UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 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 Registrant; State of Incorporation; Address; IRS Employer
File Number and Telephone Number Identification No.
1-9187 IES INDUSTRIES INC. (an Iowa Corporation) 42-1271452
IES Tower, Cedar Rapids, Iowa 52401
319-398-4411
0-4117-1 IES UTILITIES INC. (an Iowa Corporation) 42-0331370
IES Tower, Cedar Rapids, Iowa 52401
319-398-4411
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange on
Registrant Title of Each Class Which Registered
IES Industries Inc. Common Stock, no par value New York Stock Exchange
IES Utilities Inc. 7-7/8% Quarterly Debt
Capital Securities New York Stock Exchange
(Subordinated Deferrable
Interest Debentures)
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Class
IES Industries Inc. None
IES Utilities Inc. Cumulative Preferred Stock Par Value $50 per share 4.80%
Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2)
have been subject to such filing requirements for the past 90
days. Yes X No
----- -----
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of the registrants' knowledge, in definitive
proxy or information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K. ______
The aggregate market value of the voting stock of IES Industries Inc.
held by non-affiliates, as of January 31, 1997 was approximately
$918,961,374 based upon the Composite Tape closing price as reported in
The Wall Street Journal. (For this purpose only, the individuals listed
under "Security Ownership of Management" in the Definitive Proxy
Statement incorporated herein by reference are considered to be
affiliates.)
The aggregate market value of the voting stock of IES Utilities Inc.
held by non-affiliates, as of January 31, 1997 was $0.
Indicate the number of shares outstanding of each of the registrants'
classes of Common Stock, as of January 31, 1997.
IES Industries Inc. Common Stock, no par value - 30,162,731 shares
IES Utilities Inc. Common Stock, $2.50 par value - 13,370,788 shares
DOCUMENTS INCORPORATED BY REFERENCE
Part of this Form 10-K into
Document Which Document is Incorporated
Definitive proxy statement of IES Industries Inc.
to be filed within 120 days of December 31, 1996 III
IES INDUSTRIES INC. and IES UTILITIES INC.
Form 10-K for the Year Ended December 31, 1996
TABLE OF CONTENTS
PART I Page No.
Item 1. Business 3
Proposed Merger of the Company 6
Construction and Acquisition Program and Financing 7
Regulation 8
Employees 9
Environmental Matters 9
Competition 11
Rate Matters 13
Electric Operations 13
Gas Operations 20
Item 2. Properties 23
Item 3. Legal Proceedings 24
Item 4. Submission of Matters to a Vote of Security Holders 25
PART II
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters 26
Item 6. Selected Consolidated Financial Data 27
Item 7. Management's Discussion and Analysis of the Results
of Operations and Financial Condition 30
Selected Consolidated Quarterly Financial
Data (unaudited) 43
Item 8. Financial Statements and Supplementary Data
IES Industries Inc. Consolidated Financial
Statements 44
IES Industries Inc. Notes to Consolidated Financial
Statements 50
IES Utilities Inc. Consolidated Financial Statements 73
IES Utilities Inc. Notes to Consolidated Financial
Statements 79
Item 9. Changes and Disagreements with Accountants on
Accounting and Financial Disclosure 84
PART III
Item 10. Directors, Executive Officers, Promoters and
Control Persons of the Registrant 85
Item 11. Executive Compensation 86
Item 12. Security Ownership of Certain Beneficial Owners
and Management 87
Item 13. Certain Relationships and Related Transactions 87
PART IV
Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 88
Schedule II - Valuation and Qualifying
Accounts and Reserves 95
Unaudited Pro Forma Combined Financial
Information of Interstate Energy Corporation 96
Signatures 105
This document contains the Annual Reports on Form 10-K for the
fiscal year ended December 31, 1996 for each of IES Industries Inc. and
IES Utilities Inc. Information contained herein relating to an
individual registrant is filed by such registrant on its own behalf.
Accordingly, except for its subsidiaries, IES Utilities Inc. makes no
representation as to information relating to IES Industries Inc. or to
any other companies affiliated with IES Industries Inc. IES Industries
Inc. and its consolidated subsidiaries may collectively be referred to as
"the Company".
From time to time, the Company may make forward-looking statements
within the meaning of the federal securities laws that involve judgments,
assumptions and other uncertainties beyond the control of the Company.
These forward-looking statements may include, among others, statements
concerning revenue and cost trends, cost recovery, cost reduction
strategies and anticipated outcomes, pricing strategies, changes in
the utility industry, planned capital expenditures, financing needs
and availability, statements of the Company's expectations, beliefs,
future plans and strategies, anticipated events or trends and similar
comments concerning matters that are not historical facts. Investors
and other users of the forward-looking statements are cautioned that
such statements are not a guarantee of future performance of the
Company and that such forward-looking statements are subject
to risks and uncertainties that could cause actual results to differ
materially from those expressed in, or implied by, such statements.
Some, but not all, of the risks and uncertainties include weather
effects on sales and revenues, competitive factors, general economic
conditions in the Company's service territory, federal and state
regulatory and government actions, the operating of a nuclear
facility and changes in the rate of inflation.
PART I
Item 1. Business
IES Industries Inc.
IES Industries Inc. (Industries) is a holding company which is
incorporated under the laws of Iowa. Industries' wholly-owned
subsidiaries are IES Utilities Inc. (Utilities) and IES Diversified Inc.
(Diversified). Utilities is primarily an electric and natural gas utility
company operating in the State of Iowa and serving
approximately 336,000 electric and 176,000 natural gas
retail customers as well as 30 electric resale customers in more than
550 Iowa communities. Diversified is a holding company for non-utility
subsidiaries which are primarily engaged in the energy-related,
transportation and real estate development businesses. Industries'
consolidated assets and earnings are predominantly those of Utilities.
Utilities
Utilities is primarily a public utility operating company engaged
in providing electric energy, natural gas and, to a limited extent,
steam used for industrial and heating purposes, in the State of Iowa.
Utilities' only wholly-owned subsidiary as of December 31, 1996,
was IES Ventures Inc. (Ventures), which is a holding company for
unregulated investments. Ventures' wholly-owned subsidiary at
December 31, 1996, was IES Midland Development Inc. (Midland), which
owns and operates a landfill in Ottumwa, Iowa. Ventures also has a 35%
equity investment in Aqua Ventures L.C., which is an aquaculture
facility formed to raise fish for human consumption.
Utilities' sales of electricity (in Kwh), excluding off-system
sales, increased 1.7%, 5.3% and 4.3%, during the years 1996-1994,
respectively. Under historically normal weather conditions, total sales
(excluding off-system sales) would have increased 3.5%, 3.6% and 4.8%
during 1996-1994, respectively. Total gas delivered by Utilities,
including transported volumes, increased or (decreased) 5.9%, 4.8% and
(2.7)% during the years 1996-1994, respectively. Under historically
normal weather conditions, Utilities' gas sales and transported volumes
would have increased 1.9%, 3.5% and 0.7% during 1996-1994, respectively.
There are seasonal variations in Utilities' electric and gas
businesses, which are principally related to the use of energy for air
conditioning and heating. In 1996, 39.8% of Utilities' electric
revenues were earned in June through September, reflecting the use of
electricity for cooling, and 72.0% of Utilities' gas revenues were
earned in the months of January - March, November and December,
reflecting the use of gas for heating.
The approximate percentages of Utilities' revenue and operating
income derived from the sale of electricity and gas during the years
1996-1994 are as follows:
1996 1995 1994
Revenues:
Electric 76% 79% 78%
Gas 21% 19 20
Operating income:
Electric 86% 92% 93%
Gas 11% 6 6
The relationships between the electric and gas percentages
presented above are influenced by changes in energy sales, timing of
regulatory price proceedings and changes in the costs of fuel or
purchased gas billed to customers through related adjustment clauses.
For additional information concerning electric and gas operations,
see Item 1. "Other Information Relating to Utilities Only", Item 7.
"Management's Discussion and Analysis of the Results of Operations and
Financial Condition" and the "Electric Operations" and "Gas Operations"
sections of Item 1.
Diversified
Other than Utilities' unregulated investments, the non-utility
operations of the Company are organized under Diversified. Diversified
is a holding company whose wholly-owned subsidiaries include IES
Transportation Inc. (IES Transportation), IES Energy Inc. (IES Energy),
IES Investments Inc. (IES Investments) and IES International Inc. (IES
International).
IES Transportation is a holding company whose wholly-owned
subsidiaries at December 31, 1996, included the Cedar Rapids and Iowa
City Railway Company (CRANDIC) and IES Transfer Services Inc.
(Transfer). CRANDIC is a short-line railway which renders freight
service between Cedar Rapids and Iowa City. Transfer's operations
include transloading and storage services. IES Transportation also has
a 75% equity investment in IEI Barge Services, Inc. (Barge) which
provides barge terminal and hauling service on the Mississippi River.
In addition, IES Transportation has investments in two Iowa railroad
companies. IES Transportation's 1996 operating revenues and assets at
December 31, 1996 were as follows:
Operating
Revenues Assets
(in 000s)
CRANDIC $ 17,375 $ 39,162
Barge 1,872 8,112
Transfer 415 838
Other (including eliminations) - 286
$ 19,662 $ 48,398
IES Energy is a holding company whose wholly-owned subsidiaries at
December 31, 1996, included Industrial Energy Applications, Inc. (IEA)
and Whiting Petroleum Corporation (Whiting). IEA offers commodities-
based and facilities-based energy services for customers, including
purchasing energy, standby generation, cogeneration, steam production
and propane air systems. Whiting is organized to purchase, develop and
produce crude oil and natural gas. IES Energy's 1996 operating revenues
and assets at December 31, 1996 were as follows:
Operating
Revenues Assets
(in 000s)
IEA $ 126,932 $ 52,204
Whiting 65,724 129,227
Other (including eliminations) (1,670) (1,255)
$ 190,986 $ 180,176
IES Investments is a holding company whose primary wholly-owned
subsidiaries at December 31, 1996, included Iowa Land and Building
Company (Iowa Land), IES Investco Inc. (Investco) and Village
Lakeshares, Inc. (Lakeshares). Iowa Land is organized to pursue real
estate and economic development activities in Utilities' service
territory. Investco is a holding company for certain equity investments
and currently has no operating revenues. The gains and losses on the
sale of such investments are recorded in "Miscellaneous, net" in Industries'
Consolidated Statements of Income. Lakeshares is a holding company for
resort properties in Iowa.
IES Investments had a $29.2 million investment in McLeod, Inc.
(McLeod), a holding company for various telecommunications businesses,
at December 31, 1996. The McLeod investment is not consolidated,
therefore Industries does not include any of McLeod's operating revenues in
its consolidated results. IES Investments also has direct and indirect
equity interests in various real estate ventures, primarily concentrated
in Cedar Rapids, and holds other passive investments. IES Investments'
1996 operating revenues and assets, other than the international
investments noted below, at December 31, 1996, were as follows:
Operating
Revenues Assets
(in 000s)
Iowa Land $ 1,570 $ 11,969
Investco - 2,941
Lakeshares 4,313 11,230
Real estate ventures 3,863 24,893
Investment in McLeod - 29,200
Other (including eliminations) - 13,535
$ 9,746 $ 93,768
IES International is a holding company whose wholly-owned
subsidiaries are IES New Zealand Limited (IES New Zealand) and
Interstate Energy Corporation Pte Ltd. (IECP). IES New Zealand has
equity investments in two New Zealand electric distribution entities.
IECP has a 50% equity investment in JIES Heat and Power Ltd., a
cogeneration facility in China. None of the investments under IES
International are consolidated, therefore IES International has no
operating revenues. (IES Investments also has several investments in
foreign entities, including a loan to a New Zealand company and an
investment in an international venture capital fund. These investments
are considered international investments for management purposes and
therefore are included in the following schedule.) IES International's
assets at December 31, 1996, were as follows:
Assets
(in 000s)
IES New Zealand $ 19,819
Investment in JIES Heat and Power Ltd. 13,598
IES Investments' foreign investments 11,665
Other (including eliminations) (136)
$ 44,946
Refer to Note 15 of Industries' Notes to Consolidated Financial
Statements for a further discussion of the Company's segments of business.
Other Information Relating to the Company
PROPOSED MERGER OF THE COMPANY. Industries, WPL Holdings, Inc.
(WPLH) and Interstate Power Company (IPC) have entered into an
Agreement and Plan of Merger, as amended (Merger Agreement), dated
November 10, 1995, which provides for the combination of all three
companies (Proposed Merger). The new company will be named Interstate Energy
Corporation (IEC).
WPLH is a holding company headquartered in Madison, Wisconsin, and
is the parent company of Wisconsin Power and Light Company (WP&L) and
Heartland Development Corporation (HDC). WP&L supplies electric and gas
service to approximately 385,000 and 150,000 customers, respectively, in
south and central Wisconsin. HDC and its principal subsidiaries are
engaged in businesses in three major areas: environmental engineering
and consulting, affordable housing and energy services. IPC, a public
utility headquartered in Dubuque, Iowa, supplies electric and gas
service to approximately 165,000 and 49,000 customers, respectively, in
northeast Iowa, northwest Illinois and southern Minnesota.
The Proposed Merger, which will be accounted for as a pooling of
interests, has been approved by the respective Boards of Directors and
shareholders. The merger is conditioned on the receipt of approvals of
several federal and state regulatory agencies. The status of these
approvals is as follows:
On January 15, 1997, the Federal Energy Regulatory Commission
(FERC) issued an order in which it accepted several provisions of the
IEC merger application without the need for public hearings. The FERC
has set limited issues for hearing, including generation market power in
the transmission-constrained Wisconsin Upper Michigan System (WUMS)
subregion in Wisconsin. The FERC has also ordered the merger partners to
attempt to negotiate a wholesale customer protection mechanism with
those intervenors who are not satisfied with the four year rate freeze
proposed in the application. If an agreement between the merger
partners and the intervenors is not reached, the FERC will decide the
issue. A final decision on the merger is expected to be issued by the
FERC by the end of the third quarter of 1997.
Utilities and IPC announced in 1996 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 IEC
merger application filed with the Iowa Utilities Board (IUB). The
proposal excludes price changes due to government-mandated programs,
such as energy efficiency cost recovery, or unforeseen dramatic changes
in operations. Hearings before the IUB are expected to be held in the
summer of 1997 with a decision expected by the end of the third quarter
of 1997.
In March of 1996, an application requesting approval of the merger
was filed with the Public Service Commission of Wisconsin (PSCW).
Hearings are currently scheduled for June 4, 1997, with a decision
anticipated in the third quarter of 1997. Legislation was introduced in
the Wisconsin State Senate in February 1997 which could delay the PSCW
approval of the merger. Industries cannot predict the outcome of such
legislation.
In March of 1996, an application requesting approval of the merger
was also submitted to the Illinois Commerce Commission (ICC). The ICC
conducted hearings on November 12, 1996 and final briefs were filed on
December 23, 1996. A decision is pending.
On January 15, 1997, the Minnesota Public Utilities Commission
(MPUC) announced that it had approved the IEC merger without hearings,
subject to a number of technical conditions, which Industries
anticipates will not be opposed by the merger partners. Included in
these conditions is a four year rate freeze for IEC's electric and gas
customers in the state of Minnesota.
An application to establish IEC as a registered holding company
under the Public Utility Holding Company Act of 1935 (1935 Act) was
submitted to the Securities and Exchange Commission (SEC). The period
for comments by interested parties closed on November 5, 1996. A
decision on the application is expected at the end of the third quarter
of 1997. The SEC historically has interpreted the 1935 Act to preclude
registered holding companies, with limited exceptions, from owning both
electric and gas utility systems. In addition, the SEC could also
require that IEC divest certain non-utility ventures of Industries and
WPLH. As part of the application, IEC has requested permission to
retain its existing gas utility properties and non-utility ventures.
An impact review of the merger on market power, which is required
by the Hart-Scott-Rodino Antitrust Improvements Act, was completed by
the U.S. Department of Justice (DOJ). All requirements of this review
have been satisfied. If the merger is not consummated before July 7,
1997, the merger partners will be required to submit new information to
the DOJ. The merger partners do not believe that any such resubmission
would cause a material delay in approval.
An application was filed with the Nuclear Regulatory Commission
(NRC) to approve the transfer of indirect control over the licenses of
Utilities and WP&L for the Duane Arnold Energy Center (DAEC) nuclear
facility and Kewaunee Nuclear Power Plant, respectively, to IEC. Both
plants are jointly owned with other companies. The application, which
was filed on October 1, 1996, is pending.
See Note 2 of Industries' Notes to Consolidated Financial
Statements and Item 14 for further information and the unaudited pro
forma financial statements of IEC, respectively.
CONSTRUCTION AND ACQUISITION PROGRAM AND FINANCING.
The Company's construction and acquisition program
anticipates expenditures of approximately $225 million
for 1997, of which approximately $147 million represents
expenditures at Utilities and approximately $78 million
represents expenditures at Diversified. Of the $147 million
of Utilities' expenditures, 39% represents expenditures for
electric transmission and distribution facilities, 21%
represents electric generation expenditures, 21% represents
information technology expenditures and 5% represents
gas expenditures. The remaining 14% represents
miscellaneous electric, steam and general expenditures.
Diversified's anticipated expenditures include approximately
$75 million for domestic and international energy-related
construction and acquisition expenditures.
The Company's levels of construction and acquisition
expenditures are projected to be $208 million in 1998,
$212 million in 1999, $182 million in 2000 and $198
million in 2001. It is estimated that virtually all of Utilities'
construction and acquisition expenditures will be provided by
cash from operating activities (after payment of dividends)
for the five-year period 1997 - 2001. Financing plans for
Diversified's construction and acquisition program will
vary, depending primarily on the level of energy-related
acquisitions.
Capital expenditure and investment and financing plans
are subject to continual review and change. The capital
expenditure and investment programs may be revised
significantly as a result of many considerations including
changes in economic conditions, variations in actual sales
and load growth compared to forecasts, requirements of
environmental, nuclear and other regulatory authorities,
acquisition and business combination opportunities, the
availability of alternate energy and purchased power sources,
the ability to obtain adequate and timely rate relief, escalations
in construction costs and conservation and energy efficiency
programs.
Under provisions of the Merger Agreement, there are
restrictions on the amount of construction and acquisition
expenditures the Company can make pending the merger.
The Company does not expect the restrictions to have a
material effect on its ability to implement its anticipated
construction and acquisition program.
Other than Utilities' periodic sinking fund requirements,
which Utilities intends to meet by pledging additional
property, the following long-term debt will mature prior
to December 31, 2001:
(in millions)
Utilities $207.2
Diversified's credit facility 172.1
Other subsidiaries' debt 11.2
$390.5
The Company intends to refinance the majority of the
debt maturities with long-term securities.
For a discussion regarding the Company's assumptions in financing
future capital requirements, see the "Liquidity and Capital Resources"
section of Item 7. "Management's Discussion and Analysis of the Results
of Operations and Financial Condition."
REGULATION. Because of its ownership of Utilities, Industries is a
"holding company" as defined by the 1935 Act. However, Industries
claims exemption from regulation under the 1935 Act (except for Section
9(a)2 thereof, which requires that any acquisition of securities of a
utility company by Industries be approved by the SEC) on the basis that
Industries and Utilities are both organized in the same state and
Utilities conducts its business in that state. Congress began examining
repeal of PUHCA during 1995 and is expected to continue reviewing this
issue. No assurance can be given as to when or if such legislation will
be considered or enacted.
Utilities operates pursuant to the laws of the State of Iowa and is
thereby subject to the jurisdiction of the IUB. The IUB has authority
to regulate rates and standards of service, to prescribe accounting
requirements and to approve the location and construction of electric
generating facilities having a capacity in excess of 25,000 Kw. The IUB
is comprised of three Commissioners appointed by the Governor and
ratified by the State Senate. Requests for price relief are based on
historical test periods, adjusted for certain known and measurable
changes. The IUB must decide on requests for price relief within 10
months of the date of the application for which relief is filed or the
interim prices granted become permanent. Interim prices, if allowed,
are permitted to become effective, subject to refund, no later than 90
days after the price increase application is filed.
In Iowa, non-exclusive franchises, which cover the use of streets
and alleys for public utility facilities in incorporated communities,
are granted for a maximum of twenty-five years by a majority vote of
local qualified residents. In addition, the IUB defines the boundaries
of mutually exclusive service territories for all electric utilities.
The IUB has jurisdiction and grants franchises for the use of public
highway rights-of-way for electric and gas facilities outside corporate
limits.
Utilities is subject to the jurisdiction of the FERC with respect
to wholesale electric sales, its accounting practices and the issuance
of securities. Revenues derived from Utilities' wholesale and off-
system sales amounted to 6.5%, 6.3% and 6.9% of electric revenues for
1996-1994, respectively. Utilities' consolidated subsidiaries are not
subject to regulation by the IUB or the FERC.
Following consummation of the Proposed Merger, Interstate Energy
will be subject to regulation by the PSCW, as WPLH and
WP&L are currently. The PSCW regulates, among otherthings,
the type and amount of investments in non-utility businesses.
The Company does not expect such regulation to have a materially adverse
effect upon Interstate Energy following the Proposed Merger.
See the "Environmental Matters", "Competition", "Electric
Operations" and "Gas Operations" sections of Item 1 for a discussion of
various other regulatory issues.
EMPLOYEES. At December 31, 1996, the Company had a total of 2,406
(2,016 at Utilities) regular full-time employees. At December 31, 1996,
Utilities had 1,081 employees subject to 6 collective bargaining
agreements (776 of these employees were part of one agreement), CRANDIC
had 71 employees subject to 4 collective bargaining agreements and Barge
had 6 employees subject to 1 collective bargaining agreement. None of
Utilities' bargaining agreements expires in 1997.
ENVIRONMENTAL MATTERS. The Company is regulated in environmental
protection matters by a number of federal, state and local agencies.
Such regulations are the result of a number of environmental protection
laws passed by the U. S. Congress, state legislature and local
governments and enforced by federal, state and county agencies. The
laws impacting the Company's operations include the Clean Water Act;
Clean Air Act, as amended by the Clean Air Act Amendments of 1990;
National Environmental Policy Act; Resource Conservation and Recovery
Act; Comprehensive Environmental Response, Compensation and Liability
Act of 1980 (CERCLA), as amended by the Superfund Amendments and
Reauthorization Act of 1986; Occupational Safety and Health Act;
National Energy Policy Act of 1992 and a number of others. The Company
regularly secures and renews federal, state and local permits to comply
with the environmental protection laws and regulations. Costs
associated with such compliances have increased in recent years and are
expected to increase moderately in the future.
Utilities has been named as a Potentially Responsible Party (PRP)
by various federal and state environmental agencies for 28 Former
Manufactured Gas Plant (FMGP) sites. Utilities has recorded
environmental liabilities related to the FMGP sites of approximately $36
million (including $4.7 million as current liabilities) at December 31,
1996. Regulatory assets of approximately $36 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. Refer to Note 13(f) of Industries' Notes to Consolidated
Financial Statements for a further discussion, including a discussion of
a lawsuit filed by Utilities seeking recovery of FMGP-related costs from
its insurance carriers.
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 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.
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
Standards established for SO2. The worst-case modeling study suggested
that two of Utilities' generating facilities contribute to the modeled
exceedences.
Pursuant to a routine review of operations, Utilities determined
that certain changes undertaken during the previous three years at one
of its power plants may have required a federal Prevention of
Significant Deterioration (PSD) permit. Refer to Note 13(g) of
Industries' Notes to Consolidated Financial Statements for a further
discussion of the above mentioned air quality issues.
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." Refer to Note 13(f) of
Industries' Notes to Consolidated Financial Statements for a further
discussion.
The Nuclear Waste Policy Act of 1982 assigned responsibility to the
U.S. Department of Energy (DOE) to establish a facility for the ultimate
disposition of high level waste and spent nuclear fuel and authorized
the DOE to enter into contracts with parties for the disposal of such
material beginning in January 1998. Utilities entered into such a
contract and has made the agreed payments to the Nuclear Waste Fund
(NWF) held by the U.S. Treasury. The DOE, however, has experienced
significant delays in its efforts and material acceptance is now
expected to occur no earlier than 2010 with the possibility of further
delay being likely. Utilities has been storing spent nuclear fuel on-
site since plant operations began in 1974 and has current on-site
capability to store spent fuel until 2001. Utilities is aggressively
reviewing options for expanding on-site storage. Utilities has been
formally notified by the DOE that they anticipate being unable to begin
acceptance of spent nuclear fuel by January 31, 1998. Utilities is
evaluating courses of action to protect the interests of its customers
and its rights under the DOE contract. Utilities is also evaluating
legislation proposed to the Congress addressing this issue. In July
1996, the IUB initiated a Notice of Inquiry (NOI) on spent nuclear fuel.
One purpose of the NOI was to evaluate whether the current collection of
money from Utilities' customers for payment to the NWF should be placed
in an escrow account in lieu of being paid to the NWF. Utilities
believes that the issue of using an escrow account should be decided at
the federal level rather than the state level. Utilities cannot predict
the outcome of this NOI.
The Low-Level Radioactive Waste Policy Amendments Act of 1985
mandated that each state must take responsibility for the storage of low-
level radioactive waste produced within its borders. The State of Iowa
has joined the Midwest Interstate Low-Level Radioactive Waste Compact
Commission (Compact), which is planning a storage facility to be located
in Ohio to store waste generated by the Compact's six member states. At
December 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 was approved in 1996 by all six
states that are members of the Compact. Final approval by the U.S.
Congress is now required. On-site storage capability currently exists
for low-level radioactive waste expected to be generated until the
Compact facility is able to accept waste materials. In addition, the
Barnwell, South Carolina disposal facility has reopened for an
indefinite time period and Utilities is in the process of shipping to
Barnwell the majority of the low-level radioactive waste it has
accumulated on-site, and currently intends to ship the waste it produces
in the future as long as the Barnwell site remains open, thereby
minimizing the amount of low-level waste stored on-site. However,
management of the Barnwell site has modified its fee schedule to
emphasize total radioactivity content and weight, instead of the
historical volume related fees. Utilities is evaluating the outcome of
these changes on its potential future disposal costs at the Barnwell
site; such changes could result in a revision to Utilities' future
disposal plans.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects has been the subject of
increased public, governmental, industry and media attention. A recent
study completed by the National Research Council concluded that the
current body of evidence does not support the notion that exposure to
these fields may result in adverse health effects. Utilities will
continue to monitor the events in this area, including future scientific
research.
Whiting is responsible for certain dismantlement and abandonment
costs related to various off-shore oil and gas properties. Refer to
Note 13(f) of Industries' Notes to Consolidated Financial Statements for
a further discussion.
Utilities was notified in 1986 that it was designated by the EPA as
a PRP (there are 832 in total) for the investigation and cleanup of the
Maxey Flats Nuclear Disposal site at Morehead, Kentucky. The EPA notice
encouraged all PRPs to undertake voluntary clean up activities at the
site. A Steering Committee was organized and Utilities is participating
in its activities. The Steering Committee has reached settlement of the
issues with the EPA, the State of Kentucky and deminimis parties.
Consent Decrees have been finalized and Utilities' share of the cost is
estimated at $250,000, which is included in the $53 million of
environmental liabilities the Company has recorded at December 31, 1996.
Refer to Note 13 of Industries' Notes to Consolidated Financial
Statements for further discussion of environmental matters.
Other Information Relating to Utilities Only
COMPETITION. Utilities and its predominant business, electric
energy generation, transmission and distribution, are in a period of
fundamental change in the manner in which customers obtain, and energy
suppliers provide, energy services. 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. 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. The non-rate provisions of the tariffs were
approved on November 13, 1996. FERC has not yet ruled on the rate
provisions of the tariffs. 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 ofoperations or financial
condition.
FERC does not have jurisdiction over the retail jurisdiction, and
thus the final FERC rules do not provide for the recovery of stranded
costs resulting from retail competition. The various states retain
jurisdiction over the question of 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.
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" to address all forms of competition in the electric
utility industry and to gather information and perspectives on electric
competition from all persons or entities with an interest or stake in
the issues. 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 conducted public information meetings
around the State of Iowa. A draft report was created by the IUB staff
and is expected to be finalized in the first quarter of 1997. The draft
report indicated that the IUB is of the opinion that there is no
compelling reason to move quickly into restructuring the electric
utility industry in Iowa. However, they will continue the analysis and
debate on restructuring and retail competition in Iowa.
As part of Utilities' strategy for the emerging and competitive
power markets, Utilities, IPC, WP&L and a number of other utilities have
proposed the creation of an independent system operator (ISO) for the
companies' power transmission grid. The companies would retain
ownership and control of the facilities, but the ISO would set rates for
access and assure fair treatment for all companies seeking access. The
proposal requires approval from state regulators and the FERC. Various
other proposals for ISO's have been made by other companies and
Utilities is monitoring all such proposals. Membership in an ISO could
become a condition of merger approval by the various regulatory bodies.
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. In
addition, the Company would be required to determine any impairment to
other assets and write-down such assets to their fair value. 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 is in the final stages of a significant process improvement
program to improve its service levels, reduce its cost structure and
become more market-focused and customer oriented. (The Company's
continuous improvement efforts, in general, will be an ongoing effort,
however).
Examples of the process improvement changes being implemented are,
but are not limited to: managing the business in business unit form,
rather than functionally; formation of alliances with vendors of certain
types of material and/or services rather than opening most purchases to
a bidding process; changing standards and construction practices in
transmission and distribution areas; changing certain work practices in
power plants; making investments in information technology upgrades; and
improving the method by which service is delivered to customers in all
customer classes. The specific changes range from simple improvements
in current operations to radical changes in the way work is performed
and service is delivered. Some of the changes are currently in the
pilot stage thus the results from this evaluation period or the
potential effects of the pending merger could prove that some of the
changes are not efficient or effective and must be revised or
eliminated. Subject to delays caused by implementing any such
revisions, implementation of the changes began in 1996 and will continue
into 1997; however, certain results will not be realized until 1997. In
addition, the Company must give consideration to the potential effects
of the pending merger as part of the implementation process so that
duplication of efforts are avoided.
RATE MATTERS. Refer to Note 3 of Industries' Notes to Consolidated
Financial Statements for a discussion of Utilities' rate matters,
including its electric price freeze proposals.
ELECTRIC OPERATIONS -
General Utilities' net peak load (60 minutes integrated) of 1,833,203
kilowatts occurred on August 6, 1996, and represented a new energy peak
demand record. At the time of the peak load, 75 interruptible customers
were interrupted representing approximately 206,000 kilowatts of a
possible 382,259 kilowatts available for interruption. Utilities'
additional reserve obligation at the time of the peak was 262,980
kilowatts and the net capability of Utilities' generating stations was
1,864,390 kilowatts, with an additional 232,000 kilowatts being
available under purchase contracts, thereby providing an aggregate
capability of 2,096,390 kilowatts.
Utilities projects an electric sales growth rate of approximately 2
to 3 percent per year over the next five years, which will be met by a
mix of its existing generation, capacity purchases and new construction.
The construction activities will be undertaken in a fashion that best
meets the needs of individual customers and the system as a whole. See
Note 13(b) of Industries' Notes to Consolidated Financial Statements for
a discussion of Utilities' firm contracts for the purchase of capacity.
Utilities' electric facilities are interconnected with certain Iowa
and neighboring utilities. Also, Utilities is a member of the
Mid-Continent Area Power Pool (MAPP). This pool is comprised of 18
utilities which are Transmission Owning Members (TOMs) and 58 energy-
related companies providing services in the upper midwest region of the
United States, and operates pursuant to an agreement which provides for
the interchange of electric energy, the sharing of responsibilities for
production capacity and reserve and the supply of electric energy.
Utilities is a party to the Twin Cities-Iowa-St. Louis 345 Kv
Interconnection Coordinating Agreement (the Coordinating Agreement) with
five other midwestern utilities, three of which operate in the State of
Iowa. The Coordinating Agreement provides for the interconnection of
the respective systems of the companies through a 345 Kv transmission
line and for the interchange of power on various bases. The rates under
the Coordinating Agreement are primarily determined by agreement between
the delivering and receiving companies.
Utilities maintains and operates transmission and substation
facilities connecting with its high voltage transmission systems
pursuant to a non-cancelable operating agreement (the Operating
Agreement) with Central Iowa Power Cooperative (CIPCO). The Operating
Agreement, which will terminate on December 31, 2035, provides for the
joint use of certain transmission facilities of Utilities and CIPCO.
The Resale Power Group of Iowa (RPGI), consisting of virtually all
of Utilities' wholesale customers, has notified Utilities that it will
not purchase its power supply from Utilities after December 31, 1998.
It is possible that certain RPGI customers will drop out of RPGI in
order to remain as Utilities' customers. RPGI will continue to purchase
transmission services from Utilities after December 31, 1998. While the
Company cannot determine the outcome of this issue at this time, the
result will not have a material adverse effect on its financial position
or results of operations given 1) Utilities' wholesale sales only
accounted for approximately 5% of Utilities' total 1996 electric sales,
excluding off-system sales; 2) Utilities currently has to supplement its
generating capability with purchased power to meet its sales load; and
3) Utilities' annual electric sales growth rate continues to be strong.
Upon consummation of the Proposed Merger, Utilities expects to
realize reduced electric production costs through the joint dispatch of
systems and increased marketing opportunities in the wholesale and
interchange markets through electric interconnections with other
utilities.
For comments relating to agreements between Utilities and its
partners for the joint ownership of the DAEC, the Ottumwa Generating
Station (OGS) and Neal Unit No. 3, see Item 2. "Properties" and Note 14
of Industries' Notes to Consolidated Financial Statements.
Fuel Supply The following table details the sources of the electricity
sold by Utilities during 1996 and expected sources for the following
three years:
Actual /------------ Expected ------------/
1996 1997 1998 1999
Fossil, primarily coal 42% 63% 64% 63%
Nuclear 23 26 23 23
Purchases 35 11 13 14
100% 100% 100% 100%
The 1996 fossil percentage was lower than anticipated because of
several maintenance outages at the various fossil-fueled generating
facilities. Utilities expects its off-system sales in 1997-1999 to be
significantly lower than they were in 1996 as the result of the
implementation of FERC Order 888. This results in a significant
reduction in the purchases figures in 1997-1999. Utilities is
currently on an eighteen-month cycle for nuclear refueling
outages and the above percentages assume outages will
occur during both 1998 and 1999. There was also a refueling outage in
1996.
Utilities' primary fuel source is coal and the generation mix is
influenced directly by refueling outages at the DAEC. The average cost
of fuel used for generation by Utilities for the years 1996-1994 is
presented below:
1996 1995 1994
Average cost of fuel:
Nuclear, per million Btu's $ .73 $ .76 $ .67
Coal, per million Btu's .95 .97 .97
Average for all fuels, per million Btu's .94 .95 .89
The decrease in the average cost of coal during 1996 was primarily
due to a decline in Wyoming coal prices and burning more lower priced
Wyoming coal and less higher priced Illinois Basin coal. The increase
in the average cost of nuclear fuel during 1995 was the result of
compounded interest charges on uranium acquired during the mid-1980's.
Utilities used the last of this uranium during the 1996 refueling
outage. Utilities has entered into a contract to meet its nuclear
fuel needs beyond 1996 and the average cost of such fuel is expected to
be significantly lower than the prior periods.
The following table summarizes Utilities' minimum coal contract
commitments at December 31, 1996:
Average
Annual Maximum estimated base price
Quantity Termination Sulfur per ton of coal delivered
(000s Tons) Date Content 1997 1998 1999
Cordero Mining Co.
(OGS) (1) 774 12/31/01 0.6% $ 18.86 $ 19.40 $ 19.99
Koch Carbon Inc.
(Sutherland) 100 12/31/99 6.2% $ 19.77 $ 20.07 $ 20.37
Powder River Coal Co.
(OGS or BGS) (2) 1,200 12/31/97 0.4% $ 13.19 $ N/A $ N/A
Caballo Coal Co.
(Sutherland) 450 12/31/97 0.5% $ 12.66 $ N/A $ N/A
Caballo Rojo / Ft. Union
(BGS) (3) 714 12/31/97 0.3% $ 14.83 $ N/A $ N/A
Caballo Rojo / Ft. Union
(Prairie Creek) (3) 986 12/31/97 0.3% $ 16.43 $ N/A $ N/A
Franklin Coal Sales Co.
(OGS) 225 9/30/97 0.5% $ 12.68 $ N/A $ N/A
(1) Cost under the contract is comprised of base contract
prices plus specifically contracted periodic adjustments for
increases in certain specific costs of producing the coal.
The effect of such adjustments to the base contract prices of
future coal cannot currently be predicted with any certainty.
(2) The contract covers 1,200,000 annual tons delivered to
either the OGS or the Burlington Generating Station (BGS).
Utilities anticipates that 100% of the total 1997 contract
tons will be delivered to OGS. The price listed in the table
is for OGS, with the BGS price being $16.04 per ton.
(3) The contract covers 1,700,000 annual tons to be delivered
to either the Prairie Creek Generating Station (PC) or the
BGS, from either Caballo Rojo or Ft. Union. The price listed
in the table for BGS is for Ft. Union coal and the price
listed in the table for PC is for Caballo Rojo coal. Utilities
anticipates that 100% of PC's shipments will be
Caballo Rojo coal, with BGS shipments being 35% from Caballo
Rojo and the remaining 65% from Ft. Union. The price for
Caballo Rojo coal to BGS is $15.39 per ton.
During 1996, Utilities purchased a total of 3,518,000 tons of coal
for its generating plants. At December 31, 1996, Utilities had a
weighted average of approximately 60 days' usage of coal inventory at
its principal generating stations based upon the 1997 expected usage.
Utilities estimates that its existing coal fired generating units
will require approximately 12,837,000 tons of coal to operate during the
period 1997-1999. The average annual quantities listed in the preceding
table represent Utilities' minimum commitments. Many of the contracts
contain provisions allowing Utilities to purchase additional tons of
coal. Utilities estimates that it has the capability to purchase almost
50% of its 1997-1999 coal requirements under these contracts and will
meet the remainder of its requirements from either future contracts or
purchases in the spot market. Utilities believes that an ample supply of
coal is available in the spot market to meet its needs.
Some of Utilities' contracted coal supply is provided by surface
mining operations which are regulated by the Federal Strip Mine Act.
Most of the surface mining coal contracts contain clauses which pass
reclamation and royalty costs through to the respective utility; such
costs billed to Utilities are recoverable through its Energy Adjustment
Clauses (EAC). See Note 1(k) of Industries' Notes to Consolidated
Financial Statements for discussion of the EAC.
A contract for enrichment services and enriched uranium product was
signed with the United States Enrichment Corporation (USEC) in 1995,
which will reduce Utilities' enrichment and uranium costs. This
contract will be effective through 2001 and may extend beyond 2001 if
certain conditions occur. Fabrication of the nuclear fuel is being
performed by General Electric Company for fuel through the 2008
refueling of the DAEC. Utilities believes that an ample supply of
uranium and enrichment services will be available in the future and
intends to purchase such uranium and enrichment services as necessary on
the spot market and/or via medium length (less than five years)
contracts to supplement its current contracts and meet its generation
requirements. See Note 13(f) of Industries' Notes to Consolidated
Financial Statements for a discussion of Utilities' assessment under the
National Energy Policy Act of 1992 for the "Uranium Enrichment
Decontamination and Decommissioning Fund," which is based upon prior
nuclear fuel purchases.
Refer to Item 1. "Environmental Matters" for a discussion of
nuclear waste disposal issues.
Nuclear As an owner and the operator of a nuclear generating unit at
the DAEC, Utilities is subject to the jurisdiction of the NRC. The NRC
has broad supervisory and regulatory jurisdiction over the construction
and operation of nuclear reactors, particularly with regard to public
health, safety and environmental considerations. Utilities' current NRC
license for DAEC expires in 2014.
The operation and design of nuclear power plants is under constant
review by the NRC. Utilities has complied with and is currently
complying with all NRC requests for data relating to these reviews. As
a result of such reviews, further changes in operations or
modifications of equipment may be required, the cost of
which cannot currently be estimated. Utilities' anticipated nuclear-
related construction expenditures for 1997-2001 are approximately $33
million.
The DAEC received the highest ratings in its history in the
NRC's last Systematic Assessment of Licensee Performance (SALP) report
by earning the highest score possible (1 on a 3-point scale) in the
areas of plant operations, engineering and plant support and a "good"
rating (2) in the area of maintenance. The SALP evaluation process is
being reviewed along with an overall rebaselining of regulatory strategy
and initiatives by the NRC. The results of this NRC effort appear to
include an overall reduction in SALP scores across the nuclear industry.
The effect on the DAEC will be clearer after the current evaluation
period closes in the second quarter of 1997.
Utilities conducted an inspection during the 1996 refueling outage
of the DAEC reactor core internals. No cracks were identified and no
related repairs were required. Utilities continues its efforts to
monitor and maintain the reactor core internals.
The large number of design documents, drawings, specifications,
license documents, analyses, evaluations, reports, procedures,
instructions and other documents related to nuclear plant design and
operation present a particular challenge to Utilities to make sure all
affected plant documents are updated when changes are made to
a nuclear plant's design or operating practice. The NRC is currently
applying new, and more exacting, interpretations to existing
regulations that result in increased expectations relating to the
level of detail and the scope of the information to be documented.
Utilities has made significant efforts through its configuration
management and design basis programs, and expects to continue
such efforts in the future, to meet the NRC's expectations.
Under the Price-Anderson Amendments Act of 1988 (1988 Act),
Utilities currently has the benefit of $8.9 billion of public liability
coverage which would compensate the public in the event of an accident
at a commercial nuclear power plant. The 1988 Act permits such coverage
to rise with increased availability of nuclear insurance and the
changing number of operating nuclear plants subject to retroactive
premium assessments. The 1988 Act provides for inflation indexing
(Consumer Price Index every fifth year) of the retroactive premium
assessments.
As an outgrowth of the Three Mile Island Nuclear Power Plant (TMI)
experience, nuclear plant owners have initiated a cooperative insurance
program designed to help cover business interruption expenses for
participating utilities arising from a possible nuclear plant event.
Utilities is a participant in this program. This type of insurance is
an industry response intended to lessen the cost burden on customers in
the event of a lengthy plant shutdown.
To provide this coverage, a nuclear utility mutual insurance
company known as Nuclear Electric Insurance Limited (NEIL) was formed.
Under Utilities' policy, following a 21 week waiting period from the
time of an accident, coverage of up to 100% of estimated replacement
power costs for an ensuing one year period is provided and up to 80% of
that amount will be provided for a second and third year. The annual
premium cost to Utilities is estimated to be less than the cost of
replacement power for one week.
Utilities currently carries primary property insurance coverage on
the DAEC facility of $500 million with Nuclear Mutual Limited (NML).
Following the TMI incident, it became apparent to nuclear plant owners
that the commercially available property insurance was inadequate
considering the cost of decontamination. Consequently, Utilities
obtained excess property insurance through NEIL, providing an additional
$1.4 billion of coverage after losses exceed $500 million. These
policies bring the total property coverage to $1.9 billion.
For information concerning the potential assessment of retroactive
premiums relating to the above described public liability, replacement
power and excess property insurance coverages, refer to Note 13(e) of
Industries' Notes to Consolidated Financial Statements. The NRC
established requirements with respect to guaranteeing the ability of
owners to make such retroactive payments on the public liability policy.
Of the various alternatives available, Utilities elected to submit
certified financial statements showing that sufficient cash flow could
be generated and would be available for payment of the required
assessments within a three month period. The maximum of the annual
retroactive premiums was approximately $7 million at December 31, 1996.
In the unlikely event of 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.
Refer to Item 1. "Environmental Matters" for a discussion of
nuclear waste disposal issues and Note 1(g) of Industries' Notes to
Consolidated Financial Statements for a discussion of the
decommissioning of the DAEC.
ELECTRIC OPERATING COMPARISON
1996 1995 1994 1993 1992 1986
Operating revenues (000's):
Residential and rural $ 212,799 $ 216,270 $ 199,587 $ 203,870 $ 176,811 $ 160,267
General service 98,196 97,496 97,454 99,221 87,202 75,649
Large general service 213,223 199,840 191,601 184,657 140,496 127,034
Street lighting 8,778 8,810 8,521 8,404 7,241 7,194
Total from ultimate consumers 532,996 522,416 497,163 496,152 411,750 370,144
Sales for resale 17,894 17,554 19,195 20,254 18,602 14,963
Off-system 19,490 17,802 18,077 29,400 28,304 34,397
Other 3,893 2,699 2,892 4,715 4,343 2,091
$ 574,273 $ 560,471 $ 537,327 $ 550,521 $ 462,999 $ 421,595
Energy sales (000's Kwh):
Residential and rural 2,633,704 2,680,340 2,484,089 2,518,580 2,146,079 2,122,204
General service 1,231,115 1,242,373 1,170,923 1,166,072 1,061,444 914,665
Large general service 5,500,606 5,283,694 4,990,890 4,581,590 3,320,439 2,629,046
Street lighting 73,381 77,388 77,952 78,004 75,957 78,754
Total to ultimate consumers 9,438,806 9,283,795 8,723,854 8,344,246 6,603,919 5,744,669
Sales for resale 514,398 499,719 567,721 561,276 528,752 411,043
Sales of electricity to customers 9,953,204 9,783,514 9,291,575 8,905,522 7,132,671 6,155,712
Off-system 1,231,298 1,086,121 1,137,219 2,068,015 2,275,616 2,349,985
11,184,502 10,869,635 10,428,794 10,973,537 9,408,287 8,505,697
Sources of electric energy (000's Kwh):
Generation:
Fossil, primarily coal 4,972,736 5,775,002 5,522,966 5,356,930 4,317,154 3,983,607
Nuclear (1) 2,753,542 2,610,979 2,875,867 2,264,507 2,402,501 2,095,334
Hydro 7,081 7,690 8,205 7,201 7,579 5,595
7,733,359 8,393,671 8,407,038 7,628,638 6,727,234 6,084,536
Purchases 4,176,700 3,012,934 2,646,673 3,949,296 3,322,182 2,930,845
11,910,059 11,406,605 11,053,711 11,577,934 10,049,416 9,015,381
Net capability at time of peak load (Kw):
Generating capability 1,864,390 1,873,300 1,741,100 1,733,700 1,718,600 1,626,600
Purchase capability 232,000 207,100 280,000 248,000 207,000 100,000
2,096,390 2,080,400 2,021,100 1,981,700 1,925,600 1,726,600
Net peak load (Kw) (2) 1,833,203 1,824,100 1,779,627 1,716,380 1,425,441 1,380,391
Cooling degree days as
percentage of normal 89% 128% 99% 89% 72% 106%
Number of customers at year-end 336,048 333,489 330,405 327,265 325,172 299,506
Revenue per Kwh (excluding
off-system) in cents 5.57 5.55 5.59 5.85 6.09 6.29
(1) Represents IES Utilities' 70% undivided interest in the
Duane Arnold Energy Center, which is operated by IES Utilities Inc.
(2) 60 minutes integrated.
GAS OPERATIONS. With the advent of FERC Order 636 (Order 636),
issued in 1992, the nature of Utilities' gas supply portfolio has
changed. Order 636, among other things, eliminated the interstate
pipelines' obligation to serve and now requires Utilities to purchase
virtually 100% of its gas supply requirements from non-pipeline
suppliers. Utilities has enhanced access to competitively priced gas
supply and more flexible transportation services as a result of Order
636. 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 December
31, 1996, has recorded a liability of $4.2 million for those transition
costs that have been incurred, but not yet billed, by the pipelines to
date, including $2.1 million expected to be billed through 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
$3.8 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.
Contracts with the pipelines subsequent to Order 636 are comprised
primarily of firm transportation, firm storage and no-notice service.
Firm transportation contracts grant Utilities access to firm pipeline
capacity which is used to transport gas supplies from non-pipeline
suppliers on peak day. Firm storage service allows Utilities to
purchase gas during off-peak periods and place this gas in an account
with the pipelines. When the gas is needed for peak day deliveries,
Utilities requests and the pipelines deliver the gas back on a firm
basis. No-notice service grants Utilities the right to take more or
less gas than is actually scheduled up to the level of no-notice
service. No-notice service takes the form of transportation balancing
or storage service depending on the pipeline.
Utilities' portfolio of firm transportation, firm storage and no-
notice service from pipelines is as follows:
Firm Firm
Transportation Storage No-Notice
Northern:
Volume (Dekatherm/day) 142,996 48,218 10,000
Expiration date 10/31/97 10/31/97 10/31/97
Natural:
Volume (Dekatherm/day) 28,605 34,014 996
Expiration date 11/30/2000 11/30/98 11/30/98
ANR:
Volume (Dekatherm/day) 60,737 19,180 5,000
Expiration date 10/31/2003 10/31/2003 10/31/2003
In addition to firm storage with pipelines, Utilities also
contracts for firm storage from Llano, Inc. This contract calls for peak
day deliveries of 18,667 Dekatherm(Dth)/day and expires May 31, 1997.
Gas supply is purchased from a variety of non-pipeline suppliers
located in the United States and Canada having access to virtually all
major natural gas producing regions. For the calendar year 1996,
Utilities' maximum daily load occurred on February 2, 1996 with total
system flow of approximately 290,987 dekatherms, including transported
volumes, and a total contract availability of approximately 276,352
dekatherms.
As a result of Order 636, Utilities accepted assignment of certain
gas supply contracts previously held by Northern. Accepting assignment
of these contracts resulted in lower costs to Utilities than would have
been incurred had Northern bought out the agreements and billed
Utilities for its share of such costs.
Contracts assigned to Utilities from Northern have maximum delivery
requirements of 13,631 Dth, and minimum take requirements of 2,726 Dth.
Additional firm gas supply agreements were independently negotiated by
Utilities with various non-pipeline suppliers. These gas supply
agreements have maximum and minimum obligations and will
be delivered through gas transmission pipelines as follows:
Maximum Minimum
Daily Quantity Daily Quantity
(Dth/day) (Dth/day)
Northern 57,569 28,358
Natural 26,575 18,575
ANR 41,000 25,500
These gas supply contracts have expiration dates
ranging from a few months to almost seven years.
Rates charged by Utilities' suppliers are subject to
regulation by the FERC. Utilities' tariffs provide for
subsequent adjustments to its natural gas rates for changes in the
cost of natural gas purchased for resale. See Note 1(k) of
Industries' Notes to Consolidated Financial
Statements for discussion of the PGA.
GAS OPERATING COMPARISON
1996 1995 1994 1993 1992 1986
Operating revenues (000's):
IES Utilities Inc.:
Residential $ 97,708 $ 84,562 $ 82,795 $ 90,462 $ 78,685 $ 79,176
Commercial 46,966 40,390 40,912 45,528 39,780 42,608
Industrial 12,256 8,790 12,515 15,593 18,649 39,485
156,930 133,742 136,222 151,583 137,114 161,269
Other 3,934 3,550 2,811 2,735 2,341 881
Total revenues 160,864 137,292 139,033 154,318 139,455 162,150
Industrial Energy Applications, Inc. 113,115 53,047 26,536 27,605 27,627 0
$ 273,979 $ 190,339 $ 165,569 $ 181,923 $ 167,082 $ 162,150
Energy sales (000's dekatherms):
IES Utilities Inc.:
Residential 17,680 16,302 15,766 16,971 15,098 15,825
Commercial 10,323 9,534 9,298 10,133 8,479 9,707
Industrial 3,796 3,098 4,010 4,618 6,175 11,722
31,799 28,934 29,074 31,722 29,752 37,254
Industrial - transported volumes * 10,341 10,871 8,901 7,284 7,283 1,031
Total volumes delivered 42,140 39,805 37,975 39,006 37,035 38,285
Industrial Energy Applications, Inc. * 43,055 31,916 14,443 12,493 14,830 0
85,195 71,721 52,418 51,499 51,865 38,285
*IEA energy sales that are also
included as transported volumes
of IES Utilities Inc. 4,383 4,232 3,134 2,883 2,955 0
Operating statistics for
IES Utilities Inc.:
Cost per dekatherm of gas
purchased for resale $ 3.29 $ 3.13 $ 3.31 $ 3.49 $ 3.36 $ 3.62
Peak daily sendout in dekatherms 290,987 269,545 288,352 268,419 254,989 282,956
Heating degree days as
percentage of normal 109% 101% 96% 103% 93% 94%
Number of customers at year-end 176,238 174,470 172,829 170,719 167,813 164,670
Revenue per dekatherm sold
for IES Utilities Inc.
(excluding transported volumes) $ 4.94 $ 4.62 $ 4.69 $ 4.78 $ 4.61 $ 4.33
Item 2. Properties
Industries has no significant properties other than common stock of
affiliates, temporary cash investments and cash surrender value of
corporate life insurance policies.
Utilities' principal electric generating stations at December 31,
1996, are as follows:
Name and Location Major Fuel Minimum Net Kilowatts Accredited
of Station Type Generating Capability
Duane Arnold Energy Center, Palo, Iowa Nuclear 364,000 (1)
Ottumwa Generating Station, Ottumwa, Iowa Coal 343,440 (2)
Prairie Creek Station, Cedar Rapids, Iowa Coal 205,500
Sutherland Station, Marshalltown, Iowa Coal 143,000
Sixth Street Station, Cedar Rapids, Iowa Coal 65,000
Burlington Generating Station, Burlington, Iowa Coal 211,800
George Neal Unit 3, Sioux City, Iowa Coal 144,200 (3)
Total Coal 1,112,940
Peaking Turbines, Marshalltown, Iowa Oil 162,500
Centerville Combustion Turbines, Centerville, Iowa Oil 48,600
Diesel Stations, all in Iowa Oil 12,200
Total Oil 223,300
Grinnell Station, Grinnell, Iowa Gas 45,300
Agency Street Combustion Turbines,
West Burlington, Iowa Gas 57,700
Burlington Combustion Turbines, Burlington, Iowa Gas 63,100 (4)
Red Cedar Combustion Turbine, Cedar Rapids, Iowa Gas 18,800 (5)
Total Gas 184,900
Total generating capability 1,885,140
(1) Represents Utilities' 70% ownership interest in this 520,000
Kw generating station. The plant is operated by Utilities.
(2) Represents Utilities' 48% ownership interest in this 715,500
Kw generating station. The plant is operated by Utilities.
(3) Represents Utilities' 28% ownership interest in this 515,000
Kw generating station which is operated by an unaffiliated
utility.
(4) Burlington Combustion Turbine Unit 3 became operational June
28, 1996.
(5) Red Cedar Cogeneration Station became operational December 13,
1996.
At December 31, 1996, the transmission lines of Utilities,
operating from 34,000 to 345,000 volts, approximated 4,436 circuit miles
(substantially all located in Iowa). Utilities owned 108 transmission
substations (all located in Iowa) with a total installed capacity of
8,647 MVa and 468 distribution substations (all located in Iowa) with a
total installed capacity of 2,626 MVa.
Subsidiaries other than Utilities also own property which primarily
represents investments in transportation, energy-related, telecommunications
and real estate properties.
The Company's principal properties are suitable for their intended
use. Utilities' principal properties are held subject to liens of
indentures relating to its bonds.
Item 3. 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 Utilities 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. Settlement discussions are proceeding between
Utilities and its insurance carriers regarding the recovery of these
FMGP-related costs. Settlement has been reached with two carriers and
an agreement in principle has been reached with three other carriers
thus far. Any amounts received from insurance carriers will be deferred
pending a determination of the regulatory treatment of such recoveries.
Industries, Diversified, IES Energy, MicroFuel Corporation (the
Corporation) now known as Ely, Inc. in which IES Energy has a 69.40%
equity ownership, and other parties have been sued in Linn County
District Court in Cedar Rapids, Iowa, by Allen C. Wiley. Mr. Wiley
claims money damages on various tort and contract theories arising out
of the 1992 sale of the assets of the Corporation, of which Mr. Wiley
was a director and shareholder. All of the defendants in Mr. Wiley's
suit answered the complaint and denied liability. Industries and
Diversified were dismissed from the suit in a motion for summary
judgment. In addition, a grant of summary judgment has reduced Mr.
Wiley's claims against the remaining parties to breach of fiduciary
duty. A separate motion for summary judgment, which was filed seeking
dismissal of the remaining claims against the remaining parties, was
overruled on September 20, 1996, and the trial has been set for May 1998.
All of the defendants are vigorously contesting the claims.
The Corporation commenced a separate suit to determine the fair
value of Mr. Wiley's shares under Iowa Code section 490. A decision was
issued on August 31, 1994, by the Linn County District Court ruling that
the value of Mr. Wiley's shares was $377,600 based on a 40 cent per
share valuation. The Corporation contended that the value of Mr. Wiley's
shares was 2.5 cents per share. The Decision was appealed to the Iowa
Supreme Court by the Corporation on a number of issues, including the
Corporation's position that the trial court erred as a matter of law in
discounting the testimony of the Corporation's expert witness. The Iowa
Supreme Court assigned the case to the Iowa Court of Appeals. On
February 2, 1996, the Iowa Court of Appeals reversed the District Court
ruling after determining the District Court erred in discounting the
expert testimony. The case was remanded back to the District Court for
consideration of the expert testimony, but with no additional evidence
taken. The District Court re-affirmed its original decision on August
28, 1996, and the Corporation has again appealed to the Iowa Supreme
Court.
On October 3, 1996, Lambda Energy Marketing Company, L. C. (Lambda)
filed a request with the IUB that the IUB initiate formal complaint
proceedings against Utilities. Lambda alleges that Utilities is
discriminating against it by refusing to enter into contracts with it
for remote displacement service and by favoring IEA in such matters. On
October 17, 1996, Utilities filed a Response which denied the
allegations, and alleged, inter alia, that Lambda is unlawfully
attempting to provide retail electrical services in Utilities' exclusive
service territory. The IUB has set the matter for hearing on March 17,
1997. A decision is expected in the second quarter of 1997.
On October 9, 1996, the Company filed a civil suit in the Iowa
District Court in and for Linn County against Lambda, Robert Latham,
Louie Ervin, and David Charles (collectively the "Defendants", including
three former employees of the Company and/or its subsidiaries) alleging,
inter alia, violations of Iowa's trade secret act and interference with
existing and prospective business advantage. On November 1, 1996, the
Defendants filed their Answer and Counterclaims alleging, inter alia,
violation of Iowa competition law, tortious interference and commercial
disparagement. The Defendants therewith also filed a Third-Party
Petition against Utilities, IEA and Lee Liu, Chairman of the Board &
Chief Executive Officer of Industries and Utilities, alleging, inter alia,
tortious interference and commercial disparagement.
Reference is made to Notes 3 and 13 of Industries' Notes to
Consolidated Financial Statements for a discussion of Utilities' rate
proceedings and the Company's environmental matters, respectively. Also
see Item 1. "Business - Environmental Matters" and Item 7.
"Management's Discussion and Analysis of the Results of Operations and
Financial Condition - Environmental Matters."
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5. Market for the Registrant's Common Stock and Related
Stockholder Matters
IES Industries Inc.
(a) Price Range of Industries' Common Stock and Dividends
Declared
Industries' Common Stock is listed on the New York Stock Exchange
(NYSE) under the symbol "IES." The table below sets forth, for the
calendar quarters indicated, the reported high and low sales prices of
Industries' Common Stock as reported on the NYSE Composite Tape based on
published financial sources, and the dividends declared per share on
Industries' Common Stock.
Industries' Common stock
High Sale Low Sale Dividend (i)
1996
First Quarter $ 29 5/8 $ 26 1/2 $ .525
Second Quarter 30 1/8 25 1/2 .525
Third Quarter 34 3/4 29 .525
Fourth Quarter 31 1/2 29 .525
Year $ 34 3/4 $ 25 1/2 $ 2.10
1995
First Quarter $ 27 5/8 $ 24 5/8 $ .525
Second Quarter 26 3/8 20 3/8 .525
Third Quarter 26 3/4 21 3/8 .525
Fourth Quarter 28 1/2 25 7/8 .525
Year $ 28 1/2 $ 20 3/8 $ 2.10
The closing price of Industries' common stock on December 31, 1996
was $29 7/8.
(i) Industries has paid regular quarterly dividends on its
common stock since April 1, 1950. Although Industries'
practice has been to pay dividends quarterly, the timing of
payment and amount of future dividends are necessarily
dependent upon earnings, financial requirements and other
factors.
(b) Approximate Number of Equity Security Holders of Industries
Approximate Number of Record
Title of Class Holders (as of December 31, 1996)
Common Stock, no par value 27,468
(c) Restriction on Payment of Dividends by Industries
Under provisions of the Merger Agreement, Industries' annual
dividend payment cannot exceed $2.10 per share, the current annual
payment level, pending the Proposed Merger.
See Item 1, "Proposed Merger of the Company" for a further
discussion of Industries' pending merger.
IES Utilities Inc.
(a) Price Range of Utilities' Common Stock and Dividends
Declared
All outstanding common stock of Utilities is held by its parent
(Industries), and is not traded.
(b) Approximate Number of Equity Security Holders of Utilities
All outstanding common stock of Utilities is held by its parent
(Industries).
(c) Restriction on Payment of Dividends by Utilities
Utilities has the right under the terms of the Subordinated
Deferrable Interest Debentures, so long as an Event of Default has not
occurred and is not continuing, to extend the interest payment period at
any time and from time to time on the Subordinated Deferrable Interest
Debentures to a period not exceeding 20 consecutive quarters. If
Utilities exercises its right to extend the interest payment period,
Utilities may not, during any such extended interest payment period,
declare or pay dividends on, or redeem, purchase or acquire, or make any
liquidation payment with respect to, any of its capital stock or make
any guarantee payment with respect to the foregoing. Utilities does not
intend to exercise its right to extend the interest payment period.
Item 6. Selected Consolidated Financial Data
The following selected consolidated financial data, in the opinion
of the Company, includes adjustments, which are normal and recurring in
nature, necessary for the fair presentation of the results of operations
and financial position. See Item 7. "Management's Discussion and
Analysis of the Results of Operations and Financial Condition" for a
discussion of transactions that affect the comparability of the years
1996-1994.
The 1996 results were affected by costs incurred relating to the
successful defense of the hostile takeover attempt mounted by
MidAmerican Energy Company. The 1995 results were affected by the
impact of the IUB price reduction order in Utilities' last electric rate
case and significantly warmer than normal weather. The 1993 results
were affected by the acquisition of the Iowa service territory from
Union Electric Company on December 31, 1992.
The Selected Consolidated Financial Data should be read in
conjunction with the Consolidated Financial Statements, the Notes to
Consolidated Financial Statements and Management's Discussion and
Analysis of the Results of Operations and Financial Condition contained
elsewhere in this report.
IES INDUSTRIES INC. SELECTED CONSOLIDATED FINANCIAL DATA
1996 1995 1994 1993 1992
Income statement data (000's):
Operating revenues $ 973,912 $ 851,010 $ 785,864 $ 801,266 $ 678,296
Operating income 164,308 151,712 147,933 151,269 109,024
Net income 60,907 64,176 66,818 67,938 48,711
Common stock data (per share
except percentages):
Earnings $ 2.04 $ 2.20 $ 2.34 $ 2.45 $ 1.92
Dividends declared 2.10 2.10 2.10 2.10 2.10
Return on average common equity 9.9% 10.7% 11.5% 12.4% 10.3%
Market price at year-end $ 29.88 $ 26.50 $ 25.25 $ 31.25 $ 29.50
Book value at year-end 20.84 20.75 20.56 20.21 18.89
Ratio of market price to book value
at year-end 143% 128% 123% 155% 156%
Capitalization:
Common equity 47% 49% 50% 51% 48%
Preferred and preference stock 1 2 2 2 2
Long-term debt 52 49 48 47 50
100% 100% 100% 100% 100%
Other selected financial data:
Total assets (000's) $ 2,125,562 $ 1,985,591 $ 1,849,093 $ 1,699,819 $ 1,594,382
Non-utility assets (000's) (1) 352,824 282,433 206,411 153,853 153,491
Long-term obligations, net (000's) 744,298 654,090 623,359 574,488 551,335
Construction and acquisition
expenditures (000's) 238,378 218,099 206,548 169,017 192,520 (2)
Times interest earned before
income taxes 2.99 3.12 3.38 3.38 2.63
Selected financial data for
IES Utilities Inc.:
Utility plant in service (000's) $ 2,310,161 $ 2,172,378 $ 2,042,179 $ 1,932,558 $ 1,852,733
Accumulated depreciation of
utility plant in service (000's) 1,030,390 950,324 880,888 813,312 759,754
Construction and acquisition
expenditures (000's) (3) 143,648 129,444 148,103 113,212 171,013 (2)
Times interest earned before
income taxes 3.44 3.26 3.39 3.64 2.67
Electric Kwh sales
(excluding off-system) (000's) 9,953,204 9,783,514 9,291,575 8,905,522 7,132,671
Gas Dth sales (including
transported volumes) (000's) 42,140 39,805 37,975 39,006 37,035
(1) Includes non-utility assets of IES Utilities Inc.
(2) Includes $61 million for the acquisition of the Iowa
service territory from Union Electric Company.
(3) Includes acquisitions from affiliated companies and
Utilities' non-utility expenditures.
IES UTILITIES INC. SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended December 31
1996 1995 1994 1993 1992
($ in thousands)
Operating revenues $ 754,979 $ 709,826 $ 685,366 $ 713,750 $ 610,262
Operating income 153,725 142,265 135,591 143,329 100,361
Net income 63,729 59,278 61,210 67,970 45,291
Net income available for common stock 62,815 58,364 60,296 67,056 43,562
Cash dividends declared on common stock 44,000 43,000 52,000 31,300 24,721
Total assets 1,778,610 1,708,635 1,645,368 1,546,978 1,440,891
Long-term obligations 560,199 517,538 530,275 531,979 490,251
Times interest earned before income taxes 3.44 3.26 3.39 3.64 2.67
Capitalization ratios:
Common equity 50% 51% 50% 50% 48%
Preferred and preference stock 2 2 2 2 2
Long-term debt 48 47 48 48 50
100% 100% 100% 100% 100%
Item 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF THE RESULTS OF OPERATIONS AND FINANCIAL CONDITION
IES Industries Inc.'s Consolidated Financial Statements include
the accounts of IES Industries Inc. (Industries) and its consolidated
subsidiaries (collectively the Company). Industries'
wholly-owned subsidiaries are IES Utilities Inc. (Utilities)
and IES Diversified Inc. (Diversified). The information
presented in this management's discussion and analysis
addresses the financial statements of Industries and Utilities as
presented in this joint filing. Information related to Utilities also
relates to Industries' Consolidated Financial Statements.
Information related to Diversified does not pertain
to the discussion of the financial condition and results of operations
of Utilities. The references to various Notes to Consolidated Financial
Statements are all to Industries' Notes to Consolidated Financial
Statements.
COMPETITION
Utilities and its predominant business, electric energy generation,
transmission and distribution, are in a period of fundamental change in
the manner in which customers obtain, and energy suppliers provide,
energy services. 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 Federal Energy Regulatory
Commission (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. 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. The non-
rate provisions of the tariffs were approved on November 13, 1996. FERC
has not yet ruled on the rate provisions of the tariffs. The geographic
position of Utilities' transmission system could provide revenue
opportunities in the open access environment. Industrial Energy
Applications, Inc. (IEA), a wholly-owned subsidiary under Diversified,
received approval in the 1995 FERC proceeding to market electric power
at market based rates. The Company cannot predict the long-term
consequences of these rules on its results of operations or financial
condition.
FERC does not have jurisdiction over the retail jurisdiction, and
thus the final FERC rules do not provide for the recovery of stranded
costs resulting from retail competition. The various states retain
jurisdiction over the question of 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.
The Iowa Utilities Board (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" to address all forms of
competition in the electric utility industry and to gather information
and perspectives on electric competition from all persons or entities
with an interest or stake in the issues. 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 conducted public
information meetings around the State of Iowa. A draft report was
created by the IUB staff and is expected to be finalized in the first
quarter of 1997. The draft report indicated that the IUB is of the
opinion that there is no compelling reason to move quickly into
restructuring the electric utility industry in Iowa. However, they will
continue the analysis and debate on restructuring and retail competition
in Iowa.
As part of Utilities' strategy for the emerging and competitive
power markets, Utilities, Interstate Power Company (IPC) and Wisconsin
Power and Light Company (the utility subsidiary of WPL Holdings, Inc.
(WPLH)), and a number of other utilities have proposed the creation of
an independent system operator (ISO) for the companies' power
transmission grid. (The Company, WPLH and IPC have entered into a
merger agreement, as discussed later). The companies would retain
ownership and control of the facilities, but the ISO would set rates for
access and assure fair treatment for all companies seeking access. The
proposal requires approval from state regulators and the FERC. Various
other proposals for ISO's have been made by other companies and
Utilities is monitoring all such proposals. Membership in an ISO could
become a condition of merger approval by the various regulatory bodies.
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. In
addition, the Company would be required to determine any impairment to
other assets and write-down such assets to their fair value. 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 is in the final stages of a significant process improvement
program to improve its service levels, reduce its cost structure and
become more market-focused and customer oriented. (The Company's
continuous improvement efforts, in general, will be an ongoing effort,
however).
Examples of the process improvement changes being implemented are,
but are not limited to: managing the business in business unit form,
rather than functionally; formation of alliances with vendors of certain
types of material and/or services rather than opening most purchases to
a bidding process; changing standards and construction practices in
transmission and distribution areas; changing certain work practices in
power plants; making investments in information technology upgrades; and
improving the method by which service is delivered to customers in all
customer classes. The specific changes range from simple improvements
in current operations to radical changes in the way work is performed
and service is delivered. Some of the changes are currently in the
pilot stage thus the results from this evaluation period or the
potential effects of the pending merger could prove that some of the
changes are not efficient or effective and must be revised or
eliminated. Subject to delays caused by implementing any such
revisions, implementation of the changes began in 1996 and will continue
into 1997; however, certain results will not be realized until 1997. In
addition, the Company must give consideration to the potential effects
of the pending merger as part of the implementation process so that
duplication of efforts are avoided.
PROPOSED MERGER OF THE COMPANY
The Company, WPLH and IPC have entered into an Agreement and Plan
of Merger, as amended (Merger Agreement), dated November 10, 1995. As a
result of the transactions contemplated by the Merger Agreement, the
combined company, Interstate Energy Corporation (Interstate Energy),
anticipates cost savings of approximately $749 million over a ten-year
period, net of transaction costs and costs to achieve the savings of
approximately $14 million and $64 million, respectively. The estimate
of potential cost savings constitutes a forward-looking statement and
actual results may differ materially from this estimate. The estimate
is necessarily based upon various assumptions that involve judgments
with respect to, among other things, future national and regional
economic and competitive conditions, technological developments,
inflation rates, regulatory treatments, weather conditions, financial
market conditions, future business decisions and other uncertainties.
No assurance can be given that the estimated cost savings will actually
be realized.
The merger, which is conditioned upon, among other things, receipt
of certain regulatory and governmental approvals, is expected to close
by the end of the third quarter of 1997. As part of the approval
process, management has proposed retail and wholesale price freezes to
be implemented in certain jurisdictions. Refer to Notes 2 and 3 of the
Notes to Consolidated Financial Statements for additional information
regarding the proposed merger and the proposed price freezes.
RESULTS OF OPERATIONS OF THE COMPANY
The following discussion analyzes significant changes in the
components of net income and financial condition from the prior periods
for the Company.
The Company's net income decreased ($3.3) million and ($2.6)
million during 1996 and 1995, respectively. Earnings per average common
share declined to $2.04 in 1996 from $2.20 in 1995. The 1996 decrease
in earnings was primarily due to costs incurred relating to the
successful defense of the hostile takeover attempt mounted by
MidAmerican Energy Company (MAEC) and preparing for the Company's
pending three-way merger. The Company estimates that the hostile
takeover defense and merger costs reduced 1996 earnings by $0.15 per
share and $0.11 per share, respectively. The 1996 earnings benefited
from increased electric, gas and steam sales at Utilities, the impact of
a natural gas pricing increase implemented in the fourth quarter of 1995
and increased earnings at the Company's oil and gas subsidiary, Whiting
Petroleum Corporation (Whiting). Increased operating expenses, higher
interest expense and a higher effective income tax rate also contributed
to the decrease in earnings in 1996. The 1995 results reflect the
impact of the IUB price reduction order in Utilities' latest electric
rate case. The effect of the lower electric prices, including the
required refund, reduced the 1995 net income by approximately $9.7
million ($0.33 per share). Warmer than normal weather conditions during
the summer months, which added $0.18 to earnings, and an aggressive cost
containment program partially offset the negative effects of the IUB
order. The 1994 results were affected by milder than normal weather,
particularly during the summer months.
The Company's operating income increased $12.6 million and $3.8
million during 1996 and 1995, respectively. The contrasting
relationship between the change in operating income and net income for
1996 was due to the hostile takeover defense costs of $7.8 million,
which are included in "Miscellaneous, net" in the Consolidated
Statements of Income, higher interest expense and a higher effective
income tax rate. The 1995 difference was also due to increased interest
expense and a higher effective income tax rate. Reasons for the changes
in the results of operations are explained in the following discussion.
Electric Operations
Electric margins and Kwh sales for Utilities were as follows:
Revenues and Costs Kwhs Sold
(In thousands) (In thousands)
1996 1995 1994 1996 1995 1994
Residential and rural $ 212,799 $ 216,270 $ 199,587 $ 2,633,704 $ 2,680,340 $ 2,484,089
General service 98,196 97,496 97,454 1,231,115 1,242,373 1,170,923
Large general service 213,223 199,840 191,601 5,500,606 5,283,694 4,990,890
Sales for resale
and other 30,565 29,063 30,608 587,779 577,107 645,673
Total, excluding off-
system sales 554,783 542,669 519,250 9,953,204 9,783,514 9,291,575
Off-system sales 19,490 17,802 18,077 1,231,298 1,086,121 1,137,219
Total 574,273 560,471 537,327 11,184,502 10,869,635 10,428,794
Fuel for production
(excluding steam) 74,608 90,558 81,567
Purchased power 88,350 66,874 68,794
Margin $ 411,315 $ 403,039 $ 386,966
Electric margins increased $8.3 million and $16.1 million during
1996 and 1995, respectively. The increase during 1996 was primarily due
to higher sales relating to continuing sales growth in Utilities'
service territory, lower purchased power capacity costs and increased
revenues due to the recovery of previously deferred energy efficiency
expenditures. These increases were partially offset by a true-up
adjustment to Utilities' unbilled sales recorded in 1995 and lower sales
to residential and rural customers during 1996, primarily due to cooler
weather conditions during the summer of 1996 as compared to the summer
of 1995. The 1995 electric margin increase was primarily due to higher
sales due to a significantly warmer summer in 1995 as compared to 1994,
sales growth, the unbilled sales adjustment, lower purchased power
capacity costs and the recovery of energy efficiency costs. These
increases were partially offset by a reduction in revenues of
approximately $17 million as a result of the IUB price reduction order,
of which approximately $3.5 million related to revenues collected in the
fourth quarter of 1994. Refer to Notes 3(a) and 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 and the energy efficiency cost recoveries, respectively.
Under historically normal weather conditions, total sales
(excluding off-system sales) during 1996 and 1995 would have increased
3.5% and 3.6%, as compared to actual increases of 1.7% and 5.3%,
respectively.
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. See Note 1(k) of the
Notes to Consolidated Financial Statements for discussion of the EAC.
Gas Operations
Gas margins and dekatherm sales for Utilities and IEA were as
follows:
Revenues and Costs Dths Sold
(In thousands) (In thousands)
1996 1995 1994 1996 1995 1994
Utilities -
Residential $ 97,708 $ 84,562 $ 82,795 17,680 16,302 15,766
Commercial 46,966 40,390 40,912 10,323 9,534 9,298
Industrial 12,256 8,790 12,515 3,796 3,098 4,010
Transportation
and other 3,934 3,550 2,811 10,341 10,871 8,901
Total Utilities 160,864 137,292 139,033 42,140 39,805 37,975
IEA 113,115 53,047 26,536 43,055 31,916 14,443
Total 273,979 190,339 165,569 85,195 71,721 52,418
Gas purchased
for resale 217,351 141,716 120,795
Margin $ 56,628 $ 48,623 $ 44,774
Total gas margins increased $8.0 million and $3.8 million during
1996 and 1995, respectively. The 1996 increase was primarily due to an
annual increase of $6.3 million in Utilities' gas rates that was
implemented in the fourth quarter of 1995, recovery of Utilities'
previously deferred energy efficiency expenditures and the increased
sales, largely the result of more favorable weather conditions in 1996.
While IEA's gas sales were up significantly in 1996, their margins
actually decreased due to fluctuations in gas prices and the
competitiveness of the gas marketing business. Therefore, this decrease
partially offset the increase in Utilities' margin. The 1995 margin
increase was primarily due to the price increase at Utilities mentioned
above, recovery of Utilities' previously deferred energy efficiency
expenditures and higher IEA gas margins resulting from increased volumes
sold due to heightened marketing efforts as well as expanding into
additional regional markets.
Under historically normal weather conditions, Utilities' gas sales
and transported volumes would have increased 1.9% and 3.5% in 1996 and
1995, as compared to actual increases of 5.9% and 4.8%, respectively.
Utilities' gas tariffs include purchased gas adjustment clauses
(PGA) that are designed to currently recover the cost of gas sold. See
Note 1(k) of the Notes to Consolidated Financial Statements for
discussion of the PGA.
Other Revenues Other revenues increased $25.5 million and
$17.2 million during 1996 and 1995, respectively, primarily because of
increased revenues at Whiting due to increases in oil and gas prices and
increased gas volumes sold during 1996, and increases in oil and gas
volumes sold in 1995. An increase in Utilities' steam revenues also
contributed to the increase in both years. The steam volumes sold
increased significantly during 1996 and 1995 primarily due to the
addition of a new industrial customer. The 1995 increase was partially
offset as a result of the sale of several of Diversified's subsidiaries
during 1995 and 1994. The operations of the subsidiaries that were sold
were not significant to the results of operations or financial position
of the Company.
Operating Expenses Other operating expenses increased $13.4 million
and $24.5 million in 1996 and 1995, respectively. Contributing to the
increase in both periods were increased operating activities at Whiting
and IEA, increased labor and benefits costs at Utilities, increases in
the amortization of previously deferred energy efficiency expenditures
at Utilities (which are currently being recovered through rates) and
costs relating to the pending merger. The 1996 increase was partially
offset by decreased operating expenses at the Duane Arnold Energy Center
(DAEC), Utilities' nuclear generating facility. The 1995 increase was
also due to costs relating to the Company's process improvement program,
partially offset by lower nuclear operating and insurance costs at
Utilities, decreased costs resulting from the sale of the Diversified
subsidiaries and a cost-cutting effort implemented after the receipt of
the IUB electric price reduction order earlier in 1995.
Maintenance expenses increased or (decreased) $2.9 million and
($6.7) million during 1996 and 1995, respectively. The 1996 increase
was due to increased maintenance activities at Utilities' fossil-fueled
generating stations, partially offset by lower maintenance expenses at
the DAEC. The 1995 decrease was due to lower maintenance expenses at
the DAEC and at Utilities' fossil-fueled generating stations as well as
the cost containment actions discussed above.
Depreciation and amortization increased $9.4 million and $11.6
million in 1996 and 1995, respectively, because of increases in utility
plant in service, the acquisition of oil and gas operating properties
and amortization costs relating to the future dismantlement and
abandonment of Whiting's offshore oil and gas properties. (See Note
13(f) of the Notes to Consolidated Financial Statements for a further
discussion of the dismantlement and abandonment costs). The 1995
increase was 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 include a
provision for decommissioning the DAEC, which is collected through
rates. The current annual recovery level is $6.0 million.
During the first quarter of 1996, the Financial Accounting
Standards Board (FASB) issued an Exposure Draft on Accounting for
Liabilities Related to Closure and Removal of Long-Lived Assets which
deals with, among other issues, the accounting for decommissioning
costs. If current electric utility industry accounting practices for
such decommissioning are changed: (1) annual provisions for
decommissioning could increase relative to 1996 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. See Note 1(g) of the Notes to Consolidated Financial
Statements for a discussion of the recovery of decommissioning costs
allowed in Utilities' most recent rate case.
Taxes other than income taxes increased or (decreased)
($0.8) million and $2.7 million during 1996 and 1995, respectively,
largely due to changes in property taxes at Utilities caused by
fluctuations in assessed property values. The 1996 decrease was
partially offset by an increase in production taxes at Whiting.
Interest Expense and Other Interest expense increased $4.1 million and
$4.7 million in 1996 and 1995, respectively, primarily because of
increases in the average amount of short-term debt outstanding at
Utilities and the average amount of borrowings under Diversified's
credit facility. Lower average interest rates, partially attributable
to refinancing long-term debt at lower rates and the mix of long-term
and short-term debt, partially offset the increases for both periods.
The increase in interest expense during 1996 was also due to a higher
amount of long-term debt outstanding at Utilities, partially offset by
rate refund interest recorded in 1995 at Utilities and the effects of
the interest rate swap agreement discussed in Note 12(a) of the Notes to
Consolidated Financial Statements.
Miscellaneous, net reflects comparative decreases in income of
($5.5) million and ($0.3) million during 1996 and 1995, respectively.
The 1996 decrease was primarily due to approximately $7.8 million in
costs incurred relating to the successful defense of the hostile
takeover attempt mounted by MAEC and certain property write-downs at
Diversified. The decrease was partially offset by dividends received
from the two New Zealand entities in which the company has equity
investments and various gains realized on the disposition of assets.
The 1995 decrease was primarily because of higher fees associated with
an increase in the average amount of utility accounts receivable sold,
partially offset by various gains realized on the sale of several
investments by Diversified.
Federal and State Income Taxes Federal and state income taxes
increased $4.9 million and $0.9 million in 1996 and 1995, respectively.
The increase for both periods was due to a higher effective tax rate
resulting from: 1) the effect of property related temporary differences
for which deferred taxes had not previously been provided in rates,
pursuant to rate making principles, that are now becoming payable and
are being recovered from ratepayers and 2) adjustments to tax reserves.
The 1996 increase in effective tax rate was also due to recording the
impacts of a tentative Internal Revenue Service audit settlement for tax
years 1991-1993 as well as the incurrence of certain merger-related
expenses, which are not tax deductible.
LIQUIDITY AND CAPITAL RESOURCES
The Company's capital requirements are primarily attributable to
Utilities' construction programs, its debt maturities and the level of
Diversified's business opportunities. The Company's pretax ratio of
times interest earned was 2.99, 3.12 and 3.38 in 1996-1994,
respectively. Cash flows from operating activities were $183 million,
$200 million and $217 million in 1996-1994, respectively. The 1996
decrease was primarily due to the timing of income tax payments and
other changes in working capital. The 1995 decrease was primarily due
to expenditures related to 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
regulatory recovery of Utilities' costs. See Notes 3 and 13 of the
Notes to Consolidated Financial Statements.
Access to the long-term and short-term capital and credit markets,
and costs of external financing, are dependent on the Company's
creditworthiness. The Company's debt ratings are as follows:
Moody's Standard & Poor's
Utilities - Long-term debt A2 A
- Commercial paper P1 A1
Diversified - Commercial paper P2 A2
Utilities' credit ratings are under review for potential upgrade
related to the pending merger.
The Company's liquidity and capital resources will be affected by
environmental, regulatory and competitive 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 13 of the Notes to Consolidated Financial Statements, and
emerging competition in the electric utility industry as discussed in
the Competition 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.
At December 31, 1996, Utilities had approximately $61 million of
energy efficiency program costs recorded as regulatory assets. See Note
3(b) of the Notes to Consolidated Financial Statements for a discussion
of the timing of the filings for the recovery of these costs under IUB
rules and Iowa statutory changes recently enacted relating to these
programs.
At December 31, 1996, the Company had a $20.0 million investment in
Class A common stock of McLeod, Inc. (McLeod), a $9.2 million investment
in Class B common stock and vested options that, if exercised, would
represent an additional investment of approximately $2.3 million.
McLeod provides local, long-distance and other telecommunications
services. See Notes 6(b) and 11 of the Notes to Consolidated Financial
Statements for further information on the Company's investment in
McLeod.
The Company has financial guarantees amounting to $22.9 million
outstanding at December 31, 1996, which are not reflected in the
consolidated financial statements. Such guarantees are generally issued
to support third-party borrowing arrangements and similar transactions.
The Company believes that the likelihood of material cash payments by
the Company under these agreements is remote.
The Company increased its investments in foreign entities by
approximately $20 million in 1996 (see Note 6(a) of the Notes to
Consolidated Financial Statements for a further discussion). The
Company also continues to explore other international investment
opportunities. Such investments carry a higher level of risk than the
Company's traditional utility investments or Diversified's domestic
investments. Such risks could include foreign government actions,
foreign economic and currency risks and others. The Company may also
incur business development expenses for potential projects pursued by
the Company that may never materialize. The Company is striving to
select international investments where these risks are both understood
and minimized.
The Resale Power Group of Iowa (RPGI), consisting of virtually all
of Utilities' wholesale customers, has notified Utilities that it will
not purchase its power supply from Utilities after December 31, 1998.
It is possible that certain RPGI customers will drop out of RPGI in
order to remain as Utilities' customers. RPGI will continue to purchase
transmission services from Utilities after December 31, 1998. While the
Company cannot determine the outcome of this issue at this time, the
result will not have a material adverse effect on its financial position
or results of operations given 1) Utilities' wholesale sales only
accounted for approximately 5% of Utilities' total 1996 electric sales,
excluding off-system sales; 2) Utilities currently has to supplement its
generating capability with purchased power to meet its sales load; and
3) Utilities' annual electric sales growth rate continues to be strong.
Under provisions of the Merger Agreement, there are restrictions on
the amount of common stock and long-term debt the Company can issue
pending the merger. The Company does not expect the restrictions to
have a material effect on its ability to meet its future capital
requirements.
CONSTRUCTION AND ACQUISITION PROGRAM
The Company's construction and acquisition program anticipates
expenditures of approximately $225 million for 1997, of which
approximately $147 million represents expenditures at Utilities and
approximately $78 million represents expenditures at Diversified. Of
the $147 million of Utilities' expenditures, 39% represents expenditures
for electric transmission and distribution facilities, 21% represents
electric generation expenditures, 21% represents information technology
expenditures and 5% represents gas expenditures. The remaining 14%
represents miscellaneous electric, steam and general expenditures.
Diversified's anticipated expenditures include approximately $75 million
for domestic and international energy-related construction and
acquisition expenditures.
The Company's levels of construction and acquisition expenditures
are projected to be $208 million in 1998, $212 million in 1999,
$182 million in 2000 and $198 million in 2001. It is estimated that
virtually all of Utilities' construction and acquisition expenditures
will be provided by cash from operating activities (after payment of
dividends) for the five-year period 1997-2001. Financing plans for
Diversified's construction and acquisition program will vary, depending
primarily on the level of energy-related acquisitions.
Capital expenditure and investment and financing plans are subject
to continual review and change. The capital expenditure and investment
programs may be revised significantly as a result of many considerations
including changes in economic conditions, variations in actual sales and
load growth compared to forecasts, requirements of environmental,
nuclear and other regulatory authorities, acquisition and business
combination opportunities, the availability of alternate energy and
purchased power sources, the ability to obtain adequate and timely rate
relief, escalations in construction costs and conservation and energy
efficiency programs.
Under provisions of the Merger Agreement, there are restrictions on
the amount of construction and acquisition expenditures the Company can
make pending the merger. The Company does not expect the restrictions
to have a material effect on its ability to implement its anticipated
construction and acquisition program.
LONG-TERM FINANCING
Other than Utilities' periodic sinking fund requirements, which
Utilities intends to meet by pledging additional property, the following
long-term debt will mature prior to December 31, 2001:
(in millions)
Utilities $ 207.2
Diversified's credit facility 172.1
Other subsidiaries' debt 11.2
$ 390.5
The Company intends to refinance the majority of the debt
maturities with long-term securities.
In September 1996, Utilities repaid at maturity $15 million of
Series J, 6.25% First Mortgage Bonds and, in a separate transaction,
issued $60 million of Collateral Trust Bonds, 7.25%, due 2006.
Utilities has entered into an Indenture of Mortgage and Deed of
Trust dated September 1, 1993 (New Mortgage). The New Mortgage provides
for, among other things, the issuance of Collateral Trust Bonds upon the
basis of First Mortgage Bonds being issued by Utilities. The lien of
the New Mortgage is subordinate to the lien of Utilities' first
mortgages until such time as all bonds issued under the first mortgages
have been retired and such mortgages satisfied. Accordingly, to the
extent that Utilities issues Collateral Trust Bonds on the basis of
First Mortgage Bonds, it must comply with the requirements for the
issuance of First Mortgage Bonds under Utilities' first mortgages.
Under the terms of the New Mortgage, Utilities has covenanted not to
issue any additional First Mortgage Bonds under its first mortgages
except to provide the basis for issuance of Collateral Trust Bonds.
The indentures pursuant to which Utilities issues First Mortgage
Bonds constitute direct first mortgage liens upon substantially all
tangible public utility property and contain covenants which restrict
the amount of additional bonds which may be issued. At
December 31, 1996, such restrictions would have allowed Utilities to
issue at least $241 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 FERC and the SEC to issue
up to $250 million of long-term debt, and has $190 million of remaining
authority under the current FERC docket through April 1998, and $140
million of remaining authority under the current SEC shelf registration.
Diversified has a variable rate credit facility that extends
through November 20, 1999, with two one-year extensions potentially
available to Diversified. Refer to Note 10(a) of the Notes to
Consolidated Financial Statements for a further discussion of this
credit facility.
The Articles of Incorporation of Utilities authorize and limit the
aggregate amount of additional shares of Cumulative Preference Stock and
Cumulative Preferred Stock that may be issued. At December 31, 1996,
Utilities could have issued an additional 700,000 shares of Cumulative
Preference Stock and 100,000 additional shares of Cumulative Preferred
Stock. In addition, Industries had 5,000,000 shares of Cumulative
Preferred Stock, no par value, authorized for issuance, none of which
were outstanding at December 31, 1996.
The Company's capitalization ratios at year-end were as follows:
1996 1995
Long-term debt 52% 49%
Preferred stock 1 2
Common equity 47 49
100% 100%
Under provisions of the Merger Agreement, there are restrictions on
the amount of common stock and long-term debt the Company can issue
pending the merger. The Company does not expect the restrictions to
have a material effect on its ability to meet its future capital
requirements.
SHORT-TERM FINANCING
For interim financing, Utilities is authorized by the FERC to
issue, through 1998, 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 December 31, 1996, Utilities
had outstanding short-term borrowings of $135 million.
Utilities has 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 December 31, 1996, Utilities had sold $65 million under
the agreement. Refer to Note 5 of the Notes to Consolidated Financial
Statements for a further discussion of this agreement, including the
issuance of a new accounting standard which impacts the accounting for
the sales.
At December 31, 1996, the Company had bank lines of credit
aggregating $136.1 million. Utilities was using $110 million to support
commercial paper (weighted average interest rate of 5.70%) 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
December 31, 1996, there was $25 million outstanding under this facility
(weighted average interest rate of 6.28%).
ENVIRONMENTAL MATTERS
Utilities has been named as a Potentially Responsible Party (PRP)
by various federal and state environmental agencies for 28 Former
Manufactured Gas Plant (FMGP) sites. Utilities has recorded
environmental liabilities related to the FMGP sites of approximately $36
million (including $4.7 million as current liabilities) at December 31,
1996. Regulatory assets of approximately $36 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. Refer to Note 13(f) of the Notes to Consolidated Financial
Statements for a further discussion, including a discussion of a lawsuit
filed by Utilities seeking recovery of FMGP-related costs from its
insurance carriers.
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
acid rain program under the Act also governs SO2 allowances. 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.
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
Standards established for SO2. The worst-case modeling study suggested
that two of Utilities' generating facilities contribute to the modeled
exceedences.
Pursuant to a routine review of operations, Utilities determined
that certain changes undertaken during the previous three years at one
of its power plants may have required a federal Prevention of
Significant Deterioration (PSD) permit. Refer to Note 13(g) of the
Notes to Consolidated Financial Statements for a further discussion of
the above mentioned air quality issues.
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." Refer to Note 13(f) of the
Notes to Consolidated Financial Statements for a further discussion.
The Nuclear Waste Policy Act of 1982 assigned responsibility to the
U.S. Department of Energy (DOE) to establish a facility for the ultimate
disposition of high level waste and spent nuclear fuel and authorized
the DOE to enter into contracts with parties for the disposal of such
material beginning in January 1998. Utilities entered into such a
contract and has made the agreed payments to the Nuclear Waste Fund
(NWF) held by the U.S. Treasury. The DOE, however, has experienced
significant delays in its efforts and material acceptance is now
expected to occur no earlier than 2010 with the possibility of further
delay being likely. Utilities has been storing spent nuclear fuel on-
site since plant operations began in 1974 and has current on-site
capability to store spent fuel until 2001. Utilities is aggressively
reviewing options for expanding on-site storage. Utilities has been
formally notified by the DOE that they anticipate being unable to begin
acceptance of spent nuclear fuel by January 31, 1998. Utilities is
evaluating courses of action to protect the interests of its customers
and its rights under the DOE contract. Utilities is also evaluating
legislation proposed to the Congress addressing this issue. In July
1996, the IUB initiated a Notice of Inquiry (NOI) on spent nuclear fuel.
One purpose of the NOI was to evaluate whether the current collection of
money from Utilities' customers for payment to the NWF should be placed
in an escrow account in lieu of being paid to the NWF. Utilities
believes that the issue of using an escrow account should be decided at
the federal level rather than the state level. Utilities cannot predict
the outcome of this NOI.
The Low-Level Radioactive Waste Policy Amendments Act of 1985
mandated that each state must take responsibility for the storage of low-
level radioactive waste produced within its borders. The State of Iowa
has joined the Midwest Interstate Low-Level Radioactive Waste Compact
Commission (Compact), which is planning a storage facility to be located
in Ohio to store waste generated by the Compact's six member states. At
December 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 was approved in 1996 by all six
states that are members of the Compact. Final approval by the U.S.
Congress is now required. On-site storage capability currently exists
for low-level radioactive waste expected to be generated until the
Compact facility is able to accept waste materials. In addition, the
Barnwell, South Carolina disposal facility has reopened for an
indefinite time period and Utilities is in the process of shipping to
Barnwell the majority of the low-level radioactive waste it has
accumulated on-site, and currently intends to ship the waste it produces
in the future as long as the Barnwell site remains open, thereby
minimizing the amount of low-level waste stored on-site. However,
management of the Barnwell site has modified its fee schedule to
emphasize total radioactivity content and weight, instead of the
historical volume related fees. Utilities is evaluating the outcome of
these changes on its potential future disposal costs at the Barnwell
site; such changes could result in a revision to Utilities' future
disposal plans.
The possibility that exposure to electric and magnetic fields (EMF)
emanating from power lines, household appliances and other electric
sources may result in adverse health effects has been the subject of
increased public, governmental, industry and media attention. A recent
study completed by the National Research Council concluded that the
current body of evidence does not support the notion that exposure to
these fields may result in adverse health effects. Utilities will
continue to monitor the events in this area, including future scientific
research.
Whiting is responsible for certain dismantlement and abandonment
costs related to various off-shore oil and gas properties. Refer to
Note 13(f) of the Notes to Consolidated Financial Statements for a
further discussion.
OTHER MATTERS
Labor Issues Utilities has six collective bargaining agreements,
covering approximately 54% of its workforce. None of the agreements
expires in 1997.
Financial Derivatives The Company has a policy that financial
derivatives are to be used only to mitigate business risks and not for
speculative purposes. Derivatives have been used by the Company on a
very limited basis. At December 31, 1996, the only material financial
derivatives outstanding for the Company were the interest rate swap
agreement and gas futures contracts described in Note 12 of the Notes to
Consolidated Financial Statements.
Inflation The Company does not expect the effects of inflation at
current levels to have a significant effect on its financial position or
results of operations.
Selected Consolidated Quarterly Financial Data (unaudited)
The following unaudited consolidated quarterly data, in the opinion
of the Company, includes adjustments, which are normal and recurring in
nature, necessary for the fair presentation of the results of operations
and financial position. Utilities' results of operations are a
significant portion of Industries' consolidated results. The quarterly
amounts were affected by, among other items, Utilities' rate activities,
seasonal weather conditions, changes in sales and operating expenses and
costs incurred relating to the successful defense of the hostile
takeover attempt mounted by MidAmerican Energy Company. Refer to
Management's Discussion and Analysis of the Results of Operations and
Financial Condition for a discussion of these items. The fourth quarter
of 1996 net income benefited from lower than anticipated costs for a
refueling outage at Utilities' nuclear power plant.
IES INDUSTRIES INC.
Quarter Ended
March 31 June 30 September 30 December 31
(in thousands, except per share amounts)
1996
Operating revenues $ 243,197 $ 210,648 $ 233,907 $ 286,160
Operating income 36,995 26,770 55,701 44,842
Net income 14,095 8,056 20,889 17,867
Earnings per average
common share 0.48 0.27 0.70 0.59
1995
Operating revenues $ 206,392 $ 189,447 $ 238,467 $ 216,704
Operating income 22,115 33,456 63,710 32,431
Net income 6,740 12,508 31,120 13,808
Earnings per average
common share 0.23 0.43 1.06 0.48
IES UTILITIES INC.
Quarter Ended
March 31 June 30 September 30 December 31
(in thousands)
1996
Operating revenues $ 198,768 $ 164,240 $ 190,170 $ 201,801
Operating income 34,204 23,009 53,253 43,259
Net income 14,128 7,230 20,013 22,358
Net income available
for common stock 13,899 7,001 19,784 22,131
1995
Operating revenues $ 172,839 $ 157,671 $ 200,448 $ 178,868
Operating income 19,896 30,444 61,360 30,565
Net income 6,161 11,067 29,842 12,208
Net income available
for common stock 5,932 10,838 29,613 11,981
Item 8. Financial Statements and Supplementary Data
Information required by Item 8. begins on page 44 for Industries
and page 73 for Utilities.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
IES Industries Inc.:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of IES Industries Inc. (an Iowa
corporation) and subsidiary companies as of December 31, 1996 and 1995,
and the related consolidated statements of income, retained earnings and
cash flows for each of the three years in the period ended
December 31, 1996. These financial statements and the financial
statement schedule referred to below are the responsibility of the
Company's management. Our responsibility is to express an opinion on
these financial statements and schedule based on our
audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of IES
Industries Inc. and subsidiary companies as of December 31, 1996 and
1995, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1996, in conformity
with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedule
listed in Item 14(a)2 is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and,
in our opinion, fairly states in all material respects the financial
data required to be set forth therein in relation to the basic financial
statements taken as a whole.
ARTHUR ANDERSEN LLP
Chicago, Illinois
January 31, 1997
IES INDUSTRIES INC. CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31
1996 1995 1994
(in thousands, except per share amounts)
Operating revenues:
Electric $ 574,273 $ 560,471 $ 537,327
Gas 273,979 190,339 165,569
Other 125,660 100,200 82,968
973,912 851,010 785,864
Operating expenses:
Fuel for production 84,579 96,256 85,952
Purchased power 88,350 66,874 68,794
Gas purchased for resale 217,351 141,716 120,795
Other operating expenses 214,759 201,390 176,863
Maintenance 49,001 46,093 52,841
Depreciation and amortization 107,393 97,958 86,378
Taxes other than income taxes 48,171 49,011 46,308
809,604 699,298 637,931
Operating income 164,308 151,712 147,933
Interest expense and other:
Interest expense 54,822 50,727 46,010
Allowance for funds used during construction -2,103 -3,424 -3,910
Preferred dividend requirements of IES Utilities Inc. 914 914 914
Miscellaneous, net 2,333 -3,170 -3,472
55,966 45,047 39,542
Income before income taxes 108,342 106,665 108,391
Federal and state income taxes 47,435 42,489 41,573
Net income $ 60,907 $ 64,176 $ 66,818
Average number of common shares outstanding 29,861 29,202 28,560
Earnings per average common share $ 2.04 $ 2.20 $ 2.34
IES INDUSTRIES INC. CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31
1996 1995 1994
(in thousands)
Balance at beginning of year $ 221,077 $ 218,293 $ 211,750
Net income 60,907 64,176 66,818
Cash dividends declared on common stock, at a per
share rate of $2.10 for all years -62,738 -61,392 -60,065
Other 0 0 -210
Balance at end of year $ 219,246 $ 221,077 $ 218,293
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
IES INDUSTRIES INC. CONSOLIDATED BALANCE SHEETS
December 31
ASSETS (in thousands) 1996 1995
Property, plant and equipment:
Utility -
Plant in service -
Electric $ 2,007,839 $ 1,900,157
Gas 175,472 165,825
Other 126,850 106,396
2,310,161 2,172,378
Less - Accumulated depreciation 1,030,390 950,324
1,279,771 1,222,054
Leased nuclear fuel, net of amortization 34,725 36,935
Construction work in progress 43,719 52,772
1,358,215 1,311,761
Other, net of accumulated depreciation and
amortization of $70,031 and $53,026, respectively 223,805 193,215
1,582,020 1,504,976
Current assets:
Cash and temporary cash investments 8,675 6,942
Accounts receivable -
Customer, less allowance for doubtful accounts
of $1,087 and $1,145, respectively 50,821 37,214
Other 12,040 10,493
Income tax refunds receivable 8,890 982
Production fuel, at average cost 13,323 12,155
Materials and supplies, at average cost 22,842 28,354
Adjustment clause balances 10,752 0
Regulatory assets 26,539 22,791
Oil and gas properties held for resale 0 9,843
Prepayments and other 24,169 23,099
178,051 151,873
Investments:
Nuclear decommissioning trust funds 59,325 47,028
Investment in foreign entities 44,946 24,770
Investment in McLeod, Inc. 29,200 9,200
Cash surrender value of life insurance policies 11,217 9,838
Other 4,903 3,897
149,591 94,733
Other assets:
Regulatory assets 201,129 207,202
Deferred charges and other 14,771 26,807
215,900 234,009
$ 2,125,562 $ 1,985,591
December 31
CAPITALIZATION AND LIABILITIES (in thousands) 1996 1995
Capitalization (See Consolidated Statements of Capitalization):
Common stock $ 407,635 $ 391,269
Retained earnings 219,246 221,077
Total common equity 626,881 612,346
Cumulative preferred stock of IES Utilities Inc. 18,320 18,320
Long-term debt (excluding current portion) 701,100 601,708
1,346,301 1,232,374
Current liabilities:
Short-term borrowings 135,000 101,000
Capital lease obligations 15,125 15,717
Maturities and sinking funds 8,473 15,447
Accounts payable 99,861 80,089
Dividends payable 16,431 16,244
Accrued interest 8,985 8,051
Accrued taxes 43,926 53,983
Accumulated refueling outage provision 1,316 7,690
Adjustment clause balances 0 3,148
Environmental liabilities 5,679 5,634
Other 22,087 21,800
356,883 328,803
Long-term liabilities:
Pension and other benefit obligations 39,643 52,677
Capital lease obligations 19,600 21,218
Environmental liabilities 47,502 43,087
Other 18,488 13,039
125,233 130,021
Deferred credits:
Accumulated deferred income taxes 262,675 257,278
Accumulated deferred investment tax credits 34,470 37,115
297,145 294,393
Commitments and contingencies (Note 13)
$ 2,125,562 $ 1,985,591
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
IES INDUSTRIES INC. CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
1996 1995
(in thousands)
Common equity:
Common stock - no par value - authorized 48,000,000 shares;
outstanding 30,077,212 and 29,508,415 shares, respectively $ 407,635 $ 391,269
Retained earnings 219,246 221,077
626,881 612,346
Cumulative preferred stock of IES Utilities Inc. 18,320 18,320
Long-term debt:
IES Utilities Inc. -
Collateral Trust Bonds -
7.65% series, due 2000 50,000 50,000
7.25% series, due 2006 60,000 0
6% series, due 2008 50,000 50,000
7% series, due 2023 50,000 50,000
5.5% series, due 2023 19,400 19,400
229,400 169,400
First Mortgage Bonds -
Series J, 6-1/4%, retired in 1996 0 15,000
Series L, 7-7/8%, due 2000 15,000 15,000
Series M, 7-5/8%, due 2002 30,000 30,000
Series Y, 8-5/8%, due 2001 60,000 60,000
Series Z, 7.60%, due 1999 50,000 50,000
6-1/8% series, due 1997 8,000 8,000
9-1/8% series, due 2001 21,000 21,000
7-3/8% series, due 2003 10,000 10,000
7-1/4% series, due 2007 30,000 30,000
224,000 239,000
Pollution control obligations -
5.75%, due serially 1997 to 2003 3,416 3,556
5.95%, due serially 2000 to 2007, secured by First
Mortgage Bonds 10,000 10,000
Variable rate (4.25% - 4.35% at December 31, 1996),
due 2000 to 2010 11,100 11,100
24,516 24,656
Subordinated Deferrable Interest Debentures, 7-7/8%, due 2025 50,000 50,000
Total IES Utilities Inc. 527,916 483,056
IES Diversified Inc. -
Credit facility 172,105 124,245
Other subsidiaries' debt maturing through 2013 11,994 12,307
712,015 619,608
Unamortized debt premium and (discount), net -2,442 -2,453
709,573 617,155
Less - Amount due within one year 8,473 15,447
701,100 601,708
$ 1,346,301 $ 1,232,374
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
IES INDUSTRIES INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
1996 1995 1994
(in thousands)
Cash flows from operating activities:
Net income $ 60,907 $ 64,176 $ 66,818
Adjustments to reconcile net income to net cash flows
from operating activities -
Depreciation and amortization 107,393 97,958 86,378
Amortization of principal under capital lease obligations 16,491 15,714 16,246
Deferred taxes and investment tax credits 9,189 7,757 4,050
Refueling outage provision -6,374 -7,506 12,536
Amortization of other assets 9,828 7,391 2,228
Other 856 712 387
Other changes in assets and liabilities -
Accounts receivable -22,154 -15,221 6,777
Sale of utility accounts receivable 7,000 4,000 800
Production fuel, materials and supplies 650 4,050 -1,184
Accounts payable 20,934 2,902 21,871
Accrued taxes -17,965 9,434 4,575
Provision for rate refunds -106 106 -8,670
Adjustment clause balances -13,900 4,581 -6,582
Gas in storage -1,154 3,245 1,135
Other 11,764 532 9,340
Net cash flows from operating activities 183,359 199,831 216,705
Cash flows from financing activities:
Dividends declared on common stock -62,738 -61,392 -60,065
Proceeds from issuance of common stock 14,164 15,616 16,426
Purchase of treasury stock -269 0 -6,233
Net change in IES Diversified Inc. credit facility 47,860 43,745 48,500
Proceeds from issuance of other long-term debt 60,000 100,007 11,640
Reductions in other long-term debt -15,454 -100,424 -9,790
Net change in short-term borrowings 34,000 64,000 13,000
Principal payments under capital lease obligations -19,108 -14,463 -16,304
Other -458 -1,438 -46
Net cash flows from financing activities 57,997 45,651 -2,872
Cash flows from investing activities:
Construction and acquisition expenditures -
Utility -142,259 -125,558 -138,829
Other -96,119 -92,541 -67,719
Oil and gas properties held for resale 9,843 -9,843 0
Deferred energy efficiency expenditures -16,857 -18,029 -16,157
Nuclear decommissioning trust funds -6,008 -6,100 -5,532
Proceeds from disposition of assets 8,295 14,271 8,803
Other 3,482 -5,733 3,129
Net cash flows from investing activities -239,623 -243,533 -216,305
Net increase (decrease) in cash and temporary cash investments 1,733 1,949 -2,472
Cash and temporary cash investments at beginning of year 6,942 4,993 7,465
Cash and temporary cash investments at end of year $ 8,675 $ 6,942 $ 4,993
Supplemental cash flow information:
Cash paid during the year for -
Interest $ 53,046 $ 50,877 $ 44,421
Income taxes $ 54,881 $ 26,478 $ 36,097
Noncash investing and financing activities -
Capital lease obligations incurred $ 14,281 $ 2,918 $ 14,297
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
IES INDUSTRIES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(a) Basis of Consolidation -
The Consolidated Financial Statements include the accounts of IES
Industries Inc. (Industries) and its consolidated subsidiaries
(collectively the Company). Industries is an investor-owned holding
company whose primary operating company, IES Utilities Inc. (Utilities),
is engaged principally in the generation, transmission, distribution and
sale of electric energy and the purchase, distribution, transportation
and sale of natural gas. The Company's principal markets are located in
the state of Iowa. The Company also has various non-utility
subsidiaries which are primarily engaged in the energy-related,
transportation and real estate development businesses.
All subsidiaries for which Industries owns directly or indirectly
more than 50% of the voting stock are included as consolidated
subsidiaries. Industries' wholly-owned subsidiaries are Utilities and
IES Diversified Inc. (Diversified). All significant intercompany
balances and transactions, other than energy-related transactions
affecting Utilities, have been eliminated from the Consolidated
Financial Statements. Such energy-related transactions are made at
prices that approximate market value and the associated costs are
recoverable from Utilities' customers through the rate making process.
Investments for which the Company has at least a 20% voting
interest are generally accounted for under the equity method of
accounting. These investments are stated at acquisition cost, increased
or decreased for the Company's equity in undistributed net income or
loss, which is included in "Miscellaneous, net" in the Consolidated
Statements of Income. Investments that do not meet the criteria for the
consolidating or equity methods of accounting are accounted for under
the cost method.
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.
Certain prior period amounts have been reclassified on a basis
consistent with the 1996 presentation.
(b) Regulation -
Because of its ownership of Utilities, Industries is a holding
company under the Public Utility Holding Company Act of 1935, but claims
an exemption from all provisions thereof except Section 9(a)(2), which
applies to the purchase of stock of other utility companies. Utilities
is subject to regulation by the Iowa Utilities Board (IUB) and the
Federal Energy Regulatory Commission (FERC).
Refer to Note 2 for a discussion of the proposed merger of the
Company.
(c) Regulatory Assets -
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). The regulatory assets represent
probable future revenue to Utilities associated with certain incurred
costs as these costs are recovered through the rate making process. At
December 31, regulatory assets as reflected in the Consolidated Balance
Sheets were comprised of the following items:
1996 1995
(in millions)
Deferred income taxes (Note 1(d)) $ 84.7 $ 91.1
Energy efficiency program costs (Note 3(b)) 61.1 49.7
Environmental liabilities (Note 13(f)) 46.3 46.9
Employee pension and benefit costs (Note 8) 22.9 27.5
Other 12.7 14.8
227.7 230.0
Classified as "Current assets - regulatory assets" 26.6 22.8
Classified as "Other assets - regulatory assets" $ 201.1 $ 207.2
Refer to the individual notes referenced above for a further
discussion of certain items reflected in regulatory assets.
If a portion of Utilities' operations become no longer subject to
the provisions of SFAS 71, a write-off of related regulatory assets
would be required, unless some form of transition cost recovery is
established by the appropriate regulatory body. In addition, the
Company would be required to determine any impairment to other assets
and write-down such assets to their fair value. Effective January 1,
1996, the Company adopted SFAS 121 which established accounting
standards for the impairment of long-lived assets. This standard also
requires that regulatory assets that are no longer probable of recovery
through future revenues be charged to earnings. There was no impact on
the Company's financial position or results of operations upon adoption
of SFAS 121.
(d) Income Taxes -
The Company follows the liability method of accounting for deferred
income taxes, which requires the establishment of deferred tax
liabilities and assets, as appropriate, for all temporary differences
between the tax basis of assets and liabilities and the amounts reported
in the financial statements. Deferred taxes are recorded using
currently enacted tax rates.
Except as noted below, income tax expense includes provisions for
deferred taxes to reflect the tax effects of temporary differences
between the time when certain costs are recorded in the accounts and
when they are deducted for tax return purposes. As temporary
differences reverse, the related accumulated deferred income taxes are
reversed to income. Investment tax credits for Utilities have been
deferred and are subsequently credited to income over the average lives
of the related property.
Consistent with rate making practices for Utilities, deferred tax
expense is not recorded for certain temporary differences (primarily
related to utility property, plant and equipment). As the deferred
taxes become payable, over periods exceeding 30 years for some
generating plant differences, they are recovered through rates.
Accordingly, Utilities has recorded deferred tax liabilities and
regulatory assets, as identified in Note 1(c).
(e) Temporary Cash Investments -
Temporary cash investments are stated at cost, which approximates
market value, and are considered cash equivalents for the Consolidated
Statements of Cash Flows. These investments consist of short-term
liquid investments that have maturities of less than 90 days from the
date of acquisition.
(f) Depreciation of Utility Property, Plant and Equipment -
Utilities uses the remaining life method of depreciation for its
nuclear generating facility, the Duane Arnold Energy Center (DAEC), and
the straight-line method for all other utility property. The remaining
life of the DAEC is based on the Nuclear Regulatory Commission (NRC)
license life of 2014. The average rates of depreciation for electric and
gas properties of Utilities, consistent with current rate making
practices, were as follows:
1996 1995 1994
Electric 3.5% 3.4% 3.6%
Gas 3.5% 3.5% 3.8%
The electric and gas depreciation rates declined in 1995 from 1994
because of revised depreciation rates approved in rate proceedings of
Utilities.
(g) Decommissioning of the DAEC -
Pursuant to the most recent electric rate case order, the IUB
allows Utilities to recover $6.0 million annually for the cost to
decommission the DAEC. Decommissioning expense is included in
"Depreciation and amortization" in the Consolidated Statements of Income
and the cumulative amount is included in "Accumulated depreciation" in
the Consolidated Balance Sheets to the extent recovered through rates.
The current recovery figures are based on the following assumptions: 1)
cost to decommission the DAEC of $252.8 million, which is Utilities' 70%
portion in 1993 dollars, based on the NRC minimum formula (which exceeds
the amount in the current site-specific study completed in 1994); 2)
inflation of 4.91% annually through 1997; 3) the prompt dismantling and
removal method of decommissioning, which is assumed to begin in the year
2014; 4) monthly funding of all future collections into external trust
funds and funded on a tax-qualified basis to the extent possible; and 5)
an average after-tax return of 6.82% for all external investments. All
of these assumptions are subject to change in future regulatory
proceedings. At December 31, 1996, Utilities had $59.3 million invested
in external decommissioning trust funds as indicated in the Consolidated
Balance Sheets, and also had an internal decommissioning reserve of
$21.7 million recorded as accumulated depreciation. Earnings on the
external trust funds, which were $2.2 million in 1996, are recorded as
interest income and a corresponding interest expense payable to the
funds is recorded. The earnings accumulate in the external trust fund
balances and in accumulated depreciation on utility plant.
See "Management's Discussion and Analysis of the Results of
Operations and Financial Condition" for a discussion of the Exposure
Draft on Accounting for Liabilities Related to Closure and Removal of
Long-Lived Assets, issued by the Financial Accounting Standards Board
(FASB) in the first quarter of 1996, which deals with, among other
issues, the accounting for decommissioning costs.
(h) Property, Plant and Equipment -
Utility plant (other than acquisition adjustments of $29.4 million,
net of accumulated amortization, recorded at cost) is recorded at
original cost, which includes overhead and administrative costs and an
allowance for funds used during construction (AFC). The AFC, which
represents the cost during the construction period of funds used for
construction purposes, is capitalized by Utilities as a component of the
cost of utility plant. The amount of AFC applicable to debt funds and
to other (equity) funds, a non-cash item, is computed in accordance with
the prescribed FERC formula. The aggregate gross rates used by
Utilities for 1996-1994 were 5.5%, 6.5% and 9.3%, respectively. These
capitalized costs are recovered by Utilities in rates as the cost of the
utility plant is depreciated.
Other property, plant and equipment is recorded at cost. Upon
retirement or sale of other property and equipment, the cost and related
accumulated depreciation are removed from the accounts and any gain or
loss is included in "Miscellaneous, net" in the Consolidated Statements
of Income.
Normal repairs, maintenance and minor items of utility plant and
other property, plant and equipment are expensed. Ordinary retirements
of utility plant, including removal costs less salvage value, are
charged to accumulated depreciation upon removal from utility plant
accounts, and no gain or loss is recognized.
(i) Oil and Gas Properties -
Whiting Petroleum Corporation (Whiting), a wholly-owned subsidiary
under Diversified, uses the full cost method of accounting for its oil
and gas properties. Accordingly, all costs of acquisition, exploration
and development of properties are capitalized. Amortization of proved
oil and gas properties is calculated using the units of production
method. At December 31, 1996, capitalized costs less related
accumulated amortization did not exceed the sum of 1) the present value
of future net revenue from estimated production of proved oil and gas
reserves (calculated using current prices); plus 2) the cost of
properties not being amortized, if any; plus 3) the lower of cost or
estimated fair value of unproved properties included in the costs being
amortized, if any; less 4) income tax effects related to differences in
the book and tax basis of oil and gas properties. The Company had $9.8
million on its Consolidated Balance Sheet at December 31, 1995, relating
to specific oil and gas properties purchased by Whiting in the fourth
quarter of 1995 that it intended to sell during 1996. The Company
subsequently decided not to sell these properties and, accordingly, the
balance at December 31, 1996 is included in "Other property, plant and
equipment" on the Consolidated Balance Sheet.
(j) Operating Revenues -
The Company accrues revenues for services rendered but unbilled at
month-end in order to more properly match revenues with expenses.
(k) Adjustment Clauses -
Utilities' tariffs provide for subsequent adjustments to its
electric and natural gas rates for changes in the cost of fuel and
purchased energy and in the cost of natural gas purchased for resale.
Changes in the under/over collection of these costs are reflected in
"Fuel for production" and "Gas purchased for resale" in the Consolidated
Statements of Income. The cumulative effects are reflected in the
Consolidated Balance Sheets as a current asset or current liability,
pending automatic reflection in future billings to customers.
(l) Accumulated Refueling Outage Provision -
The IUB allows Utilities to collect, as part of its base revenues,
funds to offset other operating and maintenance expenditures incurred
during refueling outages at the DAEC. As these revenues are collected,
an equivalent amount is charged to other operating and maintenance
expenses with a corresponding credit to a reserve. During a refueling
outage, the reserve is reversed to offset the refueling outage
expenditures.
(2) PROPOSED MERGER OF THE COMPANY:
On November 10, 1995, Industries, WPL Holdings, Inc. (WPLH) and
Interstate Power Company (IPC) entered into an Agreement and Plan of
Merger, as amended (Merger Agreement), 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
and is intended to be tax-free for federal income tax purposes, has been
approved by the respective Boards of Directors and shareholders. It is
still subject to approval by several federal and state regulatory
agencies. The companies expect to receive such regulatory approvals by
the end of the third quarter of 1997.
The summary below contains selected unaudited pro forma financial
data for the year ended December 31, 1996. The financial data should be
read in conjunction with the historical consolidated financial
statements and related notes of the Company, WPLH, and IPC and in
conjunction with the unaudited pro forma combined financial statements
and related notes of Interstate Energy included in Item 14. The pro
forma combined earnings per share reflect the issuance of shares
associated with the exchange ratios discussed below.
PRO FORMA
IES COMBINED
INDUSTRIES WPLH IPC (Unaudited)
(in thousands, except per share amounts)
Operating revenues $ 973,912 $ 932,844 $ 326,084 $ 2,232,840
Net income from
continuing operations 60,907 73,205 25,860 159,972
Earnings per share from
continuing operations 2.04 2.38 2.69 2.12
Assets at December 31, 1996 2,125,562 1,900,531 639,200 4,665,293
Long-term obligations at
December 31, 1996 744,298 430,190 188,731 1,363,219
Under the terms of the Merger Agreement, the outstanding shares of
WPLH's common stock will remain unchanged and outstanding as shares of
Interstate Energy. Each outstanding share of the Company's common stock
will be converted to 1.14 shares of Interstate Energy's common stock.
Each share of IPC's common stock will be converted to 1.11 shares of
Interstate Energy's common stock. It is anticipated that Interstate
Energy will retain WPLH's common share dividend payment level as of the
effective time of the merger. On January 22, 1997, the Board of
Directors of WPLH declared a quarterly dividend of $0.50 per share.
This represents an equivalent annual rate of $2.00 per share.
WPLH is a holding company headquartered in Madison, Wisconsin, and
is the parent company of Wisconsin Power and Light Company (WP&L) and
Heartland Development Corporation (HDC). WP&L supplies electric and gas
service to approximately 385,000 and 150,000 customers, respectively, in
south and central Wisconsin. HDC and its principal subsidiaries are
engaged in businesses in three major areas: environmental engineering
and consulting, affordable housing and energy services. IPC, an
operating public utility headquartered in Dubuque, Iowa, supplies
electric and gas service to approximately 165,000 and 49,000 customers,
respectively, in northeast Iowa, northwest Illinois and southern
Minnesota.
Interstate Energy will be the parent company of Utilities, WP&L and
IPC and will be registered under the Public Utility Holding Company Act
of 1935, as amended (1935 Act). The Merger Agreement provides that
these operating utility companies will continue to operate as separate
entities for a minimum of three years beyond the effective date of the
merger. In addition, the non-utility operations of the Company and WPLH
will be combined shortly after the effective date of the merger under
one entity to manage the diversified operations of Interstate Energy.
The corporate headquarters of Interstate Energy will be in Madison.
The SEC historically has interpreted the 1935 Act to preclude
registered holding companies, with limited exceptions, from owning both
electric and gas utility systems. Although the SEC has recommended that
registered holding companies be allowed to hold both gas and electric
utility operations if the affected states agree, it remains possible
that the SEC may require as a condition to its approval of the Proposed
Merger that the Company, WPLH and IPC divest their gas utility
properties, and possibly certain non-utility ventures of the Company and
WPLH, within a reasonable time after the effective date of the Proposed
Merger.
(3) RATE MATTERS:
(a) Electric Price Announcements -
Utilities and its Iowa-based proposed merger partner, IPC,
announced in 1996 their intentions to hold retail electric prices to
their current levels until at least January 1, 2000. The companies made
the proposal as part of their testimony in the merger-related
application filed with the IUB; the application was later withdrawn and
was resubmitted in January 1997 and the companies included the same
proposal in the resubmittal of the filing. The proposal excludes price
changes due to government-mandated programs, such as energy efficiency
cost recovery, or unforeseen dramatic changes in operations.
Utilities, WP&L and IPC also proposed to freeze their wholesale
electric prices for four years from the effective date of the merger as
part of their merger filing with the 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.
(b) Energy Efficiency Cost Recovery -
Current IUB rules mandate Utilities to spend 2% of electric and
1.5% of gas gross retail operating revenues for energy efficiency
programs. Under provisions of the IUB rules, Utilities is currently
recovering the energy efficiency costs incurred through 1993 for such
programs, including its direct expenditures, carrying costs, a return on
its expenditures and a reward. These costs are being recovered over a
four-year period and the recovery began on June 1, 1995.
In December 1996, under provisions of the IUB rules, the Company
filed for recovery of the costs relating to its 1994 and 1995 programs.
Utilities' proposed recovery was for approximately $53 million ($42
million electric and $11 million gas) and was composed of $34 million
for direct expenditures and carrying costs, $10 million for a return on
the expenditures over the recovery period and $9 million for a reward
based on a sharing of the benefits of such programs. The Company
expects to receive the final order in the proceeding in June 1997 with
recovery of the allowed costs to commence in the third quarter of 1997.
Iowa statutory changes enacted in 1996, and applicable to future
programs once the legislation is implemented by the IUB, have
eliminated: 1) the 2% and 1.5% spending requirements described above in
favor of IUB-determined energy savings targets, 2) the delay in
recovery of energy efficiency costs by allowing recovery which is
concurrent with spending and 3) the recovery of a sharing reward. The
IUB commenced a rulemaking in January 1997 to implement the statutory
change and a final order in this proceeding is expected in the second
quarter of 1997. The proposed rules provide that the Company would
begin to recover its 1996 expenditures, and the 1997 expenditures
incurred at such time, during the summer of 1997 over a likely four-year
recovery period. The Company would also begin concurrent recovery of
its prospective expenditures at such time. The implementation of these
changes will gradually eliminate the regulatory asset which exists under
the current rate making mechanism as these costs are recovered.
The Company has the following amounts of energy efficiency costs
included in regulatory assets on its Consolidated Balance Sheets at
December 31 (in thousands):
1996 1995
Costs incurred through 1993 $ 12,834 $ 18,287
Costs incurred in 1994-1995 33,161 31,393
Costs incurred in 1996 15,087 -
$ 61,082 $ 49,680
The above amounts include the direct expenditures and carrying
costs incurred by the Company but do not include any amounts for a
return on its expenditures over the recovery period or for a reward.
(4) LEASES:
Utilities has a capital lease covering its 70% undivided interest
in nuclear fuel purchased for the DAEC. Future purchases of fuel may
also be added to the fuel lease. This lease provides for annual
one-year extensions and Utilities intends to continue exercising such
extensions. Interest costs under the lease are based on commercial
paper costs incurred by the lessor. Utilities is responsible for the
payment of taxes, maintenance, operating cost, risk of loss and
insurance relating to the leased fuel.
The lessor has a $45 million credit agreement with a bank
supporting the nuclear fuel lease. The agreement continues on a year-to-
year basis, unless either party provides at least a three-year notice of
termination; no such notice of termination has been provided by either
party.
Annual nuclear fuel lease expenses include the cost of fuel, based
on the quantity of heat produced for the generation of electric energy,
plus the lessor's interest costs related to fuel in the reactor and
administrative expenses. These expenses (included in "Fuel for
production" in the Consolidated Statements of Income) for 1996-1994 were
$18.2 million, $18.0 million and $17.8 million, respectively.
The Company's operating lease rental expenses for 1996-1994 were
$8.3 million, $10.4 million and $11.1 million, respectively.
The Company's future minimum lease payments by year are as follows:
Capital Operating
Year Lease Leases
(in thousands)
1997 $ 16,808 $ 6,891
1998 9,889 6,565
1999 6,969 4,741
2000 3,004 2,510
2001 861 1,370
Thereafter 307 197
37,838 $ 22,274
Less: Amount representing interest 3,113
Present value of net minimum
capital lease payments $ 34,725
(5) UTILITY ACCOUNTS RECEIVABLE:
Customer accounts receivable, including unbilled revenues, arise
primarily from the sale of electricity and natural gas. At December 31,
1996, Utilities was serving a diversified base of residential,
commercial and industrial customers consisting of approximately 336,000
electric and 176,000 gas customers and did not have any significant
concentrations of credit risk.
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. Expenses related to the sale of
receivables are paid to the financial organization under this contract
and approximated a 5.86% annual rate during 1996. During 1996 and 1995,
the monthly proceeds from the sale of accounts receivable averaged
$62.9 million and $61.9 million, respectively. At December 31, 1996,
$65 million was sold under the agreement.
SFAS 125, issued by the FASB in 1996 and effective for 1997,
provides accounting and reporting standards for transfers and servicing
of financial assets and extinguishment of liabilities. The accounting
for Utilities' sale of accounts receivable agreement is impacted by this
standard. As a result, the agreement is being modified to comply with
the SFAS 125 requirements and thus the accounting and reporting for the
sale of Utilities' receivables will remain unchanged.
(6) INVESTMENTS:
(a) Foreign Entities -
At December 31, 1996, the Company had $44.9 million of investments
in foreign entities on its Consolidated Balance Sheet that included 1)
investments in two New Zealand electric distribution entities, 2) a loan
to a New Zealand company, 3) an investment in a cogeneration facility in
China, and 4) an investment in an international venture capital fund.
The Company accounts for the China investment under the equity method
and the other investments under the cost method. The geographic
concentration of the Company's investments in foreign entities at
December 31, 1996, included investments of approximately $30.9 million
in New Zealand, $13.6 in China and $0.4 million in other countries.
(b) McLeod, Inc. (McLeod) -
At December 31, 1996, the Company had a $20.0 million investment in
Class A common stock of McLeod, a $9.2 million investment in Class B
common stock and vested options that, if exercised, would represent an
additional investment of approximately $2.3 million. McLeod provides
local, long-distance and other telecommunications services.
McLeod completed an Initial Public Offering (IPO) of its Class A
common stock in June 1996 and a secondary offering in November 1996. As
of December 31, 1996, the Company is the beneficial owner of
approximately 10.6 million total shares on a fully diluted basis. Class
B shares are convertible at the option of the Company into Class A
shares at any time on a one-for-one basis. The rights of McLeod Class A
common stock and Class B common stock are substantially identical except
that Class A common stock has 1 vote per share and Class B common stock
has 0.40 vote per share. The Company currently accounts for this
investment under the cost method.
The Company has entered into an agreement with McLeod which
provides that for two years commencing on June 10, 1996, the Company
cannot sell or otherwise dispose of any of its securities of McLeod
without the consent of the McLeod Board of Directors. This contractual
sale restriction results in restricted stock under the provisions of
Statement of Financial Accounting Standards No. 115 (SFAS No. 115),
Accounting for Certain Investments in Debt and Equity Securities, until
such time as the restrictions lapse and such shares became qualified for
sale within a one year period. As a result, the Company currently
carries this investment at cost.
The closing price of the McLeod Class A common stock on December
31, 1996, on the Nasdaq National Market, was $25.50 per share. The
current market value of the shares the Company beneficially owns
(approximately 10.6 million shares) is currently impacted by, among
other things, the fact that the shares cannot be sold for a period of
time and it is not possible to estimate what the market value of the
shares will be at the point in time such sale restrictions are lifted.
In addition, any gain upon an eventual sale of this investment would
likely be subject to a tax.
Under the provisions of SFAS No. 115, the carrying value of the
McLeod investment will be adjusted to estimated fair value at the time
such shares become qualified for sale within a one year period; this
will occur on June 10, 1997, which is one year before the contractual
restrictions on sale are lifted. At that time, the adjustment to
reflect the estimated fair value of this investment will be reflected as
an increase in the investment carrying value with the unrealized gain
reported as a net of tax amount in other common shareholders equity
until realized (i.e., sold by the Company).
(7) INCOME TAXES:
The components of federal and state income taxes for the years
ended December 31, were as follows:
1996 1995 1994
(in millions)
Current tax expense $ 38.2 $ 34.7 $ 37.5
Deferred tax expense 11.8 10.5 6.7
Amortization and adjustment
of investment tax credits (2.6) (2.7) (2.6)
$ 47.4 $ 42.5 $ 41.6
The overall effective income tax rates shown below for the years
ended December 31, were computed by dividing total income tax expense by
income before income taxes.
1996 1995 1994
Statutory federal income tax rate 35.0% 35.0% 35.0%
State income taxes, net of federal benefits 6.6 5.5 5.9
Effect of rate making on property
related differences 2.8 2.6 1.6
Amortization of investment tax credits (2.4) (2.5) (2.5)
Adjustment of prior period taxes 1.4 (0.4) (1.6)
Other items, net 0.4 (0.4) -
Overall effective income tax rate 43.8% 39.8% 38.4%
The accumulated deferred income taxes as set forth below in the
Consolidated Balance Sheets at December 31, arise from the following
temporary differences:
1996 1995
(in millions)
Property related $ 293 $ 296
Investment tax credit related (24) (26)
Decommissioning related (15) (14)
Other 9 1
$ 263 $ 257
(8) BENEFIT PLANS:
(a) Pension Plans -
The Company has two non-contributory pension plans that,
collectively, cover substantially all of its employees. Plan benefits
are generally based on years of service and compensation during the
employees' latter years of employment. Payments made from the pension
funds to retired employees and beneficiaries during 1996 totaled
$10.7 million.
The Company's policy is to fund the pension cost at an amount that
is at least equal to the minimum funding requirements mandated by the
Employee Retirement Income Security Act (ERISA) and that does not exceed
the maximum tax deductible amount for the year. The Company has an
investment policy governing asset allocation guidelines for its pension
plans. The target ranges are as follows: 1) 37%-43% in large and mid-
sized domestic company equity securities, 2) 7%-13% in foreign equity
securities, 3) 7%-13% in small domestic company equity securities, 4) 0-
5% in real estate, and 5) the remainder in fixed income securities. As
of December 31, 1996, the plan's investment mix was consistent with the
policy guidelines.
Pursuant to the provisions of SFAS 71, certain adjustments to
Utilities' pension provision are necessary to reflect the accounting for
pension costs allowed in its most recent rate cases.
The components of the pension provision for the years ended
December 31, were as follows:
1996 1995 1994
(in thousands)
Service cost $ 5,997 $ 5,215 $ 5,863
Interest cost on projected benefit
obligation 12,711 11,811 11,431
Assumed return on plans' assets (14,976) (12,567) (12,593)
Early retirement benefits 4,713 - -
Net amortization 906 268 841
Pension cost 9,351 4,727 5,542
Adjustment to funding level (9,351) (4,727) (5,431)
Total pension costs paid to the Trustee $ - $ - $ 111
Actual return on plans' assets $ 26,297 $ 36,614 $ (97)
During 1996, the Company incurred a one-time charge of $4.7 million
related to an early retirement program. Of such costs, $0.2 million was
charged to expense and the remaining amount was deferred for future
recovery through the regulatory process.
A reconciliation of the funded status of the plans to the amounts
recognized in the Consolidated Balance Sheets at December 31, is
presented below:
1996 1995
(in thousands)
Fair market value of plans' assets $ 212,394 $ 195,329
Actuarial present value of benefits rendered to date -
Accumulated benefits based on compensation to date,
including vested benefits of $130,334,000 and
$119,996,000, respectively 142,515 131,274
Additional benefits based on estimated future
salary levels 42,940 41,581
Projected benefit obligation 185,455 172,855
Plans' assets in excess of projected
benefit obligation 26,939 22,474
Remaining unrecognized net asset existing at
January 1, 1987, being amortized over 20 years (3,179) (3,511)
Unrecognized prior service cost 15,523 16,905
Unrecognized net gain (54,442) (41,795)
Accrued pension cost recognized in the
Consolidated Balance Sheets $ (15,159) $ (5,927)
Assumed rate of return, all plans 9.00% 8.00%
Weighted average discount rate of projected benefit
obligation, all plans 7.50% 7.50%
Assumed rate of increase in future compensation
levels for the plans 4.75% 4.75%
The assumed rate of return was increased to 9.00% in 1996 based on
actual historical performance of the previously stated investment mix.
The Company also sponsors defined contribution pension plans
(401(k) plans) covering substantially all employees. The Company's
contributions to the plans, which are based on the participants' level
of contribution and cannot exceed 2.8% of the participants' salaries or
wages, were $1.7 million, $1.5 million and $1.8 million in 1996, 1995
and 1994, respectively.
(b) Other Postemployment Benefit Plans -
The Company provides certain benefits to retirees (primarily health
care benefits). The IUB adopted rules stating that postretirement
benefits other than pensions will be included in Utilities' rates
pursuant to the provisions of SFAS 106. The rules permit Utilities to
amortize the transition obligation as of January 1, 1993, over 20 years
and require that all amounts collected are to be funded into an external
trust to pay benefits as they become due. The gas and electric portions
of these costs are being recovered through rates beginning in 1993 and
1995, respectively, including amounts that were deferred by the Company,
pursuant to IUB rules, between when SFAS 106 was adopted and when
recovery through rates began. The amounts deferred are being amortized
as they are collected through rates over a three-year period.
Utilities' unamortized balance of these deferred costs was $1.5 million
at December 31, 1996.
Pursuant to the provisions of SFAS 71, certain adjustments to
Utilities' other postretirement benefit provisions are necessary to
reflect the accounting for other postretirement benefit costs allowed in
its most recent rate cases.
The components of postretirement benefit costs for the years ended
December 31, were as follows:
1996 1995 1994
(in thousands)
Service cost $ 1,888 $ 1,387 $ 1,838
Interest cost on accumulated
postretirement benefit obligation 3,726 3,175 3,275
Assumed return on plans' assets (388) (56) (60)
Net amortization of transition
obligation and other 1,970 1,813 2,037
Amortized/(deferred) postretirement
benefit costs 1,863 2,220 (2,732)
Regulatory recognition of incurred cost 49 1,162 -
Net postretirement benefit costs $ 9,108 $ 9,701 $ 4,358
Actual return on plans' assets $ 945 $ 273 $ 47
A reconciliation of the funded status of the plans to the amounts
recognized in the Consolidated Balance Sheets at December 31, is
presented below:
1996 1995
(in thousands)
Fair market value of plans' assets $ 12,312 $ 6,515
Accumulated postretirement benefit obligation -
Active employees not yet eligible 19,056 22,254
Active employees eligible 4,866 6,282
Retirees 25,992 22,575
Total accumulated postretirement benefit
obligation 49,914 51,111
Accumulated postretirement benefit obligation
in excess of plans' assets (37,602) (44,596)
Unrecognized transition obligation 31,020 34,415
Unrecognized net (gain)/loss (2,505) 349
Unrecognized prior service cost (427) 151
Accrued postretirement benefit cost in the
Consolidated Balance Sheets $ (9,514) $ (9,681)
Assumed rate of return 9.00% 8.00%
Weighted average discount rate of accumulated
postretirement benefit obligation 7.50% 7.50%
Medical trend on paid charges:
Initial trend rate 9.00% 10.00%
Ultimate trend rate 6.50% 6.50%
The assumed rate of return was increased to 9.00% in 1996 based on
actual historical performance of investments of a similar nature. The
assumed medical trend rates are critical assumptions in determining the
service and interest cost and accumulated postretirement benefit
obligation related to postretirement benefit costs. A 1% change in the
medical trend rates, holding all other assumptions constant, would have
changed the 1996 service and interest cost by $1.2 million (21%) and the
accumulated postretirement benefit obligation at December 31, 1996, by
$8.5 million (17%).
(9) COMMON, PREFERRED AND PREFERENCE STOCK:
(a) Common Stock -
The following table presents information relating to the changes in
common stock.
Common Stock
Number of Shares
Outstanding Amount
(in thousands)
Balance, December 31, 1993 28,304,188 $ 360,301
Shares issued in connection with
acquisition of oil and gas companies 139,102 4,027
Purchases of treasury stock (213,300) (6,233)
Stock plan issuances* 547,056 15,395
Balance, December 31, 1994 28,777,046 373,490
Shares issued in connection with
acquisition of oil and gas companies 75,638 1,925
Stock plan issuances* 655,731 15,854
Balance, December 31, 1995 29,508,415 391,269
Purchases of treasury stock (9,448) (269)
Stock plan issuances* 578,245 16,635
Balance, December 31, 1996 30,077,212 $ 407,635
Shares reserved for issuance pursuant to the
Company's stock plans at December 31, 1996* 1,632,869
* Dividend Reinvestment and Stock Purchase Plan,
Employee Stock Purchase Plan, Employee Savings Plan,
Long-Term Incentive Plan, IES Bonus Stock Ownership
Plan and Whiting Stock Option Plans
During 1996, Industries reacquired 9,448 shares of its common stock
on the open market, at an average price of $28.44 per share, which were
subsequently issued to various Company Directors and employees. During
1994, Industries reacquired 213,300 shares of its common stock on the
open market, at an average price of $29.22 per share, which were
subsequently issued to the Dividend Reinvestment Plan and certain of its
benefit plans. At December 31, 1996, no shares remained held as
treasury stock.
(b) Preferred and Preference Stock:
Utilities has 466,406 shares of Cumulative Preferred Stock, $50 par
value, authorized for issuance at December 31, 1996, of which the 6.10%,
4.80% and 4.30% Series had 100,000, 146,406 and 120,000 shares,
respectively, outstanding at both December 31, 1996 and 1995. These
shares are redeemable at the option of Utilities upon 30 days notice at
$51.00, $50.25 and $51.00 per share, respectively, plus accrued
dividends.
There are 5,000,000 shares of Industries Cumulative Preferred Stock
(no par value) and 700,000 shares of Utilities Cumulative Preference
Stock ($100 par value) authorized for issuance, of which none were
outstanding at December 31, 1996.
(10) DEBT:
(a) Long-Term Debt -
In September 1996, Utilities repaid at maturity $15 million of
Series J, 6.25% First Mortgage Bonds and, in a separate transaction,
issued $60 million of Collateral Trust Bonds, 7.25%, due 2006.
Utilities' Indentures and Deeds of Trust securing its First
Mortgage Bonds constitute direct first mortgage liens upon substantially
all tangible public utility property. Utilities' Indenture and Deed of
Trust securing its Collateral Trust Bonds constitutes a second lien on
substantially all tangible public utility property while First Mortgage
Bonds remain outstanding.
Diversified has a variable rate credit facility that extends
through November 20, 1999, with two one-year extensions potentially
available to Diversified. The unborrowed portion of the agreement is
also used to support Diversified's commercial paper program. A combined
maximum of $300 million of borrowings under the agreement and commercial
paper program may be outstanding at any one time. Interest rates and
maturities are set at the time of borrowing for direct borrowings under
the agreement and for issuances of commercial paper. The interest rate
options are based upon quoted market rates and the maturities are less
than one year. At December 31, 1996, $23 million was borrowed under
this facility, bearing an interest rate of 5.75%, maturing in the first
quarter of 1997. Diversified had $149.1 million of commercial paper
outstanding at December 31, 1996, with interest rates ranging from 5.50%
to 7.10% and maturity dates in the first quarter of 1997. Diversified
intends to continue borrowing under the renewal options of the facility
and no conditions exist at December 31, 1996, that would prevent such
borrowings. Accordingly, this debt is classified as long-term in the
Consolidated Balance Sheets. Refer to Note 12(a) for a discussion of an
interest rate swap agreement Diversified entered into relating to this
facility.
Total sinking fund requirements, which Utilities intends to meet by
pledging additional property under the terms of its Indentures and Deeds
of Trust, and debt maturities for 1997-2001 are $9 million, $1 million,
$61 million, $67 million and $255 million, respectively. The Company
intends to refinance the majority of the debt maturities with long-term
securities.
(b) Short-Term Debt -
At December 31, 1996, the Company had bank lines of credit
aggregating $136.1 million. Utilities was using $110 million to support
commercial paper 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. Information regarding short-term debt (all issued by
Utilities) is as follows (dollars in thousands):
1996 1995 1994
As of end of year -
Commercial paper outstanding $ 110,000 $ 101,000 $ 37,000
Notes payable outstanding 25,000 - -
Weighted average interest rate
on commercial paper 5.70% 5.81% 6.13%
Weighted average interest rate
on notes payable 6.28% - -
For the year ended -
Maximum month-end amount
of short-term debt $ 145,000 $ 132,000 $ 37,000
Average daily amount outstanding 120,112 79,159 5,269
Weighted average interest rate 5.52% 5.97% 5.31%
(11) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS:
The following methods and assumptions were used to estimate the
fair value of each class of financial instruments:
Current Assets and Current Liabilities - The carrying amount
approximates fair value because of the short maturity of such financial
instruments.
Nuclear Decommissioning Trust Funds - The carrying amount
represents the fair value of these trust funds, as reported by the
trustee. The balance of the "Nuclear decommissioning trust funds" as
shown in the Consolidated Balance Sheets included $9.4 million of
unrealized gains at December 31, 1996, and $5.3 million of unrealized
gains at December 31, 1995, on the investments held in the trust funds.
The accumulated reserve for decommissioning costs was adjusted by a
corresponding amount.
Cumulative Preferred Stock of Utilities - Based upon the market
yield of similar securities and quoted market prices.
Long-Term Debt - Based upon the market yield of similar securities
and quoted market prices.
Investments carried at cost - Fair value of the McLeod investment
is based on quoted market prices at December 31, 1996 (including an
assumed exercise of the Company's options at the December 31, 1996
market price less the exercise price); the 1995 fair value is based on
the carrying value as there was no quoted market price prior to the 1996
IPO. Fair value of the New Zealand investments is based on quoted
market prices; while the market is not of a breadth and scope comparable
to a U.S. market as required for SFAS 115 accounting purposes, the
Company does believe it produces a reasonable representation of the fair
market value of the investment. Fair value of the other investments is
based on quoted market prices where available, and cost when not
available as the Company believes the carrying value approximates fair
value for such investments.
The following table presents the carrying amount and estimated fair
value of certain financial instruments as of December 31 (in millions):
1996 1995
Carrying Fair Carrying Fair
Value Value Value Value
Cumulative preferred stock
of Utilities $ 18 $ 12 $ 18 $ 11
Long-term debt, including
current portion 712 722 620 644
Investments carried at cost -
Investment in McLeod, Inc. (Note 6(b)) 29 267 9 9
Investments in New Zealand (Note 6(a)) 31 45 25 22
Other 3 4 3 5
Since Utilities is subject to regulation, any gains or losses
related to the difference between the carrying amount and the fair value
of its financial instruments may not be realized by the Company's
shareholders.
(12) DERIVATIVE FINANCIAL INSTRUMENTS:
The Company has a policy that financial derivatives are to be used
only to mitigate business risks and not for speculative purposes.
Derivatives have been used by the Company on a very limited basis.
(a) Interest Rate Swap Agreement -
In February 1996, Diversified entered into an interest rate swap
agreement on a variable rate borrowing of $100 million converting this
debt into a fixed-rate borrowing at a rate of 4.7 percent. The swap
period is for two years with an additional one-year option available to
the counterparty and the agreement includes quarterly settlement dates.
Diversified realized approximately $0.7 million in interest expense
savings in 1996 under the agreement. The fair value of this financial
instrument is based on the amounts estimated to terminate or settle the
agreement. At December 31, 1996, the agreement, if settled on that
date, would have required the counterparty to pay the Company
approximately $1.2 million. Such value is based on the difference in
the interest rates as well as the amount of time remaining in the
agreement. The Company has no intention of terminating the agreement at
this time.
(b) Gas Futures Contracts -
Industrial Energy Applications, Inc. (IEA), a wholly-owned
subsidiary under Diversified, has entered into natural gas contracts on
the New York Mercantile Exchange (NYMEX) in the notional amount of $6.4
million at December 31, 1996. The original contract terms range from
one to seventeen months. The contracts are intended to mitigate risk
from fluctuations in the price of natural gas that will be required to
satisfy sales commitments for future deliveries to customers and for
sales from storage. Gains and losses on these hedging contracts are
deferred and recognized in income when the transactions being hedged are
finalized.
(13) COMMITMENTS AND CONTINGENCIES:
(a) Construction Program -
The Company's construction and acquisition program anticipates
expenditures of approximately $225 million for 1997, which includes $147
million at Utilities and $78 million at Diversified. Substantial
commitments have been made in connection with these expenditures.
(b) Purchased Power, Coal and Natural Gas Contracts -
Utilities has entered into purchased power capacity and coal
contracts and its minimum commitments are as follows (dollars and tons
in thousands):
Purchased Power Coal
Dollars Mw's Dollars Tons
1997 $ 11,175 69 - 144 $ 68,323 4,472
1998 3,415 9 - 109 17,250 886
1999 3,283 1 - 101 17,509 874
2000 283 1 15,696 762
2001 283 1 15,913 751
The Company has several purchased power contracts for the annual
six-month summer season and thus the minimum and maximum of the noted
range represent the power purchased during the winter and summer
seasons, respectively. The Company expects to supplement its coal
contracts with spot market purchases to fulfill its future fossil fuel
needs.
Utilities also has various natural gas supply, transportation and
storage contracts outstanding. The gas supply commitments are all index
based and the minimum dekatherm commitments, in thousands, for 1997-2001
are 10,699, 5,074, 5,074, 3,574 and 3,574, respectively. The minimum
transportation and storage commitments for 1997-2001, in thousands, are
$32,080, $31,842, $29,220, $27,050 and $24,008, respectively. The
Company expects to supplement its natural gas supply with spot market
purchases as needed.
(c) Information Technology Services -
The Company entered into an agreement, expiring in 2004, with
Electronic Data Systems Corporation (EDS) for information technology
services. The contract is subject to declining termination fees. The
Company's anticipated operating and capital expenditures under the
agreement for 1997 are estimated to total approximately $12.5 million.
Future costs under the agreement are variable and are dependent upon the
Company's level of usage of technological services from EDS.
(d) Financial Guarantees -
The Company has financial guarantees amounting to $22.9 million
outstanding at December 31, 1996, which are not reflected in the
consolidated financial statements. Such guarantees are generally issued
to support third-party borrowing arrangements and similar transactions.
The Company believes that the likelihood of material cash payments by
the Company under these agreements is remote.
(e) 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, $6.4 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.
(f) Environmental Liabilities -
The Company has recorded environmental liabilities of approximately
$53 million in its Consolidated Balance Sheets at December 31, 1996. The
Company's significant environmental liabilities 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 ten 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 16 sites
and estimates the range of additional costs to be incurred for
investigation, remediation and monitoring of the sites to be
approximately $24 million to $54 million.
Utilities has recorded environmental liabilities related to the
FMGP sites of approximately $36 million (including $4.7 million as
current liabilities) at December 31, 1996. These amounts are based upon
Utilities' best current estimate of the amount to be incurred for
investigation, remediation and monitoring 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.
Regulatory assets of approximately $36 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.
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.
Settlement has been reached with two carriers and an agreement in
principle has been reached with three other carriers thus far. Any
amounts received from insurance carriers will be deferred pending a
determination of the regulatory treatment of such recoveries.
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 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, $9.9
million payable through 2007, has been recorded as a liability in the
Consolidated Balance Sheets, including $0.9 million included in "Current
liabilities - Environmental liabilities," with a related regulatory
asset for the unrecovered amount.
Oil and Gas Properties Dismantlement and Abandonment Costs
Whiting is responsible for certain dismantlement and abandonment
costs related to various off-shore oil and gas properties, the most
significant of which is located off the coast of California. The
Company estimates the total costs for these properties to be
approximately $16 million and the expenditures are not expected to be
incurred for approximately five years. Whiting accrues these costs as
reserves are extracted and such costs are included in "Depreciation and
amortization" in the Consolidated Statements of Income, resulting in a
liability of $7.0 million at December 31, 1996, in the Consolidated
Balance Sheets.
The Company adopted the provisions of Statement of Position 96-1
(SOP-96-1), Environmental Remediation Liabilities, in 1996. This
statement provides authoritative guidance for recognition, measurement
and disclosure of environmental remediation liabilities in financial
statements. Upon adoption of SOP-96-1, the Company's estimated
liability increased by approximately $2.2 million, primarily resulting
from the recording of Utilities' anticipated FMGP postremediation
monitoring costs, and a related increase to regulatory assets was also
recorded.
(g) 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 $12.9 million,
including $0.6 million in 1997, 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. In December 1996, the EPA issued
proposed rules that would tighten the National Ambient Air Quality
Standards (NAAQS) for ozone and particulate matter emissions. Also in
the fourth quarter of 1996, the EPA announced that it would issue a
notice in March 1997 requiring the 37 states in the Ozone Transport
Assessment Group (OTAG), which includes Iowa, to implement further
controls on NOx. These proposals could result in the Company having to
incur additional capital expenditures to further reduce its emissions of
NOx, ozone and particulate matter. 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 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. As a result of these exceedences, Utilities is
entering into a Consent Agreement with the Iowa Department of Natural
Resources. The intent of this agreement, as currently proposed, is to
develop a three-year plan for a process to explore and implement options
to modify one of Utilities fossil generating facilities to reduce SO2
emissions. In addition, Utilities is proposing to resolve the remainder
of EPA's nonattainment concerns by either modifying the current stack or
installing a new stack at the other generating facility contributing to
the modeled exceedences at a potential aggregate capital cost of up to
$4.5 million over the next two years.
Pursuant to a routine internal review of operations, Utilities
determined that certain changes undertaken during the previous three
years at one of its power plants may have required a federal Prevention
of Significant Deterioration (PSD) permit. Utilities initiated
discussions with its regulators on the matter and is preparing the PSD
permit application for filing in the first quarter of 1997. Utilities
may be required to accept operational limits or to install additional
controls and may be subject to liability for not having obtained the
permit previously; however, Utilities believes that any likely actions
resulting from this matter will not have a material adverse effect on
its financial position or results of operations.
(h) Spent Nuclear Fuel -
The Nuclear Waste Policy Act of 1982 assigned responsibility to the
U.S. Department of Energy (DOE) to establish a facility for the ultimate
disposition of high level waste and spent nuclear fuel and authorized
the DOE to enter into contracts with parties for the disposal of such
material beginning in January 1998. Utilities entered into such a
contract and has made the agreed payments to the Nuclear Waste Fund
(NWF) held by the U.S. Treasury. The DOE, however, has experienced
significant delays in its efforts and material acceptance is now
expected to occur no earlier than 2010 with the possibility of further
delay being likely. Utilities has been storing spent nuclear fuel on-
site since plant operations began in 1974 and has current on-site
capability to store spent fuel until 2001. Utilities is aggressively
reviewing options for expanding on-site storage. Utilities has been
formally notified by the DOE that they anticipate being unable to begin
acceptance of spent nuclear fuel by January 31, 1998. Utilities is
evaluating courses of action to protect the interests of its customers
and its rights under the DOE contract. Utilities is also evaluating
legislation proposed to the Congress addressing this issue.
(i) Legal Proceedings -
The Company is involved in other legal and administrative
proceedings before various courts and agencies with respect to matters
arising in the ordinary course of business. Although unable to predict
the outcome of these matters, the Company believes that appropriate
liabilities have been established and final disposition of these actions
will not have a material adverse effect on its financial position or
results of operations.
(14) JOINTLY-OWNED ELECTRIC UTILITY PLANT:
Under joint ownership agreements with other Iowa utilities,
Utilities has undivided ownership interests in jointly-owned electric
generating stations and related transmission facilities. Each of the
respective owners is responsible for the financing of its portion of the
construction costs. Kilowatt-hour generation and operating expenses are
divided on the same basis as ownership with each owner reflecting its
respective costs in its Statements of Income. Information relative to
Utilities' ownership interest in these facilities at December 31, 1996
is as follows:
Ottumwa Neal
DAEC Unit 1 Unit 3
(Nuclear) (Coal) (Coal)
($ in millions)
Utility plant in service $ 501.0 $ 190.2 $ 60.7
Accumulated depreciation $ 217.2 $ 91.0 $ 28.8
Construction work in progress $ 1.2 $ 0.1 $ 0.1
Plant capacity - Mw 520 716 515
Percent ownership 70% 48% 28%
In-service date 1974 1981 1975
(15) SEGMENTS OF BUSINESS:
The principal business segments of Industries are the generation,
transmission, distribution and sale of electric energy by Utilities and
the purchase, distribution, transportation and sale of natural gas by
Utilities and IEA. Certain financial information relating to
Industries' significant segments of business is presented below:
Year Ended December 31
1996 1995 1994
(in thousands)
Operating results:
Revenues -
Electric $ 574,273 $ 560,471 $ 537,327
Gas 273,979 190,339 165,569
Operating income -
Electric 132,278 130,390 125,487
Gas 14,978 11,056 8,762
Other information:
Depreciation and amortization -
Electric 77,578 72,487 68,640
Gas 6,200 6,176 6,214
Construction and acquisition expenditures - *
Electric 115,810 108,356 112,773
Gas 20,980 9,368 10,066
Assets -
Identifiable assets -
Electric 1,438,370 1,395,666 1,347,024
Gas 228,780 199,050 192,397
1,667,150 1,594,716 1,539,421
Other corporate assets 458,412 390,875 309,672
Total consolidated assets $ 2,125,562 $ 1,985,591 $ 1,849,093
* Excludes intercompany acquisitions which are eliminated for consolidated
financial statement purposes.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
IES Utilities Inc.:
We have audited the accompanying consolidated balance sheets and
statements of capitalization of IES Utilities Inc. (an Iowa corporation)
and subsidiary companies as of December 31, 1996 and 1995, and the
related consolidated statements of income, retained earnings and cash
flows for each of the three years in the period ended December 31, 1996.
These financial statements and the financial statement schedule referred
to below are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements
and schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of IES
Utilities Inc. and subsidiary companies as of December 31, 1996 and
1995, and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 1996, in conformity
with generally accepted accounting principles.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedule
listed in Item 14(a)2 is presented for purposes of complying with the
Securities and Exchange Commission's rules and is not part of the basic
financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and,
in our opinion, fairly states in all material respects the financial
data required to be set forth therein in relation to the basic financial
statements taken as a whole.
ARTHUR ANDERSEN LLP
Chicago, Illinois
January 31, 1997
IES UTILITIES INC. CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31
1996 1995 1994
(in thousands)
Operating revenues:
Electric $ 574,273 $ 560,471 $ 537,327
Gas 160,864 137,292 139,033
Other 19,842 12,063 9,006
754,979 709,826 685,366
Operating expenses:
Fuel for production 84,579 96,256 85,952
Purchased power 88,350 66,874 68,794
Gas purchased for resale 103,877 91,198 95,340
Other operating expenses 150,001 145,250 132,281
Maintenance 45,869 43,586 49,542
Depreciation and amortization 84,975 79,384 75,316
Taxes other than income taxes 43,603 45,013 42,550
601,254 567,561 549,775
Operating income 153,725 142,265 135,591
Interest expense and other:
Interest expense 43,714 44,460 41,572
Allowance for funds used during construction -2,103 -3,424 -3,910
Miscellaneous, net 5,293 856 -1,247
46,904 41,892 36,415
Income before income taxes 106,821 100,373 99,176
Federal and state income taxes 43,092 41,095 37,966
Net income 63,729 59,278 61,210
Preferred dividend requirements 914 914 914
Net income available for common stock $ 62,815 $ 58,364 $ 60,296
IES UTILITIES INC. CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31
1996 1995 1994
(in thousands)
Balance at beginning of year $ 212,522 $ 197,158 $ 188,862
Net income 63,729 59,278 61,210
Cash dividends declared -
Common stock -44,000 -43,000 -52,000
Preferred stock, at stated rates -914 -914 -914
Balance at end of year $ 231,337 $ 212,522 $ 197,158
The accompanying Notes to Consolidated Financial Statements are an
integral part of these statements.
IES UTILITIES INC. CONSOLIDATED BALANCE SHEETS
December 31
ASSETS (in thousands) 1996 1995
Property, plant and equipment:
Utility -
Plant in service -
Electric $ 2,007,839 $ 1,900,157
Gas 175,472 165,825
Other 126,850 106,396
2,310,161 2,172,378
Less - Accumulated depreciation 1,030,390 950,324
1,279,771 1,222,054
Leased nuclear fuel, net of amortization 34,725 36,935
Construction work in progress 43,719 52,772
1,358,215 1,311,761
Other, net of accumulated depreciation and amortization
of $1,438 and $1,166, respectively 5,872 5,477
1,364,087 1,317,238
Current assets:
Cash and temporary cash investments 11,608 2,734
Accounts receivable -
Customer, less allowance for doubtful accounts
of $546 and $676, respectively 22,461 18,619
Other 11,270 8,912
Income tax refunds receivable 2,664 846
Production fuel, at average cost 13,323 12,155
Materials and supplies, at average cost 21,716 27,229
Adjustment clause balances 10,752 0
Regulatory assets 26,539 22,791
Prepayments and other 18,705 18,556
139,038 111,842
Investments:
Nuclear decommissioning trust funds 59,325 47,028
Cash surrender value of life insurance policies 4,281 3,582
Other 313 475
63,919 51,085
Other assets:
Regulatory assets 201,129 207,202
Deferred charges and other 10,437 21,268
211,566 228,470
$ 1,778,610 $ 1,708,635
December 31
CAPITALIZATION AND LIABILITIES (in thousands) 1996 1995
Capitalization (See Consolidated Statements of Capitalization):
Common stock $ 33,427 $ 33,427
Paid-in surplus 279,042 279,042
Retained earnings 231,337 212,522
Total common equity 543,806 524,991
Cumulative preferred stock 18,320 18,320
Long-term debt (excluding current portion) 517,334 465,463
1,079,460 1,008,774
Current liabilities:
Notes payable to associated companies 0 8,888
Other short-term borrowings 135,000 101,000
Capital lease obligations 15,125 15,717
Maturities and sinking funds 8,140 15,140
Accounts payable 76,287 64,564
Accrued interest 8,839 8,038
Accrued taxes 40,953 50,369
Accumulated refueling outage provision 1,316 7,690
Adjustment clause balances 0 3,148
Environmental liabilities 5,517 5,521
Other 17,114 17,300
308,291 297,375
Long-term liabilities:
Pension and other benefit obligations 25,826 41,866
Capital lease obligations 19,600 21,218
Environmental liabilities 40,299 40,905
Other 14,030 8,719
99,755 112,708
Deferred credits:
Accumulated deferred income taxes 256,634 252,663
Accumulated deferred investment tax credits 34,470 37,115
291,104 289,778
Commitments and contingencies (Note 13)
$ 1,778,610 $ 1,708,635
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
IES UTILITIES INC. CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31
1996 1995
(in thousands)
Common equity:
Common stock - par value $2.50 per share - authorized
24,000,000 shares; outstanding 13,370,788 shares $ 33,427 $ 33,427
Paid-in surplus 279,042 279,042
Retained earnings 231,337 212,522
543,806 524,991
Cumulative preferred stock 18,320 18,320
Long-term debt:
Collateral Trust Bonds -
7.65% series, due 2000 50,000 50,000
7.25% series, due 2006 60,000 0
6% series, due 2008 50,000 50,000
7% series, due 2023 50,000 50,000
5.5% series, due 2023 19,400 19,400
229,400 169,400
First Mortgage Bonds -
Series J, 6-1/4%, retired in 1996 0 15,000
Series L, 7-7/8%, due 2000 15,000 15,000
Series M, 7-5/8%, due 2002 30,000 30,000
Series Y, 8-5/8%, due 2001 60,000 60,000
Series Z, 7.60%, due 1999 50,000 50,000
6-1/8% series, due 1997 8,000 8,000
9-1/8% series, due 2001 21,000 21,000
7-3/8% series, due 2003 10,000 10,000
7-1/4% series, due 2007 30,000 30,000
224,000 239,000
Pollution control obligations -
5.75%, due serially 1997 to 2003 3,416 3,556
5.95%, due serially 2000 to 2007, secured by
First Mortgage Bonds 10,000 10,000
Variable rate (4.25%-4.35% at December 31, 1996),
due 2000 to 2010 11,100 11,100
24,516 24,656
Subordinated Deferrable Interest Debentures, 7-7/8%, due 2025 50,000 50,000
Unamortized debt premium and (discount), net -2,442 -2,453
525,474 480,603
Less - Amount due within one year 8,140 15,140
517,334 465,463
$ 1,079,460 $ 1,008,774
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
IES UTILITIES INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
1996 1995 1994
(in thousands)
Cash flows from operating activities:
Net income $ 63,729 $ 59,278 $ 61,210
Adjustments to reconcile net income to net cash
flows from operating activities -
Depreciation and amortization 84,975 79,384 75,316
Amortization of principal under capital
lease obligations 16,491 15,714 16,246
Deferred taxes and investment tax credits 7,763 7,628 -410
Refueling outage provision -6,374 -7,506 12,536
Amortization of other assets 9,776 7,391 2,228
Other 279 184 -1,232
Other changes in assets and liabilities -
Accounts receivable -13,200 -9,717 10,395
Sale of utility accounts receivable 7,000 4,000 800
Production fuel, materials and supplies 651 1,658 404
Accounts payable 12,885 -4,395 20,444
Accrued taxes -11,234 5,785 7,057
Provision for rate refunds -106 106 -8,670
Adjustment clause balances -13,900 4,581 -6,582
Gas in storage -551 2,429 1,919
Other 7,322 -1,085 4,171
Net cash flows from operating activities 165,506 165,435 195,832
Cash flows from financing activities:
Dividends declared on common stock -44,000 -43,000 -52,000
Dividends declared on preferred stock -914 -914 -914
Proceeds from issuance of long-term debt 60,000 100,000 0
Reductions in long-term debt -15,140 -100,140 -224
Net change in short-term borrowings 25,112 54,393 31,495
Principal payments under capital lease obligations -19,108 -14,463 -16,304
Other -420 -1,831 -5,144
Net cash flows from financing activities 5,530 -5,955 -43,091
Cash flows from investing activities:
Construction and acquisition expenditures -
Utility -142,381 -126,104 -146,240
Other -1,267 -3,340 -1,863
Deferred energy efficiency expenditures -16,857 -18,029 -16,157
Nuclear decommissioning trust funds -6,008 -6,100 -5,532
Other 4,351 -5,308 873
Net cash flows from investing activities -162,162 -158,881 -168,919
Net increase (decrease) in cash and
temporary cash investments 8,874 599 -16,178
Cash and temporary cash investments at
beginning of year 2,734 2,135 18,313
Cash and temporary cash investments at
end of year $ 11,608 $ 2,734 $ 2,135
Supplemental cash flow information:
Cash paid during the year for -
Interest $ 42,072 $ 44,569 $ 40,005
Income taxes $ 45,383 $ 29,083 $ 34,479
Noncash investing and financing activities -
Capital lease obligations incurred $ 14,281 $ 2,918 $ 14,297
The accompanying Notes to Consolidated Financial Statements
are an integral part of these statements.
IES UTILITIES INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Except as modified below, the IES Industries Inc. (Industries)
Notes to Consolidated Financial Statements are incorporated
by reference insofar as they relate to IES Utilities Inc.
(Utilities). Industries' Notes 1(i), 6, 9(a) and 12 do
not relate to Utilities and, therefore, are not incorporated by
reference.
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(a) Basis of Consolidation -
Utilities is a wholly-owned subsidiary of
Industries. The Consolidated Financial Statements
include the accounts of Utilities and its consolidated subsidiaries.
Utilities is engaged principally in the generation, transmission,
distribution and sale of electric energy, the purchase, distribution,
transportation and sale of natural gas and to provide steam for
industrial and heating purposes. Utilities' markets are located in the
state of Iowa.
All subsidiaries for which Utilities owns directly or indirectly
more than 50% of the voting stock are included as consolidated
subsidiaries. Utilities' only wholly-owned subsidiary at December 31,
1996 was IES Ventures Inc. (Ventures). Ventures' wholly-owned
subsidiary at December 31, 1996 was IES Midland Development Inc. All
significant intercompany balances and transactions have been eliminated
from the Consolidated Financial Statements.
(4) LEASES:
Utilities' operating lease rental expenses for 1996-1994 were $7.1
million, $9.0 million and $9.8 million, respectively.
Utilities' future minimum lease payments by year are as follows:
Capital Operating
Year Lease Leases
(in thousands)
1997 $ 16,808 $ 5,601
1998 9,889 5,374
1999 6,969 3,658
2000 3,004 1,654
2001 861 1,329
Thereafter 307 19
37,838 $ 17,635
Less: Amount representing interest 3,113
Present value of net minimum
capital lease payments $ 34,725
(7) INCOME TAXES:
The components of federal and state income taxes for the years
ended December 31, were as follows:
1996 1995 1994
(in millions)
Current tax expense $ 35.3 $ 33.5 $ 38.4
Deferred tax expense 10.4 10.3 2.2
Amortization and adjustment
of investment tax credits (2.6) (2.7) (2.6)
$ 43.1 $ 41.1 $ 38.0
Utilities' overall effective income tax rates shown below for the
years ended December 31, were computed by dividing total income tax
expense by income before income taxes.
1996 1995 1994
Statutory federal income tax rate 35.0% 35.0% 35.0%
State income taxes, net of federal benefits 6.9 5.9 6.1
Effect of rate making on property
related differences 2.9 2.8 1.7
Amortization of investment tax credits (2.5) (2.7) (2.7)
Adjustment of prior period taxes (3.3) (0.1) (1.9)
Other items, net 1.3 - 0.1
Overall effective income tax rate 40.3% 40.9% 38.3%
Utilities' accumulated deferred income taxes as set forth below in
the Consolidated Balance Sheets at December 31, arise from the following
temporary differences:
1996 1995
(in millions)
Property related $ 275 $ 282
Investment tax credit related (24) (26)
Decommissioning related (15) (14)
Other 21 11
$ 257 $ 253
(8) BENEFIT PLANS:
(a) Pension Plans -
Payments made from the pension funds to retired employees and
beneficiaries during 1996 totaled $10.4 million for Utilities.
The components of the pension provision for the years ended
December 31, were as follows:
1996 1995 1994
(in thousands)
Service cost $ 5,439 $ 4,721 $ 5,786
Interest cost on projected benefit
obligation 12,435 11,577 11,265
Assumed return on plans' assets (14,653) (12,340) (12,426)
Early retirement benefits 4,498 - -
Net amortization 885 260 826
Pension cost 8,604 4,218 5,451
Adjustment to funding level (8,604) (4,218) (5,340)
Total pension costs paid to the Trustee $ - $ - $ 111
Actual return on plans' assets $ 25,727 $ 35,947 $ (101)
During 1996, Utilities incurred a one-time charge of $4.5 million
related to an early retirement program. These costs were deferred for
future recovery through the regulatory process.
A reconciliation of the funded status of the plans to the amounts
recognized in Utilities' Consolidated Balance Sheets at December 31, is
presented below:
1996 1995
(in thousands)
Fair market value of plans' assets $ 205,699 $ 191,782
Actuarial present value of benefits
rendered to date -
Accumulated benefits based on compensation
to date, including vested benefits of
$125,983,000 and $117,624,000, respectively 137,772 128,674
Additional benefits based on estimated future
salary levels 41,589 40,790
Projected benefit obligation 179,361 169,464
Plans' assets in excess of projected benefit
obligation 26,338 22,318
Remaining unrecognized net asset existing at
January 1, 1987, being amortized over 20 years (3,124) (3,451)
Unrecognized prior service cost 15,195 16,564
Unrecognized net gain (50,818) (40,707)
Accrued pension cost recognized in the
Consolidated Balance Sheets $ (12,409) $ (5,276)
Assumed rate of return, all plans 9.00% 8.00%
Weighted average discount rate of projected
benefit obligation, all plans 7.50% 7.50%
Assumed rate of increase in future compensation
levels for the plans 4.75% 4.75%
Utilities' employees also participate in defined contribution
pension plans (401(k) plans) covering substantially all employees.
Utilities' contributions to the plans, which are based on the
participants' level of contribution and cannot exceed 2.8% of the
participants' salaries or wages, were $1.5 million, $1.4 million and
$1.6 million in 1996, 1995 and 1994, respectively.
(b) Other Postemployment Benefit Plans -
The components of postretirement benefit costs for the years ended
December 31, were as follows:
1996 1995 1994
(in thousands)
Service cost $ 1,714 $ 1,227 $ 1,785
Interest cost on accumulated postretirement
benefit obligation 3,577 3,049 3,175
Assumed return on plans' assets (388) (56) (60)
Net amortization of transition obligation
and other 1,987 1,822 2,039
Amortized/(deferred) postretirement
benefit costs 1,863 2,220 (2,732)
Costs billed to affiliate - (265) -
Regulatory recognition of incurred cost 49 1,162 -
Net postretirement benefit costs $ 8,802 $ 9,159 $ 4,207
Actual return on plans' assets $ 945 $ 273 $ 47
A reconciliation of the funded status of the plans to the amounts
recognized in Utilities' Consolidated Balance Sheets at December 31, is
presented below:
1996 1995
(in thousands)
Fair market value of plans' assets $ 12,312 $ 6,515
Accumulated postretirement benefit obligation -
Active employees not yet eligible 17,990 20,936
Active employees eligible 4,675 6,148
Retirees 25,300 21,846
Total accumulated postretirement benefit
obligation 47,965 48,930
Accumulated postretirement benefit obligation
in excess of plans' assets (35,653) (42,415)
Unrecognized transition obligation 31,020 34,415
Unrecognized net (gain)/loss (2,571) 268
Unrecognized prior service cost - 151
Accrued postretirement benefit cost in the
Consolidated Balance Sheets $ (7,204) $ (7,581)
Assumed rate of return 9.00% 8.00%
Weighted average discount rate of accumulated
postretirement benefit obligation 7.50% 7.50%
Medical trend on paid charges:
Initial trend rate 9.00% 10.00%
Ultimate trend rate 6.50% 6.50%
The assumed medical trend rates are critical assumptions in
determining the service and interest cost and accumulated postretirement
benefit obligation related to postretirement benefit costs. A 1% change
in the medical trend rates, holding all other assumptions constant,
would have changed the 1996 service and interest cost for Utilities by
$1.1 million (21%) and the accumulated postretirement benefit obligation
for Utilities at December 31, 1996, by $8.1 million (17%).
(11) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS:
Long-Term Debt - The estimated fair value is based upon the market
yield of similar securities and quoted market prices. At December 31,
1996, and December 31, 1995, the carrying amount of Utilities' long-term
debt was $528 million and $483 million, compared to estimated fair
values of $538 million and $507 million, respectively.
(13) COMMITMENTS AND CONTINGENCIES:
(c) Information Technology Services -
Industries entered into an agreement, expiring in 2004, with
Electronic Data Systems Corporation (EDS) for information technology
services. The contract is subject to declining termination fees.
Utilities' anticipated operating and capital expenditures under the
agreement for 1997 are estimated to total approximately $12.1 million.
Future costs under the agreement are variable and are dependent upon
Utilities' level of usage of technological services from EDS.
(d) Financial Guarantees -
Utilities' has financial guarantees amounting to $22.6 million
outstanding at December 31, 1996, which are not reflected in Utilities'
consolidated financial statements. Such guarantees are generally issued
to support third-party borrowing arrangements and similar transactions.
Utilities believes that the likelihood of material cash payments by
Utilities under these agreements is remote.
(15) SEGMENTS OF BUSINESS:
The principal business segments of Utilities are the generation,
transmission, distribution and sale of electric energy and the purchase,
distribution, transportation and sale of natural gas. Certain financial
information relating to Utilities' significant segments of business is
presented below:
Year Ended December 31
1996 1995 1994
(in thousands)
Operating results:
Revenues -
Electric $ 574,273 $ 560,471 $ 537,327
Gas 160,864 137,292 139,033
Operating income -
Electric 132,278 130,390 125,487
Gas 17,088 9,208 8,135
Other information:
Depreciation and amortization -
Electric 77,578 72,487 68,640
Gas 6,200 6,176 6,214
Construction and acquisition expenditures -
Electric 115,929 108,902 120,180
Gas 12,981 9,368 10,066
Assets -
Identifiable assets -
Electric 1,438,370 1,395,666 1,347,024
Gas 205,680 192,045 186,911
1,644,050 1,587,711 1,533,935
Other corporate assets 134,560 120,924 111,433
Total consolidated assets $ 1,778,610 $ 1,708,635 $ 1,645,368
Item 9. Changes and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
PART III
Item 10. Directors, Executive Officers, Promoters and Control Persons
of the Registrant
Information regarding the identification of directors of IES
Industries Inc. and IES Utilities Inc. and compliance with Section 16(a)
reporting requirements of the Securities and Exchange Commission is
included in Industries' definitive proxy statement (Proxy Statement)
prepared for the 1997 annual meeting of stockholders, which will be
filed within 120 days of December 31, 1996, (Proxy Statement under the
captions "Proposal - Nomination and Election of Directors" and "Section
16(a) Beneficial Ownership Reporting Compliance" and is incorporated
herein by reference. The executive officers of the registrants as of
December 31, 1996 are as follows: (Figures following the names
represent the officer's age as of December 31, 1996).
Executive Officers of IES Industries Inc.
Lee Liu, 63, Chairman of the Board & Chief Executive Officer.
First elected officer in 1975.
Larry D. Root, 60, President & Chief Operating Officer. Re-elected
officer in 1996. (i)
James E. Hoffman, 43, Executive Vice President. First elected
officer in 1996. (ii)
Thomas M. Walker, 49, Executive Vice President & Chief Financial
Officer. First elected officer in 1996. (iii)
Peter W. Dietrich, 57, Vice President, Corporate Development.
First elected officer in 1988.
Dean E. Ekstrom, 49, Vice President, Administration. First elected
officer in 1991.
Stephen W. Southwick, 50, Vice President, General Counsel &
Secretary. First elected officer in 1982.
John E. Ebright, 53, Controller & Chief Accounting Officer. First
elected officer in 1996. (iv)
Dennis B. Vass, 47, Treasurer. First elected officer in 1995.
Executive Officers of IES Utilities Inc.
Lee Liu, 63, Chairman of the Board & Chief Executive Officer.
First elected officer in 1975.
Larry D. Root, 60, President & Chief Operating Officer. Re-elected
officer in 1996. (i)
James E. Hoffman, 43, Executive Vice President, Customer Service &
Energy Delivery. First elected officer in 1995. (ii)
Thomas M. Walker, 49, Executive Vice President & Chief Financial
Officer. First elected officer in 1996. (iii)
John F. Franz, Jr., 57, Vice President, Nuclear. First elected
officer in 1992.
Harold W. Rehrauer, 59, Vice President, Field Operations. First
elected officer in 1987.
Stephen W. Southwick, 50, Vice President, General Counsel &
Secretary. First elected officer in 1982.
Philip D. Ward, 56, Vice President, Generation. First elected
officer in 1990.
John E. Ebright, 53, Controller & Chief Accounting Officer. First
elected officer in 1996. (iv)
Dennis B. Vass, 47, Treasurer. First elected officer in 1995.
Officers are elected annually by the Board of Directors and each of
the officers named above, except Larry D. Root, James E. Hoffman, Thomas
M. Walker and John E. Ebright, has been employed by Industries or one of
its significant subsidiaries as an officer or in other responsible
positions at such companies for at least five years. There are no
family relationships among these officers or among the officers and
directors. There are no arrangements or understandings with respect to
election of any person as an officer.
(i) Larry D. Root, who retired in 1995, was re-elected as
President & Chief Operating Officer of both IES Industries
Inc. and IES Utilities Inc. effective November 6, 1996. Mr.
Root was first elected as an officer in 1979.
(ii) James E. Hoffman was elected Executive Vice President of
IES Industries Inc. effective November 6, 1996. Prior to his
appointment as Executive Vice President, Customer Service
& Energy Delivery of IES Utilities Inc. in 1995, he
was employed by MCI Communications as Chief Information
Officer from 1990 to 1995.
(iii) Thomas M. Walker was elected Executive Vice
President & Chief Financial Officer of both IES Industries
Inc. and IES Utilities Inc. effective December 16, 1996.
Prior to joining the Company in December 1996, he was employed
from 1990 - 1995 by Information Resources, Inc. as Executive
Vice President, Chief Financial and Administrative Officer and
Member of the Board of Directors.
(iv) John E. Ebright was elected Controller & Chief Accounting
Officer of both IES Industries Inc. and IES Utilities Inc.
effective July 8, 1996. Prior to joining the Company in July
1996, he was employed by MidCon Corp., a subsidiary of
Occidental Petroleum Corporation, as Vice President and
Controller from 1987 to 1996.
Item 11. Executive Compensation
Information regarding executive compensation and transactions is
included in the Proxy Statement under the captions "Compensation of
Directors", "Summary Compensation Table" and "IES Industries Plans" and
is incorporated herein by reference, except for the "Report of the
Compensation Committee on Executive Compensation" and the "Performance
Graph", which are not incorporated herein by reference. The Proxy
Statement will be filed with the Securities and Exchange Commission
within 120 days of December 31, 1996.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information regarding security ownership of certain beneficial
owners and management is included in the Proxy Statement under the
captions "Security Ownership of Beneficial Owners" and "Security
Ownership of Management" and is incorporated herein by reference. The
Proxy Statement will be filed with the Securities and Exchange
Commission within 120 days of December 31, 1996.
Item 13. Certain Relationships and Related Transactions
Information regarding certain relationships and related
transactions is included in the Proxy Statement under the captions
"Other Transactions" and "Compensation of Directors" and is incorporated
herein by reference. The Proxy Statement will be filed with the
Securities and Exchange Commission within 120 days of December 31, 1996.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K
(a) 1. Financial Statements (Included in Part II of this report) -
Page No.
IES IES
Description Industries Utilities
Inc. Inc.
Report of Independent Public Accountants 44 73
Consolidated Statements of Income
for the years ended December 31, 1996, 1995 and 1994 45 74
Consolidated Statements of Retained Earnings
for the years ended December 31, 1996, 1995 and 1994 45 74
Consolidated Balance Sheets
at December 31, 1996 and 1995 46 - 47 75 - 76
Consolidated Statements of Capitalization
at December 31, 1996 and 1995 48 77
Consolidated Statements of Cash Flows
for the years ended December 31, 1996, 1995 and 1994 49 78
Notes to Consolidated Financial Statements 50 - 72 79 - 84
(a) 2. Financial Statement Schedules (Included in Part IV of
this report) -
Schedule II - Valuation and Qualifying Accounts
and Reserves for the years ended
December 31, 1996, 1995 and 1994 95
Other schedules are omitted as not required under
Rules of Regulation S-X
(a) 3. Exhibits Required by Securities and Exchange Commission
Regulation S-K -
The Exhibits designated by an asterisk are filed herewith and all other
Exhibits as stated to be filed are incorporated herein by reference.
Exhibit
2(a) Agreement and Plan of Merger, dated as of November
10, 1995, as amended, by and among WPL Holdings, Inc., IES
Industries Inc., Interstate Power Company, WPLH Acquisition Co.
and Interstate Power Company (Filed as Exhibit 2.1 to Industries'
Joint Proxy Statement, dated July 11, 1996).
2(b) Amendment No. 2 to Agreement and Plan of Merger,
as amended, dated August 16, 1996, by and among IES Industries
Inc., WPL Holdings, Inc., Interstate Power Company, WPLH
Acquisition Co. and Interstate Power Company (Filed as Annex 1 to
the Supplement to the Joint Proxy Statement of WPL Holdings,
Inc., IES Industries Inc. and Interstate Power Company, dated
August 21, 1996).
2(c) Option Grantor/Option Holder Stock Option and Trigger Payment
Agreement, dated as of November 10, 1995, by and among
WPL Holdings, Inc. and IES Industries Inc. (Filed as Exhibit
2.2 to Industries' Current Report on Form 8-K, dated
November 10, 1995).
2(d) Option Grantor/Option Holder Stock Option and Trigger
Payment Agreement, dated as of November 10, 1995,
by and among WPL Holdings, Inc. and Interstate
Power Company. (Filed as Exhibit 2.3 to Industries'
Current Report on Form 8-K, dated November 10, 1995).
2(e) Option Grantor/Option Holder Stock Option and
Trigger Payment Agreement, dated as of November
10, 1995, by and among IES Industries Inc. and
WPL Holdings, Inc. (Filed as Exhibit 2.4 to Industries'
Current Report on Form 8-K, dated November 10, 1995).
2(f) Option Grantor/Option Holder Stock Option and Trigger
Payment Agreement, dated as of November 10, 1995,
by and among IES Industries Inc. and Interstate Power
Company. (Filed as Exhibit 2.5 to Industries' Current
Report on Form 8-K, dated November 10, 1995).
2(g) Option Grantor/Option Holder Stock Option and Trigger
Payment Agreement, dated as of November 10, 1995,
by and among Interstate Power Company and WPL
Holdings, Inc. (Filed as Exhibit 2.6 to Industries'
Current Report on Form 8-K, dated November 10, 1995).
2(h) Option Grantor/Option Holder Stock Option and Trigger
Payment Agreement, dated as of November 10, 1995,
by and among Interstate Power Company and IES
Industries Inc. (Filed as Exhibit 2.7 to Industries'
Current Report on Form 8-K, dated November 10, 1995).
3(a) Articles of Incorporation of IES Industries Inc.
(Industries), Amended and Restated as of May 4, 1993 (Filed as
Exhibit 3(a) to Industries' Form 10-K for the year 1993).
3(b) Articles of Incorporation of IES Utilities Inc.
(Utilities), Amended and Restated as of January 6, 1994 (Filed as
Exhibit 4(b) to Utilities' Current Report on Form 8-K, dated
January 7, 1994).
* 3(c) Bylaws of Industries, as amended February 4, 1997.
* 3(d) Bylaws of Utilities, as amended February 4, 1997.
4(a) Indenture of Mortgage and Deed of Trust, dated as
of September 1, 1993, between Utilities (formerly Iowa Electric
Light and Power Company (IE)) and The First National Bank of
Chicago, as Trustee (Mortgage) (Filed as Exhibit 4(c) to IE's
Form 10-Q for the quarter ended September 30, 1993).
4(b) Supplemental Indentures to the Mortgage:
Number Dated as of IE/Utilities File Reference Exhibit
First October 1, 1993 Form 10-Q, 11/12/93 4(d)
Second November 1, 1993 Form 10-Q, 11/12/93 4(e)
Third March 1, 1995 Form 10-Q, 5/12/95 4(b)
Fourth September 1, 1996 Form 8-K, 9/19/96 4(c)(i)
4(c) Indenture of Mortgage and Deed of Trust, dated as
of August 1, 1940, between Utilities (formerly IE) and The First
National Bank of Chicago, Trustee (1940 Indenture) (Filed as
Exhibit 2(a) to IE's Registration Statement, File No. 2-25347).
4(d) Supplemental Indentures to the 1940 Indenture:
Number Dated as of IE/Utiliites File Reference Exhibit
First March 1, 1941 2-25347 2(a)
Second July 15, 1942 2-25347 2(a)
Third August 2, 1943 2-25347 2(a)
Fourth August 10, 1944 2-25347 2(a)
Fifth November 10, 1944 2-25347 2(a)
Sixth August 8, 1945 2-25347 2(a)
Seventh July 1, 1946 2-25347 2(a)
Eighth July 1, 1947 2-25347 2(a)
Ninth December 15, 1948 2-25347 2(a)
Tenth November 1, 1949 2-25347 2(a)
Eleventh November 10, 1950 2-25347 2(a)
Twelfth October 1, 1951 2-25347 2(a)
Thirteenth March 1, 1952 2-25347 2(a)
Fourteenth November 5, 1952 2-25347 2(a)
Fifteenth February 1, 1953 2-25347 2(a)
Sixteenth May 1, 1953 2-25347 2(a)
Seventeenth November 3, 1953 2-25347 2(a)
Eighteenth November 8, 1954 2-25347 2(a)
Nineteenth January 1, 1955 2-25347 2(a)
Twentieth November 1, 1955 2-25347 2(a)
Twenty-first November 9, 1956 2-25347 2(a)
Twenty-second November 6, 1957 2-25347 2(a)
Twenty-third November 4, 1958 2-25347 2(a)
Twenty-fourth November 3, 1959 2-25347 2(a)
Twenty-fifth November 1, 1960 2-25347 2(a)
Twenty-sixth January 1, 1961 2-25347 2(a)
Twenty-seventh November 7, 1961 2-25347 2(a)
Twenty-eighth November 6, 1962 2-25347 2(a)
Twenty-ninth November 5, 1963 2-25347 2(a)
Thirtieth November 4, 1964 2-25347 2(a)
Thirty-first November 2, 1965 2-25347 2(a)
Thirty-second September 1, 1966 Form 10-K, 1966 4.10
Thirty-third November 30, 1966 Form 10-K, 1966 4.10
Thirty-fourth November 7, 1967 Form 10-K, 1967 4.10
Thirty-fifth November 5, 1968 Form 10-K, 1968 4.10
Thirty-sixth November 1, 1969 Form 10-K, 1969 4.10
Thirty-seventh December 1, 1970 Form 8-K, 12/70 1
Thirty-eighth November 2, 1971 2-43131 2(g)
Thirty-ninth May 1, 1972 Form 8-K, 5/72 1
Fortieth November 7, 1972 2-56078 2(i)
Forty-first November 7, 1973 2-56078 2(j)
Forty-second September 10, 1974 2-56078 2(k)
Forty-third November 5, 1975 2-56078 2(l)
Forty-fourth July 1, 1976 Form 8-K, 7/76 1
Forty-fifth November 1, 1976 Form 8-K, 12/76 1
Forty-sixth December 1, 1977 2-60040 2(o)
Forty-seventh November 1, 1978 Form 10-Q, 6/30/79 1
Forty-eighth December 1, 1979 Form S-16, 2-65996 2(q)
Forty-ninth November 1, 1981 Form 10-Q, 3/31/82 2
Fiftieth December 1, 1980 Form 10-K, 1981 4(s)
Fifty-first December 1, 1982 Form 10-K, 1982 4(t)
Fifty-second December 1, 1983 Form 10-K, 1983 4(u)
Fifty-third December 1, 1984 Form 10-K, 1984 4(v)
Fifty-fourth March 1, 1985 Form 10-K, 1984 4(w)
Fifty-fifth March 1, 1988 Form 10-Q, 5/12/88 4(b)
Fifty-sixth October 1, 1988 Form 10-Q, 11/10/88 4(c)
Fifty-seventh May 1, 1991 Form 10-Q, 8/13/91 4(d)
Fifty-eighth March 1, 1992 Form 10-K, 1991 4(c)
Fifty-ninth October 1, 1993 Form 10-Q, 11/12/93 4(a)
Sixtieth November 1, 1993 Form 10-Q, 11/12/93 4(b)
Sixty-first March 1, 1995 Form 10-Q, 5/12/95 4(a)
Sixty-second September 1, 1996 Form 8-K, 9/19/96 4(f)
4(e) Indenture or Deed of Trust dated as of February 1,
1923, between Utilities (successor to Iowa Southern Utilities
Company (IS) as result of merger of IS and IE) and The Northern
Trust Company (The First National Bank of Chicago, successor) and
Harold H. Rockwell (Richard D. Manella, successor), as Trustees
(1923 Indenture) (Filed as Exhibit B-1 to File No. 2-1719).
4(f) Supplemental Indentures to the 1923 Indenture:
Dated as of File Reference Exhibit
May 1, 1940 2-4921 B-1-k
May 2, 1940 2-4921 B-1-l
October 1, 1945 2-8053 7(m)
October 2, 1945 2-8053 7(n)
January 1, 1948 2-8053 7(o)
September 1, 1950 33-3995 4(e)
February 1, 1953 2-10543 4(b)
October 2, 1953 2-10543 4(q)
August 1, 1957 2-13496 2(b)
September 1, 1962 2-20667 2(b)
June 1, 1967 2-26478 2(b)
February 1, 1973 2-46530 2(b)
February 1, 1975 2-53860 2(aa)
July 1, 1975 2-54285 2(bb)
September 2, 1975 2-57510 2(bb)
March 10, 1976 2-57510 2(cc)
February 1, 1977 2-60276 2(ee)
January 1, 1978 0-849 2
March 1, 1979 0-849 2
March 1, 1980 0-849 2
May 31, 1986 33-3995 4(g)
July 1, 1991 0-849 4(h)
September 1, 1992 0-849 4(m)
December 1, 1994 0-4117-1 4(f)
* 4(g) Third Amended and Restated Credit Agreement dated
as of November 20, 1996 among IES Diversified Inc. as Borrower,
certain banks and Citibank, N.A., as Agent.
4(h) Indenture (For Unsecured Subordinated Debt
Securities), dated as of December 1, 1995, between Utilities and
The First National Bank of Chicago, as Trustee (Subordinated
Indenture) (Filed as Exhibit 4(i) to Utilities' Amendment No. 1
to Registration Statement, File No. 33-62259).
10(a) Operating and Transmission Agreement between
Central Iowa Power Cooperative and IE (Filed as Exhibit 10(q) to
IE's Form 10-K for the year 1990).
10(b) Duane Arnold Energy Center Ownership Participation
Agreement dated June 1, 1970 between Central Iowa Power
Cooperative, Corn Belt Power Cooperative and IE. (Filed as
Exhibit 5(kk) to IE's Registration Statement, File No. 2-38674).
10(c) Duane Arnold Energy Center Operating Agreement
dated June 1, 1970 between Central Iowa Power Cooperative, Corn
Belt Power Cooperative and IE. (Filed as Exhibit 5(ll) to IE's
Registration Statement, File No. 2-38674).
10(d) Duane Arnold Energy Center Agreement for
Transmission, Transformation, Switching, and Related Facilities
dated June 1, 1970 between Central Iowa Power Cooperative, Corn
Belt Power Cooperative and IE. (Filed as Exhibit 5(mm) to IE's
Registration Statement, File No. 2-38674).
10(e) Basic Generating Agreement dated April 16, 1975
between Iowa Public Service Company, Iowa Power and Light
Company, Iowa-Illinois Gas and Electric Company and IS for the
joint ownership of Ottumwa Generating Station-Unit 1 (OGS-1).
(Filed as Exhibit 1 to IE's Form 10-K for the year 1977).
10(f) Addendum Agreement to the Basic Generating
Agreement for OGS-1 dated December 7, 1977 between Iowa Public
Service Company, Iowa-Illinois Gas and Electric Company, Iowa
Power and Light Company, IS and IE for the purchase of 15%
ownership in OGS-1. (Filed as Exhibit 3 to IE's Form 10-K for
the year 1977).
10(g) Second Amended and Restated Credit Agreement dated
as of September 17, 1987 between Arnold Fuel, Inc. and the First
National Bank of Chicago and the Amended and Restated Consent and
Agreement dated as of September 17, 1987 by IE. (Filed as
Exhibit 10(j) to IE's Form 10-K for the year 1987).
Management Contracts and/or Compensatory Plans (Exhibits 10(h) through 10(s))
10(h) Supplemental Retirement Plan. (Filed as Exhibit
10(l) to Industries' Form 10-K for the year 1987).
10(i) Management Incentive Compensation Plan. (Filed as
Exhibit 10(m) to Industries' Form 10-K for the year 1987).
10(j) Key Employee Deferred Compensation Plan. (Filed
as Exhibit 10(n) to Industries' Form 10-K for the year 1987).
10(k) Long-Term Incentive Plan. (Filed as Exhibit A to
Industries' Proxy Statement dated March 20, 1995).
10(l) Executive Guaranty Plan. (Filed as Exhibit 10(p)
to Industries' Form 10-K for the year 1987).
10(m) Executive Change of Control Severance Agreement -
CEO (Filed as Exhibit 10(a) to Industries' Form 10-Q for the
quarter ended September 30, 1996 (File No. 1-9187)).
10(n) Executive Change of Control Severance Agreement -
Vice Presidents (Filed as Exhibit 10(b) to Industries' Form 10-Q
for the quarter ended September 30, 1996 (File No. 1-9187)).
10(o) Executive Change of Control Severance Agreement -
Other Officers (Filed as Exhibit 10(c) to Industries' Form 10-Q
for the quarter ended September 30, 1996 (File No. 1-9187)).
10(p) Amendments to Key Employee Deferred Compensation
Agreement for Directors. (Filed as Exhibit 10(u) to Industries'
Form 10-Q for the quarter ended March 31, 1990).
10(q) Amendments to Key Employee Deferred Compensation
Agreement for Key Employees. (Filed as Exhibit 10(v) to
Industries' Form 10-Q for the quarter ended March 31, 1990).
10(r) Amendments to Management Incentive Compensation
Plan. (Filed as Exhibit 10(y) to Industries' Form 10-Q for the
quarter ended March 31, 1990).
*10(s) Director Retirement Plan.
10(t) Agreement and Plan of Merger, dated as of February
27, 1991, by and between IE Industries Inc. and Iowa Southern
Inc. (Filed as Exhibit 2 to Industries' Form 8-K dated
February 27, 1991).
10(u) IES Industries Inc. Shareholders' Rights Plan.
(Filed as Exhibit I-2 to Industries' Registration Statement on
Form 8-A filed November 13, 1991).
10(v) Lease and Security Agreement, dated
October 1, 1993, between IES Diversified Inc., as lessee, and
Sumitomo Bank Leasing and Finance, Inc., as lessor. (Filed as
Exhibit 10(z) to Industries' Form 10-K for the year 1993).
10(w) Receivables Purchase and Sale Agreement dated as of June 30,
1989, as Amended and Restated as of April 15, 1994, among IES
Utilities Inc. (as Seller) and CIESCO L.P. (as the Investor) and
Citicorp North America, Inc. (as Agent). (Filed as Exhibit 10(a)
to Utilities' Form 10-Q for the quarter ended March 31, 1994
(File No. 0-4117-1)).
10(x) Guaranty (IES Utilities Trust No. 1994-A) from IES Utilities
Inc., dated as of June 29, 1994. (Filed as Exhibit 10(b) to
Utilities' Form 10-Q for the quarter ended June 30, 1994 (File
No. 0-4117-1)).
10(y) Copy of Coal Supply Agreement, dated July 27,
1977, between IS and Sunoco Energy Development Co. (former parent
of Cordero Mining Co.), and letter memorandum thereto, dated
October 29, 1984, relating to the purchase of coal supplies for
the fuel requirements at the Ottumwa Generating Station. (Filed
as Exhibit 10-A-4 to File No. 33-3995).
*12 Ratio of Earnings to Fixed Charges (IES Utilities Inc.)
*21 Subsidiaries of the Registrant (IES Industries Inc.)
*23(a) Consent of Independent Public Accountants (IES Industries Inc.)
*23(b) Consent of Independent Public Accountants (IES Utilities Inc.)
*27(a) Financial Data Schedule (IES Industries Inc.)
*27(b) Financial Data Schedule (IES Utilities Inc.)
Note: Pursuant to (b)(4)(iii)(A) of Item 601 of Regulation
S-K, the Company has not filed as an exhibit to this Form 10-K
certain instruments with respect to long-term debt that has not
been registered if the total amount of securities authorized
thereunder does not exceed 10% of total assets of the Company but
hereby agrees to furnish to the Commission on request any such
instruments.
(a) 4. Unaudited Pro Forma Combined Financial Information of
Interstate Energy Corporation:
Unaudited Pro Forma Combined Balance Sheet at
December 31, 1996 97 - 98
Unaudited Pro Forma Combined Statements of Income
for the years ended December 31, 1996, 1995 and 1994 99 - 101
Notes to Unaudited Pro Forma Combined
Financial Statements 102 - 104
(b) Reports on Form 8-K -
Industries - None.
Utilities - None.
IES INDUSTRIES INC. AND IES UTILITIES INC.
SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
Column A Column B Column E
Balance Balance
Description January 1 December 31
(in thousands)
VALUATION AND QUALIFYING ACCOUNTS WHICH ARE DEDUCTED IN THE BALANCE SHEET
FROM THE ASSETS TO WHICH THEY APPLY:
IES Utilities Inc.:
Accumulated Provision for Uncollectible Accounts:
Year ended December 31, 1996 $ 676 $ 757
Year ended December 31, 1995 $ 650 $ 676
Year ended December 31, 1994 $ 409 $ 650
Non-utility Subsidiaries:
Accumulated Provision for Uncollectible Accounts:
Year ended December 31, 1996 $ 685 $ 774
Year ended December 31, 1995 $ 372 $ 685
Year ended December 31, 1994 $ 506 $ 372
Note: The above provisions relate to various customer, notes and other
receivable balances included in several line items on the Company's
Consolidated Balance Sheets.
OTHER RESERVES:
IES Utilities Inc.:
Accumulated Provision for Rate Refunds
Year ended December 31, 1996 $ 106 $ -
Year ended December 31, 1995 $ - $ 106
Year ended December 31, 1994 $ 8,670 $ -
IES Utilities Inc.:
Accumulated Provision for Merchandise Warranty, Property
Insurance, Injuries and Damages, Workmen's Compensation
and Other Miscellaneous Claims
Year ended December 31, 1996 $ 2,876 $ 2,694
Year ended December 31, 1995 $ 2,516 $ 2,876
Year ended December 31, 1994 $ 1,611 $ 2,516
UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION
OF INTERSTATE ENERGY CORPORATION
IES Industries Inc. (IES), WPL Holdings, Inc. (WPLH), Interstate Power
Company (IPC), and certain related parties have entered into an
Agreement and Plan of Merger, dated as of November 10, 1995, as amended
(the Merger Agreement), providing for (a) the merger of IES with and
into WPLH and (b) the merger of IPC with a subsidiary of WPLH pursuant
to which IPC will become a subsidiary of WPLH (the above referenced
mergers are collectively referred herein to as the Mergers). In
connection with the consummation of the Mergers, WPLH will change its
name to Interstate Energy Corporation. Detailed information with
respect to the Merger Agreement and the proposed Mergers is contained in
the Joint Proxy Statement/Prospectus, dated July 11, 1996, as
supplemented by the Supplement to Joint Proxy Statement/Prospectus,
dated August 21, 1996, contained in WPLH's Registration Statements on
Form S-4, Registration Nos. 333-07931 and 333-10401 relating to the
meetings of shareowners of WPLH, IES and IPC to vote on the Merger
Agreement and related matters.
The following unaudited pro forma financial information combines the
historical consolidated balance sheets and statements of income of WPLH,
IES and IPC, including their respective subsidiaries, after giving
effect to the Mergers. The historical data for WPLH have been adjusted
to reflect the restatement of such data to account for certain
discontinued operations discussed in the notes hereto. The unaudited
pro forma combined balance sheet at December 31, 1996 gives effect to
the Mergers as if they had occurred at December 31, 1996. The unaudited
pro forma combined statements of income for each of the three years in
the period ended December 31, 1996 give effect to the Mergers as if they
had occurred at January 1, 1994. These statements are prepared on the
basis of accounting for the Mergers as a pooling of interests and are
based on the assumptions set forth in the notes thereto. In addition,
the pro forma financial information does not give effect to the expected
synergies or the cost to be incurred to achieve such synergies. The pro
forma financial information, however, does reflect the transaction costs
to effect the Mergers.
The following pro forma financial information has been prepared from,
and should be read in conjunction with, the historical consolidated
financial statements and related notes thereto of WPLH, IES and IPC.
The following information is not necessarily indicative of the financial
position or operating results that would have occurred had the Mergers
been consummated on the date, or at the beginning of the periods, for
which the Mergers are being given effect nor is it necessarily
indicative of future operating results or financial position.
INTERSTATE ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED BALANCE SHEET
December 31, 1996
(In thousands)
ASSETS WPLH IES IPC Pro Forma Pro Forma
(As Reported) (As Reported) (As Reported) Adjustments Combined
UTILITY PLANT
Electric $ 1,729,311 $ 2,007,839 $ 853,007 $ ---- $ 4,590,157
Gas 227,809 175,472 68,047 ---- 471,328
Other 175,998 126,850 --- ---- 302,848
Total 2,133,118 2,310,161 921,054 ---- 5,364,333
Less: Accumulated provision for depreciation 967,436 1,030,390 426,471 ---- 2,424,297
Construction work in progress 55,519 43,719 3,129 ---- 102,367
Nuclear fuel--net 19,368 34,725 --- ---- 54,093
Net utility plant 1,240,569 1,358,215 497,712 ---- 3,096,496
OTHER PROPERTY, PLANT AND EQUIPMENT
---NET AND INVESTMENTS (NOTE 8) 144,671 314,071 453 ---- 459,195
CURRENT ASSETS
Cash and cash equivalents 11,070 8,675 3,072 ---- 22,817
Accounts receivable ---net 88,798 62,861 28,227 ---- 179,886
Fossil fuel inventories, at average cost 15,841 13,323 16,623 ---- 45,787
Materials and supplies, at average cost 29,907 22,842 6,214 ---- 58,963
Prepayments and other 26,786 70,350 13,497 ---- 110,633
Total current assets 172,402 178,051 67,633 ---- 418,086
EXTERNAL DECOMMISSIONING FUND 90,671 59,325 --- ---- 149,996
DEFERRED CHARGES AND OTHER 252,218 215,900 73,402 ---- 541,520
TOTAL ASSETS $ 1,900,531 $ 2,125,562 $ 639,200 $ ---- $ 4,665,293
See accompanying Notes to Unaudited Pro Forma Combined Financial Statements
INTERSTATE ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED BALANCE SHEET (Continued)
December 31, 1996
(In thousands)
LIABILITIES AND EQUITY WPLH IES IPC Pro Forma Pro Forma
(As Reported) (As Reported) (As Reported) Adjustments Combined
CAPITALIZATION
Common Stock Equity:
Common Stock (Note 1) $ 308 $ 407,635 $ 33,848 $ -441,033 $ 758
Other stockholders' equity (Note 1) 607,047 219,246 172,210 430,033 1,428,536
Total common stock equity 607,355 626,881 206,058 -11,000 1,429,294
Preferred stock not mandatorily redeemable 59,963 18,320 10,819 ---- 89,102
Preferred stock mandatory sinking fund ---- ---- 24,147 ---- 24,147
Long-term debt ---net 362,564 701,100 171,731 ---- 1,235,395
Total capitalization 1,029,882 1,346,301 412,755 -11,000 2,777,938
CURRENT LIABILITIES
Current maturities, sinking funds, and
capital lease obligations 67,626 23,598 17,000 ---- 108,224
Commercial paper, notes payable and other 102,779 135,000 28,700 ---- 266,479
Variable rate demand bonds 56,975 ---- ---- ---- 56,975
Accounts payable and accruals 120,986 99,861 14,013 ---- 234,860
Taxes accrued 4,669 43,926 16,953 ---- 65,548
Other accrued liabilities 54,303 54,498 11,785 11,000 131,586
Total current liabilities 407,338 356,883 88,451 11,000 863,672
OTHER LIABILITIES
Deferred income taxes 245,686 262,675 99,303 ---- 607,664
Deferred investment tax credits 36,931 34,470 17,013 ---- 88,414
Accrued environmental remediation costs 74,075 47,502 7,234 ---- 128,811
Capital lease obligations ---- 19,600 ---- ---- 19,600
Other liabilities and deferred credits 106,619 58,131 14,444 ---- 179,194
Total other liabilities 463,311 422,378 137,994 ---- 1,023,683
TOTAL CAPITALIZATION AND LIABILITIES $ 1,900,531 $ 2,125,562 $ 639,200 $ ---- $ 4,665,293
See accompanying Notes to Unaudited Pro Forma Combined Financial Statements
INTERSTATE ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, 1996
(In thousands, except per share amounts)
WPLH IES IPC Pro Forma Pro Forma
(As Reported) (As Reported) (As Reported) Adjustments Combined
Operating Revenues
Electric $ 589,482 $ 574,273 $ 276,620 $ ----- $ 1,440,375
Gas 165,627 273,979 49,464 ----- 489,070
Other 177,735 125,660 ----- ----- 303,395
Total operating revenues 932,844 973,912 326,084 ----- 2,232,840
Operating Expenses
Electric production fuels 114,470 84,579 57,560 ----- 256,609
Purchased power 81,108 88,350 61,556 ----- 231,014
Cost of gas sold 104,830 217,351 31,617 ----- 353,798
Other operation 319,154 214,759 53,134 ----- 587,047
Maintenance 46,492 49,001 16,164 ----- 111,657
Depreciation and amortization 90,683 107,393 31,087 ----- 229,163
Taxes other than income
taxes 34,603 48,171 16,064 ----- 98,838
Total operating expenses 791,340 809,604 267,182 ----- 1,868,126
Operating Income 141,504 164,308 58,902 ----- 364,714
Other Income (Expense)
Allowance for equity funds
used during construction 2,270 -100 13 ----- 2,183
Other income and
deductions ---net 15,644 -2,333 3,763 ----- 17,074
Total other income (expense) 17,914 -2,433 3,776 ----- 19,257
Interest Charges 41,089 52,619 16,222 ----- 109,930
Income from continuing
operations before income taxes
and preferred dividends 118,329 109,256 46,456 ----- 274,041
Income Taxes 41,814 47,435 18,133 ----- 107,382
Preferred dividends of
subsidiaries (Note 2) 3,310 914 2,463 ----- 6,687
Income from continuing
Operations (Notes 3 and 6) $ 73,205 $ 60,907 $ 25,860 $ ----- $ 159,972
Average Common Shares
Outstanding (Note 1) 30,790 29,861 9,594 5,236 75,481
Earnings per share of Common
Stock from continuing
operations $ 2.38 $ 2.04 $ 2.69 $ ---- $ 2.12
See accompanying Notes to Unaudited Pro Forma Combined Financial Statements
INTERSTATE ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, 1995
(In thousands, except per share amounts)
WPLH IES IPC Pro Forma Pro Forma
(As Reported) (As Reported) (As Reported) Adjustments Combined
Operating Revenues
Electric $ 546,324 $ 560,471 $ 274,873 $ ---- $ 1,381,668
Gas 139,165 190,339 43,669 ---- 373,173
Other 121,766 100,200 ---- ---- 221,966
Total operating revenues 807,255 851,010 318,542 ---- 1,976,807
Operating Expenses
Electric production fuels 116,488 96,256 62,164 ---- 274,908
Purchased power 44,940 66,874 57,566 ---- 169,380
Cost of gas sold 84,002 141,716 25,888 ---- 251,606
Other operation 253,277 201,390 45,717 ---- 500,384
Maintenance 42,043 46,093 14,881 ---- 103,017
Depreciation and amortization 86,319 97,958 29,560 ---- 213,837
Taxes other than income
taxes 34,188 49,011 15,990 ---- 99,189
Total operating expenses 661,257 699,298 251,766 ---- 1,612,321
Operating Income 145,998 151,712 66,776 ---- 364,486
Other Income (Expense)
Allowance for equity funds
used during construction 1,425 386 ---- ---- 1,811
Other income and
deductions ---net 6,509 3,170 -2,872 ---- 6,807
Total other income (expense) 7,934 3,556 -2,872 ---- 8,618
Interest Charges 42,896 47,689 16,795 ---- 107,380
Income from continuing
operations before income taxes
and preferred dividends 111,036 107,579 47,109 ---- 265,724
Income Taxes 36,108 42,489 19,453 ---- 98,050
Preferred dividends of
subsidiaries (Note 2) 3,310 914 2,458 ---- 6,682
Income from continuing
Operations (Notes 3 and 6) $ 71,618 $ 64,176 $ 25,198 $ ---- $ 160,992
Average Common Shares
Outstanding (Note 1) 30,774 29,202 9,564 5,140 74,680
Earnings per share of Common
Stock from continuing
operations $ 2.33 $ 2.20 $ 2.63 $ ---- $ 2.16
See accompanying Notes to Unaudited Pro Forma Combined Financial Statements
INTERSTATE ENERGY CORPORATION
UNAUDITED PRO FORMA COMBINED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, 1994
(In thousands, except per share amounts)
WPLH IES IPC Pro Forma Pro Forma
(As Reported) (As Reported) (As Reported) Adjustments Combined
Operating Revenues
Electric $ 531,747 $ 537,327 $ 261,730 $ ----- $ 1,330,804
Gas 151,931 165,569 45,920 ----- 363,420
Other 112,039 82,968 ---- ----- 195,007
Total operating revenues 795,717 785,864 307,650 ----- 1,889,231
Operating Expenses
Electric production fuels 123,469 85,952 61,384 ----- 270,805
Purchased power 37,913 68,794 58,339 ----- 165,046
Cost of gas sold 100,942 120,795 30,905 ----- 252,642
Other operation 248,847 176,863 51,917 ----- 477,627
Maintenance 41,227 52,841 17,160 ----- 111,228
Depreciation and amortization 80,351 86,378 28,212 ----- 194,941
Taxes other than income
taxes 33,788 46,308 16,298 ----- 96,394
Total operating expenses 666,537 637,931 264,215 ----- 1,568,683
Operating Income 129,180 147,933 43,435 ----- 320,548
Other Income (Expense)
Allowance for equity funds
used during construction 3,009 2,299 166 ----- 5,474
Other income and
deductions ---net 10,245 3,472 3,100 ----- 16,817
Total other income (expense) 13,254 5,771 3,266 ----- 22,291
Interest Charges 36,657 44,399 16,845 ----- 97,901
Income from continuing
operations before income taxes
and preferred dividends 105,777 109,305 29,856 ----- 244,938
Income Taxes 36,043 41,573 9,189 ----- 86,805
Preferred dividends of
subsidiaries (Note 2) 3,310 914 2,454 ---- 6,678
Income from continuing
Operations (Notes 3 and 6) $ 66,424 $ 66,818 $ 18,213 $ ---- $ 151,455
Average Common Shares
Outstanding (Note 1) 30,671 28,560 9,479 5,041 73,751
Earnings per share of Common
Stock from continuing
operations $ 2.17 $ 2.34 $ 1.92 $ ---- $ 2.05
See accompanying Notes to Unaudited Pro Forma Combined Financial Statements
INTERSTATE ENERGY CORPORATION
NOTES TO UNAUDITED PRO FORMA
COMBINED FINANCIAL STATEMENTS
1. The pro forma combined financial statements reflect the
conversion of each share of IES Common Stock (no par value) outstanding
into 1.14 shares of WPLH Common Stock ($.01 par value) and the
conversion of each share of IPC Common Stock ($3.50 par value) into
1.11 shares of WPLH Common Stock ($.01 par value), and the continuation
of each share of WPLH Common Stock ($.01 par value) outstanding as one
share of Interstate Energy Common Stock, as provided in the Merger
Agreement. The pro forma adjustment to common stock equity restates
the common stock account to equal par value for all shares to be issued
($.01 par value per share of Interstate Energy Common Stock) and
reclassifies the excess to other stockholders' equity. The pro forma
combined statements of income are presented as if the companies were
combined on January 1, 1994. The pro forma combined balance sheet
gives effect to the Mergers as if they occurred at December 31, 1996.
The number of shares of common stock used for calculating per share
amounts is based on the exchange ratio shown below.
Exchange As reported Pro forma As reported Pro forma As reported Pro forma
Ratio 12/31/96 12/31/96 12/31/95 12/31/95 12/31/94 12/31/94
IES___ 1.14 29,861 34,042 29,202 33,290 28,560 32,558
IPC___ 1.11 9,594 10,649 9,564 10,616 9,479 10,522
WPLH__ N/A 30,790 30,790 30,774 30,774 30,671 30,671
2. The Preferred Stock of IPC has been reclassified in the pro forma
statements as preferred stock of subsidiary companies and deducted in
the determination of income from continuing operations which reflects
the holding company structure of the entity formed through the
Mergers.
3. IES's income from continuing operations for the year ended December
31, 1996 included costs incurred relating to its successful defense of
a hostile takeover attempt mounted by MidAmerican Energy Company. The
after-tax impact on income from continuing operations was a decrease
of $4.6 million.
Nonrecurring items affecting WPLH's performance for the year ended
December 31, 1996 included the impact of the sale of a combustion
turbine and the sale of WPLH's assisted-living real estate
investments. The after-tax impact of these items on continuing
operations was an increase of $5.9 million. Nonrecurring items
affecting WPLH's 1994 performance included the impact of early
retirement and severance programs and the reversal of a coal contract
penalty assessed by the Public Service Commission of Wisconsin which was
charged to income in 1989. The net after-tax impact of these items on
income from continuing operations for the year ended December 31, 1994
was a decrease of $8.3 million related to the early retirement and
severance programs offset by an increase of $4.9 million related to
the coal contract penalty reversal.
4. The allocation between WPLH, IES and IPC and their customers of the
estimated cost savings of approximately $749 million over ten years
resulting from the Mergers, net of the costs incurred to achieve such
savings, will be subject to regulatory review and approval. Costs
arising from the proposed Mergers are currently estimated to be
approximately $78 million (including transaction costs of $11 million
related to fees for financial advisors, attorneys, accountants and
consultants). The estimate of potential cost savings constitutes a
forward-looking statement and actual results may differ materially from
this estimate. The estimate is necessarily based upon various
assumptions that involve judgments with respect to, among other things,
future national and regional economic and competitive conditions,
technological developments, inflation rates, regulatory treatments,
weather conditions, financial market conditions, future business
decisions and other uncertainties. No assurance can be given that the
estimated costs savings will actually be realized.
In addition to the $11 million of remaining transaction costs, since
the announcement of the Merger Agreement on November 11, 1995, IES,
IPC and WPLH have collectively incurred $6 million of merger-related
transaction costs through December 31, 1996, which have been expensed
and are reflected in the combined income statements as presented. The
remaining $11 million of transaction costs have been reflected in the
pro forma balance sheet at December 31, 1996 such that shareowners'
equity has been reduced by $11 million and accrued liabilities have
been increased by $11 million. None of the estimated cost savings,
or costs to achieve such savings, have been reflected in the pro forma
combined financial statements.
5. Intercompany transactions (including purchased and exchange power
transactions) between WPLH, IES and IPC during the periods presented
were included in the determination of regulated rates and were not
material. Accordingly, no pro forma adjustments were made to eliminate
such transactions.
6. The financial statements of WPLH reflect the discontinuance of
operations of its utility energy and marketing consulting business in
1995. The discontinuance of this business resulted in a pre-tax loss
in the fourth quarter of 1995 of $7.7 million. The after-tax loss on
disposition was $11.0 million reflecting the associated tax expense on
disposition due to the non-deductibility of the carrying value of
goodwill at sale. During 1996, WPLH recognized an additional loss of
$1.3 million, net of applicable income tax benefit, associated with the
final disposition of the business. Operating revenues, operating
expenses, other income and expense and income taxes for the
discontinued operations for the time periods presented have been
excluded from income from continuing operations. Interest expense has
been adjusted for the amounts associated with direct obligations of the
discontinued operations.
Operating revenues, related losses, and income tax benefits associated
with the discontinued operations for the years ending December 31 were
as follows:
1995 1994
Operating revenues $ 24,979 $ 34,798
Loss from discontinued operations before income tax $ 3,663 $ 1,806
Income tax benefit 1,451 632
Loss from discontinued operations $ 2,212 $ 1,174
7. Accounting principles have been consistently applied in the
financial statement presentations for WPLH, IES and IPC with one
exception. IPC does not include unbilled electric and gas revenues in
its calculation of total revenues. The utility subsidiaries of WPLH and
IES accrue unbilled revenues. The impact of this difference in
accounting principles among the companies does not have a material
impact on the unaudited pro forma combined financial statements as
presented and, accordingly, no adjustments have been made to conform
accounting principles.
8. At December 31, 1996, IES had a $20.0 million investment in Class A
common stock of McLeod, Inc. (McLeod), a $9.2 million investment in
Class B common stock and vested options that, if exercised, would
represent an additional investment of approximately $2.3 million.
McLeod provides local, long-distance and other telecommunications
services.
McLeod completed an Initial Public Offering (IPO) of its Class A common
stock in June 1996 and a secondary offering in November 1996. As of
December 31, 1996, IES is the beneficial owner of approximately 10.6
million total shares on a fully diluted basis. Class B shares are
convertible at the option of IES into Class A shares at any time on a
one-for-one basis. The rights of McLeod Class A common stock and Class
B common stock are substantially identical except that Class A common
stock has 1 vote per share and Class B common stock has 0.40 vote per
share. IES currently accounts for this investment under the cost method.
IES has entered into an agreement with McLeod which provides that for
two years commencing on June 10, 1996, IES cannot sell or otherwise
dispose of any of its securities of McLeod without the consent of the
McLeod Board of Directors. This contractual sale restriction results in
restricted stock under the provisions of Statement of Financial
Accounting Standards No. 115 (SFAS No. 115), Accounting for Certain
Investments in Debt and Equity Securities, until such time as the
restrictions lapse and such shares became qualified for sale within a
one year period. As a result, IES currently carries this investment at
cost.
The closing price of the McLeod Class A common stock on December 31,
1996, on the Nasdaq National Market, was $25.50 per share. The current
market value of the shares IES beneficially owns (approximately 10.6
million shares) is currently impacted by, among other things, the fact
that the shares cannot be sold for a period of time and it is not
possible to estimate what the market value of the shares will be at the
point in time such sale restrictions are lifted. In addition, any gain
upon an eventual sale of this investment would likely be subject to a
tax.
Under the provisions of SFAS No. 115, the carrying value of the McLeod
investment will be adjusted to estimated fair value at the time such
shares become qualified for sale within a one year period; this will
occur on June 10, 1997, which is one year before the contractual
restrictions on sale are lifted. At that time, the adjustment to
reflect the estimated fair value of this investment will be reflected
as an increase in the investment carrying value with the unrealized gain
reported as a net of tax amount in other common shareholders' equity
until realized (i.e. until the shares are sold by IES).
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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, on the 14th day of March 1997.
IES INDUSTRIES INC.
(Registrant)
By /s/ Lee Liu
Lee Liu
Chairman of the Board &
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities indicated on March 14,
1997:
/s/ Lee Liu Chairman of the Board &
Lee Liu Chief Executive Officer
(Principal Executive Officer)
/s/ Thomas M. Walker Executive Vice President &
Thomas M. Walker Chief Financial Officer
(Principal Financial Officer)
/s/ John E. Ebright Controller & Chief Accounting Officer
John E. Ebright (Principal Accounting Officer)
/s/ C.R.S. Anderson Director
C.R.S. Anderson
J. Wayne Bevis Director
J. Wayne Bevis
/s/ Jack R. Newman Director
Jack R. Newman
/s/ Robert D. Ray Director
Robert D. Ray
/s/ David Q. Reed Director
David Q. Reed
/s/ Henry Royer Director
Henry Royer
/s/ Robert W. Schlutz Director
Robert W. Schlutz
/s/ Anthony R. Weiler Director
Anthony R. Weiler
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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, on the 14th day of March 1997.
IES UTILITIES INC.
(Registrant)
By /s/ Lee Liu
Lee Liu
Chairman of the Board &
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities indicated on
March 14, 1997:
/s/ Lee Liu Chairman of the Board &
Lee Liu Chief Executive Officer
(Principal Executive Officer)
/s/ Thomas M. Walker Executive Vice President &
Thomas M. Walker Chief Financial Officer
(Principal Financial Officer)
/s/ John E. Ebright Controller & Chief Accounting Officer
John E. Ebright (Principal Accounting Officer)
/s/ C.R.S. Anderson Director
C.R.S. Anderson
J. Wayne Bevis Director
J. Wayne Bevis
/s/ Jack R. Newman Director
Jack R. Newman
/s/ Robert D. Ray Director
Robert D. Ray
/s/ David Q. Reed Director
David Q. Reed
/s/ Henry Royer Director
Henry Royer
/s/ Robert W. Schlutz Director
Robert W. Schlutz
/s/ Anthony R. Weiler Director
Anthony R. Weiler