Page 1 of 40
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Quarterly Report Under Section 13 or 15(d)
of the Securities Exchange Act of 1934
For the Quarter Ended September 30, 1996
Commission File Number 1-3751
NorAm Energy Corp.
(Exact name of registrant as specified in its charter)
DELAWARE 72-0120530
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
NorAm Energy Corp.
1600 Smith Street, 32nd Floor
Houston, Texas 77002
(Address of principal executive offices)
(713) 654-5699
(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
Outstanding Common Stock, $.625 Par Value
at November 8, 1996 - 137,293,574
Exhibit Index Appears on Page 39
<PAGE>
INDEX
Page
Part I. Financial Information 3
Item 1. Financial Statements
Consolidated Balance Sheet - September 30, 1996 and 1995
and December 31, 1995 4
Consolidated Statement of Income - Quarter Ended
September 30, 1996 and 1995 and Nine Months Ended
September 30, 1996 and 1995 6
Statement of Consolidated Cash Flows - Nine Months Ended
September 30, 1996 and 1995 7
Notes to Consolidated Financial Statements 8
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 13
Part II. Other Information
Item 1. Legal Proceedings 39
Item 6. Exhibits and Reports on Form 8-K 39
Signature 40
<PAGE>
Part I. Financial Information
Item 1. Financial Statements
The consolidated financial statements of NorAm Energy Corp. and
Subsidiaries (the "Company") included herein have been prepared, without audit,
pursuant to the rules and regulations of the Securities and Exchange Commission.
Certain information and notes normally included in financial statements prepared
in accordance with generally accepted accounting principles have been condensed
or omitted pursuant to such rules and regulations, although the Company believes
that the disclosures are adequate to make the information presented not
misleading. It is suggested that these financial statements be read in
conjunction with the financial statements and the notes thereto included in the
Company's 1995 Report on Form 10-K. In August 1996, the Company signed a
definitive agreement which is expected to result in the merger of the Company
with and into a wholly owned subsidiary of Houston Industries Incorporated
("Houston Industries"), see Note L of the accompanying Notes to Consolidated
Financial Statements.
<PAGE>
<TABLE>
<CAPTION>
NorAm Energy Corp. and Subsidiaries
CONSOLIDATED BALANCE SHEET
(in thousands of dollars)
(unaudited)
ASSETS September 30 December 31 September 30
- ------
1996 1995 1995
------------------ ------------------- ------------------
<S> <C> <C> <C>
Property, Plant and Equipment
Natural Gas Distribution $ 2,127,263 $ 2,059,376 $ 2,012,347
Interstate Pipelines 1,680,538 1,666,017 1,669,814
Natural Gas Gathering 219,333 208,989 205,879
Other 39,109 35,157 34,694
------------------ ------------------- ------------------
4,066,243 3,969,539 3,922,734
Less: Accumulated depreciation and amortization 1,644,357 1,561,764 1,533,402
------------------ ------------------- ------------------
2,421,886 2,407,775 2,389,332
Investments and Other Assets
Goodwill, net 470,485 481,125 484,672
Prepaid pension asset 48,462 57,965 59,301
Investment in Itron, Inc. (Note B) 39,442 50,711 41,696
Regulatory asset for environmental costs 40,017 48,500 41,632
Gas purchased in advance of delivery 33,801 24,284 24,548
Other 20,249 21,324 19,192
------------------ ------------------- ------------------
652,456 683,909 671,041
Current Assets
Cash and cash equivalents 14,347 13,311 7,343
Accounts and notes receivable, principally customer 141,984 335,779 180,480
Deferred income taxes 13,244 13,601 8,247
Inventories
Gas in underground storage 97,628 53,183 66,915
Materials and supplies 31,661 33,354 37,912
Other 587 445 277
Deferred gas cost 7,406 13,019 14,865
Gas purchased in advance of delivery 6,200 23,440 23,404
Other current assets 30,435 25,496 42,773
------------------ ------------------- ------------------
343,492 511,628 382,216
Deferred Charges 55,913 62,671 67,437
------------------ ------------------- ------------------
TOTAL ASSETS $ 3,473,747 $ 3,665,983 $ 3,510,026
================== =================== ==================
</TABLE>
The Notes to Consolidated Financial Statements are an
integral part of this statement.
<PAGE>
<TABLE>
<CAPTION>
NorAm Energy Corp. and Subsidiaries
CONSOLIDATED BALANCE SHEET
(in thousands of dollars)
(unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY September 30 December 31 September 30
- ------------------------------------
1996 1995 1995
------------------ ------------------- ---------------
<S> <C> <C> <C>
Stockholders' Equity
Preferred stock (Note E) $ - $ 130,000 $ 130,000
Common stock 85,763 78,002 77,735
Paid-in capital 994,396 880,885 878,850
Accumulated deficit (316,784) (336,940) (361,191)
Unrealized gain on investment, net of tax 8,137 15,316 9,793
------------------ ------------------- ------------------
Total Stockholders' Equity 771,512 767,263 735,187
Company-Obligated Mandatorily Redeemable
Convertible Preferred Securities of Subsidiary Trust
Holding Solely $177.8 Million Principal Amount of
6.25% Convertible Subordinated Debentures Due
2026 of NorAm Energy Corp. (Note E) 167,749 - -
Long-Term Debt, Less Current Maturities 1,106,969 1,474,924 1,474,924
Current Liabilities
Current maturities of long-term debt 225,964 118,750 269,750
Notes payable to banks 58,000 10,000 -
Accounts payable, principally trade 324,303 472,374 253,353
Income taxes payable (700) 5,337 (3,975)
Interest payable 30,206 38,730 41,252
General taxes 45,580 48,320 43,265
Customers' deposits 34,132 35,651 34,472
Other current liabilities 102,815 96,645 86,402
------------------ ------------------- ------------------
820,300 825,807 724,519
Other Liabilities and Deferred Credits
Accumulated deferred income taxes 320,688 303,445 277,848
Estimated environmental remediation costs 40,017 48,500 41,632
Payable under capacity lease agreement 41,000 41,000 41,000
Supplemental retirement and deferred compensation 41,109 40,869 40,799
Estimated obligations under indemnification
provisions of sale agreements 30,626 34,207 35,151
Refundable excess deferred income taxes 18,156 26,599 26,788
Other 115,621 103,369 112,178
------------------ ------------------- ------------------
607,217 597,989 575,396
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 3,473,747 $ 3,665,983 $ 3,510,026
================== =================== ==================
</TABLE>
The Notes to Consolidated Financial Statements are an
integral part of this statement.
<PAGE>
<TABLE>
<CAPTION>
NorAm Energy Corp. and Subsidiaries
CONSOLIDATED STATEMENT OF INCOME
(in thousands of dollars except per share amounts)
(unaudited)
Quarter Ended Nine Months Ended
September 30 September 30
----------------------------- --------------------------------
1996 1995 1996 1995
--------------- ------------- --------------- ---------------
<S> <C> <C> <C> <C>
Operating Revenues $ 899,283 $ 542,611 $3,208,271 $1,996,601
Operating Expenses
Cost of natural gas purchased, net 688,499 324,746 2,401,038 1,212,635
Operating, maintenance, cost of sales & other 131,416 143,682 385,056 416,130
Depreciation and amortization (Note I) 36,109 34,893 107,681 111,971
Taxes other than income taxes 24,625 23,171 87,263 77,764
Early retirement and severance (Note D) - - 22,344 -
--------------- ------------- --------------- ---------------
880,649 526,492 3,003,382 1,818,500
Operating Income 18,634 16,119 204,889 178,101
Other Deductions
Interest expense, net 30,976 41,399 101,683 118,254
Dividend requirement on preferred
securities of subsidiary trust (Note E) 2,703 - 3,128 -
Other, net 637 1,317 6,390 5,687
--------------- ------------- --------------- ---------------
34,316 42,716 111,201 123,941
Income(Loss) Before Income Taxes (15,682) (26,597) 93,688 54,160
Provision for Income Taxes(Benefit) (Note B) (7,499) (12,313) 38,339 23,520
--------------- ------------- --------------- ---------------
Income(Loss) Before Extraordinary Item (8,183) (14,284) 55,349 30,640
Net extraordinary gain(loss) on early
retirement of debt, less taxes (Note B) 477 - (4,256) (52)
--------------- ------------- --------------- ---------------
Net Income(Loss) (7,706) (14,284) 51,093 30,588
Preferred dividend requirement (Note E) - 1,950 3,597 5,850
--------------- ------------- --------------- ---------------
Balance Available to Common Stock $ (7,706) $ (16,234) $ 47,496 $ 24,738
=============== ============= =============== ===============
Per Share Data:
Primary:
Before extraordinary item $ (0.06) $ (0.13) $ 0.40 $ 0.20
Extraordinary item, less taxes 0.00 - (0.03) 0.00
=============== ============= =============== ===============
Earnings per common share $ (0.06) $ (0.13) $ 0.37 $ 0.20
=============== ============= =============== ===============
Fully Diluted:
Before extraordinary item $ (0.05) $ (0.13) $ 0.38 $ 0.20
Extraordinary item, less taxes 0.00 - (0.03) 0.00
=============== ============= =============== ===============
Earnings per common share $ (0.05) $ (0.13) $ 0.35 $ 0.20
=============== ============= =============== ===============
Average Common Shares
Outstanding (in thousands)
Primary 137,104 124,103 129,725 123,604
Fully diluted 151,331 124,103 135,229 123,604
Cash Dividends per Common Share $ 0.07 $ 0.07 $ 0.21 $ 0.21
</TABLE>
The Notes to Consolidated Financial Statements are an
integral part of this statement.
<PAGE>
<TABLE>
<CAPTION>
NorAm Energy Corp. and Subsidiaries
STATEMENT OF CONSOLIDATED CASH FLOWS
Increase(Decrease) in Cash and Cash Equivalents
(in thousands of dollars)
(unaudited)
Nine Months
Ended September 30
-------------------------------------
1996 1995
----------------- ----------------
CASH FLOWS FROM OPERATING ACTIVITIES:
<S> <C> <C>
Net income $ 51,093 $ 30,588
Adjustments to reconcile net income to cash provided
by operating activities:
Depreciation and amortization 107,681 111,971
Early retirement and severance, less cash costs (Note D) 12,941 -
Deferred income taxes 21,579 18,082
Extraordinary loss, less taxes (Note B) 4,256 52
Other 2,675 2,455
Changes in certain assets and liabilities, net of noncash transactions:
Accounts and notes receivable, principally customer 201,295 35,366
Inventories (42,894) 6,990
Deferred gas costs 5,613 (21,677)
Other current assets (4,939) (6,616)
Accounts payable, principally trade (154,045) (42,512)
Income taxes payable (6,037) (8,665)
Interest payable (8,524) (928)
General taxes (2,740) (2,452)
Customers' deposits (1,519) (1,029)
Other current liabilities (330) (5,092)
Recoveries under gas contract disputes 8,800 22,200
----------------- ----------------
Net cash provided by operating activities 194,905 138,733
----------------- ----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (116,200) (118,000)
Sale of Itron stock - 1,441
Other, net 17,500 1,091
----------------- ----------------
Net cash used in investing activities (98,700) (115,468)
----------------- ----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Retirements and reacquisitions of long-term debt (Note B) (394,997) (34,352)
Public issuance of common stock (Note E) 108,963 -
Public issuance of convertible preferred securities of subsidiary
trust (Note E) 167,756 -
Issuance of 7 1/2% Notes due 2000 - 200,000
Other interim debt borrowings(repayments) 48,000 (110,000)
Return of advance received under contingent sales agreement - (50,000)
Issuance of common stock under Direct Stock Purchase Plan 7,572 7,698
Common and preferred stock dividends (Note E) (30,937) (31,824)
Decrease in overdrafts (1,526) (15,076)
----------------- ----------------
Net cash used in financing activities (95,169) (33,554)
----------------- ----------------
Net increase(decrease) in cash and cash equivalents 1,036 (10,289)
Cash and cash equivalents - beginning of period 13,311 17,632
----------------- ----------------
Cash and cash equivalents - end of period $ 14,347 $ 7,343
================= ================
</TABLE>
For supplemental cash flow information,
see Note C.
The Notes to Consolidated Financial Statements are an
integral part of this statement.
<PAGE>
===============================================================================
NorAm Energy Corp. and Subsidiaries
===============================================================================
Notes to Consolidated Financial Statements
(unaudited)
A. In the opinion of Management, all adjustments (consisting solely of normal
recurring accruals, except as explicitly described herein) necessary for a
fair presentation of the results of operations for the periods presented
have been included in the accompanying consolidated financial statements.
Because of the seasonal nature of the Company's operations, among other
factors, the results of operations for the periods presented are not
necessarily indicative of the results that will be achieved in an entire
year. The preparation of financial statements 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 each reporting period. Actual results could differ from
those estimates. In the accompanying consolidated financial statements,
certain prior period amounts have been reclassified to conform to the
current presentation. In August 1996, the Company signed a definitive
agreement which is expected to result in the acquisition of the Company by
Houston Industries, see Note L.
B. Following are components of and additional information concerning certain
line items from the accompanying consolidated financial statements:
Investment in Itron, Inc. ("Itron")
At November 11, 1996, the Company's investment in Itron had declined to a
market value of approximately $30.0 million, representing an unrealized
gain of approximately $2.2 million, net of tax of approximately $1.2
million. For additional information concerning the Company's investment in
Itron, see the Company's 1995 Report on Form 10-K.
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
Provision for Income September 30 September 30
- --------------------
----------------------------- ------------------------------
Taxes(Benefit) 1996 1995 1996 1995
- ----------------
--------------- ------------- -------------- --------------
(millions of dollars)
<S> <C> <C> <C> <C>
Federal
Current $ (12.2) $ (15.3) $ 16.4 $ 7.5
Deferred 6.9 6.7 17.7 12.2
Investment tax credit (0.2) (0.2) (0.5) (0.5)
State
Current (3.1) (6.0) 0.8 (1.6)
Deferred 1.1 2.5 3.9 5.9
=============== ============= ============== ==============
$ (7.5) $ (12.3) $ 38.3 $ 23.5
=============== ============= ============== ==============
</TABLE>
<TABLE>
<CAPTION>
Nine Months
Retirements and Reacquisitions Ended September 30
---------------------------------
of Long Term Debt (1) 1996 1995
- -----------------------
-------------- -------------
<S> <C> <C>
(millions of dollars)
Reacquisition of 9.875% Series due 2018 $ 7.4 (1) $ 5.7 (1)
Reacquisition of 10% Debentures due 2019 - 15.0 (1)
Retirement, at maturity, of Medium Term Notes,
weighted average interest rate of approximately 9.06% 118.8 -
Retirement of Bank Term Loan due 2000 (Note E) 150.0 -
Retirement of 9.875% Series Due 2018 (Note E) 109.1 (1) -
Retirement, at maturity, of Note Payable to Gas Supplier - 13.6
Other reacquisitions 5.5 (1) -
Net loss on reacquisition of debt, less taxes 4.2 0.1
============== =============
$ 395.0 $ 34.4
============== =============
</TABLE>
(1) The premiums associated with these reacquisitions and retirements are
reported in the accompanying Statement of Consolidated Income as "Net
extraordinary gain(loss) on early retirement of debt, less taxes", and are
net of tax benefits of $2.7 million and $0.03 million for the nine months
ended September 30, 1996 and 1995, respectively.
C. In the accompanying consolidated financial statements, all highly
liquid investments purchased with an original maturity of three months
or less are considered to be cash equivalents. Following is selected
supplemental cash flow information.
<TABLE>
<CAPTION>
Nine Months
Ended September 30
--------------------------------------
1996 1995
----------------- -----------------
(millions of dollars)
<S> <C> <C>
Cash interest payments, net of capitalized interest $ 110.2 $ 115.7
Net income tax payments $ 21.6 $ 17.1
</TABLE>
In June 1996, the Company exercised its right to exchange its $3.00
Preferred Stock Series A for its 6% Convertible Subordinated Debentures
due 2012 in a non-cash transaction, see Note E.
D. During the first quarter of 1996, the Company instituted a reorganization
plan affecting its NorAm Gas Transmission Company ("NGT") and Mississippi
River Transmission Corporation ("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".
E. During June 1996, the Company engaged in the following significant
financing transactions:
*The Company issued 11,500,000 shares of NorAm Energy Corp. Common
Stock (the "Common Stock") to the public at a price of $9.875 per
share, yielding net cash proceeds of approximately $109.0 million after
deducting an underwriting discount of 4.05% and before deducting
expenses of approximately $0.1 million. The net proceeds from the
offering principally were used to retire debt as described following.
*The Company issued $177.8 million of 6.25% Convertible Subordinated
Debentures due 2026 (unless extended by the Company as discussed
following) (the "Trust Debentures") to NorAm Financing I (the "Trust"),
a statutory business trust under Delaware law, wholly owned by the
Company. The Trust Debentures were purchased by the Trust using the
proceeds from (1) the public issuance by the Trust of 3,450,000 shares
of 6.25% Convertible Preferred Securities (the "Trust Preferred") at
$50 per share, a total of $172.5 million and (2) the sale of
approximately $5.3 million of the Trust's common stock (106,720 shares,
representing 100% of the Trust's common equity) to the Company. The
sole assets of the Trust are and will be the Trust Debentures. The
interest and other payment dates on the Trust Debentures correspond to
the interest and other payment dates on the Trust Preferred. In
conjunction with the issuance of the Trust Preferred, the Company paid
an underwriting commission of $1.375 per share and expenses of
approximately $0.1 million in view of the fact that the proceeds from
such issuance would be invested in the Trust Debentures. The net
proceeds from these transactions principally were used to retire debt
as described following.
The Trust Preferred, as more fully described in the offering
documents, accrues a dividend equal to 6.25% of the $50 liquidation
amount, payable quarterly in arrears. The ability of the Trust to pay
distributions on the Trust Preferred is solely dependent on its receipt
of interest payments on the Trust Debentures. The Company has
guaranteed, on a subordinated basis, distributions and other payments
due on the Trust Preferred (the "Guarantee"). The Guarantee, when taken
together with the Company's obligations under the Trust Debentures and
in the indenture pursuant to which the Trust Debentures were issued and
the Company's obligations under the Amended and Restated Declaration of
Trust governing the Trust, provides a full and unconditional guarantee
of amounts due on the Trust Preferred. The Company has the right to
defer interest payments on the Trust Debentures as discussed following.
In the case of such deferral, quarterly distributions on the Trust
Preferred would be deferred by the Trust but would continue to
accumulate quarterly and would accrue interest. Each share of Trust
Preferred is convertible at the option of the holder into shares of
Common Stock at an initial conversion rate of 4.1237 shares of Common
Stock for each share of the Trust Preferred, subject to adjustment in
certain circumstances. The Trust Preferred does not have a stated
maturity date, although it is subject to mandatory redemption upon
maturity of the Trust Debentures or to the extent that the Trust
Debentures are redeemed. The redemption price in either such case will
be $50 per share plus accrued and unpaid distributions to the date
fixed for redemption. In general, holders of the Trust Preferred do not
have any voting rights.
The Trust Debentures, as more fully described in the offering
documents, bear interest at 6.25% and are redeemable for cash at the
option of the Company, in whole or in part, from time to time on or
after June 30, 2000, if and only if for 20 trading days within any
period of 30 consecutive days, including the last trading day of such
period, the current market price of the Common Stock equals or exceeds
125% of the then-applicable conversion price of the Trust Debentures,
or at any time in certain circumstances upon the occurrence of a
specified tax event. The Trust Debentures will mature on June 30, 2026,
although the maturity date may be extended only once at the Company's
election for up to an additional 19 years, provided certain
requirements and conditions are met. Under existing law, interest
payments made by the Company for the Trust Debentures are deductible
for federal income tax purposes. The Company has the right at any time
and from time to time to defer interest payments on the Trust
Debentures for successive periods not to exceed 20 consecutive quarters
for each such extension period. In such case, (1) quarterly
distributions on the Trust Preferred would also be deferred as
discussed preceding and (2) the Company has agreed not to declare or
pay any dividend on any common or preferred stock, except in certain
instances.
The Trust is consolidated with the Company for financial
reporting purposes and, therefore, the Trust Debentures are eliminated
in consolidation and the Trust Preferred appears on the Company's
Consolidated Balance Sheet under the caption "Company-Obligated
Mandatorily Redeemable Convertible Preferred Securities of Subsidiary
Trust Holding Solely $177.8 Million Principal Amount of 6.25%
Convertible Subordinated Debentures due 2026 of NorAm Energy Corp.".
The dividend on the Trust Preferred is reported on a pre-tax basis in
the accompanying Statement of Consolidated Income under the caption
"Dividend requirement on preferred securities of subsidiary trust".
*Utilizing, in large part, the proceeds from the offerings discussed
preceding, the Company (1) retired the $109.1 million principal amount
then outstanding of its 9.875% Debentures due 2018 at a price equal to
105.93% of face value, recognizing an extraordinary pre-tax loss of
approximately $6.5 million (approximately $3.9 million or $0.03 per
share after-tax) and (2) retired its $150 million bank term loan due
2000 at face value, see Note B.
*The Company exercised its right to exchange the $130 million
principal amount of its $3.00 Preferred Stock Series A (the
"Preferred") for its 6% Convertible Subordinated Debentures due 2012
(the "Subordinated Debentures"). The holders of the Subordinated
Debentures will receive interest quarterly at 6% and have the right at
any time on or before the maturity date thereof to convert the
Subordinated Debentures into Common Stock, initially at the conversion
rate in effect for the Preferred at the date of the exchange, which
conversion rate of approximately 1.7467 shares of the Common Stock for
each $50 principal amount of the Subordinated Debentures is subject to
adjustment should certain events occur. The Company is required to make
annual sinking fund payments of $6.5 million on the Subordinated
Debentures beginning on March 15, 1997 and on each succeeding March 15
to and including March 15, 2011. The Company (1) may credit against the
sinking fund requirements (i) any Subordinated debentures redeemed by
the Company and (ii) Subordinated Debentures which have been converted
at the option of the holder and (2) may deliver outstanding
Subordinated Debentures in satisfaction of the sinking fund
requirements.
F. During April 1996, the Company announced that, together with its partners,
it had submitted a Declaration of Interest to the Mexican Regulatory
Commission to obtain 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 October 1996, the Energy Regulatory Commission of Mexico
announced that competitive bids would be taken on January 23, 1997 and that
the winner of the bid would be announced on March 20, 1997, with the permit
to be issued on April 20, 1997. Chihuahua is the capital city of Mexico's
largest state and, together with the surrounding geographic area, has a
population of approximately 850,000 and includes expanding commercial and
industrial development. The Company and its partners previously had
announced the filing of a similar proposal with respect to the Mexico City
Metropolitan Area, which may be subdivided into several franchises to be
permitted separately. The Company cannot yet determine with respect to
either project whether it will be the successful bidder or whether
construction will ultimately be undertaken and completed.
G. Primary earnings per share is computed using the weighted average number of
shares of 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 the immaterial number of
such options which 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 E) 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 in each
period from the cessation of the dividends on the Trust Preferred (net of
the related tax benefit) which would result from such assumed conversion.
For the quarter and nine months ended September 30, 1996, this assumed
earnings increase was approximately $2.7 million and $3.1 million,
respectively, net of related tax benefits of approximately $1.6 million and
$1.9 million, respectively. The Company's 6% Convertible Subordinated
Debentures due 2012 (see Note E) and the Company's $3.00 Series A Preferred
Stock (prior to its exchange as described preceding), 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 Series
A Preferred Stock was outstanding, all per share calculations are made
using earnings after reduction for the preferred stock dividend requirement
associated with such security.
H. As further discussed in the Company's 1995 Report on Form 10-K, under
an August 1995 agreement (the "Receivable Sale Agreement"), the Company
sells an undivided interest in a pool of accounts receivable with
limited recourse. Total receivables sold under the Receivable Sale
Agreement but not yet collected were approximately $235.0 million,
$235.0 million and $82.1 million at September 30, 1996, December 31,
1995 and September 30, 1995, respectively, which amounts have been
deducted from "Accounts and notes receivable, principally customer" in
the accompanying Consolidated Balance Sheet and, at September 30, 1996,
approximately $30.0 million of the Company's remaining receivables were
collateral for receivables which had been sold.
I. 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. The effect of
this change was to reduce depreciation expense for the nine months
ended September 30, 1996 by approximately $5.4 million (approximately
$3.2 million or $0.026/share after tax) from the corresponding period
of 1995.
J. As more fully described in the Company's 1995 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, 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 improperly disposed of. 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. To the extent that such potential
costs are 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 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 K.
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 K.
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.
K. 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 or to rescind the
merger and/or to recover damages in the event that the Houston Industries
merger 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.
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.
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.
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.
L. On August 11, 1996, the Company entered into an Agreement and Plan of
Merger (the "Merger Agreement") with Houston Industries Incorporated
("Houston Industries"), 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
below). 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). A Special Meeting of the Company's stockholders will be held on
December 17, 1996, whereby NorAm stockholders will be asked to approve and
adopt the Merger Agreement. A Special Meeting of Houston Industries
stockholders is scheduled for the same day. Such stockholder approvals are
a condition to the obligations of Houston Industries and the Company to
consummate the Transaction. Consideration for the purchase of Company
shares will be a combination of cash and shares of HII common stock. The
transaction is valued at $3.8 billion, consisting of $2.4 billion for the
Company's common stock and equivalents and $1.4 billion of the Company's
debt. For information regarding the Merger Agreement, see the Joint Proxy
Statement/ Prospectus of Houston Industries, HL&P and the Company dated
October 29, 1996.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
NorAm Energy Corp., referred to herein together with its consolidated
subsidiaries and divisions (all of which are wholly owned) as "NorAm" or "the
Company", principally conducts operations in the natural gas industry, including
gathering, transmission, marketing, storage and distribution which,
collectively, account for in excess of 90% of the Company's total revenues,
income or loss and identifiable assets. The Company also makes certain
non-energy sales and provides certain non-energy services, principally to
certain of its retail gas distribution customers. The reader is directed to the
Company's 1995 Report on Form 10-K for (1) a more detailed discussion of the
business units into which the Company currently has been segregated and the
activities conducted by each such business unit, including (i) a reconciliation
to the Company's previous business unit reporting structure and (ii) information
concerning major customers and (2) a discussion of the Company's significant
accounting policies. In August 1996, the Company signed a definitive agreement
which is expected to result in the merger of the Company with and into a wholly
owned subsidiary of Houston Industries Incorporated, see "Merger with Houston
Industries Incorporated" following.
Merger with Houston Industries Incorporated
On August 11, 1996, the Company entered into an Agreement and Plan of
Merger (the "Merger Agreement") with Houston Industries Incorporated ("Houston
Industries"), 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 below). 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). A Special Meeting of the Company's
stockholders will be held on December 17, 1996, whereby NorAm stockholders will
be asked to approve and adopt the Merger Agreement. A Special Meeting of Houston
Industries stockholders is scheduled for the same day. Such stockholder
approvals are a condition to the obligations of Houston Industries and the
Company to consummate the Transaction. Consideration for the purchase of Company
shares will be a combination of cash and shares of HII common stock. The
transaction is valued at $3.8 billion, consisting of $2.4 billion for the
Company's common stock and equivalents and $1.4 billion of the Company's debt.
For information regarding the merger, see the Joint Proxy Statement/Prospectus
of Houston Industries, HL&P and the Company dated August 11, 1996.
Recent Developments
Dividend Declaration
On November 13, 1996, the Company's Board of Directors declared
dividends of $0.07 per share on common stock, payable December 13 to owners of
record on November 25, 1996. The Company's $3.00 Preferred Stock, Series A is no
longer outstanding, see "Net Cash Flows from Financing Activities" elsewhere
herein.
Regulatory Matters
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. $7 million using Minnegasco's
1995 gas cost) for Minnegasco during any year.
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 refunded 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
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 case, had the Court's ruling been in effect at that time.
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 distribution 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 Minnesota Supreme Court (the "Court"). On June 13, 1996, the
Court reversed the MPUC's decisions, finding in Minnegasco's favor and, in July,
the Court denied the MPUC's request for rehearing.
In October 1996, the MPUC met to reconsider its June 1996 order.
Although a final written order has not yet been issued, 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
should not recover the cost of gas leak check calls, nor did it approve
Minnegasco's request with respect to the 1993 costs. An appeal related to the
1993 rate case is pending before the Minnesota Court of Appeals. Arguments were
heard on October 30 and a decision is expected to be issued the end of January.
Minnegasco will seek a stay of the Commission's order pending Minnegasco's
appeal of the gas leak issue. Should the Commission deny the stay, the amounts
to be refunded are not materially in excess of existing accruals.
On May 31, 1996, Mississippi River Transmission Corporation ("MRT")
received authorization from the Federal Energy Regulatory Commission (the
"FERC") in Docket No. CP95-376 to abandon by transfer to NorAm Field Services
("NFS") certain certificated natural gas gathering facilities. In March 1996,
MRT filed with the FERC in Docket No. CP96-268 seeking authorization to spindown
the remainder of its gathering facilities to NFS. On August 2, 1996, the D.C.
Court of Appeals remanded, to the FERC, its requirement that a default contract
be placed into effect by the non-jurisdictional gatherer for a two-year period
after the abandonment and transfer of facilities. The order in MRT's application
has been delayed pending the FERC's action on the Court's remand.
In April 1996, MRT submitted a general rate increase filing to the FERC
applicable to its unbundled transportation and storage services. MRT has
requested a rate increase of $14.7 million to cover increased costs and an
increased rate of return. The proceeding is currently in the settlement phase
and the procedural schedule has been temporarily suspended. Several settlement
conferences have been held and discussions with customers are on-going.
In April 1996, the FERC approved NorAm Gas Transmission Company's
("NGT") previously filed request for negotiated rates, providing enhanced rate
flexibility on the NGT system. Pursuant to a new policy statement (under Docket
No. RM96-7-000) issued by the FERC in January 1996, NGT and its shippers may now
negotiate a rate for service more consistent with actual market conditions,
which rates may exceed the maximum cost-based rate set forth in NGT's filed
tariff and/or deviate from the current FERC-mandated rate design. NGT has
negotiated certain "market-sensitive" transactions which allow shippers' rates
to be based on various factors such as gas price differentials between the west
and east side of the NGT system. As a result there is the potential that, in
some instances, NGT will charge and collect a negotiated rate which exceeds
NGT's then-current maximum tariff rate. NGT made a compliance filing on May 28,
1996 which was rejected without prejudice by the FERC on June 26. NGT made its
second compliance filing on July 11, and received an order approving such on
August 21. On October 2, the FERC issued its order on rehearing, ruling that NGT
could not include any negotiated rate contracts in its discount adjustment in a
future rate case. NGT filed for rehearing of this decision on November 1 and is
awaiting a FERC decision. NGT is continuing to make filings on the first of
every month to reflect negotiated rate transactions for that month.
<PAGE>
Material Changes in the Results of Operations
The Company's results of operations are seasonal due to seasonal
fluctuations in the demand for and, to a lesser extent, the price of natural gas
and, accordingly, the results of operations for interim periods are not
necessarily indicative of the results to be expected for an entire year. As
reported in the Company's 1995 Report on Form 10-K, however, the Company's
regulated businesses have obtained rate design changes which have lessened the
seasonality of the Company's results of operations and further such changes may
occur. In addition to the demand for and price of natural gas, the Company's
results of operations are significantly affected by regulatory actions (see
"Regulatory Matters" elsewhere herein and in the Company's 1995 Report on Form
10-K), competition and, below the operating income line, by (1) the level of
borrowings and interest rates thereon and (2) income tax expense, see
"NON-OPERATING INCOME AND EXPENSE" elsewhere herein. Following are detailed
discussions of material changes in the results of operations by business unit:
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
September 30 September 30
------------------------------------------- --------------------------------------------------
Increase Increase
Operating Income(Loss) 1996 1995 (Decrease) 1996 1995 (Decrease)
- ----------------------
----------- ---------- ------------------- ----------- ----------- --------------------
(dollars in millions) ($/%) ($/%)
<S> <C> <C> <C> <C> <C> <C>
Natural Gas Distribution $ (15.6) $ (10.3) $(5.3) / (51.5)% $ 111.8 (1) $ 86.6 $25.2 / 29.1%
Interstate Pipelines 29.7 21.6 8.1 / 37.5% 90.1 (1)(2) 72.5 17.6 / 24.3%
Wholesale Energy Marketing (0.6) (0.7) 0.1 / 14.3% 8.4 1.7 6.7 / 394.1%
Natural Gas Gathering 3.4 2.8 0.6 / 21.4% 9.5 (2) 6.7 2.8 / 41.8%
Retail Energy Marketing 7.1 5.6 1.5 / 26.8% 24.1 16.9 7.2 / 42.6%
Corporate and Other (3) (5.3) (2.9) (2.4) / (82.8)% (16.7) (6.3) (10.4) / (165.1)%
----------- ---------- ----------- -----------
18.7 16.1 2.6 / 16.1% 227.2 178.1 49.1 / 27.6%
Early Retirement and
Severance (4) - - - / - (22.3) - (22.3) / N/A
----------- ---------- ----------- -----------
Consolidated $ 18.7 $ 16.1 $2.6 / 16.1% $ 204.9 $ 178.1 $26.8 / 15.0%
=========== ========== =========== ===========
</TABLE>
(1) Before expenses for early retirement and severance, see (4) following.
(2) Includes the impact of a change in depreciation rates, see the individual
discussions of the results of operations for these business units
following.
(3) Includes approximately $3.6 million and $10.8 million of goodwill
amortization in each quarter and nine-month period presented, respectively.
(4) During the first quarter of 1996, the Company recorded non-recurring
charges in "Natural Gas Distribution" and "Interstate Pipelines" associated
with staffing reductions, see the individual discussions of the results of
operations for these business units elsewhere herein.
<PAGE>
NATURAL GAS DISTRIBUTION
The Company's natural gas distribution business is conducted by its
Entex, Minnegasco and Arkla Divisions, collectively referred to herein as
"Distribution" or "Natural Gas Distribution". Certain issues exist with respect
to environmental matters, see "Contingencies" elsewhere herein.
During the first quarter of 1996, approximately 100 employees of Entex
accepted an early retirement program and approximately 25 positions were
eliminated at Minnegasco as a result of the reorganization of certain functions,
resulting in a total non-recurring pre-tax charge of approximately $5.8 million,
which amount is included under the caption "Early retirement and severance" in
the accompanying Statement of Consolidated Income and in the following table.
The Company currently expects that a substantial portion of this expense will be
offset during 1996 by the associated cost savings.
<TABLE>
<CAPTION>
Quarter Ended Nine Months
September 30 Ended September 30
--------------------------------------------- --------------------------------------------
FINANCIAL RESULTS Increase Increase
- -----------------
(dollars in millions) 1996 1995 (Decrease) 1996 1995 (Decrease)
----------- ----------- ------------------- ------------ ----------- ------------------
($/%) ($/%)
<S> <C> <C> <C> <C> <C> <C>
Natural gas sales $249.4 $224.3 $25.1 / 11.2% $1,387.3 $1,127.5 $259.8 / 23.0%
Transportation revenue 2.5 3.6 (1.1) / (30.6)% 12.3 13.2 (0.9) / (6.8)%
Other revenue 4.6 4.5 0.1 / 2.2% 17.9 16.8 1.1 / 6.5%
----------- ----------- ------------ -----------
Total operating revenues 256.5 232.4 24.1 / 10.4% 1,417.5 1,157.5 260.0 / 22.5%
Purchased gas cost
Unaffiliated 127.8 93.2 34.6 / 37.1% 691.7 511.9 179.8 / 35.1%
Affiliated 7.5 18.3 (10.8) / (59.0)% 183.5 153.4 30.1 / 19.6%
Operations and maintenance 93.4 89.6 3.8 / 4.2% 287.6 270.6 17.0 / 6.3%
Depreciation and amortization 23.9 22.7 1.2 / 5.3% 71.0 67.6 3.4 / 5.0%
Other operating expenses 19.5 18.9 0.6 / 3.2% 71.9 67.4 4.5 / 6.7%
----------- ----------- ------------ -----------
(15.6) (10.3) (5.3) / (51.5)% 111.8 86.6 25.2 / 29.1%
Early retirement and severance - - - / - 5.8 - 5.8 / N/A
----------- ----------- ------------ -----------
Operating income $ (15.6) $ (10.3) $(5.3) / (51.5)% $ 106.0 $ 86.6 $19.4 / 22.4%
=========== =========== ============ ===========
OPERATING STATISTICS
(billions of cubic feet) (Bcf/%) (Bcf/%)
Residential sales 15.4 15.8 (0.4) / (2.5)% 137.8 121.8 16.0 / 13.1%
Commercial sales 15.9 15.6 0.3 / 1.9% 92.7 83.8 8.9 / 10.6%
Industrial sales 13.7 12.7 1.0 / 7.9% 41.8 38.4 3.4 / 8.9%
Transportation 9.5 10.3 (0.8) / (7.8)% 32.5 35.4 (2.9) / (8.2)%
----------- ----------- ------------ -----------
Total throughput 54.5 54.4 0.1 / 0.2% 304.8 279.4 25.4 / 9.1%
=========== =========== ============ ===========
DEGREE DAYS 1996 1995 Normal 1996 1995 Normal
------------ ----------- ----------- ----------- ---------- ---------
Arkla 14 29 7 1,939 1,661 1,864
Entex 3 4 2 1,067 800 889
Minnegasco 173 205 194 5,486 4,772 4,869
</TABLE>
Quarter Comparison
Distribution operating results which, due to the seasonal nature of the
residential and commercial demand for natural gas are routinely negative in the
third quarter, declined from a loss of $(10.3) million in the third quarter of
1995 to a loss of $(15.6) million in the third quarter of 1996, a decrease of
$5.3 million (51.5%). This increased loss reflected both increased operating
revenues and increased operating expenses as discussed following.
"Natural gas sales", representing approximately 97% of Distribution's
total operating revenues in each quarter presented, increased from $224.3
million in the third quarter of 1995 to $249.4 million in the third quarter of
1996, an increase of $25.1 million (11.2%). This increase, approximately $20.5
million (81.7%) of which was attributable to an increase in the average sales
price and approximately $4.6 million (18.3%) of which was due to increased
volume, was principally due to, (1) an increase in the average cost of gas (a
component of the sales price) as discussed following, (2) rate increases
obtained in certain jurisdictions, see "Regulatory Proceedings" in the Company's
1995 Report on Form 10-K and (3) an increase in commercial and industrial sales
volume from 28.3 Bcf in the third quarter of 1995 to 29.6 Bcf in the third
quarter of 1996, an increase of 1.3 Bcf (4.6%).
"Purchased gas cost" increased from $111.5 million in the third quarter
of 1995 to $135.3 million in the third quarter of 1996, an increase of $23.8
million (21.3%), approximately $21.5 million (90.3%) of which was attributable
to an increase in the average cost of purchased gas and approximately $2.3
million (9.7%) of which was attributable to increased volume. The increase in
the weighted average cost of gas from approximately $2.53 per Mcf in the third
quarter of 1995 to approximately $3.01 per Mcf in the third quarter of 1996, an
increase of approximately $0.48 per Mcf (19.0%), was reflective of an overall
increase in the market price of gas, while the increased volume was principally
due to increased commercial and industrial sales volume as discussed preceding.
The gross sales margin ("Natural gas sales" minus total purchased gas
cost) increased from $112.8 million in the third quarter of 1995 to $114.1
million in the third quarter of 1996, an increase of $1.3 million (1.2%). This
increase was principally due to the increased commercial and industrial sales
volume as discussed preceding.
Operating expenses, exclusive of purchased gas cost, increased from
$131.2 million in the third quarter of 1995 to $136.8 million in the third
quarter of 1996, an increase of $5.6 million (4.3%), principally due to (1)
increased environmental costs (which, as discussed in the Company's 1995 Report
on Form 10-K, are substantially being recovered through the regulatory process),
(2) increased depreciation expense due to increased investment, including the
transfer of certain Corporate assets as described in the Company's 1995 Report
on Form 10-K and (3) increased payroll, supplies and bad debt expense.
Year-to-Date Comparison
Distribution operating income increased from $86.6 million in the first
nine months of 1995 to $111.8 million (before the 1996 charge for early
retirement and severance as discussed preceding) in the first nine months of
1996, an increase of $25.2 million (29.1%). This increased operating income
reflected both increased operating revenues and increased operating expenses as
discussed following.
"Natural gas sales", representing more than 97% of Distribution's total
operating revenues in each period presented, increased from $1,127.5 million in
the first nine months of 1995 to $1,387.3 million in the first nine months of
1996, an increase of $259.8 million (23.0%). This increase, approximately $130.8
million (50.3%) of which was attributable to increased volume and approximately
$129.0 million (49.7%) of which was attributable to an increase in the average
sales price, was principally due to (1) colder weather, 8,492 total degree days
in the first nine months of 1996 vs. 7,233 in the first nine months of 1995, an
increase of 1,259 degree days (17.4%), which was largely responsible for
increases of 16.0 Bcf and 8.9 Bcf in residential and commercial sales volumes,
respectively, (2) rate increases obtained in certain jurisdictions, see
"Regulatory Proceedings" in the Company's 1995 Report on Form 10-K and (3) an
increase in the average cost of gas (a component of the sales price) as
discussed following.
"Purchased gas cost" increased from $665.3 million in the first nine
months of 1995 to $875.2 million in the first nine months of 1996, an increase
of $209.9 million (31.5%), approximately $132.7 million (63.2%) of which was
attributable to an increase in the average cost of purchased gas and
approximately $77.2 million (36.8%) of which was attributable to increased
volume. The increased volume was principally due to the colder weather and
related increased residential and commercial sales volumes as discussed
preceding, while the increase in the weighted average cost of gas from
approximately $2.73 per Mcf in the first nine months of 1995 to approximately
$3.21 per Mcf in the first nine months of 1996, an increase of approximately
$0.48 per Mcf (17.6%), was reflective of an overall increase in the market price
of gas during 1996.
The gross sales margin ("Natural gas sales" minus total purchased gas
cost) increased from $462.2 million in the first nine months of 1995 to $512.1
million in the first nine months of 1996, an increase of $49.9 million (10.8%).
This increase was principally due to the largely weather-related 11.6% increase
in total sales volume as discussed preceding.
Operating expenses, exclusive of purchased gas cost and the 1996 charge
for early retirement and severance, increased from $405.6 million in the first
nine months of 1995 to $430.5 million in the first nine months of 1996, an
increase of $24.9 million (6.1%), principally due to (1) increased environmental
costs (which, as discussed in the Company's 1995 Report on Form 10-K, are
substantially being recovered through the regulatory process), (2) increased bad
debt provisions largely resulting from weather-related increases in customer
bills and (3) increased depreciation expense due to increased investment,
including the transfer to Distribution of certain Corporate assets as described
in the Company's 1995 Report on Form 10-K.
<PAGE>
INTERSTATE PIPELINES
The Company's interstate pipeline business is conducted by NorAm Gas
Transmission Company ("NGT") and Mississippi River Transmission Corporation
("MRT"), together with certain subsidiaries and affiliates, collectively
referred to herein as "Pipeline" or "Interstate Pipelines". The Company is a
party to certain claims involving its gas purchase contracts and issues exist
with respect to environmental matters, see "Contingencies" elsewhere herein.
During the first quarter of 1996, the Company instituted a
reorganization plan (the "Plan") affecting NGT and MRT. The Plan, which included
the reorganization of a number of departments and the redesign of a number of
processes, is intended to allow Pipeline to operate more efficiently, thus
improving its ability to compete in its market areas. Approximately 275
positions were eliminated pursuant to the Plan, resulting in a non-recurring
pre-tax charge of approximately $16.5 million, included in the accompanying
Statement of Consolidated Income and in the following table under the caption
"Early retirement and severance." The Company currently expects that a
substantial portion of this expense will be offset during 1996 by the associated
cost savings.
<TABLE>
<CAPTION>
Quarter Ended Nine Months
September 30 Ended September 30
-------------------------------------------- -------------------------------------------
FINANCIAL RESULTS Increase Increase
- -----------------
(dollars in millions) 1996 1995 (Decrease) 1996 1995 (Decrease)
----------- ----------- ------------------- ----------- ----------- ------------------
($/%) ($/%)
<S> <C> <C> <C> <C> <C> <C>
Natural gas sales
Sales to Distribution $ 15.4 $ 13.0 $2.4 / 18.5% $ 60.4 $ 44.4 $16.0 / 36.0%
Sales for resale and other 3.9 11.7 (7.8) / (66.7)% 12.1 26.2 (14.1) / (53.8)%
----------- ----------- ----------- -----------
Total gas sales revenue 19.3 24.7 (5.4) / (21.9)% 72.5 70.6 1.9 / 2.7%
Transportation revenue
Distribution 26.5 23.9 2.6 / 10.9% 75.6 68.5 7.1 / 10.4%
Unaffiliated 39.1 36.5 2.6 / 7.1% 119.4 110.3 9.1 / 8.3%
----------- ----------- ----------- -----------
Total transportation revenue 65.6 60.4 5.2 / 8.6% 195.0 178.8 16.2 / 9.1%
----------- ----------- ----------- -----------
Total operating revenues 84.9 85.1 (0.2) / (0.2)% 267.5 249.4 18.1 / 7.3%
Purchased gas cost 18.2 23.9 (5.7) / (23.8)% 63.9 62.4 1.5 / 2.4%
Operations and maintenance
expense 11.5 15.9 (4.4) / (27.7)% 38.4 43.3 (4.9) / (11.3)%
Depreciation and amortization 7.7 7.8 (0.1) / (1.3)% 22.8 26.3 (3.5) / (13.3)%
General, administrative and other 17.8 15.9 1.9 / 11.9% 52.3 44.9 7.4 / 16.5%
----------- ----------- ----------- -----------
29.7 21.6 8.1 / 37.5% 90.1 72.5 17.6 / 24.3%
Early retirement and severance - - - / - 16.5 - 16.5 / N/A
----------- ----------- ----------- -----------
Operating income $ 29.7 $ 21.6 $8.1 / 37.5% $ 73.6 $ 72.5 $1.1 / 1.5%
=========== =========== =========== ===========
OPERATING STATISTICS
(millions of MMBtu) (millions of (millions of
Natural gas sales MMBtu/%) MMBtu/%)
Sales to Distribution 6.0 7.5 (1.5) / (20.0)% 22.9 21.6 1.3 / 6.0%
Sales for resale and other 1.7 4.1 (2.4) / (58.5)% 5.1 16.7 (11.6) / (69.5)%
----------- ----------- ----------- -----------
Total sales 7.7 11.6 (3.9) / (33.6)% 28.0 38.3 (10.3) / (26.9)%
----------- ----------- ----------- -----------
Transportation
Distribution 14.4 15.9 (1.5) / (9.4)% 81.4 75.2 6.2 / 8.2%
Other 184.0 201.5 (17.5) / (8.7)% 632.8 631.1 1.7 / 0.3%
----------- ----------- ----------- -----------
Total transportation 198.4 217.4 (19.0) / (8.7)% 714.2 706.3 7.9 / 1.1%
Elimination (1) (7.3) (12.4) 5.1 / 41.1% (26.4) (36.8) 10.4 / 28.3%
----------- ----------- ----------- -----------
Total throughput 198.8 216.6 (17.8) / (8.2)% 715.8 707.8 8.0 / 1.1%
=========== =========== =========== ===========
</TABLE>
(1) This elimination is made to prevent the overstatement of total
throughput which would otherwise occur due to physical volumes which
were both sold and transported by Pipeline and are therefore included
in the above volumetric data in both categories. No elimination is made
for volumes of 45.8 million MMBtu, 42.0 million MMBtu, 153.9 million
MMBtu and 142.0 million MMBtu in the quarters ended September 30, 1996
and 1995, and the nine months ended September 30, 1996 and 1995,
respectively, which were transported on both the NGT and MRT systems.
Quarter Comparison
Interstate Pipeline operating income for the third quarter of 1996 was
$29.7 million, an increase of $8.1 million (37.5%) from the corresponding
quarter in 1995. This improvement was largely attributable to a $5.2 million
increase in transportation margins and a $2.6 million reduction in total
operating expenses as discussed following.
"Total gas sales revenues" decreased from $24.7 million in the third
quarter of 1995 to $19.3 million in the third quarter of 1996, a decrease of
$5.4 million (21.9%). This decrease was composed of an $8.3 million decrease
attributable to a 3.9 million MMBtu (33.6%) decrease in 1996 sales volumes,
partially offset by a $2.9 million increase attributable to a higher 1996
average sales price. "Sales to Distribution" for the third quarter of 1996
increased by $2.4 million (18.5%), while corresponding sales volumes decreased
by 1.5 million MMBtu (20.0%). The revenue increase was principally due to higher
1996 gas prices which increase the commodity component of the overall sales
price, resulting in higher sales revenues without necessarily increasing total
margins. The decline in sales volumes to Distribution was principally due to the
August 31, 1996 expiration of a contract under which certain volumes were sold
to the Company's Arkla distribution unit. "Sales for resale and other" decreased
by $7.8 million (66.7%) primarily due to a 2.4 million MMBtu (58.5%) decrease in
sales volumes. This decline in 1996 sales volumes was principally due to the
discontinuation of certain sales to a marketing affiliate. "Purchased gas cost"
decreased by $5.7 million (23.8%) from the third quarter of 1995 to the third
quarter of 1996. This net decrease was composed of an $8.0 million decrease
attributable to reduced 1996 sales volumes, partially offset by a $2.3 million
increase associated with higher 1996 gas prices as discussed preceding.
"Total transportation revenue" for the third quarter of 1996 increased
by $5.2 million (8.6%) from the third quarter of 1995, while corresponding
transportation volumes decreased by 19.0 million MMBtu (8.7%). These increased
transportation revenues are primarily attributable to the positive impact of
NGT's recent rate case which became effective in February 1995 (see "Regulatory
Matters" elsewhere herein), combined with a change in the relative pricing of
Mid-Continent gas supplies. When prices of Gulf Coast gas increase significantly
over Mid-Continent gas (Pipeline's primary supply area), competitive pressure on
transportation prices are reduced. During the third quarter of 1996, the price
differential between Mid-Continent and Gulf Coast gas was $0.18/MMBtu compared
to a $0.12/MMBtu differential in the third quarter of 1995. The decrease in
transportation volumes tends to have a less than proportionate impact on
transportation revenues because, under the straight-fixed-variable rate design
currently applicable to Pipeline, a relatively small portion of the overall
transportation rate varies directly with the volume transported. During the
third quarter of 1996, Pipeline continued to utilize the Company's risk
management program to mitigate the market risk, associated with certain of its
transportation agreements which contain market-sensitive pricing provisions,
arising from movement in certain basin differentials, see "Regulatory Matters"
and "Wholesale Energy Marketing" elsewhere herein.
"Operations and maintenance expense" decreased by $4.4 million (27.7%)
from the third quarter of 1995 to the third quarter of 1996. Approximately $1.5
million of this decrease was due to a reduction in third-party transportation
expense, with the remainder of the variance primarily attributable to cost
reductions associated with the reorganization plan implemented during the first
quarter of 1996. The cost reductions associated with the reorganization plan
were partially offset by a reduction in capitalized labor during 1996. This
reduction in capitalization of labor cost, which results in increased labor
expense, was principally due to lower 1996 capital expenditures and a change in
company policy which has resulted in increased use of contract personnel rather
than company personnel for many of its capital projects. "Other operating
expenses, net" increased by $1.9 million (11.9%) from the third quarter of 1995
to the third quarter of 1996. Approximately $1.3 million of this increase was
due to relocation, consulting and other costs associated with the early-1996
Pipeline reorganization. The remainder of the increase is primarily due to
increased legal and regulatory cost related to current year rate proceedings.
Year-to-Date Comparison
Interstate Pipeline operating income, before the charge for early
retirement and severance as discussed preceding, increased by $17.6 million
(24.3%) from the first nine months of 1995 to the first nine months of 1996.
This improvement reflected a $16.2 million increase in transportation margins, a
$0.4 million increase in sales margins and a $1.0 million reduction in total
operating expenses, each as discussed following.
"Total gas sales revenue" increased from $70.6 million in the first
nine months of 1995 to $72.5 million in the corresponding period of 1996, an
increase of $1.9 million (2.7%). This net improvement was attributable to a
$20.9 million increase principally due to an increase in the average 1996 sale
price (principally due to an increase in the cost of purchased gas as discussed
following), partially offset by a $19.0 million decrease related to a 10.3
million MMBtu reduction in 1996 sales volumes. The reduction in sales volumes
was primarily due to a discontinuation of certain sales transactions to a
marketing affiliate. "Sales to Distribution" increased by $16.0 million (36.0%)
from the first nine months of 1995 to the first nine months of 1996, with
approximately $2.7 million of the increase due to higher sales volumes,
primarily due to increased Distribution demand resulting from colder
first-quarter 1996 weather. The remainder of the increase in 1996 "Sales to
Distribution" was primarily due to higher 1996 sales prices, primarily resulting
from increases in 1996 gas prices which tend to increase the commodity component
of the overall sales price as discussed preceding.
"Purchased gas cost" increased by $1.5 million (2.4%) from the first
nine months of 1995 to the first nine months of 1996. This increase was composed
of an $18.3 million increase attributable to an increase in the average cost of
purchased gas, partially offset by a $16.8 million decrease attributable to
reduced 1996 total sales volumes. The $18.3 million increase in the average cost
of purchased gas was primarily due to (1) the increased 1996 market price of gas
and (2) the inclusion in 1995 results of $5.0 million credit to purchased gas
cost related to a fixed price sales commitment and the resolution of certain
take-or-pay related issues.
"Total transportation revenue" increased by $16.2 million (9.1%) from
the first nine months of 1995 to the first nine months of 1996. This increase
was largely attributable to (1) the positive impact of NGT's recent rate case
which became effective in February 1995 (see "Regulatory Matters" elsewhere
herein) and (2) favorable market conditions resulting in increased price spreads
between Mid-Continent and Gulf Coast supplies which tend to ease competitive
pressures on transportation margins as discussed preceding. Transportation
volumes for 1996 increased by 7.9 million MMBtu (1.1%), although the increased
volumes tend to have a less than proportionate impact on transportation rates
due to the straight-fixed-variable rate design currently applicable to Pipeline
which ties a relatively small portion of the overall transportation rate to the
volume transported. During 1996, Pipeline continued to utilize the Company's
risk management program to mitigate the market risk associated with certain of
its transportation agreements which contain market-sensitive pricing provisions,
arising from movement in certain basis differentials, see "Regulatory Matters"
and "Wholesale Energy Marketing" elsewhere herein.
"Operations and maintenance expense" decreased by $4.9 million (11.3%)
from the first nine months of 1995 to the first nine months of 1996.
Approximately $2.1 million (42.9%) of this variance was associated with lower
transportation expense, primarily due to reductions in gas supply realignment
cost. Approximately $0.6 million (12.2%) of the variance was related to the
completion, in March 1996, of the amortization period for certain PCB
remediation cost as required by a previous rate proceeding. The remainder of the
reduction was attributable to cost savings associated with the early-1996
Pipeline reorganization, partially offset by a reduction in capitalized labor
cost associated with lower 1996 capital expenditures and a change in company
policy which has resulted in the use of contract personnel rather than company
personnel for many of its capital projects. "Depreciation and amortization" for
1996 decreased by $3.5 million (13.3%) primarily due to a July 1995 change in
the depreciation rates associated with certain Pipeline assets, see Note I of
the accompanying Notes to Consolidated Financial Statements. "Other operating
expenses" increased by $7.4 million (16.5%) from the first nine months of 1995
to the first nine months of 1996. Approximately $1.1 million (14.9%) of this
increase was due to increased taxes other than income, primarily due to higher
1996 property taxes. The remainder of the increase was due to several factors
including (1) increased consulting and relocation cost associated with the
reorganization as discussed preceding, (2) a non-recurring adjustment of $1.2
million recorded in the second quarter of 1995 which reduced medical expenses,
(3) increased legal and regulatory cost, primarily related to current year rate
proceedings and (4) a change in the method of recording payments to the Gas
Research Institute ("GRI"). During 1995, payments to GRI were recorded as a
"flow-through", with no effect on income or expense. During 1996, these payments
result in both expense and revenue in equal amounts. These negative variances
were partially offset by a reduction in 1996 general and administrative cost
associated with the Pipeline reorganization.
<PAGE>
WHOLESALE ENERGY MARKETING
The Company's marketing of natural gas and risk management services to
natural gas resellers and certain large volume industrial consumers is
principally conducted by NorAm Energy Services, Inc., together with certain
affiliates, collectively referred to herein as "NES" or "Wholesale Energy
Marketing". During the third quarter of 1996, NES acquired its import/export
license for the sale or purchase of electricity to or from Canada. Additionally,
NES added marketing staff to focus exclusively on natural gas and electric
transactions in Mexico as the Mexican government continues to evaluate
privatization initiatives. The nature of natural gas marketing is such that
contractual disputes arise, see "Contingencies" elsewhere herein.
<TABLE>
<CAPTION>
Quarter Ended Nine Months
September 30 Ended September 30
---------------------------------------------- ---------------------------------------------
FINANCIAL AND Increase Increase
OPERATING RESULTS 1996 1995 (Decrease) 1996 1995 (Decrease)
- -----------------
----------- ----------- --------------------- ------------ ----------- --------------------
(dollars in millions) ($/%) ($/%)
<S> <C> <C> <C> <C> <C> <C>
Natural gas sales
Unaffiliated sales $ 455.5 $ 184.1 $271.4 / 147.4% $1,258.1 $477.9 $780.2 / 163.3%
Sales to Distribution 12.0 12.4 (0.4) / (3.2)% 66.4 45.3 21.1 / 46.6%
Sales to Pipeline 0.5 14.5 (14.0) / (96.6)% 37.9 40.5 (2.6) / (6.4)%
Other affiliated sales 5.6 2.4 3.2 / 133.3% 14.5 14.0 0.5 / 3.6%
----------- ----------- ------------ -----------
Total gas sales revenue 473.6 213.4 260.2 / 121.9% 1,376.9 577.7 799.2 / 138.3%
Electricity sales 20.1 8.1 12.0 / 148.1% 30.8 9.9 20.9 / 211.1%
Other operating revenues - 0.5 (0.5) / (100.0)% - 0.8 (0.8) / (100.0)%
----------- ----------- ------------ -----------
Total operating revenues 493.7 222.0 271.7 / 122.4% 1,407.7 588.4 819.3 / 139.2%
Purchased gas costs
Unaffiliated 413.5 177.8 235.7 / 132.6% 1,242.7 487.2 755.5 / 155.1%
Affiliated 48.2 24.1 24.1 / 100.0% 78.2 50.4 27.8 / 55.2%
Transportation and storage
expense 8.6 11.1 (2.5) / (22.5)% 38.1 33.6 4.5 / 13.4%
Electricity purchases and
transmission costs 19.9 7.4 12.5 / 168.9% 29.8 9.2 20.6 / 223.9%
----------- ----------- ------------ -----------
Operating margin 3.5 1.6 1.9 / 118.8% 18.9 8.0 10.9 / 136.2%
General and administrative 4.1 2.3 1.8 / 78.3% 10.5 6.3 4.2 / 66.7%
----------- ----------- ------------ -----------
Operating income(loss) $ (0.6) $ (0.7) $0.1 / 14.3% $ 8.4 $ 1.7 $6.7 / 394.1%
=========== =========== ============ ===========
(Bcf/%) (Bcf/%)
Natural gas sales volume (Bcf) 225.3 162.6 62.7 / 38.6% 622.5 374.8 247.7 / 66.1%
($/Mcf/%) ($/Mcf/%)
Average sales margin ($/Mcf) $0.015 $0.002 $0.013 / 650.0% $0.029 $0.017 $0.012 / 70.6%
</TABLE>
Quarter Comparison
The operating loss for NES in the third quarter of 1996 was $(0.6)
million, an improvement of $0.1 million from the $(0.7) million operating loss
in the third quarter of 1995. This improvement reflected both increased
operating revenues and increased operating expenses as discussed following.
"Total gas sales revenues" increased from $213.4 million in the third
quarter of 1995 to $473.6 million in the third quarter of 1996, an increase of
$260.2 million (121.9%). Approximately $82.3 million (31.6%) of this increase
was attributable to increased sales volumes and approximately $177.9 million
(68.4%) was attributable to an increase in the average sales price. The increase
of 62.7 Bcf (38.6%) in 1996 sales volumes was principally due to the continuing
expansion of NES's marketing efforts. Utilizing an increased staff of marketers
and a network of regional sales offices, NES continues to step up its efforts to
become a nationwide marketing company with emphasis on increasing market share,
principally targeting end-use customers in the industrial, local gas
distribution, and electric generation sectors. The increase of approximately
$0.79 per Mcf (60.2%) in the average sales price of natural gas in the third
quarter of 1996 was principally due to a general increase in the market price of
natural gas, primarily due to adverse weather conditions in the Gulf of Mexico,
coupled with concerns regarding the relatively low level of natural gas in
storage inventories as the winter heating season approaches.
"Total purchased gas costs" were $461.7 million in the third quarter of
1996, an increase of $259.8 million (128.7%) from the corresponding quarter of
1995. This total increase was composed of (1) a $77.9 million increase
attributable to the increased 1996 sales volumes as discussed preceding and (2)
a $181.9 million increase attributable to a $0.807 per Mcf increase in the
average cost of purchased gas, reflecting the increased third-quarter 1996
market price of natural gas as discussed preceding. "Transportation and storage
expense" decreased from $11.1 million in the third quarter of 1995 to $8.6
million in the third quarter of 1996, a decrease of $2.5 million (22.5%),
principally due to (1) expanded use of capacity release transportation, (2)
decreased use of firm transportation and (3) natural gas sales entered into on a
delivered basis, each of which had the effect of lowering the storage and
transportation cost per unit of sales. "Electricity sales" and "Electricity
purchases and transmission costs" of $20.1 million and $19.9 million,
respectively, in the third quarter of 1996 represented significant increases
over the amounts for the corresponding quarter of 1995. These increases are
representative of the continuing efforts with regard to electric industry
deregulation which have given power marketers (such as NES) greater access to
electric markets, coupled with increased staffing and intensified marketing
efforts within NES.
The operating margin for the third quarter of 1996 was $3.5 million, an
increase of $1.9 million (118.8%) from the third quarter of 1995. The margin on
gas sales was $3.3 million, an increase of $2.9 million (725%) over the third
quarter of 1996. Of this total increase, $0.2 million (6.9%) was attributable to
the increased 1996 sales volume as discussed preceding and $2.7 million (93.1%)
was attributable to a $0.013 per Mcf increase in the 1996 average margin per
unit of sales, principally due to the enhanced marketing efforts, increase in
demand related to storage concerns and decreased 1996 per unit transportation
and storage costs, each as discussed preceding.
The increase of $1.8 million (78.3%) in "General and administrative"
from the third quarter of 1995 to the third quarter of 1996 was principally due
to increased 1996 costs associated with staffing increases made in support of
the increased sales and marketing efforts as described preceding.
Year-to-Date Comparison
Operating income for NES in the first nine months of 1996 was $8.4
million, an increase of $6.7 million from the $1.7 million earned in the first
nine months of 1995. This improvement reflected both increased operating
revenues and increased operating expenses as discussed following.
"Total gas sales revenues" increased from $577.7 million in the first
nine months of 1995 to $1,376.9 million in the first nine months of 1996, an
increase of $799.2 million (138.3%). Approximately $381.8 million (47.8%) of
this increase was attributable to increased sales volumes and approximately
$417.4 million (52.2%) was attributable to an increase in the average sales
price. The increase of 247.7 Bcf (66.1%) in 1996 sales volumes was principally
due to the continuing expansion of NES's marketing efforts as discussed
preceding. The increase of $0.671 per Mcf (43.5%) in the average sales price of
natural gas in the first nine months of 1996 was principally due to (1) a colder
than normal winter heating season, particularly in the Mid-Continent and
Northeast, which both increased demand for natural gas supplies for heating
season and caused above normal storage withdrawals in comparison to the
corresponding period of 1995, (2) adverse 1996 weather conditions in the Gulf of
Mexico and (3) concerns regarding the levels of gas in storage inventories as
the winter heating season approaches. The increase in demand, primarily in the
first six months of 1996 for the reasons discussed preceding, caused both an
increase in natural gas prices (a component of the overall sales rate) and a
divergence in pipeline differentials.
"Total purchased gas costs" were $1,320.9 million in the first nine
months of 1996, an increase of $783.3 million (145.7%) over the corresponding
period of 1995. This total increase was composed of (1) a $355.3 million
increase attributable to the increased 1996 sales volumes as discussed preceding
and (2) a $428.0 million increase attributable to a $0.688 per Mcf increase in
the average cost of purchased gas during 1996, reflecting the increased 1996
market price of natural gas as discussed preceding. "Transportation and storage
expense" increased from $33.6 million in the first nine months of 1995 to $38.1
million in the first nine months of 1996, an increase of $4.5 million (13.4%),
principally representing expenditures made in support of the increased 1996
sales volumes as discussed preceding, which more than offset a decrease in the
1996 transportation and storage expense per unit of sales, also as discussed
preceding. "Electricity sales" and "Electricity purchases and transmission
costs" of $30.8 million and $29.8 million, respectively, in the first nine
months of 1996 represented significant increases over the amounts for the
corresponding period of 1995. These increases are representative of the
continuing efforts with regard to electric industry deregulation which have
given power marketers greater access to the electric markets, coupled with
increased staffing and intensified marketing efforts within NES.
The operating margin for the first nine months of 1996 was $18.9
million, an increase of $10.9 million (136.2%) from the first nine months 1995.
The margin on gas sales was $17.9 million for the first nine months of 1996, an
increase of $11.4 million (175.4%) from the corresponding period of 1995. Of
this total increase, $4.3 million (37.7%) was attributable to the increased 1996
sales volume as discussed preceding and $7.1 million (62.3%) was attributable to
a $0.011 per Mcf increase in the 1996 average margin per unit of sales,
principally due to (1) enhanced marketing efforts, (2) increased demand and
divergence in basin differentials during 1996, (3) concerns regarding storage
withdrawal and injection levels during 1996 and (4) decreased 1996 per unit
transportation and storage costs, each as discussed preceding.
The increase of $4.2 million (66.7%) in "General and administrative"
from the first nine months of 1995 to the first nine months of 1996 was
principally due to increased 1996 costs associated with staffing increases made
in support of the increased sales and marketing efforts as described preceding.
As further discussed in the Company's 1995 Report on Form 10-K, the
Company's earnings from its gas supply, marketing, gathering and transportation
activities are subject to variability based on fluctuations in both the 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 this financial risk both for itself and for certain
customers who have requested the Company's assistance in managing similar
exposures, the Company, generally through NES, routinely enters into natural gas
swaps, futures contracts and options (collectively, "derivatives"). None of
these derivatives are held for speculative purposes and, in general, the
Company's risk management policy requires that these positions be offset by
positions in physical transactions or in other derivatives. In general,
therefore, gains and losses resulting from the Company's risk management
activities are offset by changes in value associated with the items being hedged
or are reimbursed by the customers who request this service.
<PAGE>
<TABLE>
<CAPTION>
Natural Gas Swaps (1)
(volumes in Bcf's, dollars in millions)
Volume
---------------------------------- Estimated
Fixed Price Fixed Price Mkt. Value
Payor Receiver Gain (Loss) (2)
--------------- --------------- ------------------
<S> <C> <C> <C>
September 30, 1996 147.4 90.4 5.3
December 31, 1995 235.7 214.3 (2.3)
September 30, 1995 117.7 103.9 (10.2)
</TABLE>
<TABLE>
<CAPTION>
Natural Gas Futures (3)
(volumes in Bcf's, dollars in millions)
Purchased Sold
---------------------------------- --------------------------------- Estimated
Notional Notional Mkt. Value
Volume Amount (4) Volume Amount (4) Gain(Loss) (2)
--------------- ---------------- -------------- --------------- -------------------
<S> <C> <C> <C> <C> <C>
September 30, 1996 28.7 64.6 35.4 79.6 (0.1)
December 31, 1995 15.1 29.6 8.2 18.9 3.3
September 30, 1995 26.6 48.3 16.9 30.2 (0.6)
</TABLE>
(1) The financial impact of these swaps was to increase(decrease) earnings
by $1.0 million, $1.1 million and $(5.9) million during 1995 and the
quarter and nine months ended September 30, 1996, respectively. For the
quarter and nine months ended September 30, 1995, the financial impact
was to increase earnings by $0.6 million and $1.3 million,
respectively.
(2) Represents the amount which would have been realized upon termination
of the relevant derivative as of the date indicated. As more fully
discussed in the Company's 1995 Annual Report on Form 10-K, in the case
of swaps associated with certain agreements pursuant to which the
Company has committed to supply gas to a distribution affiliate through
April 1999, no earnings impact is expected due to the existing
accruals. Swaps associated with these commitments and included in the
above totals had fair market values of $0.5 million, $(1.0) million and
$(9.2) million at September 30, 1996, December 31, 1995 and September
30, 1995, respectively.
(3) The financial impact of these futures was to increase(decrease)
earnings by $(4.1) million, $2.7 million and $(0.2) million during 1995
and the quarter and nine months ended September 30, 1996, respectively.
For the quarter and nine months ended September 30, 1995, the financial
impact was to decrease earnings by $(1.5) million and $(2.9) million,
respectively.
(4) The term "Notional Amount" refers to the contract unit price times the
contract volume and is intended to be indicative of the Company's level
of activity in these derivatives. In general, however, the amounts at
risk are significantly smaller because, as discussed preceding, changes
in the market value of these derivatives are offset by changes in the
value associated with the underlying physical transactions or in other
derivatives.
At September 30, 1996, the Company held options covering the purchase
of 20.6 Bcf of gas, principally in conjunction with the commitment to supply gas
to a distribution affiliate as discussed preceding. The majority of these
options, due to their nature and term, have no readily available market value
and the market value of the remainder is not material.
<PAGE>
NATURAL GAS GATHERING
The Company's natural gas gathering business, including related liquids
extraction and marketing activities, is conducted by NorAm Field Services Corp.
together with certain affiliates, collectively referred to herein as "NFS" or
"Natural Gas Gathering".
<TABLE>
<CAPTION>
Quarter Ended Nine Months
September 30 Ended September 30
--------------------------------------------- ------------------------------------------
FINANCIAL AND Increase Increase
OPERATING RESULTS 1996 1995 (Decrease) 1996 1995 (Decrease)
- -----------------
----------- ----------- ------------------- ----------- ----------- ------------------
(dollars in millions) ($/%) ($/%)
<S> <C> <C> <C> <C> <C> <C>
Gathering revenue $ 5.9 $ 7.3 $(1.4) / (19.2)% $ 18.4 $ 20.4 $(2.0) / (9.8)%
Natural gas sales 18.0 4.7 13.3 / 283.0% 46.0 14.6 31.4 / 215.1%
Products extraction 1.9 1.7 0.2 / 11.8% 6.1 6.3 (0.2) / (3.2)%
Other operating revenue 1.1 0.2 0.9 / 450.0% 2.5 0.8 1.7 / 212.5%
----------- ----------- ----------- -----------
Total operating revenues 26.9 13.9 13.0 / 93.5% 73.0 42.1 30.9 / 73.4%
----------- ----------- ----------- -----------
Gas purchased, net 18.2 5.2 13.0 / 250.0% 45.7 14.6 31.1 / 213.0%
Cost of sales 0.1 0.9 (0.8) / (88.9)% 2.4 3.3 (0.9) / (27.3)%
Operation and maintenance 3.1 3.1 - / - 9.1 9.7 (0.6) / (6.2)%
Administrative expense 1.3 1.1 0.2 / 18.2% 3.7 3.2 0.5 / 15.6%
Depreciation 0.5 0.5 - / - 1.6 3.6 (2.0) / (55.6)%
Taxes other than income 0.3 0.3 - / - 1.0 1.0 - / -
----------- ----------- ----------- -----------
Operating income $ 3.4 $ 2.8 $0.6 / 21.4% $ 9.5 $ 6.7 $2.8 / 41.8%
=========== =========== =========== ===========
(millions of (millions of
Total throughput (millions MMBtu/%) MMBtu/%)
of MMBtu) 58.0 56.8 1.2 / 2.1% 170.0 175.8 (5.8) / (3.3)%
Margin/unit of throughput ($/MMBtu/%) ($/MMBtu/%)
($/MMBtu) $0.148 $0.137 $0.011 / 8.0% $0.146 $0.138 $0.008 / 5.8%
Number of receipt points 3,127 2,972 155 / 5.2% 3,127 2,987 140 /4.7%
</TABLE>
Quarter Comparison
Operating income of $3.4 million for the third quarter of 1996
represented an increase of $0.6 million (21.4%) from the corresponding period in
1995. This increase in operating income was primarily due to an increase in the
margin from gathering, including low pressure services, and products extraction.
During the third quarter of 1996, NFS's throughput exceeded
third-quarter 1995 throughput by 1.2 million MMBtu (13,000 MMBtu/day). This
favorable volume variance was primarily due to new gas (from well connects)
being added over and above normal depletion declines, in addition to volumes
added from the transfer of certain MRT facilities, effective September 1, 1996.
The comparison of third-quarter 1996 gathering revenues to those of
third-quarter 1995 is affected by (1) the fact that balancing fees were rolled
into "Gathering revenue" in 1995 and recognized as part of "Other operating
revenue" in 1996 and (2) the inclusion, in third-quarter 1995, of an
approximately $0.8 million adjustment to gathering revenues to recognize other
balancing services, over and above normal balancing fees for the quarter. After
adjustment for these two items, gathering revenues for the third quarter of 1996
increased from the third quarter of 1995 by $0.5 million, while margins from
products extraction, including cost of sales, increased by $1.0 million,
primarily as the result of higher liquid prices. The net impact of these items
was an overall third-quarter 1996 margin increase of approximately $0.01/MMBtu.
Year-to-Date Comparison
Operating income for NFS in the first nine months of 1996 increased by
$2.8 million (41.8%) from the corresponding period of 1995. This increase in
operating income was largely due to a reduction in depreciation expense combined
with an increase in operating margins from gathering and products extraction,
each as discussed following.
Despite an overall decline in throughput, NFS's operating margin
increased by $0.7 million from the first nine months of 1995 to the first nine
months of 1996, primarily due to improved gathering and products extraction
activity. NFS has experienced producer shut-ins, well freeze-offs, curtailments
due to allowables and capacity constraints on downstream pipelines, as well as
normal depletion declines in deliverability. Nevertheless, NFS has been able to
offset this reduced throughput by an increase in the margin from gathering. In
addition, products extraction has shown improvement due to higher 1996 liquid
prices. These combined factors resulted in an increase in 1996 margin of
approximately $0.008/MMBtu (5.8%) when compared to the corresponding period of
1995.
NFS conducted a review of the gas reserves connected and proximate to
its facilities in July 1995 and as a result, the service life of certain of its
assets was extended. This change resulted in a $2.0 million decrease in 1996
depreciation expense when compared to the corresponding period in 1995.
In general, NFS's business continues to be susceptible to the rate of
producer drilling, curtailments, and shut-ins on its gathering systems. However,
NFS's marketing strategy of aggressively connecting wells and marketing new
services has allowed it to show overall improvement in a competitive market.
<PAGE>
RETAIL ENERGY MARKETING
The Company's marketing of natural gas and related services to certain
commercial and industrial customers, including those located behind the
"unbundled city gate" of local gas distribution companies, is principally
carried out by NorAm Energy Management and certain affiliated companies
(collectively, "NEM"). The nature of natural gas marketing activities is such
that contractual disputes arise, see "Contingencies" elsewhere herein. NEM's
results of operations as presented following also include the Company's home
care service activities, including (1) appliance sales and service, (2) home
security services and (3) resale of long distance telephone service, the latter
two of which businesses are essentially in a "start-up" mode.
<TABLE>
<CAPTION>
Quarter Ended Nine Months
September 30 Ended September 30
-------------------------------------------- ------------------------------------------
FINANCIAL AND Increase Increase
OPERATING RESULTS 1996 1995 (Decrease) 1996 1995 (Decrease)
- -----------------
----------- ----------- ------------------- ----------- ----------- ------------------
(dollars in millions) ($/%) ($/%)
<S> <C> <C> <C> <C> <C> <C>
Natural gas sales $114.5 $ 65.2 $49.3 / 75.6% $348.0 $213.4 $134.6 / 63.1%
Transportation 0.7 0.7 - / - 2.7 2.6 0.1 / 3.8%
Other, principally Home
Care Services 14.7 12.7 2.0 / 15.7% 38.5 33.1 5.4 / 16.3%
----------- ----------- ----------- -----------
Total operating revenues 129.9 78.6 51.3 / 65.3% 389.2 249.1 140.1 / 56.2%
----------- ----------- ----------- -----------
Purchased gas costs 107.0 59.4 47.6 / 80.1% 321.8 193.6 128.2 / 66.2%
Operations, maintenance, cost
of sales and other, principally
Home Care Services 13.1 11.9 1.2 / 10.1% 36.2 33.6 2.6 / 7.7%
General and administrative 1.6 0.8 0.8 / 100.0% 4.3 2.4 1.9 / 79.2%
Depreciation and amortization 0.5 0.5 - / - 1.4 1.5 (0.1) / (6.7)%
Taxes other than income 0.6 0.4 0.2 / 50.0% 1.4 1.1 0.3 / 27.3
----------- ----------- ----------- -----------
Operating income $ 7.1 $ 5.6 $1.5 / 26.8% $ 24.1 $ 16.9 $7.2 / 42.6%
=========== =========== =========== ===========
(Bcf/%) (Bcf/%)
Natural gas sales (Bcf) 50.0 39.9 10.1 / 25.3% 147.8 126.0 21.8 / 17.3%
Transportation volume (Bcf) 5.0 5.2 (0.2) / (3.8)% 19.7 18.5 1.2 / 6.5%
($/Mcf/%) ($/Mcf/%)
Average sales margin ($/Mcf) $0.150 $0.145 $0.005 / 3.4% $0.177 $0.157 $0.020 / 12.7%
</TABLE>
Quarter Comparison
Operating income for NEM increased from $5.6 million in the third
quarter of 1995 to $7.1 million in the third quarter of 1996, an increase of
$1.5 million (26.8%). Approximately $1.0 million of this increase was
attributable to improved results from Home Care Services, principally due to
increased margin from appliance sales and service. The balance of the increase
was attributable to natural gas marketing activities, reflecting both increased
operating revenues and increased operating expenses as discussed following.
Natural gas sales revenues increased from $65.2 million in the third
quarter of 1995 to $114.5 million in the third quarter of 1996, an increase of
$49.3 million (75.6%). Approximately $32.8 million (66.5%) of this increase was
attributable to an increase in the 1996 average sales price and approximately
$16.5 million (33.5%) of the increase was attributable to increased 1996 sales
volumes. The increase of approximately $0.66 per Mcf (40.5%) in the average
sales price during 1996 was principally due to (1) an increase of approximately
$0.65 per Mcf in the average cost of purchased gas in 1996 (a component of the
sales rate) and, to a lesser extent, (2) an increase in the 1996 average sales
margin as discussed following. The increase of 10.1 Bcf (25.3%) in third-quarter
1996 sales volumes was principally due to increased marketing efforts by an
expanded staff.
Purchased gas cost increased from $59.4 million in the third quarter of
1995 to $107.0 million in the third quarter of 1996, an increase of $47.6
million (80.1%). This increase was principally due to the increase in the 1996
average cost of gas and the increased sales volume as discussed preceding, which
were responsible for $32.6 million (68.4%) and $15.0 million (31.6%),
respectively, of the total increase.
The average sales margin increased from $0.145 per Mcf in the third
quarter of 1995 to $0.150 per Mcf in the third quarter of 1996, an increase of
$0.005 per Mcf (3.4%), principally due to opportunities created by increased
1996 market volatility.
The increase of $1.2 million (10.1%) in "Operating, maintenance, cost
of sales and other, principally Home Care Services" from the third quarter of
1995 to the third quarter of 1996 was principally due to increased costs of
appliance sales and various miscellaneous expenses not associated with Home Care
Services' activities. The increase of $0.8 million (100.0%) in "General and
administrative" was principally due to increased staffing costs incurred in
support of the increased sales as discussed preceding.
Year-to-Date Comparison
Operating income for NEM increased from $16.9 million in the first nine
months of 1995 to $24.1 million in the first nine months of 1996, an increase of
$7.2 million (42.6%). Approximately $3.2 million of this increase was
attributable to improved results from Home Care Services, principally due to
increased margin from appliance sales and service. The balance of the increase
was attributable to natural gas marketing activities, reflecting both increased
operating revenues and increased operating expenses as discussed following.
Natural gas sales revenues increased from $213.4 million in the first
nine months of 1995 to $348.0 million in the first nine months of 1996, an
increase of $134.6 million (63.1%). Approximately $97.7 million (72.6%) of this
increase was attributable to an increase in the 1996 average sales price and
approximately $36.9 million (27.4%) of the increase was attributable to
increased 1996 sales volumes. The increase of approximately $0.66 per Mcf
(39.0%) in the 1996 average sales price was principally due to (1) an increase
of approximately $0.64 per Mcf in the average cost of purchased gas in 1996 (a
component of the sales rate) and (2) an increase in the average sales margin as
discussed following. The increase of 21.8 Bcf (17.3%) in sales volumes during
the first nine months of 1996 was principally due to (1) increased marketing
efforts by an expanded staff and (2) weather-related increases in demand for
firm supplies of gas which created opportunities to serve customers outside
NEM's traditional service area who were unable to obtain supplies under their
usual arrangements.
Purchased gas cost increased from $193.6 million in the first nine
months of 1995 to $321.8 million in the corresponding period of 1996, an
increase of $128.2 million (66.2%). This increase was principally due to the
increase in the 1996 average cost of gas and the increased 1996 sales volume as
discussed preceding, which were responsible for $94.7 million (73.9%) and $33.5
million (26.1%), respectively, of the total increase.
The average sales margin increased from $0.157 per Mcf in the first
nine months of 1995 to $0.177 per Mcf in the first nine months of 1996, an
increase of $0.020 per Mcf (12.7%), principally due to the relatively colder
1996 weather and resulting decreased availability of pipeline capacity and firm
supplies of gas at various locations. This decreased availability of gas
resulted in the payment of significant premiums by certain customers in certain
circumstances in order to avoid interruption of supply.
The increase of $2.6 million (7.7%) in "Operating, maintenance, cost of
sales and other, principally Home Care Services" from the first nine months of
1995 to the first nine months of 1996 was principally due to increased appliance
service expenses for consulting fees and vehicle leases, together with various
miscellaneous expenses not associated with Home Care Services' activities. The
increase of $1.9 million (79.2%) in "General and administrative" was principally
due to increased staffing costs incurred in support of the increased sales as
discussed preceding.
<PAGE>
CORPORATE AND OTHER
Quarter Comparison
The $2.4 million increase in the operating loss for Corporate & Other
from $(2.9) million in the third quarter of 1995 to $(5.3) million in the third
quarter of 1996 was principally due to (1) an increase in 1996 general and
administrative expenses, principally due to business development activities, (2)
increased 1996 expenses for international activities and (3) 1996 operating
losses associated with the start-up of NorAm Damage Prevention.
Year-to-Date Comparison
The $10.4 million increase in the operating loss for Corporate & Other
from $(6.3) million in the first nine months of 1995 to $(16.7) million in the
first nine months of 1996 was principally due to (1) an increase in 1996 general
and administrative expenses, principally due to increased business development
activities and a decrease in the 1996 favorable consolidation adjustment related
to pension costs, (2) the 1995 operating income associated with a forward oil
sale agreement which terminated in mid-1995, (3) increased 1996 expenditures for
international activities and (4) 1996 expenditures associated with the start-up
of NorAm Damage Prevention. These unfavorable impacts were partially offset by a
decrease in 1996 depreciation expense, principally due to the 1995 transfer of
certain Corporate assets to Distribution.
NON-OPERATING INCOME AND EXPENSE
Net income(loss) for the quarter and nine months ended September 30,
1996 was $(7.7) million and $51.1 million, respectively, increases of
approximately $6.6 million (46.2%) and $20.5 million (67.0%), respectively, from
the corresponding periods of 1995 while, as discussed preceding, operating
income increased by $2.6 million (16.1%) and $26.8 million (15.0%) during the
same periods. The components of this decrease of $4.0 million and increase of
$6.3 million in net expense below the operating income line were as follows:
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
September 30 September 30
------------------------------------------- -------------------------------------------
Increase Increase
1996 1995 (Decrease) 1996 1995 (Decrease)
---------- ---------- -------------------- ---------- ---------- --------------------
(dollars in millions) ($/%) ($/%)
<S> <C> <C> <C> <C> <C> <C>
Interest expense, net $ 31.0 $ 41.4 $(10.4) / (25.1)% (1) $ 101.7 $ 118.2 $(16.5) / (14.0)% (1)
Dividend requirement on
preferred securities of
subsidiary trust (2) 2.7 - 2.7 / N/A 3.1 - 3.1 / N/A
Other, net 0.6 1.3 (0.7) / (53.8)% 6.4 5.7 0.7 / 12.3%
Provision for income
taxes(benefit) (7.5) (12.3) 4.8 / 39.0% (3) 38.3 23.5 14.8 / 63.0% (3)
Extraordinary losses(gains) (4) (0.4) - (0.4) / N/A 4.3 0.1 4.2 / N/M
========== ========== ========== ==========
$ 26.4 $ 30.4 $(4.0) / (13.2)% $ 153.8 $ 147.5 $6.3 / 4.3%
========== ========== ========== ==========
</TABLE>
(1) For the quarter ended September 30, approximately $8.6 million (82.7%)
of the favorable variance was due to a decrease in the average level of
debt and approximately $1.8 million (17.3%) was due to a decrease in
the average interest rate. For the nine months ended September 30,
approximately $11.8 million (71.1%) of the favorable variance was due
to a decrease in the average level of debt and approximately $4.8
million (28.9%) was due to a decrease in the average interest rate.
Both the reduced level of debt and the reduction in interest rates
during these periods were due, in part, to the Company's financing
activities designed to lower its overall cost of debt and increase its
financial flexibility. The Company has engaged in several financing
transactions during 1996 which will affect non-operating income and
expense in future periods, see "Net Cash Flows from Financing
Activities" elsewhere herein and the Company's 1995 Report on Form
10-K.
(2) See "Net Cash Flows from Financing Activities" elsewhere herein.
(3) For the quarter ended September 30, reflects an increase of $5.1
million attributable to an increase in pre-tax income, partially offset
by a decrease of $0.3 million attributable to an increase in the 1996
interim effective tax rate. For the nine months ended September 30,
reflects an increase of $17.2 million attributable to an increase in
pre-tax income, partially offset by a decrease of $2.4 million
attributable to a decrease of approximately 2.5% in the 1996 interim
effective tax rate. This decrease in the interim effective tax rate was
principally due to a 2.8% decrease in the state effective tax rate.
(4) See Note B of the accompanying Notes to Consolidated Financial
Statements.
<PAGE>
Liquidity and Capital Resources
The table below illustrates the sources of the Company's invested
capital during the last four years and at September 30, 1996 and 1995 (see also
"Receivable Sales Facility" elsewhere herein). The Company has engaged in
several significant financing transactions during 1996, see "Net Cash Flows from
Financing Activities" elsewhere herein.
<TABLE>
<CAPTION>
September 30 December 31,
------------------------- ----------------------------------------------------
INVESTED CAPITAL 1996 1995 1995 1994 1993 1992
- ----------------
------------ ------------ ----------- ------------ ------------ ------------
(millions of dollars)
<S> <C> <C> <C> <C> <C> <C>
Long-Term Debt $1,107.0 $1,474.9 $1,474.9 $1,414.4 $1,629.4 $1,783.1
Trust Preferred (1) 167.7 - - - - -
Common Equity (2) 771.5 605.2 637.3 587.4 578.0 582.9
Preferred Stock (3) - 130.0 130.0 130.0 130.0 130.0
------------ ------------ ----------- ------------ ------------ ------------
Total Capitalization 2,046.2 2,210.1 2,242.2 2,131.8 2,337.4 2,496.0
Short-Term Debt 284.0 269.8 128.8 274.6 192.4 120.0
------------ ------------ ----------- ------------ ------------ ------------
Total Invested Capital $2,330.2 $2,479.9 $2,371.0 $2,406.4 $2,529.8 $2,616.0
============ ============ =========== ============ ============ ============
Total Capitalization:
Long-Term Debt 54.1% 66.7% 65.8% 66.3% 69.7% 71.4%
Trust Preferred (1) 8.2% - - - - -
Common Equity 37.7% 27.4% 28.4% 27.6% 24.7% 23.4%
Preferred Stock - 5.9% 5.8% 6.1% 5.6% 5.2%
Total Invested Capital:
Senior Debt (4) 54.4% 70.4% 67.6% 70.2% 72.0% 72.7%
Total Debt:
W/O Receivables Sold (5) 59.7% 70.4% 67.6% 70.2% 72.0% 72.7%
With Receivables Sold (5) 63.4% 71.3% 70.6% 72.4% 74.3% 74.8%
</TABLE>
(1) Company-Obligated Mandatorily Redeemable Convertible Preferred
Securities of Subsidiary Trust Holding Solely $177.8 Million Principal
Amount of 6.25% Convertible Subordinated Debentures due 2026 of NorAm
Energy Corp., see "Net Cash Flows from Financing Activities" elsewhere
herein.
(2) Includes unrealized gains on its investment in Itron, Inc. ("Itron"),
net of tax of $8.1 million, $9.8 million, $15.3 million and $2.6
million at September 30, 1996 and 1995 and December 31, 1995 and 1994,
respectively. At November 11, 1996, the Company's investment in Itron
had declined to a market value of approximately $30.0 million,
representing an unrealized gain of approximately $2.2 million, net of
tax of approximately $1.2 million.
(3) Exchanged for convertible subordinated debentures in June 1996, see
"Net Cash Flows From Financing Activities" elsewhere herein.
(4) Excludes the $124.5 million of the Company's 6% Convertible
Subordinated Debentures due 2012 outstanding at September 30, 1996, see
"Net Cash Flows From Financing Activities" elsewhere herein.
(5) See "Receivable Sales Facility" under "Net Cash Flows From Operating
Activities" elsewhere herein.
CASH FLOW ANALYSIS
The Company's cash flows, like its results of operations, are seasonal
and, therefore, the cash flows experienced during an interim period are not
necessarily indicative of the results to be expected for an entire year. The
following discussion of cash flows should be read in conjunction with the
accompanying Statement of Consolidated Cash Flows and related supplemental cash
flow information, and with the cash flow information included in the Company's
1995 Report on Form 10-K.
<PAGE>
Net Cash Flows from Operating Activities
"Net cash provided by operating activities" as shown in the
accompanying Statement of Consolidated Cash Flows ("Cash Flow Statement")
increased from $138.7 million in the first nine months of 1995 to $194.9 million
in the first nine months of 1996. This increase of $56.2 million (40.5%) was
principally due to:
* An increase of $54.4 million in 1996 cash provided by the net of
accounts receivable and accounts payable. This net increase was
principally due to (1) $110.7 million of decreased 1996 cash outflows
associated with the Company's use of its receivable sales facility, see
"Receivable Sales Facility" following and (2) $55.2 million of
increased 1996 accounts receivable collections, principally due to the
relatively higher December 31, 1995 accounts receivable balance. These
favorable impacts were partially offset by $111.5 million of increased
1996 cash used for accounts payable, principally due to the relatively
larger December 31, 1995 balance in accounts payable.
* An increase of $27.3 million in 1996 cash provided by recovery of
deferred gas costs, principally due to the relatively higher December
31, 1995 balance in deferred gas costs.
* An increase of $37.0 million in 1996 income before depreciation and
amortization, deferred income taxes, extraordinary items and other
non-cash charges and credits, see "Material Changes in the Results of
Operations" elsewhere herein.
These favorable impacts were partially offset by:
* Increases totaling $49.1 million in 1996 cash used for certain
miscellaneous working capital items, principally due to $49.9 million
of decreased 1996 cash provided from inventories. This decrease was
principally due to the relatively lower December 31, 1995 balance of
gas in underground storage due to the late-1995 storage withdrawals due
to colder weather.
* A decrease of $13.4 million in 1996 cash recoveries under gas contract
disputes as the underlying agreements continue to "unwind".
As further described in the Company's 1995 Report on Form 10-K, under
an August 1995 agreement, the Company sells an undivided interest (currently
limited to a maximum of $235 million) in a designated pool of accounts
receivable with limited recourse and subject to a floating interest rate
provision. Following is selected information concerning the utilization of this
facility.
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
Receivable Sales Facility September 30 September 30
- ---------------------------------------- ------------------------------ ------------------------------------
(dollars in millions) 1996 1995 1996 1995
------------- ------------- ----------------- ---------------
<S> <C> <C> <C> <C>
Net cash inflows(outflows) $ 96.9 $ (69.8) $ - $ (110.7)
Pre-tax loss on sale (2.2) (2.1) (7.0) (7.2)
Average receivables sold (1) $ 200.3 $ 90.1 $ 172.0 $ 128.4
Weighted average rate (2) 5.33% 6.02% 5.42% 6.07%
September 30
------------------------------ December 31
1996 1995 1995
------------- ------------- -----------------
(millions of dollars)
Receivables sold and uncollected $ 235.0 $ 82.1 $ 235.0
Collateral for receivables sold $ 30.0 $ 18.7 $ 35.0
</TABLE>
(1) Based on daily balances.
(2) Exclusive of a facility fee payable on the full commitment of $235
million, which fee was 60 basis points through August 21, 1995,
declined to 40 basis points through March 1, 1996 and currently is 30
basis points. The rate in effect at September 30, 1996 (exclusive of
the facility fee) was 5.36%.
<PAGE>
Net Cash Flows from Investing Activities
The Company's capital expenditures by business unit for the nine months
ended September 30, 1996 and 1995 were as follows:
<TABLE>
<CAPTION>
Nine Months Ended
September 30
----------------------------------------------
Increase
1996 1995 (Decrease)
----------- ----------- ---------------------
(millions of dollars) ($/%)
<S> <C> <C> <C>
Natural Gas Distribution $ 78.7 $ 89.6 $(10.9) / (12.2)%
Interstate Pipelines 26.1 25.7 0.4 / 1.6%
Wholesale Energy Marketing - - - / -
Natural Gas Gathering 6.1 2.3 3.8 / 165.2%
Retail Energy Marketing 1.6 0.1 1.5 / N/M
Corporate and Other 3.7 0.3 3.4 / N/M
=========== ===========
$ 116.2 $ 118.0 $(1.8) / (1.5)%
=========== ===========
</TABLE>
Capital expenditures decreased from $118.0 million in the first nine
months of 1995 to $116.2 million in the first nine months of 1996, a decrease of
$1.8 million (1.5%), as a decrease in spending by Distribution was partially
offset by increased spending in Natural Gas Gathering and Corporate and Other.
The decrease from 1995 to 1996 in Distribution spending was principally due to
(1) decreased 1996 expenditures at Minnegasco for distribution mains, reflecting
(i) the late construction start due to cold weather and (ii) higher system
expansion costs in 1995, (2) decreased 1996 capital spending at Entex for meters
and regulators and system replacements, and (3) decreased 1996 capital spending
at Arkla for system extensions and replacements. The increased 1996 spending in
Natural Gas Gathering was principally due to the purchase of field compression
equipment which formerly had been leased. The increased 1996 spending for
Corporate and Other was principally due to 1996 expenditures for Corporate
aircraft and leasehold improvements. The Company's capital expenditures for the
full year 1996 are currently budgeted at approximately $184.3 million, exclusive
of expenditures for international projects (which are expected to average
approximately $25 million per year for the next 3-5 years). The Company expects
that its capital spending needs will be met with cash provided by operations
and, if necessary, by incremental borrowing.
During the first quarter of 1995, the Company sold 80,000 shares of the
Common Stock of Itron, Inc., yielding cash proceeds of approximately $1.4
million. As further discussed in the Company's 1995 Report on Form 10-K, the
Company currently owns approximately 1.5 million of such shares, see "INVESTED
CAPITAL" elsewhere herein.
<PAGE>
Net Cash Flows from Financing Activities
As further discussed in the Company's 1995 Report on Form 10-K, the
Company's principal sources of short-term liquidity are (1) its December 1995
unsecured Credit Agreement (the "Facility") with Citibank, N.A., as Agent and a
group of eighteen other commercial banks which provides a $400 million
commitment to the Company through December 11, 1998, (2) the Company's
receivable sales program, see "Net Cash Flows from Operating Activities"
elsewhere herein and, to a lesser extent, (3) informal bank lines of credit.
Following is selected information concerning the Company's short-term
borrowings.
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
Short-Term Borrowings September 30 September 30
- ---------------------
------------------------------- -----------------------------------
1996 1995 1996 1995
-------------- -------------- ---------------- --------------
(dollars in millions)
<S> <C> <C> <C> <C>
Weighted average amount borrowed (1) $ 9.3 $ 43.3 $ 9.8 $ 52.7
Maximum amount borrowed (1) $ 58.0 $ 130.0 $ 58.0 $ 135.0
Weighted average rate (1) 5.61% 6.95% 6.05% 6.84%
</TABLE>
<TABLE>
<CAPTION>
September 30
------------------------------- December 31
1996 1995 1995
-------------- -------------- ----------------
(dollars in millions)
<S> <C> <C> <C>
Amount Borrowed: (2)
The Facility $ 40.0 $ 0.0 $ 0.0
Informal lines of credit $ 18.0 $ 0.0 $ 10.0
Weighted average rate 5.73% N/A 6.68%
</TABLE>
(1) As applicable, includes both the Facility and informal credit lines.
Weighted average amount borrowed and maximum amount borrowed are based on
week-end balances.
(2) The Company had $50 million in borrowings under the Facility at October 31,
1996, and therefore had $350 million of remaining capacity under the
Facility, which amount is expected to be adequate for the Company's current
and projected needs for short-term financing.
As further discussed in the Company's 1995 Report on Form 10-K, the
Company's long-term financing historically has been obtained through the
issuance of common stock, preferred stock and unsecured debentures and notes
(the Company is precluded under an indenture from issuing mortgage debt).
Following is a discussion of significant financing activities during 1996:
Common Stock Offering
In June 1996, the Company issued 11,500,000 shares of NorAm Energy
Corp. Common Stock (the "Common Stock") to the public at a price of $9.875 per
share, yielding net cash proceeds of approximately $109.0 million after
deducting an underwriting discount of 4.05% and before deducting expenses of
approximately $0.1 million. The net proceeds from the offering principally were
used to retire debt as described following.
Trust Preferred Offering
In June 1996, the Company issued $177.8 million of 6.25%
Convertible Subordinated Debentures due 2026 (unless extended by the Company as
discussed following) (the "Trust Debentures") to NorAm Financing I (the
"Trust"), a statutory business trust under Delaware law, wholly owned by the
Company. The Trust Debentures were purchased by the Trust using the proceeds
from (1) the public issuance by the Trust of 3,450,000 shares of 6.25%
Convertible Preferred Securities (the "Trust Preferred") at $50 per share, a
total of $172.5 million and (2) the sale of approximately $5.3 million of the
Trust's common stock (106,720 shares, representing 100% of the Trust's common
equity) to the Company. The sole assets of the Trust are and will be the Trust
Debentures. The interest and other payment dates on the Trust Debentures
correspond to the interest and other payment dates on the Trust Preferred. In
conjunction with the issuance of the Trust Preferred, the Company paid an
underwriting commission of $1.375 per share and expenses of approximately $0.1
million in view of the fact that the proceeds from such issuance would be
invested in the Trust Debentures. The net proceeds from these transactions
principally were used to retire debt as described following.
The Trust Preferred, as more fully described in the offering
documents, accrues a dividend equal to 6.25% of the $50 liquidation amount,
payable quarterly in arrears. The ability of the Trust to pay distributions on
the Trust Preferred is solely dependent on its receipt of interest payments on
the Trust Debentures. The Company has guaranteed, on a subordinated basis,
distributions and other payments due on the Trust Preferred (the "Guarantee").
The Guarantee, when taken together with the Company's obligations under the
Trust Debentures and in the indenture pursuant to which the Trust Debentures
were issued and the Company's obligations under the Amended and Restated
Declaration of Trust governing the Trust, provides a full and unconditional
guarantee of amounts due on the Trust Preferred. The Company has the right to
defer interest payments on the Trust Debentures as discussed following. In the
case of such deferral, quarterly distributions on the Trust Preferred would be
deferred by the Trust but would continue to accumulate quarterly and would
accrue interest. Each share of Trust Preferred is convertible at the option of
the holder into shares of Common Stock at an initial conversion rate of 4.1237
shares of Common Stock for each share of the Trust Preferred, subject to
adjustment in certain circumstances. The Trust Preferred does not have a stated
maturity date, although it is subject to mandatory redemption upon maturity of
the Trust Debentures or to the extent that the Trust Debentures are redeemed.
The redemption price in either such case will be $50 per share plus accrued and
unpaid distributions to the date fixed for redemption. In general, holders of
the Trust Preferred do not have any voting rights.
The Trust Debentures, as more fully described in the offering
documents, bear interest at 6.25% and are redeemable for cash at the option of
the Company, in whole or in part, from time to time on or after June 30, 2000,
if and only if for 20 trading days within any period of 30 consecutive days,
including the last trading day of such period, the current market price of the
Common Stock equals or exceeds 125% of the then-applicable conversion price of
the Trust Debentures, or at any time in certain circumstances upon the
occurrence of a specified tax event. The Trust Debentures will mature on June
30, 2026, although the maturity date may be extended only once at the Company's
election for up to an additional 19 years, provided certain requirements and
conditions are met. Under existing law, interest payments made by the Company
for the Trust Debentures are deductible for federal income tax purposes. The
Company has the right at any time and from time to time to defer interest
payments on the Trust Debentures for successive periods not to exceed 20
consecutive quarters for each such extension period. In such case, (1) quarterly
distributions on the Trust Preferred would also be deferred as discussed
preceding and (2) the Company has agreed not to declare or pay any dividend on
any common or preferred stock, except in certain instances.
The Trust is consolidated with the Company for financial reporting
purposes and, therefore, the Trust Debentures are eliminated in consolidation
and the Trust Preferred appears on the Company's Consolidated Balance Sheet
under the caption "Company-Obligated Mandatorily Redeemable Convertible
Preferred Securities of Subsidiary Trust Holding Solely $177.8 Million Principal
Amount of 6.25% Convertible Subordinated Debentures due 2026 of NorAm Energy
Corp.". The dividend on the Trust Preferred is reported on a pre-tax basis in
the accompanying Statement of Consolidated Income under the caption "Dividend
requirement on preferred securities of subsidiary trust".
Debt Retirements and Reacquisitions
Utilizing, in large part, the proceeds from the offerings discussed
preceding, in June 1996, the Company (1) retired the $109.1 million principal
amount then outstanding of its 9.875% Debentures due 2018 at a price equal to
105.93% of face value, recognizing an extraordinary pre-tax loss of
approximately $6.5 million (approximately $3.9 million or $0.03 per share
after-tax) and (2) retired its $150 million bank term loan due 2000 at face
value. The Company also made certain other debt reacquisitions and scheduled
debt retirements, see Note B of the accompanying Notes to Consolidated Financial
Statements.
Exchange of Preferred Stock, Series A
Also in June 1996, the Company exercised its right to exchange the $130
million principal amount of its $3.00 Preferred Stock Series A (the "Preferred")
for its 6% Convertible Subordinated Debentures due 2012 (the "Subordinated
Debentures"). The holders of the Subordinated Debentures will receive interest
quarterly at 6% and have the right at any time on or before the maturity date
thereof to convert the Subordinated Debentures into Common Stock, initially at
the conversion rate in effect for the Preferred at the date of the exchange,
which conversion rate of approximately 1.7467 shares of the Common Stock for
each $50 principal amount of the Subordinated Debentures is subject to
adjustment should certain events occur. The Company is required to make annual
sinking fund payments of $6.5 million on the Subordinated Debentures beginning
on March 15, 1997 and on each succeeding March 15 to and including March 15,
2011. The Company (1) may credit against the sinking fund requirements (i) any
Subordinated Debentures redeemed by the Company and (ii) Subordinated Debentures
which have been converted at the option of the holder and (2) may deliver
outstanding Subordinated Debentures in satisfaction of the sinking fund
requirements.
As more fully discussed in the Company's 1995 Report on Form 10-K, the
Company enters into interest rate swaps in which, in general, one party pays a
fixed rate on the notional amount while the other party pays a LIBOR-based rate
for the purposes of (1) effectively fixing the interest rate on debt expected to
be issued for refunding purposes and (2) adjusting the amount of its overall
debt portfolio which is exposed to market interest rate fluctuations. The effect
of these swaps (none of which are leveraged) was to increase the Company's
interest expense by $0.1 million and $0.5 million for the quarters ended
September 30, 1996 and 1995, respectively, and to decrease the Company's
interest expense by $1.3 million for the nine months ended September 30, 1996.
The impact of these swaps on interest expense for the nine months ended
September 30, 1995 was not material. Following is selected information on the
Company's portfolio of interest rate swaps at September 30, 1996:
<PAGE>
<TABLE>
<CAPTION>
Interest Rate Swap Portfolio at September 30, 1996(1)
- -------------------------------------------------------------------
(dollars in millions) Estimated
Notional Period Interest Rate Market
Initiated Amount Covered Fixed/Floating(2) Value(3)
- ----------------------- ------------ ------------------------- --------------------- -------------
<S> <C> <C> <C> <C>
December 1995 $ 50.0 Apr.1997 - Apr.2002 (4) 5.92% / 6.88% $ 1.9
December 1995 50.0 Apr.1997 - Apr.2002 (4) 5.92% / 6.88% 1.9
January 1996 50.0 Apr.1997 - Apr.2002 (4) 5.80% / 6.88% 2.2
February 1996 50.0 Apr.1997 - Apr.2002 (4) 5.77% / 6.88% 2.3
February 1996 50.0 Mar.1996 - Jan.1998 (5) 4.76% / 5.90% 0.7
February 1996 50.0 Jun.1996 - Dec.1997 (5) 4.71% / 5.91% 0.7
------------ -------------
Totals $ 300.0 $ 9.7
============ =============
</TABLE>
(1) In addition to the swaps entered into during 1996, the Company's portfolio
of interest rate swaps as of December 31, 1995 also changed due to the
termination of $250.0 million notional amount of swaps during the first
quarter of 1996 (no material gain or loss was recognized).
(2) In each case, the Company is the fixed-price payor. The floating rate is
estimated as of September 30, 1996.
(3) Represents the estimated amount which would have been realized upon
termination of the swap at September 30, 1996.
(4) Swaps entered into for the purpose of effectively fixing the interest rate
on debt expected to be issued in 1997 for refunding purposes.
(5) Swaps entered into for the purpose of reducing the Company's exposure to
fluctuations in market interest rates.
The Company received cash proceeds from sales of its common stock
pursuant to its Direct Stock Purchase Plan of approximately $7.6 million and
$7.7 million during the nine months ended September 30, 1996 and 1995,
respectively. The Company (1) paid common and preferred dividends totaling
approximately $30.9 million and $31.8 million during the nine months ended
September 30, 1996 and 1995, respectively, (2) recently declared its regular
quarterly common dividend and (3) during June 1996, exchanged its Preferred
Stock, Series A for convertible subordinated debentures, see "Dividend
Declaration" under "Recent Developments" elsewhere herein and "Exchange of
Preferred Stock, Series A" preceding.
As further discussed in the Company's 1995 Report on Form 10-K, the
Facility contains a provision which requires the Company to maintain a minimum
level of total stockholders' equity, as well as placing a limitation of (1)
$2,055 million on total debt and (2) $200 million on the amount of outstanding
long-term debt which may be retired in advance of its maturity using funds
borrowed under the Facility. Certain of the Company's other financial
arrangements contain similar provisions. Based on these restrictions, at
September 30, 1996, the Company had incremental debt capacity of $619.1 million
and, while the Company is not required to calculate and apply the stockholders'
equity limitation on an interim basis, if it were applied at September 30, 1996,
the Company would have had incremental dividend capacity of $212.6 million. The
Company has engaged in several transactions which affect these calculations, see
"Common Stock Offering", "Trust Preferred Offering", "Debt Retirements and
Reacquisitions" and "Exchange of Preferred Stock, Series A" preceding.
<PAGE>
The accompanying Cash Flow Statement has been prepared in accordance
with authoritative accounting guidelines which require the segregation of cash
flows into specific categories. Management believes that other groupings of cash
flows may also be useful and that the following information (which amounts are
consistent with the Cash Flow Statement) will assist in understanding the
Company's sources and uses of cash during the periods presented. This
information should not be viewed as a substitute for the Cash Flow Statement,
nor should the totals or subtotals presented be considered surrogates for totals
or subtotals appearing on the Cash Flow Statement.
<TABLE>
<CAPTION>
Nine Months Ended
September 30
--------------------------
1996 1995
------------ ------------
<S> <C> <C>
Use (Source) (millions of dollars)
Recoveries under gas contract
settlements $ (8.8) $ (22.2)
Capital expenditures 116.2 118.0
Common and preferred dividends 30.9 31.8
Debt retirements and reacquisitions (1) 395.0 34.4
Other interim debt repayments(borrowings) (48.0) 110.0
Change in receivables sold 0.0 110.7
Return of advance received under
contingent sales agreement - 50.0
Decrease in overdrafts 1.5 15.1
------------ ------------
Selected External Uses of Cash 486.8 447.8
Less:
Sale of Itron stock - (1.4)
Common stock issuance (2) (116.5) (7.7)
Issuance of Trust Preferred (2) (167.7) -
Issuance of debt - (200.0)
Change in cash balance 1.0 (10.3)
------------ ------------
Cash Generated from Other Sources,
Principally Internal $ 203.6 $ 228.4
</TABLE>
============ ============
(1) See Note B of the accompanying Notes to Consolidated Financial Statements.
(2) See "Net Cash Flows from Financing Activities" elsewhere herein.
COMMITMENTS
Capital Expenditures. The Company had capital commitments of less than
$30 million at September 30, 1996, which projects are expected to be funded
through cash provided by operations and/or incremental borrowings, see "Net Cash
Flows from Investing Activities" elsewhere herein. As described in the Company's
1995 Report on Form 10-K, the Company has commitments under certain of its
leasing arrangements.
Transportation Agreement. As further discussed in the Company's 1995
Report on Form 10-K, the Company has an agreement with ANR Pipeline Company
("ANR") pursuant to which the Company (1) currently retains $41 million
previously advanced by ANR, (2) provides 130 MMcf/day of capacity in certain of
the Company's transportation facilities to ANR and (3) is committed to refund $5
million and $36 million to ANR in 2003 and 2005, respectively, in exchange for
ANR's release of 30 MMcf/day and 100 MMcf/day, respectively, of such capacity.
CONTINGENCIES
Letters of Credit. At September 30, 1996, the Company was obligated for
approximately $22.0 million under letters of credit which are incidental to its
ordinary business operations.
Indemnity Provisions. As discussed in the Company's 1995 Report on Form
10-K, the Company has obligations under the indemnification provisions of
certain sale agreements.
Sale of Receivables. Certain of the Company's receivables are
collateral for receivables which have been sold, see "Net Cash Flows from
Operating Activities" elsewhere herein.
Gas Contract Issues. As discussed in the Company's 1995 Report on Form
10-K, the Company is a party to certain claims involving, and has certain
commitments under, its gas purchase contracts. The nature of the Company's
natural gas marketing business is such that, in general, and particularly during
periods of production interruptions, delivery curtailments and shortages of
pipeline capacity, disputes arise as to compliance with terms of
purchase/delivery commitments and related pricing provisions. While certain of
these disputes are not resolved for extended periods of time, the Company
believes that it has adequately reserved for any such amounts in dispute which
may ultimately not be resolved in its favor.
Credit Risk and Off-Balance-Sheet Risk. As discussed in the Company's
1995 Report on Form 10-K, the Company has off-balance-sheet risk as a result of
(1) its interest rate swaps, see "Net Cash Flows from Financing Activities"
elsewhere herein and (2) its natural gas hedging activities, see "Wholesale
Energy Marketing" under "Material Changes in the Results of Operations"
elsewhere herein.
Litigation. The Company is a party to litigation which arises in the normal
course of business, see "Legal Proceedings" elsewhere herein.
Environmental. As more fully described in the Company's 1995 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, 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 improperly disposed of. 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. To the extent that
such potential costs are 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 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 "Legal Proceedings" elsewhere herein.
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 "Legal
Proceedings" elsewhere herein.
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>
Part II. Other Information
Item 1. 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 merger or to rescind the merger and/or to
recover damages in the event that the Houston Industries merger 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.
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.
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.
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.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
EX-27, Financial Data Schedule
(b) Reports on Form 8-K
Current Report on Form 8-K dated August 11, 1996
announcing the approval by the Company's Board of Directors of
an Agreement and Plan of Merger ("the Merger Agreement") with
Houston Industries Incorporated ("HI"), Houston Lighting and
Power Company ("HL&P") and HI Merger, Inc. Pursuant to the
Merger Agreement, the Company would merge into HI Merger, Inc.
which would be renamed "NorAm Energy Corp." and would be a
wholly-owned subsidiary of the entity which would result from
the merger of HI and HL&P.
<PAGE>
SIGNATURES
Pursuant to the requirements of the
Securities Exchange Act of 1934, the
Registrant has duly caused this report to be
signed on its behalf by the undersigned
thereunto duly authorized.
NorAm Energy Corp.
(Registrant)
By: Jack W. Ellis II
Jack W. Ellis II
Vice President & Controller
Dated: November 14, 1996
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,421,886
<OTHER-PROPERTY-AND-INVEST> 652,456
<TOTAL-CURRENT-ASSETS> 343,492
<TOTAL-DEFERRED-CHARGES> 55,913
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 3,473,747
<COMMON> 85,763
<CAPITAL-SURPLUS-PAID-IN> 994,396
<RETAINED-EARNINGS> (316,784)
<TOTAL-COMMON-STOCKHOLDERS-EQ> 771,512
0
0
<LONG-TERM-DEBT-NET> 1,106,969
<SHORT-TERM-NOTES> 58,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 225,964
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,311,302
<TOT-CAPITALIZATION-AND-LIAB> 3,473,747
<GROSS-OPERATING-REVENUE> 3,208,271
<INCOME-TAX-EXPENSE> 38,339
<OTHER-OPERATING-EXPENSES> 0
<TOTAL-OPERATING-EXPENSES> 3,003,382
<OPERATING-INCOME-LOSS> 204,889
<OTHER-INCOME-NET> (9,518)
<INCOME-BEFORE-INTEREST-EXPEN> 195,371
<TOTAL-INTEREST-EXPENSE> 101,683
<NET-INCOME> 51,093
3,597
<EARNINGS-AVAILABLE-FOR-COMM> 47,496
<COMMON-STOCK-DIVIDENDS> 27,037
<TOTAL-INTEREST-ON-BONDS> 27,624
<CASH-FLOW-OPERATIONS> 194,905
<EPS-PRIMARY> 0.37
<EPS-DILUTED> 0.35
</TABLE>
