EXHIBIT 13.1
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
CORPORATE OVERVIEW
MidAmerican Energy Company (the Company or MidAmerican) was formed on
July 1, 1995, as a result of the merger of Iowa-Illinois Gas and Electric
Company (Iowa-Illinois), Midwest Resources Inc. (Resources) and its utility
subsidiary, Midwest Power Systems Inc. (Midwest). Pursuant to the merger,
each outstanding share of preferred and preference stock of the predecessor
companies was converted into one share of a similarly designated series of
MidAmerican preferred stock, no par value. Each outstanding share of common
stock of Resources and Iowa-Illinois was converted into one share and 1.47
shares, respectively, of MidAmerican common stock, no par value.
The Company's utility operations (the Utility) consist of two principal
business units: an electric business unit headquartered in Davenport, Iowa, and
a natural gas business unit headquartered in Sioux City, Iowa. The Company's
corporate headquarters, which includes various staff functions, is in Des
Moines, Iowa. InterCoast Energy Company (InterCoast) and Midwest Capital Group,
Inc. (Midwest Capital) are the nonregulated subsidiaries of the Company and are
headquartered in Des Moines. InterCoast conducts various nonregulated
activities of the Company, while Midwest Capital functions as a regional
business development company in the utility service territory.
Management anticipates that the merger will permit the Company to derive
benefits from more efficient and economic use of the combined facilities and
resources of its predecessors. Savings from avoided costs and cost reductions
are estimated to total in excess of $500 million over the next 10 years.
Although the Company began realizing some benefits of the merger in 1995,
additional benefits and savings will be realized in 1996 and future years. As
discussed below, the Company has incurred significant costs related to
consummation of the merger, business restructuring and work force reduction.
The merger is being accounted for as a pooling-of-interests, and the
Consolidated Financial Statements included in this Annual Report are presented
as if the merger was consummated as of the beginning of the earliest period
presented. Portions of the following discussion provide information related to
material changes in the Company's financial condition and results of operations
between the periods presented, based on the combined historical information of
the predecessor companies. It is not necessarily indicative of what would have
occurred had the merger actually been consummated at the beginning of the
earliest period.
In January 1996, the Company's Board of Directors approved the formation
of a holding company structure. The holding company would have two wholly
owned subsidiaries consisting of MidAmerican (utility operations) and
InterCoast. Midwest Capital would remain a subsidiary of MidAmerican. The
Board of Directors and management believe a holding company structure will
provide a more flexible organization better designed to operate in a more
competitive environment. Consummation of the holding company structure is
subject to approval by holders of a majority of the outstanding shares of the
Company's common stock. In addition, certain orders must be received from
the Illinois Commerce Commission (ICC), the Iowa Utilities Board (IUB), the
Federal Energy Regulatory Commission (FERC), and the Nuclear Regulatory
Commission (NRC). Subject to such approvals, each share of MidAmerican common
stock will be exchanged for one share of the holding company's common stock.
It is management's intent, if possible, to complete the formation of the
holding company and share exchange by the end of 1996.
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RESULTS OF OPERATIONS
EARNINGS
The following tables provide a summary of the earnings contributions of the
Company's operations for the past three years:
1995 1994 1993
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Earnings (in millions)
Utility operations............... $124.5 $110.6 $125.5
Nonregulated operations.......... (2.1) 15.2 13.8
Income (loss) from
discontinued operations........ 0.4 (5.6) (3.8)
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Consolidated earnings............ $122.8 $120.2 $135.5
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Earnings Per Common Share
Utility operations............... $1.24 $1.12 $1.29
Nonregulated operations.......... (0.02) 0.16 0.14
Income (loss) from
discontinued operations........ - (0.06) (0.04)
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Consolidated earnings............ $1.22 $1.22 $1.39
------ ------ -------
------ ------ -------
Earnings per share for 1995 were unchanged compared to 1994. Increases in
the gross margins of utility electric and natural gas operations favorably
affected earnings for 1995. Gross margin is the amount of revenues remaining
after deducting electric fuel costs or the cost of gas sold, as appropriate.
Decreases in nuclear operations and maintenance costs also favorably affected
earnings. Merger-related costs and write-downs of certain nonregulated assets
had a significant adverse affect on 1995 earnings.
The increases in utility gross margins were due primarily to electric and
gas service rate increases filed prior to the merger. Recent rate activity is
discussed in greater detail later in this section. A portion of the rate
increases relate directly to increases in certain operating expenses. The gross
margin for electric operations, net of the increase in directly-related
operating expenses, contributed $0.26 per share more to earnings in 1995 than
in 1994. In addition to increases in electric rates, increased sales due to hot
weather in the third quarter of 1995, though offset somewhat by less extreme
temperatures in the heating season, resulted in a 3% increase in electric retail
sales for 1995 compared to 1994. The gross margin for gas operations, net of
the increase in directly-related operating expenses, contributed $0.07 per share
more to earnings in 1995 than in 1994. An increase in retail natural gas sales
also contributed to the improved gross margin due to colder temperatures in the
fourth quarter of 1995 compared to 1994.
As part of the process of merging the operations of MidAmerican's
predecessors, the Company developed a restructuring plan which includes employee
incentive early retirement, relocation and separation programs. The
restructuring plan, which was completed in 1995, resulted in the elimination of
over 700 positions. During 1995 the Company recorded $33.4 million of
restructuring costs which included the Company's estimate of the remaining
amount of such costs to be incurred. These costs are primarily reflected in
Other Operating Expenses in the Consolidated Statements of Income.
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In addition, the Company incurred nonrecurring costs to accomplish
consummation of the merger. These "transaction costs," which are included in
Other Non-Operating Income, in the Consolidated Statements of Income, totalled
$4.6 million in 1995 and $4.5 million in 1994.
In total, restructuring and transaction costs reduced 1995 earnings by
$0.24 per share, while transaction costs reduced 1994 earnings by $0.05 per
share.
Write-downs of certain assets of the Company's nonregulated subsidiaries
reduced 1995 earnings by approximately $10.2 million, or $0.10 per share. The
pre-tax amount of the write-downs, which is included in Other Non-Operating
Income, in the Consolidated Statements of Income, reflects other-than-temporary
declines of $18.0 million in the value of those nonregulated investments. The
investments are primarily alternative energy projects.
Earnings for 1994 decreased $15.3 million from the 1993 level due
primarily to merger transaction costs in 1994 and recognition of an $11.5
million aftertax gain on the exchange of gas service territory in 1993.
UTILITY OPERATING REVENUES
ELECTRIC:
A combination of factors contributed to the $73.0 million increase in
electric operating revenues for 1995.
Various increases in retail electric rates contributed to the increase in
electric revenues. In October 1994 and January 1995, the Company implemented
rate increases for Iowa energy efficiency cost recovery filings which allow a
total increase in electric revenues of $31.7 million over a four-year period.
In August 1995, the Company began collection of $18.6 million over a four-year
prospective period related to another energy efficiency cost recovery filing.
In connection with an Iowa electric rate filing, the Company began collecting in
January 1995 interim rates representing an increase of $13.6 million in annual
electric revenues. A final rate increase in the proceeding, representing an
increase of $20.3 million in annual electric revenues, was effective in August
1995. The new rates include a component for the recovery of other
postretirement employee benefit (OPEB) costs on an accrual basis instead of the
pay-as-you-go basis previously used. Approximately $8 million of the $20.3
million increase in annual revenues relates to additional expensing of OPEB
costs. Increases in revenues due to OPEB and energy efficiency costs have an
immaterial impact on net income due to corresponding increases in operating
expenses.
An 11% increase in retail sales of electricity for the 1995 third quarter
compared to the 1994 third quarter was the main cause of the increase in
electric retail sales for 1995. The increase in sales was primarily the result
of warmer temperatures which, measured in cooling degree days, were 56% warmer
in the 1995 third quarter than in the comparable 1994 quarter.
The Company has been allowed current recovery from most of its electric
utility customers for fuel and purchased power costs through energy adjustment
clauses (EACs). As the cost of energy to serve those customers fluctuates,
revenues fluctuate accordingly with no impact on gross margin or net income. In
1995, the average energy cost per unit decreased 4.5%. As a result, 1995
revenues collected through the EACs decreased compared to 1994.
Revenues from sales for resale accounted for $21.2 million of the increase
in electric revenues. Sales for resale volumes increased 53% for 1995 compared
to 1994. Greater availability of nuclear generating facilities in 1995
increased the amount of energy available for sales for resale. Coal delivery
uncertainties also limited the
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Company's sales for resale activity in 1994. Sales for resale have a lower
margin than other sales and, accordingly, increases in related revenues do
not increase net income as much as increases in retail revenues.
The Company is a 25% owner in Quad-Cities Nuclear Power Station (Quad-
Cities Station), which is jointly owned and operated by Commonwealth Edison.
The Company also purchases 50% of the energy of Cooper Nuclear Station (Cooper),
which is owned and operated by Nebraska Public Power District (NPPD), through a
power purchase agreement which terminates in 2004. NPPD took Cooper out of
service on May 25, 1994. Pending satisfaction of the concerns of the NRC,
Cooper remained out of service until February 1995 when it returned to service
following NRC approval to restart. In May 1995, the Company filed a lawsuit
seeking unspecified damages from NPPD related to the 1994-95 Cooper outage. In
June 1995, the NRC removed Cooper and the Quad-Cities Station from its list of
adversely trending plants.
Total electric operating revenues for 1994 increased $18.7 million compared
to 1993. Electric retail revenues increased $38.2 million in 1994 compared to
1993. The increase in retail revenues was partially offset by a decrease of
approximately $20 million in sales for resale revenues. As discussed above,
outages at Cooper in 1994 and coal delivery uncertainties limited the Company's
sales for resale activity. An increase in retail sales, due mostly to increased
sales to general service customers, was the primary cause of the increase in
retail revenues. An increase in the cost of energy per unit sold also increased
revenues through the EACs in 1994. Rate increases also contributed to the
increase in electric revenues for 1994 compared to 1993 as discussed below.
In July 1993, the Company implemented electric rates for some of its Iowa
customers designed to increase annual electric revenues by $6.8 million. Also
in July 1993, an annual electric rate increase in Illinois of $9.6 million
became effective.
GAS:
Gas operating revenues for 1995 decreased $32.4 million compared to 1994.
A reduction in revenues collected through the purchased gas adjustment clauses
(PGAs) was the primary cause of the decrease in revenues. This was due to a
significant decrease in the average cost of gas per unit sold. Variations in
revenues collected through the PGAs reflecting changes in the cost of gas and
volumes sold do not affect gross margin or net income.
An increase in sales and rates offset part of the impact of lower PGA
revenues. In January 1995, the Company implemented a gas service rate increase
resulting from findings in an Iowa energy efficiency cost recovery filing which
allows an increase in gas revenues of $6.7 million over a four-year period. In
October 1994, the Company began collecting interim rates for an Iowa gas rate
filing representing an increase of $8.2 million in annual gas revenues. A final
rate increase of $10.6 million in annual gas revenues was effective in August
1995. Approximately $2.5 million of the $10.6 million increase in annual
revenues relates to the recovery of OPEB costs on an accrual basis. Increases
in revenues due to OPEB and energy efficiency costs have an immaterial impact on
net income due to corresponding increases in operating expenses. Retail sales
of natural gas increased slightly due to a 4% increase in residential sales.
This was due mostly to colder weather in the fourth quarter of 1995.
Gas operating revenues for 1994 decreased $47.0 million compared to 1993
due to a decrease in retail natural gas sales. Temperatures, measured in
heating degree days, decreased considerably in 1994 compared to 1993, resulting
in the decrease in retail sales. In addition, an exchange of gas service
territories in the third quarter of 1993 resulted in a decrease in natural gas
customers. A reduction in revenues collected through the PGAs also contributed
to the decrease in retail revenues. The effect of rate increases partially
offset the decrease in revenues due to reduced sales volumes and PGA revenues.
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UTILITY OPERATING EXPENSES
Changes in the cost of electric fuel, energy and capacity (collectively,
Energy Costs) reflect fluctuations in generation levels and mix, fuel cost, and
energy and capacity purchases. Energy Costs for 1995 increased 8% compared to
1994 due primarily to a 13% increase in total electric sales. The increase in
Energy Costs as a result of greater sales of electricity was partially offset by
a 5% decrease in the average Energy Cost per unit. Energy Costs for 1994
decreased 2% compared to 1993 due primarily to the reduction in sales for
resale. The decrease due to reduced sales of electricity was partially offset
by a 7% increase in the average Energy Cost per unit. Part of the fluctuation
in the average Energy Cost per unit was due to the changes in the availability
of nuclear generation throughout the three-year period.
Cost of gas sold for 1995 decreased compared to 1994 due to a 15% decrease
in the average cost of gas per unit sold. Cost of gas sold decreased in 1994
compared to 1993 due primarily to a 9% decrease in sales which was due in part
to a gas property exchange.
Other operating expenses increased $45.5 million in 1995 compared to 1994
due primarily to costs related to the restructuring plan discussed in the
opening section of Results of Operations. Utility operating expenses include
$31.9 million of the $33.4 million total restructuring costs. As discussed
above, 1995 expenses also include increases from deferred energy efficiency and
OPEB costs. The increases for 1995 were partially offset by an $8.6 million
reduction in nuclear operations costs. Expenses for 1994 were reduced by $3.0
million due to capitalizing previously expensed energy efficiency costs to
comply with the IUB regulation of these costs.
Other operating expenses in 1994 increased $13.5 million compared to 1993.
Increased nuclear operations costs related to extended outages at Cooper and
Quad-Cities Station during 1994 contributed to the increase. The increase in
nuclear costs was partially offset by the adjustment to energy efficiency costs
mentioned above.
Maintenance expenses decreased $15.9 million in 1995 compared to 1994.
Quad-Cities Station maintenance expenses decreased $5.5 million due in part to
the 1994 outage. The timing of power plant maintenance and a reduction in
various distribution maintenance accounted for much of the remaining variation
between years.
Depreciation expense increased compared to each prior year due primarily to
additions to utility plant in service.
NONREGULATED OPERATING REVENUES
Revenues for the Company's nonregulated subsidiaries decreased $7.8 million
for 1995 compared to 1994. A decrease in real estate revenues and reduced
revenues due to the impact of the sale of a telecommunications subsidiary in
early 1995 accounted for most of the decrease. Revenues from the Company's oil
and gas production subsidiary were basically unchanged with increases in gas
production volumes and oil prices offsetting decreases due to lower prices for
natural gas. A 16% decrease in sales volumes for a nonregulated retail natural
gas marketing subsidiary resulted in a $13.9 million decrease in nonregulated
gas revenues for 1995. This decrease was offset by $14.2 million in revenues of
a wholesale natural gas marketing firm acquired in December 1995.
Revenues for 1994 increased $36.3 million compared to 1993 due primarily to
a $33.4 million increase in revenues from retail sales of natural gas. The
increase in retail natural gas sales and revenues for 1994 is attributable
primarily to the purchase of the assets of an existing nonregulated natural gas
business in January 1994. Higher production volumes reflecting additional
acquired reserves and successful drilling results also contributed to the
increase in revenues for 1995.
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NONREGULATED OPERATING EXPENSES
Cost of sales includes expenses directly related to sales of oil, natural
gas and real estate. The factors discussed above for revenues, including
natural gas sales volumes, lower gas prices and reduced real estate sales, also
affected the variances in cost of sales for the years 1993 through 1995. Cost
of sales for the newly acquired natural gas firm also contributed to the
increase in 1995 compared to 1994.
Other nonregulated expenses increased $3.0 million for 1995 compared to
1994. The 1995 amount includes $1.5 million of expenses for the Company's
restructuring plan. The $5.7 million increase in 1994 compared to 1993 was due
primarily to expenses of the natural gas marketing business acquired in January
1994.
REALIZED GAINS AND LOSSES ON SECURITIES, NET
Realized gains and losses on securities decreased $6.9 million for 1995
compared to 1994. The decrease resulted primarily from the sale of a single
holding in 1994 which generated a $5.9 million pre-tax gain. During 1993,
InterCoast realized significant gains on some of its investments in marketable
securities due to the impact of favorable market conditions.
NON-OPERATING INCOME - OTHER, NET
The adjustments to nonregulated investments discussed at the beginning of
Results of Operations were the primary cause of the decrease in Other, Net, for
1995 compared to 1994. In addition, merger transaction costs reduced Other, Net
in 1995 and 1994. A gain on the sale of an investment in a leveraged lease in
1994 also contributed to the comparative decrease for 1995 compared to 1994.
Gains totalling $8.5 million on the sales of a partnership interest in a gas
marketing organization and a telecommunication subsidiary in 1995 partially
offset the decreases. The decrease from 1993 to 1994 is due primarily to an
$18.5 million pre-tax gain on the exchange of natural gas service territories in
1993.
INTEREST CHARGES
Increased interest on long-term debt in 1995 compared to 1994 was due
primarily to the issuance of $60 million of 7.875% Series of mortgage bonds in
November 1994. The decrease in interest on long-term debt from 1993 to 1994
reflects refinancing of several series of long-term debt at lower interest rates
in 1993.
DISCONTINUED OPERATIONS
In 1994, the Company announced its intent to divest its construction
subsidiaries and recognized the anticipated loss on disposal. The sale of
certain assets of one of the subsidiaries was completed in December 1994, and
the sale of the other construction subsidiary was completed in March 1995.
Settlement of a construction receivable in the second quarter of 1995 resulted
in $0.4 million of income in 1995.
PREFERRED DIVIDENDS
The decrease in the preferred dividend requirement for 1995 compared to
1994 was due mostly to the redemption of three series of outstanding preferred
shares in December 1994.
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LIQUIDITY AND CAPITAL RESOURCES
The Company has available a variety of sources of liquidity and capital
resources, both internal and external. These resources provide funds required
for current operations, debt retirement, dividends, construction expenditures
and other capital requirements.
For 1995, the Company had net cash provided from operating activities of
$382 million and net cash used of $320 million and $54 million for investing and
financing activities, respectively.
INVESTING ACTIVITIES
Utility construction expenditures, including allowance for funds used
during construction (AFUDC), Quad-Cities Station nuclear fuel purchases and
Cooper capital improvements, were $191 million for 1995. The decrease from the
1994 total of $212 million reflects the Company's efforts to limit construction
expenditures.
Forecasted utility construction expenditures for 1996 are $166 million
including AFUDC. The 1996 plan includes $35 million for Cooper capital
improvements and Quad-Cities Station nuclear fuel purchases and construction
expenditures. For the years 1996 through 2000, the Company forecasts $818
million for utility construction expenditures, $154 million of which is for
nuclear expenditures. The Company presently expects that all utility
construction expenditures for 1996 through 2000 will be met with cash generated
from utility operations, net of dividends.
In general, decommissioning of a nuclear facility means to safely remove
the facility from service and restore the property to a condition allowing
unrestricted use. During 1995, the Utility contributed approximately $9 million
to an external trust established for the investment of funds for decommissioning
the Quad-Cities Station. Based on information presently available, the Utility
expects to contribute $45 million to the trust during the period 1996 through
2000. The funds are invested predominately in investment grade municipal, and
U.S. Treasury, bonds. In addition, approximately $9 million of the 1995
payments made under the power purchase contract with NPPD were for
decommissioning funding related to Cooper. The Cooper costs are reflected in
Other Operating Expenses in the Consolidated Statements of Income. Based on
NPPD estimates, the Utility expects to pay approximately $54 million for Cooper
decommissioning during the period 1996 through 2000. NPPD invests the funds in
instruments similar to those of the Quad-Cities Station trust fund. The
Company's obligation for Cooper decommissioning may be affected by the actual
plant shutdown date and the status of the power purchase contract at that time.
The Company currently recovers Quad-Cities Station decommissioning costs charged
to Illinois customers through a rate rider on customer billings. Cooper and
Quad-Cities Station decommissioning costs charged to Iowa customers are included
in base rates, and increases in those amounts must be sought through the normal
ratemaking process. Refer to Note 4(d) of Notes to Consolidated Financial
Statements (Notes) for additional details regarding decommissioning.
Capital expenditures of nonregulated subsidiaries were $56 million for
1995. Capital expenditures of nonregulated subsidiaries depend upon the
availability of suitable investment opportunities and other factors. For 1996,
such expenditures are forecasted to be approximately $85 million, primarily
related to InterCoast.
InterCoast invests in a variety of marketable securities which it holds for
indefinite periods of time. For 1995, InterCoast had net cash outflows of $67
million from its marketable securities investment activities. In the
Consolidated Statements of Cash Flows, the lines Purchase of Securities and
Proceeds from Sale of Securities consist primarily of the gross amounts of these
activities, including realized gains and losses on investments in marketable
securities.
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FINANCING ACTIVITIES
The Utility currently has authority from the FERC to issue short-term debt
in the form of commercial paper and bank notes aggregating $400 million. As of
December 31, 1995, the Utility had bank lines of credit of $250 million to
provide short-term financing for utility operations. In January 1996, the
Utility entered into a $250 million revolving credit facility agreement to
replace those lines of credit. The Utility's commercial paper borrowings, which
totalled $185 million at December 31, 1995, are currently supported by the
revolving credit facility. The Utility also has lines of credit and revolving
credit facilities which are dedicated to provide liquidity for its obligations
under outstanding pollution control revenue bonds that are periodically
remarketed.
In January 1995, $12.75 million of floating rate pollution control
refunding revenue bonds due 2025 were issued. Proceeds from this financing were
used to redeem $12.75 million of collateralized pollution control revenue bonds,
5.8% Series, due 2007.
The Utility has $347 million of long-term debt maturities and sinking fund
requirements for 1996 through 2000, $1 million of which matures in 1996.
The Utility is currently considering several long-term financing options
for 1996. Proceeds from those issuances would be used to reduce commercial
paper outstanding and to refinance higher cost securities.
As of December 31, 1995, the Utility had the capability to issue
approximately $1.3 billion of mortgage bonds under the current Midwest
indenture. The Utility does not expect to issue additional debt under the Iowa-
Illinois indenture, but may if necessary.
During the first six months of 1995, Resources and Iowa-Illinois sold
original issue shares of common stock through certain of their employee stock
purchase and dividend reinvestment plans. On a MidAmerican share basis,
1,065,240 shares of common stock were issued. The Company has the necessary
authority to issue up to 6,000,000 shares of common stock through its
Shareholder Options Plan (the Company's dividend reinvestment and stock
purchase plan). Since the effective date of the merger, the Company has used
open market purchases of its common stock rather than original issue shares to
meet share obligations under its Employee Stock Purchase Plan and the
Shareholder Options Plan. The Company currently plans to continue using open
market purchases to meet share obligations under these plans.
Subsequent to the consummation of the merger, the Utility made a $55
million equity contribution to InterCoast. In addition, nonregulated businesses
not related to regional business development were transferred from Midwest
Capital to InterCoast. The equity contribution was then used to extinguish
Senior Notes and variable interest rate Notes Payable, thus eliminating several
financial relationships between the Company's utility and nonregulated
operations.
One support agreement remains between the Utility and Midwest Capital
related to a performance guarantee by Midwest Capital of a joint venture turnkey
engineering, procurement and construction contract for a cogeneration project.
The project received preliminary acceptance from the owner in 1995, which
pursuant to the construction contract, eliminates the potential for liquidated
damages being incurred related to the project. Midwest Capital also has $25
million of long-term debt outstanding at December 31, 1995, that matures in 1996
and is supported by a guarantee from the Utility. In addition, Midwest Capital
has a $25 million line of credit with the Utility.
During the third quarter of 1995, InterCoast entered into a $64 million
unsecured revolving credit facility agreement which matures in 1998. The
facility was used primarily to refinance maturing Senior Notes. InterCoast also
has a $110 million unsecured revolving credit facility agreement which matures
in 1999.
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Borrowings under these agreements may be at a fixed rate, floating rate or
competitive bid rate basis. All borrowings under these agreements are
without recourse to the Utility. At December 31, 1995, InterCoast had $130
million of debt outstanding under these two revolving credit facility
agreements.
In addition, InterCoast has entered into two floating rate to fixed
interest rate swaps each in the amount of $32 million. The interest rate swaps
have fixed rates of 5.97% and 6.00%, respectively, and are for three-year and
two-year terms, respectively, with an optional third year on the latter.
InterCoast's aggregate amounts of maturities and sinking fund requirements
for long-term debt outstanding at December 31, 1995, are $39 million for 1996
and $287 million for the years 1996 through 2000. Amounts due in 1996 are
expected to be refinanced with debt instruments.
On January 24, 1996, the Company's Board of Directors declared a quarterly
dividend on common shares of $0.30 per share payable March 1, 1996. The
dividend represents an annual rate of $1.20 per share.
OPERATING ACTIVITIES
The Utility is subject to regulation by several utility regulatory
agencies. The operating environment and the recoverability of costs from
utility customers are significantly influenced by the regulation of those
agencies. The Company anticipates that changes in the utility industry will
create a more competitive environment. Although these anticipated changes may
create opportunities, they will also create additional challenges and risks for
utilities. The Company is evaluating strategies that will assist it in a more
competitive environment.
A possible consequence of competition in the utility industry is the
discontinued applicability of Statement of Financial Accounting Standards (SFAS)
No. 71. SFAS 71 sets forth accounting principles for all, or a portion, of a
company's operations that are regulated and meet certain criteria. For
operations that meet the criteria, SFAS 71 allows, among other things, the
deferral of costs that would otherwise be expensed when incurred. The Company's
electric and gas utility operations are currently subject to the provisions of
SFAS 71. Should the utility industry become more competitive as presently
anticipated, the Company will reexamine the applicability of SFAS 71. If a
portion of the Company's utility operations no longer meets the criteria of SFAS
71, the Company could be required to eliminate from its balance sheet assets and
liabilities related to those operations that resulted from actions of its
regulators (i.e., regulatory assets and liabilities). A material adjustment to
earnings in the appropriate period could result from the discontinuance of SFAS
71. Refer to Note (1)(c) of Notes for a discussion of regulatory assets.
The Energy Policy Act (EPAct) was enacted in 1992. This law promotes
competition in the wholesale electric power market. The FERC has taken action
to establish rules and policies in compliance with provisions of the EPAct
through a Notice of Proposed Rulemaking issued March 29, 1995. The Company has
been active in providing filed, written comments with the FERC in an effort to
shape new transmission policies in ways that will best serve the interests of
its customers and shareholders. In conjunction with the Merger, the Company
submitted an open access transmission tariff in 1994 which was accepted for
filing by the FERC in June 1995.
Legislation enacted by the State of Illinois in 1995 allows public
utilities to file for regulatory approval of nontraditional rate design.
Alternative forms of rate design may include price caps, flexible rate
structures and other modifications of the cost-based method currently used to
determine rates for electric and gas services. The Company is evaluating its
options in light of the new legislation. If appropriate, the Company may file a
request in 1996 for alternate rate design in Illinois.
In 1992, the FERC issued Order No. 636, directing a restructuring by
interstate pipeline companies for their natural gas sales and transportation
services. The unbundling of pipeline services increased the Company's access
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to supply options and its supply responsibilities. Certain transition costs
incurred by interstate natural gas pipelines for their compliance with Order
636 will be paid to the pipeline companies over the next several years. The
Company's Consolidated Balance Sheet as of December 31, 1995, includes a $41
million noncurrent liability and regulatory asset recorded for transition
costs. The Company may incur other transition costs in conjunction with
future purchases of gas, but does not expect these billings to have a
material impact on the cost of gas. The Company is currently recovering
costs related to Order 636 from its customers.
Electric and gas utilities in Iowa are required to spend approximately 2%
and 1.5%, respectively, of their annual Iowa jurisdictional revenues on energy
efficiency activities. In October 1994 and in January 1995, the Company began
collecting over a four-year prospective period $19.7 million and $18.7 million,
respectively, related to prior energy efficiency cost recovery filings. A
recent district court ruling was issued which affirmed in all respects the IUB
decisions allowing such recovery. In another cost recovery filing, the IUB
issued an order approving the collection over a four-year prospective period of
$18.6 million. Collection related to this filing began August 8, 1995. As of
December 31, 1995, the Company had approximately $68 million of energy
efficiency costs deferred on its Consolidated Balance Sheet for which recovery
will be sought in future energy efficiency filings.
The United States Environmental Protection Agency (EPA) and state
environmental agencies have determined that contaminated wastes remaining at
certain decommissioned manufactured gas plant facilities may pose a threat to
the public health or the environment if such contaminants are in sufficient
quantities and at such concentrations as to warrant remedial action.
The Company is evaluating 26 properties which were, at one time, sites of
gas manufacturing plants in which it may be a potentially responsible party
(PRP). The purpose of these evaluations is to determine whether waste materials
are present, whether such materials constitute an environmental or health risk,
and whether the Company has any responsibility for remedial action. The
Company's present estimate of probable remediation costs for these sites is $21
million. This estimate has been recorded as a liability and a regulatory asset
for future recovery through the regulatory process. Refer to Note (4)(b) of
Notes for further discussion of the Company's environmental activities related
to manufactured gas plant sites and cost recovery.
Although the timing of potential incurred costs and recovery of such cost
in rates may affect the results of operations in individual periods, management
believes that the outcome of these issues will not have a material adverse
effect on the Company's financial position or results of operations.
The Clean Air Act Amendments of 1990 (CAA) were signed into law in November
1990. The Company has five jointly owned and five wholly owned coal-fired
generating stations, which represent approximately 65% of the Company's electric
generating capability.
Two of the Company's coal-fired generating units were subject to the
requirements of the CAA beginning in 1995. These units were given a set number
of allowances by the EPA. Each allowance permits the units to emit one ton of
sulfur dioxide. The Company has completed most of the modifications necessary
to one unit to burn low-sulfur coal and to install nitrogen oxides controls and
an emissions monitoring system. Under proposed regulations, the second unit
will require additional capital expenditures to reduce emissions of nitrogen
oxides.
The Company's other coal-fired generating units are not materially affected
by the provisions of the CAA. Due to the use of low-sulfur western coal, the
Company does not anticipate the need for additional capital expenditures to
lower sulfur dioxide emission rates to ensure that allowances allocated by the
federal government are not exceeded. While the Company estimates that
sufficient emission allowances have been allocated on a system-wide basis for
its units to operate at the capacity factors needed to meet system energy
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requirements, additional purchases of allowances may be necessary to meet
desired sales for resale levels. By the year 2000, some Company coal-fired
generating units will be required to install controls to reduce emissions of
nitrogen oxides. Essentially all utility generating units are subject to CAA
provisions which address continuous emission monitoring, permit requirements and
fees, and emission of toxic substances. Based on currently proposed CAA
regulations, the Company does not anticipate its remaining construction costs
for the installation of low nitrogen oxides burner technology and emissions
monitoring system upgrades to exceed $16 million.
ACCOUNTING ISSUES
In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS
No. 121 regarding accounting for asset impairments. This statement, which will
be adopted by the Company in the first quarter of 1996, requires the Company to
review long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of such assets may not be
recoverable. SFAS 121 also requires rate-regulated companies to recognize an
impairment for regulatory assets that are not probable of future recovery.
Adoption of SFAS 121 is not expected to have a material impact on the Company's
results of operations or financial position at the time of adoption.
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry, including
those of the Company, regarding the recognition, measurement and classification
of nuclear decommissioning costs in the financial statements. In response to
these questions, the FASB has added a project to its agenda to review the
accounting for closure and removal costs, including decommissioning of nuclear
power plants. If current electric utility industry accounting practices for
such decommissioning are changed, the annual provision for decommissioning could
increase relative to 1995, and the total estimated cost for decommissioning
could be recorded as a liability with recognition of an increase in the cost of
related nuclear power plant. The Company has not determined what impact, if
any, it would have on the Company's operation and financial position.
In October 1995, the FASB issued SFAS No. 123 regarding stock-based
compensation plans. SFAS 123, which is effective for reporting periods
beginning January 1, 1996, allows for alternative methods of adoption. The
Company does not expect the accounting provisions or alternative disclosure
provisions of SFAS 123 to have a material impact on the Company's results of
operations.
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