IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
1993 1992 1991
(In thousands, except per share amounts)
OPERATING REVENUES
Electric $338,593 $312,667 $331,577
Gas 206,821 184,867 180,960
545,414 497,534 512,537
OPERATING EXPENSES AND TAXES
Operation-
Cost of gas sold 141,712 125,317 126,134
Cost of fuel, energy and capacity 64,619 58,266 65,437
Other operation 104,281 102,311 95,590
Maintenance 44,524 39,536 39,408
Provision for depreciation 58,647 53,941 48,501
Depreciation and equity funds recovered
under Louisa Phase-In Clause 2,370 4,515 4,086
Income taxes 24,477 16,320 25,360
Property and other taxes 33,401 33,827 32,711
474,031 434,033 437,227
OPERATING INCOME 71,383 63,501 75,310
OTHER INCOME
InterCoast Energy Company -
Oil and gas revenues 54,979 28,478 6,740
Other income 29,105 27,350 26,350
Expenses, including interest and
provision for income taxes (71,583) (46,351) (25,697)
Net income of InterCoast Energy Company 12,501 9,477 7,393
Miscellaneous 461 (984) (648)
12,962 8,493 6,745
INCOME BEFORE UTILITY INTEREST CHARGES 84,345 71,994 82,055
UTILITY INTEREST CHARGES
Interest on long-term debt 24,471 25,793 27,096
Other interest expense 1,625 1,872 2,040
Allowance for borrowed funds
used during construction (979) (1,104) (1,448)
25,117 26,561 27,688
NET INCOME 59,228 45,433 54,367
PREFERRED AND PREFERENCE
DIVIDEND REQUIREMENTS 4,995 5,029 4,347
NET INCOME ON COMMON SHARES $54,233 $40,404 $50,020
AVERAGE COMMON SHARES OUTSTANDING 29,338 27,944 26,838
NET INCOME PER AVERAGE
COMMON SHARE OUTSTANDING $1.85 $1.45 $1.86
CASH DIVIDENDS DECLARED AND PAID PER COMMON SHARE $1.73 $1.73 $1.71
<FN>
The accompanying notes to consolidated financial statements are an intergral
part of these statements.
-1-
/TABLE
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
December 31,
1993 1992
(In thousands)
PROPERTY AND OTHER ASSETS
UTILITY PLANT, at original cost
Electric $1,279,700 $1,235,276
Gas 271,342 260,963
1,551,042 1,496,239
Less--Accumulated provision for depreciation 605,708 569,104
945,334 927,135
Nuclear fuel, net of accumulated amortization 25,120 26,314
Construction work in progress 22,791 32,541
993,245 985,990
CURRENT ASSETS
Cash and cash equivalents 17,844 20,827
Accounts receivable, less reserves of $1,165 and $1,171 43,389 45,823
Accrued unbilled revenues 22,182 20,615
Inventories 35,597 40,147
Deferred gas expense 5,794 8,887
Other 18,246 14,972
143,052 151,271
INVESTMENTS
InterCoast Energy Company investments 501,829 442,149
Nuclear decommissioning trust fund 39,470 29,675
Corporate-owned life insurance 12,836 9,344
554,135 481,168
OTHER ASSETS
Regulatory assets 92,828 31,257
Other 10,303 9,685
103,131 40,942
1,793,563 1,659,371
CAPITALIZATION AND LIABILITIES
CAPITALIZATION (See accompanying statements) 1,183,641 1,152,216
CURRENT LIABILITIES
Notes payable 31,000 52,500
Debt and preference shares redeemable within one year 59,232 11,235
Accounts payable 44,847 39,783
Accrued taxes 24,913 27,556
Accrued interest 11,413 13,018
Accrued gas expense 11,745 11,528
Other 18,322 17,542
201,472 173,162
OTHER LIABILITIES
Capital lease obligations 10,036 10,500
Accumulated provision for nuclear decommissioning 39,470 29,675
Other 42,984 35,929
92,490 76,104
ACCUMULATED DEFERRED INCOME TAXES 274,605 214,326
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS 41,355 43,563
$1,793,563 $1,659,371
<FN>
The accompanying notes to consolidated financial statements are an integral
part of these statements.
-2-
/TABLE
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31,
1993 1992
(In thousands,
except share amounts)
COMMON SHAREHOLDERS' EQUITY
Common shares-authorized 80,000,000 shares-
outstanding 29,352,173 and 29,349,177 shares stated at $280,009 $280,055
Retained earnings 219,371 216,082
Other 32 (555)
Total 499,412 42% 495,582 43%
PREFERRED SHARES-authorized 400,000 shares, cumulative-
Not subject to mandatory redemption-outstanding-
$4.36 Series Preferred, 60,000 shares (callable at $102.125) 6,000 6,000
$4.22 Series Preferred, 40,000 shares (callable at $100) 4,000 4,000
$7.50 Series Preferred, 98,288 shares (callable at $101.88) 9,829 9,829
Total 19,829 2% 19,829 2%
PREFERENCE SHARES-authorized 2,386,250 and 2,392,000 shares, cumulative-
Subject to mandatory redemption-outstanding-
$5.25 Series Preference, 100,000 shares 10,000 -
$7.90 Series Preference, 86,250 shares - 8,625
$7.80 Series Preference, 400,000 shares (callable at $107.80) 40,000 40,000
Total 50,000 4% 48,625 4%
LONG-TERM DEBT
First Mortgage Bonds-
5-7/8% Series, due 1997 22,000 22,000
Adjustable Rate Series, due 1997 (7.6% and 9.7%) 25,000 25,000
5.05% Series, due 1998 50,000 -
7-5/8% Series, due 1999 - 15,000
7-7/8% Series, due 1999 - 20,000
6.0% Series, due 2000 35,000 -
8.15% Series, due 2001 40,000 40,000
7.70% Series, due 2004 60,000 60,000
7-5/8% Series, due 2005 - 6,850
8-1/4% Series, due 2007 - 30,000
5.8% Series, due 2007 12,750 12,750
7-3/4% Series, due 2010 - 4,200
8-1/2% Series, due 2017 - 60,000
7.45% Series, due 2023 30,000 -
6.95% Series, due 2025 50,000 -
324,750 295,800
Pollution Control Obligations-
5.75%, due 2003 3,828 4,060
Variable Rate-
Due 2016 (3.2%) 4,200 -
Due 2016 (2.4% and 2.8%) 29,500 29,500
Due 2017 (2.5% and 3.0%) 3,900 3,900
Due 2023 (3.2%) 6,850 -
Unamortized debt premium and discount, net (1,128) (2,080)
Total utility 371,900 331,180
InterCoast Energy Company-
Senior Notes-
9.83%, due 1994 - 15,000
7.89%, due 1994 - 28,000
9.80%, due 1995 9,000 17,000
10.01%, due 1995 15,000 15,000
8.27%, due 1995 32,000 32,000
9.30%, due 1995 and 1996 17,000 25,000
10.20%, due 1996 and 1997 60,000 60,000
7.34%, due 1998 20,000 20,000
7.76%, due 1999 45,000 45,000
Borrowings under unsecured revolving credit facility (4.1%) 44,500 -
Total InterCoast Energy Company 242,500 257,000
Total 614,400 52% 588,180 51%
$1,183,641 100%$1,152,216 100%
<FN>
The accompanying notes to consolidated financial statements are an integral part of these statements.
-3-
/TABLE
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
1993 1992 1991
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $59,228 $45,433 $54,367
Adjustments to reconcile net income
to net cash from operating activities -
Depreciation 63,839 58,374 52,381
Depletion 12,880 8,517 3,025
Depreciation and equity funds recovered under
Louisa Phase-In Clause 2,370 4,515 4,086
Nuclear fuel amortization 7,989 7,860 8,832
Deferred income taxes, net 9,707 5,128 10,874
Tax credits, net (2,208) (2,326) (2,385)
Net gain on disposition of securities (3,289) (4,261) (3,464)
Changes in current assets and liabilities -
Accounts receivable 2,434 (2,937) 2,664
Accrued unbilled revenues (1,567) (2,340) 6,028
Inventories 4,550 (349) (4,603)
Deferred and accrued gas expense 3,310 (7,641) 428
Accounts payable 5,038 3,529 (2,797)
Accrued taxes (2,643) 2,794 (2,613)
Other current assets and liabilitie (4,659) (6,568) 2,533
Energy-efficiency program cost deferra (5,669) (4,005) (877)
Other 3,054 (5,743) 1,318
Net cash from operating activities 154,364 99,980 129,797
CASH FLOWS FROM INVESTING ACTIVITIES
Utility plant expenditures (60,162) (64,385) (55,389)
Nuclear fuel expenditures (6,795) (9,313) (6,163)
Nuclear decommissioning trust fund (7,918) (4,469) (11,766)
Oil and gas investments (73,538) (22,169) (34,885)
Purchase of investments (68,239) (94,179) (116,675)
Sale of investments 70,371 51,856 58,296
Other (1,151) (6,826) (4,849)
Net cash from investing activities (147,432) (149,485) (171,431)
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued - 61,563 -
Preference shares issued 10,000 - 40,000
Preference shares redeemed (9,373) (575) (575)
Long-term debt issued 175,784 59,830 39,945
Long-term debt retired (143,493) (62,626) (56,122)
Long-term borrowings of InterCoast Energy Company -
Senior Notes issued - 65,000 60,000
Senior Notes retired (8,000) - -
Increase (decrease) in unsecured revolving
credit facility 44,500 (15,100) (3,900)
Increase (decrease) in short-term borrowings (21,500) - 20,000
Dividends paid (55,745) (53,630) (49,735)
Issuance expense (2,088) (3,187) (868)
Net cash from financing activities (9,915) 51,275 48,745
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (2,983) 1,770 7,111
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 20,827 19,057 11,946
CASH AND CASH EQUIVALENTS AT END OF YEAR $17,844 $20,827 $19,057
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the year for -
Interest (net of amounts capitalized) $51,295 $48,036 $45,354
Income taxes 18,014 10,074 18,129
<FN>
The accompanying notes to consolidated financial statements are an
integral part of these statements.
-4-
/TABLE
IOWA-ILLINOIS GAS AND ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
Year Ended December 31,
1993 1992 1991
(In thousands)
BALANCE BEGINNING OF YEAR $216,082 $224,345 $220,512
ADD-NET INCOME 59,228 45,433 54,367
DEDUCT:
Cash dividends declared-
Preferred and preference shares 4,978 5,026 4,604
Common shares 50,756 48,592 45,901
Loss on reissuance of treasury shares 32 78 29
Premium paid to reacquire preference shares 173 - -
55,939 53,696 50,534
BALANCE END OF YEAR $219,371 $216,082 $224,345
<FN>
The accompanying notes to consolidated financial statements are an integral
part of these statements.
-5-
Iowa-Illinois Gas and Electric Company
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies:
(A) Principles of Consolidation
The consolidated financial statements include the Company and its wholly
owned, non-regulated subsidiary, InterCoast Energy Company (InterCoast).
Intercompany transactions have been eliminated.
_________________________________________________________________
(B) Regulation
The Company's utility operations are subject to the regulation of the Iowa
Utilities Board (IUB), the Illinois Commerce Commission (ICC) and the Federal
Energy Regulatory Commission (FERC). The Company's accounting policies and the
accompanying Consolidated Financial Statements conform to generally accepted
accounting principles applicable to rate-regulated enterprises and reflect the
effects of the ratemaking process. Such effects concern mainly the time at
which various items enter into the determination of net income in accordance
with the principle of matching costs and revenues.
The following regulatory assets represent probable future revenue to the
Company because provisions for these costs are expected to be included in
charges to utility customers through the ratemaking process:
Dec. 31,
1993 1992
(In thousands)
Income taxes related to Statement
of Financial Accounting
Standards No. 109 (SFAS 109). $50,535 $ -
Unamortized premium on reacquired
debt......................... 11,513 5,963
Deferred energy-efficiency
program costs................ 10,791 5,122
United States Department of Energy
(DOE) nuclear enrichment
facilities decontamination
and decommissioning fee...... 10,656 11,800
Manufactured gas plant site
related costs................ 7,768 5,341
Deferred pension costs............ 1,565 661
Louisa Phase-In Clause............ - 2,370
$92,828 $31,257
Refer to Note 4 for information regarding SFAS 109.
Consistent with regulatory treatment, the premiums paid to reacquire debt
prior to scheduled maturity dates are deferred and amortized over the life of
the debt issued to finance the reacquisitions.
In 1991, the Company filed a comprehensive three-year energy-efficiency
plan with the IUB in compliance with 1990 Iowa legislation. The legislation
permits recovery of deferred energy-efficiency program costs, and related
carrying charges, so long as the utility's programs are cost effective or, if
not cost effective, planned and implemented in a prudent and reasonable manner.
The Company will file its initial application for cost recovery of deferred
energy-efficiency program costs in October 1994.
The National Energy Policy Act of 1992 established funding for the
decontamination and decommissioning of nuclear enrichment facilities operated
by the DOE. A portion of such funding is to be collected over a 15-year period
which began in 1992 from electric utilities that had previously purchased
enrichment services from the DOE. At Dec. 31, 1993, the Company's liability
for its share of such funding is $10.7 million. In 1993 and 1992, $770,000 and
$200,000 of such payments were charged to fuel expense and recognized in the
energy adjustment clauses.
In Illinois, costs related to the litigation, investigation and
remediation of former manufactured gas plant sites are recovered through gas
and electric adjustment riders. Costs from 1992 and 1993 were deferred
pursuant to an ICC order for recovery beginning in 1994. All such costs are to
be amortized over a five-year period and no carrying charges are assigned to
the unamortized balances. In Iowa, costs related to the litigation,
investigation and remediation of former manufactured gas plant sites are being
expensed as incurred. The Company's current Iowa gas rates include an annual
provision of $250,000 for such costs. Refer to Note 14 for information
regarding former manufactured gas plant sites.
Refer to Note 5 for information regarding deferred pension costs.
Pursuant to a 1983 Order of the ICC, the Company established an adjustment
clause which gave ratemaking recognition to the depreciation charges and equity
return requirements applicable to the portion of the Company's Louisa
Generating Station investment which is allocable to Illinois. From October
1983 through June 1987, the Clause deferred the inclusion in rates of portions
of both the depreciation and equity return related to the Louisa Station. From
July 1, 1987 through June 30, 1993, the deferred balances were recovered in
rates at a levelized annual revenue amount of approximately $6.6 million. The
Clause, which provided a current cash return on the deferred balances, expired
on June 30, 1993 with the recovery of all deferred amounts.
_________________________________________________________________
(C) Customer Receivables and Operating Revenues
The Company's customer receivables, gas and electric sales and gas
transportation revenue are derived from supplying and delivering electricity
and natural gas to a well diversified base of residential, commercial and
industrial customers located in central and eastern Iowa and western Illinois.
Customer accounts receivable include the following amounts by class of
customer:
Dec. 31,
1993 1992
(In thousands)
Residential.................... $ 25,564 $ 23,810
Commercial..................... 8,166 8,380
Industrial..................... 6,608 6,647
Other.......................... 646 1,156
Revenues are recorded as services are rendered to customers. The Company
records unbilled revenues, and related energy costs, representing the estimated
amount customers will be billed for services rendered between the meter reading
dates in a particular month and the end of that month.
_________________________________________________________________
(D) Energy Costs
The energy (electric fuel and energy and purchased gas) rate provisions in
the Company's tariffs are designed to provide for separately stated energy
billings which cover changes in applicable net energy costs from levels
incorporated in base rates. Differences between applicable energy costs
incurred and energy rate revenues billed in any given period are accounted for
as other current assets or other current liabilities, pending the disposition
of such differences through reconciliation provisions provided in the energy
adjustment clauses.
_________________________________________________________________
(E) Nuclear Fuel Costs
Included as a part of the cost of nuclear fuel is a provision for its
estimated disposal cost which is being recognized at a rate of 1 mill per
kilowatt-hour of nuclear generation in conformance with DOE rules. Such
amounts are recoverable through the energy adjustment clauses.
_________________________________________________________________
(F) Allowance for Funds Used During Construction
The allowance for funds used during construction (AFUDC) includes the
costs of equity and borrowed funds used to finance construction which are
capitalized in accordance with rules prescribed by the FERC. The FERC's
Uniform System of Accounts defines AFUDC as the net cost of borrowed funds used
for construction and a reasonable rate to reflect the costs of other funds so
used. Under FERC rules, if average short-term debt outstanding exceeds average
construction work in progress (CWIP), all CWIP is assumed to have been financed
with short-term debt. This situation arose in 1993, 1992 and 1991, when the
Company's AFUDC rates were 3.3%, 3.8% and 6.0%, respectively, compounded semi-
annually. While currently capitalized AFUDC does not represent a current
source of cash, it does represent a basis for future sources of cash through
the inclusion in rates of depreciation charges and allowance for returns on
investment.
_________________________________________________________________
(G) Depreciation
Depreciation is computed using the straight-line method. Provisions for
depreciation, expressed as an annual percentage of the cost of average
depreciable plant in service, were as follows for the periods shown:
Year Ended Dec. 31,
1993 1992 1991
Electric........................ 4.2% 4.0% 3.7%
Gas............................. 4.0 3.8 3.7
An allowance for the estimated decommissioning costs of the Quad-Cities
Nuclear Power Station (Quad-Cities) is included in depreciation expense. The
Company's share of the cost to decommission the Quad-Cities units is estimated
to be $172.7 million in 1993 dollars. Such decommissioning costs include the
cost of decontamination, dismantlement and site restoration in accordance with
Nuclear Regulatory Commission guidelines. Electric tariffs included provisions
for the costs of nuclear decommissioning of $7.9 million, $5.0 million and $1.7
million for 1993, 1992 and 1991, respectively.
The Company has established an external trust for the investment of funds
collected for nuclear decommissioning. Electric tariffs for 1994 include
provisions for annual decommissioning costs of approximately $9.1 million. In
Illinois, nuclear decommissioning costs are included in customer billings
through a mechanism which permits annual adjustments. In Iowa, such costs are
reflected in base rates.
_________________________________________________________________
(H) Scheduled Nuclear Refueling Outage Costs
Incremental operation and maintenance costs due to scheduled nuclear
refueling outages are accrued, based upon the planned outage schedules and the
estimated costs for such outages, over the estimated periods (approximately
eighteen months) between scheduled outages. Any differences between accrued
and actual outage costs are expensed in the periods in which the outages occur.
_________________________________________________________________
(I) Marketable Securities
InterCoast's holdings of preferred stocks, common stocks and mutual funds
are stated at the lower of aggregate cost or market. A decline in the market
value of marketable equity securities below their cost basis is recognized in
the consolidated financial statements through the establishment of a valuation
allowance which is reflected as a reduction of shareholders' equity. An other
than temporary decline in the value of a marketable security is recognized
through a write-down or write-off of the investment.
In May 1993, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 115, Accounting for Certain Investments in
Debt and Equity Securities (SFAS 115). This statement requires that equity
securities with readily determinable fair values and all debt securities be
classified into one of the following three categories: 1) Trading securities,
2) Available-for-Sale securities or 3) Held-to-Maturity securities. The
Company will adopt SFAS 115 in 1994. It is anticipated that such adoption will
not have a material effect on financial position or results of operations.
_______________________________________________________________
(J) Oil and Gas
InterCoast uses the full cost method of accounting for oil and gas
drilling operations. Under the full cost method, all exploration and
development costs are capitalized and amortized over the estimated production
from proved oil and gas reserves. Under the full cost method, net capitalized
costs may not exceed the present value of proved reserves as determined under
the rules of the Securities and Exchange Commission.
_________________________________________________________________
(K) Consolidated Statements of Cash Flows
For purposes of the Consolidated Balance Sheets and the Consolidated
Statements of Cash Flows, the Company considers all highly liquid debt
instruments held which have original maturities of three months or less to be
cash equivalents. No material non-cash investing or financing transactions
occurred during 1993, 1992 or 1991.
_________________________________________________________________
(L) Reclassification
Certain 1991 and 1992 amounts have been reclassified to conform to the
current year presentation.
_________________________________________________________________
(2) Rate Matters:
(A) Iowa Rate Filing
On May 3, 1993, the Company filed revised electric rates with the IUB
designed to increase annual electric revenues by approximately $13.5 million
(7.5%) and to provide for any increase in the federal corporate income tax rate
ultimately enacted. A temporary annual rate increase of $6.8 million (3.8%)
became effective July 26, 1993. In 1993, approximately $3.1 million was
billed, subject to refund, pursuant to such temporary rates. In February 1994,
the IUB approved rates at the $6.8 million level.
_________________________________________________________________
(B) Illinois Rate Filings
On Sept. 1, 1992, the Company filed revised electric and gas rates with
the ICC to increase annual electric and gas revenues by approximately $14
million (12%) and $3 million (5.9%), respectively. On July 28, 1993, electric
and gas increases of $9.6 million (8.6%) and $2 million (3.7%), respectively,
became effective following ICC approval. On Jan. 15, 1994, additional electric
and gas increases of $230,000 (0.2%) and $49,000 (0.1%), respectively, related
to the increase in the federal corporate income tax rate became effective
following ICC approval on rehearing. The ICC also approved electric and gas
riders which permit the Company to recover costs of litigation, investigation
and remediation relating to former manufactured gas plant sites.
_________________________________________________________________
(C) Federal Gas Transition Costs
In April 1992, the FERC issued Order No. 636, directing a restructuring by
interstate pipeline companies for their natural gas sales and transportation
services. The FERC Order contemplated that transitional gas supply realignment
costs relating to this restructuring may be billed by interstate pipelines to
their customers. The amount of transition costs which the FERC may ultimately
authorize the pipelines to bill the Company is estimated to be $35 to $50
million. The Company expects to be allowed to include provisions for such
costs in its customer billings.
_________________________________________________________________
(3) InterCoast Energy Company:
InterCoast is a wholly owned, non-regulated subsidiary of the Company.
The business strategy of InterCoast is focused on areas closely related to the
Company's core electric and gas utility businesses. These activities are: oil
and natural gas, energy services and financial investments.
Condensed consolidated financial information of InterCoast and its
subsidiaries follows.
Consolidated Statements of Income
Year Ended Dec. 31,
1993 1992 1991
(In thousands)
Income:
Oil and gas revenues.......... $54,979 $28,478 $ 6,740
Dividends and interest........ 19,103 18,917 16,307
Realized gains................ 3,289 4,261 3,464
Other income.................. 6,713 4,172 6,579
Total income.................... 84,084 55,828 33,090
Expenses:
Oil and gas................... 38,749 20,285 4,911
Interest...................... 24,573 20,994 17,694
Other expenses................ 8,885 6,240 3,789
Provision for income taxes.... ( 624) ( 1,168) ( 697)
Total expenses.................. 71,583 46,351 25,697
Net income...................... $12,501 $ 9,477 $ 7,393
Consolidated Balance Sheets
Dec. 31,
1993 1992
(In thousands)
Current assets.................. $ 21,926 $ 20,978
Investments:
Marketable securities......... 233,386 234,772
Oil and gas................... 120,952 60,334
Equipment leases.............. 59,937 58,831
Energy projects............... 48,777 46,817
Special purpose funds......... 36,021 35,723
Other......................... 2,756 5,672
Total investments............... 501,829 442,149
Other assets.................... 2,961 3,008
Total assets.................... 526,716 466,135
Long-term debt maturing
within one year............... 59,000 8,000
Other current liabilities....... 20,682 13,869
Long-term debt.................. 242,500 257,000
Accumulated deferred income
taxes......................... 59,433 55,253
Shareholder's equity............ 145,101 132,013
Total liabilities and
shareholder's equity.......... $526,716 $466,135
InterCoast is subject to certain restrictions under the terms of its
borrowing arrangements. Such restrictions include provisions which limit the
amounts that can be expended for dividends. At Dec. 31, 1993 and 1992, $16.5
million and $7.1 million, respectively, of InterCoast's equity was available
for dividends.
_________________________________________________________________
(4) Income Taxes:
The IUB has primarily limited the use of deferred income tax accounting to
federal income taxes deferred as a result of the use of accelerated tax
depreciation, as mandated by the normalization provisions of the Internal
Revenue Code. The ICC, however, generally permits deferral of the tax effect
of all book and tax differences.
Investment tax credits (ITC) on the Company's investments in utility plant
have been deferred and are being amortized to income over the life of the
related property.
In 1993 and prior years, additional current income tax liability resulted
and accumulated deferred income tax benefits have been recorded due to the
application of federal and state Alternative Minimum Tax (AMT). The
accumulated provision for these additional taxes at Dec. 31, 1993, in the
amounts of $32.3 million in federal AMT and $5.5 million in state AMT,
represents AMT credits which may be carried forward indefinitely to offset
future regular tax liabilities.
On Jan. 1, 1993, the Company adopted Statement of Financial Accounting
Standards No. 109, Accounting for Income Taxes (SFAS 109). This statement
requires recognition of deferred income tax assets and liabilities, based on
enacted tax laws, for all temporary differences between the financial reporting
and tax bases of assets and liabilities. The portion of the Company's deferred
tax liability applicable to utility operations which has not been reflected in
service rates represents income taxes recoverable through future rates. On a
consolidated basis, the adoption of SFAS 109 on Jan. 1, 1993 increased deferred
income tax liabilities by $42.3 million and resulted in the establishment of a
net regulatory asset of $43 million. On a consolidated basis, the cumulative
effect on net income of the change in accounting principle was immaterial.
Income tax expense is reflected in the Consolidated Statements of Income
as follows:
Year Ended Dec. 31,
1993 1992 1991
(In thousands)
Included in Operating Expenses:
Current -Federal............. $16,398 $12,607 $24,756
-State............... 4,429 3,464 6,823
Deferred -Federal............. 5,318 2,532 ( 3,030)
-State............... 539 43 ( 804)
Deferred federal ITC, net..... ( 2,207) ( 2,326) ( 2,385)
Total included in Operating
Expenses.................... 24,477 16,320 25,360
Included in Other Income........ ( 666) ( 1,763) ( 1,262)
Total income tax expense........ $23,811 $14,557 $24,098
The components of the net deferred tax liability are as follows:
Dec. 31, 1993
(In thousands)
Accelerated depreciation methods.............. $ 267,942
Income taxes recoverable through future rates. 75,212
AMT credit carryforward....................... ( 37,756)
Deferred ITC refundable through future rates.. ( 24,641)
Nuclear reserves and decommissioning.......... ( 6,708)
Other deferred taxes, net..................... 556
Accumulated deferred income taxes............. $ 274,605
The following is a reconciliation of the statutory federal income tax rate
to the overall effective income tax rate (computed by dividing income taxes,
including income tax amounts applicable to other income, by net income before
the deduction of such taxes):
Year Ended Dec. 31,
1993 1992 1991
Statutory federal income
tax rate...................... 35.0% 34.0% 34.0%
State income taxes, net of
federal income tax benefit.... 4.7 3.3 4.6
Investment and energy tax
credits....................... ( 2.7) ( 3.9) ( 3.1)
Excess of book depreciation over
tax depreciation not deferred. 1.6 2.2 2.6
Dividends received deduction.... ( 5.2) ( 6.9) ( 4.3)
Adjustment for method of
deducting property taxes...... ( 1.4) ( 2.0) ( 1.5)
Other items, net................ ( 3.3) ( 2.4) ( 1.6)
Overall effective income
tax rate...................... 28.7% 24.3% 30.7%
_________________________________________________________________
(5) Pensions and Other Employee Benefits:
The Company has a noncontributory defined benefit retirement income plan
covering substantially all regular employees. Benefits under the plan are
based on participants' compensation, years of service and age at retirement.
Funding is based upon the actuarially determined costs of the plan and the
requirements of the Internal Revenue Code and the Employee Retirement Income
Security Act.
Provisions for pension costs are determined under generally accepted
accounting principles, which include the use of the projected unit credit
actuarial cost method. A regulatory adjustment has been made to the pension
cost amounts to reflect only the amount of pension cost recognized through the
ratemaking process. Net pension cost, part of which was charged to utility
plant or billed to others, was $562,000 in 1993, $175,000 in 1992 and $67,000
in 1991. The components of the 1993, 1992 and 1991 pension cost provisions are
as follows:
Year Ended Dec. 31,
1993 1992 1991
(In thousands)
Cost of benefits earned during
the year...................... $ 3,283 $ 2,769 $ 2,434
Interest on projected benefit
obligation.................... 10,480 9,519 8,944
Actual investment return on
plan assets................... (17,009) (12,340) (13,224)
Net amortization and deferral... 4,712 548 2,034
Pension cost.................... 1,466 496 188
Regulatory adjustment........... ( 904) ( 321) ( 121)
Net pension cost................ $ 562 $ 175 $ 67
The expected long-term rate of return on plan assets used in determining
pension cost was 8.75% for 1993, 1992 and 1991.
A reconciliation of plan assets and liabilities to the accrued pension
costs included in the Consolidated Balance Sheets is presented below:
Dec. 31,
1993 1992
(In thousands)
Fair market value of pension plan
assets, invested primarily in
equity and fixed-income
securities.................... $151,134 $140,038
Actuarial present value of
benefits for services
rendered to date:
Accumulated benefits to date,
including vested benefits
of $118,300 and $92,318
for 1993 and 1992,
respectively.............. 122,221 96,382
Additional benefits based
on estimated future
compensation levels....... 29,478 35,859
Projected benefit obligation.... 151,699 132,241
Plan assets in excess of (or less
than) projected benefit
obligation.................... ( 565) 7,797
Unamortized balance of plan net
assets existing at Jan. 1, 1986,
being amortized over 17 years. ( 10,305) ( 11,450)
Unrecognized prior service cost. 18,849 20,327
Unrecognized net gain........... ( 10,492) ( 17,721)
Accrued pension cost............ $( 2,513) $( 1,047)
Assumed discount rate........... 7.0% 8.0%
Assumed rate of increase in
future compensation levels.... 5.0% 6.0%
The Company currently provides certain health care and life insurance
benefits for retired employees. Substantially all of the Company's employees
become eligible for these additional benefits if they reach retirement age
while employed by the Company.
On Jan. 1, 1993, the Company adopted Statement of Financial Accounting
Standards No. 106, Employers' Accounting for Postretirement Benefits Other Than
Pensions (SFAS 106). SFAS 106 requires accrual of the expected cost of
providing postretirement benefits other than pensions to employees over the
years the employees are expected to render the necessary service.
The Company, as permitted by SFAS 106, has elected to amortize to expense
over 20 years the $13.6 million accumulated postretirement benefit obligation
at Jan. 1, 1993. Prior to 1993, the Company recognized the costs associated
with postretirement benefits other than pensions in the year that the benefits
were paid. The incremental effect of this change in accounting was to increase
1993 annual operating expenses before income taxes by approximately $1.4
million.
For its Iowa operations, the Company began including provisions for these
costs in its customer rates in January 1993. For its Illinois operations, the
Company began including provisions for these costs in its customer rates in
July 1993. The Company is externally funding all such provisions.
The components of the 1993 net postretirement benefits other than pensions
cost provision are as follows:
Year Ended Dec. 31,
1993
(In thousands)
Cost of benefits earned
during the year.................. $ 474
Interest on accumulated
postretirement benefit
obligation....................... 1,061
Actual investment return
on plan assets................... ( 6)
Net amortization and deferral...... 688
Net postretirement benefits
other than pensions cost......... $ 2,217
A reconciliation of such postretirement benefit plan assets and
liabilities to the amounts included in the Consolidated Balance Sheets is
presented below:
Dec. 31, Jan. 1,
1993 1993
(In thousands)
Fair market value of plan assets,
invested primarily in short-
term securities.................. $ 976 $ -
Actuarial present value of
benefits for services
rendered to date:
Active plan participants........ 6,941 6,721
Fully eligible plan participants 2,321 3,097
Retirees........................ 3,792 3,828
Accumulated postretirement
benefit obligation............... 13,054 13,646
Accumulated postretirement
benefit obligation in excess
of plan assets................... (12,078) (13,646)
Unamortized balance of plan
obligation existing at
Jan. 1, 1993, being amortized
over 20 years.................... 12,829 13,646
Unrecognized net gain.............. ( 751) -
Accrued postretirement benefit
other than pensions cost......... $ - $ -
For measurement purposes, the health care cost trend rate assumed for pre-
65 coverage is 13% for 1994, decreasing 1% per year to 5% in 2002 and
thereafter. The health care cost trend rate assumption has a significant
effect on the amounts reported. To illustrate, increasing the assumed health
care cost trend rates by one percentage point in each year would increase the
accumulated postretirement benefit obligation for health care costs as of Dec.
31, 1993 by $924,000 and the aggregate of the 1993 service and interest cost
components of net postretirement health care cost by $137,000. The discount
rate used was 7%.
The Company has adopted voluntary Compensation Deferral and Supplemental
Retirement plans for designated executives. Such plans are unfunded and the
liabilities thereunder are payable from general funds of the Company. To
provide for its liabilities under these plans, the Company has purchased, owns
and is the beneficiary of life insurance policies on the lives of participating
executives. Returns on such policies are expected to cover the full cost of
the related plans.
In November 1992, the FASB issued Statement of Financial Accounting
Standards No. 112, Employers' Accounting for Postemployment Benefits (SFAS
112), which will require the Company to accrue the estimated cost of benefits
provided to former or inactive employees after employment but before
retirement. The Company will adopt SFAS 112 in 1994. Adoption will not have a
material effect on financial position or results of operations.
_________________________________________________________________
(6) Jointly Owned Generating Stations:
Under joint ownership agreements with other utility companies, the Company
has undivided interests in one nuclear and four coal-fired electric generating
stations. Information concerning each of the jointly owned stations follows:
Nuclear Coal-fired
Council
Quad-Cities Neal Bluffs Ottumwa Louisa
Units Unit Unit Unit Unit
No. 1 & 2 No.3 No.3 No.1 No.1
In service date..... 1972 1975 1978 1981 1983
Company share of
utility plant in
service (in
millions)......... $193.0 $49.1 $124.1 $73.7 $259.9
Total plant capacity
-megawatts........ 1,539 515 675 708 650
Company share
-percent.......... 25% 29% 32.4% 18.5% 43%
The Consolidated Financial Statements reflect the Company's portions of
all plant investments and all operating costs associated with these units.
Depreciation reserves by individual station are not maintained.
Although the Louisa Unit No. 1 is operated and maintained by the Company,
each of the other units is operated and maintained by another utility company.
Each participant has provided the financing for its share of the total
investment in each project.
________________________________________________________________
(7) Inventories:
Inventories include the following amounts:
Dec. 31,
1993 1992
(In thousands)
Materials and supplies,
at average cost............ $15,151 $14,683
Coal stocks, at Last-In,
First-Out (LIFO) cost...... 6,385 11,263
Fuel oil, at average cost......... 249 348
Gas in storage, at LIFO cost...... 13,812 13,853
$35,597 $40,147
At Dec. 31, 1993 prices, the current costs of coal stocks and gas in
storage were $7.5 million and $30.5 million, respectively.
_________________________________________________________________
(8) Fair Value of Financial Instruments:
The following methods and assumptions were used to estimate the fair value
at Dec. 31, 1993 of each class of financial instruments for which it is
practicable to make such estimates. Tariffs for the Company's utility services
are established based on historical cost ratemaking and therefore the impact of
any realized gains or losses related to financial instruments applicable to the
Company's utility operations is dependent on the treatment authorized under
future ratemaking proceedings.
Cash and cash equivalents - The carrying amount approximates fair value
due to the short maturity of these instruments.
Nuclear decommissioning trust fund - Fair value is based on quoted market
prices of the investments held by the fund.
Marketable securities - Fair value is based on quoted market prices.
Debt securities - Fair value is based on the discounted value of the
future cash flows expected to be received from such investments.
Equity investments carried at cost - Fair value is based on an estimate of
the Company's share of partnership equity or on the discounted value of the
future cash flows expected to be received from such investments.
Equity investments in developing companies - It is not practicable to
determine the fair value of such investments as they represent new ventures for
which no market price exists.
Notes payable - Fair value is estimated to be the carrying amount due to
the short maturity of these issues.
Preference shares - Fair value of preference shares with mandatory
redemption provisions is estimated based on the quoted market prices for
similar issues.
Long-term debt - Fair value of long-term debt is estimated based on the
quoted market prices for the same or similar issues or on the current rates
offered to the Company for debt of the same remaining maturities.
Dec. 31, 1993 Dec. 31, 1992
Carrying Fair Carrying Fair
Amount Value Amount Value
(In thousands)
Electric and gas utility:
Nuclear decommissioning
trust fund........... $ 39,470 $ 41,588 $ 29,675 $ 30,417
Preference shares,
including
current portion...... 50,000 54,850 49,200 52,511
Long-term debt,
including
current portion...... 372,132 384,954 333,840 347,807
InterCoast Energy Company:
Marketable securities.. 233,386 239,114 236,251 239,132
Debt securities........ 14,195 16,124 12,184 11,956
Equity investments
carried at cost...... 27,141 27,789 25,540 23,983
Long-term debt,
including
current portion...... 301,500 317,700 265,000 277,625
_________________________________________________________________
(9) Common Shareholders' Equity:
Changes in the Company's outstanding common shares for the years 1993,
1992 and 1991 are as follows:
Year Ended Dec. 31,
Amount
1993 1992 1991
(In thousands)
Outstanding, beginning of year. $280,055 $220,819 $221,397
Public sale of shares........ - 61,563 -
Capital stock expense........ (122) ( 2,392) ( 451)
Treasury shares
Purchased.................. (689) ( 632) ( 653)
Reissued................... 765 697 526
Outstanding, end of year....... $280,009 $280,055 $220,819
Shares
1993 1992 1991
Outstanding, beginning of year. 29,349,177 26,845,687 26,851,424
Public sale of shares........ - 2,500,000 -
Treasury shares
Purchased.................. (31,100) ( 25,000) ( 30,110)
Reissued................... 34,096 28,490 24,373
Outstanding, end of year....... 29,352,173 29,349,177 26,845,687
The components of Other Common Shareholders' Equity are as follows:
Dec. 31,
1993 1992
(In thousands)
Premium on Preferred shares.... $ 32 $ 32
Valuation allowance............ - ( 587)
$ 32 $( 555)
The Company has a Dividend Reinvestment Plan and an Employee Stock
Purchase Plan. The purchase of common shares under these Plans is made on the
open market. At Dec. 31, 1993 and 1992, 439 and 3,435 treasury shares
acquired in the open market for the Employee Stock Purchase Plan were held for
reissuance.
_________________________________________________________________
(10) Long-Term Debt, Maturities and Sinking Fund Requirements:
The 1993 sinking fund requirements for First Mortgage Bonds and Senior
Notes were satisfied through the reacquisition of debt or the bonding of
additional property. The aggregate maturities and sinking fund requirements
for long-term debt outstanding at Dec. 31, 1993 are as follows:
1994 1995 1996 1997 1998
(In thousands)
First Mortgage Bonds. $ 220 $ 220 $ 220 $47,200 $50,200
Pollution Control
Obligations........ 232 145 145 145 145
Senior Notes of
InterCoast Energy
Company............ 59,000 64,000 39,000 30,000 20,000
Unsecured Revolving
Credit Facility of
InterCoast Energy
Company............ - - 44,500 - -
Total................ $59,452 $64,365 $83,865 $77,345 $70,345
Included in the above amounts are sinking fund requirements related to
First Mortgage Bonds of $220,000 for each of the years 1994 through 1996, which
may be reduced by certifying net property additions not previously bonded, in
accordance with the terms of the Company's Indenture of Mortgage securing its
First Mortgage Bonds.
The interest rate on the Company's Adjustable Rate Series First Mortgage
Bonds is reset every two years at 160 basis points over the average yield to
maturity of 10-year Treasury securities. The rate was reset in 1993.
The Company's Variable Rate Pollution Control Obligations bear interest at
rates which are periodically established through remarketing of the bonds in
the short-term tax-exempt market. The Company, at its option, may change the
mode of interest calculation for these bonds by selection from among several
alternative floating or fixed rate modes. The interest rates shown in the
Consolidated Statements of Capitalization are the weighted average interest
rates as of Dec. 31, 1993 and 1992. The Company maintains backup long-term
letters of credit providing liquidity for holders of the $29.5 million and $3.9
million issues and a dedicated long-term revolving line of credit for holders
of the $4.2 million and $6.85 million issues.
The Company's First Mortgage Bonds are secured by substantially all fixed
property and franchises of the Company devoted to its utility businesses.
InterCoast's unsecured Senior Notes (Notes) are issued in private
placement transactions. All Notes are issued without recourse to the parent
Company.
In January 1994, InterCoast renegotiated its unsecured revolving credit
facility agreement. The renegotiation increased the amount of capital
available from $65 million to $110 million. The amended credit agreement
matures Feb. 14, 1996. Borrowings under this agreement may be on a fixed rate,
floating rate or competitive bid rate basis. All such borrowings are without
recourse to the parent Company. Borrowings at Dec. 31, 1993 were $44.5 million
at a weighted average interest cost of 4.1%. No such borrowings were
outstanding at Dec. 31, 1992.
_________________________________________________________________
(11) Redeemable Preference Shares:
The $5.25 Series Preference Shares, which are not redeemable prior to Nov.
1, 1998 for any purpose, are subject to mandatory redemption on Nov. 1, 2003 at
$100 per share. The $7.80 Series Preference Shares have sinking fund
requirements under which 66,600 shares will be redeemed at $100 per share each
May 1, beginning in 2001 through May 1, 2006.
_________________________________________________________________
(12) Notes Payable:
The Company's notes payable reflect borrowings which have been obtained
solely through its short-term commercial paper program. Information regarding
short-term debt follows:
1993 1992 1991
(Dollars in thousands)
Balance at year-end............. $31,000 $52,500 $52,500
Weighted average interest rate
on year-end balance........... 3.4% 3.6% 5.0%
Maximum amount outstanding
during the year............... $73,000 $77,000 $52,500
Average daily amount outstanding
during the year............... $43,291 $39,973 $26,255
Weighted average interest rate
on average daily amount
outstanding during the year... 3.3% 3.8% 6.0%
At Dec. 31, 1993, the Company had bank lines of credit of $72.8 million
to provide short-term financing for its utility operations. All such lines of
credit were unused. The Company generally maintains compensating balances
under its bank line of credit arrangements. The Company has regulatory
authority to incur up to $100 million of short-term debt for its utility
operations.
_________________________________________________________________
(13) Leases:
The Company has capitalized lease obligations for certain transmission
lines and other property, all of which are accounted for as operating leases in
the Consolidated Statements of Income pursuant to ratemaking practices.
Components of rent expense are as follows:
Year Ended Dec. 31,
1993 1992 1991
(In thousands)
Capital leases
Interest...................... $1,002 $1,037 $1,026
Amortization of utility
plant....................... 421 387 391
Total capital leases.......... 1,423 1,424 1,417
Operating leases................ 590 517 399
Total rent expense.............. $2,013 $1,941 $1,816
At Dec. 31, 1993, the future minimum lease payments under noncancelable
operating and capital leases are as follows:
Obligation
Operating Under
Leases Capital Leases
(In thousands)
1994........................... $ 575 $ 1,423
1995........................... 563 1,423
1996........................... 462 1,423
1997........................... 292 1,326
1998........................... 283 1,133
After 1998..................... 759 12,234
Total minimum lease payments... $ 2,934 18,962
Less amount representing interest............ 8,469
Present value of minimum lease payments...... $ 10,493
_________________________________________________________________
(14) Commitments and Contingencies:
Utility construction expenditures in 1994 are estimated at $87.6 million,
including $8.9 million for nuclear fuel. The forecasted 1994 capital
expenditures for InterCoast are $82.6 million. Actual expenditures are
dependent on overall InterCoast performance and general market conditions.
The Company is investigating five properties currently owned by the
Company which were, at one time, sites of gas manufacturing plants. The
purpose of these investigations 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. One site is
located in Illinois and four sites are located in Iowa. With regard to the
Illinois property, the Company has signed a working agreement with the Illinois
Environmental Protection Agency to perform further investigation to determine
whether waste materials are present and, if so, whether such materials
constitute an environmental or health risk. At Dec. 31, 1993, an estimated
liability of $3.4 million has been recorded for litigation, investigation and
remediation related to the Illinois site. A regulatory asset has been recorded
reflecting anticipated cost recovery through rates in Illinois. With regard to
the Iowa sites, no agreement or consent order has been negotiated to perform
any site investigations or remediation. The Company has recorded a $4 million
estimated liability for the Iowa sites. A regulatory asset has been recorded
based on the current regulatory treatment of comparable costs in Iowa. The
estimated recorded liabilities for these properties are based upon preliminary
data. Thus, actual costs could vary significantly from the estimates. In
addition, insurance recoveries for some or all of the costs may be possible,
but the liabilities recorded have not been reduced by any estimate of such
recoveries. Although the timing of incurred costs, recoveries and the
inclusion of provision for such costs 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.
Clean Air Act legislation was signed into law in November 1990 and U.S.
Environmental Protection Agency rulemaking proceedings are underway. The
Company has four jointly and one wholly owned coal-fired generating stations
which represent approximately 65% of the Company's electric generating
capability. Each of these facilities will be impacted to varying degrees by
the legislation.
Only one unit at the wholly owned generating station, representing
approximately 10% of the Company's electric generating capability, will be
impacted by the emission reduction requirements effective in 1995. The
compliance strategy for this unit includes modifications to allow for burning
low sulfur coal, modifications for nitrogen oxide control and installation of
a new emission monitoring system. The Company's remaining construction
expenditures relative to this work are estimated to be $5.4 million.
The four generating stations not affected until 2000 already burn low
sulfur coal, so additional capital costs will not be incurred for sulfur
dioxide emission reduction requirements. Installation of low nitrogen oxide
burners is required at one of these facilities and existing emission monitoring
systems at all four facilities will require upgrading. The Company's remaining
construction cost for this work is estimated to be $2.1 million.
It is anticipated that any costs incurred by the Company to comply with
the Clean Air Act legislation would be included in the cost of service on which
the Company's rates for utility service are based.
The Company is a member of Nuclear Mutual Limited (NML), an industry
mutual insurer established to provide property damage coverage for members'
nuclear generating facilities. The Company would be subject to a maximum
retrospective premium assessment of approximately $2.4 million based on its 25%
share of the NML premium for Quad-Cities coverage in the event covered losses
of NML members exceed the financial resources of the insurance company. A
reserve has been established for this contingency. At Dec. 31, 1993, NML had
accumulated capital to a level which would assure that the Company would have
no exposure to a retrospective premium assessment in the event of a single
incident to a member's facility.
The Company is also a member of Nuclear Electric Insurance Limited (NEIL),
an industry mutual insurance company, and an insured of American Nuclear
Insurers/Mutual Atomic Energy Liability Underwriters (ANI/MAELU). The related
policy provisions provide that expenses for decontamination and the removal of
debris shall be paid before any payment in respect of claims for property
damage. A separate NEIL insurance policy covers the extra costs which would be
incurred in obtaining replacement power during a prolonged covered outage of a
member's nuclear plant. The Company is subject to retrospective premium
assessments of up to $4 million and $685,000 for its 25% share of the premium
under the NEIL portion of the excess property damage coverage and the
replacement power coverage, respectively. At Dec. 31, 1993, NEIL had
accumulated capital to a level which would assure that the Company would have
no exposure to a retrospective premium assessment in the event of a single
incident to a member's facility.
A Master Worker Policy issued by ANI/MAELU provides coverage for worker
tort claims filed for bodily injury caused by the nuclear energy hazard. The
coverage applies to workers whose "nuclear related employment" began after Jan.
1, 1988. Under this policy, the Company could be subject to a maximum
retrospective premium assessment of $1.5 million.
Under the Price-Anderson federal legislation adopted in 1988, nuclear
public liability coverage is supported by a mandatory industry-wide program
under which owners of nuclear generating facilities could be assessed in the
event of nuclear incidents. The Company would currently be subject to a
maximum assessment of $39.6 million in the event of an incident, to be paid in
increments of no more than $5 million per year per incident.
_________________________________________________________________
(15) Segment Information:
Information related to segments of the Company's business is as follows:
Year Ended Dec. 31,
1993 1992 1991
(In thousands)
Operating information
Electric-
Operating revenues.......... $ 338,593 $ 312,667 $ 331,577
Operating expenses
excluding income taxes.... 257,493 245,753 240,978
Pre-tax operating income.... 81,100 66,914 90,599
Income taxes................ 20,171 12,959 22,328
Operating income............ 60,929 53,955 68,271
Allowance for funds used
during construction
(AFUDC)................... 886 1,019 1,375
Operating income and AFUDC.. 61,815 54,974 69,646
Depreciation expense........ 50,379 46,236 41,288
Depreciation and equity
funds recovered under
Louisa Phase-In
Clause (LPIC)............. 2,370 4,515 4,086
Total depreciation expense.. 52,749 50,751 45,374
Capital expenditures........ 49,976 52,922 46,484
Gas-
Operating revenues.......... 206,821 184,867 180,960
Operating expenses
excluding income taxes.... 192,061 171,960 170,889
Pre-tax operating income.... 14,760 12,907 10,071
Income taxes................ 4,306 3,361 3,032
Operating income............ 10,454 9,546 7,039
AFUDC....................... 93 85 73
Operating income and AFUDC.. 10,547 9,631 7,112
Depreciation expense........ 8,268 7,705 7,213
Capital expenditures........ 16,981 20,776 15,068
InterCoast Energy Company-
Income...................... 84,084 55,828 33,090
Expenses excluding
income taxes.............. 72,207 47,519 26,394
Pre-tax operating income.... 11,877 8,309 6,696
Depreciation, depletion
and amortization.......... 13,920 9,267 3,536
Capital expenditures........ $ 68,147 $ 64,096 $ 93,161
Dec. 31,
1993 1992 1991
(In thousands)
Asset information
Identifiable assets-
Electric (a)................ $ 997,861 $ 945,845 $ 921,167
Gas (a)..................... 236,406 216,592 186,886
Used in overall utility
operations................ 32,580 30,799 31,757
InterCoast Energy Company... 526,716 466,135 391,102
Total assets.................. $1,793,563 $1,659,371 $1,530,912
(a) Utility plant less accumulated provision for depreciation, accounts
receivable, accrued unbilled revenues, inventories, deferred gas expense,
energy adjustment clause balance, nuclear decommissioning trust fund and
regulatory assets.
_________________________________________________________________
(16) Quarterly Results (Unaudited):
1993 Quarter Ended
Dec. Sept. June March
31 30 30 31
(In thousands, except per share amounts)
Operating revenues....... $141,210 $127,720 $114,614 $161,870
Operating income......... 10,592 23,871 16,608 20,312
Net income on common
shares................. 7,215 17,921 12,099 16,998
Net income per average
common share
outstanding............ $ .25 $ .61 $ .41 $ .58
1992 Quarter Ended
Dec. Sept. June March
31 30 30 31
(In thousands, except per share amounts)
Operating revenues....... $142,225 $112,542 $107,380 $135,387
Operating income......... 12,974 19,060 15,995 15,472
Net income on common
shares................. 7,008 13,258 9,164 10,974
Net income per average
common share
outstanding............ $ .24 $ .46 $ .34 $ .41
The quarterly data reflect seasonal variations common in the utility
industry.
Report of Management
Management is responsible for the preparation of all information contained
in this Annual Report, including the financial statements. The statements and
related financial information have been prepared in conformity with generally
accepted accounting principles. In the opinion of management, the financial
position, results of operation and cash flows of the Company are reflected
fairly in the statements. The statements have been audited by the Company's
independent public accountants, Deloitte & Touche, whose report appears below.
The Company maintains a system of internal controls which is designed to
provide reasonable assurance, on a cost effective basis, that transactions are
executed in accordance with management's authorization, the financial
statements are reliable and the Company's assets are properly accounted for and
safeguarded. The Company's internal auditors continually evaluate and test the
system of internal controls and actions are taken when opportunities for
improvement are identified. Management believes that the system of internal
controls is effective.
The financial statements have been reviewed by the Audit Committee of the
Board of Directors. The Audit Committee, the members of which are directors
who are not employees of the Company, meets regularly with management, the
internal auditors and Deloitte & Touche to discuss accounting, auditing,
internal control and financial reporting matters. The Company's independent
public accountants are appointed annually by the Board of Directors on
recommendation of the Audit Committee. The internal auditors and Deloitte &
Touche each have full access to the Audit Committee, without management
representatives present.
/s/S. J. Bright
S. J. Bright
Chairman and Chief Executive Officer
/s/L. E. Cooper
L. E. Cooper
Vice President-Finance and Chief Financial Officer
Independent Auditor's Report
To the Shareholders and Board of Directors of Iowa-Illinois Gas and Electric
Company:
We have audited the accompanying consolidated balance sheet and statement
of capitalization of Iowa-Illinois Gas and Electric Company and subsidiary as
of December 31, 1993, and the related consolidated statements of income,
retained earnings, and cash flows for the year then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit. The consolidated financial statements of the companies for the
years ended December 31, 1992 and 1991 were audited by other auditors whose
report, dated January 28, 1993, expressed an unqualified opinion on those
statements.
We conducted our audit 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 audit provides a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the companies as of December
31, 1993, and the results of their operations and their cash flows for the year
then ended in conformity with generally accepted accounting principles.
As discussed in Note 4 and Note 5 to the consolidated financial
statements, the companies changed their method of accounting for income taxes
and postretirement benefits other than pensions effective January 1, 1993.
/s/DELOITTE & TOUCHE
DELOITTE & TOUCHE
Davenport, Iowa
January 26, 1994