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 June 30, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 0-4117-1
IES UTILITIES INC.
(Exact name of registrant as specified in its charter)
Iowa 42-0331370
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
IES Tower, Cedar Rapids, Iowa 52401
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (319) 398-4411
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes X No ___
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Class Outstanding at July 31, 1996
Common Stock, $2.50 par value 13,370,788 shares
IES UTILITIES INC.
INDEX
Page No.
Part I. Financial Information.
Item 1. Consolidated Financial Statements.
Consolidated Balance Sheets -
June 30, 1996 and December 31, 1995 3 - 4
Consolidated Statements of Income -
Three, Six and Twelve Months Ended
June 30, 1996 and 1995 5
Consolidated Statements of Cash Flows -
Three, Six and Twelve Months Ended
June 30, 1996 and 1995 6
Notes to Consolidated Financial Statements 7 - 19
Item 2. Management's Discussion and Analysis of the
Results of Operations and Financial Condition. 20 - 42
Part II. Other Information. 43 - 45
Signatures. 46
PART 1. - FINANCIAL INFORMATION
ITEM 1. - CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED BALANCE SHEETS
June 30,
1996 December 31,
ASSETS (Unaudited) 1995
(in thousands)
Property, plant and equipment:
Utility -
Plant in service -
Electric $ 1,921,426 $ 1,900,157
Gas 167,760 165,825
Other 109,088 106,396
2,198,274 2,172,378
Less - Accumulated depreciation 996,595 950,324
1,201,679 1,222,054
Leased nuclear fuel, net of amortization 40,532 36,935
Construction work in progress 82,070 52,772
1,324,281 1,311,761
Other, net of accumulated depreciation and
amortization of $1,356,000 and
$1,166,000, respectively 5,123 5,477
1,329,404 1,317,238
Current assets:
Cash and temporary cash investments 118 2,734
Accounts receivable -
Customer, less reserve 11,497 18,619
Other 8,059 8,912
Income tax refunds receivable 8,572 846
Production fuel, at average cost 12,821 12,155
Materials and supplies, at average cost 22,399 27,229
Regulatory assets 24,772 22,791
Prepayments and other 10,266 18,556
98,504 111,842
Investments:
Nuclear decommissioning trust funds 52,084 47,028
Cash surrender value of life insurance policies 3,920 3,582
Other 454 475
56,458 51,085
Other assets:
Regulatory assets 211,776 207,202
Deferred charges and other 21,697 21,268
233,473 228,470
$ 1,717,839 $ 1,708,635
CONSOLIDATED BALANCE SHEETS (CONTINUED)
June 30,
1996 December 31,
CAPITALIZATION AND LIABILITIES (Unaudited) 1995
(in thousands)
Capitalization:
Common stock - par value $2.50 per share -
authorized 24,000,000 shares; 13,370,788
shares outstanding $ 33,427 $ 33,427
Paid-in surplus 279,042 279,042
Retained earnings 211,422 212,522
Total common equity 523,891 524,991
Cumulative preferred stock - par value
$50 per share - authorized 466,406 shares;
366,354 shares outstanding 18,320 18,320
Long-term debt (excluding current portion) 457,422 465,463
999,633 1,008,774
Current liabilities:
Notes payable to associated companies 4,575 8,888
Other short-term borrowings 125,000 101,000
Capital lease obligations 13,883 15,717
Maturities and sinking funds 23,140 15,140
Accounts payable 48,332 64,564
Accrued interest 9,014 8,038
Accrued taxes 45,137 50,369
Accumulated refueling outage provision 12,610 7,690
Adjustment clause balances 2,809 3,148
Environmental liabilities 5,421 5,521
Other 19,726 17,300
309,647 297,375
Long-term liabilities:
Pension and other benefit obligations 46,229 41,866
Capital lease obligations 26,649 21,218
Environmental liabilities 40,668 40,905
Other 6,881 8,719
120,427 112,708
Deferred credits:
Accumulated deferred income taxes 252,339 252,663
Accumulated deferred investment tax
credits 35,793 37,115
288,132 289,778
Commitments and contingencies (Note 6)
$ 1,717,839 $ 1,708,635
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
<TABLE>
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
<CAPTION>
For the For the For the
Three Months Ended Six Months Ended Twelve Months Ended
June 30 June 30 June 30
1996 1995 1996 1995 1996 1995
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Operating revenues:
Electric $ 137,032 $ 133,048 $ 262,400 $ 249,626 $ 573,246 $ 539,964
Gas 22,445 21,852 91,686 75,027 153,951 125,762
Other 4,763 2,771 8,922 5,858 15,126 10,118
164,240 157,671 363,008 330,511 742,323 675,844
Operating expenses:
Fuel for production 22,728 20,304 43,021 39,746 99,530 87,050
Purchased power 22,000 17,130 36,469 33,444 69,899 71,412
Gas purchased for resale 12,042 13,454 59,411 51,587 99,021 82,929
Other operating expenses 36,555 32,644 74,912 67,056 153,106 137,385
Maintenance 14,333 10,611 24,325 22,290 45,621 47,637
Depreciation and amortization 22,024 20,728 44,049 41,317 82,116 78,313
Taxes other than income taxes 11,549 12,356 23,609 24,731 43,892 44,215
141,231 127,227 305,796 280,171 593,185 548,941
Operating income 23,009 30,444 57,212 50,340 149,138 126,903
Interest expense and other:
Interest expense 10,988 11,731 21,880 22,190 44,151 43,001
Allowance for funds used during
construction -691 -785 -1,380 -1,900 -2,904 -3,934
Miscellaneous, net -176 588 -1,139 595 -880 -406
10,121 11,534 19,361 20,885 40,367 38,661
Income before income taxes 12,888 18,910 37,851 29,455 108,771 88,242
Income taxes:
Current 4,994 4,959 18,355 2,975 48,847 27,143
Deferred 1,325 3,556 -538 10,597 -821 9,527
Amortization of investment
tax credits -661 -672 -1,323 -1,345 -2,663 -2,668
5,658 7,843 16,494 12,227 45,363 34,002
Net income 7,230 11,067 21,357 17,228 63,408 54,240
Preferred dividend requirements 229 229 457 457 914 914
Net income available for
common stock $ 7,001 $ 10,838 $ 20,900 $ 16,771 $ 62,494 $ 53,326
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</TABLE>
<TABLE>
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
<CAPTION>
For the Three For the Six For the Twelve
Months Ended Months Ended Months Ended
June 30 June 30 June 30
1996 1995 1996 1995 1996 1995
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Cash flows from operating activities:
Net income $ 7,230 $ 11,067 $ 21,357 $ 17,228 $ 63,408 $ 54,240
Adjustments to reconcile net income to
net cash flows from operating activities -
Depreciation and amortization 22,024 20,728 44,049 41,317 82,116 78,313
Amortization of principal under capital
lease obligations 4,626 3,311 9,250 5,867 19,096 13,608
Deferred taxes and investment tax credits 664 2,884 -1,861 9,252 -3,484 6,859
Refueling outage provision 2,373 -4,432 4,920 -12,960 10,374 -6,475
Amortization of other assets 2,194 1,587 5,104 2,643 9,853 3,776
Other 65 -60 61 -323 586 -618
Other changes in assets and liabilities -
Accounts receivable 8,434 4,419 975 4,545 -13,287 2,226
Production fuel, materials and supplies 26 -2,879 928 -2,931 5,517 -5,409
Accounts payable -3,068 -14,178 -13,365 -18,959 1,200 10,071
Accrued taxes -30,028 -12,237 -12,958 -6,020 -1,153 573
Provision for rate refunds -229 2,207 -63 10,207 -10,164 10,207
Adjustment clause balances -3,726 -2,325 -339 1,910 2,332 -2,599
Gas in storage 1,501 1,948 9,245 9,324 2,350 2,285
Other 2,865 -1,493 4,372 4,922 -1,703 7,810
Net cash flows from operating activities 14,951 10,547 71,675 66,022 167,041 174,867
Cash flows from financing activities:
Dividends declared on common stock -12,000 -10,000 -22,000 -23,000 -42,000 -53,000
Dividends declared on preferred stock -229 -229 -457 -457 -914 -914
Proceeds from issuance of long-term debt 0 0 0 50,000 50,000 50,000
Reductions in long-term debt -140 -140 -140 -50,140 -50,140 -50,140
Net change in short-term borrowings 34,334 49,237 19,687 37,286 36,794 75,515
Principal payments under capital lease
obligations -4,624 -2,556 -9,536 -6,218 -17,781 -14,375
Sale of utility accounts receivable 7,000 -8,000 7,000 2,000 9,000 3,000
Other -86 0 -172 0 -1,936 0
Net cash flows from financing activities 24,255 28,312 -5,618 9,471 -16,977 10,086
Cash flows from investing activities:
Construction and acquisition expenditures -
Utility -34,009 -30,351 -57,383 -57,995 -125,492 -155,901
Other -146 -1,405 -342 -1,977 -1,705 -3,840
Deferred energy efficiency expenditures -5,090 -4,441 -8,757 -7,978 -18,808 -16,964
Nuclear decommissioning trust funds -1,502 -1,383 -3,004 -2,766 -6,338 -5,532
Other 1,225 -2,288 813 -5,431 916 -1,926
Net cash flows from investing activities -39,522 -39,868 -68,673 -76,147 -151,427 -184,163
Net increase (decrease) in cash and temporary
cash investments -316 -1,009 -2,616 -654 -1,363 790
Cash and temporary cash investments at
beginning of period 434 2,490 2,734 2,135 1,481 691
Cash and temporary cash investments at
end of period $ 118 $ 1,481 $ 118 $ 1,481 $ 118 $ 1,481
Supplemental cash flow information:
Cash paid during the period for -
Interest $ 11,046 $ 13,819 $ 19,576 $ 22,073 $ 42,072 $ 41,132
Income taxes $ 24,430 $ 8,533 $ 31,568 $ 11,383 $ 49,268 $ 29,256
Noncash investing and financing activities -
Capital lease obligations incurred $ 10,243 $ 1,542 $ 12,846 $ 2,658 $ 13,106 $ 16,531
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
June 30, 1996
(1) GENERAL:
The interim Consolidated Financial Statements have been prepared by
IES Utilities Inc. (Utilities) and its consolidated subsidiaries
(collectively the Company), without audit, pursuant to the rules and
regulations of the United States Securities and Exchange Commission
(SEC). Utilities is a wholly-owned subsidiary of IES Industries Inc.
(Industries). Utilities' wholly-owned subsidiary is IES Ventures Inc.
(Ventures), which is a holding company for unregulated investments.
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.
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. 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
Preferred and preference stock
Debt (other than discussed in Note 5)
Estimated fair value of financial instruments
Commitments and contingencies (other than discussed in Note 6)
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 Industries' common stock will
receive 1.01 shares of Interstate Energy common stock for each share of
Industries' common stock. The Proposed Merger, which will be accounted
for as a pooling of interests, has been approved by the respective
Boards of Directors. It is still subject to approval by the
shareholders of each company as well as several federal and state
regulatory agencies. The companies mailed the joint proxy statement to
their shareholders the week of July 23, 1996. The companies expect to
receive the shareholder approvals in the third quarter of 1996 and
regulatory approvals by the summer of 1997. The corporate headquarters
of Interstate Energy will be in Madison, Wisconsin.
The business of Interstate Energy will consist of utility
operations and various non-utility enterprises. The utility
subsidiaries currently serve approximately 870,000 electric customers
and 360,000 natural gas customers in Iowa, Wisconsin, Illinois and
Minnesota.
(b) Unsolicited Acquisition Proposal -
On August 5, 1996, MidAmerican Energy Company (MAEC), an electric
and natural gas utility company based in Des Moines, Iowa, announced
that it had made an unsolicited offer to acquire Industries in a cash
and stock transaction. Under the terms of the offer, Industries would
merge with and into MAEC in a transaction in which Industries'
shareholders would receive up to 40% in cash and the remainder in shares
of MAEC common stock. Industries' shareholders receiving cash would
receive $39 for each Industries' share and shareholders receiving shares
would receive 2.346 shares of MAEC stock for each Industries' share. On
August 12, 1996, the closing price for MAEC stock on the NYSE was $15.75
per share. MAEC has stated that, if Industries and MAEC do not promptly
reach agreement with respect to a business combination between the two
companies, MAEC will solicit proxies against the Proposed Merger for use
at the upcoming Industries' shareholder meeting. Industries cannot
currently determine what, if any, impact the unsolicited offer of MAEC
may have on the Proposed Merger. The proposal will be given full
consideration by Industries' Board of Directors.
(3) RATE MATTERS:
(a) 1995 Gas Rate Case -
On August 4, 1995, Utilities applied to the Iowa Utilities Board
(IUB) for an annual increase in gas rates of $8.8 million, or 6.2%. An
interim increase of $8.6 million was requested and the IUB,
subsequently, approved an interim increase of $7.1 million annually,
effective October 11, 1995, subject to refund. On April 4, 1996, the
IUB issued an order approving a settlement agreement entered into by
Utilities, the Office of Consumer Advocate and all three industrial
intervenor groups, which allows Utilities a $6.3 million annual
increase. Utilities subsequently filed final compliance tariffs which
became effective on May 30, 1996. Primarily because of changes in rate
design, there is a refund obligation of approximately $43,000 which will
be made in the third quarter of 1996.
(b) Electric Price Announcements -
Utilities and its Iowa-based proposed merger partner, IPC,
announced in April their intentions to hold retail electric prices to
their current levels until at least January 1, 2000. The companies made
the proposal as part of their testimony in the merger-related
application filed with the IUB, which was later withdrawn and will be
resubmitted at a future date. (The companies intend to include the same
proposal in the resubmittal of the filing.) The companies did specify
that the proposal excludes price changes due to government-mandated
programs, such as energy efficiency cost recovery, or unforeseen
dramatic changes in operations.
Utilities, Wisconsin Power and Light Company (the utility
subsidiary of WPLH) and IPC also agreed to freeze their wholesale
electric prices for four years from the effective date of the merger as
part of their merger filing with the Federal Energy Regulatory
Commission (FERC). The Company does not expect the merger-related
electric price proposals to have a material adverse effect on its
financial position or results of operations.
(c) Energy Efficiency Cost Recovery -
Current IUB rules mandate Utilities to spend 2% of electric and
1.5% of gas gross retail operating revenues for energy efficiency
programs. Under provisions of the IUB rules, Utilities is currently
recovering the energy efficiency costs incurred through 1993 for such
programs, including its direct expenditures, carrying costs, a return on
its expenditures and a reward. Recovery of the costs will be over a
four-year period and began on June 1, 1995. In October 1996, under
provisions of the IUB rules, the Company will file for recovery of the
costs relating to its 1994 and 1995 programs ($31.9 million as of June
30, 1996).
Iowa statutory changes enacted recently have eliminated both: 1)
the 2% and 1.5% spending requirements described above in favor of IUB-
determined energy savings targets and 2) the delay in recovery of energy
efficiency costs by allowing recovery which is concurrent with spending.
This will eventually eliminate the regulatory asset which exists under
the current rate making mechanism.
(4) UTILITY ACCOUNTS RECEIVABLE:
Utilities has entered into an agreement, which expires in 1999,
with a financial institution to sell, with limited recourse, an
undivided fractional interest of up to $65 million in its pool of
utility accounts receivable. At June 30, 1996, $65 million was sold
under the agreement.
(5) DEBT:
At June 30, 1996, the Company had bank lines of credit aggregating
$121.1 million, of which $108 million was being used to support
commercial paper (weighted average interest rate of 5.40%) and $11.1
million to support certain pollution control obligations. Commitment
fees are paid to maintain these lines and there are no conditions which
restrict the unused lines of credit. In addition to the above,
Utilities has an uncommitted credit facility with a financial
institution whereby it can borrow up to $40 million. Rates are set at
the time of borrowing and no fees are paid to maintain this facility.
At June 30, 1996, there was $17 million outstanding under this facility
(weighted average interest rate of 5.57%).
(6) CONTINGENCIES:
(a) Environmental Liabilities -
The Company has recorded environmental liabilities of approximately
$46 million in its Consolidated Balance Sheets at June 30, 1996. The
significant items are discussed below.
Former Manufactured Gas Plant (FMGP) Sites
Utilities has been named as a Potentially Responsible Party (PRP)
by various federal and state environmental agencies for 28 FMGP sites,
but believes it is not responsible for two of these sites based on
extensive reviews of the ownership records and historical information
available for the two sites. Utilities has notified the appropriate
regulatory agency that it believes it does not have any responsibility
as relates to these two sites, but no response has been received from
the agency on this issue. Utilities is also aware of six other sites
that it may have owned or operated in the past and for which, as a
result, it may be designated as a PRP in the future in the event that
environmental concerns arise at these sites. Utilities is working
pursuant to the requirements of the various agencies to investigate,
mitigate, prevent and remediate, where necessary, damage to property,
including damage to natural resources, at and around the sites in order
to protect public health and the environment. Utilities believes it has
completed the remediation of seven sites although it is in the process
of obtaining final approval from the applicable environmental agencies
on this issue for each site. Utilities is in various stages of the
investigation and/or remediation processes for the remaining 19 sites
and estimates the range of additional costs to be incurred for
investigation and/or remediation of the sites to be approximately $24
million to $57 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $35 million (including $4.6 million as
current liabilities) at June 30, 1996. These amounts are based upon
Utilities' best current estimate of the amount to be incurred for
investigation and remediation costs for those sites where the
investigation process has been or is substantially completed, and the
minimum of the estimated cost range for those sites where the
investigation is in its earlier stages. It is possible that future cost
estimates will be greater than the current estimates as the
investigation process proceeds and as additional facts become known; in
addition, Utilities may be required to monitor these sites for a number
of years upon completion of remediation, as is the case with several of
the sites for which remediation has been completed.
In April 1996, Utilities filed a lawsuit against certain of its
insurance carriers seeking reimbursement for investigation, mitigation,
prevention, remediation and monitoring costs associated with the FMGP
sites. Settlement discussions are proceeding between Utilities and its
insurance carriers regarding the recovery of these FMGP-related costs.
The amount of aggregate potential recovery, or the regulatory treatment
of any such recoveries, cannot be reasonably determined at this time
and, accordingly, no estimated amounts have been recorded at June
30, 1996. Regulatory assets of approximately $35 million, which reflect
the future recovery that is being provided through Utilities' rates,
have been recorded in the Consolidated Balance Sheets. Considering the
current rate treatment allowed by the IUB, management believes that the
clean-up costs incurred by Utilities for these FMGP sites will not have
a material adverse effect on its financial position or results of
operations.
National Energy Policy Act of 1992
The National Energy Policy Act of 1992 requires owners of nuclear
power plants to pay a special assessment into a "Uranium Enrichment
Decontamination and Decommissioning Fund." The assessment is based upon
prior nuclear fuel purchases and, for the Duane Arnold Energy Center
(DAEC), averages $1.4 million annually through 2007, of which Utilities'
70% share is $1.0 million. Utilities is recovering the costs associated
with this assessment through its electric fuel adjustment clauses over
the period the costs are assessed. Utilities' 70% share of the future
assessment, $10.9 million payable through 2007, has been recorded as a
liability in the Consolidated Balance Sheets, including $0.8 million
included in "Current liabilities - Environmental liabilities," with a
related regulatory asset for the unrecovered amount.
(b) Air Quality Issues -
The Clean Air Act Amendments of 1990 (Act) requires emission
reductions of sulfur dioxide (SO2) and nitrogen oxides (NOx) to achieve
reductions of atmospheric chemicals believed to cause acid rain. The
provisions of the Act are being implemented in two phases; the Phase I
requirements have been met and the Phase II requirements affect eleven
other fossil units beginning in the year 2000. Utilities expects to
meet the requirements of Phase II by switching to lower sulfur fuels,
capital expenditures primarily related to fuel burning equipment and
boiler modifications, and the possible purchase of SO2 allowances.
Utilities estimates capital expenditures at approximately $20 million,
including $4 million in 1996, in order to meet the acid rain
requirements of the Act.
The acid rain program under the Act also governs SO2 allowances.
An allowance is defined as an authorization for an owner to emit one ton
of SO2 into the atmosphere. Currently, Utilities receives a sufficient
number of allowances annually to offset its emissions of SO2 from its
Phase I units. It is anticipated that in the year 2000, Utilities may
have an insufficient number of allowances annually to offset its
estimated emissions and may have to purchase additional allowances, or
make modifications to the plants or limit operations to reduce
emissions. Utilities is reviewing its options to ensure that it will
have sufficient allowances to offset its emissions in the future.
Utilities believes that the potential cost of ensuring sufficient
allowances will not have a material adverse effect on its financial
position or results of operations.
The Act and other federal laws also require the United States
Environmental Protection Agency (EPA) to study and regulate, if
necessary, additional issues that potentially affect the electric
utility industry, including emissions relating to NOx, ozone transport,
mercury and particulate control; toxic release inventories and
modifications to the PCB rules. Currently, the impacts of these
potential regulations are too speculative to quantify.
In 1995, the EPA published the Sulfur Dioxide Network Design Review
for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-
case modeling method suggests that the Cedar Rapids area could be
classified as "nonattainment" for the National Ambient Air Quality
Standard (NAAQS) established for SO2. The worst-case modeling study
suggested that two of Utilities' generating facilities contribute to the
modeled exceedences and recommended that additional monitors be located
near Utilities' sources to assess actual ambient air quality. In the
event that Utilities' facilities contribute excessive emissions,
Utilities would be required to reduce emissions, which would primarily
entail capital expenditures for modifications to the facilities.
Utilities is planning to convert one of its fossil generating facilities
to a natural gas-fired cogeneration facility. Such facility was
contributing to the modeled exceedences thus the conversion will have
the added inherent benefit of reducing SO2 emissions. Utilities is
proposing to resolve the remainder of EPA's nonattainment concerns by
installing a new stack at the other generating facility contributing to
the modeled exceedences at a potential capital cost of up to $4.5
million over the next four years.
(c) FERC Order No. 636 -
Pursuant to FERC Order No. 636 (Order 636), which transitions the
natural gas supply business to a less regulated environment, Utilities
has enhanced access to competitively priced gas supply and more flexible
transportation services. However, under Order 636, Utilities is
required to pay certain transition costs incurred and billed by its
pipeline suppliers.
Utilities began paying the transition costs in 1993 and at June 30,
1996, has recorded a liability of $4.2 million for those transition
costs that have been incurred, but not yet billed, by the pipelines to
date, including $1.9 million expected to be billed through June 1997.
Utilities is currently recovering the transition costs from its
customers through its Purchased Gas Adjustment Clauses as such costs are
billed by the pipelines. Transition costs, in addition to the recorded
liability, that may ultimately be charged to Utilities could approximate
$4.6 million. The ultimate level of costs to be billed to Utilities
depends on the pipelines' future filings with the FERC and other future
events, including the market price of natural gas. However, Utilities
believes any transition costs that the FERC would allow the pipelines to
collect from Utilities would be recovered from its customers, based upon
regulatory treatment of these costs currently and similar past costs by
the IUB. Accordingly, regulatory assets, in amounts corresponding to
the recorded liabilities, have been recorded to reflect the anticipated
recovery.
(d) Nuclear Insurance Programs -
Public liability for nuclear accidents is governed by the Price
Anderson Act of 1988 which sets a statutory limit of $8.9 billion for
liability to the public for a single nuclear power plant incident and
requires nuclear power plant operators to provide financial protection
for this amount. As required, Utilities provides this financial
protection for a nuclear incident at the DAEC through a combination of
liability insurance ($200 million) and industry-wide retrospective
payment plans ($8.7 billion). Under the industry-wide plan, each
operating licensed nuclear reactor in the United States is subject to an
assessment in the event of a nuclear incident at any nuclear plant in
the United States. Based on its ownership of the DAEC, Utilities could
be assessed a maximum of $79.3 million per nuclear incident, with a
maximum of $10 million per incident per year (of which Utilities' 70%
ownership portion would be approximately $55 million and $7 million,
respectively) if losses relating to the incident exceeded $200 million.
These limits are subject to adjustments for changes in the number of
participants and inflation in future years.
Utilities is a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL). These companies provide $1.9 billion
of insurance coverage on certain property losses at DAEC for property
damage, decontamination and premature decommissioning. The proceeds
from such insurance, however, must first be used for reactor
stabilization and site decontamination before they can be used for plant
repair and premature decommissioning. NEIL also provides separate
coverage for the cost of replacement power during certain outages.
Owners of nuclear generating stations insured through NML and NEIL are
subject to retroactive premium adjustments if losses exceed accumulated
reserve funds. NML and NEIL's accumulated reserve funds are currently
sufficient to more than cover its exposure in the event of a single
incident under the primary and excess property damage or replacement
power coverages. However, Utilities could be assessed annually a maximum
of $3.0 million under NML, $9.8 million for NEIL property and $0.7
million for NEIL replacement power if losses exceed the accumulated
reserve funds. Utilities is not aware of any losses that it believes
are likely to result in an assessment.
In the unlikely event of a catastrophic loss at DAEC, the amount of
insurance available may not be adequate to cover property damage,
decontamination and premature decommissioning. Uninsured losses, to the
extent not recovered through rates, would be borne by Utilities and
could have a material adverse effect on Utilities' financial position
and results of operations.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF THE RESULTS OF OPERATIONS AND FINANCIAL CONDITION
The Consolidated Financial Statements include the accounts of IES
Utilities Inc. (Utilities) and its consolidated subsidiaries
(collectively the Company). Utilities is a wholly-owned subsidiary of
IES Industries Inc. (Industries). Utilities' wholly-owned subsidiary is
IES Ventures Inc. (Ventures), which is a holding company for unregulated
investments.
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 Industries' common stock will
receive 1.01 shares of Interstate Energy common stock for each share of
Industries' common stock. The Proposed Merger, which will be accounted
for as a pooling of interests, has been approved by the respective
Boards of Directors. It is still subject to approval by the
shareholders of each company as well as several federal and state
regulatory agencies. The companies mailed the joint proxy statement to
their shareholders the week of July 23, 1996. The companies expect to
receive the shareholder approvals in the third quarter of 1996 and
regulatory approvals by the summer of 1997. The corporate headquarters
of Interstate Energy will be in Madison, Wisconsin.
The business of Interstate Energy will consist of utility
operations and various non-utility enterprises. The utility
subsidiaries currently serve approximately 870,000 electric customers
and 360,000 natural gas customers in Iowa, Wisconsin, Illinois and
Minnesota.
(b) Unsolicited Acquisition Proposal -
On August 5, 1996, MidAmerican Energy Company (MAEC), an electric
and natural gas utility company based in Des Moines, Iowa, announced
that it had made an unsolicited offer to acquire Industries in a cash
and stock transaction. Under the terms of the offer, Industries would
merge with and into MAEC in a transaction in which Industries'
shareholders would receive up to 40% in cash and the remainder in shares
of MAEC common stock. Industries' shareholders receiving cash would
receive $39 for each Industries' share and shareholders receiving shares
would receive 2.346 shares of MAEC stock for each Industries' share. On
August 12, 1996, the closing price for MAEC stock on the NYSE was $15.75
per share. MAEC has stated that, if Industries and MAEC do not promptly
reach agreement with respect to a business combination between the two
companies, MAEC will solicit proxies against the Proposed Merger for use
at the upcoming Industries' shareholder meeting. Industries cannot
currently determine what, if any, impact the unsolicited offer of MAEC
may have on the Proposed Merger. The proposal will be given full
consideration by Industries' Board of Directors.
RESULTS OF OPERATIONS
The following discussion analyzes significant changes in the
components of net income available for common stock and financial condition
from the prior periods for the Company:
The Company's net income available for common stock increased or
(decreased) ($3.8) million, $4.1 million and $9.2 million during the
three, six and twelve month periods, respectively. The three month
period decrease was primarily due to increased operating expenses. The
increase in earnings for the six month period was primarily due to
increased electric and gas sales, the impact of a natural gas pricing
increase implemented in the fourth quarter of 1995 and a reserve for
electric rate refund recorded in the first quarter of 1995 which
included $3.5 million relating to revenues collected in 1994. The
twelve month increase was primarily due to increased electric and gas
sales, the natural gas pricing increase and lower purchased power
capacity costs, partially offset by lower electric prices. Increased
operating expenses also partially offset the six and twelve month
increases in earnings.
The Company's operating income increased or (decreased) ($7.4)
million, $6.9 million and $22.2 million during the three, six and twelve
month periods, respectively. Reasons for the changes in the results of
operations are explained in the following discussion.
Electric Revenues Electric revenues and Kwh sales (before off-system
sales) for Utilities increased or (decreased) as compared with the prior
year as follows:
Changes vs. Prior Period
Three Six Twelve
Months Months Months
($ in millions)
Total electric revenues $ 4.0 $ 12.8 $ 33.3
Off-system sales revenues 3.5 4.1 6.2
Electric revenues (excluding off-system sales) $ 0.5 $ 8.7 $ 27.1
Electric sales (excluding off-system sales):
Residential and Rural 1.4% 3.8% 9.7%
General Service (5.3) (0.2) 4.7
Large General Service (0.1) 2.5 4.1
Total (0.4) 2.6 5.1
Weather had a significant impact on sales during the six and twelve
month periods. The largest effect of weather for the periods was on
sales to residential and rural customers. Under historically normal
weather conditions, total sales (excluding off-system sales) during the
three, six and twelve month periods would have increased or (decreased)
(0.5%), 1.5% and 1.7%, respectively. The sales comparisons for all
three periods were impacted by a true-up adjustment to Utilities'
unbilled sales recorded in the second quarter of 1995. The sales
increases to the large general service customers (which are not
significantly impacted by weather) during the six and twelve month
periods reflect the underlying strength of the economy as industrial
expansions in Utilities' service territory continued during these
periods.
Utilities' electric tariffs include energy adjustment clauses (EAC)
that are designed to currently recover the costs of fuel and the energy
portion of purchased power billings to customers.
The increase in the electric revenues during all periods was
primarily due to increased sales (excluding the impact of the 1995 true-
up adjustment to unbilled sales), the recovery of expenditures for
energy efficiency programs pursuant to an Iowa Utilities Board (IUB)
order and higher fuel costs collected through the EAC. The impact of
these items was partially offset by the 1995 unbilled revenue
adjustment. The twelve month period increase was also partially offset
by lower electric prices resulting from the IUB price reduction order
received in 1995.
Refer to note 3(b) of the Notes to Consolidated Financial
Statements for a discussion of merger-related retail and wholesale
electric price proposals that Utilities has announced.
Gas Revenues Gas revenues increased $0.6 million, $16.7 million and
$28.2 million for the three, six and twelve month periods, respectively.
Utilities' gas sales and transported volumes increased or
(decreased) for the periods ended June 30, 1996, as compared with the
prior periods, as follows:
Three Months Six Months Twelve Months
Residential 1.8% 14.0% 16.5%
Commercial (0.3) 11.5 13.4
Industrial 18.4 4.9 (9.3)
Sales to consumers 3.0 12.4 12.2
Transported volumes (5.2) (1.8) 5.4
Total (0.1) 8.9 10.4
Under historically normal weather conditions, Utilities' gas sales
and transported volumes would have increased or (decreased) (0.8%), 2.9%
and 3.5% during the three, six and twelve month periods, respectively.
Utilities' gas tariffs include purchased gas adjustment clauses
(PGA) that are designed to currently recover the cost of gas sold.
On August 4, 1995, Utilities applied to the IUB for an annual
increase in gas rates of $8.8 million, or 6.2%. An interim increase of
$8.6 million was requested and the IUB, subsequently, approved an
interim increase of $7.1 million annually, effective October 11, 1995,
subject to refund. On April 4, 1996, the IUB issued an order approving
a settlement agreement entered into by Utilities, the Office of Consumer
Advocate and all three industrial intervenor groups, which allows
Utilities a $6.3 million annual increase. Utilities subsequently filed
final compliance tariffs which became effective on May 30, 1996.
Primarily because of changes in rate design, there is a refund
obligation of approximately $43,000 which will be made in the third
quarter of 1996.
Utilities' gas revenues increased during both the six and twelve
month periods primarily because of higher gas costs recovered through
the PGA, the gas pricing increase, recovery of expenditures for the
energy efficiency programs and increased sales to ultimate consumers
(largely on account of the weather).
Other Revenues Other revenues increased $2.0 million, $3.1 million and
$5.0 million during the three, six and twelve month periods,
respectively, primarily due to new industrial steam customers.
Operating Expenses Fuel for production increased $2.4 million, $3.3
million and $12.5 million during the three, six and twelve month
periods, respectively. The three month increase was primarily due to
higher fuel costs recovered through the EAC which are included in fuel
for production expense. The increases during the six and twelve month
periods were substantially related to increased Kwh generation,
primarily the result of a refueling outage during early 1995 at
Utilities' nuclear generating station, the Duane Arnold Energy Center
(DAEC).
Purchased power increased or (decreased) $4.9 million, $3.0 million
and ($1.5) million during the three, six and twelve month periods,
respectively. The three and six month increases were primarily due to
increased energy purchases, as a result of the increased electric sales
(excluding the 1995 unbilled adjustment), partially offset by lower
capacity costs. The twelve month decrease was due to a ($4.2) million
decrease in capacity costs, partially offset by higher energy purchases
due to the increased sales.
Gas purchased for resale increased
$7.8 million and $16.1 million during the six and twelve month
periods, respectively. The increases were
primarily due to higher natural gas costs and increased gas sales
to consumers.
Other operating expenses increased $3.9 million, $7.9 million and
$15.7 million during the three, six and twelve month periods,
respectively. Increased labor and benefits costs, the
amortization of previously deferred energy efficiency expenditures
(which are currently being recovered through rates) and costs
incurred in the Company's efforts to prepare for an increasingly
competitive utility industry contributed to the increases in all
periods. The costs to prepare for a competitive utility industry
included costs associated with items such as: 1) a project to review and
redesign Utilities' major business processes, 2) the Proposed Merger and
3) an early retirement program. These increases were partially offset
by lower former manufactured gas plant (FMGP) clean-up costs.
Maintenance expenses increased or (decreased) $3.7 million, $2.0
million and ($2.0) million during the three, six and twelve month
periods, respectively. The three and six month increases are primarily
due to increased maintenance activities at Utilities' generating
stations. The twelve month decrease was primarily caused by less
required maintenance at the DAEC and lower tree trimming costs.
Depreciation and amortization increased during all periods because
of increases in utility plant in service. These increases were
partially offset by lower depreciation rates implemented at Utilities as
a result of the IUB electric price reduction order. Depreciation and
amortization expenses for all periods included a provision for
decommissioning the DAEC, which is collected through rates. The annual
recovery level was increased to $6.0 million in 1995 from $5.5 million,
as a result of Utilities' most recent electric rate case.
During the first quarter of 1996, the Financial Accounting
Standards Board (FASB) issued an Exposure Draft on Accounting for
Liabilities Related to Closure and Removal of Long-Lived Assets which
deals with, among other issues, the accounting for decommissioning
costs. If current electric utility industry accounting practices for
such decommissioning are changed: 1) annual provisions for
decommissioning could increase and 2) the estimated cost for
decommissioning could be recorded as a liability, rather than as
accumulated depreciation, with recognition of an increase in the
recorded amount of the related DAEC plant. If such changes are
required, Utilities believes that there would not be an adverse effect
on its financial position or results of operations based on current rate
making practices.
Income taxes increased or (decreased) ($2.2) million, $4.3 million
and $11.4 million for the three, six and twelve month periods,
respectively. The variances for all periods were due to changes in pre-
tax income and a higher effective tax rate. The higher effective tax
rate for each period is due to: 1) the effect of property related
temporary differences for which deferred taxes had not been provided,
pursuant to rate making principles, that are now becoming payable and
are being recovered from ratepayers, and 2) the effect of prior period
audit adjustments.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are primarily attributable to
its construction programs and debt maturities. The Company's pre-tax
ratio of times interest earned was 3.46 and 3.05 for the twelve months
ended June 30, 1996 and June 30, 1995, respectively. Cash flows from
operating activities for the twelve months ended June 30, 1996 and June
30, 1995 were $167 million and $175 million, respectively. The decrease
was primarily due to the electric rate case refund paid to customers in
the fourth quarter of 1995. Cash
paid for income taxes increased significantly during all three periods
primarily because of the timing of estimated tax payments computed under
the annualized income approach.
The Company anticipates that future capital requirements will be
met by cash generated from operations and external financing. The level
of cash generated from operations is partially dependent upon economic
conditions, legislative activities, environmental matters and timely
rate relief for Utilities. See Notes 3 and 6 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
Long-term debt A2 A
Short-term debt P1 A1
Both Moody's and Standard & Poor's have indicated that Utilities'
credit ratings are under review as the result of the unsolicited
acquisition proposal Industries received from MidAmerican Energy Co.
It is not certain if, and how, such proposal or the Proposed Merger may
affect the Company's debt ratings.
The Company's liquidity and capital resources will be affected by
environmental and legislative issues, including the ultimate disposition
of remediation issues surrounding the Company's environmental
liabilities and the Clean Air Act as amended, as discussed in Note 6 of
the Notes to Consolidated Financial Statements, and the National Energy
Policy Act of 1992 as discussed in the Other Matters section. Consistent
with rate making principles of the IUB, management believes that the
costs incurred for the above matters will not have a material adverse
effect on the financial position or results of operations of the
Company.
Current IUB rules require Utilities to spend 2% of electric and
1.5% of gas gross retail operating revenues annually for energy
efficiency programs. Energy efficiency costs in excess of the amount in
the most recent electric and gas rate cases are being recorded as
regulatory assets by Utilities. At June 30, 1996, Utilities had
approximately $55 million of such costs recorded as regulatory assets.
On June 1, 1995, Utilities began recovery of those costs incurred
through 1993. See Note 3(c) of the Notes to Consolidated Financial
Statements for a discussion of the timing of the filings for the
recovery of these costs under IUB rules and Iowa statutory changes
recently enacted relating to these programs.
Under provisions of the Merger Agreement, there are restrictions on
the amount of 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 $164 million for 1996, of which
approximately 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. The
Company had construction and acquisition expenditures of approximately
$58 million for the six months ended June 30, 1996.
The Company's levels of construction and acquisition expenditures
are projected to be $185 million in 1997, $176 million in 1998,
$161 million in 1999 and $137 million in 2000. It is estimated that
approximately 80% of these construction and acquisition expenditures
will be provided by cash from operating activities (after payment of
dividends) for the five-year period 1996-2000.
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, approximately
$140 million of long-term debt will mature prior to December 31, 2000.
The Company intends to refinance the majority of the debt maturities
with long-term securities.
Utilities has entered into an Indenture of Mortgage and Deed of
Trust dated September 1, 1993 (New Mortgage). The New Mortgage provides
for, among other things, the issuance of Collateral Trust Bonds upon the
basis of First Mortgage Bonds being issued by Utilities. The lien of
the New Mortgage is subordinate to the lien of Utilities' first
mortgages until such time as all bonds issued under the first mortgages
have been retired and such mortgages satisfied. Accordingly, to the
extent that Utilities issues Collateral Trust Bonds on the basis of
First Mortgage Bonds, it must comply with the requirements for the
issuance of First Mortgage Bonds under Utilities' first mortgages.
Under the terms of the New Mortgage, Utilities has covenanted not to
issue any additional First Mortgage Bonds under its first mortgages
except to provide the basis for issuance of Collateral Trust Bonds.
The indentures pursuant to which Utilities issues First Mortgage
Bonds constitute direct first mortgage liens upon substantially all
tangible public utility property and contain covenants which restrict
the amount of additional bonds which may be issued. At June 30, 1996,
such restrictions would have allowed Utilities to issue at least
$266 million of additional First Mortgage Bonds.
In order to provide an instrument for the issuance of unsecured
subordinated debt securities, Utilities entered into an Indenture dated
December 1, 1995 (Subordinated Indenture). The Subordinated Indenture
provides for, among other things, the issuance of unsecured subordinated
debt securities. Any debt securities issued under the Subordinated
Indenture are subordinate to all senior indebtedness of Utilities,
including First Mortgage Bonds and Collateral Trust Bonds.
Utilities has received authority from the Federal Energy Regulatory
Commission (FERC) and the SEC to issue up to $250 million of long-term
debt, and has $250 million of remaining authority under the current FERC
docket through April 1998, and $200 million of remaining authority under
the current SEC shelf registration. Utilities expects to initially
replace $15 million of First Mortgage Bonds that mature in September
1996 with short-term borrowings pending the issuance of long-term debt.
The Articles of Incorporation of Utilities authorize and limit the
aggregate amount of additional shares of Cumulative Preference Stock and
Cumulative Preferred Stock that may be issued. At June 30, 1996,
Utilities could have issued an additional 700,000 shares of Cumulative
Preference Stock and 100,000 additional shares of Cumulative Preferred
Stock.
The Company's capitalization ratios at June 30, were as follows:
1996 1995
Long-term debt 46% 48%
Preferred stock 2 2
Common equity 52 50
100% 100%
The 1995 ratios included $50 million of long-term debt due in
less than one year because it was the Company's intention to
refinance the debt with long-term securities.
Under provisions of the Merger Agreement, there are restrictions on
the amount of long-term debt the Company can issue
pending the merger. The Company does not expect the restrictions to
have a material effect on its ability to meet its future capital
requirements.
SHORT-TERM FINANCING
For interim financing, Utilities is authorized by the FERC to
issue, through 1996, up to $200 million of short-term notes. In
addition to providing for ongoing working capital needs, this
availability of short-term financing provides Utilities flexibility in
the issuance of long-term securities. At June 30, 1996, Utilities had
outstanding short-term borrowings of $129.6 million, including
$4.6 million of notes payable to associated companies.
Utilities has entered into an agreement, which expires in 1999,
with a financial institution to sell, with limited recourse, an
undivided fractional interest of up to $65 million in its pool of
utility accounts receivable. At June 30, 1996, $65 million was sold
under the agreement.
At June 30, 1996, the Company had bank lines of credit aggregating
$121.1 million, of which $108 million was being used to support
commercial paper (weighted average interest rate of 5.40%) and $11.1
million to support certain pollution control obligations. Commitment
fees are paid to maintain these lines and there are no conditions which
restrict the unused lines of credit. In addition to the above,
Utilities has an uncommitted credit facility with a financial
institution whereby it can borrow up to $40 million. Rates are set at
the time of borrowing and no fees are paid to maintain this facility.
At June 30, 1996, there was $17 million outstanding under this facility
(weighted average interest rate of 5.57%).
ENVIRONMENTAL MATTERS
Utilities has been named as a Potentially Responsible Party (PRP)
by various federal and state environmental agencies for 28 FMGP sites,
but believes it is not responsible for two of these sites based on
extensive reviews of the ownership records and historical information
available for the two sites. Utilities has notified the appropriate
regulatory agency that it believes it does not have any responsibility
as relates to these two sites, but no response has been received from
the agency on this issue. Utilities is also aware of six other sites
that it may have owned or operated in the past and for which, as a
result, it may be designated as a PRP in the future in the event that
environmental concerns arise at these sites. Utilities is working
pursuant to the requirements of the various agencies to investigate,
mitigate, prevent and remediate, where necessary, damage to property,
including damage to natural resources, at and around the sites in order
to protect public health and the environment. Utilities believes it has
completed the remediation of seven sites although it is in the process
of obtaining final approval from the applicable environmental agencies
on this issue for each site. Utilities is in various stages of the
investigation and/or remediation processes for the remaining 19 sites
and estimates the range of additional costs to be incurred for
investigation and/or remediation of the sites to be approximately $24
million to $57 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $35 million (including $4.6 million as
current liabilities) at June 30, 1996. These amounts are based upon
Utilities' best current estimate of the amount to be incurred for
investigation and remediation costs for those sites where the
investigation process has been or is substantially completed, and the
minimum of the estimated cost range for those sites where the
investigation is in its earlier stages. It is possible that future cost
estimates will be greater than the current estimates as the
investigation process proceeds and as additional facts become known; in
addition, Utilities may be required to monitor these sites for a number
of years upon completion of remediation, as is the case with several of
the sites for which remediation has been completed.
In April 1996, Utilities filed a lawsuit against certain of its
insurance carriers seeking reimbursement for investigation, mitigation,
prevention, remediation and monitoring costs associated with the FMGP
sites. Settlement discussions are proceeding between Utilities and its
insurance carriers regarding the recovery of these FMGP-related costs.
The amount of aggregate potential recovery, or the regulatory treatment
of any such recoveries, cannot be reasonably determined at this time
and, accordingly, no estimated amounts have been recorded at June
30, 1996. Regulatory assets of approximately $35 million, which reflect
the future recovery that is being provided through Utilities' rates,
have been recorded in the Consolidated Balance Sheets. Considering the
current rate treatment allowed by the IUB, management believes that the
clean-up costs incurred by Utilities for these FMGP sites will not have
a material adverse effect on its financial position or results of
operations.
The Clean Air Act Amendments of 1990 (Act) requires emission
reductions of sulfur dioxide (SO2) and nitrogen oxides (NOx) to achieve
reductions of atmospheric chemicals believed to cause acid rain. The
provisions of the Act are being implemented in two phases; the Phase I
requirements have been met and the Phase II requirements affect eleven
other fossil units beginning in the year 2000. Utilities expects to
meet the requirements of Phase II by switching to lower sulfur fuels,
capital expenditures primarily related to fuel burning equipment and
boiler modifications, and the possible purchase of SO2 allowances.
Utilities estimates capital expenditures at approximately $20 million,
including $4 million in 1996, in order to meet the acid rain
requirements of the Act.
The acid rain program under the Act also governs SO2 allowances.
An allowance is defined as an authorization for an owner to emit one ton
of SO2 into the atmosphere. Currently, Utilities receives a sufficient
number of allowances annually to offset its emissions of SO2 from its
Phase I units. It is anticipated that in the year 2000, Utilities may
have an insufficient number of allowances annually to offset its
estimated emissions and may have to purchase additional allowances, or
make modifications to the plants or limit operations to reduce
emissions. Utilities is reviewing its options to ensure that it will
have sufficient allowances to offset its emissions in the future.
Utilities believes that the potential cost of ensuring sufficient
allowances will not have a material adverse effect on its financial
position or results of operations.
The Act and other federal laws also require the United States
Environmental Protection Agency (EPA) to study and regulate, if
necessary, additional issues that potentially affect the electric
utility industry, including emissions relating to NOx, ozone transport,
mercury and particulate control; toxic release inventories and
modifications to the PCB rules. Currently, the impacts of these
potential regulations are too speculative to quantify.
In 1995, the EPA published the Sulfur Dioxide Network Design Review
for Cedar Rapids, Iowa, which, based on the EPA's assumptions and worst-
case modeling method suggests that the Cedar Rapids area could be
classified as "nonattainment" for the National Ambient Air Quality
Standard (NAAQS) established for SO2. The worst-case modeling study
suggested that two of Utilities' generating facilities contribute to the
modeled exceedences and recommended that additional monitors be located
near Utilities' sources to assess actual ambient air quality. In the
event that Utilities' facilities contribute excessive emissions,
Utilities would be required to reduce emissions, which would primarily
entail capital expenditures for modifications to the facilities.
Utilities is planning to convert one of its fossil generating facilities
to a natural gas-fired cogeneration facility. Such facility was
contributing to the modeled exceedences thus the conversion will have
the added inherent benefit of reducing SO2 emissions. Utilities is
proposing to resolve the remainder of EPA's nonattainment concerns by
installing a new stack at the other generating facility contributing to
the modeled exceedences at a potential capital cost of up to $4.5
million over the next four years.
The National Energy Policy Act of 1992 requires owners of nuclear
power plants to pay a special assessment into a "Uranium Enrichment
Decontamination and Decommissioning Fund." The assessment is based upon
prior nuclear fuel purchases and, for the DAEC, averages $1.4 million
annually through 2007, of which Utilities' 70% share is $1.0 million.
Utilities is recovering the costs associated with this assessment
through its electric fuel adjustment clauses over the period the costs
are assessed. Utilities' 70% share of the future assessment, $10.9
million payable through 2007, has been recorded as a liability in the
Consolidated Balance Sheets, including $0.8 million included in "Current
liabilities - Environmental liabilities," with a related regulatory
asset for the unrecovered amount.
The Nuclear Waste Policy Act of 1982 assigned responsibility to the
U.S. Department of Energy (DOE) to establish a facility for the ultimate
disposition of high level waste and spent nuclear fuel and authorized
the DOE to enter into contracts with parties for the disposal of such
material beginning in January 1998. Utilities entered into such a
contract and has made the agreed payments to DOE. The DOE, however, has
experienced significant delays in its efforts and material acceptance is
now expected to occur no earlier than 2010 with the possibility of
further delay being likely. Utilities has been storing spent nuclear
fuel on-site since plant operations began in 1974 and has current on-
site capability to store spent fuel until 2002. Utilities is
aggressively reviewing options for additional spent nuclear fuel storage
capability, including expanding on-site storage and supporting
legislation currently before the U.S. Congress, to resolve the lack of
progress by the DOE.
The Low-Level Radioactive Waste Policy Amendments Act of 1985
mandated that each state must take responsibility for the storage of low-
level radioactive waste produced within its borders. The State of Iowa
has joined the Midwest Interstate Low-Level Radioactive Waste Compact
Commission (Compact), which is planning a storage facility to be located
in Ohio to store waste generated by the Compact's six member states. At
June 30, 1996, Utilities has prepaid costs of approximately $1.1 million
to the Compact for the building of such a facility. A Compact disposal
facility is anticipated to be in operation in approximately ten years
after approval of new enabling legislation by the member states. Such
legislation has been approved by all six states. Approval by the U.S.
Congress will also be required before it is effective and is currently
expected to be considered in 1997. On-site storage capability currently
exists for low-level radioactive waste expected to be generated until
the Compact facility is able to accept waste materials. In addition,
the Barnwell, South Carolina disposal facility has reopened for an
indefinite time period and Utilities is in the process of shipping to
Barnwell the majority of the low-level radioactive waste it has
accumulated on-site, and intends to ship the waste it produces in the
future as long as the Barnwell site remains open, thereby minimizing the
amount of low-level waste stored on-site.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects has been the subject of
increased public, governmental, industry and media attention. A
considerable amount of scientific research has been conducted on this
topic without definitive results. Research is continuing in order to
resolve scientific uncertainties. The Company cannot predict the
outcome of this research.
OTHER MATTERS
Competition As legislative, regulatory, economic and technological
changes occur, electric utilities are faced with increasing pressure to
become more competitive. Such competitive pressures could result in
loss of customers and an incurrence of stranded costs (i.e. the cost of
assets rendered unrecoverable as the result of competitive pricing). To
the extent stranded costs cannot be recovered from customers, they would
be borne by security holders.
The National Energy Policy Act of 1992 addresses several matters
designed to promote competition in the electric wholesale power
generation market. In April 1996, the FERC issued final rules (FERC
Orders 888 and 889), largely confirming earlier proposals, requiring
electric utilities to open their transmission lines to other wholesale
buyers and sellers of electricity. The rules became effective on July
9, 1996. The key provisions of the rules are: 1) utilities must act as
"common carriers" of electricity, reserving capacity on their lines for
other wholesale buyers and sellers of electricity and charging
competitors no more than they pay themselves for use of the lines; 2)
utilities must establish electronic bulletin boards to share information
about transmission capacity; and 3) utilities can recover "stranded
costs" by charging large wholesale customers a fee for switching to a
new supplier. Utilities filed conforming pro-forma open access
transmission tariffs with the FERC which became effective October 1,
1995. In response to FERC Order 888, Utilities filed its final pro-forma
tariffs with FERC on July 9, 1996. These tariffs have not yet been
approved by the FERC. The geographic position of Utilities'
transmission system could provide revenue opportunities in the open
access environment. The Company cannot predict the long-term
consequences of these rules on its results of operation or financial
condition.
The final FERC rules do not provide for the recovery of stranded
costs resulting from retail competition. The various states retain
jurisdiction over whether to permit retail competition, the terms of
such retail competition and the recovery of any portion of stranded
costs that are ultimately determined by FERC and the states to have
resulted from retail competition.
As part of Utilities' strategy for the emerging and competitive
power markets, Utilities, IPC and Wisconsin Power and Light Company (the
utility subsidiary of WPLH), and a number of other utilities have proposed
the creation of an independent system operator (ISO) for the companies'
power transmission grid. The companies would retain ownership and
control of the facilities, but the ISO, subject to FERC approval,
would set rates for access and
assume fair treatment for all companies seeking access. The proposal
requires approval from state regulators and the FERC.
The IUB initiated a Notice of Inquiry (Docket No. NOI-95-1) in
early 1995 on the subject of "Emerging Competition in the Electric
Utility Industry." A one-day roundtable discussion was held to address
all forms of competition in the electric utility industry and to assist
the IUB in gathering information and perspectives on electric
competition from all persons or entities with an interest or stake in
the issues. Additional discussions were held in December 1995, May 1996
and July 1996. In January 1996, the IUB created its own timeline for
evaluating industry restructuring in Iowa. Included in the IUB's
process was the creation of a 22-member advisory panel, of which
Utilities is a member. The IUB has established a self-imposed deadline
of the fourth quarter of 1996, for publishing its analysis of various
restructuring options and any advisory panel comments on the IUB's
options and analysis. The IUB's schedule calls for public information
meetings to be held around the state of Iowa during late 1996 and early
1997.
Utilities is subject to the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS 71). If a portion of Utilities' operations
become no longer subject to the provisions of SFAS 71, as a result of
competitive restructurings or otherwise, a write-down of related
regulatory assets would be required, unless some form of transition cost
recovery is established by the appropriate regulatory body. Utilities
believes that it still meets the requirements of SFAS 71.
The Company cannot predict the long-term consequences of these
competitive issues on its results of operations or financial condition.
The Company's strategy for dealing with these emerging issues includes
seeking growth opportunities, continuing to offer quality customer
service, ongoing cost reductions and productivity enhancements, the
major objective of which is to allow Utilities to better prepare for a
competitive, deregulated electric utility industry. In this connection,
Utilities has undertaken Process Redesign, an effort to improve service
levels, to reduce its cost structure and to become more market-focused
and customer-oriented.
Process Redesign is examining the major business processes within
Utilities, which are: Customer Service Fulfillment, Fossil-Fueled Energy
Supply, Nuclear Energy Supply, Non-Electric Fuel Supply Chain,
Transmission and Distribution Energy Delivery, and Planning, Budgeting &
Performance Management. These areas were examined during Phase I of the
effort, which lasted from January 1995 through May 1995. Phase I
recommendations were designed to make broad-based changes in the way
work was performed and results were achieved in each of the processes.
Management accepted the recommendations and, in June 1995, initiated
Phase II of the project. The detailed designs resulting from Phase II
were substantially completed in November 1995 and pilot programs began.
Examples of the Process Redesign changes include, but are not
limited to: managing the business in business unit form, rather than
functionally; formation of alliances with vendors of certain types of
material rather than opening most purchases to a bidding process;
changing standards and construction practices in transmission and
distribution areas; changing certain work practices in power plants; and
improving the method by which service is delivered to customers in all
customer classes. The specific recommendations range from simple
improvements in current operations to radical changes in the way work is
performed and service is delivered. Utilities currently intends to
implement all of the recommendations of the Process Redesign teams,
although the pilot stage or potential effects of the Proposed Merger
could prove that some of the recommendations are not efficient or
effective and must be revised or eliminated. Subject to delays caused
by implementing any such revisions, implementation of the Process
Redesign changes will be partially completed in 1996, but, certain
results will not be achieved until 1997. In addition, the Company must
give consideration to the potential effects of the Proposed Merger as
part of the implementation process so that duplication of efforts are
avoided.
Accounting Pronouncements SFAS 121, issued in March 1995 by the FASB
and effective for 1996, establishes accounting standards for the
impairment of long-lived assets. SFAS 121 also requires that regulatory
assets that are no longer probable of recovery through future revenues
be charged to earnings. The Company adopted this standard on January 1,
1996, and the adoption had no effect on the financial position or
results of operations of the Company.
Financial Derivatives The Company has a policy that financial derivatives
are to be used only to mitigate business risks and not for speculative
purposes. At June 30, 1996, the Company did not have any material financial
derivatives outstanding.
Inflation Under the rate making principles prescribed by the regulatory
commissions to which Utilities is subject, only the historical cost of
plant is recoverable in revenues as depreciation. As a result,
Utilities has experienced economic losses equivalent to the current
year's impact of inflation on utility plant. In addition, the
regulatory process imposes a substantial time lag between the time when
operating and capital costs are incurred and when they are recovered.
Utilities does not expect the effects of inflation at current levels to
have a significant effect on its financial position or results of
operations.
PART II. - OTHER INFORMATION
Item 1. Legal Proceedings.
On April 30, 1996, Utilities filed suit, IES Utilities Inc. v. Home
Ins. Co., et al., No. 4-96-CV-10343 (S.D. Iowa filed Apr. 30, 1996),
against various insurers who had sold comprehensive general liability
policies to Iowa Southern Utilities Company (ISU) and Iowa Electric
Light and Power Company (IE) (Utilities was formed as the result of a
merger of ISU and IE). The suit seeks judicial determination of the
respective rights of the parties, a judgment that each defendant is
obligated under its respective insurance policies to pay in full all
sums that the Company has become or may become obligated to pay in
connection with its defense against allegations of liability for
property damage at and around FMGP sites, and indemnification for all
sums that it has or may become obligated to pay for the investigation,
mitigation, prevention, remediation and monitoring of damage to
property, including damage to natural resources like groundwater, at and
around the FMGP sites.
Reference is made to Notes 3 and 6 of the Notes to Consolidated
Financial Statements for a discussion of rate matters and environmental
matters, respectively, and Item 2. Management's Discussion and Analysis
of the Results of Operations and Financial Condition - Environmental
Matters.
Item 2. Changes in the Rights of the Company's Security Holders.
None.
Item 3. Default Upon Senior Securities.
None.
Item 4. Results of Votes of Security Holders.
None.
Item 5. Other Information.
(a) The Company has calculated the ratio of earnings to fixed charges
pursuant to Item 503 of Regulation S-K of the Securities and
Exchange Commission as follows:
For the twelve months ended:
June 30, 1996 3.23
December 31, 1995 3.04
December 31, 1994 3.18
December 31, 1993 3.41
December 31, 1992 2.49
December 31, 1991 2.64
(b) John E. Ebright joined the Company as Controller & Chief Accounting
Officer, effective July 8, 1996.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits -
3(a) Bylaws of Registrant, as amended May 7, 1996 (Filed as Exhibit
3(a) to the Company's Form 10-Q for the quarter ended March
31, 1996).
*12 Ratio of Earnings to Fixed Charges
*27 Financial Data Schedule.
* Exhibits designated by an asterisk are filed herewith.
(b) Reports on Form 8-K -
Items Reported Financial Statements Date of Report
5,7 None April 3, 1996 (1)
5,7 None April 12, 1996 (2)
5,7 None May 22, 1996 (3)
(1) The Form 8-K report was filed on April 8, 1996 with the earliest
event reported occurring on April 3, 1996.
(2) The Form 8-K report was filed on April 18, 1996 with the earliest
event reported occurring on April 12, 1996.
(3) The Form 8-K report was filed on May 24, 1996 with the earliest event
reported occurring on May 22, 1996.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
IES UTILITIES INC.
(Registrant)
Date: August 14, 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
<TABLE>
EXHIBIT 12
IES UTILITIES INC.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
<CAPTION>
Twelve Months
Year Ended December 31, Ended
1991 1992 1993 1994 1995 June 30, 1996
(in thousands, except ratio of earnings to fixed charges)
<S> <C> <C> <C> <C> <C> <C>
Net income $ 47,563 $ 45,291 $ 67,970 $ 61,210 $ 59,278 $ 63,408
Federal and state
income taxes 23,494 20,723 37,963 37,966 41,095 45,363
Net income before
income taxes 71,057 66,014 105,933 99,176 100,373 108,771
Interest on long-term debt 31,171 35,689 34,926 37,942 36,375 35,923
Other interest 5,595 3,939 5,243 3,630 8,085 8,228
Estimated interest
component of rents 6,594 4,567 3,729 3,970 4,637 4,562
Fixed charges as defined 43,360 44,195 43,898 45,542 49,097 48,713
Earnings as defined $ 114,417 $ 110,209 $ 149,831 $ 144,718 $ 149,470 $ 157,484
Ratio of earnings to fixed
charges (unaudited) 2.64 2.49 3.41 3.18 3.04 3.23
For the purposes of computation of these ratios (a) earnings have been
calculated by adding fixed charges and federal and state income taxes
to net income; (b) fixed charges consist of interest (including
amortization of debt expense, premium and discount) on long-term and
other debt and the estimated interest component of rents.
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
The schedule contains summary financial information extracted from the
Consolidated Balance Sheet at June 30, 1996 and the Consolidated Statement
of Income and the Consolidated Statement of Cash Flows for the six months
ended June 30, 1996 and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,324,281
<OTHER-PROPERTY-AND-INVEST> 61,581
<TOTAL-CURRENT-ASSETS> 98,504
<TOTAL-DEFERRED-CHARGES> 21,697
<OTHER-ASSETS> 211,776
<TOTAL-ASSETS> 1,717,839
<COMMON> 33,427
<CAPITAL-SURPLUS-PAID-IN> 279,042
<RETAINED-EARNINGS> 211,422
<TOTAL-COMMON-STOCKHOLDERS-EQ> 523,891
0
18,320
<LONG-TERM-DEBT-NET> 457,422
<SHORT-TERM-NOTES> 21,575
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 108,000
<LONG-TERM-DEBT-CURRENT-PORT> 23,140
0
<CAPITAL-LEASE-OBLIGATIONS> 26,649
<LEASES-CURRENT> 13,883
<OTHER-ITEMS-CAPITAL-AND-LIAB> 524,959
<TOT-CAPITALIZATION-AND-LIAB> 1,717,839
<GROSS-OPERATING-REVENUE> 363,008
<INCOME-TAX-EXPENSE> 16,494<F1>
<OTHER-OPERATING-EXPENSES> 305,796
<TOTAL-OPERATING-EXPENSES> 305,796<F1>
<OPERATING-INCOME-LOSS> 57,212
<OTHER-INCOME-NET> 2,519
<INCOME-BEFORE-INTEREST-EXPEN> 59,731
<TOTAL-INTEREST-EXPENSE> 21,880
<NET-INCOME> 21,357
457
<EARNINGS-AVAILABLE-FOR-COMM> 20,900
<COMMON-STOCK-DIVIDENDS> 22,000
<TOTAL-INTEREST-ON-BONDS> 35,222
<CASH-FLOW-OPERATIONS> 71,675
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1>Income tax expense is not included in Operating Expense in the Consolidated
Statements of Income for IES Utilities Inc.
</FN>
</TABLE>
