provisions for depreciation of work equipment and other miscellaneous equipment of the Company which are charged to clearing accounts and apportioned therefrom, together with other expenses, to various accounts.
(4)
See Note (2) to Schedule V for the year ended December 31,1992.
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SCHEDULE VI MIDWEST POWER SYSTEMS INC.
CONSOLIDATED ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31,1991 (In Thousands)
Column A Column B Column C Column D Column E Column F Retirements Balance at Additions Charced to Cost of Adjustments Balance at Beginning Other At Original Removal or and Close Descrirition of Year income Accounts Cost Salvace. Net Transfers of Year (Notes 1&2) (Note 3) (Note 4)
UTILITY PLANT:
Electne plant.......
5750,557 568,195
$2,970 S14,918 51,070 S4.204 5809,938 Gas phnt 74,899 9,989 1,354 1,835 318 9
84,098 Plant acquisition adjustment 3,243 649 3,892 Common plant....
15.889 2.023 376 2.840 (90) 13 15.551 l
Total utility plant accumulated l
depreciation and amonization. 5844,5R8 580,856 S 4,700
$19,593
$1,298 5 4,226 5913,479 OTHER PHYSICAL PROPERTY S 100 5
1 5 S 410
$ (91)
S 222 S
4 NOTES:
(1)
See Footnote 1(c) of Notes to Consolidated Financial Statements for the basis of the provisions for depreciation.
(2)
Depreciation and amortization as shown on the Consolidated S tatements ofincome and the Consolidated Statements of Cash Flows includes $1,618 of amortization of defened charges.
(3)
Represents provisions for depreciation of work equipment and other miscellaneous equipment of the Company which are charged to clearing accounts and apportioned therefrom, together with other expenses, to various accounts.
(4)
See Note (2) to Schedule V for the year ended December 31,1991.
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SCHEDULE Vill MIDWEST POWER SYSTEMS INC.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE THREE YEARS ENDED DECEMBER 31,1993 (In Thousands)
Column A Column B Column C Column D Column E Deductions Additions for Purposts Balance at Charged for Which Balance at Beginning Charged to Other Reserves End Description of Year to Income Accounts Were Created of Year Reserves Deducted From Assets To Which Rey Apply:
Reserve for uncollectable accounts:
Year ended 1993 51,151 51,936 S
S2.212 S 875 Year ended 1992 51.069 51.651 S
51,569
$5j Year ended 1991 51,145 51,737 5
S1,813 51,069 e
l SCHEDULEIX MIDWEST POWER SYSTEMS INC.
CONSOLIDATED SHORT-TERM BORROWINGS I
FOR THE THREE YEARS ENDED DECEMBER 31,1993 (In Thousands)
Column A Column B Column C Column D Column E Column F Maximum Average Weighted Category of Waghted Amount Amount Average Aggregate Balance at Average Outstanding Outstanding Interest Rate Short-term End Interest During the During the During the Borrowings of Year Rate Year Year Year (Note 1)
(Note 2)
(Note 3)
Year Ended:
1993 Commercial paper $129.R00 3.39 %
S129.800 S 72,129 3.25 %
1992 Commercial paper S 58,100 3.78 %
S 68,300 5 27,149 3.75 %
1991 Commercial paper S134,600 S104,327 6.15 %
NOTES: (1) Weighted average interest rate on balance at the end of the year.
(2) The computation of the average amount outstanding during the year is based on the sum of the daily amounts outstanding divided by the number of days in the year.
(3) The computation of the weighted average interest rate is based on the sum of the annual interest on each transaction divided by the sum of the daily net amounts of commercial paper and notes outstanding.
(4) See Footnote (7) of Notes to Consolidated Financial Statements.
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SCHEDULE X MIDWEST POWER SYSTEMS INC.
CONSOLIDATED SUPPLEMESTARY INCOME STATEMENT INFORMATION FOR THE THREE YEARS ENDED DECEMBER 31,1993 (In Thousands)
Column A Column B Charged to Cest And Expenses Year Ended December 31 1993 1992 1991 Taxes, other than payroll and income taxes - Property.
552.369 555.333 552.625 NOTE:
Maintenance and repairs is not set forth inasmuch as the information is included in the consolidated financial statements.
Depreciation and amortization of intangible assets, royalties and advertising are not set forth inasmuch as such items do not exceed one percent of total revenues as shown in the related Consolidated Statement of Income.
See Footnote (3) of Notes to Consolidated Financial Statements for additional supplementary income statement information by business segment.
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0 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this repon to be signed on its behalf by the undersigned, thereunto duly authorized.
MIDWEST POWER SYSTEMS INC.
Date: March 25,1994 By R. E. Christiansen (R. E. Christiansen)
]
Chairman, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
Signature Title Date R. E. Christiansen Chairman, President and March 25,1994 (R. E. Christiansen)
Chief Executive Officer P. G. Lindner Group Vice President-March 25,1994 (P. G. Lindner)
Administrative Services and Director (Chief Financial and Accounting Officer)
R. C. Engle Director March 25,1994 (R. C. Engle)
I.. K. Vorbrich Director March 25,1994 (L. K. Vorbrich)
B. A. Wharton Director March 25,1994 (B. A. Wharton) _
_,,,-,_m-,,,,iii-i
" ' = ' ' ' ' ' ' ' " ' ' " ' ' '
4 EXIIIBITS INDEX Sequential Exhibits Filed Herewith Pace Nos.
4.4 Third Supplemental Indenture dated as of May 1,1993, between MPS and Morgan Guaranty Trust Company of New York, Trustee.
76 4(a) 2 Twenty-Seventh Supplemental Indenture dated July 2 2,1992, between MPS and Chemical Bank, as trustece under Iowa Public Service Company's Mongage and Deed of Trust, Dated as of June 1,1946.
94 10.6 Midwest Power Systems 1993 Key Executive Incentive Compensation Plan.
115 12 Computation of ratios of camings to fixed charges and computation of ratios of earnings to fixed charges plus preferred dividend requirements.
127 21 Subsidiaries of MPS.
129 23 Consent of Independent Public Accotm: ants.
130 Exhibits incorporated by Reference 3.1 Articles of Incorporation of MPS, as amended (Filed as Annex B to MPS' Registration Statement, Registration No. 33-42866.)
3.2 Bylaws of MPS (Filed as Exhibit 3(b) to MPS' Registration Statement, Registration No. 33-42866.)
4.1 General Mortgage indenture and Deed of Trust dated as of January 1,
- 1993, between MPS and Morgan Guaranty Trust Company of New York, Trustee. (Filed as Exhibit l
4(b)-1 to the Company's Annual Report on Form 10-K for the year ended December 31,1992, Commission File No. 0-20452.)
4.2 First Supplemental Indenture dated as of January 1,
1993, between MPS and l
Morgan Guaranty Trust Company of New York, Trustee. (Filed as Exhibit 4(b)-2 to the Company's Annual Report on Form 10-K for the year ended December 31,1992, Commission File No. 0-20452.)
4.3 Second Supplemental Indenture dated as of January 15, 1993, between MPS and Morgan Guaranty Trust Company of New York, Trustee. (Filed as Exhibit 4(b)-3 to the Company's Annual Report on Form 10-K for the year ended December 31,1992, Commission File No. 0-20452.)
4(a)
Mongage and Deed of Trust dated as of June 1,1946 (physically filed in IPS' Registration Statement No. 2-6418 under the Securities Act of 1933 as Exhibit B-2). 1
o 4(a)-1 Twenty-Third Supplemental Indenture dated as of December 1,1983 (physically filed in IPS' 10-K for fiscal year ended December 31,1984, File Number 1-5131, under the Securities Act of 1934 as Exhibit 4(a)-23).
10.1 Power Sales Contract between IPR and Nebraska Public Power District, dated September 22, 1967. (Filed as Exhibit 4-C-2 to IPR's Registration Statement, Registration No. 2-27681.)
10.2 Amendments No. I and 2 to Power Sales Contract between IPR and Nebraska Public Power District. (Filed as Exhibit 4-C-2-a to IPR's Registration Statement, Registration No. 2-35624.)
10.3 Amendment No. 3 dated August 31, 1970, to the Power Sales Contract between IPR and Nebraska Public Power District, dated September 22, 1967.
(Filed as Exhibit 5-C-2-b to IPR's Registration Statement, Registration No. 2-42191.)
10.4 Amendment No. 4 dated March 28, 1974, to the Power Sales Contract between IPR and Nebraska Public Power District, dated September 22,1967. (Filed as Exhibit 5-C-2-c to IPR's Registration Statement, Registratien No. 2-42191.)
10.5 Amended and Restated Agreement and Plan of Merger among Midwest Power Systems Inc.,
Iowa Public Service Company and Iowa Power Inc. (Filed as Annex A to Midwest Power Systems Inc.'s Registration Statement, Registration No. 33-42866)
Note:
Pursuant to (b)(4)(iii)(A) of Item 601 of Regulation S-K, the Company has not filed as an exhibit to this Form 10-K cvery instrument with respect to long-term not being rgistered debt if the total amount of securities authorized thereunder does not exceed 10 percent of total assets of the Company but hereby agrees to fumish to the Commission on request any such instruments. m
4 FIVE YEAR FORECAST fMIDWEST MRESOURCES RELEASED NOVEMBER 1993 666 GilAND AVEtiUL PO BOXT44 DESM ItJES tonA503%9244 515-242-430?
Profile Midwest Resources is the largest utility holding company in the state of lowo, serving one-third of the state's electric and natural gas customers in urbon, small town and rural creos. Midwest Power Systems, the utility subsidiary, serves 418,000 electric customers in towa and South Dakoto and 337,000 natural gas customers in lowo, South Dakota and Nebraska. The Company hos additional holdings in nonregulated businesses. Midwest Resources has $2.5 bHlion in j
ossets and nearly S900 million in annual revenues. The Company has 54,000 shareholders in all 50 states and 22 countries. Midwest Resources and its predecessors have paid dividends continuously since 1909.
Midwest Resources
)
Financial Forecast (S in millions)
Projected Forecast Totd 1
1993 1994 1995 1996 1997 1998 1994 - 1998 j
Capital Requirements Midwest Power Systems S
165 167 S 196 S 189 $
184 S 189 S 925 Midwest Capital Group 15 12 10 13 18 27 80 Moturities and Sinking Funds 22 8
7 40 9
78 142 Less: AFUDC (1)
(3)
(4)
(3)
(4)
(3)
(17)
J Subtotd Capital Requirements S
201 S
184 S 209 S 239 S 207 S 291 S 1,130 Refinanced Long-Term Debt S
675 Totd Capital Requirements S
876 S
184 $
209 S 239 S 207 S 291 $
1,130 Intemal Sources of Capitol Depreclotion and Amortization S
116 118 $
117 $
122 S 122 S 123 S 602 Demond-Side Mgmt Amortization 0
4 7
13 16 18 58 Deferred Tax Items - Net (10)
(10)
(5)
(1)
(1)
(4)
(21)
Other 25 17 32 24 31 40 144 Subtotal internal Sources of Capitol 131 129 $
151 S 158 S 168 $
177 $
783 Percent of Total Capital Requirements 70%
72%
66%
81%
61%
69%
External Sources of Capital Long-Term Debt Financing 632 85 $
40 $
30 $
35 S 100 $
290 Common Equity Financing 0
40 0
30 0
0 70 Short-Term Financing 113 (70) 18 21 4
14 (13)
Subtotal External Sources of Capito!
745 S
55 S 58 S 81 S 39 S 114 S 347 Percent of Total Capitol Requirements 3(4 28%
34%
19%
39%
31%
Totd Sources of Capital S
876 S
184 $
209 $
239 S 207 S 291 S 1,130 Capitalization Ratios - Year-End Long-Term Debt 49%
49%
49%
48%
48%
48%
Preferred Stock 5%
5%
5%
5%
5%
5%
Common Equity 46%
46%
46%
47%
47%
47%
i Midwest Power Systems Financlol Forecast
($ in millions)
Projected Forecast Total 1993 1994 1995 1996 1997 1998 1994-1998 Capitol Requirements Midw:st Power Capital Expenditures S
129 S 129 $
152 S 149 S 141 S
145 S 716 Demand-Side Mgmt Expenditures 10 10 13 13 15 15 66 Less: AFUDC (2)
(2)
(4)
(3)
(4)
(3)
(16)
Subtotal Midwest Power S
137 S 137 S 161 S
159 $
152 S 157 S 766 Midw:st Gas Capito! Expenditures S
24 $
23 S 26 $
21 S
21 S
21 S
112 Demond-Side Mgmt Expenditures 3
4 5
6 7
8 30 Less: AFUDC 0
0 0
0 0
0 0
Subtotal Midwest Gas S
27 S 27 S 31 S 27 S 28 S 29 $
142 Midw:st Power Systems Maturities and Sinking Funds S
14 S 2 S 1
S 1
S 3 $
78 S 85 Subtotal Midwest Power Systems S
14 S 2 S 1
S 1
S 3 S 78 S 85 Refinanced Long-Term Debt S
675 Total Capitol Requirements S
853 S 166 S 193 S 187 $
183 $
264 S 993 Int:rnd Sources of Capitd D:preciation and Amortization S
107 S 110 $
111 S
116 S 115 S 116 S 568 D mond-Side Mgmt Amorttzotion 0
4 7
13 16 18 58 Defstred Tax ttems - Net 1
0 (1) 0 (1)
(2)
(3)
Cnher 23 13 19 13 14 17 76 SubtotallnternalSources of Capitol S
131 S 127 S 137 S 142 S 144 S 149 S 699 Percent of Total Capitol Requirements 77%
71%
76%
79%
56%
70%
Ext md Sources of Capitd Long-Term Debt Financing S
632 S 85 $
40 $
30 $
35 $
100 $
290 Common Equity Financing 0
40 0
30 0
0 70 Short-Term Financing 90 (86) 16 (15) 4 15 (66)
Subtoio! External Sources of Capitol S
722 S 39 S 56 S 45 S 39 $
115 S 294 Percent of Total Capital Requirements 23%
29%
24%
21%
44%
30%
TotalSources of Capitol S
853 S 166 S 193 S 187 S 183 S 264 $
993 Capitalization Ratios - Year End 47%
50%
50%
50 %
50%
50%
Long-Term Debt Preferred Stock 6%
5%
5%
5%
5%
5%
Common Equity 47%
45%
45%
45%
45%
45%
Prs-Tax Interest Coverage 3.2 3.2 3.3 3.1 3.1 3.2 l
1 Midwest Power Systems Operating Forecast Compound Projected Forecast Growth 1993 1994 1995 1996 1997 1998 1993-1998 Midwest Power (1)
MWh Sales (in thousands) (2)
Retail Sales 9,664 9,938 10.163 10,344 10,530 10,740 2.1%
Sales for Resole 3.934 4.952 4A65 4.504 4420 4278 1.7%
Total Soles 13,598 14,890 14428 14,848 15,150 15D18 2.CL Electric Generating Capabilrty (MW) 2,836 2.938 2.938 2,938 2,938 2.938 Copacity Purchases 359 357 378 258 251 251 Capacity Sales 433 459 429 304 306 306 Peak Demand 2,205 2,312 2,398 2A05 2A25 2455 Reserve Morgin 25.3%
22.7 %
20.4 %
20.2%
18.9%
17.4 %
Fuel Sources Cool 78%
81 %
81 %
78%
80%
Nucl eor (3) 21%
18%
18%
21%
19%
Oil /Gos 1%
1%
1%
1%
1%
Total 100%
100%
100%
100%
100%
Midwest Gas (1)
MMCF Sores (2)
RetailSales 61,578 61,704 62,977 63414 64,502 65,125 1.1%
Transportation Sales 13407 13.960 14.538 15,122 15.706 16,290 4.0%
Total Sales 74.985 75464 77,515 78,736 80,208 81 A15 1.7%
Notes:
(1) Midwest Power Systems has two divisions: Midwest Power (electric) and Midwest Gas (notural gas).
(2) Legislation enacted in lowo in 1990 requires electric and gas utilities to spend 2.0 percent and 1.5 percent, respectively, of their annual revenues on demand-side management progroms. The impact of these programs hos been reflected in the soles forecasts.
(3) The Company hos a long-term power purchase contract with the Nebraska Public Power District for one-half the capacity of the Cooper Nuclear Station. The station went into service in 1974 and has generated significont amounts of energy for the Company since that time.
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Key Assumptions
- Projected 1993 is based on octual results through June 1993 plus estimates for the lost six months of the year.
- Electric peak load growth of 1.5% is forecasted for 1994-1998.
- The forecost assumes the addition of an 80 MW combustion turbine generator at the Pleasant Hill Energy Center in 1994. An application for regulatory approval of the unit was filed in October 1993.
- The forecast reflects the change in Midwest Gas sales due to the exchange of service territories with Minnegosco, which was finalized August 31,1993.
- Rote increases for the period 1994-1998 ore anticipated to be less than the rote of inflation.
- The inflation rate for operoflons and maintenance, excluding fuel,is projected to overage 2.4% per annum.
- Projected 1993 Internal Generation, excluding the $675 million of redeemed debt, would be 65% of Capital Requirements for Midwest Resources and 74% for Midwest Power Systems.
Company Contacts J. Sue Rozemo Maureen E. Moore Treasurer Administrator-Finance (515) 281-2250 (515) 242-4380 Midwest Resources Inc.
666 Grand Avenue P.O. Box 9244 Des Moines,lowo 50306-9244 l
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