<PAGE> 1
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
-------------- ---------------
------------------------------
Commission file number 1-3187
HOUSTON INDUSTRIES INCORPORATED
(FORMERLY HOUSTON LIGHTING & POWER COMPANY)
(Exact name of registrant as specified in its charter)
Texas 74-0694415
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1111 Louisiana
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
(713) 207-3000
(Registrant's telephone number, including area code)
------------------------------
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ----
As of October 31, 1997, Houston Industries Incorporated had 295,070,776 shares
of common stock outstanding, including 12,388,551 ESOP shares not deemed
outstanding for financial statement purposes and excluding 70,652 shares held as
treasury stock.
------------------------------
On August 6, 1997, Houston Industries Incorporated, the former parent
corporation of the registrant (Former HI), merged with and into Houston Lighting
& Power Company, which was renamed "Houston Industries Incorporated" on the date
of the merger. Pursuant to the merger, each outstanding share of Former HI
common stock was converted into one share of the registrant's common stock
(including associated preference stock purchase rights).
<PAGE> 2
HOUSTON INDUSTRIES INCORPORATED
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 1997
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Part I. Financial Information Page No.
<S> <C>
Item 1. Financial Statements
Statements of Consolidated Income
Three Months and Nine Months Ended
September 30, 1997 and 1996 3
Consolidated Balance Sheets
September 30, 1997 and December 31, 1996 4
Statements of Consolidated Cash Flows
Nine Months Ended September 30, 1997 and 1996 6
Statements of Consolidated Retained Earnings
Three Months and Nine Months Ended
September 30, 1997 and 1996 8
Notes to Consolidated Financial Statements 9
Item 2. Management's Discussion and Analysis
of Financial Condition and Results of
Operations 17
Item 3. Quantitative and Qualitative Disclosures
About Market Risk 31
Part II. Other Information
Item 1. Legal Proceedings 32
Item 6. Exhibits and Reports on Form 8-K 32
Signature 34
</TABLE>
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<PAGE> 3
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- ----------------------------
1997 1996 1997 1996
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
REVENUES:
Electric ................................................. $1,385,451 $1,230,298 $3,285,005 $3,142,234
Natural gas distribution.................................. 180,101 180,101
Interstate pipelines...................................... 23,821 23,821
Energy marketing and gathering............................ 533,284 533,284
International............................................. 21,458 16,906 61,386 38,201
Other..................................................... 14,436 3,821 17,503 6,236
---------- ---------- ---------- ----------
Total.................................................. 2,158,551 1,251,025 4,101,100 3,186,671
---------- ---------- ---------- ----------
EXPENSES:
Electric and natural gas:
Fuel .................................................. 895,012 319,548 1,361,374 817,836
Purchased power........................................ 99,298 71,762 278,922 224,078
Operation and maintenance.............................. 405,793 206,748 850,249 637,561
Taxes other than income taxes.......................... 85,588 63,280 207,008 191,148
International............................................. 14,036 13,207 44,530 57,324
Depreciation and amortization............................. 184,156 130,970 446,889 389,868
Other operating expenses.................................. 11,952 4,441 46,063 5,870
---------- ---------- ---------- ----------
Total.................................................. 1,695,835 809,956 3,235,035 2,323,685
---------- ---------- ---------- ----------
OPERATING INCOME.............................................. 462,716 441,069 866,065 862,986
---------- ---------- ---------- ----------
OTHER INCOME (EXPENSE):
Litigation settlements.................................... (95,000)
Time Warner dividend income............................... 10,313 10,403 31,028 31,208
Interest income........................................... 3,696 770 5,387 3,482
Other - net............................................... 11,028 (322) 8,244 (1,523)
---------- ---------- ---------- ----------
Total.................................................. 25,037 10,851 44,659 (61,833)
---------- ---------- ---------- ----------
INTEREST AND OTHER CHARGES:
Interest on long-term debt................................ 91,874 68,610 217,513 208,861
Other interest............................................ 18,667 11,475 51,826 22,810
Distribution on trust securities.......................... 7,055 18,728
Allowance for borrowed funds used
during construction.................................... (47) (583) (1,892) (1,939)
Preferred dividends of subsidiary......................... 33 5,373 2,255 17,318
---------- ---------- ---------- ----------
Total.................................................. 117,582 84,875 288,430 247,050
---------- ---------- ---------- ----------
INCOME BEFORE INCOME TAXES.................................... 370,171 367,045 622,294 554,103
INCOME TAXES.................................................. 126,209 127,021 197,249 185,485
---------- ---------- ---------- ----------
NET INCOME.................................................... 243,962 240,024 425,045 368,618
---------- ---------- ---------- ----------
PREFERRED STOCK DIVIDEND...................................... 64 64
---------- ---------- ----------
NET INCOME AVAILABLE FOR COMMON STOCK......................... $ 243,898 $ 240,024 $ 424,981 $ 368,618
=========== ========== ========== ==========
EARNINGS PER COMMON SHARE..................................... $ 0.93 $ 0.98 $ 1.74 $ 1.49
DIVIDENDS DECLARED PER COMMON SHARE........................... $ 0.375 $ 0.375 $ 1.125 $ 1.125
WEIGHTED AVERAGE COMMON SHARES
Outstanding (000)......................................... 263,373 245,889 243,769 247,664
</TABLE>
See Notes to Consolidated Financial Statements.
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<PAGE> 4
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
ASSETS
<TABLE>
<CAPTION>
September 30, December 31,
1997 1996
------------ -------------
<S> <C> <C>
PROPERTY, PLANT AND EQUIPMENT - AT COST:
Electric plant:
Plant in service............................................................ $ 12,576,498 $ 12,387,375
Construction work in progress............................................... 187,827 251,497
Nuclear fuel................................................................ 253,998 241,001
Plant held for future use................................................... 48,631 48,631
Gas Plant and Pipelines:
Natural gas distribution.................................................... 1,287,648
Interstate pipelines........................................................ 1,291,202
Energy marketing and gathering.............................................. 161,546
Other property................................................................. 142,537 86,969
------------ -------------
Total................................................................. 15,949,887 13,015,473
Less accumulated depreciation and amortization................................. 4,623,328 4,259,050
------------ -------------
Property, plant and equipment - net................................... 11,326,559 8,756,423
------------ -------------
CURRENT ASSETS:
Cash and cash equivalents...................................................... 53,407 8,001
Accounts receivable - net...................................................... 538,385 36,277
Accrued unbilled revenues...................................................... 119,135 77,853
Time Warner dividends receivable............................................... 10,313 10,313
Fuel stock and petroleum products.............................................. 118,998 61,795
Materials and supplies, at average cost........................................ 158,681 130,380
Prepayments and other current assets........................................... 62,719 19,301
------------ -------------
Total current assets.................................................. 1,061,638 343,920
------------ -------------
OTHER ASSETS:
Investment in Time Warner securities........................................... 990,000 1,027,500
Goodwill - net................................................................. 1,955,788
Deferred plant costs - net..................................................... 571,641 587,352
Equity investments in and advances to foreign and
non-regulated affiliates - net.............................................. 677,565 501,991
Regulatory tax asset - net..................................................... 356,580 362,310
Deferred debits................................................................ 562,738 306,473
Recoverable project costs - net................................................ 113,634 163,630
Unamortized debt expense and premium on
reacquired debt............................................................. 215,498 153,823
Fuel-related debits............................................................ 182,178 84,435
------------ -------------
Total other assets.................................................... 5,625,622 3,187,514
------------ -------------
Total.............................................................. $ 18,013,819 $ 12,287,857
============ =============
</TABLE>
See Notes to Consolidated Financial Statements.
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<PAGE> 5
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
CAPITALIZATION AND LIABILITIES
<TABLE>
<CAPTION>
September 30, December 31,
1997 1996
----------- -------------
<S> <C> <C>
CAPITALIZATION:
Common stock equity:
Common stock, no par value..................................................... $ 3,097,299 $ 2,446,754
Treasury stock, at cost........................................................ (1,090) (361,196)
Unearned ESOP shares........................................................... (233,437) (251,350)
Retained earnings.............................................................. 2,141,326 1,997,490
Currency translation adjustment................................................ (442)
Unrealized gain (loss) on equity securities.................................... 3,809 (3,737)
----------- -------------
Total common stock equity............................................... 5,007,465 3,827,961
----------- -------------
Cumulative preferred stock, no par
value, not subject to mandatory redemption..................................... 9,740 135,179
----------- -------------
HL&P/NorAm obligated mandatorily redeemable securities
of subsidiary trusts holding solely subordinated
debentures of HL&P/NorAm......................................................... 380,350
-----------
Long-Term Debt:
Automatic common exchange securities (ACES).................................... 1,052,384
Debentures..................................................................... 349,237 349,098
Long-term debt of HL&P and subsidiaries:
First mortgage bonds........................................................ 2,495,268 2,670,041
Debentures.................................................................. 405,600
Notes payable............................................................... 932,901
Pollution control revenue bonds............................................. 118,000 5,000
Other....................................................................... 15,936 1,511
----------- -------------
Total long-term debt.................................................... 5,369,326 3,025,650
----------- -------------
Total capitalization................................................ 10,766,881 6,988,790
----------- -------------
CURRENT LIABILITIES:
Notes payable..................................................................... 1,763,313 1,337,872
Accounts payable.................................................................. 592,717 157,682
Taxes accrued..................................................................... 287,709 191,011
Interest accrued.................................................................. 118,239 67,707
Dividends declared................................................................ 92,549 92,515
Customer deposits................................................................. 82,198 53,633
Current portion of long-term debt and preferred stock............................. 190,385 254,463
Other............................................................................. 241,742 89,238
----------- -------------
Total current liabilities........................................... 3,368,852 2,244,121
----------- -------------
DEFERRED CREDITS:
Accumulated deferred income taxes - net........................................... 2,757,698 2,265,031
Unamortized investment tax credit................................................. 354,109 373,749
Fuel-related credits.............................................................. 93,479 74,639
Benefit liabilities............................................................... 354,214 243,375
Other............................................................................. 318,586 98,152
----------- -------------
Total deferred credits.............................................. 3,878,086 3,054,946
----------- -------------
COMMITMENTS AND CONTINGENCIES
Total............................................................. $18,013,819 $ 12,287,857
=========== =============
</TABLE>
See Notes to Consolidated Financial Statements.
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<PAGE> 6
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(THOUSANDS OF DOLLARS)
(UNAUDITED)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
-----------------------------
1997 1996
---------- ----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................................................... $ 425,045 $ 368,618
Adjustments to reconcile income from continuing operations to net cash
provided by operating activities:
Depreciation and amortization..................................................... 446,889 389,868
Amortization of nuclear fuel...................................................... 21,727 24,261
Deferred income taxes............................................................. 23,973 (5,127)
Investment tax credit............................................................. (14,740) (14,592)
Allowance for other funds used during construction ............................... (171) (3,093)
Contribution of marketable equity securities to
charitable trust............................................................... 19,463
Fuel cost and over/(under) recovery - net......................................... (67,171) (119,442)
Changes in other assets and liabilities:
Accounts receivable - net...................................................... 75,006 19,604
Inventory...................................................................... 21,260 9,061
Other current assets........................................................... (13,584) 1,328
Accounts payable............................................................... (95,054) (15,146)
Interest and taxes accrued..................................................... 73,724 105,746
Other current liabilities...................................................... 43,590 (73)
Other - net.................................................................... (13,457) 17,673
---------- ----------
Net cash provided by operating activities.................................. 946,500 778,686
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (including allowance for
borrowed funds used during construction).......................................... (180,472) (226,783)
Purchase of NorAm Energy Corp., net of cash acquired................................. (1,422,672)
Non-regulated electric power project expenditures.................................... (215,020) (446,600)
Sale of Time Warner securities....................................................... 25,043
Other - net.......................................................................... (10,484) (37,984)
---------- ----------
Net cash used in investing activities...................................... (1,803,605) (711,367)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of ACES - net..................................................... 1,020,770
Proceeds from issuance of commercial paper........................................... 1,379,568
Payment to retire commercial paper................................................... (1,020,317)
Proceeds from sale of HL&P obligated mandatorily
redeemable securities of subsidiary trusts holding
solely subordinated debentures of HL&P............................................ 340,785
Purchase of treasury stock........................................................... (205,901)
Payment of matured bonds............................................................. (190,000) (150,000)
Proceeds from issuance of pollution control revenue
bonds............................................................................. 115,739
Redemption of preferred stock........................................................ (153,628) (51,400)
Payment of common and preferred stock dividends...................................... (281,009) (279,498)
Increase/(decrease)in notes payable - net............................................ (214,486) 691,531
Extinguishment of long-term debt..................................................... (190,338) (85,263)
Other - net.......................................................................... 95,427 9,131
---------- ----------
Net cash provided by/(used in) financing
activities............................................................... 902,511 (71,400)
---------- ----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS...................................... 45,406 (4,081)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.......................................... 8,001 11,779
---------- ----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD................................................ $ 53,407 $ 7,698
========== ==========
</TABLE>
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<PAGE> 7
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(THOUSANDS OF DOLLARS)
CONT'D
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
------------------------------
1997 1996
----------- -----------
<S> <C> <C>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest (net of amounts capitalized)....................................... $ 274,560 $ 221,641
Income taxes................................................................ 113,128 91,867
</TABLE>
The aggregate consideration paid to Former NorAm stockholders in connection
with the Merger consisted of $1.4 billion in cash and 47.8 million shares of
the Company's common stock valued at approximately $1.0 billion. The overall
transaction was valued at $4.0 billion consisting of $2.4 billion for Former
NorAm's common stock and common stock equivalents and $1.6 billion of NorAm
debt.
See Notes to Consolidated Financial Statements.
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<PAGE> 8
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED RETAINED EARNINGS
(THOUSANDS OF DOLLARS)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------------- -------------------------
1997 1996 1997 1996
---------- ---------- ---------- -------
<S> <C> <C> <C> <C>
Balance at Beginning of Period................................ $2,003,194 $1,896,173 $1,997,490 $1,953,672
Net Income for the Period..................................... 243,962 240,024 425,045 368,618
---------- ---------- ---------- ----------
Total............................................... 2,247,156 2,136,197 2,422,535 2,322,290
Preferred Stock Dividends..................................... (64) (64)
Common Stock Dividends........................................ (105,766) (89,960) (281,145) (276,053)
---------- ---------- ---------- ----------
Balance at End of Period...................................... $2,141,326 $2,046,237 $2,141,326 $2,046.237
========== ========== ========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
-8-
<PAGE> 9
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) BASIS OF PRESENTATION
On August 6, 1997, Houston Industries Incorporated (Former HI) merged with
and into Houston Lighting & Power Company (HL&P), which was renamed
"Houston Industries Incorporated" (Company), and NorAm Energy Corp., a
natural gas gathering, transmission, marketing and distribution company
(Former NorAm), merged with and into a subsidiary of the Company, HI
Merger, Inc., which was renamed "NorAm Energy Corp." (NorAm). Effective
upon the mergers (collectively, the Merger), each outstanding share of
common stock of Former HI was converted into one share of common stock
(including associated preference stock purchase rights) of the Company, and
each outstanding share of common stock of Former NorAm was converted into
the right to receive $16.3051 cash or 0.74963 shares of common stock of the
Company. For additional information regarding the Merger, see Note 3 below.
The interim financial statements and notes (Interim Financial Statements)
in this Form 10-Q (Form 10-Q) include the accounts of the Company and its
wholly owned and majority owned subsidiaries including, effective as of
August 6, 1997, the accounts of NorAm and its wholly owned and majority
owned subsidiaries. The Interim Financial Statements are unaudited, omit
certain information included in financial statements prepared in accordance
with generally accepted accounting principles and should be read in
combination with the Combined Annual Report on Form 10-K of Former HI and
HL&P (Company's Form 10-K) for the year ended December 31, 1996 (File Nos.
1-7629 and 1-3187) and the Annual Report on Form 10-K of Former NorAm
(NorAm's Form 10-K) for the year ended December 31, 1996 (File No. 1-3751).
For additional information regarding the presentation of interim period
results, see Note 10 below.
The following notes to the financial statements in the Company's Form 10-K
and NorAm's Form 10-K relate to material contingencies. These notes, as
updated by the notes contained in this Form 10-Q and the notes contained in
the Quarterly Report on Form 10-Q of Former HI and HL&P for the quarter
ended March 31, 1997 (Company's First Quarter Form 10-Q) and for the
quarter ended June 30, 1997 (Company's Second Quarter Form 10-Q), and from
the Quarterly Report on Form 10-Q of Former NorAm for the quarter ended
March 31, 1997 (NorAm's First Quarter Form 10-Q) and for the quarter ended
June 30, 1997 (NorAm's Second Quarter Form 10-Q) are incorporated herein by
reference and include the following:
Company: Note 1(b) (System of Accounts and Effects of Regulation), Note
1(n) (Nature of Operations), Note 1(o) (Use of Estimates), Note 2
(Jointly-Owned Nuclear Plant), Note 3 (Rate Matters), Note 4 (Investments
in HI Energy) and Note 11 (Commitments and Contingencies).
NorAm: Note 1 (Accounting Policies and Components of Certain Financial
Statement Line Items) and Note 7 (Commitments and Contingencies).
(2) SIGNIFICANT ACCOUNTING POLICIES
For information regarding significant accounting policies of the Company
and its wholly owned subsidiary, NorAm, see Note 1 to the Company's Form
10-K and Note 1 to NorAm's Form 10-K, which notes, as updated by the
information contained in this note, are incorporated herein by reference.
-9-
<PAGE> 10
Accounting for Energy Risk Management Activities. The Company, through
NorAm and certain of its subsidiaries, utilizes a variety of derivative
financial instruments, including swaps and exchange-traded futures and
options (Derivatives) as part of its overall risk-management strategy and
for limited trading purposes as discussed below. To reduce the risk from
market fluctuations in the price of electric power, natural gas and related
transportation, NorAm and certain of its subsidiaries enter into futures
transactions, swaps and options (Energy Derivatives) in order to hedge
certain natural gas in storage, as well as certain expected purchases,
sales and transportation of natural gas and electric power (a portion of
which are firm commitments at the inception of the hedge). NorAm also
utilizes interest-rate derivatives (principally interest-rate swaps) in
order to adjust the portion of its overall borrowings which are subject to
interest-rate risk, and also has utilized such derivatives to effectively
fix the interest rate on debt expected to be issued for refunding purposes.
In addition, a subsidiary of NorAm maintains a portfolio of Energy
Derivatives for trading purposes.
The Company's accounting for activities involving derivative financial
instruments is in accordance with the concepts established in Statement of
Financial Accounting Standards (SFAS) No. 80, "Accounting for Futures
Contracts", American Institute of Certified Public Accountants Statement of
Position 86-2, "Accounting for Options" and various pronouncements of the
Emerging Issues Task Force of the Financial Accounting Standards Board
(FASB).
Unrealized changes in the market value of Energy Derivatives utilized as
hedges are not generally recognized in the Company's consolidated financial
statements. The cash impacts associated with such derivatives are (i)
recognized as an asset or liability in the case of options or other
derivatives for which money is exchanged either (A) at the inception of the
position or (B) as a result of margin calls, (ii) included in the
measurement of the transaction that satisfies the commitment in the case of
firm commitments and (iii) included in the measurement of the subsequent
transaction in the case of anticipated transactions, whether or not the
Energy Derivative position is closed out before the date of the anticipated
transaction. Once it becomes probable that an anticipated transaction will
not occur, deferred gains and losses are recognized. In general, the
financial impact of transactions involving these Energy Derivatives is
included in the Company's Statement of Consolidated Income under the
caption (i) "Fuel expenses" in the case of natural gas transactions and
(ii) "Operation and maintenance" in the case of electric power
transactions. Cash flows resulting from these transactions in Energy
Derivatives are included in the Company's Statements of Consolidated Cash
Flows in the same category as the item being hedged.
In the case of interest-rate swaps associated with existing obligations,
cash flows and expense associated with the interest-rate derivative
transactions are matched with the cash flows and interest expense of the
obligation being hedged, resulting in an adjustment to the effective
interest rate. When interest-rate swaps are utilized to effectively fix the
interest rate for an anticipated debt issuance, changes in the market value
of the interest-rate derivatives are deferred and recognized as an
adjustment to the effective interest rate on the newly-issued debt. If it
is determined that the anticipated issuance of debt will not occur, or that
the issuance will be for an amount or a term different from that
anticipated at the inception of the hedge, either all or a pro rata portion
(as applicable) of the deferred gain or loss is recognized concurrently
with such determination.
For transactions involving either Energy Derivatives or interest-rate
derivatives, hedge accounting is applied only if the derivative (i) reduces
the risk of the underlying hedged item and (ii) is designated as a hedge at
its inception. Additionally, the derivatives
-10-
<PAGE> 11
must be expected to result in financial impacts which are inversely
correlated to those of the item(s) to be hedged. This correlation (a
measure of hedge effectiveness) is measured both at the inception of the
hedge and on an ongoing basis, with an acceptable level of variation from
80% to 125% for hedge designation. If and when correlation ceases to exist
at an acceptable level, hedge accounting ceases and "mark-to-market"
accounting (as described below) is applied.
A subsidiary of NorAm maintains a portfolio of Energy Derivatives for
trading purposes, representing a small portion of the Company's overall
derivative positions. In addition, the total underlying notional amounts of
natural gas or electric power associated with these trading activities
represents a small fraction of NorAm's total notional transaction volume in
these energy commodities for any given period. This trading portfolio of
Energy Derivatives is "marked-to-market" on a daily basis, with unrealized
gains and losses included in income as they occur and reported in the
Company's consolidated financial statements under the same line items as
the impacts of the energy hedging transactions as described above.
(3) ACQUISITION OF NORAM
The aggregate consideration paid to Former NorAm stockholders in connection
with the Merger consisted of $1.4 billion in cash and 47.8 million shares
of the Company's common stock valued at approximately $1 billion. The
overall transaction was valued at $4.0 billion consisting of $2.4 billion
for Former NorAm's common stock and common stock equivalents and $1.6
billion of Former NorAm debt ($1.3 billion of which was long-term debt).
The Company has recorded the acquisition of NorAm under the purchase method
of accounting with assets and liabilities of NorAm reflected at their
estimated fair market values as of the date of the purchase. The Company
has recorded the $2 billion excess of the acquisition cost over the fair
value of the net assets acquired as goodwill and is amortizing this amount
over 40 years. On a preliminary basis, the Company's fair value adjustments
included increases in property, plant and equipment, long-term debt, and
unrecognized pension and post retirement benefits liabilities plus related
deferred taxes. The allocation of the purchase price is preliminary, since
valuation and other studies have not been finalized.
The Company's results of operations incorporate NorAm's results of
operations only for the period beginning August 6, 1997. The following
table presents certain unaudited pro forma information for the three and
nine month periods ended September 30, 1997 and 1996, as if the Merger
had occurred on January 1, 1997 or 1996, as applicable.
-11-
<PAGE> 12
Pro Forma Combined Results
of Operation
(In millions, except per share data)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
1997 1996 1997 1996
------ ------ ------ ------
<S> <C> <C> <C> <C>
Revenues $2,555 $2,150 $7,438 $6,395
Net Income Available for
Common Stock $ 215 $ 215 $ 431 $ 367
Earnings Per Share $ 0.76 $ 0.73 $ 1.53 $ 1.24
</TABLE>
These and other pro forma results appearing in this Form 10-Q are based on
assumptions deemed appropriate by the Company's management, have been
prepared for informational purposes only and are not necessarily indicative
of the combined results that would have resulted had the Merger occurred at
the beginning of the periods indicated.
(4) CAPITAL STOCK
(a) Common Stock. At September 30, 1997, the Company had 282,346,858 shares of
common stock issued and outstanding (out of a total of 700,000,000
authorized shares). At December 31, 1996, the number of shares of
outstanding Common Stock of Former HI was 233,335,481. Outstanding common
shares excluded (i) shares pledged to secure a loan to the Company's
Employee Stock Ownership Plan (12,388,551 and 13,370,939 at September 30,
1997 and December 31, 1996, respectively) and (ii) treasury shares (50,747
and 16,042,027 at September 30, 1997, and December 31, 1996, respectively).
(b) Earnings Per Share. The Company calculates earnings per common share by
dividing net income by the weighted average common shares outstanding
during the relevant period. For information regarding the adoption of SFAS
No. 128, "Earnings Per Share" (Dual Presentation of Basic and Diluted
Earnings per Share Calculations for Financial Statements) with respect to
periods ending after December 15, 1997, see Note 5 to the Company's First
Quarter Form 10-Q. The Company's current earnings per share calculation
conforms to basic earnings per share. Diluted earnings per share are not
expected to be materially different from basic earnings per share.
(c) Preferred Stock. At September 30, 1997 and December 31, 1996, the Company
had 10,000,000 authorized shares of preferred stock, of which 97,397 shares
were outstanding at September 30, 1997 and 1,604,397 shares were
outstanding at December 31, 1996.
As of September 30, 1997, the Company's only outstanding series of
preferred stock was its $4.00 Preferred Stock. The $4.00 Preferred Stock
pays an annual dividend of $4.00 per share, is redeemable at $105 per share
and has a liquidation price of $100 per share.
For information regarding the redemption during the first six months of
1997 of the Company's $6.72, $7.52, $8.12 and $9.375 cumulative preferred
stock, see Note 7 to
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<PAGE> 13
the Company's First Quarter Form 10-Q and Note 3 to the Company's Second
Quarter Form 10-Q.
(d) Preference Stock. At September 30, 1997, the Company had 10,000,000
authorized shares of preference stock, of which 700,000 shares are
classified as Series A Preference Stock and 27,000 shares are classified as
Series B Preference Stock. As of September 30, 1997, there were no shares
of Series A Preference Stock issued and outstanding (such shares being
issuable in accordance with the Company's Shareholder Rights Agreement upon
the occurrence of certain events). The number of shares of Series B
Preference Stock issued and outstanding as of September 30, 1997 was
17,000. The sole holder of the Series B Preference Stock is a wholly owned
financing subsidiary of the Company.
(5) LONG-TERM DEBT AND SHORT-TERM FINANCING
(a) Overview. At September 30, 1997 and December 31, 1996, the Company had $7.3
billion and $4.6 billion, respectively, in long-term and short-term debt
outstanding. Of the amount of long-term and short-term debt outstanding as
of September 30, 1997, $1.8 billion represents debt of NorAm.
<TABLE>
<CAPTION>
Consolidated Long-Term Debt and Short-Term Borrowings
-----------------------------------------------------
(In millions)
September 30, December 31,
1997 1996
------------- ------------
<S> <C> <C>
Short-Term Borrowings:
Commercial Paper $1,288 $1,332
Current Portion of Long-Term Debt 190 259
Lines of Credit 180
NorAm Sale of Receivables 295
Long-Term Debt:
Debentures(1) 756 350
First Mortgage Bonds(1) 2,510 2,685
Notes Payable 933
Pollution Control Revenue Bonds 118 5
Automatic Common Exchange Securities 1,052
Other 16 2
</TABLE>
(1) Unamortized discount related to debentures was approximately
$1 million at September 30, 1997 and December 31, 1996. Unamortized
discount related to first mortgage bonds was approximately $15
million at September 30, 1997 and December 31, 1996.
Consolidated maturities of long-term debt for the Company (including NorAm)
are approximately $87 million for the remainder of 1997, $238 million in
1998, $378 million in 1999, $1.4 billion in 2000 and $401 million in 2001.
-13-
<PAGE> 14
(b) FinanceCo Credit Facility. In August 1997, a limited partnership special
purpose subsidiary of the Company (FinanceCo), established a five-year,
$1.644 billion revolving credit facility with a consortium of commercial
banks (FinanceCo Facility). The FinanceCo Facility supported $1.288 billion
in commercial paper borrowings by FinanceCo at September 30, 1997 recorded
as notes payable in the Consolidated Balance Sheet. The weighted average
interest rate of these borrowings at September 30, 1997, was 5.91%.
Proceeds from the initial issuances of commercial paper were used to fund
the cash portion of the consideration paid to Former NorAm stockholders
under the terms of the Merger.
Borrowings under the FinanceCo Facility, which bear interest at a rate
based upon either the London interbank offered rate (LIBOR) plus a margin
or a base rate plus a margin or at a rate determined through a bidding
process. The FinanceCo Facility may be used (i) to support the issuance of
commercial paper or other short-term indebtedness of FinanceCo, (ii)
subject to certain limitations, to finance repurchases of Company common
stock and (iii) subject to certain limitations, to provide funds for
general purposes of FinanceCo, including the making of intercompany loans
to, or securing letters of credit for the benefit of, FinanceCo's
affiliates.
The FinanceCo Facility requires the Company to maintain a ratio of
consolidated indebtedness for borrowed money to consolidated capitalization
that does not exceed 0.64:1.00 from October 1, 1997 through December 31,
1997; 0.62:1.00 from January 1, 1998 through December 31, 1998; and
0.60:1.00 from January 1, 1999 until termination of the FinanceCo Facility.
The FinanceCo Facility also contains restrictions applicable to the Company
with respect to, among other things, (i) liens, (ii) consolidations,
mergers and dispositions of assets, (iii) dividends and repurchases of
common stock, (iv) certain types of investments and (v) certain changes in
its business. The FinanceCo Facility contains customary covenants and
default provisions applicable to FinanceCo and its subsidiaries, including
limitations on, among other things, additional indebtedness (other than
certain permitted indebtedness), liens and certain investments or loans.
Subject to certain conditions and limitations, the Company is required to
make cash payments from time to time to FinanceCo from excess cash flow (as
defined in the FinanceCo Facility) to the extent necessary to enable
FinanceCo to meet its financial obligations. Borrowings under the FinanceCo
Facility are secured by pledges of (i) the shares of common stock of NorAm
held by the Company, (ii) all of the limited and general partner interests
of FinanceCo and all of the Company's interest in the general partner of
FinanceCo, (iii) the capital stock of HI Energy, (iv) the capital stock of
other significant subsidiaries of the Company, (v) the Series B Preference
Stock and (vi) certain intercompany notes held by FinanceCo. The
obligations under the FinanceCo Facility are not secured by the utility
assets of the Company or NorAm or by the Company's investment in Time
Warner Inc. (Time Warner).
(c) ACE Securities. The Company owns 11 million shares of non-publicly traded
Convertible Preferred Stock of Time Warner (Time Warner Preferred Stock).
In connection with the monetization of its investment in these securities,
Former HI sold in July 1997, 22,909,040 of its unsecured 7% Automatic
Common Exchange Securities due July 1, 2000 (ACE Securities), having a face
amount of $45.9375 per security.
At maturity, the principal amount of the ACE Securities will be mandatorily
exchangeable by the Company into either (i) a number of shares of common
stock of Time Warner based on an exchange rate or (ii) cash having an equal
value. Subject to adjustments that may result from certain dilution events,
the exchange rate for each
-14-
<PAGE> 15
ACE Security is determined as follows: (i) 0.8264 shares of Time Warner
common stock if the price of Time Warner common stock at maturity (Maturity
Price) is at least $55.5844 per share, (ii) a fractional share of Time
Warner common stock such that the fractional share will have a value equal
to $45.9375 if the Maturity Price is less than $55.5844 but greater than
$45.9375 and (iii) one share of Time Warner common stock if the Maturity
Price is not more than $45.9375.
Prior to maturity, the Company has the option of redeeming the ACE
Securities if (i) changes in federal tax regulations require recognition of
a taxable gain on the Company's Time Warner Preferred Stock and (ii) the
Company could defer such gain by redeeming the ACE Securities. The
redemption price is 105% of the closing sales price of the ACE Securities
as determined over a period prior to the redemption notice. The redemption
price may be paid in cash or in shares of Time Warner common stock or a
combination of the two.
Former HI used the net proceeds of the sale of the ACE Securities
(approximately $1.021 billion) to retire an equivalent amount of Former
HI's then outstanding commercial paper. For a description of the Company's
accounting treatment of the ACE Securities and its investment in Time
Warner (including the potential adverse impact on earnings that may be
caused by certain fluctuations in the market value of Time Warner
securities), see "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Future
Earnings -- Accounting Treatment of ACE Securities" in Item 2 of the Form
10-Q.
(6) COMPANY OBLIGATED MANDATORILY REDEEMABLE SECURITIES OF SUBSIDIARY TRUSTS
HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF THE COMPANY AND NORAM
For information regarding (i) $250 million of preferred securities and
$100 million of capital securities issued by statutory business trusts
formed by HL&P and (ii) $177.8 million of convertible preferred securities
issued by a statutory business trust formed by Former NorAm, of which
$30.5 million were outstanding at September 30, 1997, see Note 7 to the
Company's First Quarter Form 10-Q and Note 3 to the NorAm Form 10-K,
respectively. The sole asset of each trust consists of subordinated
debentures of the Company or NorAm (as the case may be) having principal
amounts, interest rates and maturity dates corresponding to each issue of
preferred or capital securities.
(7) DEPRECIATION
The Company calculates depreciation using the straight-line method. The
Company's depreciation expense for the third quarter of 1997 and the nine
months ended September 30, 1997 was $115 million and $296 million,
respectively, compared with $91 million and $269 million for the same
periods in 1996.
(8) CERTAIN RATE AND TAX MATTERS
(a) Rate Matters -- Company. For information about rate case proceedings
affecting the Company's electric operations division, see Note 3 (Rate
Matters) in the Company's Form 10-K, which note is incorporated herein by
reference.
In September 1997, the Company received a judgment dismissing all
outstanding appeals of the Public Utility Commission of Texas' (Utility
Commission) order in Docket No. 6668. As a result of this judgment, all
outstanding appeals of the Company's prior rate cases have now been
dismissed and such action is final.
For information regarding the Company's electric operations division's
proposed transition plan and price reduction agreement
-15-
<PAGE> 16
relating to the transition to retail access for utility customers (Proposed
Transition Plan), see "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Certain Factors Affecting Future
Earnings" in Item 2 of this Form 10-Q.
(b) Tax Refund Case. In July 1990, Former HI paid approximately $104.5 million
to the Internal Revenue Service (IRS) following an IRS audit of Former HI's
1983 and 1984 federal income tax returns. In November 1991, Former HI filed
a refund suit in the U.S. Court of Federal Claims seeking the return of
$52.1 million of tax and $36.3 million of accrued interest, plus interest
on both of those amounts accruing after July 1990. The major contested
issue in the refund case involved the IRS allegation that certain amounts
related to the over-recovery of fuel costs should have been included as
taxable income in 1983 and 1984 even though HL&P had an obligation to
refund the over-recoveries to its ratepayers.
In September 1997, the United States Court of Appeals for the Federal
Circuit upheld a lower court ruling that the Company (as successor
corporation to Former HI) was due a refund of federal income taxes assessed
on fuel over-recoveries during 1983 and 1984 that subsequently were
refunded to HL&P's customers. If the opinion is upheld in its current form,
the Company estimates that it will receive a refund of approximately $82
million in taxes and interest paid by Former HI in July 1990, plus interest
that has accrued since 1990 (approximately $138 million in total refund as
of September 30, 1997). Based on the Company's deferred recognition of the
1990 tax payment and after giving effect to federal income taxes due on the
accrued interest, the Company estimates that this refund would increase
earnings by approximately $30 million. The IRS has not yet indicated
whether it will ask the U.S. Supreme Court to review the Court of Appeals'
decision.
(9) SUBSEQUENT EVENTS
The Company and the other three owners of the South Texas Project (South
Texas Project) are executing agreements, to be effective in March 1997, to
transfer the Company's responsibility for operation of the South Texas
Project to a new Texas non-profit corporation formed by the four owners and
known as the STP Nuclear Operating Company. That new operating company was
formed exclusively for the purpose of operating the South Texas Project,
and the Company's officers and employees who have been responsible for
day-to-day operation and management of the South Texas Project were
transferred to the operating company effective as of October 1, 1997. The
operating company will be managed by a board of directors composed of one
director from each of the four owners, along with the chief executive
officer of the operating company. Formation of the operating company did
not affect the underlying ownership of the South Texas Project, which
continues as a tenancy in common among the four owners, with each owner
retaining its undivided ownership interest in the two nuclear-fueled
generating units and the electrical output from those units. The four
owners will continue to provide overall oversight of the operations of the
South Texas Project through an owners' committee composed of
representatives of each of the owners and through the board of directors of
the operating company. The formation of the operating company and the
transfer of employees and operations to the operating company are not
anticipated to have a material effect on the Company's earnings.
(10) INTERIM PERIOD RESULTS; RECLASSIFICATIONS
The Interim Financial Statements reflect all normal recurring adjustments
that are, in the opinion of management, necessary to present fairly the
financial position and results of operation for the respective periods.
Amounts reported in the Consolidated Statements of Income are not
necessarily indicative of amounts expected for a full year period due to
the effects of, among other things, (i) the acquisition of NorAm, (ii)
seasonal temperature variations in energy consumption and (iii) the timing
of maintenance and other expenditures. In addition, certain amounts from
the prior year have been reclassified to conform to the Company's
presentation of financial statements in the current year. Such
reclassifications do not affect earnings.
-16-
<PAGE> 17
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
The following discussion and analysis should be read in combination with
Management's Discussion and Analysis of Financial Condition and Results of
Operations in Item 7 of the Company's Form 10-K and NorAm's Form 10-K, the
financial statements and notes contained in Item 8 of the Company's Form 10-K
and NorAm's Form 10-K and the Interim Financial Statements contained in this
Form 10-Q.
Statements contained in this Form 10-Q that are not historical facts are
forward-looking statements as defined in the Private Securities Litigation
Reform Act of 1995. Forward-looking statements are based on management's beliefs
as well as assumptions made by and information currently available to
management. Because such statements are based on expectations as to future
economic performance and are not statements of fact, actual results may differ
materially from those projected. Important factors that could cause future
results to differ include (i) the effects of competition in the electric power
and natural gas industries, (ii) legislative and regulatory changes, (iii)
fluctuations in the weather, (iv) fluctuations in energy commodity prices, (v)
environmental liabilities, (vi) changes in the economy and (vii) other factors
discussed in this and other filings by the Company with the Securities and
Exchange Commission. When used in the Company's or NorAm's documents or oral
presentations, the words "anticipate," "estimate," "expect," "objective,"
"projection," "forecast," "goal" or similar words are intended to identify
forward-looking statements. The sections of Management's Discussion and Analysis
of Financial Condition and Results of Operations captioned "Results of
Operations by Business Segment" and "Certain Factors Affecting Future Earnings"
contain or incorporate by reference forward-looking statements.
HOUSTON INDUSTRIES INCORPORATED
The Company is a diversified international energy services company. It
operates the nation's tenth largest electric utility in terms of kilowatt-hour
sales and its three natural gas distribution divisions together form the
nation's third largest natural gas distribution operations in terms of customers
served. The Company also invests in electric utility privatizations, gas
distribution projects and the development of unregulated power generation
projects. The Company's unregulated retail businesses provide energy-related
products and services to consumers, small business customers and utilities. The
Company is also a major interstate natural gas pipeline and energy services
company, providing gas transportation, supply, gathering and storage, and
wholesale natural gas and electric power marketing services.
The Company is exempt from regulation as a public utility holding company
pursuant to Section 3(a)(2) of the Public Utility Holding Company Act of 1935,
as amended (1935 Act), except with respect to (i) the acquisition of certain
voting securities of other domestic public utility companies and utility holding
companies and (ii) the provisions of Section 33 of the 1935 Act regarding the
acquisition, ownership and financing of foreign utility companies.
CONSOLIDATED RESULTS OF OPERATIONS
On August 6, 1997, the Company completed its acquisition of NorAm, a
natural gas gathering, transmission, marketing and distribution company. The
acquisition was accounted for under the purchase method of accounting;
accordingly, the Company's actual results of operations for the three and nine
month periods ended September 30, 1997 incorporate NorAm's results of operations
only for periods beginning effective as of August 6, 1997.
To enhance comparability between reporting periods, the Company is
presenting consolidated results of operations data on both (i) an actual basis
and (ii) a pro forma basis as if the acquisition of NorAm had occurred on
January 1, 1996 or 1997, as applicable. Although pro forma results of operations
are not necessarily indicative of the combined results of operations that
actually would have occurred had the acquisition occurred on such dates, the
Company believes that the
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<PAGE> 18
presentation of pro forma data provides a more meaningful comparative standard
for assessing changes in the Company's consolidated financial condition and
results of operations.
CONSOLIDATED RESULTS OF OPERATIONS
(in thousands, except per share data)
<TABLE>
<CAPTION>
Actual Pro Forma
------------------------ --------------------------
Three Months Ended Three Months Ended
September 30, Percent September 30, Percent
1997 1996 Change 1997 1996 Change
------------------------ ------ ---------- ---------- ------
<S> <C> <C> <C> <C> <C> <C>
Revenues ............................. $2,158,551 $1,251,025 73 $2,555,419 $2,150,308 19
Operating Expenses ....................... 1,695,835 809,956 109 2,122,712 1,700,240 25
Operating Income.......................... 462,716 441,069 5 432,707 450,068 (4)
Other Expenses, Net....................... 218,754 201,045 9 217,615 235,127 (7)
Net Income from Continuing Operations 243,962 240,024 2 215,092 214,941 --
Preferred Dividends....................... 64 64 --
From Continuing Operations:
Net Income for Common Stock............ 243,898 240,024 2 215,028 214,941 --
Earnings Per Share..................... .93 .98 .76 .73
Weighted Average Number of
Common Shares Outstanding.............. 263,373 245,889 282,093 293,729
</TABLE>
<TABLE>
<CAPTION>
Actual Pro Forma
------------------------- --------------------------
Nine Months Ended Nine Months Ended
September 30, Percent September 30, Percent
1997 1996 Change 1997 1996 Change
------------------------- ------ ---------- ---------- ------
<S> <C> <C> <C> <C> <C> <C>
Revenues ............................. $4,101,100 $3,186,671 29 $7,438,148 $6,394,942 16
Operating Expenses ....................... 3,235,035 2,323,685 39 6,439,525 5,355,972 20
Operating Income.......................... 866,065 862,986 -- 998,623 1,038,970 (4)
Other Expenses, Net....................... 441,020 494,368 (11) 567,131 668,078 (15)
Net Income from Continuing Operations 425,045 368,618 15 431,492 370,892 16
Preferred Dividends....................... 64 64 3,597 (98)
From Continuing Operations:
Net Income for Common Stock............ 424,981 368,618 15 431,428 367,295 17
Earnings Per Share..................... 1.74 1.49 1.53 1.24
Weighted Average Number of
Common Shares Outstanding.............. 243,769 247,664 281,796 295,504
</TABLE>
Actual. The Company's actual consolidated earnings for the three months
ended September 30, 1997, were $244 million compared with $240 million for the
third quarter of 1996. The $4 million increase in actual consolidated earnings
reflects (i) increased sales at the Company's electric utility division
(reflecting customer growth and warmer weather) and (ii) improved earnings at
the Company's international division, as described below. Partially offsetting
these factors was $19 million ($13 million after-tax) in additional amortization
of certain lignite reserves in the third quarter of 1997.
Although actual consolidated earnings increased by $4 million, the
Company's earnings per share declined from $.98 per share in the third quarter
of 1996 to $.93 per share in the third quarter of 1997. The decline in earnings
per share was caused by the issuance of approximately 47.8 million additional
shares of the Company's common stock as a portion of the consideration paid in
the Merger.
The Company's actual consolidated earnings for the nine months ended
September 30, 1997, were $425 million ($1.74 per share) compared with $369
million ($1.49 per share) for the same period in 1996. However, excluding
non-recurring charges, earnings for the first nine months
-18-
<PAGE> 19
of 1996 would have been $436 million, resulting in an $11 million decrease in
earnings between the two periods. This decrease is due in part to the effects of
the NorAm purchase including seasonal losses at the gas distribution segment,
amortization of goodwill and incremental interest costs related to the Merger.
The non-recurring charges excluded from adjusted earnings relate to the
settlement of South Texas Project litigation claims ($62 million recorded in the
first quarter of 1996) and the suspension by a subsidiary of the Company of
operations at two tire-to-energy plants in Illinois ($5 million recorded in the
first quarter of 1996).
Pro Forma. The Company's pro forma consolidated earnings for the three
months ended September 30, 1997, were $215 million ($.76 per share) compared
with $215 million ($.73 per share) for the same period in 1996.
The Company's pro forma consolidated earnings for the nine months ended
September 30, 1997, were $431 million ($1.53 per share) compared with $367
million ($1.24 per share) in the same period in 1996. Excluding the $67 million
in non-recurring charges described above, the Company's pro forma consolidated
earnings in 1996 would have been $434 million, resulting in a decrease of $3
million in pro forma earnings between the two periods (as compared to an $11
million decrease on an actual basis adjusted for non-recurring charges).
Pro forma consolidated earnings have been reduced by (i) additional
interest expense associated with debt incurred by the Company to finance the
Merger and (ii) purchase accounting adjustments associated with the Merger,
including the amortization of goodwill and the revaluation, on a preliminary
basis, of the fair market value of certain NorAm assets and liabilities.
For the nine months ended comparative results, pro forma consolidated
earnings are greater than actual earnings due to the net income associated with
NorAm operations for the period January 1, 1997 through August 5, 1997 (which is
not part of the reported actual results for the same period). Pro forma
consolidated earnings exceed actual consolidated earnings because merger
related costs were more than offset on a pro forma basis by NorAm's earnings
for the nine month period.
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
In order to reflect the changes in the Company's business resulting from
the acquisition of NorAm, the Company has elected to present selected results of
operations and operational data for each of the following business segments:
Electric Operations, Natural Gas Distribution, Interstate Pipelines, Energy
Marketing and Gathering, International and Corporate. The business and
operations of each of these segments are described below.
Purchase related adjustments, including amortization of goodwill and the
revaluation on a preliminary basis of the fair market value of certain NorAm
assets and liabilities, have been recorded at the business segment level. All
business segment data (other than data relating to Electric Operations) is
presented on a pro forma basis as if the acquisition of NorAm had occurred on
January 1, 1996 or 1997, as applicable. Although pro forma results of operations
are not necessarily indicative of the combined results of operations that
actually would have occurred had the acquisition occurred on such date, the
Company believes that the presentation of pro forma data provides a more
meaningful comparative standard for assessing changes in the Company's
consolidated results of operations.
The following table presents on (i) an actual basis and (ii) a pro forma
basis operating income for each of the Company's business segments for the three
and nine month periods ended September 30, 1997 and 1996, as if the acquisition
of NorAm had occurred as of January 1, 1997 or 1996, as applicable.
-19-
<PAGE> 20
OPERATING INCOME (LOSS)
BY BUSINESS SEGMENT
(in millions)
<TABLE>
<CAPTION>
Actual Pro Forma
------ ---------
Three Months Ended Three Months Ended
September 30, September 30,
1997 1996 1997 1996
--------- -------- -------- -------
<S> <C> <C> <C> <C>
Electric Operations $ 456.6 $ 438.9 $ 456.6 $ 438.9
Natural Gas Distribution (6.2) (14.6) (21.1)
Interstate Pipelines 13.7 19.3 24.0
Energy Marketing and Gathering 5.1 0.2 6.8
International 6.4 3.3 5.6 2.5
Corporate (12.9) (1.1) (34.4) (1.0)
-------- -------- ------- ---------
Total Consolidated $ 462.7 $ 441.1 $ 432.7 $ 450.1
======== ======== ======= =========
</TABLE>
<TABLE>
<CAPTION>
Actual Pro Forma
------ ---------
Nine Months Ended Nine Months Ended
September 30, September 30,
1997 1996 1997 1996
--------- -------- --------- -------
<S> <C> <C> <C> <C>
Electric Operations $ 883.4 $ 883.7 $ 883.4 $ 883.7
Natural Gas Distribution (6.2) 92.8 95.3
Interstate Pipelines 13.7 77.1 72.9
Energy Marketing and Gathering 5.1 3.8 34.8
International 14.4 (19.6) 12.5 (21.8)
Corporate (44.3) (1.1) (71.0) (25.9)
------- ------- ------- ---------
Total Consolidated $ 866.1 $ 863.0 $ 998.6 $ 1,039.0
======= ======= ======= =========
</TABLE>
ELECTRIC OPERATIONS
The Company's domestic electric operations are conducted under the name
"Houston Lighting & Power Company," an unincorporated division of the Company
(Electric Operations). Electric Operations provides electric generation,
transmission, distribution and sales to approximately 1.6 million customers in a
5,000 square mile area on the Texas Gulf Coast, including Houston (the nation's
fourth largest city). Electric Operations constitutes the Company's largest
business unit, representing 106% and 88%, respectively, of the Company's
consolidated pro forma operating income for the three month and nine month
periods ended September 30, 1997.
The following table provides summary data regarding the results of
operations of Electric Operations for the three and nine month periods ended
September 30, 1997 and 1996. Results of operations data for Electric Operations
are presented on an actual basis.
-20-
<PAGE> 21
ACTUAL
RESULTS OF OPERATION
(in millions)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Percent Percent
1997 1996 Change 1997 1996 Change
---- ---- ------ ---- ---- ------
<S> <C> <C> <C> <C> <C> <C>
Base Revenues $ 916.2 $ 855.0 7 $ 2 ,160.2 $ 2,150.2 --
Transmission Revenues 21.5 -- 64.4 --
Reconcilable Fuel Revenues 449.6 375.3 20 1,062.2 992.0 7
Operating Expenses:
Fuel and Purchased Power 465.6 391.3 19 1,111.6 1,041.9 7
Operation and Maintenance 245.9 206.7 19 690.4 637.6 8
Depreciation and
Amortization 151.2 130.1 16 412.2 387.9 6
Other Taxes 68.0 63.3 7 189.2 191.1 (1)
Operating Income $ 456.6 $ 438.9 4 $ 883.4 $ 883.7 --
</TABLE>
OPERATIONS DATA
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Percent Percent
1997 1996 Change 1997 1996 Change
---- ---- ------ ---- ---- ------
<S> <C> <C> <C> <C> <C> <C>
Electric Sales (MWH):
Residential 7,633,159 6,520,694 17 15,557,785 15,297,424 2
Commercial 4,558,281 4,288,243 6 11,826,003 11,251,882 5
Industrial 7,837,044 8,047,587 (3) 22,574,240 22,481,860 --
Average Cost of Fuel
(Cents/MMBtu) 190.9 180.9 6 184.2 184.7 --
</TABLE>
In the third quarter of 1997, operating income for Electric Operations
increased by $17.7 million over operating income for the third quarter of 1996.
Operating income for the first nine months of 1997 decreased slightly from
operating income for the same period in 1996. The increase in operating income
for the quarter is due to warmer weather in the third quarter of 1997 over the
same period in 1996 and steady customer growth. Partially offsetting these
effects were increased operation and amortization expense, as described below.
The decrease in operating income between the nine month period ended September
30, 1997, compared to the same period last year was due to milder weather and
increased amortization expense, partially offset by customer growth and
increased usage.
ELECTRIC OPERATIONS -- REVENUES
Total operating revenues for Electric Operations increased by $157.0
million during the three month period ended September 30, 1997, and increased by
$144.6 million for the nine months ended September 30, 1997 compared to the same
periods in 1996.
Base Revenues. Base revenues include electric sales (excluding fuel),
miscellaneous revenues (excluding transmission revenue), certain
non-reconcilable fuel, and certain purchased power related revenues. Base
revenues increased $61.2 million for the third quarter of 1997 and $10.0 million
for the first nine months of 1997 (7.2% and 0.5%, respectively) compared to the
same
-21-
<PAGE> 22
periods of 1996. The third quarter increase was primarily due to warmer weather
as compared to the same period in 1996 and steady customer growth. Base revenues
between the two nine month periods were relatively constant due to the net
effect of milder weather offset by steady customer growth, as mentioned above.
Transmission Revenues. Transmission revenues include revenues collected
through a pricing and billing mechanism implemented by the Utility Commission
for wholesale transmission services. During the three and nine month periods
ended September 30, 1997, Electric Operations recorded $21.5 million in revenues
(offset by $22.1 million in expenses) and $64.4 million in revenues (offset by
$66.3 million in expenses) associated with wholesale transmission services,
respectively. For additional information, see "-- Electric
Operations--Expenses--Operation and Maintenance Expense" below and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Certain Factors Affecting Future Earnings of the Company and
HL&P--Competition--Competition in Wholesale Market" in the Company's Form 10-K.
Fuel Revenues. Fuel revenues include revenues generated by a fixed fuel
factor established by the Utility Commission and included in electric rates to
permit the Company to recover certain fuel and purchased power costs. The fixed
fuel factor is established during general rate proceedings or periodic fuel
factor proceedings. The fixed fuel factor is generally effective for a minimum
of six months. Since reconcilable fuel revenues are adjusted monthly to equal
expenses, fuel revenues and expenses have no effect on earnings unless the
Utility Commission subsequently determines that a utility's fuel costs are not
recoverable.
In 1997, the Company implemented (i) a $70 million temporary fuel surcharge
(inclusive of interest) effective for the first six months of 1997 and (ii) a
$62 million temporary fuel surcharge (inclusive of interest) effective for the
last six months of 1997. In October 1997, HL&P filed with the Utility Commission
a request to implement a $102 million temporary fuel surcharge, inclusive of
interest, beginning in January 1998 and extending from 8 months to 16 months
depending on the customer class. HL&P requested the surcharge in order to
recover its under-recovery of fuel expenses for the period March 1997 through
August 1997. Fuel surcharges have no effect on earnings. At September 30, 1997,
the Company's cumulative under-recovery of fuel costs was $154 million. The
adjusted over/under recovery of fuel costs is recorded on the Company's Balance
Sheets as fuel-related credits or fuel-related debits. For information regarding
the recovery of fuel costs, see "Business of HL&P--Fuel--Recovery of Fuel Costs"
in Item 1 of the Company's Form 10-K.
ELECTRIC OPERATIONS -- EXPENSES
Fuel and Purchased Power Expense. Electric Operations' fuel expenses for
the three and nine month periods ended September 30, 1997 increased $46.8
million and $14.9 million, respectively, compared with the same periods in 1996.
The third quarter increase is the result of an increase in kilowatt-hour (KWH)
sales due to warmer weather and an increase in the per unit cost of fuel. The
increase for the nine month period ended September 30, 1997 is primarily the
result of an increase in KWH sales.
Purchased power expense for the third quarter of 1997 increased $27.5
million compared with the same period in 1996. Purchased power expenses for the
nine month period ended September 30, 1997 increased $54.8 million compared with
the same period in 1996. The overall increase in purchased power expenses was in
part due to greater energy sales and a planned refueling outage at the South
Texas Project.
Operation and Maintenance Expense. Operation expense increased 11% for the
third quarter of 1997 and remained constant for the nine months ended September
30, 1997, compared to the same period in 1996, excluding $22.1 million in the
third quarter 1997 and $66.3 million in the
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<PAGE> 23
nine months ended September 1997 due to transmission tariffs within the Electric
Reliability Council of Texas. As discussed above, in the nine months ended
September 30, 1997, the Company recorded $66.3 million of expenses which is
substantially offset by $64.4 million of revenue associated with wholesale
transmission services. These additional expenses do not reflect a significant
increase in HL&P's cost of providing transmission service.
Maintenance expense remained constant for the third quarter of 1997 and
decreased $15 million (8%) for the nine months ended September 30, 1997 compared
to the same periods in 1996. The decrease is primarily due to two outages at
solid fuel plants in 1996 compared to no corresponding outages in 1997. One
outage is planned for the fourth quarter of 1997.
Depreciation and Amortization Expense. Depreciation and amortization
expense increased in the third quarter and first nine months of 1997 when
compared to the same period in 1996 primarily because of $19 million of
additional amortization of the Company's investment in lignite reserves
associated with a canceled generation project. For additional information
regarding these expenses, see Note 3(a) to the Financial Statements included in
the Company's Form 10-K.
NATURAL GAS DISTRIBUTION
The Company's domestic natural gas distribution operations are conducted by
NorAm (through its Arkla, Entex and Minnegasco divisions) and are included in
the Company's actual consolidated results of operations from August 6, 1997, the
effective date of the Merger. These operations consist of natural gas sales to,
and natural gas transportation for, residential, commercial and a limited number
of industrial customers in six states: Arkansas, Louisiana, Minnesota,
Mississippi, Oklahoma and Texas.
The following table provides summary data regarding the pro forma financial
results of operations of the Natural Gas Distribution segment, including
operating statistics, for the three and nine month periods ended September 30,
1997 and 1996. Results of operations data are presented on a pro forma basis as
if the Merger had occurred as of January 1, 1996 and 1997, as applicable.
PRO FORMA
RESULTS OF OPERATIONS
(in millions)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
----------------------- ---------------------
Percent Percent
1997 1996 Change 1997 1996 Change
---------- ----------- ------ --------- -------- ------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 272.2 $ 256.5 6.1 $1,490.0 $1,417.5 5.1
Operating Expenses 286.8 277.6 3.3 1,397.2 1,322.2 5.7
--------- --------- -------- --------
Operating Income (Loss) $ (14.6) $ (21.1) 30.8 $ 92.8 $ 95.3 (2.6)
========= ========= ======== ========
</TABLE>
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<PAGE> 24
OPERATIONS DATA
(in Bcf)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Percent Percent
1997 1996 Change 1997 1996 Change
--------- ---------- ------ ------------ ----------- ------
--------- ---------- ------------ -----------
<S> <C> <C> <C> <C> <C> <C>
Residential and Commercial Sales 31.7 31.3 1.3 219.7 230.5 (4.7)
Industrial Sales 14.0 13.7 2.2 42.6 41.8 1.9
Transportation 8.9 9.5 (6.3) 30.8 32.5 (5.2)
-------- --------- ------- --------
Total Throughput 54.6 54.5 0.2 293.1 304.8 (3.8)
======== ========= ======= =========
</TABLE>
For the third quarter of 1997, Natural Gas Distribution pro forma operating
loss was $14.6 million compared with a loss of $21.1 million for the same period
in 1996. The approximately $6.5 million increase in operating income in 1997
reflects the impact of rate increases, a small increase in sales volume and
reduced operating expenses. For additional information on rate increases, see
"Management Analysis--Material Changes in the Results of Continuing
Operations--Regulatory Matters" in NorAm's Form 10-K.
For the nine months ended September 30, 1997, Natural Gas Distribution had
pro forma operating income of $92.8 million compared with $95.3 million for the
same period in 1996. The approximately $2.5 million decrease (2.6%) in pro forma
operating income was principally due to a weather-related decline in residential
and commercial sales volumes and a small increase in 1997 operating expenses.
These negative factors were partially offset by an increased 1997 average margin
per unit of sales, principally due to rate increases in certain jurisdictions.
INTERSTATE PIPELINE
The Company's interstate natural gas pipeline operations (Interstate
Pipeline) are conducted through NorAm Gas Transmission Company (NGT) and
Mississippi River Transmission Corporation (MRT), two wholly owned subsidiaries
of NorAm. The NGT system consists of approximately 6,200 miles of natural gas
transmission lines located in portions of Arkansas, Louisiana, Mississippi,
Missouri, Kansas, Oklahoma, Tennessee and Texas. The MRT system consists of
approximately 2,000 miles of pipeline serving principally the greater St. Louis
area in Missouri and Illinois. The results of operations of Interstate Pipeline
are included in the Company's actual consolidated results of operations from
August 6, 1997, the effective date of the Merger.
The following table provides summary data regarding the pro forma results
of operations of the Interstate Pipeline segment, for the three and nine month
periods ended September 30, 1997 and 1996. Results of operations data are
presented on a pro forma basis as if the Merger had occurred as of January 1,
1996, and 1997, as applicable.
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<PAGE> 25
PRO FORMA
RESULTS OF OPERATIONS
(in millions)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Percent Percent
1997 1996 Change 1997 1996 Change
---------- ----------- ------ ---------- ---------- ------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 68.9 $ 84.9 (18.9) $ 225.7 $ 266.4 (15.2)
Operating Expenses 49.6 60.9 (18.6) 148.6 193.5 (23.2)
--------- ---------- --------- ---------
Operating Income $ 19.3 $ 24.0 (19.6) $ 77.1 $ 72.9 5.7
========= ========== ========= ==========
</TABLE>
OPERATIONS DATA
(million MMBtu)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Percent Percent
1997 1996 Change 1997 1996 Change
------- ------- ------ ---------- -------- ------
<S> <C> <C> <C> <C> <C> <C>
Natural Gas Sales: 4.4 7.7 (42.9) 13.8 28.0 (50.7)
Transportation: 205.3 198.4 3.5 667.2 714.2 (6.6)
Elimination (4.2) (7.3) 42.5 (12.9) (26.4) 51.1
------- -------
Total Throughput 205.5 198.8 3.4 668.1 715.8 (6.7)
======= ======= ===== =====
</TABLE>
Interstate Pipeline pro forma operating income for the third quarter of
1997 was $19.3 million compared with $24 million for the same period in 1996.
The approximately $4.7 million decrease (19.6%) in pro forma operating income is
primarily attributable to a decline in operating margins due to (i) the
elimination of margins on sales by Interstate Pipeline to Natural Gas
Distribution and (ii) a combination of lower electric generation load and
reductions in price differentials between Gulf Coast and Mid-Continent gas
supplies. The reduction in price differentials had the effect of increasing
competitive pressures on transportation rates thereby reducing the average
transportation margin.
The increase of approximately $4.2 million (5.7%) in pro forma Interstate
Pipeline's operating income (before the charge for early retirement and
severance) for the nine months ended September 30, 1997 in comparison to the
corresponding period of 1996 was principally due to reduced 1997 operating
expenses associated with cost reduction initiatives implemented in first quarter
1996, together with the 1996 incurrence of certain consulting and other
non-recurring costs associated with these initiatives. Operating margins
declined only modestly because (i) current year transportation revenues for
Natural Gas Distribution are at higher rates due to removal in late 1996 of a
rate cap and (ii) declines in transportation volume have a less than
proportional impact on margins due to Interstate Pipeline's rate design. For
additional information, see "Management Analysis--Material Changes in the
Results of Continuing Operations--Interstate Pipeline" in NorAm's Form 10-K.
ENERGY MARKETING AND GATHERING
The Company's Energy Marketing and Gathering segment (Energy Marketing)
includes the operations of the Company's wholesale and retail energy marketing
businesses (conducted, respectively, by NorAm Energy Services, Inc. (NES) and
NorAm Energy Management, Inc.) and natural gas gathering activities (conducted
by NorAm Field Services Corp.).
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<PAGE> 26
The following table provides summary data regarding the pro forma results of
operations of the Energy Marketing segment, including operating statistics, for
the three and nine month periods ended September 30, 1997 and 1996. Results of
operations data are presented on a pro forma basis as if the Merger had occurred
as of January 1, 1997 and 1996, as applicable.
PRO FORMA
RESULTS OF OPERATIONS
(in millions)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Percent Percent
1997 1996 Change 1997 1996 Change
-------- --------- ------ --------- -------- ------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 842.0 $ 636.3 32.3 $ 2,535.3 $ 1,835.6 38.1
Operating Expenses 841.8 629.5 33.7 2,531.5 1,800.8 40.6
-------- --------- --------- ---------
Operating Income $ 0.2 $ 6.8 (97.1) $ 3.8 $ 34.8 (89.1)
======== ========= ========= =========
</TABLE>
OPERATIONS DATA
(in Bcf)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Percent Percent
1997 1996 Change 1997 1996 Change
-------- ------- ------ --------- --------- ------
<S> <C> <C> <C> <C> <C> <C>
Natural Gas Sales Volume 266.8 264.3 .9 846.0 749.8 12.8
Transportation Volumes 4.9 5.0 (2.0) 17.3 19.7 (12.2)
Gathering Volumes 59.6 58.0 2.8 181.5 170.0 6.8
------- ------ -------- ---------
Total 331.3 327.3 1.2 1,044.8 939.5 11.2
======= ====== ======== =========
</TABLE>
For the third quarter of 1997, Energy Marketing pro forma operating income
was $0.2 million compared with $6.8 million for the same period in 1996. The
approximately $6.6 million decrease was primarily due to decreased margins and
increased general and administrative costs associated with increased staffing
levels.
Energy Marketing's pro forma operating income for the nine months ended
September 30, 1997 decreased approximately $31.0 million compared with the same
period in 1996. The decrease was principally due to (i) hedging losses
associated with anticipated first-quarter 1997 sales under peaking contracts and
(ii) losses from the sale of natural gas held in storage and unhedged in the
first quarter of 1997 for a total of $17.4 million. For additional information,
see "Management Analysis--Material Changes in the Results of Continuing
Operations--Wholesale Energy Marketing" in NorAm's Form 10-K. In addition,
Energy Marketing's general and administrative expenses for 1997 increased by
approximately $8 million primarily due to increased staffing and marketing
activities. Partially offsetting these unfavorable impacts were increased
margins from natural gas gathering and products extraction activities.
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<PAGE> 27
INTERNATIONAL
The Company's international business segment (International) principally
includes the results of operations of Houston Industries Energy, Inc. (HI
Energy), a wholly owned subsidiary of the Company that participates in the
development and acquisition of foreign independent power projects and the
privatization of foreign generation and distribution facilities, and the
international operations of Former NorAm.
The following table provides summary data regarding the results of
operations of International for the three and nine month periods ended September
30, 1997 and 1996. Results of operations data for International are presented on
a pro forma basis as if the Merger had occurred as of January 1, 1997 and 1996,
as applicable.
PRO FORMA
RESULTS OF OPERATIONS
(in millions)
<TABLE>
<CAPTION>
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
Percent Percent
1997 1996 Change 1997 1996 Change
---- ---- ------ ---- ---- ------
<S> <C> <C> <C> <C> <C> <C>
Equity Earnings 11.5 6.0 92 29.5 6.4 361
Operating Income (Loss) 5.6 2.5 124 12.5 (21.8) --
Net Income (Loss) 7.2 3.9 85 13.3 (8.4) --
</TABLE>
During the third quarter and first nine months of 1997, International's pro
forma operating income was $5.6 million and $12.5 million, respectively,
compared to $2.5 million and a loss of $21.8 million in the same periods in
1996. Operating losses for the first nine months of 1996 included pre-tax
non-recurring charges of approximately $8 million associated with an investment
in two tire-to-energy plants in Illinois. Excluding non-recurring charges,
International's losses for the first nine months of 1996 would have been $13.8
million. The increase in operating income is due primarily to increased equity
earnings from entities in which HI Energy owns an interest.
Excluding the 1996 after-tax non-recurring charges related to the
tire-to-energy plant ($5 million), the increase in net income compared to
operating income each period is due to tax benefits related to International's
corporate expenses.
As of September 30, 1997, HI Energy's consolidated debt equaled $167.5
million. Substantially all of the debt is non-recourse to the Company and
limited recourse to HI Energy.
As disclosed in the Company's Form 10-K, HI Energy had expected to complete
development in late 1997 of a 160 MW cogeneration facility in Argentina. The
estimated cost of completion of the project was $100 million. In October 1997,
certain components that comprise the generating unit for this project suffered
extensive damage during testing. Based on current information, the delay in the
commercial operation date for the project could be substantial. However, it is
not anticipated that such delay will have a material adverse financial impact on
HI Energy because payments due from the construction consortium pursuant to the
construction contract relating to this project are expected to offset the cost
of liquidated damages owed by HI Energy to the host plant and the project fuel
supplier.
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<PAGE> 28
CORPORATE
Corporate. The Company's Corporate and other business segment (Corporate)
includes the operations of HI Power Generation, Inc., which is engaged in the
development and operation of domestic power generation projects (HIPG), the
Company's unregulated retail electric services business, certain real estate
investments, corporate costs, and inter-unit eliminations.
Corporate pro forma operating loss increased by $33.4 million and $45.1
million for the third quarter and nine months ended September 30, 1997,
respectively, as compared to the same two periods in 1996. The increase in
operating losses for the third quarter ended September 30, 1997 as compared to
the same period last year was primarily due to merger related expenses incurred
by NorAm which were not capitalized and development costs associated with the
Company's utility services business; consumer services business; unregulated
retail electric services business; and expenses related to the development and
operation of domestic power generation projects. The increase in operating
losses for the nine months ended September 30, 1997 as compared to the same
period in 1996 was due to the same factors that affected the third quarter
results. In addition, pre-tax operating expenses increased $19 million due to
the establishment of a charitable foundation formed to fund certain charitable
activities previously funded by the Company.
HIPG. HIPG was formed in March 1997 to pursue the acquisition of domestic
electric generation assets as well as the development of new domestic
independent power generation facilities. Since its formation, HIPG has
participated in a number of sales of utility generation plants that have been
conducted in connection with various state initiatives to restructure the
electric utility industry. HIPG expects to spend approximately $200 to $260
million in 1997 pursuant to commitments entered into with respect to bids
previously awarded to HIPG and bids previously submitted by HIPG but pending
award. The bulk of this amount relates to bids already awarded to HIPG. The
Company expects that HIPG will continue to participate in a number of future
sales of generation assets. Depending on the timing and success of HIPG's future
bidding efforts, expenditures resulting from these sales could be significant.
HIPG is also participating in the development of several independent power
generation facilities, including, among others, the El Dorado Project located in
Boulder City, Nevada (El Dorado Project). The El Dorado Project is an
approximately 450 megawatt gas-fired power plant. Upon completion of
construction and subject to the successful negotiation of various project
development agreements, it is expected that the output of the El Dorado Project
will be sold on the wholesale market. The El Dorado Project is being developed
jointly with Enova Corp., the parent company of San Diego Gas & Electric Co.
Based on current information, it is anticipated that HIPG will spend
approximately $12 million in 1997 in connection with the El Dorado Project.
The Company believes that HIPG's efforts to develop or acquire generation
assets will complement its other operations, including the trading and marketing
activities of NES. For example, it is currently anticipated that NES will supply
approximately 50% of the gas requirements of the El Dorado Project and will
purchase approximately 50% of the electric output of the project.
The Company's estimates regarding HIPG expenditures are forward-looking
statements and are based on numerous assumptions, some of which may prove to be
incorrect. HIPG's actual capital requirements could vary because of changes in
economic conditions, changes in governmental regulations and other factors.
Although it is HIPG's intent to seek project financing where possible to fund
its projects there can be no assurance given concerning the cost, amount and
availability of such funding sources.
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<PAGE> 29
LIQUIDITY AND CAPITAL RESOURCES
The Company generated $947 million in cash flow from operations during the
nine month period ended September 30, 1997. Substantially all of this cash flow
was produced from $425 million of income from continuing operations and $447
million of depreciation and amortization expense. The Company used this cash
flow to reinvest in its existing businesses, to meet its dividend requirements
and to contribute to the financing of business expansion.
Overall, the Company's cash flow from operating activities in the nine
month period ended September 30, 1997 exceeded its cash flow from
non-acquisition investing activities by $781 million. With respect to
acquisition activities, the Company invested $1.4 billion of cash in the
acquisition of NorAm and $215 million of cash in non-regulated electric power
project expenditures and advances during the nine month period ended September
30, 1997.
During the nine months ended September 30, 1997, the Company's financing
activities included the issuance of $1.052 billion aggregate face amount of ACE
Securities ($1.021 billion net of issuance costs). The Company used the proceeds
of the sale of the ACE Securities for general corporate purposes, including the
retirement of an equivalent amount of then outstanding Former HI commercial
paper. For additional information regarding the ACE Securities, see Note 5(c) to
the Interim Financial Statements.
In August 1997, FinanceCo, a limited partnership subsidiary of the Company,
entered into the FinanceCo Facility, a five-year, $1.6 billion revolving credit
facility. At September 30, 1997, the FinanceCo Facility supported $1.3 billion
in commercial paper borrowings having a weighted average interest rate of 5.91%.
Proceeds from the initial issuances of commercial paper by FinanceCo were used
to fund the cash portion of the consideration paid to stockholders of Former
NorAm under the terms of the Merger. For additional information regarding the
FinanceCo Facility, see Note 5(b) to the Interim Financial Statements.
At September 30, 1997, the Company, exclusive of subsidiaries, had a
revolving credit facility of $200 million with no borrowings outstanding. In
addition, at September 30, 1997, the Company had shelf registration statements
providing for the future issuance, subject to market and other conditions, of
$230 million aggregate liquidation value of its preferred stock and $580 million
aggregate principal amount of its debt securities.
At September 30, 1997, NorAm had (i) a $400 million revolving credit
facility under which loans of $135 million were outstanding, (ii) uncommitted
lines of credit under which loans of $45 million were outstanding, (iii) a trade
receivables facility of $300 million under which receivables of $295 million
have been sold and (iv) a shelf registration statement providing for the future
issuance of debt and equity securities of up to $213.9 million.
For information regarding the Company's maturing long-term debt (including
NorAm's long-term debt), see Note 5 to the Interim Financial Statements.
The Company believes that its current level of cash and borrowing
capability along with future cash flows from operations are sufficient to meet
the needs of its existing businesses. However, to achieve its objectives, the
Company may, when necessary, supplement its available cash resources by seeking
funds in the equity or debt markets.
The Company is currently evaluating its computer and software requirements
in light of changes in the electric utility and energy services industries and
the acquisition of NorAm and resulting expansions of the Company into energy
trading activities. The Company is also evaluating
-29-
<PAGE> 30
various alternatives intended to permit its existing computer programs to
accommodate the year 2000 and beyond, currently estimated to cost approximately
$15 million. In September 1997, the Company entered into an agreement with SAP
America, Inc. (SAP) to license SAP's proprietary R/3 enterprise software. The
licensed software includes financial and accounting, human resources, materials
management and service delivery components. Based on the current timetable for
completion of the SAP implementation and integration project (Project), the
Company estimates that the third party cost of the Project will be approximately
$95 million (including software license fees, fees for consulting and other
services and hardware acquisition costs). It is currently projected that these
costs would be incurred over a three-year period. The Company is also
considering installing a customer information system offered by SAP.
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
For information on developments, factors, and trends that may have an
impact on the Company's future earnings, reference is made to (i) Item 7 of the
Company's Form 10-K, "Management's Discussion and Analysis of Financial
Condition and Results of Operations--The Merger" and"--Certain Factors Affecting
Future Earnings of the Company and HL&P," Item 2 of the Company's First Quarter
10-Q, "Management's Discussion and Analysis of Financial Condition and Results
of Operations--Recent Developments" and (ii) Item 7 of NorAm's Form 10-K
"Management Analysis--Commitments and Contingencies."
RATE MATTERS
ELECTRIC OPERATIONS. The Utility Commission has jurisdiction (or, in some
cases, appellate jurisdiction) over the electric rates of the Company's Electric
Operations Division (also known as HL&P) and as such monitors HL&P's earnings to
ensure that HL&P is not earning in excess of its permitted rate of return.
In October, 1997, HL&P announced a proposed transition plan and price
reduction plan relating to retail access to electric services for its customers
(Transition Plan).
Subject to the approval of the Transition Plan, HL&P would agree to support
legislation providing (i) retail customer choice effective December 31, 2001;
(ii) customer safeguards and rate reductions effective January 1, 2000 and
January 1, 2001; and (iii) securitization and stranded cost determination and
recovery provisions on terms substantially similar to those contained in the
final bill on electric deregulation as considered in the 1997 Texas legislative
session.
In addition, HL&P has proposed (i) granting residential customers a base
rate reduction of 4% effective January 1, 1998, with an additional 2% base
reduction effective January 1, 1999; (ii) granting commercial and small
industrial customers a base rate reduction of 2% effective January 1, 1998; and
(iii) implementing, subject to certain force majeure events, a freeze on HL&P's
retail and wholesale base rate tariffs (excluding fuel and purchased power cost
recovery). The rate freeze and rate credits would extend through the earlier of
December 31, 1999 or the effective date of certain legislative or regulatory
action resulting in amendments to Title 2 of the Utilities Code or HL&P's rates
(Rate Freeze Period).
During the Rate Freeze Period, HL&P's overall regulated rate of return on
invested capital would not exceed 10.03%. Any return above 10.03% would be
applied to reduce potentially stranded costs. In addition, HL&P would be allowed
to redirect depreciation expense from transmission and distribution investments
to generation production investments.
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<PAGE> 31
The Transition Plan would be subject to the approval of the Utility
Commission upon the plan's formal submission to the Commission. At present, the
Company cannot predict what action the Utility Commission would take once the
Transition Plan is submitted for approval or the ultimate terms that such plan
might contain.
NorAm. A substantial portion of NorAm's earnings are derived from
operations, such as Natural Gas Distribution and Interstate Pipeline, that are
subject to state and federal rate regulation. For information regarding these
and other regulations affecting NorAm and its subsidiaries, see "Management
Analysis--Material Changes in the Results of Continuing Operations--Regulatory
Matters" in NorAm's Form 10-K.
ACCOUNTING TREATMENT OF ACE SECURITIES
The Company accounts for its investment in Time Warner Convertible
Preferred Stock under the cost method. As a result of the Company's issuance of
the ACE Securities, certain increases in the market value of Time Warner common
stock (the security into which the Time Warner Convertible Preferred Stock is
convertible) could result in an accounting loss to the Company, pending the
conversion of the Company's Time Warner Convertible Preferred Stock into Time
Warner common stock.
If, prior to the conversion of the Time Warner Convertible Preferred Stock
into Time Warner common stock, the market price of Time Warner common stock
were to increase above $55.5844, the Company would record in Other Income
(Expense) an accounting loss equal to (i) the aggregate amount of such increase
as applicable to all ACE Securities multiplied by (ii) 0.8264. In accordance
with generally accepted accounting principles, this accounting loss (which
reflects the unrealized increase in the Company's indebtedness with respect to
the ACE Securities) may not be offset by accounting recognition of the increase
in the market price of the Time Warner common stock. Upon conversion of the
Time Warner Convertible Preferred Stock, the Company would begin recording
unrealized net changes in the market prices of the Time Warner common stock and
the ACE Securities as a component of common stock equity.
If as of September 30, 1997, the market price of Time Warner common stock
had been $57 11/16 (the closing market price of Time Warner common stock on
October 31, 1997), the liability for the ACE Securities would have increased by
approximately $40 million. This unrealized loss for the ACE Securities is more
than economically hedged by the approximately $330 million unrecorded unrealized
gain relating to the increase in the fair value of the Time Warner common stock
underlying the investment in Time Warner Convertible Preferred Stock on the
date of its acquisition.
NEW ACCOUNTING ISSUES
The Financial Accounting Standards Board recently issued SFAS No. 130,
"Reporting Comprehensive Income" and SFAS No. 131, "Disclosures about Segments
of an Enterprise and Related Information" effective for financial statements
issued for periods beginning after December 15, 1997. SFAS No. 130 requires that
all items that meet the definition of a component of comprehensive income be
reported in a financial statement for the period in which they are recognized
and the total amount of comprehensive income be prominently displayed in that
same financial statement. Comprehensive income is defined as the change in
equity of a business enterprise during a period from transactions and other
events and circumstances from non-owner sources. Currently, the Company does
not have any material items which require reporting of comprehensive income.
SFAS No. 131 requires that companies report financial and descriptive
information about reportable operating segments in financial statements.
Segment information to be reported is to be based upon the way management
organizes the segments for making operating decisions and assessing
performance. The Company will adopt SFAS No. 130 and SFAS No. 131 beginning the
first quarter of 1998.
For information regarding SFAS No. 128, "Earnings Per Share," which will
be effective for the Company's 1997 fiscal year, see Note 4(b) to the Interim
Financial Statements and Note 5 in the First Quarter 10-Q.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS.
Not Applicable.
-31-
<PAGE> 32
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.
For a description of legal proceedings affecting the Company and its
subsidiaries, including NorAm and HI Energy, reference is made to the
information set forth in the following items and notes:
With respect to the Company, Item 3 of the Company's Form 10-K and
Notes 2(b), 3, 10 and 11(c) to the financial statements in the
Company's Form 10-K, which information, as qualified and updated by the
description of developments in regulatory and litigation matters
contained in Note 8 to the financial statements in the Company's First
Quarter Form 10-Q, Note 7 to the financial statements in the Company's
Second Quarter Form 10-Q and Note 8 to the Interim Financial Statements
in this Form 10-Q, is incorporated herein by reference.
With respect to NorAm and its subsidiaries, Item 3 of NorAm's Form
10-K, "Management Analysis--Material Changes in the Results of
Continuing Operations--Regulatory Matters" in Item 7 of NorAm's Form
10-K and Note 7 to the financial statements in NorAm's Form 10-K, which
information, as qualified and updated by the description of
developments in regulatory and litigation matters contained in Notes G
and H to the financial statements in NorAm's First Quarter Form 10-Q
and Notes K and L to the financial statements in NorAm's Second Quarter
Form 10-Q, is incorporated herein by reference.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.
(a) Exhibits. (Exhibits designated by an asterisk (*) are incorporated
herein by reference to a separate filing as indicated.)
Houston Industries Incorporated:
Exhibit 11 - Computation of Earnings per Common Share and Common
Equivalent Share.
Exhibit 27 - Financial Data Schedule.
Exhibit 99(a)- Notes 1-4, 10 and 11 to the Financial Statements
included on pages 60-66 and 74-77 of the Company's
Form 10-K and Item 3 included on page 21 of the
Company's Form 10-K.
Exhibit 99(b)- Note 8 to the Financial Statements included on pages
16 and 17 of the Company's First Quarter Form 10-Q.
Exhibit 99(c)- Note 7 to the Financial Statements included on pages
15 and 16 of the Company's Second Quarter Form 10-Q.
Exhibit 99(d)- Notes 1 and 7 to the Financial Statements included on
pages 64-69 and 83-88 of NorAm's Form 10-K (File No.
1-3751), Item 3 included on page 14 of NorAm's Form
10-K and "Item 7. Management Analysis--Material
Changes in the Results of Continuing
Operations--Regulatory Matters" included on
-32-
<PAGE> 33
pages 22-24 of NorAm's Form 10-K.
Exhibit 99(e)- Notes G and H to the Financial Statements included on
pages 11 and 12 of NorAm's First Quarter Form 10-Q.
Exhibit 99(f)- Notes K and L to the Financial Statements included on
pages 12-14 of NorAm's Second Quarter Form 10-Q.
(b) Reports on Form 8-K.
Report on Form 8-K of the Company and Former HI dated August 6, 1997
relating to the acquisition of NorAm (Item 2).
-33-
<PAGE> 34
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
HOUSTON INDUSTRIES INCORPORATED
(Registrant)
/s/ Mary P. Ricciardello
--------------------------------------
Mary P. Ricciardello
Vice President and Comptroller
(Principal Accounting Officer)
Date: November 14, 1997
<PAGE> 35
INDEX TO EXHIBITS
Exhibit 11 - Computation of Earnings per Common Share and Common
Equivalent Share.
Exhibit 27 - Financial Data Schedule.
Exhibit 99(a)- Notes 1-4, 10 and 11 to the Financial Statements
included on pages 60-66 and 84-77 of the Company's
Form 10-K and Item 3 included on page 21 of the
Company's Form 10-K.
Exhibit 99(b)- Note 8 to the Financial Statements included on pages
16 and 17 of the Company's First Quarter Form 10-Q.
Exhibit 99(c)- Note 7 to the Financial Statements included on pages
15 and 16 of the Company's Second Quarter Form 10-Q.
Exhibit 99(d)- Notes 1 and 7 to the Financial Statements included on
pages 64-69 and 83-88 of NorAm's Form 10-K (File No.
1-3751), Item 3 included on page 14 of NorAm's Form
10-K and "Item 7. Management Analysis--Material
Changes in the Results of Continuing
Operations--Regulatory Matters" included on
pages 22-24 of NorAm's Form 10-K.
Exhibit 99(e)- Notes G and H to the Financial Statements included on
pages 11 and 12 of NorAm's First Quarter Form 10-Q.
Exhibit 99(f)- Notes K and L to the Financial Statements included on
pages 12-14 of NorAm's Second Quarter Form 10-Q.
<PAGE> 1
Exhibit 11
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
COMPUTATION OF EARNINGS PER COMMON SHARE
AND COMMON EQUIVALENT SHARE
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------------------ ----------------------------------
1997 1996 1997 1996
-------------- -------------- ------------ --------------
<S> <C> <C> <C> <C>
Primary Earnings Per Share:
(1) Weighted average shares of
common stock outstanding................... 263,373 245,889 243,769 247,664
(2) Effect of issuance of shares
from assumed exercise of
stock options (treasury stock method)...... 196 19 206 24
-------------- -------------- ------------ --------------
(3) Weighted average shares.................... 263,569 245,908 243,975 247,688
============== ============== ============ ==============
(4) Net income................................. $ 243,898 $ 240,024 $ 424,981 $ 368,618
(5) Primary earnings per share
(line 4/line 3)............................ $ 0.93 $ 0.98 $ 1.74 $ 1.49
Fully Diluted Earnings Per Share:
(6) Weighted average shares per
computation on line 3 above................ 263,569 245,908 243,975 247,688
(7) Shares applicable to options
included on line 2 above................... (196) (19) (206) (24)
(8) Dilutive effect of stock
options based on the average
price for the period or quarter-
end price, whichever is higher,
of $21.75 and $22.63 for the
third quarter of 1997 and 1996,
respectively, and $21.75 and
$22.88 for the first nine months
of 1997 and 1996, respectively
(treasury stock method).................... 215 19 215 24
(9) Effect of issuance of shares from
assumed conversion of debentures........... 946 946
(10) Fully diluted
weighted average shares.................... 264,534 245,908 244,930 247,688
============== ============== ============ ==============
(11) Net income................................. $ 243,898 $ 240,024 $ 424,981 $ 368,618
(12) Add: Interest on Bonds, net tax............ 310 930
(13) Fully diluted net income................... $ 244,208 $ 240,024 $ 425,911 $ 368,618
(14) Fully diluted earnings per
share (line 13/line 10).................... $ 0.92 $ 0.98 $ 1.74 $ 1.49
</TABLE>
Notes:
These calculations are submitted in accordance with Regulation S-K item 601(b)
(11) although it is not required for financial presentation disclosure per
footnote 2 to paragraph 14 of Accounting Principles Board (APB) Opinion No. 15
because it does not meet the 3% dilutive test.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
COMPANY'S FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JUL-01-1997
<PERIOD-END> SEP-30-1997
<BOOK-VALUE> PRO-FORMA
<TOTAL-NET-UTILITY-PLANT> 11,188,741
<OTHER-PROPERTY-AND-INVEST> 1,805,383
<TOTAL-CURRENT-ASSETS> 1,061,638
<TOTAL-DEFERRED-CHARGES> 3,958,057
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 18,013,819
<COMMON> 2,866,139
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 2,141,326
<TOTAL-COMMON-STOCKHOLDERS-EQ> 5,007,465
0
9,740
<LONG-TERM-DEBT-NET> 5,353,390
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 475,000
<COMMERCIAL-PAPER-OBLIGATIONS> 1,288,313
<LONG-TERM-DEBT-CURRENT-PORT> 189,240
0
<CAPITAL-LEASE-OBLIGATIONS> 15,936
<LEASES-CURRENT> 1,145
<OTHER-ITEMS-CAPITAL-AND-LIAB> 5,673,590
<TOT-CAPITALIZATION-AND-LIAB> 18,013,819
<GROSS-OPERATING-REVENUE> 4,101,100
<INCOME-TAX-EXPENSE> 197,249
<OTHER-OPERATING-EXPENSES> 3,235,035
<TOTAL-OPERATING-EXPENSES> 3,235,035
<OPERATING-INCOME-LOSS> 866,065
<OTHER-INCOME-NET> 44,659
<INCOME-BEFORE-INTEREST-EXPEN> 910,724
<TOTAL-INTEREST-EXPENSE> 286,175
<NET-INCOME> 427,300
2,319
<EARNINGS-AVAILABLE-FOR-COMM> 424,981
<COMMON-STOCK-DIVIDENDS> 281,145
<TOTAL-INTEREST-ON-BONDS> 164,066<F1>
<CASH-FLOW-OPERATIONS> 946,500
<EPS-PRIMARY> 1.74
<EPS-DILUTED> 1.74
<FN>
<F1>Total annual interest charges on all bonds for year-to-date September 30, 1997.
</FN>
</TABLE>
<PAGE> 1
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1996
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) PRINCIPLES OF CONSOLIDATION. The consolidated financial
statements include the accounts of the Company and its wholly
owned and majority owned subsidiaries. Certain investments in
joint ventures or other entities in which the Company or its
subsidiaries have a 50 percent or less interest are recorded
using the equity method or the cost method. For additional
information regarding investments and advances, see Notes 1(j)
and 4.
All significant intercompany transactions and balances are
eliminated in consolidation.
(b) SYSTEM OF ACCOUNTS AND EFFECTS OF REGULATION. HL&P, the principal
subsidiary of the Company, maintains its accounting records in
accordance with the FERC Uniform System of Accounts. HL&P's
accounting practices are subject to regulation by the Utility
Commission, which has adopted the FERC Uniform System of
Accounts.
As a result of its regulated status, HL&P follows the accounting
policies set forth in SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation," which allows a utility with
cost-based rates to defer certain costs in concert with rate
recovery that would otherwise be expensed. In accordance with
this statement, HL&P has deferred certain costs pursuant to rate
actions of the Utility Commission and is recovering or expects to
recover such costs in electric rates charged to customers. The
regulatory assets are included in other assets on the Company's
Consolidated and HL&P's Balance Sheets. The regulatory
liabilities are included in deferred credits on the Company's
Consolidated and HL&P's Balance Sheets. The following is a list
of significant regulatory assets and liabilities reflected on the
Company's Consolidated and HL&P's Balance Sheets:
<TABLE>
<CAPTION>
December 31, 1996
-----------------
(Millions of Dollars)
<S> <C>
Deferred plant costs - net ............................. $ 587
Malakoff and Trinity mine investments .................. 164
Regulatory tax asset - net ............................. 362
Unamortized loss on reacquired debt .................... 116
Deferred debits ........................................ 102
Unamortized investment tax credit ...................... (374)
Accumulated deferred income taxes-regulatory tax asset . (101)
</TABLE>
If, as a result of changes in regulation or competition, HL&P's
ability to recover these assets and/or liabilities would not be
assured, then pursuant to SFAS Nos. 71, 101 (Accounting for the
Discontinuation of Application of SFAS No. 71) and 121 (Accounting
for the Impairment of Long- Lived Assets and for Long-Lived Assets
to be Disposed of) and to the extent that such regulatory assets
or liabilities ultimately were determined not to be recoverable,
HL&P would be required to write off or write down such assets or
liabilities.
57
<PAGE> 2
(c) ELECTRIC PLANT. HL&P capitalizes at cost all additions to
electric plant, betterments to existing property and replacements
of units of property. Cost includes the original cost of
contracted services, direct labor and material, indirect charges
for engineering supervision and similar overhead items and AFUDC.
AFUDC represents the estimated debt and equity cost of funds used
to finance construction. Customer payments for construction
reduce additions to electric plant.
HL&P computes depreciation using the straight-line method. The
depreciation provision as a percentage of the depreciable cost of
plant was 3.2 percent for 1994 through 1996.
(d) DEFERRED PLANT COSTS. Under a "deferred accounting" plan
authorized by the Utility Commission, HL&P was permitted for
regulatory purposes to accrue carrying costs in the form of AFUDC
on its investment in the South Texas Project and defer and
capitalize depreciation and other operating costs on its
investment after commercial operation until such costs were
reflected in rates. In addition, the Utility Commission
authorized HL&P under a "qualified phase-in plan" to capitalize
allowable costs (including return) deferred for future recovery
as deferred charges.
In 1991, HL&P ceased all cost deferrals related to the South
Texas Project and began amortizing such amounts on a
straight-line basis. The accumulated deferrals for "deferred
accounting" are being amortized over the estimated depreciable
life of the South Texas Project. The accumulated deferrals for
the "qualified phase-in plan" are being amortized over a ten-year
phase-in period that commenced in 1991. The amortization of all
deferred plant costs (which totaled $25.8 million for each of the
years 1996, 1995 and 1994) is included on the Company's
Statements of Consolidated Income and HL&P's Statements of Income
as depreciation and amortization expense.
(e) REVENUES. HL&P records electricity sales under the full accrual
method, whereby unbilled electricity sales are estimated and
recorded each month. Other revenues include electricity sales of
a majority owned foreign electric utility, which are also
recorded under the full accrual method and the Company's equity
income in unconsolidated investments of HI Energy. Also included
in other revenues are management fees and other sales and
services, which are recorded when earned.
(f) INCOME TAXES. The Company and its subsidiaries file a
consolidated federal income tax return. The Company follows a
policy of comprehensive interperiod income tax allocation.
Investment tax credits were deferred and are being amortized over
the estimated lives of the related property.
(g) EARNINGS PER COMMON SHARE. Earnings per common share for the
Company are computed by dividing net income by the weighted
average number of shares outstanding during the respective
period. All earnings per common share amounts reflect the
two-for-one common stock split effected in the form of a stock
distribution on December 9, 1995.
(h) STATEMENTS OF CONSOLIDATED CASH FLOWS. For purposes of reporting
cash flows, cash equivalents are considered to be short-term,
highly liquid investments readily convertible to cash.
(i) DISCONTINUED OPERATIONS. In July 1995, the Company sold KBLCOM,
its cable television subsidiary. The operations of KBLCOM are
reflected as discontinued operations for all periods presented.
See Note 13.
(j) INVESTMENTS IN DEBT AND EQUITY SECURITIES. The Company owns one
million shares of Time Warner common stock and 11 million shares
of non-publicly traded Time Warner convertible preferred stock.
The Company has recorded its investment in these securities at
a combined value of approximately $1 billion on the Company's
Consolidated Balance Sheets. Investment in the Time Warner common
stock is considered an "available-for-sale" equity security
58
<PAGE> 3
under SFAS No. 115, "Accounting for Certain Investments in Debt
and Equity Securities." Consequently, the Company excludes
unrealized net changes in the fair value of Time Warner common
stock (exclusive of dividends and write downs) from earnings and,
until realized, reports such changes as a net amount in the
shareholders' equity section of the Company's Consolidated
Balance Sheets. Investment in the Time Warner convertible
preferred stock (which is not subject to the requirements of SFAS
No. 115, since it is a non-publicly traded equity security) is
accounted for under the cost method.
The securities held in the Company's nuclear decommissioning
trust are classified as "available-for-sale" and, in accordance
with SFAS No. 115, are reported at estimated fair value of $67
million as of December 31, 1996 and $44.5 million as of December
31, 1995 on the Company's Consolidated and HL&P's Balance Sheets
under deferred debits. The liability for nuclear decommissioning
is reported on the Company's Consolidated and HL&P's Balance
Sheets under deferred credits. Any unrealized gains or losses are
accounted for in accordance with SFAS No. 71 as a regulatory
asset/liability and reported on the Company's Consolidated and
HL&P's Balance Sheets as a deferred debit.
(k) FUEL STOCK. Gas inventory (at average cost) was $19.6 million at
December 31, 1996. Coal, lignite, and oil inventory balances
(using last-in, first-out) were $27.3 million, $11.8 million and
$3.0 million, respectively.
(l) DEPRECIATION. The Company and HL&P compute depreciation using the
straight-line method. The Company's depreciation expense for 1996
was $360 million compared to $349 million and $338 million for
1995 and 1994, respectively. HL&P's depreciation expense for 1996
was $358 million compared to $347 million and $338 million for
1995 and 1994, respectively.
(m) RECLASSIFICATION. Certain amounts from the previous years have
been reclassified to conform to the 1996 presentation of
financial statements. Such reclassifications do not affect
earnings.
(n) NATURE OF OPERATIONS. The Company is a holding company
operating principally in the electric utility business. HL&P is
engaged in the generation, transmission, distribution and sale of
electric energy. HL&P's service area covers a 5,000 square mile
area in the Texas Gulf Coast, including Houston. Another
subsidiary of the Company, HI Energy, participates in domestic
and foreign power generation projects and invests in the
privatization of foreign electric utilities. The business and
operations of HL&P account for substantially all of the Company's
income from continuing operations and common stock equity. For a
description of the Merger, see Note 16 to the Financial
Statements.
(o) USE OF ESTIMATES. The preparation of financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from
those estimates.
(p) LONG-LIVED ASSETS. Effective January 1, 1996, the Company and
HL&P adopted SFAS No. 121. SFAS No. 121 requires that long-lived
assets and certain identifiable intangibles to be held and used
or disposed of by an entity be reviewed for impairment whenever
events or changes in circumstances indicate that the carrying
amount of an asset may not be recoverable. The Company and HL&P
have determined that no impairment loss need be recognized for
applicable assets of continuing operations as of December 31,
1996. This conclusion, however, may change in the future as
competition influences wholesale and retail pricing in the
electric utility industry.
59
<PAGE> 4
(2) JOINTLY-OWNED NUCLEAR PLANT
(a) HL&P INVESTMENT. HL&P is the project manager (and one of four
co-owners) of the South Texas Project, which consists of two
1,250 MW nuclear generating units. HL&P has a 30.8 percent
interest in the project and bears a corresponding share of
capital and operating costs associated with the project. As of
December 31, 1996, HL&P's investment in the South Texas Project
was $2.0 billion (net of $503 million accumulated depreciation).
HL&P's investment in nuclear fuel (including AFUDC) was $65
million (net of $176 million amortization) as of such date.
(b) REGULATORY PROCEEDINGS AND LITIGATION. All litigation and
arbitration claims formerly pending between HL&P and the other
co-owners of the South Texas Project have been settled and
dismissed with prejudice.
On April 30, 1996, HL&P and the City of Austin (Austin), one of
the four co-owners of the South Texas Project, agreed to settle a
lawsuit in which Austin had alleged that outages occurring at the
South Texas Project between early 1993 and early 1994 were due to
HL&P's failure to perform certain obligations it owed Austin
under a Participation Agreement relating to the project. Under
the settlement, HL&P agreed to pay Austin $20 million in cash to
resolve all pending disputes between HL&P and Austin, and Austin
agreed to support the formation of a new operating company to
assume HL&P's role as project manager for the South Texas
Project. The Company and HL&P have recorded the $20 million ($13
million net of tax) payment to Austin on the Company's Statements
of Consolidated Income and HL&P's Statements of Income as
litigation settlements expense.
In July 1996, HL&P and the City of San Antonio, acting through
the City Public Service Board of San Antonio (CPS), entered into
a settlement agreement providing, among other things, for (i) the
dismissal with prejudice of all pending arbitration claims and
lawsuits between HL&P and CPS relating to the South Texas
Project, (ii) a cash payment by HL&P to CPS of $75 million, (iii)
an agreement to support formation of a new operating company to
replace HL&P as project manager for the South Texas Project and
(iv) the execution of a 10-year joint operations agreement under
which HL&P and CPS will share savings resulting from the joint
dispatching of their respective generating assets in order to
take advantage of each system's lower cost resources. Under the
terms of the joint operations agreement entered into between CPS
and HL&P, HL&P guarantees CPS minimum annual savings of $10
million and a minimum cumulative savings of $150 million over the
ten-year term of the agreement. Based on current forecasts and
other assumptions regarding the combined operation of the two
generating systems, HL&P anticipates that the savings resulting
from joint operations will equal or exceed the minimum savings
guaranteed under the joint operating agreement. In 1996, savings
generated for CPS' account for a partial year of joint operations
were approximately $14 million.
The operating company (OPCO) which is being formed to replace
HL&P as project manager of the South Texas Project will be a
Texas non-profit corporation. Regulatory and governmental
approvals are being sought for the implementation of OPCO. Once
this process is completed, HL&P's employees working at the South
Texas Project will become employees of OPCO and OPCO will assume
responsibility for managing the South Texas Project. Oversight
will be provided by an Owners' Committee and OPCO's board of
directors, under the direction of directors appointed by each of
the co-owners.
In 1996, the capability factor at the South Texas Project
improved to 93.9 percent from 87.7 percent in 1995 (the 1995
median capability factor for U.S. nuclear facilities was 75.9
percent).
60
<PAGE> 5
In 1996, the Nuclear Regulatory Commission (NRC) graded the South
Texas Project "superior" in the areas of maintenance and support
and "good" in areas of operations and engineering in the NRC's
most recent Systematic Assessment of Licensees Performance.
Between June 1993 and February 1995, the South Texas Project had
been listed on the NRC's "watch list" of plants with weaknesses
that warrant increased NRC regulatory attention.
(c) NUCLEAR INSURANCE. HL&P and the other owners of the South Texas
Project maintain nuclear property and nuclear liability insurance
coverage as required by law and periodically review available
limits and coverage for additional protection. The owners of the
South Texas Project currently maintain $2.75 billion in property
damage insurance coverage, which is above the legally required
minimum, but is less than the total amount of insurance currently
available for such losses. This coverage consists of $500 million
in primary property damage insurance and excess property
insurance in the amount of $2.25 billion. Under the excess
property insurance (which became effective in November 1996),
HL&P and the other owners of the South Texas Project are subject
to assessments, the maximum aggregate assessment under current
policies being $14.8 million during any one policy year. The
application of the proceeds of such property insurance is subject
to the priorities established by the NRC regulations relating to
the safety of licensed reactors and decontamination operations.
Pursuant to the Price Anderson Act (Act), the maximum liability
to the public of owners of nuclear power plants, such as the
South Texas Project, was $8.92 billion as of December 1996.
Owners are required under the Act to insure their liability for
nuclear incidents and protective evacuations by maintaining the
maximum amount of financial protection available from private
sources and by maintaining secondary financial protection through
an industry retrospective rating plan. The assessment of deferred
premiums provided by the plan for each nuclear incident is up to
$75.5 million per reactor, subject to indexing for inflation, a
possible 5 percent surcharge (but no more than $10 million per
reactor per incident in any one year) and a 3 percent state
premium tax. HL&P and the other owners of the South Texas Project
currently maintain the required nuclear liability insurance and
participate in the industry retrospective rating plan.
There can be no assurance that all potential losses or
liabilities will be insurable, or that the amount of insurance
will be sufficient to cover them. Any substantial losses not
covered by insurance would have a material effect on HL&P's and
the Company's financial condition and results of operations.
(d) NUCLEAR DECOMMISSIONING. In accordance with the Rate Case
Settlement, HL&P contributes $14.8 million per year to a trust
established to fund HL&P's share of the decommissioning costs for
the South Texas Project. For a discussion of securities held in
the Company's nuclear decommissioning trust, see Note 1(j). In
May 1994, an outside consultant estimated HL&P's portion of
decommissioning costs to be approximately $318 million (1994
dollars). The consultant's calculation of decommissioning costs
for financial planning purposes used the DECON methodology
(prompt removal/dismantling), one of the three alternatives
acceptable to the NRC, and assumed deactivation of Unit Nos. 1
and 2 upon the expiration of their 40-year operating licenses.
While the current and projected funding levels currently exceed
minimum NRC requirements, no assurance can be given that the
amounts held in trust will be adequate to cover the actual
decommissioning costs of the South Texas Project. Such costs may
vary because of changes in the assumed date of decommissioning,
changes in regulatory and accounting requirements, changes in
technology and changes in costs of labor, materials and
equipment.
(3) RATE MATTERS
The Utility Commission has original (or in some cases appellate)
jurisdiction over HL&P's electric rates and services. In Texas,
Utility Commission orders may be appealed to a District Court in
61
<PAGE> 6
Travis County, and from that court's decision an appeal may be
taken to the Court of Appeals for the 3rd District at Austin
(Austin Court of Appeals). Discretionary review by the Supreme
Court of Texas may be sought from decisions of the Austin Court
of Appeals. In the event that the courts ultimately reverse
actions of the Utility Commission, such matters are remanded to
the Utility Commission for action in light of the courts' orders.
(a) 1995 RATE CASE. In August 1995, the Utility Commission
unanimously approved the Rate Case Settlement, which resolved
HL&P's 1995 rate case (Docket No. 12065) as well as a separate
proceeding (Docket No. 13126) regarding the prudence of operation
of the South Texas Project. Subject to certain changes in
existing regulation or legislation, the Rate Case Settlement
precludes HL&P from seeking rate increases until after December
31, 1997.
The Rate Case Settlement gives HL&P the option to write down up
to $50 million per year of its investment in the South Texas
Project through December 31, 1999, which write-downs will be
treated under the terms of the Rate Case Settlement as reasonable
and necessary expenses for purposes of reviews of HL&P's earnings
and any rate review proceeding initiated against HL&P. In both
1995 and 1996, HL&P recorded a $50 million pre-tax write down of
its investment in the South Texas Project as amortization
expense. In 1996, HL&P also amortized $50 million (pre-tax) of
its $153 million investment in certain lignite reserves
associated with a canceled generating station. In accordance with
the settlement, HL&P's remaining investment in the canceled
generating station and certain lignite reserves ($164 million
at December 31, 1996) will be amortized fully no later than
December 31, 2002.
(b) RATE CASE APPEALS. The only HL&P rate order currently under
appeal is Docket No. 6668 (the Utility Commission's inquiry into
the prudence of the planning and construction of the South Texas
Project). Review of the Utility Commission's order in Docket No.
6668 is pending before a Travis County district court. In that
order, the Utility Commission determined that $375.5 million of
HL&P's $2.8 billion investment in the South Texas Project had
been imprudently incurred. That ruling was incorporated into
HL&P's 1988 and 1991 rate cases. Unless the order is modified or
reversed on appeal, the amount found imprudent by the Utility
Commission will be sustained.
In June 1996, the Supreme Court of Texas unanimously upheld the
decision of the Utility Commission in Docket No. 8425 (HL&P's
1988 rate case) to include in HL&P's rate base $93 million in
construction costs relating to the canceled generating station.
The Supreme Court also affirmed the Utility Commission's decision
granting deferred accounting treatment for Unit No. 2 of the
South Texas Project and the calculation of HL&P's federal income
tax expenses without taking into account deductions for expenses
paid by the Company's shareholders. As a result of this decision,
HL&P's 1988 rate case has now become final.
(4) INVESTMENTS OF HI ENERGY
(a) GENERAL. HI Energy, a wholly owned subsidiary of the Company
formed in 1993, participates primarily in the development and
acquisition of foreign independent power projects and the
privatization of foreign generating and distribution companies.
The Company generally accounts for affiliate investments of HI
Energy under the equity method of accounting where: (i) HI
Energy's ownership interest in the affiliate ranges from 20
percent to 50 percent or (ii) HI Energy exercises significant
influence over operating and financial policies of such
affiliate. The Company's proportionate share of the equity in net
income/(loss) in these affiliates for the years ended December 31,
1996, 1995 and 1994 was $17.0 million, $0.5 million and $(1.6)
million, respectively. These amounts are included on the
Company's Statement of Consolidated Income as "Other Revenues."
The Company's equity investments in and advances to foreign and
non-regulated affiliates at December 31, 1996 and 1995 were $502
million and $41 million, respectively.
62
<PAGE> 7
(b) FOREIGN INVESTMENTS. In May 1996, a subsidiary of HI Energy
acquired 11.35 percent of the common shares of Light, a publicly
held Brazilian corporation, for $392 million. Light is the
operator under a 30-year concession agreement of an integrated
electric power and distribution system that serves a portion of
the state of Rio de Janeiro, Brazil, including the city of Rio de
Janeiro. HI Energy acquired the shares as a bidder in the
government-sponsored auction of 60 percent of Light's outstanding
shares. Subsequent to the auction, the winning bidders, including
a subsidiary of HI Energy, formed a consortium whose aggregate
ownership interest of 50.44 percent represents a controlling
interest in Light.
The Company has accounted for this transaction under purchase
accounting and has recorded its investment and its interest in
Light's operations after June 1, 1996, using the equity method.
The purchase price was allocated on the basis of the estimated
fair market value of the assets acquired and the liabilities
assumed as of the date of acquisition.
A subsidiary of HI Energy has entered into a $167.5 million loan
agreement in order to refinance a portion of the acquisition
costs of Light. The full proceeds of the loan, net of a $17.5
million debt reserve account to be established for the benefit of
the lenders, will not be funded until the satisfaction of various
conditions precedent, including the obtaining of political risk
insurance. The loan is non-recourse to the Company and HL&P. The
loan is secured by, among other things, a pledge of the shares of
Light and a subsidiary of HI Energy that is the indirect holder
of the shares of Light.
In addition to the investment in Brazil, HI Energy had total
equity investments in and advances to affiliates in Argentina of
$81 million and $36 million at December 31, 1996 and 1995,
respectively, representing a 49 percent interest in the capital
stock of an electric utility operating in the Province of Buenos
Aires. In addition, HI Energy owns a 90 percent ownership
interest in an Argentine electric utility distribution system and
is constructing a 160 MW cogeneration facility in San Nicolas,
Argentina. HI Energy's investment in these projects was
approximately $68 million and $22 million at December 31, 1996 and
1995, respectively.
HI Energy also owns a 36 percent interest in a coke calcining and
power generation facility in India with an investment of
approximately $8 million and $5 million at December 31, 1996 and
December 31, 1995, respectively.
(c) VALUATION ALLOWANCE. In 1995, the Company recorded a $28 million
valuation allowance (resulting in an $18 million after-tax charge
in that year) with respect to two waste tire-to-energy projects
that were being developed in reliance on the terms of a state
subsidy intended to encourage development of energy production
facilities for the disposal of solid waste. In March 1996, the
subsidy was repealed. In 1996, the Company recorded an additional
valuation allowance of $7 million with respect to these projects,
which resulted in a $5 million after-tax charge to 1996 earnings.
The valuation allowance reflects the combined amounts lent to the
projects on a subordinated basis by HI Energy. HI Energy also is
a party to two separate note purchase agreements committing it,
under certain circumstances, to lend up to an additional $16
million. The Company has entered into a support agreement to
enable HI Energy to honor its obligation under these note
purchase agreements. In the Company's opinion, it is unlikely
that additional loans would be required to be made under the note
purchase agreements, unless construction activities with respect
to these projects were recommenced at some future date. In March
1996, a subsidiary of HI Energy purchased from a senior lending
bank all notes relating to one of the projects
63
<PAGE> 1
SUBSEQUENT EVENTS
(8) In April 1997, HL&P redeemed all outstanding shares of its
$9.375 cumulative preferred stock in satisfaction of mandatory
sinking fund requirements.
In April 1997, a subsidiary of Houston Industries Energy, Inc.
(HI Energy) borrowed
$167.5 million under a five-year term loan facility. The
proceeds of the loan, net of a $17.5 million debt reserve
account established for the benefit of the lenders, were used to
refinance a portion of the acquisition costs of Light-Servicos
de Eletricidade S.A. (Light). The loan, which is non-recourse
to the Company and HL&P, restricts payments of dividends if
Light fails to meet certain financial covenants. The loan is
secured by, among other things, a pledge of the shares of Light.
HI Energy acquired an 11.35 percent interest in Light in May
1996 for $392 million.
In February 1996, three Texas cities filed a lawsuit against
HL&P and Houston Industries Finance, Inc., formerly a
wholly-owned subsidiary of the Company, seeking recovery of
unspecified damages relating to the alleged underpayment of
municipal franchise fees. In April 1997, the plaintiffs amended
their pleadings to assert damages alleged to exceed $250
million. The Company and HL&P believe that the lawsuit is
without merit. The Company and HL&P cannot estimate a range of
possible losses, if any, from this lawsuit, nor can any
assurance be given as to its ultimate outcome. For additional
information regarding this lawsuit, reference is made to Note
11(c) to the financial statements included in the Form 10-K,
which Note is incorporated herein by reference.
In May 1997, the Company sold in open market transactions 550,000
shares of Time Warner Inc. (Time Warner) common stock for
approximately $25 million, representing an average sales price of
$45.49 per share, net of fees and other commissions . For
information regarding the Company's investment in Time Warner
securities, see Notes 1(j) and 13 to the financial statements
included in the Form 10-K.
<PAGE> 1
RATE CASE MATTERS AND OTHER PROCEEDINGS
(7) For information regarding the appeal of Docket No. 6668, an
inquiry into the prudence of the planning and construction of
the South Texas Project Electric Generating Station (South
Texas Project), see Note 3(b) to the Form 10-K.
In July 1997, the one appellant remaining in the appeal of
Docket No. 6668 voluntarily dismissed its appeal. Based on
this action, HL&P is seeking entry of a judgment affirming the
Public Utility Commission's of Texas (Utility Commission) order
in Docket No. 6668. If the motions are granted, all appeals of
HL&P's prior rate cases will be concluded.
Reference is made to Note 11(c) to the Form 10-K and Note 8 to
the First Quarter 10-Q for information regarding a lawsuit
against HL&P for recovery of allegedly unpaid franchise fees.
In June 1997, the Texas Supreme Court ruled that it did not
have jurisdiction, at this stage in the proceedings, to review
the trial court's certification of the case as a class action.
The case is scheduled for trial in April 1998 before the
District Court of Harris County, Texas. For the reasons set
forth in Note 11(c) to the Form 10-K, the Company regards the
case as spurious and is aggressively contesting the lawsuit.
<PAGE> 1
Exhibit 99(d)
[Excerpt from NorAm 1996 Form 10-K]
1. ACCOUNTING POLICIES AND COMPONENTS OF
CERTAIN FINANCIAL STATEMENT LINE ITEMS
PRINCIPLES OF CONSOLIDATION
The accompanying consolidated financial statements include the accounts of NorAm
Energy Corp. and its subsidiaries, all of which are wholly owned, and all
significant affiliated transactions and balances have been eliminated. As used
herein, "NorAm" and "the Company" refer to NorAm Energy Corp. and its
consolidated subsidiaries. Certain prior period amounts have been reclassified
to conform to current presentation.
MERGER WITH HOUSTON INDUSTRIES
On August 11, 1996, the Company entered into an Agreement and Plan of Merger
(the "Merger Agreement") with Houston Industries Incorporated ("Houston
Industries" or "HI"), Houston Lighting & Power Company ("HL&P") and a newly
formed Delaware subsidiary of Houston Industries ("HI Merger, Inc."). Under the
Merger Agreement, the Company would merge with and into HI Merger, Inc. and
would become a wholly owned subsidiary of HII (as defined following). Houston
Industries would merge with and into HL&P, which would be renamed Houston
Industries Incorporated ("HII") (the term "Transaction" refers to the business
combination between Houston Industries and the Company). Consideration for the
purchase of the Company's common stock would be a combination of cash and shares
of HI common stock, valued at approximately $3.8 billion, consisting of
approximately $2.4 billion for the Company's common stock and equivalents and
approximately $1.4 billion in assumption of the Company's debt. Additional
information concerning the Merger Agreement is contained in the Joint Proxy
Statement/Prospectus of Houston Industries, HL&P and the Company dated October
29, 1996 ("the Proxy/Prospectus").
The Merger Agreement was approved and adopted at Special Meetings of
Houston Industries' and the Company's stockholders held on December 17, 1996.
The Company and HI proceeded to obtain required state and municipal regulatory
approvals, all of which have been obtained, and to request an exemption from the
Securities and Exchange Commission ("the SEC") which would allow the Transaction
to take place under its preferred structure without subjecting post-merger HII
to the requirements of the Public Utility Holding Company Act. It is HI's and
the Company's intention to defer the closing of the Transaction until the SEC
issues its ruling on the exemption request although, as set forth in the
Proxy/Prospectus, there are two alternative structures, one of which would not
require SEC approval. Adoption of either of these structures, however, would
require that the Company and HI make new filings to obtain the various state and
municipal regulatory approvals.
In early February 1997, the Federal Energy Regulatory Commission ("the
FERC" or "the Commission") issued an order ("the Order") advising the Company
that the Transaction "...may require Commission approval pursuant to section 203
of the FPA" ( the "FPA" refers to the Federal Power Act), and directing the
Company to file a response within 30 days of the Order either "...(1) providing
arguments as to why the transaction does not require Commission authorization
under section 203 or (2) an application under section 203". In early March 1997,
the Company filed a response to the Order stating its view that the FERC does
not have jurisdiction over the Transaction. Although such response disclaimed
any FERC jurisdiction over the Transaction, it also indicated that one option
being considered was to file an application with the FERC for approval of the
Transaction in anticipation of an expedited review under the FERC's newly-issued
merger policy guidelines. On March 27, 1997, the Company filed an application
under section 203 of the FPA seeking FERC approval of the Transaction, although
continuing to assert its position that such approval is not required.
The Company continues to believe that the Transaction will be completed as
contemplated although, in light of the pending regulatory issues as set forth
preceding, the Company cannot predict with any degree of certainty when the
Transaction will be consummated.
<PAGE> 2
NATURE OF OPERATIONS
The Company's principal activities are in the natural gas industry (representing
in excess of 90% of the Company's total revenues, income or loss and
identifiable assets), primarily in the contiguous 48 states, with principal
operations in Texas, Louisiana, Mississippi, Arkansas, Oklahoma, Missouri and
Minnesota. The Company has operations in various phases of the natural gas
industry, including distribution, transmission, marketing and gathering which,
during 1996, provided approximately 50.5%, 34.2%, 11.5% and 3.8%, respectively,
of the Company's consolidated operating income (exclusive of the net operating
loss attributable to Corporate and certain miscellaneous activities). The
Company's distribution operations are conducted by its Entex, Minnegasco and
Arkla divisions, its interstate pipeline operations are conducted by NorAm Gas
Transmission Company ("NGT") and Mississippi River Transmission Corporation
("MRT"), its marketing activities are conducted by NorAm Energy Services, Inc.
("NES") and NorAm Energy Management, Inc. ("NEM"), and its gathering activities
are conducted by NorAm Field Services Corp. ("NFS"), in each case also including
certain subsidiaries and affiliates. The Company's miscellaneous activities,
whose collective results of operations currently are not material, principally
consist of home care services, including (1) appliance sales and service, (2)
home security services, (3) utility services, principally line locating and (4)
resale of long distance telephone service. The Company expects to make an
investment in international activities as discussed following.
During 1996, the Company had revenues of $55 million, approximately 1% of
consolidated operating revenues, from sales to and transportation for Laclede
Gas Company (the local natural gas distribution company which serves the greater
St. Louis, Illinois area) pursuant to several long-term firm transportation and
storage agreements which expire in 1999. The Company's interstate pipelines
received revenues of approximately $163.8 million in 1996 from services provided
to the Company's Arkla distribution division pursuant to several agreements,
representing approximately 3.4% of consolidated operating revenues and
approximately 47.2% of NGT's and MRT's combined operating revenues. With respect
to services provided to Arkla in (1) Arkansas, the current service agreement is
scheduled to expire in April 2002 and (2) Louisiana, Oklahoma and East Texas,
the process of negotiation and regulatory approval has not yet been completed,
but the Company currently expects to obtain revised agreements with a term
similar to that currently in effect for Arkansas.
In early 1997, the Company learned that four consortiums ("the
Consortiums"), each of which included the Company, were the apparent successful
bidders for the right to build and operate natural gas distribution facilities
in each of four defined service areas ("the Concessions") within Colombia.
Contracts, which extend through the year 2014 and grant the exclusive right to
distribute gas to consumers of less than 500 Mcf per day (and the right to
compete for other customers), are expected to be awarded in April 1997. The
Company estimates that the Concessions ultimately will have approximately
400,000 customers, connected over approximately a five-year period at a total
cost of approximately $160 million, with construction expected to begin no later
than the fourth quarter of 1997. The Company's ownership interest in the
Consortiums, while subject to change through continuing negotiations with its
existing and potential partners ranges from 15% to approximately 33% and, based
on the expected number of customers, represents a weighted average ownership
interest of approximately 23%.
In January 1997, the Company participated in a bid for a permit authorizing
the construction, ownership and operation of a natural gas distribution system
for the geographic area that includes the cities of Chihuahua, Delicias and
Cuauchtemoc/Anahuac in North Central Mexico. In March 1997, the Company learned
that its group was not the successful bidder. The Company had previously
announced its intention to participate in a similar bidding process for a permit
to provide natural gas distribution service to all or a portion of Mexico City,
although no date has yet been set for submission of bids.
<PAGE> 3
USE OF ESTIMATES
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting periods.
Actual results could differ from those estimates.
RATE REGULATION
Methods of allocating costs to accounting periods in the portion of the
Company's business subject to federal, state or local rate regulation may differ
from methods generally applied by unregulated companies. However, when
accounting allocations prescribed by regulatory authorities are used for
rate-making, the resultant accounting follows the concept of matching costs with
related revenues. The Company's rate-regulated divisions/subsidiaries bill
customers on a monthly cycle billing basis. Revenues are recorded on an accrual
basis, including an estimate for gas delivered but unbilled at the end of each
accounting period.
All of the Company's rate-regulated businesses historically have followed
the accounting guidance contained in Statement of Financial Accounting Standards
No. 71, "Accounting for the Effects of Certain Types of Regulation" ("SFAS 71").
The Company discontinued application of SFAS 71 to NGT effective with year-end
1992 reporting. As a result of the continued application of SFAS 71 to MRT and
the Company's distribution divisions, the accompanying consolidated financial
statements contain certain assets and liabilities which would not be recognized
by unregulated entities. In addition to regulatory assets related to
postretirement benefits other than pensions (see Note 5), the Company's only
other significant regulatory asset is related to anticipated environmental
remediation costs, see "Accounting for Remediation Costs" following and
"Environmental Matters" included in Note 7.
CHANGE IN ACCOUNTING ESTIMATE
Pursuant to a revised study of the useful lives of certain assets, in July 1995,
the Company changed the depreciation rates associated with certain of its
natural gas gathering and pipeline assets. This change had the effect of
increasing 1995 "Income before extraordinary item" and "Net income" by
approximately $3.2 million ($0.03 per share).
ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES
To reduce the risk from market fluctuations in the price of natural gas and
related transportation, the Company enters into futures transactions, swaps and
options (collectively, "financial instruments") in order to hedge certain
natural gas in storage, as well as certain expected purchases, sales and
transportation of natural gas, a portion of which are firm commitments at the
inception of the hedge. Some of these financial instruments carry
off-balance-sheet risk, see "Credit Risk and Off-Balance-Sheet Risk" included in
Note 7. Changes in the market value of these financial instruments utilized as
hedges are (1) recognized as an adjustment of the carrying value in the case of
existing assets and liabilities, (2) included in the measurement of the
transaction that satisfies the commitment in the case of firm commitments and
(3) included in the measurement of the subsequent transaction in the case of
anticipated transactions, whether or not the hedge is closed out before the date
of the anticipated transaction. In cases where anticipated transactions do not
occur, deferred gains and losses are recognized when such transactions were
scheduled to occur.
<PAGE> 4
ACCOUNTING FOR REMEDIATION COSTS
Environmental remediation costs are accrued when the Company determines that it
is probable that it will incur such costs and the amount is reasonably
estimable. To the extent that potential environmental remediation costs are
quantified within a range, the Company establishes reserves equal to the most
likely level of costs within the range and adjusts such accruals as better
information becomes available. In determining the amount of the liability,
future costs are not discounted to their present value and the liability is not
offset by expected insurance recoveries. If justified by circumstances within
the Company's business subject to SFAS 71, corresponding regulatory assets are
recorded in anticipation of recovery through the ratemaking process, see
"Environmental Matters" included in Note 7.
EARLY RETIREMENT AND SEVERANCE
During the first quarter of 1996, the Company instituted a reorganization plan
affecting its NGT and MRT subsidiaries, pursuant to which a total of
approximately 275 positions were eliminated, resulting in expense for severance
payments and enhanced retirement benefits. Also during the first quarter of
1996, (1) the Company's Entex division instituted an early retirement program
which was accepted by approximately 100 employees and (2) the Company's
Minnegasco division reorganized certain functions, resulting in the elimination
of approximately 25 positions. Collectively, these programs resulted in a
non-recurring pre-tax charge of approximately $22.3 million (approximately $13.4
million or $0.10 per share after tax), which pre-tax amount is reported in the
accompanying Statement of Consolidated Income as "Early retirement and
severance".
INTEREST EXPENSE
Interest expense includes, where applicable, amortization of debt issuance cost
and amortization of gains and losses on interest rate hedging transactions
related to the Company's debt financing activities, see Note 3. "Interest
expense, net" as presented in the accompanying Statement of Consolidated Income
is net of an allowance for borrowed funds used during construction of $1.6
million, $1.1 million and $1.3 million in 1996, 1995 and 1994, respectively.
Beginning in 1997, amounts previously reported as "Loss on sale of receivables"
will be reported as a component of interest expense, see "Sale of Receivables"
included in Note 3.
DISCONTINUED OPERATIONS
"Loss from discontinued operations, less taxes" as presented in the accompanying
Statement of Consolidated Income for 1994 represents a pre-tax loss of $3.3
million (the associated tax benefit was $1.2 million) resulting from litigation
associated with the discontinued operations of University Savings Association, a
former subsidiary of Entex.
EARNINGS PER SHARE
Primary earnings per share is computed using the weighted average number of
shares of the Company's Common Stock ("Common Stock") actually outstanding
during each period presented. Outstanding options for purchase of Common Stock,
the Company's only "common stock equivalent" as that term is defined in the
authoritative accounting literature, have been excluded due to either (1) the
fact that the options would have been anti-dilutive if exercised or (2) the
immaterial impact which would result from the exercise of those options which
are currently exercisable and would be dilutive if exercised. Fully diluted
earnings per share, in addition to the actual weighted average common shares
outstanding, assumes the conversion, as of its issuance date of June 17, 1996,
of the 3,450,000 shares of the Trust Preferred (see Note 3) at a conversion rate
of 4.1237 shares of Common Stock for each share of the Trust Preferred
(resulting in the assumed issuance of a total of 14,226,765 shares of Common
Stock), and reflects the increase in earnings from the cessation of the
dividends on the Trust Preferred (net of the related tax benefit) which would
result from such assumed conversion. For 1996, this assumed earnings increase
was approximately $3.5 million, net of related tax benefits of approximately
$2.3 million. The Company's 6% Convertible Subordinated Debentures due 2012 (see
"Other Long-Term Financing" included in Note 3) and the Company's $3.00 Series A
Preferred Stock (prior to its June 1996 exchange, see "Other Long-Term
Financing" included in Note 3), due to their exchange rates, are anti-dilutive
and are therefore excluded from all earnings per share calculations. During the
periods in which the Company's $3.00 Convertible Exchangeable Preferred Stock,
Series A was outstanding, earnings per share from continuing operations is
calculated after reduction for the preferred stock dividend requirement
associated with such security.
In February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting
<PAGE> 5
Standards No. 128, "Earnings per Share" ("SFAS 128"), which is required to be
implemented for fiscal years ending after December 15, 1997 and earlier
application is not permitted. SFAS 128 replaces the current "primary earnings
per share" ("primary EPS") and "fully diluted earnings per share" ("fully
diluted EPS") with "basic earnings per share" ("basic EPS") and "diluted
earnings per share" ("diluted EPS"). Unlike the calculation of primary EPS which
includes, in its denominator, the sum of (1) actual weighted shares outstanding
and (2) "common stock equivalents" as that term is defined in the authoritative
literature, basic EPS is calculated using only the actual weighted average
shares outstanding during the relevant periods. Diluted EPS is very similar to
fully diluted EPS, differing only in technical ways which do not currently
affect the Company.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment, in general, is carried at cost and depreciated or
amortized on a straight-line basis over its estimated useful life. Additions to
and betterments of utility property are charged to property accounts at cost,
while the costs of maintenance, repairs and minor replacements are charged to
expense as incurred. Upon normal retirement of units of utility property, plant
and equipment, the cost of such property, together with cost of removal less
salvage, is charged to accumulated depreciation. Costs of individually
significant internally developed and purchased computer software systems are
capitalized and amortized over their expected useful life.
INVESTMENTS AND OTHER ASSETS
Goodwill, none of which is being recovered in regulated service rates, is
amortized on a straight-line basis over 40 years. Approximately $14.2 million of
goodwill was amortized each year during 1996, 1995 and 1994. Accumulated
amortization of goodwill was $103.4 million and $89.2 million at December 31,
1996 and 1995, respectively. The Company periodically compares the carrying
value of its goodwill to the anticipated undiscounted future operating income
from the businesses whose acquisition gave rise to the goodwill and, as yet, no
impairment is indicated or expected.
Itron, Inc. ("Itron") is a publicly-traded Spokane, Washington company which
manufactures and markets automated meter-reading devices and provides related
services. The Company accounts for its investment in Itron utilizing the cost
method (its ownership of approximately 1.5 million Itron common shares at
December 31, 1996 represented an ownership interest of approximately 11.2%),
revalues its investment to market value as of each balance sheet date and
reports any unrealized gain or loss, net of tax, as a separate component of
stockholders' equity, which unrealized gain was immaterial at December 31, 1996.
During 1996, the market value of the Company's Itron investment (based on
closing share prices on the NASDAQ) varied from a high of approximately $88.3
million to a low of approximately $22.5 million. At March 14, 1997, the market
value of the Company's investment in Itron was approximately $29.3 million and
the unrealized gain was approximately $1.7 million (net of tax benefit of $1.0
million).
ALLOWANCE FOR DOUBTFUL ACCOUNTS
"Accounts and notes receivable, principally customer" as presented in the
accompanying Consolidated Balance Sheet are net of an allowance for doubtful
accounts of $13.0 million and $11.1 million at December 31, 1996 and 1995,
respectively.
INVENTORIES
Inventories principally follow the average cost method and all non-utility
inventories held for resale are valued at the lower of cost or market.
ACCOUNTS PAYABLE
Certain of the Company's cash balances reflect credit balances to the extent
that checks written have not yet been presented for payment. Such balances
included in "Accounts payable, principally trade" in the accompanying
Consolidated Balance Sheet were approximately $53.5 million and $44.4 million at
December 31, 1996 and 1995, respectively.
STATEMENT OF CONSOLIDATED CASH FLOWS
The accompanying Statement of Consolidated Cash Flows reflects the assumption
that all highly liquid investments
<PAGE> 6
purchased with original maturities of three months or less are cash equivalents.
Cash flows resulting from the Company's risk management (hedging) activities are
classified in the accompanying Statement of Consolidated Cash Flows in the same
category as the item being hedged.
In September 1994, the Company sold all of its Kansas distribution properties,
serving approximately 23,000 customers in 14 communities, together with certain
related pipeline assets, for approximately $23 million in cash, approximately
its carrying value, shown in the accompanying Statement of Consolidated Cash
Flows as "Sale of distribution properties".
In June 1996, the Company exercised its right to exchange its $3.00 Convertible
Exchangeable Preferred Stock, Series A for its 6% Convertible Subordinated
Debentures due 2012 in a non-cash transaction. The Company issues its common
stock in conjunction with certain compensation plans. For additional information
on these matters, see Note 6 and "Other Long-Term Financing" included in Note 3.
Following is certain supplemental cash flow information:
The caption "Changes in certain asset and liabilities, net of noncash
transactions" as shown in the accompanying Statement of Consolidated Cash Flows
includes the following:
(1) Beginning with January 1, 1997, cash flows associated with the Company's
sale of receivables facility will be included with "Cash Flows from
Financing Activities", see "Sale of Receivables" included in Note 3.
<PAGE> 7
7. COMMITMENTS AND CONTINGENCIES
LEASE COMMITMENTS
Following is certain information concerning the Company's obligations under
operating leases:
(1) Principally consisting of rental agreements for building space, data
processing equipment and vehicles (including major work equipment).
Lease payments related to assets transferred under the Company's leasing
arrangements (see "Other Long-Term Financing" included in Note 3) are included
in the preceding table for only their primary (non-cancelable) term. Subsequent
to the primary term, the Company could terminate its obligations under these
arrangements by electing to purchase the relevant assets for an amount
approximating fair market value. Total rental expense for all leases was $33.4
million, $48.9 million and $36.8 million in 1996, 1995 and 1994, respectively.
LETTERS OF CREDIT
At December 31, 1996, the Company was obligated under letters of credit
incidental to its ordinary business operations totalling approximately $21.7
million.
INDEMNITY PROVISIONS
In June 1993, the Company completed the sale of Louisiana Intrastate Gas
Corporation ("LIG"), its former subsidiary engaged in the intrastate pipeline
and liquids extraction business, to Equitable Resources, Inc. In December 1992,
the Company completed the sale of Arkla Exploration Company ("AEC"), its former
subsidiary engaged in oil and gas exploration and production activities, to
Seagull Energy Corporation. In June 1991, the Company completed the sale of Dyco
Petroleum Company ("Dyco"), the oil and gas exploration and production company
acquired in conjunction with the Company's acquisition of Diversified Energies
Inc., to Continental Drilling Company, Inc., a subsidiary of Samson Investment
Company. In each instance, the relevant sale agreement required the Company to
indemnify the purchaser against certain exposures, for which the Company has
established reserves based on, among other factors, its estimates of potential
claims. These reserves are included in the Company's Consolidated Balance Sheet
under the caption "Estimated obligations under indemnification provisions of
sale agreements".
SALE OF RECEIVABLES
Certain of the Company's receivables are collateral for receivables which have
been transferred pursuant to a sale of receivables facility, see "Sale of
Receivables" included in Note 3.
GAS PURCHASE CLAIMS
In conjunction with settlements of "take-or-pay" claims, the Company has prepaid
for certain volumes of gas, which prepayments have been recorded at their net
realizable value and, to the extent that the Company is unable to realize at
least the carrying amount as the gas is delivered and sold, the Company's
earnings will be adversely affected, although such impact is not expected to be
material. In addition to these prepayments, the Company is a party to a number
of agreements which require it to either purchase or sell gas in the future at
prices which may differ from then-prevailing market prices or which require it
to deliver gas at a point other than the expected receipt point for volumes to
be purchased. As discussed under "Credit Risk and Off-Balance-Sheet Risk"
following, the Company operates an ongoing risk management program designed to
eliminate or limit the Company's exposure from its obligations under these
purchase/sale commitments. To the extent that the Company expects that these
commitments will result in losses over the contract term, the Company has
established reserves equal to such expected losses.
TRANSPORTATION AGREEMENT
The Company had an agreement ("the ANR Agreement") with ANR Pipeline Company
("ANR") which contemplated a transfer to ANR of an interest in certain of the
Company's pipeline and related assets, representing capacity of 250
<PAGE> 8
MMcf/day, and pursuant to which ANR had advanced $125 million to the Company.
The ANR Agreement has been restructured as a lease of capacity and, after
refunds of $50 million and $34 million in 1995 and 1993, respectively, the
Company currently retains $41 million (recorded as a liability) in exchange for
ANR's use of 130 MMcf/day of capacity in certain of the Company's transportation
facilities. The level of transportation will decline to 100 MMcf/day in the year
2003 with a refund of $5 million to ANR and the ANR Agreement will terminate in
2005 with a refund of the remaining balance.
CREDIT RISK AND OFF-BALANCE-SHEET RISK
The Company's gas supply, marketing, gathering and transportation activities
subject the Company's earnings to variability based on fluctuations in both the
market price of natural gas and the value of transportation as measured by
changes in the delivered price of natural gas at various points in the nation's
natural gas grid. In order to mitigate the financial risk associated with these
activities both for itself and for certain customers who have requested the
Company's assistance in managing similar exposures, the Company routinely enters
into natural gas swaps, futures contracts and options, collectively referred to
in this discussion as "derivatives". The use of derivatives for the purpose of
reducing exposure to risk is generally referred to as hedging and, through
deferral accounting, results in matching the financial impact of these
derivative transactions with the cash impact resulting from consummation of the
transactions being hedged, see "Accounting for Price Risk Management Activities"
included in Note 1.
The futures contracts are purchased and sold on the NYMEX and generally are used
to hedge a portion of the Company's storage gas, manage intra-month and
inter-month actual and anticipated short or long commodity positions and provide
risk management assistance to certain customers, to whom the cost of the
derivative activity is generally passed on as a component of the sales price of
the service being provided. Futures contracts are also utilized to fix the price
of compressor fuel or other future operational gas requirements, although usage
to date for this purpose has not been material. The options are entered into
with various third parties and principally consist of options which serve to
limit the year-to-year escalation from January 1998 to April 1999 in the
purchase price of gas which the Company is committed to deliver to a
distribution affiliate. These options covered 2.4 Bcf, 13.2 Bcf and 30.5 Bcf at
December 31, 1996, 1995 and 1994, respectively and, due to their nature and
term, have no readily determinable fair market value. The Company previously
established a reserve equal to its projected maximum exposure to losses during
the term of this commitment and, accordingly, no impact on earnings is expected.
The Company also utilizes options in conjunction with meeting customers' needs
for custom risk management services and for other limited purposes. The Company
had an immaterial amount of such options outstanding at December 31, 1996. The
impact of such options was to decrease 1996 earnings by approximately $2.6
million and the effect on prior periods was not material. The swaps, also
entered into with various third parties, are principally associated with the
Company's marketing and transportation activities and generally require that one
party pay either a fixed price or fixed differential from the NYMEX price per
MMBtu of gas while the other party pays a price based on a published index.
These swaps allow the Company to (1) commit to purchase gas at one location and
sell it at another location without assuming unacceptable risk with respect to
changes in the cost of the intervening transportation, (2) effectively set the
value to be received for transportation of certain volumes on the Company's
facilities in the future and (3) effectively fix the base price for gas to be
delivered in conjunction with the commitment described preceding. None of these
derivatives are held for speculative purposes and the Company's risk management
policy requires that positions taken in derivatives be offset by positions in
physical transactions (actual or anticipated) or in other derivatives.
In the table which follows, the term "notional amount" refers to the contract
unit price times the contract volume for the relevant derivative category and,
in general, such amounts are not indicative of the cash requirements associated
with these derivatives. The notional amount is intended to be indicative of the
Company's level of activity in such derivatives, although the amounts at risk
are significantly smaller because, in view of the price movement correlation
required for hedge accounting, changes in the market value of these derivatives
generally are offset by changes in the value associated with the underlying
physical transactions or in other derivatives. When derivative positions are
closed out in advance of the underlying commitment or anticipated transaction,
however, the market value changes may not offset due to the fact that price
movement correlation ceases to exist when the positions are closed. Under such
circumstances, gains or losses are deferred and recognized when the underlying
commitment or anticipated transaction was scheduled to occur. Following is
certain information concerning the Company's derivative activities:
<PAGE> 9
(1) The financial impact of these swaps was to increase(decrease) earnings by
$(1.0) million, $1.0 million and $2.8 million during 1996, 1995 and 1994,
respectively, as swap transactions were matched with hedged transactions
during these periods.
(2) Represents the estimated amount which would have been realized upon
termination of the relevant derivatives as of the date indicated. The
amount which is ultimately charged or credited to earnings is affected by
subsequent changes in the market value of these derivatives and, in the
case of certain commitments described preceding, no earnings impact is
expected due to existing accruals. Swaps associated with these commitments
and included in the above totals had fair market values of $2.8 million,
$(1.0) million and $(17.6) million at December 31, 1996, 1995 and 1994,
respectively.
(3) There was no material financial impact from these futures contracts in 1994
and the effect during 1996 and 1995 was to decrease earnings by $9.3
million and $4.1 million, respectively, as futures transactions were
matched with hedged transactions during these periods. At December 31,
1996, the Company had deferred losses of approximately $11.9 million
associated with expected sales under "peaking" contracts with certain
customers which, in effect, give the customer a "call" on certain volumes
of gas. All such losses were recognized in January 1997 when the
anticipated transactions were scheduled to occur.
While, as yet, the Company has experienced no significant losses due to the
credit risk associated with these arrangements, the Company has
off-balance-sheet risk to the extent that the counterparties to these
transactions may fail to perform as required by the terms of each such contract.
In order to minimize this risk, the Company enters into such transactions solely
with firms of acceptable financial strength, in the majority of cases limiting
such transactions to counterparties whose debt securities are rated "A" or
better by recognized rating agencies. For long-term arrangements, the Company
periodically reviews the financial condition of such firms in addition to
monitoring the effectiveness of these financial contracts in achieving the
Company's objectives. Should the counterparties to these arrangements fail to
perform, the Company would seek to compel performance at law or otherwise, or to
obtain compensatory damages in lieu thereof, but the Company might be forced to
acquire alternative hedging arrangements or be required to honor the underlying
commitment at then-current market prices. In such event, the Company might incur
additional loss to the extent of amounts, if any, already paid to the
counterparties. In view of its criteria for selecting counterparties, its
process for monitoring the financial strength of these counterparties and its
experience to date in successfully completing these transactions, the Company
believes that the risk of incurring a significant loss due to the nonperformance
of counterparties to these transactions is minimal.
<PAGE> 10
LITIGATION
On August 14, 1996, an action styled Shaw vs. NorAm Energy Corp., et al. was
filed in the District Court of Harris County, Texas by a purported NorAm
stockholder against the Company, certain of its officers and directors and
Houston Industries to enjoin the merger between the Company and Houston
Industries (see "Merger With Houston Industries" included in Note 1) or to
rescind such merger and/or to recover damages in the event that the Transaction
is consummated. The complaint alleges, among other things, that the merger
consideration is inadequate, that the Company's Board of Directors breached its
fiduciary duties and that Houston Industries aided and abetted such breaches of
fiduciary duties. In addition, the plaintiff seeks certification as a class
action. The Company believes that the claims are without merit and intends to
vigorously defend against the lawsuit. Management believes that the effect on
the Company's results of operations, financial position or cash flows, if any,
from the disposition of this matter will not be material.
The Company is a party to litigation (other than that specifically noted) which
arises in the normal course of business. Management regularly analyzes current
information and, as necessary, provides accruals for probable liabilities on the
eventual disposition of these matters. Management believes that the effect on
the Company's results of operations, financial position or cash flows, if any,
from the disposition of these matters will not be material.
ENVIRONMENTAL MATTERS
The Company and its predecessors operated a manufactured gas plant ("MGP")
adjacent to the Mississippi River in Minnesota known as the former Minneapolis
Gas Works ("FMGW") until 1960. The Company is working with the Minnesota
Pollution Control Agency to implement an appropriate remediation plan. There are
six other former MGP sites in the Company's Minnesota service territory. Of the
six sites, the Company believes that two were neither owned nor operated by the
Company; two were owned at one time but were operated by others and are
currently owned by others; and one was operated by the Company and is now owned
by others. The Company believes it has no liability with respect to the sites it
neither owned nor operated.
At December 31, 1996, the Company has estimated a range of $10 million to $170
million for possible remediation of the Minnesota sites. The low end of the
range was determined using only those sites presently owned or known to have
been operated by the Company, assuming the Company's proposed remediation
methods. The upper end of the range was determined using the sites once owned by
the Company, whether or not operated by the Company, using more costly
remediation methods. The cost estimates for the FMGW site are based on studies
of that site. The remediation costs for other sites are based on industry
average costs for remediation of sites of similar size. The actual remediation
costs will be dependent upon the number of sites remediated, the participation
of other potentially responsible parties, if any, and the remediation methods
used.
In its 1993 rate case, Minnegasco was allowed $2.1 million annually to recover
amortization of previously deferred and ongoing clean-up costs. Any amounts in
excess of $2.1 million annually were deferred for future recovery. In its 1995
rate case, Minnegasco asked that the annual allowed recovery be increased to
approximately $7 million and that such costs be subject to a true-up mechanism
whereby any over or under recovered amounts, net of certain insurance recoveries
as described following, plus carrying charges, would be deferred for recovery or
refund in the next rate case. Such accounting was approved by the Minnesota
Public Utilities Commission ("MPUC") and was implemented effective October 1,
1995. The amount of insurance recoveries to be flowed back to ratepayers is
determined by multiplying insurance recoveries received by the ratio of total
costs incurred to-date as a percentage of the probable total costs of
environmental remediation. At December 31, 1996 and 1995, the Company had
under-collected, through rates, net environmental clean-up costs of $1.4 million
and $1.3 million, respectively. In addition, at December 31, 1996 and 1995, the
Company had received insurance proceeds that will be refunded through rates in
the future as clean-up expenditures are made of $4.3 million and $3.3 million,
respectively. At December 31, 1996 and 1995, the Company had recorded a
liability of $35.9 million and $45.2 million, respectively, to cover the cost of
future remediation. In addition, the Company has receivables from insurance
settlements of $5.2 million at December 31, 1996. These insurance settlements
will be collected through 1999. The Company expects that the majority of its
accrual as of December 31, 1996 will be expended within the next five years. In
accordance with the provisions of SFAS 71, a regulatory asset has been recorded
equal to the liability accrued. The Company is continuing to pursue recovery of
at
<PAGE> 11
least a portion of these costs from insurers. The Company believes the
difference between any cash expenditures for these costs and the amounts
recovered in rates during any year will not be material to the Company's overall
cash requirements.
In addition to the Minnesota MGP sites described above, the Company's
distribution divisions are investigating the possibility that the Company or
predecessor companies may be or may have been associated with other MGP sites in
the service territories of the distribution divisions. At the present time, the
Company is aware of some plant sites in addition to the Minnesota sites and is
investigating certain other locations. While the Company's evaluation of these
other MGP sites remains in its preliminary stages, it is likely that some
compliance costs will be identified and become subject to reasonable
quantification. To the extent that such potential costs are quantified, as with
the Minnesota remediation costs for MGP described preceding, the Company expects
to provide an appropriate accrual and seek recovery for such remediation costs
through all appropriate means, including regulatory relief.
On October 24, 1994, the United States Environmental Protection Agency advised
the Company that MRT and a number of other companies have been named under
federal law as potentially responsible parties for a landfill site in West
Memphis, Arkansas and may be required to share in the cost of remediation of
this site. However, considering the information currently known about the site
and the involvement of MRT, the Company does not believe that this matter will
have a material adverse effect on its financial position, results of operations
or cash flows.
On December 18, 1995, the Louisiana Department of Environmental Quality advised
the Company that the Company, through one of its subsidiaries and together with
several other unaffiliated entities, had been named under state law as a
potentially responsible party with respect to a hazardous substance site in
Shreveport, Louisiana and may be required to share in the remediation cost, if
any, of the site. However, considering the information currently known about the
site and the involvement of the Company and its subsidiaries with respect to the
site, the Company does not believe that the matter will have a material adverse
effect on its financial position, results of operations or cash flows.
In addition, the Company, as well as other similarly situated firms in the
industry, is investigating the possibility that it may elect or be required to
perform remediation of various sites where meters containing mercury were
disposed of improperly, or where mercury from such meters may have leaked or
been disposed of improperly. While the Company's evaluation of this issue
remains in its preliminary stages, it is likely that compliance costs will be
identified and become subject to reasonable quantification.
At December 31, 1996 and 1995, the Company had recorded an accrual of $3.3
million (with a maximum estimated exposure of approximately $18 million) and an
offsetting regulatory asset for environmental matters in connection with a
former fire training facility and a landfill for which future remediation may be
required. This accrual is in addition to the accrual for MGP sites as discussed
preceding.
While the nature of environmental contingencies makes complete evaluation
impracticable, the Company currently is aware of no other environmental matter
which could reasonably be expected to have a material impact on its results of
operations, financial position or cash flows.
<PAGE> 12
MATERIAL CHANGES IN THE RESULTS
OF CONTINUING OPERATIONS
GENERAL
In recognition of the manner in which the Company manages its portfolio of
businesses, and in order to facilitate a more detailed understanding of the
various activities in which the Company engages, the Company has segregated its
results of operations into (1) Natural Gas Distribution, (2) Interstate
Pipelines, (3) Wholesale Energy Marketing, (4) Natural Gas Gathering, (5)
Retail Energy Marketing and (6) Corporate and Other. The Company's results of
operations are seasonal due to weather-related fluctuations in the demand for
and price of natural gas although, as discussed following and elsewhere herein,
(1) the Company has obtained rate design changes in its rate-regulated
businesses which generally have reduced the sensitivity of the Company's
earnings to seasonal weather patterns (further such changes may occur) and (2)
the Company is seeking to derive a larger portion of its earnings from
businesses which exhibit less earnings seasonality.
Since the Company's December 1992 sale of its oil and gas exploration
and production business, the substantial majority of the Company's earnings
have been attributable to operations which are rate regulated. While these
businesses have been subjected to varying levels of competition through changes
in the form of regulation (further such changes may occur), in general, they
continue to be regulated on a cost-of-service basis and the potential for
growth in earnings and increased rates of return is limited. The Company seeks
to improve its returns from these businesses through increased efficiency,
aggressive marketing and by rate initiatives which allow these businesses to
compete more effectively and retain more of the value added through improved
operations and expanded services.
The Company continues to believe that its greatest potential for
significant increases in overall profitability lies in those businesses which
are, in some instances, subject to regulation as to the nature of services
offered, the manner in which services are provided or the allocation of joint
costs between cost-of-service regulated and other operations, but generally are
not subject to direct regulation as to the rates which may be charged. Such
operations are sometimes referred to herein for convenience as "unregulated".
The Company has separated its strategically significant unregulated activities
into discrete management units and formulated plans for increasing the future
financial contribution from these businesses. The Company has and expects to
continue to (1) expand both the range of products and services offered by these
businesses and the geographic areas served and (2) increase the percentage of
the Company's overall earnings derived from these activities.
In addition, the Company is investigating opportunities for
international investment. To date, the Company's efforts have focused on
opportunities emerging in Latin America due to privatization initiatives
currently underway in a number of countries, as well as broad-based efforts to
encourage international investment. While such investments involve increased
risks such as political, economic or regulatory instability and foreign
currency exchange rate fluctuations, the Company believes that, together with
carefully selected partners (both within the target countries and otherwise),
it can effectively apply its natural gas industry expertise to selected
projects in Latin America, thereby increasing its overall returns on invested
capital while keeping the increased risk within acceptable limits. In general,
the international investment is expected to build up gradually over a period of
years as the Company (1) identifies and creates working relationships with
strategic business partners, (2) selects projects which meet its risk/return
requirements, (3) develops specific country experience and (4) in some cases,
increases its investment in specific projects as facilities are constructed,
see the following discussion and "Capital Expenditures - Continuing Operations"
under "Net Cash Flows from Investing Activities" elsewhere herein.
In early 1997, the Company learned that four consortiums ("the
Consortiums"), each of which included the Company, were the apparent successful
bidders for the right to build and operate natural gas distribution facilities
in each of four defined service areas ("the Concessions") within Colombia.
Contracts, which extend through the year 2014 and grant the exclusive right to
distribute gas to consumers of less than 500 Mcf per day (and the right to
compete for other customers), are expected to be awarded in April 1997. The
Company estimates that the Concessions ultimately will have approximately
400,000 customers, connected over approximately a five-year period at a total
cost of approximately $160 million, with construction expected to begin no
later than the fourth quarter of 1997. The Company's ownership interest in the
Consortiums, while subject to change through continuing negotiations with its
existing and potential partners ranges from 15% to approximately 33% and, based
on the expected number of customers, represents a weighted average ownership
interest of approximately 23%. Depending upon, among other factors, its
ownership percentage and success in finalizing financing arrangements at
estimated levels and with expected terms (see
<PAGE> 13
the discussion following), the Company currently estimates that the net cash
outflows to support its investment in the Concessions will not exceed
approximately $4 million in any year, and that its investment in the
Concessions will become a net source of cash in approximately year four.
Debt is currently expected to make up a significant portion of the
financing for the Concessions in the early years of the project, reaching a
maximum level of approximately $90 million and declining thereafter. While such
debt is expected to be without direct recourse to members of the Consortiums
("the Partners"), the terms of the debt will likely require that each Partner
enter into an agreement which commits it to make pro rata capital contributions
as funds are borrowed to finance construction, and that lenders will be granted
a security interest in such agreements. The Company is considering extending an
offer of support to its Partners such that, in the event that any Partner fails
to make capital contributions as required, the Company would make such
contributions and assume the underlying ownership interest. The Company
currently estimates that, in the event this arrangement is agreed to by all
parties and finalized, and the Company is required to assume all such
interests, the Company's maximum investment in the Concessions will not exceed
$50 million and its net cash outflows in support of the Concessions will not
exceed $18 million in any year.
In January 1997, the Company participated in a bid for a permit
authorizing the construction, ownership and operation of a natural gas
distribution system for the geographic area that includes the cities of
Chihuahua, Delicias and Cuauchtemoc/Anahuac in North Central Mexico. In March
1997, the Company learned that its group was not the successful bidder. The
Company had previously announced its intention to participate in a similar
bidding process for a permit to provide natural gas distribution service to all
or a portion of Mexico City, although no date has yet been set for submission
of bids.
REGULATORY MATTERS
In general, the Company's interstate pipelines are subject to regulation by the
FERC, while its natural gas distribution operations are subject to regulation
at the state or municipal level. Historically, all of the Company's
rate-regulated businesses have followed the accounting guidance contained in
Statement of Financial Accounting Standards No. 71, "Accounting for the Effects
of Certain Types of Regulation" ("SFAS 71"). The Company discontinued
application of SFAS 71 to its NorAm Gas Transmission Company subsidiary ("NGT")
effective with year-end 1992 reporting, see "Interstate Pipelines" elsewhere
herein. As a result of the continued application of SFAS 71 to Mississippi
River Transmission Corporation ("MRT") and the Company's natural gas
distribution operations, the Company's consolidated financial statements
contain certain assets and liabilities which would not be recognized by
unregulated entities. In addition to regulatory assets related to
postretirement benefits other than pensions, the Company's only other
significant regulatory asset is related to anticipated environmental
remediation costs, see Note 5 of the accompanying Notes to Consolidated
Financial Statements and "Environmental Matters" under "Commitments and
Contingencies" elsewhere herein. Following are recent significant regulatory
actions and developments.
NGT's Negotiated Rate Filing (Docket No. RP96-200), accepted by the
FERC on April 25, 1996, allowed NGT's rates to exceed the maximum cost-based
rates set forth in its filed tariff and/or to deviate from the current
FERC-mandated rate design. NGT has negotiated certain transactions which
provide for shippers' rates to be based on various factors such as gas price
differentials between the east and west sides of the NGT system. Therefore, in
some instances, NGT will charge and collect a negotiated rate which exceeds its
then-current maximum filed tariff rate. Appeals of the FERC's negotiated rate
policy, as well as the specific authorization granted to NGT to charge
negotiated rates, have been filed with the U.S. Court of Appeals, D.C. Circuit.
Until such time as these appeals are resolved, some uncertainty will exist as
to whether the Company may be required to refund any amounts associated with
transactions billed at above the maximum tariff rate. The Company currently
believes that any such refund will not be material. The FERC accepted NGT's 4th
annual FERC Order 528 filing (Docket No. RP96-167) effective April 1, 1996,
which retained the $0.03 per MMBtu commodity surcharge for continued recovery
of 75% of eligible take-or-pay costs, to the extent that collection of such
costs is supported by market conditions. The recovery of these costs, which
commenced in 1992, will continue through the year 2002 although, as a result of
the discontinuance of the application of SFAS 71 to NGT as described preceding,
no asset has been recorded in anticipation of recovery. Additionally, in April
1996, the FERC issued certificate orders granting (1) abandonment of NGT's
Collinson Storage Facility and associated facilities and equipment (Docket No.
CP95- 250), which will not result in a material gain or loss upon abandonment
and will not be abandoned until all gas has been recovered and (2) abandonment
and transfer of NGT's Line O West facilities to NorAm Field Services Corp.
("NFS") (Docket No. RP96-105), allowing NGT to divest itself of certain
non-core facilities which supported the gas supply function in a time when NGT
was principally a merchant of natural gas.
<PAGE> 14
NGT's certificated Line F Project, constructed at a total cost of
approximately $17 million, replaced a 30 mile section of the existing Line F
from Ruston to Sterlington, Louisiana, and upgraded the maximum allowed
operating pressure of the line to 1200 psig. This replacement project was
placed in service on October 31, 1996 and allows NGT to receive gas from an
interconnect with MRT located near NGT's Ruston Compressor Station. Finally, on
November 1, 1996, both MRT and NGT filed to revise their FERC tariffs,
incorporating the Gas Industry Standards Board standards in compliance with
FERC Order 587 (Docket No. RM96-1). These filings set forth each company's
standard procedures for business practices supporting nominations, allocations,
balancing, measurement, invoicing, capacity release, and standardization of
electronic communications between pipelines and their customers. Pursuant to a
FERC acceptance order, both NGT and MRT revised and refiled specified sections
of these tariffs in February 1997.
In April 1996, MRT filed a FERC Section 4 rate case (Docket No.
RP96-199) pursuant to the settlement entered into in MRT's last rate case
(Docket No. RP93-4). MRT's proposed tariff rates would increase revenues
derived from jurisdictional service by $14.7 million annually. Motion rates,
subject to refund, were implemented October 1, 1996. As a result of a
prehearing conference in December 1996, another procedural schedule was
established, setting a hearing date of July 29, 1997.
MRT filed an application (Docket No. CP95-376) requesting spindown of
all of its gathering facilities. In May 1996, the FERC issued an order
approving MRT's abandonment of its off-system gathering facilities to NFS and
further declaring such facilities exempt from FERC jurisdiction. In March 1996,
MRT filed a second application (Docket No. CP96- 268), which is now pending,
seeking (1) FERC approval to abandon its remaining gathering facilities by
transfer and sale to NFS and (2) a FERC declaration that these facilities are
exempt from FERC jurisdiction.
Entex was granted annualized rate increases totaling $5.4 million
during 1996. In addition to annual cost-of- service adjustments in three Texas
operating divisions (approximately $0.6 million on an annualized basis),
performance- based rates were approved and implemented in Louisiana
(approximately $2.7 million on an annualized basis, effective in June ) and
Mississippi (approximately $2.1 million on an annualized basis, effective in
October). In both Louisiana and Mississippi, Entex will be allowed to earn a
return on equity ("ROE") within an approved range. Earnings will be monitored
by the public service commissions of the respective states and, while the
provisions in each state differ slightly, to the extent that Entex's ROE falls
below the lower bounds or exceeds the upper bounds of the approved range,
adjustments will be made to either adjust rates upward or refund excess
earnings to customers.
In April 1996, the Minnesota Public Utilities Commission (the "MPUC")
voted to approve Minnegasco's Performance-Based Gas Purchasing Plan (the
"PBR"), effective from September 1, 1995 to June 30, 1998. To the extent that
Minnegasco's actual purchased gas cost is either significantly higher or lower
than specified benchmarks, the PBR will require that Minnegasco and its
customers share in the savings or additional cost, resulting in a maximum
reward or penalty of up to 2% of annual gas cost (e.g. approximately $10
million using Minnegasco's 1996 gas cost) for Minnegasco during any year.
Minnegasco made a compliance filing with the MPUC on November 1, 1996, the
first year of the PBR, which filing was approved for approximately $1 million
in March 1997.
In June 1996, the MPUC issued its order in Minnegasco's August 1995
rate case. The MPUC granted an annual increase of $12.9 million as compared to
the requested increase of $24.3 million. Interim rates reflecting an increase
of $17.8 million had been put into effect in October 1995 subject to refund. As
a part of its decision, the MPUC granted Minnegasco full recovery of its
ongoing net environmental costs through the use of a true-up mechanism whereby
any amounts collected in rates which differ from actual costs incurred, plus
carrying charges, will be deferred for recovery or refund in the next rate
case. Minnegasco requested reconsideration on several issues. Among them were
(1) a request to give effect, in this rate case, to the Minnesota Supreme
Court's (the "Court") recent rulings (see the discussion following), and (2) a
request to deduct from any interim rate refund the additional amount that
Minnegasco would have realized from its 1993 rate case by applying the Court's
ruling to that case, which remained on appeal.
The MPUC decided in Minnegasco's 1993 rate case that (1) Minnegasco's
unregulated appliance sales and service operations are required to pay the
regulated utility operations a fee for the use of Minnegasco's name, image and
reputation ("goodwill") and (2) a portion of the cost of responding to certain
gas leak calls not be allowed in rates. Minnegasco appealed those decisions to
the Court of Appeals. On June 13, 1996, in a case appealed prior to the 1993
rate case, the Court reversed the MPUC's decisions on these two issues, finding
in Minnegasco's favor and, in July, the Court denied the MPUC's request for
rehearing.
In its December 4, 1996 Order After Reconsideration, the MPUC
determined that Minnegasco was entitled to an annual rate increase of $13.3
million as compared to the $12.9 million granted in June 1996. The MPUC decided
that Minnegasco's unregulated appliance sales and service operations should not
pay a fee for goodwill associated with the
<PAGE> 15
Minnegasco name, but refused to allow Minnegasco to recover certain costs
associated with gas leak check calls, and did not approve Minnegasco's request
with respect to the 1993 rate case costs. An appeal related to the 1993 rate
case is pending before the Court of Appeals. Minnegasco requested and, on
February 20, 1997, the MPUC voted to grant a stay of the Commission's order
pending Minnegasco's appeal of the gas leak issue in the 1995 rate case.
Minnegasco is accruing for any necessary interim rate refunds should the Court
deny Minnegasco's appeal.
CHANGE IN ESTIMATED SERVICE LIVES OF CERTAIN ASSETS
Pursuant to an updated study of the useful lives of certain assets, in July
1995, the Company changed the depreciation rates associated with certain of its
natural gas pipeline and gathering assets, see "Interstate Pipelines" and
"Natural Gas Gathering" elsewhere herein. This change had the effect of
increasing the Company's 1995 income before extraordinary item by approximately
$3.2 million ($0.03 per share) and represents an annualized increase of
approximately $6.5 million.
<PAGE> 16
ITEM 3. LEGAL PROCEEDINGS
On August 14, 1996, an action styled Shaw vs. NorAm Energy Corp., et al. was
filed in the District Court of Harris County, Texas by a purported NorAm
stockholder against the Company, certain of its officers and directors and
Houston Industries to enjoin the Transaction or to rescind the Transaction
and/or to recover damages in the event that the Transaction is consummated. The
complaint alleges, among other things, that the merger consideration is
inadequate, that the Company's Board of Directors breached its fiduciary duties
and that Houston Industries aided and abetted such breaches of fiduciary duties.
In addition, the plaintiff seeks certification as a class action. The Company
believes that the claims are without merit and intends to vigorously defend
against the lawsuit. The Company does not believe that the matter will have a
material adverse effect on the financial position, results of operations or cash
flows of the Company.
On December 18, 1995, the Louisiana Department of Environmental Quality
advised the Company, that the Company, through one of its subsidiaries, and
together with several other unaffiliated entities, have been named under state
law as potentially responsible parties with respect to a hazardous substance
site in Shreveport, Louisiana and may be required to share in the remediation
cost, if any are incurred. However, considering the information currently known
about the site and the involvement of the Company and its subsidiaries with
respect to the site, the Company does not believe that the matter will have a
material adverse effect on the financial position, results of operations or cash
flows of the Company.
On October 24, 1994, the United States Environmental Protection Agency (the
"EPA") advised the Company that MRT and a number of other companies have been
named under federal law as potentially responsible parties for a landfill site
in West Memphis, Arkansas and may be required to share in the cost of
remediation of this site. The EPA is continuing to investigate the possibility
that other companies may have sent waste material to this site. Considering the
information currently known about the site and the involvement of MRT, the
Company does not believe that this matter will have a material adverse effect on
the financial position, results of operations or cash flows of the Company.
The Company is a party to litigation (other than that specifically noted)
which arises in the normal course of business. Management regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters. Management believes
that the effect on the Company's results of operations, financial position or
cash flows, if any, from the disposition of theses matters will not be material.
<PAGE> 1
[Exhibit 99(e)]
[Excerpt from NorAm First Quarter 10-Q for 1997]
G. As more fully described in the Company's 1996 Report on Form 10-K, the
Company is currently working with the Minnesota Pollution Control Agency
regarding the remediation of several sites on which gas was manufactured from
the late 1800's to approximately 1960. The Company has made an accrual for its
estimate of the costs of remediation (undiscounted and without regard to
potential third-party recoveries) and, based upon discussions to date and prior
decisions by regulators in the relevant jurisdictions, the Company continues to
believe that it will be allowed substantial recovery of these costs through its
regulated rates.
In addition, the Company has identified sites with possible mercury
contamination based on the type of facilities located on these sites. The
Company has not confirmed the existence of contamination at these sites, nor has
any federal, state or local governmental agency imposed on the Company an
obligation to investigate or remediate existing or potential mercury
contamination. To the extent that any compliance costs are ultimately identified
and quantified, the Company will provide an appropriate accrual and, to the
extent justified based on the circumstances within each of the Company's
regulatory jurisdictions, set up regulatory assets in anticipation of recovery
through the ratemaking process.
On October 24, 1994, the United States Environmental Protection Agency advised
MRT that it had been named a potentially responsible party under federal law
with respect to a landfill site in West Memphis, Arkansas, see Note H.
On December 18, 1995, the Louisiana Department of Environmental Quality advised
the Company that it had been named a potentially responsible party under state
law with respect to a hazardous substance site in Shreveport, Louisiana, see
Note H.
While the nature of environmental contingencies makes complete evaluation
impractical, the Company is currently aware of no other environmental matter
which could reasonably be expected to have a material impact on its results of
operations, financial position or cash flows.
H. On August 14, 1996, an action styled Shaw vs. NorAm Energy Corp., et al. was
filed in the District Court of Harris County, Texas by a purported NorAm
stockholder against the Company, certain of its officers and directors and
Houston Industries to enjoin the merger between the Company and Houston
Industries (see Note B) or to rescind such merger and/or to recover damages in
the event that the Transaction is consummated. The complaint alleges, among
other things, that the merger consideration is inadequate, the Company's Board
of Directors breached its fiduciary duties and that Houston Industries aided and
abetted such breaches of fiduciary duties. In addition, the plaintiff seeks
certification as a class action.
The Company believes that the claims are without merit and intends to vigorously
defend against the lawsuit. Management believes that the effect on the Company's
results of operations, financial position or cash flows, if any, from the
disposition of this matter will not be material.
On October 24, 1994, the United States Environmental Protection Agency advised
MRT, a
<PAGE> 2
wholly-owned subsidiary of the Company, that MRT, together with a number of
other companies, had been named under federal law as a potentially responsible
party for a landfill site in West Memphis, Arkansas and may be required to share
in the cost of remediation of this site.
However, considering the information currently known about the site and the
involvement of MRT, the Company does not believe that this matter will have a
material adverse effect on the financial position, results of operations or cash
flows of the Company.
On December 18, 1995, the Louisiana Department of Environmental Quality advised
the Company that the Company, through one of its subsidiaries and together with
several other unaffiliated entities, had been named under state law as a
potentially responsible party with respect to a hazardous substance site in
Shreveport, Louisiana and may be required to share in the remediation cost, if
any, of the site. However, considering the information currently known about the
site and the involvement of the Company and its subsidiaries with respect to the
site, the Company does not believe that the matter will have a material adverse
effect on the financial position, results of operations or cash flows of the
Company.
The Company is a party to litigation (other than that specifically noted) which
arises in the normal course of business. Management regularly analyzes current
information and, as necessary, provides accruals for probable liabilities on the
eventual disposition of these matters.
Management believes that the effect on the Company's results of operations,
financial position or cash flows, if any, from the disposition of these matters
will not be material.
<PAGE> 1
[Exhibit 99(f)]
[Excerpt from NorAm Second Quarter Form 10-Q for 1997]
K. As more fully described in the Company's 1996 Report on Form 10-K, the
Company is currently working with the Minnesota Pollution Control Agency
regarding the remediation of several sites on which gas was manufactured from
the late 1800's to approximately 1960. The Company has made an accrual for its
estimate of the costs of remediation (undiscounted and without regard to
potential third-party recoveries) and, based upon discussions to date and prior
decisions by regulators in the relevant jurisdictions, the Company continues to
believe that it will be allowed substantial recovery of these costs through its
regulated rates.
In addition, the Company has identified sites with possible mercury
contamination based on the type of facilities located on these sites. The
Company has not confirmed the existence of contamination at these sites, nor
has any federal, state or local governmental agency imposed on the Company an
obligation to investigate or remediate existing or potential mercury
contamination. To the extent that any compliance costs are ultimately
identified and quantified, the Company will provide an appropriate accrual and,
to the extent justified based on the circumstances within each of the Company's
regulatory jurisdictions, set up regulatory assets in anticipation of recovery
through the ratemaking process.
On June 18, 1997, the Mississippi Department of Environmental Quality
advised the Company that the Company, through its Entex Distribution Division,
had been identified as a potentially responsible party at a former manufactured
gas plant site in Biloxi, Mississippi, see Note L.
On October 24, 1994, the United States Environmental Protection Agency
advised MRT that it had been named a potentially responsible party under
federal law with respect to a landfill site in West Memphis, Arkansas, see Note
L.
On December 18, 1995, the Louisiana Department of Environmental
Quality advised the Company that it had been named a potentially responsible
party under state law with respect to a hazardous substance site in Shreveport,
Louisiana, see Note L.
While the nature of environmental contingencies makes complete
evaluation impractical, the Company is currently aware of no other
environmental matter which could reasonably be expected to have a material
impact on its results of operations, financial position or cash flows.
<PAGE> 2
L. On June 18, 1997, the Mississippi Department of Environmental Quality
advised the Company that the Company, through its Entex Distribution Division,
had been identified as a potentially responsible party at a former manufactured
gas plant site in Biloxi, Mississippi. Considering the information currently
known about the site, the Company does not believe that the matter will have a
material adverse effect on the financial position, results of operations or cash
flows of the Company.
On August 14, 1996, an action styled Shaw vs. NorAm Energy Corp., et al.
was filed in the District Court of Harris County, Texas by a purported NorAm
stockholder against the Company, certain of its officers and directors and HI
to enjoin the merger between the Company and HI (see Note B) or to rescind such
merger and/or to recover damages in the event that the HI merger transaction
is consummated. The complaint alleges, among other things, that the merger
consideration is inadequate, the Company's Board of Directors breached its
fiduciary duties that HI aided and abetted such breaches of fiduciary duties.
In addition, the plaintiff seeks certification as a class action. The Company
believes that the claims are without merit and intends to vigorously defend
against the lawsuit. Management believes that the effect on the Company's
results of operations, financial position or cash flows, if any, from the
disposition of this matter will not be material.
On October 24, 1994, the United States Environmental Protection Agency
advised MRT, a wholly-owned subsidiary of the Company, that MRT, together
with a number of other companies, had been named under federal law as a
potentially responsible party for a landfill site in West Memphis, Arkansas
and may be required to share in the cost of remediation of this site.
However, considering the information currently known about the site and the
involvement of MRT, the Company does not believe that this matter will have
a material adverse effect on the financial position, results of operations
or cash flows of the Company.
On December 18, 1995, the Louisiana Department of Environmental Quality
advised the Company that the Company, through one of its subsidiaries and
together with several other unaffiliated entities, had been named under
state law as a potentially responsible party with respect to a hazardous
substance site in Shreveport, Louisiana and may be required to share in the
remediation cost, if any, of the site. However, considering the information
currently known about the site and the involvement of the Company and its
subsidiaries with respect to the site, the Company does not believe that
the matter will have a material adverse effect on the financial position,
results of operations or cash flows of the Company.
The Company is a party to litigation (other than that specifically noted)
which arises in the normal course of business. Management regularly
analyzes current information and, as necessary, provides accruals for
probable liabilities on the eventual disposition of these matters.
Management believes that the effect on the Company's results of operations,
financial position or cash flows, if any, from the disposition of these
matters will not be material.
