UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark one)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 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 October 31, 1996
Common Stock, no par value 30,043,320 shares
IES INDUSTRIES INC.
INDEX
Page No.
Part I. Financial Information.
Item 1. Consolidated Financial Statements.
Consolidated Balance Sheets -
September 30, 1996 and December 31, 1995 3 - 4
Consolidated Statements of Income -
Three, Nine and Twelve Months Ended
September 30, 1996 and 1995 5
Consolidated Statements of Cash Flows -
Three, Nine and Twelve Months Ended
September 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 - 55
Signatures. 56
PART 1. - FINANCIAL INFORMATION
ITEM 1. - CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED BALANCE SHEETS
September 30,
1996 December 31,
ASSETS (Unaudited) 1995
(in thousands)
Property, plant and equipment:
Utility -
Plant in service -
Electric $ 1,949,085 $ 1,900,157
Gas 171,050 165,825
Other 109,924 106,396
2,230,059 2,172,378
Less - Accumulated depreciation 1,020,070 950,324
1,209,989 1,222,054
Leased nuclear fuel, net of amortization 36,525 36,935
Construction work in progress 90,191 52,772
1,336,705 1,311,761
Other, net of accumulated depreciation
and amortization of $67,442,000 and
$53,026,000, respectively 206,132 193,215
1,542,837 1,504,976
Current assets:
Cash and temporary cash investments 8,366 6,942
Accounts receivable -
Customer, less reserve 20,840 37,214
Other 8,449 10,493
Income tax refunds receivable 1,893 982
Production fuel, at average cost 14,224 12,155
Materials and supplies, at average cost 22,944 28,354
Adjustment clause balances 750 0
Regulatory assets 24,351 22,791
Oil and gas properties held for resale 0 9,843
Prepayments and other 22,145 23,099
123,962 151,873
Investments:
Nuclear decommissioning trust funds 54,870 47,028
Investment in foreign entities 29,920 24,770
Investment in McLeod, Inc. 19,200 9,200
Cash surrender value of life insurance policies 10,863 9,838
Other 4,861 3,897
119,714 94,733
Other assets:
Regulatory assets 212,753 207,202
Deferred charges and other 26,332 26,807
239,085 234,009
$ 2,025,598 $ 1,985,591
CONSOLIDATED BALANCE SHEETS (CONTINUED)
September 30,
1996 December 31,
CAPITALIZATION AND LIABILITIES (Unaudited) 1995
(in thousands)
Capitalization:
Common stock - no par value - authorized
48,000,000 shares; outstanding
29,958,405 and 29,508,415
shares, respectively $ 403,712 $ 391,269
Retained earnings 217,168 221,077
Total common equity 620,880 612,346
Cumulative preferred stock of IES Utilities Inc. 18,320 18,320
Long-term debt (excluding current portion) 661,286 601,708
1,300,486 1,232,374
Current liabilities:
Short-term borrowings 78,000 101,000
Capital lease obligations 13,523 15,717
Maturities and sinking funds 8,467 15,447
Accounts payable 65,467 80,089
Dividends payable 16,395 16,244
Accrued interest 8,895 8,051
Accrued taxes 63,671 53,983
Accumulated refueling outage provision 14,441 7,690
Adjustment clause balances 0 3,148
Environmental liabilities 5,580 5,634
Other 22,872 21,800
297,311 328,803
Long-term liabilities:
Pension and other benefit obligations 53,832 52,677
Capital lease obligations 23,002 21,218
Environmental liabilities 43,173 43,087
Other 11,765 13,039
131,772 130,021
Deferred credits:
Accumulated deferred income taxes 260,898 257,278
Accumulated deferred investment tax credits 35,131 37,115
296,029 294,393
Commitments and contingencies (Note 8)
$ 2,025,598 $ 1,985,591
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the Three For the Nine For the Twelve
Months Ended Months Ended Months Ended
September 30 September 30 September 30
1996 1995 1996 1995 1996 1995
(in thousands, except per share amounts)
Operating revenues:
Electric $ 173,626 $ 183,876 $ 436,027 $ 433,502 $ 562,996 $ 558,219
Gas 28,461 29,794 161,112 126,786 224,666 175,198
Other 31,820 24,797 90,617 74,019 116,792 96,629
233,907 238,467 687,756 634,307 904,454 830,046
Operating expenses:
Fuel for production 29,148 31,945 72,168 71,691 96,733 89,576
Purchased power 18,655 19,954 55,125 53,399 68,600 74,061
Gas purchased for resale 20,841 22,913 120,091 95,269 166,538 130,945
Other operating expenses 55,554 49,994 160,367 143,958 217,788 192,272
Maintenance 14,091 12,548 40,011 36,037 50,067 50,582
Depreciation and amortization 27,417 24,201 82,025 74,662 105,320 96,390
Taxes other than income taxes 12,500 13,202 38,503 40,009 47,510 49,836
178,206 174,757 568,290 515,025 752,556 683,662
Operating income 55,701 63,710 119,466 119,282 151,898 146,384
Interest expense and other:
Interest expense 13,666 12,675 39,506 37,710 52,511 49,468
Allowance for funds used
during construction -761 -762 -2,141 -2,662 -2,904 -3,608
Preferred dividend requirements
of IES Utilities Inc. 229 229 686 686 914 914
Miscellaneous, net 4,883 -1,266 2,510 -1,776 1,132 -3,991
18,017 10,876 40,561 33,958 51,653 42,783
Income before income taxes 37,684 52,834 78,905 85,324 100,245 103,601
Income taxes:
Current 14,975 21,640 34,551 24,235 45,048 28,255
Deferred 2,481 741 3,298 12,733 1,008 14,842
Amortization of investment tax credits -661 -667 -1,984 -2,012 -2,658 -2,674
16,795 21,714 35,865 34,956 43,398 40,423
Net income $ 20,889 $ 31,120 $ 43,040 $ 50,368 $ 56,847 $ 63,178
Average number of common
shares outstanding 29,941 29,314 29,796 29,110 29,716 29,023
Earnings per average
common share $ 0.70 $ 1.06 $ 1.44 $ 1.73 $ 1.91 $ 2.18
Dividends declared per
common share $ 0.525 $ 0.525 $ 1.575 $ 1.575 $ 2.10 $ 2.10
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
For the Three For the Nine For the Twelve
Months Ended Months Ended Months Ended
September 30 September 30 September 30
1996 1995 1996 1995 1996 1995
(in thousands)
Cash flows from operating activities:
Net income $ 20,889 $ 31,120 $ 43,040 $ 50,368 $ 56,847 $ 63,178
Adjustments to reconcile net income to
net cash flows from operating activities -
Depreciation and amortization 27,417 24,201 82,025 74,662 105,320 96,390
Amortization of principal under capital
lease obligations 4,945 4,934 14,195 10,801 19,108 14,463
Deferred taxes and investment tax credits 1,820 74 1,314 10,721 -1,650 12,168
Refueling outage provision 1,831 3,006 6,751 -9,954 9,199 -6,807
Amortization of other assets 2,041 2,107 7,191 4,789 9,845 5,429
Other -751 70 542 929 262 -362
Other changes in assets and liabilities -
Accounts receivable 9,118 -9,714 11,418 -3,557 -246 -12,378
Production fuel, materials and supplies -957 963 -473 132 3,445 -2,362
Accounts payable -1,840 4,092 -12,078 -11,703 2,527 12,803
Accrued taxes 21,164 31,909 8,777 29,071 -10,860 9,679
Provision for rate refunds -43 2,759 -106 12,966 -12,966 12,966
Adjustment clause balances -3,559 -7 -3,898 1,903 -1,220 969
Gas in storage -8,610 -4,737 635 5,403 -1,523 4,457
Other -2,744 -4,125 1,980 -1,049 3,431 -585
Net cash flows from operating activities 70,721 86,652 161,313 175,482 181,519 210,008
Cash flows from financing activities:
Dividends declared on common stock -15,725 -15,404 -46,950 -45,903 -62,438 -61,012
Proceeds from issuance of common stock 3,381 3,494 10,780 11,495 14,901 14,402
Purchase of treasury stock 0 0 -269 0 -269 0
Net change in IES Diversified Inc.
credit facility -2,954 28,200 8,016 7,500 44,261 23,000
Proceeds from issuance of other
long-term debt 60,000 0 60,000 50,004 110,003 50,004
Reductions in other long-term debt -15,078 -71 -15,374 -50,351 -65,447 -50,417
Net change in short-term borrowings -47,000 -38,000 -23,000 12,000 29,000 49,000
Principal payments under capital
lease obligations -4,626 -3,314 -14,162 -9,529 -19,096 -13,608
Sale of utility accounts receivable 0 9,000 7,000 11,000 0 12,000
Other -112 95 -203 317 -1,817 369
Net cash flows from financing activities -22,114 -16,000 -14,162 -13,467 49,098 23,738
Cash flows from investing activities:
Construction and acquisition expenditures -
Utility -39,701 -31,519 -97,043 -89,323 -133,483 -146,369
Other -11,859 -39,046 -45,665 -58,318 -79,683 -84,222
Oil and gas properties held for resale 0 0 9,843 0 0 0
Deferred energy efficiency expenditures -3,887 -4,987 -12,643 -12,965 -17,708 -17,611
Nuclear decommissioning trust funds -1,502 -1,832 -4,506 -4,598 -6,008 -5,981
Proceeds from disposition of assets 1,984 3,865 3,840 9,920 8,153 15,515
Other 204 -2,105 447 -7,297 2,051 -3,369
Net cash flows from investing activities -54,761 -75,624 -145,727 -162,581 -226,678 -242,037
Net increase (decrease) in cash and temporary
cash investments -6,154 -4,972 1,424 -566 3,939 -8,291
Cash and temporary cash investments
at beginning of period 14,520 9,399 6,942 4,993 4,427 12,718
Cash and temporary cash investments
at end of period $ 8,366 $ 4,427 $ 8,366 $ 4,427 $ 8,366 $ 4,427
Supplemental cash flow information:
Cash paid during the period for -
Interest $ 12,899 $ 9,860 $ 36,435 $ 34,821 $ 52,480 $ 47,418
Income taxes $ 3,568 $ 1,239 $ 36,316 $ 9,588 $ 53,206 $ 23,736
Noncash investing and financing activities -
Capital lease obligations incurred $ 939 $ 149 $ 13,785 $ 2,807 $ 13,896 $ 5,851
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
September 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
1.14 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 and by the shareholders of each company. It is still subject
to approval by several federal and state regulatory agencies. The
companies expect to receive such 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. The Company's Board of Directors rejected MAEC's
offer and the shareholders of the Company subsequently approved the
Proposed Merger, thereby also rejecting MAEC's offer.
(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 allowed 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 was a refund obligation of approximately $43,000 which was
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; the application was later withdrawn and
will be resubmitted in either the fourth quarter of 1996 or the first
quarter of 1997 and the companies intend to include the same proposal in
the resubmittal of the filing. 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. These costs are being recovered over a
four-year period and the recovery began on June 1, 1995. In December
1996, under provisions of the IUB rules, the Company will file for
recovery of the costs relating to its 1994 and 1995 programs.
Iowa statutory changes enacted in 1996, and applicable to future
programs once the legislation is adopted by the IUB, 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 September 30, 1996, $65 million was
sold under the agreement.
(5) INVESTMENTS:
(a) Foreign Entities -
At September 30, 1996, the Company had $29.9 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 September 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 September 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 September
30, 1996, on the Nasdaq National Market, was $33.00 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 -
In September 1996, Utilities repaid at maturity $15 million of
Series J, 6.25% First Mortgage Bonds and, in a separate transaction,
issued $60 million of Collateral Trust Bonds, 7.25%, due 2006.
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 September 30, 1996, there were no borrowings
outstanding under this facility. Diversified had $132.3 million of
commercial paper outstanding at September 30, 1996, with interest rates
ranging from 5.52% to 6.00% and maturity dates in the fourth quarter of
1996. Diversified intends to continue borrowing under the renewal
options of the facility and no conditions exist at September 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 has commenced negotiations seeking to increase the
maximum permitted borrowings under the agreement from $150 million to
$300 million and to extend the length of the agreement. No assurance
can be given that a new agreement can be reached.
(b) Short-Term Debt -
At September 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 $78 million
to support commercial paper (weighted average interest rate of 5.47%)
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 September 30, 1996, there were no borrowings outstanding under this
facility.
(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
September 30, 1996, the agreement, if settled on that date, would have
required the counterparty to pay the Company approximately $1.8 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 million in its Consolidated Balance Sheets at September 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 $22
million to $54 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $34 million (including $4.6 million as
current liabilities) at September 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 September
30, 1996. Regulatory assets of approximately $34 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, $10.7 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, $3.6
million at September 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 $23.5 million,
including $7.4 million in 1996 (of which $4.1 million was expended as of
September 30, 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 currently exploring its options to modify one of its fossil
generating facilities to reduce 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 aggregate 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
September 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 $2.0 million expected to be billed through
September 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 $4.1 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
1.14 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 and by the shareholders of each company. It is still subject
to approval by several federal and state regulatory agencies. The
companies expect to receive such 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. The Company's Board of Directors rejected MAEC's
offer and the shareholders of the Company subsequently approved the
Proposed Merger, thereby also rejecting MAEC's offer.
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 decreased ($10.2) million, ($7.3) million
and ($6.3) million during the three, nine and twelve month periods,
respectively. Earnings per average common share decreased ($0.36),
($0.29) and ($0.27) for the respective periods. The decrease in
earnings for all three periods was primarily due to cooler weather
conditions during the third quarter of 1996 as compared to the third
quarter of 1995 and costs incurred relating to the successful defense of
the hostile takeover attempt mounted by MAEC. The weather conditions in
the third quarter of 1996 and 1995 were cooler than normal and
significantly warmer than normal, respectively. Accordingly, the
Company estimates the weather conditions impacted the quarterly earnings
by approximately $0.28 per share on a comparative basis. The company
estimates that hostile takeover defense costs reduced earnings for the
three periods by $0.15 per share. Increased operating expenses and a
higher effective income tax rate also adversely impacted earnings for
the three periods. These items were partially offset by sales growth in
Utilities' service territory, the impact of a natural gas pricing
increase implemented in the fourth quarter of 1995 and increased
earnings at the Company's oil and gas subsidiary, Whiting Petroleum
Corporation (Whiting).
The Company's operating income increased or (decreased) ($8.0)
million, $0.2 million and $5.5 million during the three, nine and twelve
month periods, respectively. The contrasting relationship between the
change in operating income and net income was primarily due to the
hostile takeover defense costs of $7.5 million which are included in
"Miscellaneous, net" in the Consolidated Statements of Income. Reasons
for the changes in the results of operations are explained in the
following discussion.
Electric Revenues Electric revenues and Kwh sales (before off-system
sales) for Utilities increased or (decreased) as compared with the prior
period as follows:
Changes vs. Prior Period
Three Nine Twelve
Months Months Months
($ in millions)
Total electric revenues $ (10.3) $ 2.5 $ 4.8
Off-system sales revenues (2.0) 2.1 3.6
Electric revenues (excluding off-system sales) $ (8.3) $ 0.4 $ 1.2
Electric sales (excluding off-system sales):
Residential and Rural (17.9)% (4.7)% (2.8)%
General Service (7.9) (2.9) 0.1
Large General Service 5.2 3.5 4.4
Total (3.9) 0.2 1.5
Weather had a significant impact on sales during the three and nine
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, nine and twelve month periods would have increased 4.9%, 2.7% and
2.9%, respectively. The sales comparisons for the nine and twelve month
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 all three 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.
The decrease in the electric revenues during the three month period
was primarily due to the weather-related decrease in sales to consumers
as discussed previously, lower fuel costs collected through the EAC and
lower off-system sales. The nine and twelve month increases were
primarily due to increased sales to consumers, higher off-system sales
and the recovery of expenditures for energy efficiency programs pursuant
to an Iowa Utilities Board (IUB) order. The impact of the nine and
twelve month increases was partially offset by the 1995 unbilled revenue
adjustment.
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 September 30, 1996, as compared with the prior periods, as
follows:
Changes vs. Prior Period
Three Nine Twelve
Months Months Months
($ in millions)
Gas revenues:
Utilities $ (2.0) $ 14.6 $ 24.1
Industrial Energy Applications, Inc. (IEA) 0.7 19.7 25.4
$ (1.3) $ 34.3 $ 49.5
Utilities' gas sales:
Residential (8.2)% 11.7% 14.9%
Commercial (11.2) 8.6 11.7
Industrial (5.3) 2.2 (5.5)
Sales to consumers (8.6) 9.7 11.4
Transported volumes (15.3) (6.3) (3.4)
Total (12.2) 4.9 7.2
Under historically normal weather conditions, Utilities' gas sales
and transported volumes would have increased or (decreased) (12.1)%,
0.1% and 0.7% during the three, nine 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%. The IUB 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 which
allowed Utilities a $6.3 million annual increase. Refer to Note 3(a) of
the Notes to Consolidated Financial Statements for a further discussion
of the gas rate case.
Utilities' gas revenues increased during both the nine 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 three month decrease in
Utilities' gas revenues was due to lower gas costs recovered through the
PGA partially offset by the gas pricing increase.
The increases in IEA's gas revenues during all periods were
primarily due to higher unit gas costs, although a 9% increase in
volumes sold also contributed to the twelve month increase. The three
month increase was partially offset by a 35% decrease in gas volumes
sold primarily due to a decrease in gas required for generation
facilities used during peak electric demand periods, as a direct result
of the mild 1996 summer compared to the exceptionally warm 1995 summer.
Other Revenues Other revenues increased $7.0 million, $16.6 million
and $20.2 million during the three, nine and twelve month periods,
respectively, primarily because of increased revenues at Whiting due to
increases in oil and gas prices and increases in gas volumes sold. An
increase in Utilities' steam revenues, due to increased volumes sold,
also contributed to the increase for all periods.
Operating Expenses Fuel for production increased or (decreased) ($2.8)
million, $0.5 million and $7.2 million during the three, nine and twelve
month periods, respectively. The three month decrease was primarily due
to lower Kwh generation, due to the decreased sales, and lower average
fuel costs. The twelve month increase was 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). There was no refueling outage during the
first nine months of 1996.
Purchased power increased or (decreased) ($1.3) million, $1.7
million and ($5.5) million during the three, nine and twelve month
periods, respectively. The three and twelve month decreases were due to
decreased energy purchases with lower capacity costs also contributing
to the twelve month decrease. The nine month increase was due to
increased energy purchases, partially offset by lower capacity costs.
Gas purchased for resale increased or (decreased) ($2.1) million,
$24.8 million and $35.6 million during the three, nine and twelve month
periods, respectively. The three month decrease was primarily due to
the timing of the recovery of gas costs through the PGA and decreased
gas sales, partially offset by the effects of higher average natural gas
prices. The nine and twelve month increases were due to higher average
natural gas prices and increased sales, partially offset by the timing
of the recovery of gas costs through the PGA.
Other operating expenses increased $5.6 million, $16.4 million and
$25.5 million during the three, nine and twelve month periods,
respectively. Contributing to the increase in all periods were
increased operating activities at Whiting and IEA, increased labor and
benefits costs at Utilities and costs incurred in the Company's efforts
to prepare for an increasingly competitive utility industry including,
among other items, costs relating to the Proposed Merger and the
Company's reengineering effort (Process Redesign). The nine and twelve
month increases were also due to the amortization of previously deferred
energy efficiency expenditures at Utilities (which are currently being
recovered through rates) and were partially offset by lower former
manufactured gas plant (FMGP) clean-up costs at Utilities.
Maintenance expenses increased or (decreased) $1.5 million, $4.0
million and ($0.5) million during the three, nine and twelve month
periods, respectively. The three and nine month increases were
primarily due to increased maintenance activities at Utilities' fossil-
fueled generating stations.
Depreciation and amortization increased during all periods because
of increases in utility plant in service and the depreciation of oil and
gas operating properties. The increases for the three and nine month
periods were also due to an adjustment recorded in the third quarter of
1995 to implement lower depreciation rates as a result of an IUB rate
order. Depreciation and amortization expenses for all periods included
a provision for decommissioning the DAEC, which is collected through
rates. The current annual recovery level is $6.0 million.
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.
Taxes other than income taxes decreased ($0.7) million, ($1.5)
million and ($2.3) million during the three, nine and twelve month
periods, respectively, primarily because of decreased property taxes at
Utilities, resulting from lower assessed property values.
Interest Expense and Other Interest expense increased $1.0 million,
$1.8 million and $3.0 million during the three, nine 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, partially attributable to refinancing long-term debt at
lower rates and the mix of long-term and short-term debt, and interest
related to Utilities' electric rate refund, which was recorded in the
prior periods, partially offset these items.
Miscellaneous, net reflects comparative decreases in income of
($6.1) million, ($4.3) million and ($5.1) million for the three, nine
and twelve month periods, respectively. The decreases for all three
periods were primarily due to approximately $7.5 million in costs
incurred relating to the successful defense of the hostile takeover
attempt mounted by MAEC. The decreases were partially offset by
dividends received from the two New Zealand entities in which the
company has equity investments and various gains realized on the
disposition of assets.
Income Taxes Income taxes increased or (decreased) ($4.9) million,
$0.9 million and $3.0 million for the three, nine 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, 2) the effect of prior
period adjustments, and 3) the incurrence of certain merger-related
expenses, which are not tax deductible.
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 2.93 and 3.11 for the twelve months ended
September 30, 1996 and September 30, 1995, respectively. Cash flows
from operating activities for the twelve months ended September 30, 1996
and September 30, 1995 were $182 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.
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
Utilities' credit ratings are under review for potential upgrade
related to the Proposed Merger.
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 September 30, 1996, Utilities had
approximately $58 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 September 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 September
30, 1996, on the Nasdaq National Market, was $33.00 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 $143 million
for the nine months ended September 30, 1996, including approximately
$97 million of utility expenditures and $46 million of non-utility
expenditures.
The Company's levels of construction and acquisition expenditures
are projected to be $225 million in 1997, and approximately $200 - 250
million per year in 1998 - 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 $ 125.1
Diversified's credit facility 132.3
Other subsidiaries' debt 11.2
$ 268.6
The Company intends to refinance the majority of the debt
maturities with long-term securities.
In September 1996, Utilities repaid at maturity $15 million of
Series J, 6.25% First Mortgage Bonds and, in a separate transaction,
issued $60 million of Collateral Trust Bonds, 7.25%, due 2006.
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 September
30, 1996, such restrictions would have allowed Utilities to issue at
least $229 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 $190 million of remaining authority under the current FERC
docket through April 1998, and $140 million of remaining authority under
the current SEC shelf registration.
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 September 30, 1996, there were no borrowings
outstanding under this facility. Diversified had $132.3 million of
commercial paper outstanding at September 30, 1996, with interest rates
ranging from 5.52% to 6.00% and maturity dates in the fourth quarter of
1996. Diversified intends to continue borrowing under the renewal
options of the facility and no conditions exist at September 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.
Diversified has commenced negotiations seeking to increase the
maximum permitted borrowings under the agreement from $150 million to
$300 million and to extend the length of the agreement. No assurance
can be given that a new agreement can be reached.
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 September 30, 1996,
Utilities could have issued an additional 700,000 shares of Cumulative
Preference Stock and no 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 September 30, 1996.
The Company's capitalization ratios at September 30, 1996, were as
follows:
Long-term debt 51%
Preferred stock 1
Common equity 48
100%
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. Utilities
will be making a filing with FERC in the fourth quarter of 1996 to
extend such authorization. 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
September 30, 1996, Utilities had outstanding short-term borrowings of
$82.2 million, including $4.2 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 September 30, 1996, $65 million was
sold under the agreement.
At September 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 $78 million to support commercial paper (weighted
average interest rate of 5.47%) 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 September 30, 1996, there were no
borrowings outstanding under this facility.
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 $22
million to $54 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $34 million (including $4.6 million as
current liabilities) at September 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 September
30, 1996. Regulatory assets of approximately $34 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 of approximately $23.5 million,
including $7.4 million in 1996 (of which $4.1 million was expended as of
September 30, 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 currently exploring its options to modify one of its fossil
generating facilities to reduce 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 aggregate 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, $10.7
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 the Nuclear Waste Fund
(NWF) held by the U.S. Treasury. 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 2001. Utilities is aggressively
reviewing options for additional spent nuclear fuel storage capability,
including expanding on-site storage. In July 1996, the IUB initiated a
Notice of Inquiry (NOI) on spent nuclear fuel. One purpose of the NOI
was to evaluate whether the current collection of money from Utilities'
customers for payment to the NWF should be placed in an escrow account
in lieu of being paid to the NWF. Utilities does not support this
alternative and cannot predict the outcome of this NOI.
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
September 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 was approved in 1996 by all six
states that are members of the Compact. Final approval by the U.S.
Congress is now required. 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 currently 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. However,
management of the Barnwell site is in the process of modifying its fee
schedule to include more emphasis on total radioactivity content, in
addition to volume related fees. Utilities cannot predict the outcome
of these changes on its potential future disposal costs at the Barnwell
site or if such changes would result in a revision to Utilities' future
disposal plans.
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 recent
study completed by the National Research Council concluded that the
current body of evidence does not support the notion that exposure to
these fields may result in adverse health effects. Utilities will
continue to monitor the events in this area, including future scientific
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, $3.6
million at September 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; 3) utilities must separate the energy
marketing function from the transmission system operation function, to
insure there is not inappropriate information being used by energy
marketing; and 4) utilities can recover "stranded costs" applicable to
wholesale sales. 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 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. These meetings began in
September 1996 and are scheduled to be completed in the fourth quarter
of 1996.
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 and/or services 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 September 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 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 grant of summary judgment
has reduced Mr. Wiley's claims against the remaining parties to breach
of fiduciary duty. A separate motion for summary judgment, which was
filed seeking dismissal of the remaining claims against the remaining
parties, was overruled on September 20, 1996, and the trial has been
continued, but not re-scheduled. All of the defendants are vigorously
contesting the claims.
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 was remanded back to the District Court for
consideration of the expert testimony, but with no additional evidence
taken. The District Court re-affirmed its original decision on August
28, 1996, and the Corporation has again appealed to the Iowa Supreme
Court.
On August 21, 1996, a class petition was filed in Iowa District
Court for Linn County against the Company, its Board of Directors and/or
certain executive officers. The petition seeks to force the Company to
negotiate a merger with MAEC and rescind the Merger Agreement, as well
as seeking appropriate compensatory damages. The Company has not been
served with the petition and, accordingly, has not undertaken a full
evaluation of its merits.
On October 3, 1996, Lambda Energy Marketing Company, L. C.
("Lambda") filed a request with the IUB that the IUB initiate formal
complaint proceedings against Utilities. Lambda alleges that Utilities
is discriminating against it by refusing to enter into contracts with it
for remote displacement service and by favoring IEA, a subsidiary of the
Company, in such matters. On October 17, 1996, Utilities filed a
Response which denies the allegations, a Motion for Bifurcation, a
Motion of Summary Judgment, a Countercomplaint and a Request for
Temporary Relief, alleging, inter alia, that Lambda is unlawfully
attempting to provide retail electrical services in Utilities' exclusive
service territory.
On October 9, 1996, the Company filed a civil suit in the Iowa
District Court in and for Linn County against Lambda, Robert Latham,
Louie Ervin, and David Charles (collectively the "Defendants", including
three former employees of the Company and/or its subsidiaries) alleging,
inter alia, violations of Iowa's trade secret act and interference with
existing and prospective business advantage. On November 1, 1996, the
Defendants filed their Answer and Counterclaims alleging, inter alia,
violation of Iowa competition law, tortious interference and commercial
disparagement. The Defendants therewith also filed a Third-Party
Petition against Utilities, IEA and Lee Liu alleging, inter alia,
tortious interference and commercial disparagement.
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.
(a) The Company held its Annual Meeting of Shareholders on September 5,
1996.
(b) The following matters were voted upon at the Annual Meeting of
Shareholders.
(i) The election of nominees for Directors who will serve a
one-year term or until their respective successors shall be
duly elected. The nominees were all elected. The number of
votes for, against, abstaining and non-votes for each nominee
were as follows:
FOR AGAINST ABSTAIN NON-VOTES
C.R.S. Anderson 20,909,243 822,996 2,475,171 5,715,823
J. Wayne Bevis 21,032,951 705,110 2,469,349 5,715,823
Lee Liu 21,003,660 724,202 2,479,548 5,715,823
Jack R. Newman 21,016,308 720,795 2,470,307 5,715,823
Robert D. Ray 21,017,788 717,852 2,471,770 5,715,823
David Q. Reed 21,049,077 692,104 2,466,229 5,715,823
Henry Royer 21,042,319 697,422 2,467,669 5,715,823
Robert W. Schlutz 21,050,482 690,600 2,466,328 5,715,823
Anthony R. Weiler 21,039,017 701,579 2,466,814 5,715,823
(ii) A proposal to approve the 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. The vote
was as follows:
FOR AGAINST ABSTAIN NON-VOTES
16,248,843 7,032,214 926,105 5,716,071
Item 5. Other Information.
On November 6, 1996, Larry D. Root, who retired in 1995, was named
President & Chief Operating Officer of the Company. Lee Liu will
continue to serve as Chairman of the Board & Chief Executive Officer.
On November 6, 1996, James E. Hoffman, was named Executive Vice
President of the Company. Mr. Hoffman will also continue to serve as
Executive Vice President of IES Utilities.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits -
2(a) 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).
2(b) Amendment No. 2 to Agreement and Plan of Merger, as
amended, dated August 16, 1996, by and among IES Industries
Inc., WPL Holdings, Inc., Interstate Power Company, WPLH
Acquisition Co. and Interstate Power Company. (Filed as Annex
I to the Supplement to Joint Proxy Statement of WPL Holdings,
Inc., IES Industries Inc. and Interstate Power Company, dated
August 21, 1996).
*3(a) Bylaws of Registrant, as amended November 6, 1996.
4(a) Sixty-second Supplemental Indenture, dated as of
September 1, 1996, supplementing Utilities' Indenture of
Mortgage and Deed of Trust, dated August 1, 1940. (Filed as
Exhibit 4(f) to Utilities' Current Report on Form 8-K, dated
September 19, 1996 (File No. 0-4117-1)).
4(b) Fourth Supplemental Indenture, dated as of September 1,
1996, supplementing Utilities' Indenture of Mortgage and Deed
of Trust, dated September 1, 1993. (Filed as Exhibit 4(c)(i)
to Utilities' Current Report on Form 8-K, dated September 19,
1996 (File No. 0-4117-1)).
*10(a) Executive Change of Control Severance Agreement - CEO
*10(b) Executive Change of Control Severance Agreement - Vice Presidents
*10(c) Executive Change of Control Severance Agreement - Other Officers
*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 August 16, 1996 (1)
(1) The Form 8-K report was filed on August 27, 1996 with the
earliest event reported occurring on August 16, 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: November 13, 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