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 March 31, 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 April 30, 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 -
March 31, 1996 and December 31, 1995 3 - 4
Consolidated Statements of Income -
Three and Twelve Months Ended
March 31, 1996 and 1995 5
Consolidated Statements of Cash Flows -
Three and Twelve Months Ended
March 31, 1996 and 1995 6
Notes to Consolidated Financial Statements 7 - 17
Item 2. Management's Discussion and Analysis of the
Results of Operations and Financial Condition. 18 - 39
Part II. Other Information. 40 - 42
Signatures. 43
PART 1. - FINANCIAL INFORMATION
ITEM 1. - CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED BALANCE SHEETS
March 31,
1996 December 31,
ASSETS (Unaudited) 1995
(in thousands)
Property, plant and equipment:
Utility -
Plant in service -
Electric $ 1,909,500 $ 1,900,157
Gas 166,248 165,825
Other 106,504 106,396
2,182,252 2,172,378
Less - Accumulated depreciation 973,304 950,324
1,208,948 1,222,054
Leased nuclear fuel, net of amortization 34,915 36,935
Construction work in progress 65,862 52,772
1,309,725 1,311,761
Other, net of accumulated depreciation
and amortization of $1,261,000 and
$1,166,000, respectively 5,073 5,477
1,314,798 1,317,238
Current assets:
Cash and temporary cash investments 434 2,734
Accounts receivable -
Customer, less reserve 27,003 18,619
Other 7,987 8,912
Production fuel, at average cost 12,313 12,155
Materials and supplies, at average cost 24,017 27,229
Regulatory assets 24,914 22,791
Prepayments and other 12,685 19,402
109,353 111,842
Investments:
Nuclear decommissioning trust funds 49,543 47,028
Cash surrender value of life insurance
policies 3,751 3,582
Other 561 475
53,855 51,085
Other assets:
Regulatory assets 208,039 207,202
Deferred charges and other 20,902 21,268
228,941 228,470
$ 1,706,947 $ 1,708,635
CONSOLIDATED BALANCE SHEETS (CONTINUED)
March 31,
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 216,421 212,522
Total common equity 528,890 524,991
Cumulative preferred stock - par
value $50 per share - authorized
466,406 shares; 366,406 shares outstanding 18,320 18,320
Long-term debt (excluding current portion) 465,513 465,463
1,012,723 1,008,774
Current liabilities:
Notes payable to associated companies 3,241 8,888
Other short-term borrowings 92,000 101,000
Capital lease obligations 14,780 15,717
Maturities and sinking funds 15,140 15,140
Accounts payable 51,455 64,564
Accrued interest 9,753 8,038
Accrued taxes 68,062 50,369
Accumulated refueling outage provision 10,236 7,690
Adjustment clause balances 6,535 3,148
Environmental liabilities 5,421 5,521
Other 17,862 17,300
294,485 297,375
Long-term liabilities:
Pension and other benefit obligations 43,265 41,866
Capital lease obligations 20,135 21,218
Environmental liabilities 41,053 40,905
Other 7,926 8,719
112,379 112,708
Deferred credits:
Accumulated deferred income taxes 250,906 252,663
Accumulated deferred investment tax credits 36,454 37,115
287,360 289,778
Commitments and contingencies (Note 6)
$ 1,706,947 $ 1,708,635
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
For the Three For the Twelve
Months Ended Months Ended
March 31 March 31
1996 1995 1996 1995
(in thousands)
Operating revenues:
Electric $ 125,368 $ 116,577 $ 569,262 $ 529,987
Gas 69,241 53,175 153,358 127,074
Other 4,159 3,087 13,135 9,131
198,768 172,839 735,755 666,192
Operating expenses:
Fuel for production 20,292 19,443 97,105 83,051
Purchased power 14,469 16,314 65,029 71,506
Gas purchased for resale 47,369 38,133 100,434 84,356
Other operating expenses 38,358 34,411 149,196 135,711
Maintenance 9,992 11,679 41,899 50,326
Depreciation and amortization 22,024 20,589 80,820 76,744
Taxes other than income taxes 12,060 12,374 44,699 43,258
164,564 152,943 579,182 544,952
Operating income 34,204 19,896 156,573 121,240
Interest expense and other:
Interest expense 10,893 10,458 44,895 41,502
Allowance for funds used during construction -690 -1,115 -2,999 -4,148
Miscellaneous, net -963 8 -117 -970
9,240 9,351 41,779 36,384
Income before income taxes 24,964 10,545 114,794 84,856
Income taxes:
Current 13,361 -1,985 48,812 26,717
Deferred -1,864 7,041 1,409 8,369
Amortization of investment tax credits -661 -672 -2,674 -2,657
10,836 4,384 47,547 32,429
Net income 14,128 6,161 67,247 52,427
Preferred dividend requirements 229 229 914 914
Net income available for common stock $ 13,899 $ 5,932 $ 66,333 $ 51,513
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 Twelve
Months Ended Months Ended
March 31 March 31
1996 1995 1996 1995
(in thousands)
Cash flows from operating activities:
Net income $ 14,128 $ 6,161 $ 67,247 $ 52,427
Adjustments to reconcile net income to net cash
flows from operating activities -
Depreciation and amortization 22,024 20,589 80,820 76,744
Amortization of principal under capital
lease obligations 4,624 2,556 17,781 14,375
Deferred taxes and investment tax credits -2,525 6,369 -1,265 5,712
Refueling outage provision 2,546 -8,528 3,569 871
Amortization of other assets 2,913 1,056 9,247 2,740
Other 0 -263 447 -1,063
Other changes in assets and liabilities -
Accounts receivable -7,459 126 -17,302 6,869
Production fuel, materials and supplies 902 -52 2,612 -2,678
Accounts payable -10,296 -4,239 -10,451 21,504
Accrued taxes 17,070 6,217 16,638 10,730
Provision for rate refunds 166 8,000 -7,728 -1,085
Adjustment clause balances 3,387 4,235 3,733 -7,071
Gas in storage 7,744 7,375 2,798 -796
Other 1,506 6,417 -6,006 10,919
Net cash flows from operating activities 56,730 56,019 162,140 190,198
Cash flows from financing activities:
Dividends declared on common stock -10,000 -13,000 -40,000 -58,000
Dividends declared on preferred stock -229 -229 -914 -914
Proceeds from issuance of long-term debt 0 50,000 50,000 50,000
Reductions in long-term debt 0 -50,000 -50,140 -50,224
Net change in short-term borrowings -14,647 -11,951 51,697 43,544
Principal payments under capital lease obligations -4,913 -3,662 -15,714 -16,246
Sale of utility accounts receivable 0 10,000 -6,000 10,800
Other -86 0 -1,910 0
Net cash flows from financing activities -29,875 -18,842 -12,981 -21,040
Cash flows from investing activities:
Construction and acquisition expenditures -
Utility -23,374 -27,644 -121,833 -155,182
Other -197 -572 -2,965 -2,145
Deferred energy efficiency expenditures -3,667 -3,537 -18,159 -16,295
Nuclear decommissioning trust funds -1,502 -1,383 -6,219 -5,532
Other -415 -3,686 -2,039 -254
Net cash flows from investing activities -29,155 -36,822 -151,215 -179,408
Net increase (decrease) in cash and temporary
cash investments -2,300 355 -2,056 -10,250
Cash and temporary cash investments at beginning of period 2,734 2,135 2,490 12,740
Cash and temporary cash investments at end of period $ 434 $ 2,490 $ 434 $ 2,490
Supplemental cash flow information:
Cash paid during the period for -
Interest $ 8,530 $ 8,254 $ 44,845 $ 40,281
Income taxes $ 7,138 $ 2,850 $ 33,371 $ 37,368
Noncash investing and financing activities -
Capital lease obligations incurred $ 2,604 $ 1,116 $ 4,405 $ 15,217
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
March 31, 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) 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, 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. 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 expect to
receive the shareholder approvals in the third quarter of 1996 and
regulatory approvals by the second quarter 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.
(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 and
expects them to be effective in the second quarter of 1996. Primarily
because of changes in rate design, there will be little or no refund
obligation.
(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 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 -
The IUB has current rules that 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 1996 or early
1997, under provisions of the IUB rules, the Company will file for
recovery of the costs relating to its 1994 and 1995 programs ($31.6
million as of March 31, 1996).
The IUB has recently proposed changes to the Iowa statute which
would 1) eliminate the 2% and 1.5% spending requirements described above
in favor of IUB-determined energy savings targets and 2) eliminate the
delay in recovery of energy efficiency costs by allowing recovery which
is concurrent with spending, eventually eliminating the regulatory asset
which exists under the current rate making mechanism. This legislation
has been passed by the Iowa legislature and is awaiting signature by the
governor. The Company expects the governor to sign the legislation in
the second quarter of 1996.
(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 March 31, 1996, $58 million was sold
under the agreement.
(5) DEBT:
At March 31, 1996, the Company had bank lines of credit aggregating
$121.1 million, of which $92 million was being used to support
commercial paper (weighted average interest rate of 5.27%) 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 March 31, 1996, there were no borrowings outstanding under this
facility.
(6) CONTINGENCIES:
(a) Environmental Liabilities -
The Company has recorded environmental liabilities of approximately
$46.5 million in its Consolidated Balance Sheets at March 31, 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 17 sites and expects to
begin the investigation process in 1996 for the two other sites.
Utilities estimates the range of additional costs to be incurred for
investigation and/or remediation of the sites to be approximately $23
million to $59 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $35 million (including $4.6 million as
current liabilities) at March 31, 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 or has not started. 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. The amount of potential recovery, if any, or the regulatory
treatment of any such recoveries cannot be reasonably determined at this
time and, accordingly, no estimated amounts have been recorded at March
31, 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 also requires 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 and mercury. 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 repower one of the generating facilities that
was contributing to the modeled exceedences which 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 March
31, 1996, has recorded a liability of $4.7 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 March 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
$5.0 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.
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, 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. 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 expect to
receive the shareholder approvals in the third quarter of 1996 and
regulatory approvals by the second quarter 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.
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 $8.0
million and $14.8 million during the three and twelve month periods,
respectively. The Company estimates that favorable weather conditions
increased net income available for common stock during the three and
twelve month periods ended March 31, 1996, by approximately $1 million
and $7.7 million, respectively. Milder than normal weather during the
prior periods, a gas price increase implemented in October 1995 and
electric and gas sales growth also contributed to the increased earnings
during both periods. The three month period comparison also benefited
from an out-of-period rate reserve recorded at Utilities in the first
quarter of 1995. These items were partially offset by increased
operating expenses, interest expense, and a higher effective income tax
rate during both periods and the impact of lower electric prices during
the twelve month period.
The Company's operating income increased $14.3 million and $35.3
million during the three and twelve month periods, respectively.
Reasons for the changes in the results of operations are explained in
the following discussion.
Electric Revenues Electric revenues and Kwh sales (before off-system
sales) for Utilities increased or (decreased) as compared with the prior
year as follows:
Three Twelve
Months Months
($ in millions)
Total electric revenues $ 8.8 $ 39.3
Change in off-system sales revenues .6 (0.5)
Electric revenues (excluding off-system sales) $ 8.2 $ 39.8
Electric sales (excluding off-system sales):
Residential and Rural 6.0% 11.3%
General Service 4.8 7.5
Large General Service 5.5 6.4
Total 5.6 7.0
Weather had a significant impact on sales during both periods. The
largest effect of weather for both periods was on sales to residential
and rural customers. Under historically normal weather conditions,
total sales (excluding off-system sales) during the three and twelve
month periods would have increased 3.5% and 4.0%, respectively. Sales
during the twelve month period also benefited from the effect of
Utilities' annual true up adjustment to unbilled sales. The growth in
general service and large general service sales continues to reflect the
underlying strength of the economy as industrial expansions in
Utilities' service territory continued during both 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 the three month period
was primarily due to the increased sales (excluding off-system sales),
the impact of a reserve for rate refund recorded in the first quarter of
1995 which included $3.5 million for revenues collected during 1994 and
the recovery of expenditures for energy efficiency programs pursuant to
an Iowa Utilities Board (IUB) order. The twelve month increase was
primarily due to the increased sales (excluding off-system sales),
higher fuel costs collected through the EAC, the recovery of
expenditures for energy efficiency programs and the unbilled revenue
adjustment. These items were partially offset by a reduction in revenues
of approximately $7 million as a result of the IUB price reduction order
received in 1995. The increased sales during both periods were
attributable to the impacts of the weather as well as sales growth, with
the weather the dominant factor during the twelve month period.
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 $16.1 million and $26.3 million
for the three and twelve month periods, respectively. Utilities' gas
sales and transported volumes in therms increased or (decreased) for the
periods ended March 31, 1996, as compared with the prior periods, as
follows:
Three Months Twelve Months
Residential 17.9% 17.0%
Commercial 15.4 13.5
Industrial (2.6) (17.7)
Sales to consumers 15.6 11.2
Transported volumes 1.3 11.6
Total 12.9 11.3
Under historically normal weather conditions, Utilities' gas sales
and transported volumes would have increased 4.5% and 3.0% during the
three 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 and expects them to be effective in the second
quarter of 1996. Primarily because of changes in rate design, there
will be little or no refund obligation.
Utilities' gas revenues increased during both the three and twelve
month periods primarily because of higher gas costs recovered through
the PGA, the interim rate increase, recovery of expenditures for the
energy efficiency programs and increased sales to ultimate consumers
(largely on account of colder than normal weather).
Other Revenues Other revenues increased $1.1 million and $4.0 million
during the three and twelve month periods, respectively, primarily due
to new industrial steam customers.
Operating Expenses Fuel for production increased $0.8 million and
$14.1 million during the three and twelve month periods, respectively.
The three month increase was due to increased Kwh generation partially
offset by lower fuel costs recovered through the EAC which are included
in fuel for production expense. The twelve month increase was due to
higher average fuel prices, increased Kwh generation and higher fuel
costs recovered through the EAC. Generation at Utilities' generating
stations increased during both periods because of the increased sales
and the increased availability of the Duane Arnold Energy Center (DAEC),
Utilities' nuclear generating plant, which was down during early 1995
for a scheduled refueling outage.
Purchased power decreased ($1.8) million and ($6.5) million during
the three and twelve month periods, respectively. The three month
decrease was because of decreased energy purchases, as a result of the
increased Kwh generation discussed above, and lower capacity costs. The
twelve month decrease was substantially due to a ($5.6) million decrease
in capacity costs and, to a lesser extent, lower energy purchases.
Gas purchased for resale increased $9.2 million and $16.1 million
during the three and twelve month periods, respectively, due to higher
natural gas costs recovered through the PGA and the increased gas sales.
Other operating expenses increased $3.9 million and $13.5 million
during the three 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), costs associated with a project to review and redesign
Utilities' major business processes and costs relating to the Proposed
Merger contributed to the increases in both periods. These increases
were partially offset by decreased nuclear operating costs.
Maintenance expenses decreased ($1.7) million and ($8.4) million
during the three and twelve month periods, respectively, primarily due
to less required maintenance activities at the DAEC and at Utilities'
fossil-fueled generating stations.
Depreciation and amortization increased during both 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' 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 relative to 1995 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 increased $1.4 million during the
twelve month period, largely because of increased property taxes at
Utilities caused by increases in assessed property values.
Interest Expense and Other Interest expense increased $3.4 million
during the twelve month period, primarily because of an increase in the
average amount of short-term debt outstanding and interest related to
Utilities' electric rate refund. Lower average interest rates,
attributable to refinancing $100 million of long-term debt at lower
rates and the mix of long-term and short-term debt, partially offset the
increase.
Income taxes increased $6.5 million and $15.1 million for the three
and twelve month periods, respectively. The increases for both periods
were due to an increase 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 3.56 and 3.04 for the twelve months
ended March 31, 1996 and March 31, 1995, respectively. Cash flows from
operating activities for the twelve months ended March 31, 1996 and
March 31, 1995 were $162 million and $190 million, respectively. The
decrease was primarily due to expenditures related to the effect of the
1995 DAEC refueling outage 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 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
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. It is not certain if, and how, the Proposed Merger may affect
the Company's debt ratings.
The IUB has current rules which 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 March 31, 1996, Utilities had
approximately $51 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.
The IUB has recently proposed changes to the Iowa statute which
would 1) eliminate the 2% and 1.5% spending requirements described above
in favor of IUB-determined energy savings targets and 2) eliminate the
delay in recovery of energy efficiency costs by allowing recovery which
is concurrent with spending, eventually eliminating the regulatory asset
which exists under the current rate making mechanism. This legislation
has been passed by the Iowa legislature and is awaiting signature by the
governor. The Company expects the governor to sign the legislation in
the second quarter of 1996.
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 expenditures of approximately $24 million for the three
months ended March 31, 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 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 March 31, 1996,
such restrictions would have allowed Utilities to issue at least
$261 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 replace one
series of First Mortgage Bonds that matures in 1996 with other long-term
securities.
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 March 31, 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 March 31, were as follows:
1996 1995
Long-term debt 46% 48%
Preferred stock 2 2
Common equity 52 50
100% 100%
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 March 31, 1996, Utilities had
outstanding short-term borrowings of $95.2 million, including
$3.2 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 March 31, 1996, $58 million was sold
under the agreement.
At March 31, 1996, the Company had bank lines of credit aggregating
$121.1 million, of which $92 million was being used to support
commercial paper (weighted average interest rate of 5.27%) 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 March 31, 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 17 sites and expects to
begin the investigation process in 1996 for the two other sites.
Utilities estimates the range of additional costs to be incurred for
investigation and/or remediation of the sites to be approximately $23
million to $59 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $35 million (including $4.6 million as
current liabilities) at March 31, 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 or has not started. 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. The amount of potential recovery, if any, or the regulatory
treatment of any such recoveries cannot be reasonably determined at this
time and, accordingly, no estimated amounts have been recorded at March
31, 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 also requires 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 and mercury. 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 repower one of the generating facilities that
was contributing to the modeled exceedences which 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
March 31, 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 five of the
states and is still pending with the sixth, and final state. Approval
by the U.S. Congress will also be required before it is effective. 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, largely
confirming earlier proposals, requiring electric utilities to open their
transmission lines to other wholesale buyers and sellers of electricity.
The rules will take effect 60 days after they are published in the
Federal Register. 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 on July 24, 1995. The tariffs
were accepted by the FERC and became effective October 1, 1995. 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 stranded costs resulting
therefrom.
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. 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 October 1, 1996, for
publishing their recommendations for restructuring.
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
Company is attempting to accomplish some of these tasks through Process
Redesign. Process Redesign is an effort undertaken by Utilities to
improve service levels, to reduce its cost structure and to become more
market-focused and customer-oriented. The major objective is to allow
Utilities to better prepare for a competitive, deregulated electric
utility industry.
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 made to change the way work was performed and
results were achieved in each of the processes, although the
recommendations were not at a very detailed level. 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. Implementation of
these changes will be substantially completed in 1996, however, 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.
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.
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.
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:
March 31, 1996 3.31
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) In light of the decision by the Board of Directors to reduce its
size, Dr. George Daly, Director of IES Utilities Inc., resigned
effective April 3, 1996.
(c) In light of the decision by the Board of Directors to reduce its
size, G. Sharp Lannom, IV, Director of IES Utilities Inc.,
resigned effective April 12, 1996.
(d) Richard A. Gabbianelli, Controller & Chief Accounting Officer of
IES Utilities Inc., resigned effective May 8, 1996.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits -
*3(a) Bylaws of Registrant, as amended May 7, 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 February 9, 1996 (1)
5,7 None April 3, 1996 (2)
5,7 None April 12, 1996 (3)
(1) The Form 8-K report was filed on February 20, 1996 with the
earliest event reported occurring on February 9, 1996.
(2) The Form 8-K report was filed on April 8, 1996 with the earliest
event reported occurring on April 3, 1996.
(3) The Form 8-K report was filed on April 18, 1996 with the earliest
event reported occurring on April 12, 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: May 14, 1996 By /s/ Stephen W. Southwick
(Signature)
Stephen W. Southwick
Vice President, General Counsel &
Secretary
By /s/ Dennis B. Vass
(Signature)
Dennis B. Vass
Treasurer & Principal Financial Officer