UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-9187
IES INDUSTRIES INC.
(Exact name of registrant as specified in its charter)
Iowa 42-1271452
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
IES Tower, Cedar Rapids, Iowa 52401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (319) 398-4411
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 shorter 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 the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Class Outstanding at July 31, 1996
Common Stock, no par value 29,925,030 shares
IES INDUSTRIES INC.
INDEX
Page No.
Part I. Financial Information.
Item 1. Consolidated Financial Statements.
Consolidated Balance Sheets -
June 30, 1996 and December 31, 1995 3 - 4
Consolidated Statements of Income -
Three, Six and Twelve Months Ended
June 30, 1996 and 1995 5
Consolidated Statements of Cash Flows -
Three, Six and Twelve Months Ended
June 30, 1996 and 1995 6
Notes to Consolidated Financial Statements 7 - 22
Item 2. Management's Discussion and Analysis of the
Results of Operations and Financial Condition. 23 - 49
Part II. Other Information. 50 - 53
Signatures. 54
PART 1. - FINANCIAL INFORMATION
ITEM 1. - CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED BALANCE SHEETS
June 30,
1996 December 31,
ASSETS (Unaudited) 1995
(in thousands)
Property, plant and equipment:
Utility -
Plant in service -
Electric $ 1,921,426 $ 1,900,157
Gas 167,760 165,825
Other 109,088 106,396
2,198,274 2,172,378
Less - Accumulated depreciation 996,595 950,324
1,201,679 1,222,054
Leased nuclear fuel, net of amortization 40,532 36,935
Construction work in progress 82,070 52,772
1,324,281 1,311,761
Other, net of accumulated depreciation
and amortization of $62,975,000 and
$53,026,000, respectively 203,173 193,215
1,527,454 1,504,976
Current assets:
Cash and temporary cash investments 14,520 6,942
Accounts receivable -
Customer, less reserve 29,619 37,214
Other 8,788 10,493
Income tax refunds receivable 7,084 982
Production fuel, at average cost 12,821 12,155
Materials and supplies, at average cost 23,968 28,354
Regulatory assets 24,772 22,791
Oil and gas properties held for resale 0 9,843
Prepayments and other 14,138 23,099
135,710 151,873
Investments:
Nuclear decommissioning trust funds 52,084 47,028
Investment in foreign entities 26,845 24,770
Investment in McLeod, Inc. 19,200 9,200
Cash surrender value of life insurance policies 10,521 9,838
Other 4,251 3,897
112,901 94,733
Other assets:
Regulatory assets 211,776 207,202
Deferred charges and other 26,466 26,807
238,242 234,009
$ 2,014,307 $ 1,985,591
CONSOLIDATED BALANCE SHEETS (CONTINUED)
June 30,
1996 December 31,
CAPITALIZATION AND LIABILITIES (Unaudited) 1995
(in thousands)
Capitalization:
Common stock - no par value - authorized
48,000,000 shares; outstanding 29,837,500
and 29,508,415 shares, respectively $ 399,928 $ 391,269
Retained earnings 212,003 221,077
Total common equity 611,931 612,346
Cumulative preferred stock of
IES Utilities Inc. 18,320 18,320
Long-term debt (excluding current portion) 604,469 601,708
1,234,720 1,232,374
Current liabilities:
Short-term borrowings 125,000 101,000
Capital lease obligations 13,883 15,717
Maturities and sinking funds 23,460 15,447
Accounts payable 67,047 80,089
Dividends payable 16,324 16,244
Accrued interest 9,027 8,051
Accrued taxes 47,698 53,983
Accumulated refueling outage provision 12,610 7,690
Adjustment clause balances 2,809 3,148
Environmental liabilities 5,584 5,634
Other 23,518 21,800
346,960 328,803
Long-term liabilities:
Pension and other benefit obligations 57,300 52,677
Capital lease obligations 26,649 21,218
Environmental liabilities 43,400 43,087
Other 11,175 13,039
138,524 130,021
Deferred credits:
Accumulated deferred income taxes 258,310 257,278
Accumulated deferred investment tax credits 35,793 37,115
294,103 294,393
Commitments and contingencies (Note 8)
$ 2,014,307 $ 1,985,591
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
<TABLE>
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
<CAPTION>
For the Three For the Six For the Twelve
Months Ended Months Ended Months Ended
June 30 June 30 June 30
1996 1995 1996 1995 1996 1995
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C> <C>
Operating revenues:
Electric $ 137,032 $ 133,048 $ 262,400 $ 249,626 $ 573,246 $ 539,964
Gas 42,628 32,010 132,651 96,992 225,999 164,388
Other 30,988 24,389 58,793 49,221 109,773 94,572
210,648 189,447 453,844 395,839 909,018 798,924
Operating expenses:
Fuel for production 22,728 20,304 43,021 39,746 99,530 87,050
Purchased power 22,000 17,130 36,469 33,444 69,899 71,412
Gas purchased for resale 31,814 23,067 99,250 72,356 168,610 119,750
Other operating expenses 52,283 45,875 104,808 93,965 212,231 188,714
Maintenance 15,087 11,325 25,920 23,489 48,525 50,504
Depreciation and amortization 27,225 24,923 54,608 50,461 102,104 94,083
Taxes other than income taxes 12,741 13,367 26,004 26,807 48,211 48,037
183,878 155,991 390,080 340,268 749,110 659,550
Operating income 26,770 33,456 63,764 55,571 159,908 139,374
Interest expense and other:
Interest expense 12,934 13,084 25,839 25,047 51,518 48,204
Allowance for funds used
during construction -691 -785 -1,380 -1,900 -2,904 -3,934
Preferred dividend requirements
of IES Utilities Inc. 229 229 457 457 914 914
Miscellaneous, net -696 -170 -2,373 -523 -5,016 -3,150
11,776 12,358 22,543 23,081 44,512 42,034
Income before income taxes 14,994 21,098 41,221 32,490 115,396 97,340
Income taxes:
Current 5,466 5,258 19,576 2,595 51,713 25,079
Deferred 2,133 4,004 817 11,992 -732 14,863
Amortization of investment tax credits -661 -672 -1,323 -1,345 -2,663 -2,669
6,938 8,590 19,070 13,242 48,318 37,273
Net income $ 8,056 $ 12,508 $ 22,151 $ 19,248 $ 67,078 $ 60,067
Average number of common
shares outstanding 29,801 29,128 29,723 29,008 29,560 28,853
Earnings per average
common share $ 0.27 $ 0.43 $ 0.75 $ 0.66 $ 2.27 $ 2.08
Dividends declared per
common share $ 0.525 $ 0.525 $ 1.05 $ 1.05 $ 2.10 $ 2.10
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</TABLE>
<TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
<CAPTION>
For the Three For the Six For the Twelve
Months Ended Months Ended Months Ended
June 30 June 30 June 30
1996 1995 1996 1995 1996 1995
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income $ 8,056 $ 12,508 $ 22,151 $ 19,248 $ 67,078 $ 60,067
Adjustments to reconcile net income to
net cash flows from operating activities -
Depreciation and amortization 27,225 24,923 54,608 50,461 102,104 94,083
Amortization of principal under
capital lease obligations 4,626 3,311 9,250 5,867 19,096 13,608
Deferred taxes and investment tax credits 1,472 3,332 -506 10,647 -3,395 12,194
Refueling outage provision 2,373 -4,432 4,920 -12,960 10,374 -6,475
Amortization of other assets 2,194 1,587 5,104 2,643 9,853 3,776
Other 285 121 1,390 898 1,223 672
Other changes in assets and liabilities -
Accounts receivable 9,431 8,324 2,300 6,157 -19,078 775
Production fuel, materials and supplies -396 -2,017 484 -831 5,365 -3,723
Accounts payable -1,554 -13,600 -10,175 -15,795 8,523 12,099
Accrued taxes -28,680 -8,194 -12,387 -2,838 -115 -813
Provision for rate refunds -229 2,207 -63 10,207 -10,164 10,207
Adjustment clause balances -3,726 -2,325 -339 1,910 2,332 -2,599
Gas in storage 1,501 1,948 9,245 10,140 2,350 2,566
Other 3,888 -2,608 4,662 3,080 2,020 13,476
Net cash flows from operating activities 26,466 25,085 90,644 88,834 197,566 209,913
Cash flows from financing activities:
Dividends declared on common stock -15,643 -15,316 -31,225 -30,499 -62,117 -60,648
Proceeds from issuance of common stock 3,673 3,355 7,399 8,001 15,014 14,534
Purchase of treasury stock -269 0 -269 0 -269 0
Net change in IES Diversified Inc. credit
facility 11,965 -10,725 10,970 -20,700 75,415 -6,200
Proceeds from issuance of other long-term debt 0 4 0 50,004 50,003 60,004
Reductions in other long-term debt -217 -208 -296 -50,280 -50,440 -58,117
Net change in short-term borrowings 33,000 59,000 24,000 50,000 38,000 83,700
Principal payments under capital lease
obligations -4,624 -2,556 -9,536 -6,218 -17,781 -14,375
Sale of utility accounts receivable 7,000 -8,000 7,000 2,000 9,000 3,000
Other -22 134 -91 222 -1,669 118
Net cash flows from financing activities 34,863 25,688 7,952 2,530 55,156 22,016
Cash flows from investing activities:
Construction and acquisition expenditures -
Utility -34,000 -31,551 -57,333 -59,576 -125,292 -151,855
Other -18,456 -9,834 -33,815 -17,500 -106,879 -60,792
Oil and gas properties held for resale 0 0 9,843 0 0 0
Deferred energy efficiency expenditures -5,090 -4,441 -8,757 -7,978 -18,808 -16,964
Nuclear decommissioning trust funds -1,502 -1,383 -3,004 -2,766 -6,338 -5,532
Proceeds from disposition of assets 652 3,095 1,856 6,055 10,034 12,254
Other 1,152 -2,102 192 -5,193 -318 -2,224
Net cash flows from investing activities -57,244 -46,216 -91,018 -86,958 -247,601 -225,113
Net increase in cash and temporary
cash investments 4,085 4,557 7,578 4,406 5,121 6,816
Cash and temporary cash investments
at beginning of period 10,435 4,842 6,942 4,993 9,399 2,583
Cash and temporary cash investments
at end of period $ 14,520 $ 9,399 $ 14,520 $ 9,399 $ 14,520 $ 9,399
Supplemental cash flow information:
Cash paid during the period for -
Interest $ 12,992 $ 15,172 $ 23,535 $ 24,973 $ 49,440 $ 46,435
Income taxes $ 24,277 $ 5,615 $ 32,748 $ 8,349 $ 50,877 $ 28,650
Noncash investing and financing activities -
Capital lease obligations incurred $ 10,243 $ 1,542 $ 12,846 $ 2,658 $ 13,106 $ 16,531
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
June 30, 1996
(1) GENERAL:
The interim Consolidated Financial Statements have been prepared by
IES Industries Inc. (Industries) and its consolidated subsidiaries
(collectively the Company), without audit, pursuant to the rules and
regulations of the United States Securities and Exchange Commission
(SEC). Industries' wholly-owned subsidiaries are IES Utilities Inc.
(Utilities) and IES Diversified Inc. (Diversified). Industries is an
investor-owned holding company whose primary operating company,
Utilities, is engaged principally in the generation, transmission,
distribution and sale of electric energy and the purchase, distribution,
transportation and sale of natural gas. The Company's principal markets
are located in the state of Iowa. The Company also has various non-
utility subsidiaries which are primarily engaged in the energy-related,
transportation and real estate development businesses.
Certain information and footnote disclosures normally included in
financial statements prepared in accordance with generally accepted
accounting principles have been condensed or omitted pursuant to such
rules and regulations, although the Company believes that the
disclosures are adequate to make the information presented not
misleading. In the opinion of the Company, the Consolidated Financial
Statements include all adjustments, which are normal and recurring in
nature, necessary for the fair presentation of the results of operations
and financial position. Certain prior period amounts have been
reclassified on a basis consistent with the 1996 presentation.
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make
estimates and assumptions that affect: 1) the reported amounts of assets
and liabilities and the disclosure of contingent assets and liabilities
at the date of the financial statements, and 2) the reported amounts of
revenues and expenses during the reporting period. Actual results could
differ from those estimates.
It is suggested that these Consolidated Financial Statements be
read in conjunction with the Consolidated Financial Statements and the
notes thereto included in the Company's Form 10-K for the year ended
December 31, 1995, as amended on Form 10-K/A. The accounting and
financial policies relative to the following items have been described
in those notes and have been omitted herein because they have not
changed materially through the date of this report:
Summary of significant accounting policies
Leases
Utility accounts receivable (other than discussed in Note 4)
Income taxes
Benefit plans
Common, preferred and preference stock
Debt (other than discussed in Notes 6 and 7)
Estimated fair value of financial instruments
Commitments and contingencies (other than discussed in Note 8)
Jointly-owned electric utility plant
Segments of business
(2) POTENTIAL BUSINESS COMBINATIONS:
(a) Proposed Merger of Industries -
Industries, WPL Holdings, Inc. (WPLH) and Interstate Power Company
(IPC) have entered into an Agreement and Plan of Merger (Merger
Agreement), dated November 10, 1995, as amended, providing for: a) IPC
becoming a wholly-owned subsidiary of WPLH, and b) the merger of
Industries with and into WPLH, which merger will result in the
combination of Industries and WPLH as a single holding company
(collectively, the Proposed Merger). The new holding company will be
named Interstate Energy Corporation (Interstate Energy), and Industries
will cease to exist. Each holder of Company common stock will receive
1.01 shares of Interstate Energy common stock for each share of Company
common stock. The Proposed Merger, which will be accounted for as a
pooling of interests, has been approved by the respective Boards of
Directors. It is still subject to approval by the shareholders of each
company as well as several federal and state regulatory agencies. The
companies mailed the joint proxy statement to their shareholders the
week of July 23, 1996. The companies expect to receive the shareholder
approvals in the third quarter of 1996 and regulatory approvals by the
summer of 1997. The corporate headquarters of Interstate Energy will be
in Madison, Wisconsin.
The business of Interstate Energy will consist of utility
operations and various non-utility enterprises. The utility
subsidiaries currently serve approximately 870,000 electric customers
and 360,000 natural gas customers in Iowa, Wisconsin, Illinois and
Minnesota.
(b) Unsolicited Acquisition Proposal -
On August 5, 1996, MidAmerican Energy Company (MAEC), an electric
and natural gas utility company based in Des Moines, Iowa, announced
that it had made an unsolicited offer to acquire the Company in a cash
and stock transaction. Under the terms of the offer, the Company would
merge with and into MAEC in a transaction in which the Company
shareholders would receive up to 40% in cash and the remainder in shares
of MAEC common stock. Company shareholders receiving cash would receive
$39 for each Company share and shareholders receiving shares would
receive 2.346 shares of MAEC stock for each Company share. On August
12, 1996, the closing price for MAEC stock on the NYSE was $15.75 per
share. MAEC has stated that, if the Company and MAEC do not promptly
reach agreement with respect to a business combination between the two
companies, MAEC will solicit proxies against the Proposed Merger for use
at the upcoming Company shareholder meeting.
Pursuant to the Merger Agreement, in the event that the Merger Agreement
is terminated under circumstances in which there is an outstanding tender
offer for the Company's common stock, or a proposal for a Business
Combination (as defined in the Merger Agreement), and within two and one
half years after such termination such a transaction is consummated, the
Company would be obligated to pay WPLH and IPC an aggregate fee of $25
million, provided that in the event that WPLH or IPC or both exercises
options granted pursuant to the Stock Option Agreements delivered to them
in connection with the Merger Agreement and a cash payment is required in
connection with such exercise, the aggregate amount payable by the Company
under the Merger Agreement and the Stock Option Agreements will not exceed
$40 million.
The Company cannot currently determine what, if any, impact the
unsolicited offer of MAEC may have on the Proposed Merger. The
proposal will be given full consideration by the Company's Board of
Directors.
(3) RATE MATTERS:
(a) 1995 Gas Rate Case -
On August 4, 1995, Utilities applied to the Iowa Utilities Board
(IUB) for an annual increase in gas rates of $8.8 million, or 6.2%. An
interim increase of $8.6 million was requested and the IUB,
subsequently, approved an interim increase of $7.1 million annually,
effective October 11, 1995, subject to refund. On April 4, 1996, the
IUB issued an order approving a settlement agreement entered into by
Utilities, the Office of Consumer Advocate and all three industrial
intervenor groups, which allows Utilities a $6.3 million annual
increase. Utilities subsequently filed final compliance tariffs which
became effective on May 30, 1996. Primarily because of changes in rate
design, there is a refund obligation of approximately $43,000 which will
be made in the third quarter of 1996.
(b) Electric Price Announcements -
Utilities and its Iowa-based proposed merger partner, IPC,
announced in April their intentions to hold retail electric prices to
their current levels until at least January 1, 2000. The companies made
the proposal as part of their testimony in the merger-related
application filed with the IUB, which was later withdrawn and will be
resubmitted at a future date. (The companies intend to include the same
proposal in the resubmittal of the filing.) The companies did specify
that the proposal excludes price changes due to government-mandated
programs, such as energy efficiency cost recovery, or unforeseen
dramatic changes in operations.
Utilities, Wisconsin Power and Light Company (the utility
subsidiary of WPLH) and IPC also agreed to freeze their wholesale
electric prices for four years from the effective date of the merger as
part of their merger filing with the Federal Energy Regulatory
Commission (FERC). The Company does not expect the merger-related
electric price proposals to have a material adverse effect on its
financial position or results of operations.
(c) Energy Efficiency Cost Recovery -
Current IUB rules mandate Utilities to spend 2% of electric and
1.5% of gas gross retail operating revenues for energy efficiency
programs. Under provisions of the IUB rules, Utilities is currently
recovering the energy efficiency costs incurred through 1993 for such
programs, including its direct expenditures, carrying costs, a return on
its expenditures and a reward. Recovery of the costs will be over a
four-year period and began on June 1, 1995. In October 1996, under
provisions of the IUB rules, the Company will file for recovery of the
costs relating to its 1994 and 1995 programs ($31.9 million as of June
30, 1996).
Iowa statutory changes enacted recently have eliminated both: 1)
the 2% and 1.5% spending requirements described above in favor of IUB-
determined energy savings targets and 2) the delay in recovery of energy
efficiency costs by allowing recovery which is concurrent with spending.
This will eventually eliminate the regulatory asset which exists under
the current rate making mechanism.
(4) UTILITY ACCOUNTS RECEIVABLE:
Utilities has entered into an agreement, which expires in 1999,
with a financial institution to sell, with limited recourse, an
undivided fractional interest of up to $65 million in its pool of
utility accounts receivable. At June 30, 1996, $65 million was sold
under the agreement.
(5) INVESTMENTS:
(a) Foreign Entities -
At June 30, 1996, the Company had $26.8 million of investments in
foreign entities on its Consolidated Balance Sheet that included: 1)
investments in two New Zealand electric distribution entities, 2) a loan
to a New Zealand company and 3) an investment in an international
venture capital fund. The Company accounts for these investments under
the cost method. The Company anticipates making additional investments
in foreign entities in 1996 as is noted in the Construction and
Acquisition Program section of Management's Discussion and Analysis.
(b) McLeod, Inc. -
At June 30, 1996, the Company had a $10.0 million investment in
Class A common stock of McLeod, Inc., a $9.2 million investment in Class
B common stock and vested options that, if exercised, would represent an
additional investment of approximately $2.3 million. McLeod provides
local and long-distance telecommunications services to business
customers and other services related to fiber optics.
In June 1996, McLeod completed an Initial Public Offering (IPO) of
its Class A common stock. As of June 30, 1996, the Company is the
beneficial owner of approximately 10.2 million total shares on a fully
diluted basis. Class B shares are convertible at the option of the
Company into Class A shares at any time on a one-for-one basis. The
rights of McLeod Class A common stock and Class B common stock are
substantially identical except that Class A common stock has 1 vote per
share and Class B common stock has 0.40 votes per share. The Company
currently accounts for this investment under the cost method.
The Company has entered into an agreement with McLeod which
provides that for two years commencing on June 10, 1996, the Company
cannot sell or otherwise dispose of any of its securities of McLeod
without the consent of the McLeod Board of Directors. Also, under
certain SEC rules, the Company may be subject to certain restrictions
with respect to the sale of McLeod shares for a period of time. These
contractual and SEC sale restrictions result in restricted stock under
the provisions of Statement of Financial Accounting Standards No. 115
(SFAS No. 115), Accounting for Certain Investments in Debt and Equity
Securities, until such time as the restrictions lapse and such shares
became qualified for sale within a one year period. As a result, the
Company currently carries this investment at cost.
Under the provisions of SFAS No. 115, the carrying value of the
McLeod investment will be adjusted to estimated fair value at the time
such shares are not considered to be restricted stock. Under the SEC
rules, it is possible that the shares will become unrestricted over time
rather than all at once. Therefore, adjustments to market value under
the provisions of SFAS No. 115 would only be recorded for the portion of
shares held that are no longer deemed to be restricted. Any such
adjustments to reflect the estimated fair value of this investment would
be reflected as an increase in the investment carrying value with the
unrealized gain reported as a net of tax amount in other common
shareholders equity until realized (i.e. sold by the Company).
The closing price of the McLeod Class A common stock on June 30,
1996, on the Nasdaq National Market, was $24.00 per
share. The current market value of the shares the Company beneficially
owns (approximately 10.2 million shares) is currently impacted by, among
other things, the fact that the shares cannot be sold for a period of
time and it is not possible to estimate what the market value of the
shares will be at the point in time such sale restrictions are lifted.
In addition, any gain upon an eventual sale of this investment would
likely be subject to a tax.
(6) DEBT:
(a) Long-Term Debt -
Diversified has a variable rate credit facility that extends
through November 9, 1998, with a one-year extension available to
Diversified. The facility also serves as a stand-by agreement for
Diversified's commercial paper program. The agreement provides for a
combined maximum of $150 million of borrowings under the agreement and
commercial paper to be outstanding at any one time. Interest rates and
maturities are set at the time of borrowing for direct borrowings under
the agreement and for issuances of commercial paper. The interest rate
options are based upon quoted market rates and the maturities are less
than one year. At June 30, 1996, there were no borrowings outstanding
under this facility. Diversified had $135.2 million of commercial paper
outstanding at June 30, 1996, with interest rates ranging from 5.52% to
5.85% and maturity dates in the third quarter of 1996. Diversified
intends to continue borrowing under the renewal options of the facility
and no conditions exist at June 30, 1996, that would prevent such
borrowings. Accordingly, this debt is classified as long-term in the
Consolidated Balance Sheets. Refer to Note 7 for a discussion of an
interest rate swap agreement Diversified entered into relating to the
credit facility.
Diversified had an agreement whereby it would guarantee $6 million
under a credit facility between McLeod and its bankers. Diversified was
paid an annual commitment fee and received options to purchase
additional shares of Class B common stock for as long as the guarantee
remained outstanding. This agreement was canceled by McLeod after the
completion of their IPO. Refer to Note 5(b) for a further discussion of
the Company's investment in McLeod.
(b) Short-Term Debt -
At June 30, 1996, the Company had bank lines of credit aggregating
$126.1 million (Industries - $1.5 million, Utilities - $121.1 million,
Diversified - $2.5 million and Whiting Petroleum Corporation (Whiting) -
$1.0 million). Utilities was using $108 million to support commercial
paper (weighted average interest rate of 5.40%) and $11.1 million to
support certain pollution control obligations. Commitment fees are paid
to maintain these lines and there are no conditions which restrict the
unused lines of credit. In addition to the above, Utilities has an
uncommitted credit facility with a financial institution whereby it can
borrow up to $40 million. Rates are set at the time of borrowing and no
fees are paid to maintain this facility. At June 30, 1996, there was
$17 million outstanding under this facility (weighted average interest
rate of 5.57%).
(7) INTEREST RATE SWAP AGREEMENT:
In February 1996, Diversified entered into an interest rate swap
agreement in order to fix the interest rate on $100 million of its
borrowings under the variable rate credit facility. Under the
agreement, Diversified will pay the counterparty interest at a fixed
rate of 4.705 percent and the counterparty will pay Diversified interest
at a rate based on the one month floating London Interbank Offered Rate
(LIBOR). The swap period is for two years with an additional one-year
option available to the counterparty and the agreement includes
quarterly settlement dates. Amounts to be paid or received under the
interest rate swap agreement are accrued as interest rates change and
are recognized over the life of the swap agreement as adjustments to
interest expense. The fair value of this financial instrument is based
on the amounts estimated to terminate or settle the agreement. At June
30, 1996, the agreement, if settled on that date, would have required
the counterparty to pay the Company approximately $2.2 million. Such
value is based on the difference in the fixed and LIBOR interest rates
as well as the amount of time remaining in the agreement. The Company
has no intention of terminating the agreement at this time.
(8) CONTINGENCIES:
(a) Environmental Liabilities -
The Company has recorded environmental liabilities of approximately
$49.0 million in its Consolidated Balance Sheets at June 30, 1996. The
significant items are discussed below.
Former Manufactured Gas Plant (FMGP) Sites
Utilities has been named as a Potentially Responsible Party (PRP)
by various federal and state environmental agencies for 28 FMGP sites,
but believes it is not responsible for two of these sites based on
extensive reviews of the ownership records and historical information
available for the two sites. Utilities has notified the appropriate
regulatory agency that it believes it does not have any responsibility
as relates to these two sites, but no response has been received from
the agency on this issue. Utilities is also aware of six other sites
that it may have owned or operated in the past and for which, as a
result, it may be designated as a PRP in the future in the event that
environmental concerns arise at these sites. Utilities is working
pursuant to the requirements of the various agencies to investigate,
mitigate, prevent and remediate, where necessary, damage to property,
including damage to natural resources, at and around the sites in order
to protect public health and the environment. Utilities believes it has
completed the remediation of seven sites although it is in the process
of obtaining final approval from the applicable environmental agencies
on this issue for each site. Utilities is in various stages of the
investigation and/or remediation processes for the remaining 19 sites
and estimates the range of additional costs to be incurred for
investigation and/or remediation of the sites to be approximately $24
million to $57 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $35 million (including $4.6 million as
current liabilities) at June 30, 1996. These amounts are based upon
Utilities' best current estimate of the amount to be incurred for
investigation and remediation costs for those sites where the
investigation process has been or is substantially completed, and the
minimum of the estimated cost range for those sites where the
investigation is in its earlier stages. It is possible that future cost
estimates will be greater than the current estimates as the
investigation process proceeds and as additional facts become known; in
addition, Utilities may be required to monitor these sites for a number
of years upon completion of remediation, as is the case with several of
the sites for which remediation has been completed.
In April 1996, Utilities filed a lawsuit against certain of its
insurance carriers seeking reimbursement for investigation, mitigation,
prevention, remediation and monitoring costs associated with the FMGP
sites. Settlement discussions are proceeding between Utilities and its
insurance carriers regarding the recovery of these FMGP-related costs.
The amount of aggregate potential recovery, or the regulatory treatment
of any such recoveries, cannot be reasonably determined at this time
and, accordingly, no estimated amounts have been recorded at June
30, 1996. Regulatory assets of approximately $35 million, which reflect
the future recovery that is being provided through Utilities' rates,
have been recorded in the Consolidated Balance Sheets. Considering the
current rate treatment allowed by the IUB, management believes that the
clean-up costs incurred by Utilities for these FMGP sites will not have
a material adverse effect on its financial position or results of
operations.
National Energy Policy Act of 1992
The National Energy Policy Act of 1992 requires owners of nuclear
power plants to pay a special assessment into a "Uranium Enrichment
Decontamination and Decommissioning Fund." The assessment is based upon
prior nuclear fuel purchases and, for the Duane Arnold Energy Center
(DAEC), averages $1.4 million annually through 2007, of which Utilities'
70% share is $1.0 million. Utilities is recovering the costs associated
with this assessment through its electric fuel adjustment clauses over
the period the costs are assessed. Utilities' 70% share of the future
assessment, $10.9 million payable through 2007, has been recorded as a
liability in the Consolidated Balance Sheets, including $0.8 million
included in "Current liabilities - Environmental liabilities," with a
related regulatory asset for the unrecovered amount.
Oil and Gas Properties Dismantlement and Abandonment Costs
Whiting is responsible for certain dismantlement and abandonment
costs related to various off-shore oil and gas properties, the most
significant of which is located off the coast of California. Whiting
accrues these costs as reserves are extracted and such costs are
included in "Depreciation and amortization" in the Consolidated
Statements of Income. A corresponding environmental liability, $2.6
million at June 30, 1996, has been recognized in the Consolidated
Balance Sheets for the cumulative amount expensed.
(b) Air Quality Issues -
The Clean Air Act Amendments of 1990 (Act) requires emission
reductions of sulfur dioxide (SO2) and nitrogen oxides (NOx) to achieve
reductions of atmospheric chemicals believed to cause acid rain. The
provisions of the Act are being implemented in two phases; the Phase I
requirements have been met and the Phase II requirements affect eleven
other fossil units beginning in the year 2000. Utilities expects to
meet the requirements of Phase II by switching to lower sulfur fuels,
capital expenditures primarily related to fuel burning equipment and
boiler modifications, and the possible purchase of SO2 allowances.
Utilities estimates capital expenditures at approximately $20 million,
including $4 million in 1996, in order to meet the acid rain
requirements of the Act.
The acid rain program under the Act also governs SO2 allowances.
An allowance is defined as an authorization for an owner to emit one ton
of SO2 into the atmosphere. Currently, Utilities receives a sufficient
number of allowances annually to offset its emissions of SO2 from its
Phase I units. It is anticipated that in the year 2000, Utilities may
have an insufficient number of allowances annually to offset its
estimated emissions and may have to purchase additional allowances, or
make modifications to the plants or limit operations to reduce
emissions. Utilities is reviewing its options to ensure that it will
have sufficient allowances to offset its emissions in the future.
Utilities believes that the potential cost of ensuring sufficient
allowances will not have a material adverse effect on its financial
position or results of operations.
The Act and other federal laws also require the United States
Environmental Protection Agency (EPA) to study and regulate, if
necessary, additional issues that potentially affect the electric
utility industry, including emissions relating to NOx, ozone transport,
mercury and particulate control; toxic release inventories and
modifications to the PCB rules. Currently, the impacts of these
potential regulations are too speculative to quantify.
In 1995, the EPA published the Sulfur Dioxide Network Design Review
for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-
case modeling method suggests that the Cedar Rapids area could be
classified as "nonattainment" for the National Ambient Air Quality
Standard (NAAQS) established for SO2. The worst-case modeling study
suggested that two of Utilities' generating facilities contribute to the
modeled exceedences and recommended that additional monitors be located
near Utilities' sources to assess actual ambient air quality. In the
event that Utilities' facilities contribute excessive emissions,
Utilities would be required to reduce emissions, which would primarily
entail capital expenditures for modifications to the facilities.
Utilities is planning to convert one of its fossil generating facilities
to a natural gas-fired cogeneration facility. Such facility was
contributing to the modeled exceedences thus the conversion will have
the added inherent benefit of reducing SO2 emissions. Utilities is
proposing to resolve the remainder of EPA's nonattainment concerns by
installing a new stack at the other generating facility contributing to
the modeled exceedences at a potential capital cost of up to $4.5
million over the next four years.
(c) FERC Order No. 636 -
Pursuant to FERC Order No. 636 (Order 636), which transitions the
natural gas supply business to a less regulated environment, Utilities
has enhanced access to competitively priced gas supply and more flexible
transportation services. However, under Order 636, Utilities is
required to pay certain transition costs incurred and billed by its
pipeline suppliers.
Utilities began paying the transition costs in 1993 and at June 30,
1996, has recorded a liability of $4.2 million for those transition
costs that have been incurred, but not yet billed, by the pipelines to
date, including $1.9 million expected to be billed through June 1997.
Utilities is currently recovering the transition costs from its
customers through its Purchased Gas Adjustment Clauses as such costs are
billed by the pipelines. Transition costs, in addition to the recorded
liability, that may ultimately be charged to Utilities could approximate
$4.6 million. The ultimate level of costs to be billed to Utilities
depends on the pipelines' future filings with the FERC and other future
events, including the market price of natural gas. However, Utilities
believes any transition costs that the FERC would allow the pipelines to
collect from Utilities would be recovered from its customers, based upon
regulatory treatment of these costs currently and similar past costs by
the IUB. Accordingly, regulatory assets, in amounts corresponding to
the recorded liabilities, have been recorded to reflect the anticipated
recovery.
(d) Nuclear Insurance Programs -
Public liability for nuclear accidents is governed by the Price
Anderson Act of 1988 which sets a statutory limit of $8.9 billion for
liability to the public for a single nuclear power plant incident and
requires nuclear power plant operators to provide financial protection
for this amount. As required, Utilities provides this financial
protection for a nuclear incident at the DAEC through a combination of
liability insurance ($200 million) and industry-wide retrospective
payment plans ($8.7 billion). Under the industry-wide plan, each
operating licensed nuclear reactor in the United States is subject to an
assessment in the event of a nuclear incident at any nuclear plant in
the United States. Based on its ownership of the DAEC, Utilities could
be assessed a maximum of $79.3 million per nuclear incident, with a
maximum of $10 million per incident per year (of which Utilities' 70%
ownership portion would be approximately $55 million and $7 million,
respectively) if losses relating to the incident exceeded $200 million.
These limits are subject to adjustments for changes in the number of
participants and inflation in future years.
Utilities is a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL). These companies provide $1.9 billion
of insurance coverage on certain property losses at DAEC for property
damage, decontamination and premature decommissioning. The proceeds
from such insurance, however, must first be used for reactor
stabilization and site decontamination before they can be used for plant
repair and premature decommissioning. NEIL also provides separate
coverage for the cost of replacement power during certain outages.
Owners of nuclear generating stations insured through NML and NEIL are
subject to retroactive premium adjustments if losses exceed accumulated
reserve funds. NML and NEIL's accumulated reserve funds are currently
sufficient to more than cover its exposure in the event of a single
incident under the primary and excess property damage or replacement
power coverages. However, Utilities could be assessed annually a maximum
of $3.0 million under NML, $9.8 million for NEIL property and $0.7
million for NEIL replacement power if losses exceed the accumulated
reserve funds. Utilities is not aware of any losses that it believes
are likely to result in an assessment.
In the unlikely event of a catastrophic loss at DAEC, the amount of
insurance available may not be adequate to cover property damage,
decontamination and premature decommissioning. Uninsured losses, to the
extent not recovered through rates, would be borne by Utilities and
could have a material adverse effect on Utilities' financial position
and results of operations.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF THE RESULTS OF OPERATIONS AND FINANCIAL CONDITION
The Consolidated Financial Statements include the accounts of IES
Industries Inc. (Industries) and its consolidated subsidiaries
(collectively the Company). Industries' wholly-owned subsidiaries are
IES Utilities Inc. (Utilities) and IES Diversified Inc. (Diversified).
POTENTIAL BUSINESS COMBINATIONS
(a) Proposed Merger of Industries -
Industries, WPL Holdings, Inc. (WPLH) and Interstate Power Company
(IPC) have entered into an Agreement and Plan of Merger (Merger
Agreement), dated November 10, 1995, as amended, providing for: a) IPC
becoming a wholly-owned subsidiary of WPLH, and b) the merger of
Industries with and into WPLH, which merger will result in the
combination of Industries and WPLH as a single holding company
(collectively, the Proposed Merger). The new holding company will be
named Interstate Energy Corporation (Interstate Energy), and Industries
will cease to exist. Each holder of Company common stock will receive
1.01 shares of Interstate Energy common stock for each share of Company
common stock. The Proposed Merger, which will be accounted for as a
pooling of interests, has been approved by the respective Boards of
Directors. It is still subject to approval by the shareholders of each
company as well as several federal and state regulatory agencies. The
companies mailed the joint proxy statement to their shareholders the
week of July 23, 1996. The companies expect to receive the shareholder
approvals in the third quarter of 1996 and regulatory approvals by the
summer of 1997. The corporate headquarters of Interstate Energy will be
in Madison, Wisconsin.
The business of Interstate Energy will consist of utility
operations and various non-utility enterprises. The utility
subsidiaries currently serve approximately 870,000 electric customers
and 360,000 natural gas customers in Iowa, Wisconsin, Illinois and
Minnesota.
(b) Unsolicited Acquisition Proposal -
On August 5, 1996, MidAmerican Energy Company (MAEC), an electric
and natural gas utility company based in Des Moines, Iowa, announced
that it had made an unsolicited offer to acquire the Company in a cash
and stock transaction. Under the terms of the offer, the Company would
merge with and into MAEC in a transaction in which the Company
shareholders would receive up to 40% in cash and the remainder in shares
of MAEC common stock. Company shareholders receiving cash would receive
$39 for each Company share and shareholders receiving shares would
receive 2.346 shares of MAEC stock for each Company share. On August
12, 1996, the closing price for MAEC stock on the NYSE was $15.75 per
share. MAEC has stated that, if the Company and MAEC do not promptly
reach agreement with respect to a business combination between the two
companies, MAEC will solicit proxies against the Proposed Merger for use
at the upcoming Company shareholder meeting.
Pursuant to the Merger Agreement, in the event that the Merger Agreement
is terminated under circumstances in which there is an outstanding tender
offer for the Company's common stock, or a proposal for a Business
Combination (as defined in the Merger Agreement), and within two and one
half years after such termination such a transaction is consummated, the
Company would be obligated to pay WPLH and IPC an aggregate fee of $25
million, provided that in the event that WPLH or IPC or both exercises
options granted pursuant to the Stock Option Agreements delivered to them
in connection with the Merger Agreement and a cash payment is required in
connection with such exercise, the aggregate amount payable by the Company
under the Merger Agreement and the Stock Option Agreements will not exceed
$40 million.
The Company cannot currently determine what, if any, impact the
unsolicited offer of MAEC may have on the Proposed Merger. The
proposal will be given full consideration by the Company's Board of
Directors.
RESULTS OF OPERATIONS
The following discussion analyzes significant changes in the
components of net income and financial condition from the prior periods
for the Company:
The Company's net income increased or (decreased) ($4.5) million,
$2.9 million and $7.0 million during the three, six and twelve month
periods, respectively. Earnings per average common share increased or
(decreased) ($0.16), $0.09 and $0.19 for the respective periods. The
three month period decrease was primarily due to increased operating
expenses. The increase in earnings for the six month period was
primarily due to increased electric and gas sales, the impact of a
natural gas pricing increase implemented in the fourth quarter of 1995
and a reserve for electric rate refund recorded in the first quarter of
1995 which included $3.5 million relating to revenues collected in 1994.
The twelve month increase was primarily due to increased electric and
gas sales, the natural gas pricing increase and lower purchased power
capacity costs, partially offset by lower electric prices. Increased
operating expenses also partially offset the six and twelve month
increases in earnings. All three periods benefited from an increase in
earnings at the Company's oil and gas subsidiary, Whiting Petroleum
Corporation (Whiting), resulting from increases in oil and gas prices
and increased volumes sold.
The Company's operating income increased or (decreased) ($6.7)
million, $8.2 million and $20.5 million during the three, six and twelve
month periods, respectively. Reasons for the changes in the results of
operations are explained in the following discussion.
Electric Revenues Electric revenues and Kwh sales (before off-system
sales) for Utilities increased or (decreased) as compared with the prior
year as follows:
Changes vs. Prior Period
Three Six Twelve
Months Months Months
($ in millions)
Total electric revenues $ 4.0 $ 12.8 $ 33.3
Off-system sales revenues 3.5 4.1 6.2
Electric revenues (excluding off-system sales) $ 0.5 $ 8.7 $ 27.1
Electric sales (excluding off-system sales):
Residential and Rural 1.4% 3.8% 9.7%
General Service (5.3) (0.2) 4.7
Large General Service (0.1) 2.5 4.1
Total (0.4) 2.6 5.1
Weather had a significant impact on sales during the six and twelve
month periods. The largest effect of weather for the periods was on
sales to residential and rural customers. Under historically normal
weather conditions, total sales (excluding off-system sales) during the
three, six and twelve month periods would have increased or (decreased)
(0.5%), 1.5% and 1.7%, respectively. The sales comparisons for all
three periods were impacted by a true-up adjustment to Utilities'
unbilled sales recorded in the second quarter of 1995. The sales
increases to the large general service customers (which are not
significantly impacted by weather) during the six and twelve month
periods reflect the underlying strength of the economy as industrial
expansions in Utilities' service territory continued during these
periods.
Utilities' electric tariffs include energy adjustment clauses (EAC)
that are designed to currently recover the costs of fuel and the energy
portion of purchased power billings to customers.
The increase in the electric revenues during all periods was
primarily due to increased sales (excluding the impact of the 1995 true-
up adjustment to unbilled sales), the recovery of expenditures for
energy efficiency programs pursuant to an Iowa Utilities Board (IUB)
order and higher fuel costs collected through the EAC. The impact of
these items was partially offset by the 1995 unbilled revenue
adjustment. The twelve month period increase was also partially offset
by lower electric prices resulting from the IUB price reduction order
received in 1995.
Refer to note 3(b) of the Notes to Consolidated Financial
Statements for a discussion of merger-related retail and wholesale
electric price proposals that Utilities has announced.
Gas Revenues Gas revenues and sales increased or (decreased) for the
periods ended June 30, 1996, as compared with the prior periods, as
follows:
Changes vs. Prior Period
Three Six Twelve
Months Months Months
($ in millions)
Gas revenues:
Utilities $ 0.6 $ 16.7 $ 28.2
Industrial Energy Applications, Inc. (IEA) 10.0 19.0 33.4
$ 10.6 $ 35.7 $ 61.6
Utilities' gas sales:
Residential 1.8% 14.0% 16.5%
Commercial (0.3) 11.5 13.4
Industrial 18.4 4.9 (9.3)
Sales to consumers 3.0 12.4 12.2
Transported volumes (5.2) (1.8) 5.4
Total (0.1) 8.9 10.4
Under historically normal weather conditions, Utilities' gas sales
and transported volumes would have increased or (decreased) (0.8%), 2.9%
and 3.5% during the three, six and twelve month periods, respectively.
Utilities' gas tariffs include purchased gas adjustment clauses
(PGA) that are designed to currently recover the cost of gas sold.
On August 4, 1995, Utilities applied to the IUB for an annual
increase in gas rates of $8.8 million, or 6.2%. An interim increase of
$8.6 million was requested and the IUB, subsequently, approved an
interim increase of $7.1 million annually, effective October 11, 1995,
subject to refund. On April 4, 1996, the IUB issued an order approving
a settlement agreement entered into by Utilities, the Office of Consumer
Advocate and all three industrial intervenor groups, which allows
Utilities a $6.3 million annual increase. Utilities subsequently filed
final compliance tariffs which became effective on May 30, 1996.
Primarily because of changes in rate design, there is a refund
obligation of approximately $43,000 which will be made in the third
quarter of 1996.
Utilities' gas revenues increased during both the six and twelve
month periods primarily because of higher gas costs recovered through
the PGA, the gas pricing increase, recovery of expenditures for the
energy efficiency programs and increased sales to ultimate consumers
(largely on account of the weather).
The increase in IEA's gas revenues during all periods was due to
higher unit gas costs and an increase in gas volumes sold of 44%, 31%
and 57%, respectively. The increase in gas volumes sold for all periods
was due to heightened marketing efforts as well as expanding into
additional regional markets. IEA, which is based in Cedar Rapids, IA,
opened branch offices in Phoenix, Denver, St. Louis and Atlanta in 1995.
Other Revenues Other revenues increased $6.6 million, $9.6 million and
$15.2 million during the three, six and twelve month periods,
respectively, primarily because of increased revenues at Whiting due to
increases in oil and gas prices and increases in volumes sold as a
result of continued acquisitions of oil and gas properties during the
last several years. These increases were partially offset as the result
of the sale or dissolution of several of Diversified's subsidiaries
during 1994 and 1995. The operations of such subsidiaries were not
significant to the results of operations or financial position of the
Company. An increase in Utilities' steam revenues, primarily due to new
industrial customers, also contributed to the increase for all periods.
Operating Expenses Fuel for production increased $2.4 million, $3.3
million and $12.5 million during the three, six and twelve month
periods, respectively. The three month increase was primarily due to
higher fuel costs recovered through the EAC which are included in fuel
for production expense. The increases during the six and twelve month
periods were substantially related to increased Kwh generation,
primarily the result of a refueling outage during early 1995 at
Utilities' nuclear generating station, the Duane Arnold Energy Center
(DAEC).
Purchased power increased or (decreased) $4.9 million, $3.0 million
and ($1.5) million during the three, six and twelve month periods,
respectively. The three and six month increases were primarily due to
increased energy purchases, as a result of the increased electric sales
(excluding the 1995 unbilled adjustment), partially offset by lower
capacity costs. The twelve month decrease was due to a ($4.2) million
decrease in capacity costs, partially offset by higher energy purchases
due to the increased sales.
Gas purchased for resale increased $8.7 million, $26.9 million and
$48.9 million during the three, six and twelve month periods,
respectively, primarily due to higher natural gas costs and increased
gas sales.
Other operating expenses increased $6.4 million, $10.8 million and
$23.5 million during the three, six and twelve month periods,
respectively. Increased operating activities at Whiting and IEA,
increased labor and benefits costs at Utilities, the amortization of
previously deferred energy efficiency expenditures at Utilities (which
are currently being recovered through rates) and costs incurred in the
Company's efforts to prepare for an increasingly competitive utility
industry contributed to the increases in all periods. The costs to
prepare for a competitive utility industry included costs associated
with items such as 1) a project to review and redesign Utilities' major
business processes, 2) the Proposed Merger and 3) an early retirement
program. These increases were partially offset by decreased costs
resulting from the sale or dissolution of the Diversified subsidiaries
and lower former manufactured gas plant (FMGP) clean-up costs at
Utilities.
Maintenance expenses increased or (decreased) $3.8 million, $2.4
million and ($2.0) million during the three, six and twelve month
periods, respectively. The three and six month increases are primarily
due to increased maintenance activities at Utilities' generating
stations. The twelve month decrease was primarily caused by less
required maintenance at the DAEC and lower tree trimming costs at
Utilities.
Depreciation and amortization increased during all periods because
of increases in utility plant in service and the acquisition of oil and
gas operating properties. These increases were partially offset by
lower depreciation rates implemented at Utilities as a result of the IUB
electric price reduction order. Depreciation and amortization expenses
for all periods included a provision for decommissioning the DAEC, which
is collected through rates. The annual recovery level was increased to
$6.0 million in 1995 from $5.5 million, as a result of Utilities' most
recent electric rate case.
During the first quarter of 1996, the Financial Accounting
Standards Board (FASB) issued an Exposure Draft on Accounting for
Liabilities Related to Closure and Removal of Long-Lived Assets which
deals with, among other issues, the accounting for decommissioning
costs. If current electric utility industry accounting practices for
such decommissioning are changed: 1) annual provisions for
decommissioning could increase and 2) the estimated cost for
decommissioning could be recorded as a liability, rather than as
accumulated depreciation, with recognition of an increase in the
recorded amount of the related DAEC plant. If such changes are
required, Utilities believes that there would not be an adverse effect
on its financial position or results of operations based on current rate
making practices.
Interest Expense and Other Interest expense increased $0.8 million and
$3.3 million during the six and twelve month periods, respectively,
primarily because of increases in the average amount of short-term debt
outstanding at Utilities and the average amount of borrowings under
Diversified's credit facility. Lower average interest rates, primarily
attributable to refinancing long-term debt at lower rates and the mix of
long-term and short-term debt, partially offset the increases.
Income taxes increased or (decreased) ($1.7) million, $5.8 million
and $11.0 million for the three, six and twelve month periods,
respectively. The variances for all periods were due to changes in pre-
tax income and a higher effective tax rate. The higher effective tax
rate for each period is due to: 1) the effect of property related
temporary differences for which deferred taxes had not been provided,
pursuant to rate making principles, that are now becoming payable and
are being recovered from ratepayers, and 2) the effect of prior period
audit adjustments.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are primarily attributable to
Utilities' construction programs, its debt maturities and the level of
Diversified's business opportunities. The Company's pre-tax ratio of
times interest earned was 3.26 and 3.04 for the twelve months ended June
30, 1996 and June 30, 1995, respectively. Cash flows from operating
activities for the twelve months ended June 30, 1996 and June 30, 1995
were $198 million and $210 million, respectively. The decrease was
primarily due to the electric rate case refund paid to customers in the
fourth quarter of 1995 and other changes in working capital. Cash paid
for income taxes increased significantly during all three periods
primarily because of the timing of estimated tax payments computed under
the annualized income approach.
The Company anticipates that future capital requirements will be
met by cash generated from operations and external financing. The level
of cash generated from operations is partially dependent upon economic
conditions, legislative activities, environmental matters and timely
rate relief for Utilities. See Notes 3 and 8 of the Notes to
Consolidated Financial Statements.
Access to the long-term and short-term capital and credit markets
is necessary for obtaining funds externally. The Company's debt ratings
are as follows:
Moody's Standard & Poor's
Utilities - Long-term debt A2 A
- Short-term debt P1 A1
Diversified - Short-term debt P2 A2
Both Moody's and Standard & Poor's have indicated that Utilities'
credit ratings are under review as the result of the unsolicited
acquisition proposal the Company received from MidAmerican Energy Co.
It is not certain if, and how, such proposal or the Proposed Merger may
affect the Company's debt ratings.
The Company's liquidity and capital resources will be affected by
environmental and legislative issues, including the ultimate disposition
of remediation issues surrounding the Company's environmental
liabilities and the Clean Air Act as amended, as discussed in Note 8 of
the Notes to Consolidated Financial Statements, and the National Energy
Policy Act of 1992 as discussed in the Other Matters section. Consistent
with rate making principles of the IUB, management believes that the
costs incurred for the above matters will not have a material adverse
effect on the financial position or results of operations of the
Company.
Current IUB rules require Utilities to spend 2% of electric and
1.5% of gas gross retail operating revenues annually for energy
efficiency programs. Energy efficiency costs in excess of the amount in
the most recent electric and gas rate cases are being recorded as
regulatory assets by Utilities. At June 30, 1996, Utilities had
approximately $55 million of such costs recorded as regulatory assets.
On June 1, 1995, Utilities began recovery of those costs incurred
through 1993. See Note 3(c) of the Notes to Consolidated Financial
Statements for a discussion of the timing of the filings for the
recovery of these costs under IUB rules and Iowa statutory changes
recently enacted relating to these programs.
At June 30, 1996, the Company had a $10.0 million investment in
Class A common stock of McLeod, Inc., a $9.2 million investment in Class
B common stock and vested options that, if exercised, would represent an
additional investment of approximately $2.3 million. McLeod provides
local and long-distance telecommunications services to business
customers and other services related to fiber optics.
As a result of contractual and possible SEC sale restrictions, the
McLeod shares are restricted stock under the provisions of SFAS No. 115,
Accounting for Certain Investments in Debt and Equity Securities, until
such time as the restrictions lapse and such shares became qualified for
sale within a one year period. As a result, the Company currently
carries this investment at cost.
The closing price of the McLeod Class A common stock on June 30,
1996, on the Nasdaq National Market, was $24.00 per
share. The current market value of the shares the Company beneficially
owns (approximately 10.2 million shares) is currently impacted by, among
other things, the fact that the shares cannot be sold for a period of
time and it is not possible to estimate what the market value of the
shares will be at the point in time such sale restrictions are lifted.
In addition, any gain upon an eventual sale of this investment would
likely be subject to a tax. See Note 5(b) of the Notes to Consolidated
Financial Statements for a further discussion of the Company's
investment in McLeod, Inc.
Under provisions of the Merger Agreement, there are restrictions on
the amount of common stock and long-term debt the Company can issue
pending the merger. The Company does not expect the restrictions to
have a material effect on its ability to meet its future capital
requirements.
CONSTRUCTION AND ACQUISITION PROGRAM
The Company's construction and acquisition program anticipates
expenditures of approximately $245 million for 1996, of which
approximately $164 million represents expenditures at Utilities and
approximately $81 million represents expenditures at Diversified. Of
the $164 million of Utilities' expenditures, 55% represents expenditures
for electric, gas and steam transmission and distribution facilities,
19% represents fossil-fueled generation expenditures, 13% represents
information technology expenditures and 5% represents nuclear generation
expenditures. The remaining 8% represents miscellaneous electric and
general expenditures. In addition to the $164 million, Utilities
anticipates expenditures of $13 million in connection with mandated
energy efficiency programs. Diversified's anticipated expenditures
include approximately $75 million for domestic and international energy-
related construction and acquisition expenditures. The Company had
construction and acquisition expenditures of approximately $91 million
for the six months ended June 30, 1996, including approximately
$57 million of utility expenditures and $34 million of non-utility
expenditures.
The Company's levels of construction and acquisition expenditures
are projected to be $283 million in 1997, $255 million in 1998,
$247 million in 1999 and $215 million in 2000. It is estimated that
approximately 80% of Utilities' construction and acquisition
expenditures will be provided by cash from operating activities (after
payment of dividends) for the five-year period 1996-2000. Financing
plans for Diversified's construction and acquisition program will vary,
depending primarily on the level of energy-related acquisitions.
Capital expenditure and investment and financing plans are subject
to continual review and change. The capital expenditure and investment
programs may be revised significantly as a result of many considerations
including changes in economic conditions, variations in actual sales and
load growth compared to forecasts, requirements of environmental,
nuclear and other regulatory authorities, acquisition and business
combination opportunities, the availability of alternate energy and
purchased power sources, the ability to obtain adequate and timely rate
relief, escalations in construction costs and conservation and energy
efficiency programs.
Under provisions of the Merger Agreement, there are restrictions on
the amount of construction and acquisition expenditures the Company can
make pending the merger. The Company does not expect the restrictions
to have a material effect on its ability to implement its anticipated
construction and acquisition program.
LONG-TERM FINANCING
Other than Utilities' periodic sinking fund requirements, which
Utilities intends to meet by pledging additional property, the following
long-term debt will mature prior to December 31, 2000:
(in millions)
Utilities $ 140.1
Diversified's credit facility 135.2
Other subsidiaries' debt 11.2
$ 286.5
The Company intends to refinance the majority of the debt
maturities with long-term securities.
Utilities has entered into an Indenture of Mortgage and Deed of
Trust dated September 1, 1993 (New Mortgage). The New Mortgage provides
for, among other things, the issuance of Collateral Trust Bonds upon the
basis of First Mortgage Bonds being issued by Utilities. The lien of
the New Mortgage is subordinate to the lien of Utilities' first
mortgages until such time as all bonds issued under the first mortgages
have been retired and such mortgages satisfied. Accordingly, to the
extent that Utilities issues Collateral Trust Bonds on the basis of
First Mortgage Bonds, it must comply with the requirements for the
issuance of First Mortgage Bonds under Utilities' first mortgages.
Under the terms of the New Mortgage, Utilities has covenanted not to
issue any additional First Mortgage Bonds under its first mortgages
except to provide the basis for issuance of Collateral Trust Bonds.
The indentures pursuant to which Utilities issues First Mortgage
Bonds constitute direct first mortgage liens upon substantially all
tangible public utility property and contain covenants which restrict
the amount of additional bonds which may be issued. At June 30, 1996,
such restrictions would have allowed Utilities to issue at least
$266 million of additional First Mortgage Bonds.
In order to provide an instrument for the issuance of unsecured
subordinated debt securities, Utilities entered into an Indenture dated
December 1, 1995 (Subordinated Indenture). The Subordinated Indenture
provides for, among other things, the issuance of unsecured subordinated
debt securities. Any debt securities issued under the Subordinated
Indenture are subordinate to all senior indebtedness of Utilities,
including First Mortgage Bonds and Collateral Trust Bonds.
Utilities has received authority from the Federal Energy Regulatory
Commission (FERC) and the SEC to issue up to $250 million of long-term
debt, and has $250 million of remaining authority under the current FERC
docket through April 1998, and $200 million of remaining authority under
the current SEC shelf registration. Utilities expects to initially
replace $15 million of First Mortgage Bonds that mature in September
1996 with short-term borrowings pending the issuance of long-term debt.
Diversified has a variable rate credit facility that extends
through November 9, 1998, with a one-year extension available to
Diversified. The facility also serves as a stand-by agreement for
Diversified's commercial paper program. The agreement provides for a
combined maximum of $150 million of borrowings under the agreement and
commercial paper to be outstanding at any one time. Interest rates and
maturities are set at the time of borrowing for direct borrowings under
the agreement and for issuances of commercial paper. The interest rate
options are based upon quoted market rates and the maturities are less
than one year. At June 30, 1996, there were no borrowings outstanding
under this facility. Diversified had $135.2 million of commercial paper
outstanding at June 30, 1996, with interest rates ranging from 5.52% to
5.85% and maturity dates in the third quarter of 1996. Diversified
intends to continue borrowing under the renewal options of the facility
and no conditions exist at June 30, 1996, that would prevent such
borrowings. Accordingly, this debt is classified as long-term in the
Consolidated Balance Sheets. Refer to Note 7 of the Notes to
Consolidated Financial Statements for a discussion of an interest rate
swap agreement Diversified entered into relating to the credit facility.
The Articles of Incorporation of Utilities authorize and limit the
aggregate amount of additional shares of Cumulative Preference Stock and
Cumulative Preferred Stock that may be issued. At June 30, 1996,
Utilities could have issued an additional 700,000 shares of Cumulative
Preference Stock and 100,000 additional shares of Cumulative Preferred
Stock. In addition, Industries had 5,000,000 shares of Cumulative
Preferred Stock, no par value, authorized for issuance, none of which
were outstanding at June 30, 1996.
The Company's capitalization ratios at June 30, were as follows:
1996 1995
Long-term debt 49% 47%
Preferred stock 1 2
Common equity 50 51
100% 100%
The 1995 ratios included $50 million of long-term debt due in
less than one year because it was the Company's intention to
refinance the debt with long-term securities.
Under provisions of the Merger Agreement, there are restrictions on
the amount of common stock and long-term debt the Company can issue
pending the merger. The Company does not expect the restrictions to
have a material effect on its ability to meet its future capital
requirements.
SHORT-TERM FINANCING
For interim financing, Utilities is authorized by the FERC to
issue, through 1996, up to $200 million of short-term notes. In
addition to providing for ongoing working capital needs, this
availability of short-term financing provides Utilities flexibility in
the issuance of long-term securities. At June 30, 1996, Utilities had
outstanding short-term borrowings of $129.6 million, including
$4.6 million of notes payable to associated companies.
Utilities has entered into an agreement, which expires in 1999,
with a financial institution to sell, with limited recourse, an
undivided fractional interest of up to $65 million in its pool of
utility accounts receivable. At June 30, 1996, $65 million was sold
under the agreement.
At June 30, 1996, the Company had bank lines of credit aggregating
$126.1 million (Industries - $1.5 million, Utilities - $121.1 million,
Diversified - $2.5 million and Whiting - $1.0 million). Utilities was
using $108 million to support commercial paper (weighted average
interest rate of 5.40%) and $11.1 million to support certain pollution
control obligations. Commitment fees are paid to maintain these lines
and there are no conditions which restrict the unused lines of credit.
In addition to the above, Utilities has an uncommitted credit facility
with a financial institution whereby it can borrow up to $40 million.
Rates are set at the time of borrowing and no fees are paid to maintain
this facility. At June 30, 1996, there was $17 million outstanding
under this facility (weighted average interest rate of 5.57%).
ENVIRONMENTAL MATTERS
Utilities has been named as a Potentially Responsible Party (PRP)
by various federal and state environmental agencies for 28 FMGP sites,
but believes it is not responsible for two of these sites based on
extensive reviews of the ownership records and historical information
available for the two sites. Utilities has notified the appropriate
regulatory agency that it believes it does not have any responsibility
as relates to these two sites, but no response has been received from
the agency on this issue. Utilities is also aware of six other sites
that it may have owned or operated in the past and for which, as a
result, it may be designated as a PRP in the future in the event that
environmental concerns arise at these sites. Utilities is working
pursuant to the requirements of the various agencies to investigate,
mitigate, prevent and remediate, where necessary, damage to property,
including damage to natural resources, at and around the sites in order
to protect public health and the environment. Utilities believes it has
completed the remediation of seven sites although it is in the process
of obtaining final approval from the applicable environmental agencies
on this issue for each site. Utilities is in various stages of the
investigation and/or remediation processes for the remaining 19 sites
and estimates the range of additional costs to be incurred for
investigation and/or remediation of the sites to be approximately $24
million to $57 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $35 million (including $4.6 million as
current liabilities) at June 30, 1996. These amounts are based upon
Utilities' best current estimate of the amount to be incurred for
investigation and remediation costs for those sites where the
investigation process has been or is substantially completed, and the
minimum of the estimated cost range for those sites where the
investigation is in its earlier stages. It is possible that future cost
estimates will be greater than the current estimates as the
investigation process proceeds and as additional facts become known; in
addition, Utilities may be required to monitor these sites for a number
of years upon completion of remediation, as is the case with several of
the sites for which remediation has been completed.
In April 1996, Utilities filed a lawsuit against certain of its
insurance carriers seeking reimbursement for investigation, mitigation,
prevention, remediation and monitoring costs associated with the FMGP
sites. Settlement discussions are proceeding between Utilities and its
insurance carriers regarding the recovery of these FMGP-related costs.
The amount of aggregate potential recovery, or the regulatory treatment
of any such recoveries, cannot be reasonably determined at this time
and, accordingly, no estimated amounts have been recorded at June
30, 1996. Regulatory assets of approximately $35 million, which reflect
the future recovery that is being provided through Utilities' rates,
have been recorded in the Consolidated Balance Sheets. Considering the
current rate treatment allowed by the IUB, management believes that the
clean-up costs incurred by Utilities for these FMGP sites will not have
a material adverse effect on its financial position or results of
operations.
The Clean Air Act Amendments of 1990 (Act) requires emission
reductions of sulfur dioxide (SO2) and nitrogen oxides (NOx) to achieve
reductions of atmospheric chemicals believed to cause acid rain. The
provisions of the Act are being implemented in two phases; the Phase I
requirements have been met and the Phase II requirements affect eleven
other fossil units beginning in the year 2000. Utilities expects to
meet the requirements of Phase II by switching to lower sulfur fuels,
capital expenditures primarily related to fuel burning equipment and
boiler modifications, and the possible purchase of SO2 allowances.
Utilities estimates capital expenditures at approximately $20 million,
including $4 million in 1996, in order to meet the acid rain
requirements of the Act.
The acid rain program under the Act also governs SO2 allowances.
An allowance is defined as an authorization for an owner to emit one ton
of SO2 into the atmosphere. Currently, Utilities receives a sufficient
number of allowances annually to offset its emissions of SO2 from its
Phase I units. It is anticipated that in the year 2000, Utilities may
have an insufficient number of allowances annually to offset its
estimated emissions and may have to purchase additional allowances, or
make modifications to the plants or limit operations to reduce
emissions. Utilities is reviewing its options to ensure that it will
have sufficient allowances to offset its emissions in the future.
Utilities believes that the potential cost of ensuring sufficient
allowances will not have a material adverse effect on its financial
position or results of operations.
The Act and other federal laws also require the United States
Environmental Protection Agency (EPA) to study and regulate, if
necessary, additional issues that potentially affect the electric
utility industry, including emissions relating to NOx, ozone transport,
mercury and particulate control; toxic release inventories and
modifications to the PCB rules. Currently, the impacts of these
potential regulations are too speculative to quantify.
In 1995, the EPA published the Sulfur Dioxide Network Design Review
for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-
case modeling method suggests that the Cedar Rapids area could be
classified as "nonattainment" for the National Ambient Air Quality
Standard (NAAQS) established for SO2. The worst-case modeling study
suggested that two of Utilities' generating facilities contribute to the
modeled exceedences and recommended that additional monitors be located
near Utilities' sources to assess actual ambient air quality. In the
event that Utilities' facilities contribute excessive emissions,
Utilities would be required to reduce emissions, which would primarily
entail capital expenditures for modifications to the facilities.
Utilities is planning to convert one of its fossil generating facilities
to a natural gas-fired cogeneration facility. Such facility was
contributing to the modeled exceedences thus the conversion will have
the added inherent benefit of reducing SO2 emissions. Utilities is
proposing to resolve the remainder of EPA's nonattainment concerns by
installing a new stack at the other generating facility contributing to
the modeled exceedences at a potential capital cost of up to $4.5
million over the next four years.
The National Energy Policy Act of 1992 requires owners of nuclear
power plants to pay a special assessment into a "Uranium Enrichment
Decontamination and Decommissioning Fund." The assessment is based upon
prior nuclear fuel purchases and, for the DAEC, averages $1.4 million
annually through 2007, of which Utilities' 70% share is $1.0 million.
Utilities is recovering the costs associated with this assessment
through its electric fuel adjustment clauses over the period the costs
are assessed. Utilities' 70% share of the future assessment, $10.9
million payable through 2007, has been recorded as a liability in the
Consolidated Balance Sheets, including $0.8 million included in "Current
liabilities - Environmental liabilities," with a related regulatory
asset for the unrecovered amount.
The Nuclear Waste Policy Act of 1982 assigned responsibility to the
U.S. Department of Energy (DOE) to establish a facility for the ultimate
disposition of high level waste and spent nuclear fuel and authorized
the DOE to enter into contracts with parties for the disposal of such
material beginning in January 1998. Utilities entered into such a
contract and has made the agreed payments to DOE. The DOE, however, has
experienced significant delays in its efforts and material acceptance is
now expected to occur no earlier than 2010 with the possibility of
further delay being likely. Utilities has been storing spent nuclear
fuel on-site since plant operations began in 1974 and has current on-
site capability to store spent fuel until 2002. Utilities is
aggressively reviewing options for additional spent nuclear fuel storage
capability, including expanding on-site storage and supporting
legislation currently before the U.S. Congress, to resolve the lack of
progress by the DOE.
The Low-Level Radioactive Waste Policy Amendments Act of 1985
mandated that each state must take responsibility for the storage of low-
level radioactive waste produced within its borders. The State of Iowa
has joined the Midwest Interstate Low-Level Radioactive Waste Compact
Commission (Compact), which is planning a storage facility to be located
in Ohio to store waste generated by the Compact's six member states. At
June 30, 1996, Utilities has prepaid costs of approximately $1.1 million
to the Compact for the building of such a facility. A Compact disposal
facility is anticipated to be in operation in approximately ten years
after approval of new enabling legislation by the member states. Such
legislation has been approved by all six states. Approval by the U.S.
Congress will also be required before it is effective and is currently
expected to be considered in 1997. On-site storage capability currently
exists for low-level radioactive waste expected to be generated until
the Compact facility is able to accept waste materials. In addition,
the Barnwell, South Carolina disposal facility has reopened for an
indefinite time period and Utilities is in the process of shipping to
Barnwell the majority of the low-level radioactive waste it has
accumulated on-site, and intends to ship the waste it produces in the
future as long as the Barnwell site remains open, thereby minimizing the
amount of low-level waste stored on-site.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects has been the subject of
increased public, governmental, industry and media attention. A
considerable amount of scientific research has been conducted on this
topic without definitive results. Research is continuing in order to
resolve scientific uncertainties. The Company cannot predict the
outcome of this research.
Whiting is responsible for certain dismantlement and abandonment
costs related to various off-shore oil and gas properties, the most
significant of which is located off the coast of California. Whiting
accrues these costs as reserves are extracted and such costs are
included in "Depreciation and amortization" in the Consolidated
Statements of Income. A corresponding environmental liability, $2.6
million at June 30, 1996, has been recognized in the Consolidated
Balance Sheets for the cumulative amount expensed.
OTHER MATTERS
Competition As legislative, regulatory, economic and technological
changes occur, electric utilities are faced with increasing pressure to
become more competitive. Such competitive pressures could result in
loss of customers and an incurrence of stranded costs (i.e. the cost of
assets rendered unrecoverable as the result of competitive pricing). To
the extent stranded costs cannot be recovered from customers, they would
be borne by security holders.
The National Energy Policy Act of 1992 addresses several matters
designed to promote competition in the electric wholesale power
generation market. In April 1996, the FERC issued final rules (FERC
Orders 888 and 889), largely confirming earlier proposals, requiring
electric utilities to open their transmission lines to other wholesale
buyers and sellers of electricity. The rules became effective on July
9, 1996. The key provisions of the rules are: 1) utilities must act as
"common carriers" of electricity, reserving capacity on their lines for
other wholesale buyers and sellers of electricity and charging
competitors no more than they pay themselves for use of the lines; 2)
utilities must establish electronic bulletin boards to share information
about transmission capacity; and 3) utilities can recover "stranded
costs" by charging large wholesale customers a fee for switching to a
new supplier. Utilities filed conforming pro-forma open access
transmission tariffs with the FERC which became effective October 1,
1995. In response to FERC Order 888, Utilities filed its final pro-forma
tariffs with FERC on July 9, 1996. These tariffs have not yet been
approved by the FERC. The geographic position of Utilities'
transmission system could provide revenue opportunities in the open
access environment. IEA received approval in the 1995 FERC proceeding
to market electric power at market based rates. The Company cannot
predict the long-term consequences of these rules on its results of
operation or financial condition.
The final FERC rules do not provide for the recovery of stranded
costs resulting from retail competition. The various states retain
jurisdiction over whether to permit retail competition, the terms of
such retail competition and the recovery of any portion of stranded
costs that are ultimately determined by FERC and the states to have
resulted from retail competition.
As part of Utilities' strategy for the emerging and competitive
power markets, Utilities, IPC and Wisconsin Power and Light Company (the
utility subsidiary of WPLH), and a number of other utilities have proposed
the creation of an independent system operator (ISO) for the companies'
power transmission grid. The companies would retain ownership and
control of the facilities, but the ISO, subject to FERC approval, would
set rates for access and
assume fair treatment for all companies seeking access. The proposal
requires approval from state regulators and the FERC.
The IUB initiated a Notice of Inquiry (Docket No. NOI-95-1) in
early 1995 on the subject of "Emerging Competition in the Electric
Utility Industry." A one-day roundtable discussion was held to address
all forms of competition in the electric utility industry and to assist
the IUB in gathering information and perspectives on electric
competition from all persons or entities with an interest or stake in
the issues. Additional discussions were held in December 1995, May 1996
and July 1996. In January 1996, the IUB created its own timeline for
evaluating industry restructuring in Iowa. Included in the IUB's
process was the creation of a 22-member advisory panel, of which
Utilities is a member. The IUB has established a self-imposed deadline
of the fourth quarter of 1996, for publishing its analysis of various
restructuring options and any advisory panel comments on the IUB's
options and analysis. The IUB's schedule calls for public information
meetings to be held around the state of Iowa during late 1996 and early
1997.
Utilities is subject to the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS 71). If a portion of Utilities' operations
become no longer subject to the provisions of SFAS 71, as a result of
competitive restructurings or otherwise, a write-down of related
regulatory assets would be required, unless some form of transition cost
recovery is established by the appropriate regulatory body. Utilities
believes that it still meets the requirements of SFAS 71.
The Company cannot predict the long-term consequences of these
competitive issues on its results of operations or financial condition.
The Company's strategy for dealing with these emerging issues includes
seeking growth opportunities, continuing to offer quality customer
service, ongoing cost reductions and productivity enhancements, the
major objective of which is to allow Utilities to better prepare for a
competitive, deregulated electric utility industry. In this connection,
Utilities has undertaken Process Redesign, an effort to improve service
levels, to reduce its cost structure and to become more market-focused
and customer-oriented.
Process Redesign is examining the major business processes within
Utilities, which are: Customer Service Fulfillment, Fossil-Fueled Energy
Supply, Nuclear Energy Supply, Non-Electric Fuel Supply Chain,
Transmission and Distribution Energy Delivery, and Planning, Budgeting &
Performance Management. These areas were examined during Phase I of the
effort, which lasted from January 1995 through May 1995. Phase I
recommendations were designed to make broad-based changes in the way
work was performed and results were achieved in each of the processes.
Management accepted the recommendations and, in June 1995, initiated
Phase II of the project. The detailed designs resulting from Phase II
were substantially completed in November 1995 and pilot programs began.
Examples of the Process Redesign changes include, but are not
limited to: managing the business in business unit form, rather than
functionally; formation of alliances with vendors of certain types of
material rather than opening most purchases to a bidding process;
changing standards and construction practices in transmission and
distribution areas; changing certain work practices in power plants; and
improving the method by which service is delivered to customers in all
customer classes. The specific recommendations range from simple
improvements in current operations to radical changes in the way work is
performed and service is delivered. Utilities currently intends to
implement all of the recommendations of the Process Redesign teams,
although the pilot stage or potential effects of the Proposed Merger
could prove that some of the recommendations are not efficient or
effective and must be revised or eliminated. Subject to delays caused
by implementing any such revisions, implementation of the Process
Redesign changes will be partially completed in 1996, but, certain
results will not be achieved until 1997. In addition, the Company must
give consideration to the potential effects of the Proposed Merger as
part of the implementation process so that duplication of efforts are
avoided.
Accounting Pronouncements SFAS 121, issued in March 1995 by the FASB
and effective for 1996, establishes accounting standards for the
impairment of long-lived assets. SFAS 121 also requires that regulatory
assets that are no longer probable of recovery through future revenues
be charged to earnings. The Company adopted this standard on January 1,
1996, and the adoption had no effect on the financial position or
results of operations of the Company. SFAS 121 does not apply to
Whiting's oil and gas properties as such costs are capitalized pursuant
to the full cost method of accounting and are evaluated for impairment
under rules relating to such accounting method.
Financial Derivatives The Company has a policy that financial
derivatives are to be used only to mitigate business risks and not for
speculative purposes. Derivatives have been used by the Company on a
very limited basis. At June 30, 1996, the only material financial
derivative outstanding for the Company was the interest rate swap
agreement described in Note 7 of the Notes to Consolidated Financial
Statements.
Inflation Under the rate making principles prescribed by the regulatory
commissions to which Utilities is subject, only the historical cost of
plant is recoverable in revenues as depreciation. As a result,
Utilities has experienced economic losses equivalent to the current
year's impact of inflation on utility plant. In addition, the
regulatory process imposes a substantial time lag between the time when
operating and capital costs are incurred and when they are recovered.
Utilities does not expect the effects of inflation at current levels to
have a significant effect on its financial position or results of
operations.
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings.
On April 30, 1996, Utilities filed suit, IES Utilities Inc. v. Home
Ins. Co., et al., No. 4-96-CV-10343 (S.D. Iowa filed Apr. 30, 1996),
against various insurers who had sold comprehensive general liability
policies to Iowa Southern Utilities Company (ISU) and Iowa Electric
Light and Power Company (IE) (Utilities was formed as the result of a
merger of ISU and IE). The suit seeks judicial determination of the
respective rights of the parties, a judgment that each defendant is
obligated under its respective insurance policies to pay in full all
sums that the Company has become or may become obligated to pay in
connection with its defense against allegations of liability for
property damage at and around FMGP sites, and indemnification for all
sums that it has or may become obligated to pay for the investigation,
mitigation, prevention, remediation and monitoring of damage to
property, including damage to natural resources like groundwater, at and
around the FMGP sites.
Industries, Diversified, IES Energy (a wholly-owned subsidiary of
Diversified), MicroFuel Corporation (the Corporation) now known as Ely,
Inc. in which IES Energy has a 69.40% equity ownership, and other
parties have been sued in Linn County District Court in Cedar Rapids,
Iowa, by Allen C. Wiley. Mr. Wiley claims money damages on various tort
and contract theories arising out of the 1992 sale of the assets of the
Corporation, of which Mr. Wiley was a director and shareholder. All of
the defendants in Mr. Wiley's suit answered the complaint and denied
liability. Industries and Diversified were dismissed from the suit in a
motion for summary judgment. In addition, a motion for summary judgment
has reduced Mr. Wiley's claims against the remaining parties to breach
of fiduciary duty. A separate motion for summary judgment has recently
been filed seeking dismissal of the remaining claims against the
remaining parties. A hearing on that motion is scheduled for August 30,
1996. All of the defendants believe that the claims are without merit
and are vigorously contesting them. The trial has been continued until
December 1996.
The Corporation commenced a separate suit to determine the fair
value of Mr. Wiley's shares under Iowa Code section 490. A decision was
issued on August 31, 1994, by the Linn County District Court ruling that
the value of Mr. Wiley's shares was $377,600 based on a 40 cent per
share valuation. The Corporation contended that the value of Mr. Wiley's
shares was 2.5 cents per share. The Decision was appealed to the Iowa
Supreme Court by the Corporation on a number of issues, including the
Corporation's position that the trial court erred as a matter of law in
discounting the testimony of the Corporation's expert witness. The Iowa
Supreme Court assigned the case to the Iowa Court of Appeals. On
February 2, 1996, the Iowa Court of Appeals reversed the District Court
ruling after determining the District Court erred in discounting the
expert testimony. The case has been remanded back to the District Court
for consideration of the expert testimony, but with no additional
evidence being taken.
Reference is made to Notes 3 and 8 of the Notes to Consolidated
Financial Statements for a discussion of rate matters and environmental
matters, respectively, and Item 2. Management's Discussion and Analysis
of the Results of Operations and Financial Condition - Environmental
Matters.
Item 2. Changes in the Rights of the Company's Security Holders.
None.
Item 3. Default Upon Senior Securities.
None.
Item 4. Results of Votes of Security Holders.
None.
Item 5. Other Information.
John E. Ebright joined the Company as Controller & Chief Accounting
Officer, effective July 8, 1996.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits -
2 Agreement and Plan of Merger, dated as of November 10, 1995,
as amended, by and among WPL Holdings, Inc., IES Industries
Inc., Interstate Power Company, WPLH Acquisition Co. and
Interstate Power Company (Filed as Exhibit 2.1 to the
Company's Joint Proxy Statement, dated July 11, 1996).
3(a) Bylaws of Registrant, as amended May 7, 1996 (Filed as Exhibit
3(a) to the Company's Form 10-Q for the quarter ended March
31, 1996).
*27 Financial Data Schedule.
* Exhibits designated by an asterisk are filed herewith.
(b) Reports on Form 8-K -
Items Reported Financial Statements Date of Report
5,7 None April 3, 1996 (1)
5,7 None April 12, 1996 (2)
5,7 None May 22, 1996 (3)
(1) The Form 8-K report was filed on April 8, 1996 with the earliest
event reported occurring on April 3, 1996.
(2) The Form 8-K report was filed on April 18, 1996 with the earliest
event reported occurring on April 12, 1996.
(3) The Form 8-K report was filed on May 24, 1996 with the earliest
event reported occurring on May 22, 1996.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
IES INDUSTRIES INC.
(Registrant)
Date: August 20, 1996 By /s/ Dennis B. Vass
(Signature)
Dennis B. Vass
Treasurer & Principal Financial Officer
By /s/ John E. Ebright
(Signature)
John E. Ebright
Controller & Chief Accounting Officer
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The schedule contains summary financial information extracted from the
Consolidated Balance Sheet at June 30, 1996 and the Consolidated Statement
of Income and the Consolidated Statement of Cash Flows for the six months
ended June 30, 1996 and is qualified in its entirety by reference to such
financial statements.
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<OTHER-ITEMS-CAPITAL-AND-LIAB> 590,595
<TOT-CAPITALIZATION-AND-LIAB> 2,014,307
<GROSS-OPERATING-REVENUE> 453,844
<INCOME-TAX-EXPENSE> 19,070<F1>
<OTHER-OPERATING-EXPENSES> 390,080
<TOTAL-OPERATING-EXPENSES> 390,080<F1>
<OPERATING-INCOME-LOSS> 63,764
<OTHER-INCOME-NET> 3,753
<INCOME-BEFORE-INTEREST-EXPEN> 67,517
<TOTAL-INTEREST-EXPENSE> 25,839
<NET-INCOME> 22,151<F2>
457<F2>
<EARNINGS-AVAILABLE-FOR-COMM> 22,151
<COMMON-STOCK-DIVIDENDS> 31,225
<TOTAL-INTEREST-ON-BONDS> 35,222
<CASH-FLOW-OPERATIONS> 90,644
<EPS-PRIMARY> 0.75
<EPS-DILUTED> 0
<FN>
<F1>Income tax expense is not included in Operating Expense in the Consolidated
Statements of Income for IES Industries Inc. (Industries).
<F2> Since the preferred dividends are for a subsidiary of Industries, they are
considered a fixed charge on Industries' Consolidated Statement of Income.
</FN>
</TABLE>
