<PAGE>
SCHEDULE 14A INFORMATION
Proxy Statement Pursuant to Section 14(a) of the Securities
Exchange Act of 1934
Filed by the Registrant [X]
Filed by a Party other than the Registrant [_]
Check the appropriate box:
[_] Preliminary Proxy Statement [_] Confidential, for Use of the
Commission Only (as permitted by
Rule 14a-6(e)(2))
[X] Definitive Proxy Statement
[_] Definitive Additional Materials
[_] Soliciting Material Pursuant to Section 240.14a-11(c) or Section 240.14a-12
Houston Industries Incorporated
- --------------------------------------------------------------------------------
(Name of Registrant as Specified In Its Charter)
- --------------------------------------------------------------------------------
(Name of Person(s) Filing Proxy Statement, if other than the Registrant)
Payment of Filing Fee (Check the appropriate box):
[X] No fee required.
[_] Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11.
(1) Title of each class of securities to which transaction applies:
-------------------------------------------------------------------------
(2) Aggregate number of securities to which transaction applies:
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(3) Per unit price or other underlying value of transaction computed
pursuant to Exchange Act Rule 0-11 (Set forth the amount on which
the filing fee is calculated and state how it was determined):
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(5) Total fee paid:
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[_] Fee paid previously with preliminary materials.
[_] Check box if any part of the fee is offset as provided by Exchange
Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee
was paid previously. Identify the previous filing by registration statement
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(1) Amount Previously Paid:
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<PAGE>
LOGO
[LOGO OF HOUSTON INDUSTRIES APPEARS HERE]
NOTICE OF ANNUAL MEETING OF SHAREHOLDERS
TO BE HELD ON MAY 6, 1998
AND PROXY STATEMENT
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Notice of Annual Meeting
Proxy Statement
Voting of Shares........................................................ 1
Election of Directors................................................... 2
Nominees................................................................ 2
Continuing Directors.................................................... 3
Organization of the Board of Directors.................................. 4
Compensation of Directors............................................... 5
Securities Ownership of Certain Beneficial Owners....................... 6
Securities Ownership of Management...................................... 7
Executive Compensation.................................................. 8
Retirement Plans, Related Benefits and Other Agreements................. 11
Report of the Compensation Committee on Executive Compensation.......... 15
Shareholder Return Performance Graph.................................... 19
Proposal to Amend the Company's 1994 Long-Term Incentive Compensation
Plan................................................................... 20
Ratification of Appointment of Independent Accountants and Auditors..... 25
Other Matters........................................................... 25
Shareholder Proposals for 1999 Annual Meeting of Shareholders........... 25
Director Nominations for 1999 Annual Meeting of Shareholders............ 25
Annual Report to Shareholders........................................... 26
Exhibit A--Amendment to the 1994 Houston Industries Incorporated Long-Term
Incentive
Compensation Plan........................................................ A-1
</TABLE>
Appendix A--1997 Financial Statements
<PAGE>
LOGO
Houston Industries Incorporated
1111 Louisiana, Houston, Texas 77002
NOTICE OF ANNUAL MEETING OF SHAREHOLDERS
TO BE HELD ON MAY 6, 1998
AND PROXY STATEMENT
To the Shareholders:
The Annual Meeting of Shareholders of Houston Industries Incorporated will
be held in the AUDITORIUM OF HOUSTON INDUSTRIES PLAZA, 1111 LOUISIANA,
HOUSTON, TEXAS, at 9:00 a.m., Central Daylight Time, on Wednesday, May 6,
1998, for the following purposes:
1. To elect directors to hold office in accordance with the Amended and
Restated Bylaws of the Company;
2. To consider and vote on a proposal to amend the 1994 Houston
Industries Incorporated Long-Term Incentive Compensation Plan to increase
the number of shares of Common Stock subject to the Plan by ten million and
to increase the limitation on grants of stock options to any one individual
during any calendar year;
3. To ratify the appointment of Deloitte & Touche LLP as independent
accountants and auditors for the Company for 1998; and
4. To transact such other business that may properly come before the
meeting or any adjournment or postponement thereof.
Only shareholders of record at the close of business on March 9, 1998 are
entitled to notice of, and to vote at, the meeting.
All shareholders are cordially invited and urged to attend the meeting. EVEN
IF YOU PLAN TO ATTEND THE MEETING, YOU ARE STILL REQUESTED TO SIGN, DATE AND
RETURN THE ACCOMPANYING PROXY IN THE ENCLOSED ADDRESSED ENVELOPE. If you
attend, you may vote in person if you wish, even though you have sent in your
proxy.
By order of the Board of Directors,
LOGO
/s/ Hugh Rice Kelly
Hugh Rice Kelly
Executive Vice President,
General Counsel and
Corporate Secretary
March 27, 1998
<PAGE>
HOUSTON INDUSTRIES INCORPORATED
1111 LOUISIANA, HOUSTON, TEXAS 77002
(713) 207-3000
PROXY STATEMENT
On or about March 27, 1998, Houston Industries Incorporated (Company) began
mailing this proxy statement and the accompanying proxy card to shareholders
entitled to vote at the Company's annual meeting of shareholders to be held on
May 6, 1998 (Annual Meeting). The proxy statement and proxy card are being
furnished in connection with the solicitation of proxies by the Company's
Board of Directors for the Annual Meeting.
The Company bears the expense of this solicitation. The Company has engaged
Morrow & Co. to assist in the solicitation of proxies at a fee of
approximately $9,500, plus expenses. The Company will also reimburse brokerage
firms, nominees, fiduciaries, custodians and other agents for their expenses
in distributing proxy material to the beneficial owners of the Company's
common stock, without par value (Common Stock), in accordance with Securities
and Exchange Commission (SEC) and New York Stock Exchange requirements. In
addition, certain of the Company's directors, officers and employees may
solicit proxies by telephone and personal contact.
VOTING OF SHARES
As of March 9, 1998, the record date fixed by the Board of Directors for the
determination of shareholders entitled to vote at the Annual Meeting, the
Company had outstanding 295,698,424 shares of Common Stock. Common Stock is
the only class of the Company's securities entitled to vote at the Annual
Meeting. Each share of Common Stock is entitled to one vote.
Shares represented by properly executed proxies received prior to the Annual
Meeting will be voted as specified by the shareholders. If no specifications
have been given in a proxy, the shares represented will be voted at the Annual
Meeting or any adjournments thereof FOR Item 1 (election of the nominees for
director), FOR Item 2 (approval of the proposal to amend the Company's 1994
Long-Term Incentive Compensation Plan), FOR Item 3 (ratification of the
appointment of Deloitte & Touche LLP as independent accountants and auditors
of the Company for 1998) and, in the discretion of the persons named in the
proxy, on any other business that may properly come before the meeting.
A proxy may be revoked by a shareholder at any time before it is voted at
the Annual Meeting by (i) delivering written revocation to Mr. Robert E.
Smith, Assistant Corporate Secretary, at the Company's address shown above,
(ii) submitting another valid proxy bearing a later date or (iii) voting in
person at the meeting.
At the Annual Meeting, holders of a majority of the outstanding shares of
Common Stock, represented in person or by proxy, will constitute a quorum. The
vote required for Item 1 (election of the nominees for director) is a
plurality of the votes cast. The vote required for each of Items 2 and 3
(approval of the proposal to amend the Company's 1994 Long-Term Incentive
Compensation Plan and ratification of independent accountants and auditors) is
the affirmative vote of a majority of the shares of Common Stock voted for or
against the matter (provided in the case of Item 2 that the total votes cast
must also exceed 50% of the shares of Common Stock outstanding and entitled to
vote on the matter). Abstentions and non-votes (shares held by brokers and
other nominees or fiduciaries that are present at the meeting but not voted on
a particular matter) on Items 2 and 3 do not count as voted for or against the
matter and thus do not affect the determination of whether the requisite
majority vote has been obtained.
<PAGE>
ELECTION OF DIRECTORS
The Company's Bylaws provide for a Board of Directors divided into three
classes having staggered terms with each class as nearly equal in size as
possible. Pursuant to the Company's Restated Articles of Incorporation, the
Board of Directors has set its size at fourteen members effective at the
Annual Meeting. The current term of office of the directors in Class II
expires at the Annual Meeting. The terms of office of directors in Class III
and Class I will expire at the annual meetings of shareholders to be held in
1999 and 2000, respectively. At each annual meeting of shareholders, directors
are elected to succeed those whose terms have expired. Each newly elected
director serves for a three-year term.
The Bylaws currently provide that no person is eligible to stand for re-
election to the Board of Directors at the annual meeting of shareholders on or
immediately following the tenth anniversary of such person's initial election
or appointment to the Board of Directors unless such person was serving as a
director of the Company as of April 1, 1992 or is an employee of the Company
or any of its corporate affiliates. The Bylaws also provide that no person is
eligible to serve as a director after the annual meeting of shareholders
occurring on or after the first day of the month immediately following the
month of his or her seventieth birthday. In any case, each director will serve
until his or her successor is duly elected and qualified unless he or she
resigns, becomes disqualified or disabled or is removed. Dr. Bertram Wolfe,
who has served as a director since 1993, will retire from the Board at the
conclusion of his current term at the Annual Meeting.
NOMINEES
The nominees for Class II directors to serve three-year terms ending at the
annual meeting in 2001 are current directors Milton Carroll, John T. Cater,
Robert C. Hanna and R. Steve Letbetter. Unless authority to vote is withheld,
the persons named in the accompanying proxy will vote shares represented by
properly executed proxies for the election of the foregoing nominees as
directors. If any nominee should become unavailable to serve on the Board of
Directors, the persons named in the proxy may act with discretionary authority
to vote the proxy for such other person, if any, as may be designated by the
Board of Directors.
The following sets forth certain information with respect to the business
experience of each nominee during the past five years and certain other
directorships held by each nominee. Unless otherwise indicated, each person
has had the same principal occupation for at least five years.
CLASS II DIRECTORS--TERM EXPIRING 2001
MILTON CARROLL, age 47, has been a director since 1992. Mr. Carroll is
Chairman, President and Chief Executive Officer of Instrument Products, Inc.,
an oiltool manufacturing company in Houston, Texas. He is a director of TEPPCO
Partners, L.P., Seagull Energy Corporation and Blue Cross and Blue Shield of
Texas, Inc.
JOHN T. CATER, age 62, has been a director since 1983. Mr. Cater is
President and a director of Compass Bank. He previously served as Chairman and
a director of River Oaks Trust Company and as President, Chief Operating
Officer and a director of MCorp, a Texas bank holding company.
ROBERT C. HANNA, age 69, has been a director since 1997. Mr. Hanna was
President and Chief Executive Officer of Imperial Holly Corporation and
Chairman of Holly Sugar Corporation prior to his retirement in September 1993,
serving as a director of Imperial Holly Corporation until July 1996. He
currently serves as Chairman of the Memorial Sisters of Charity Health
Network.(1)
- --------
(1) In accordance with the director retirement provisions of the Company's
bylaws, Mr. Hanna is expected to step down from the Board at the date of
the Company's 1999 annual meeting of shareholders, which is prior to the
expiration of the Class II term.
2
<PAGE>
R. STEVE LETBETTER, age 49, has been a director since 1995. Mr. Letbetter is
President and Chief Operating Officer of the Company, having served in that
capacity since January 1997. He has served since 1978 in various positions as
an executive officer of the Company and its corporate predecessors. Mr.
Letbetter is an advisory director of Chase Bank of Texas, National
Association.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR ALL NOMINEES FOR DIRECTOR.
CONTINUING DIRECTORS
The following sets forth certain information with respect to the members of
the Company's Board of Directors whose current terms will continue after the
Annual Meeting. Information is provided concerning the business experience of
each continuing director during the past five years and certain other
directorships held by each continuing director. Unless otherwise indicated,
each person has had the same principal occupation for at least five years.
CLASS III DIRECTORS--TERM EXPIRING 1999
JAMES A. BAKER, III, age 67, has been a director since 1996. Mr. Baker is
currently a senior partner in the law firm of Baker & Botts, L.L.P. in
Houston, Texas, Senior Counselor to The Carlyle Group, a merchant banking firm
in Washington, D. C., and a director of Electronic Data Systems (EDS). He
served as the U.S. Secretary of State from January 1989 through August 1992
and as White House Chief of Staff and Senior Counselor to President Bush from
August 1992 to January 1993. From 1985 to 1988, Mr. Baker was the U.S.
Secretary of the Treasury and Chairman of the President's Economic Policy
Council in the administration of President Reagan, having previously served as
President Reagan's White House Chief of Staff from 1981 to 1985 and as
President Ford's Under Secretary of Commerce in 1975.(2)
RICHARD E. BALZHISER, PH.D., age 65, has been a director since 1996. Dr.
Balzhiser is President Emeritus of the Electric Power Research Institute
(EPRI) in Palo Alto, California, a collaborative research and development
organization funded by member electric utilities. Dr. Balzhiser joined EPRI in
1973 as Director of the Fossil Fuel Advanced Systems Division. He became Vice
President of Research and Development in 1979 and Executive Vice President in
1987 and served as President and Chief Executive Officer from 1988 through
August 1996. He is a director of Electrosource Inc.
O. HOLCOMBE CROSSWELL, age 57, has been a director since 1997. Mr. Crosswell
is President of Griggs Corporation, a real estate and investment company in
Houston, Texas.
JOSEPH M. GRANT, age 59, has been a director since 1997. Mr. Grant is
Executive Vice President and Chief Financial Officer of EDS and will retire
from EDS on March 31, 1998.
DON D. JORDAN, age 65, has been a director since 1974. Mr. Jordan is
Chairman and Chief Executive Officer of the Company. He also serves as an
advisory director of Chase Bank of Texas, National Association and a director
of BJ Services Company, Inc.
CLASS I DIRECTORS--TERM EXPIRING 2000
ROBERT J. CRUIKSHANK, age 67, has been a director since 1993. Mr. Cruikshank
is primarily engaged in managing his personal investments in Houston, Texas.
Prior to his retirement in 1993, he was a Senior Partner in the accounting
firm of Deloitte & Touche. Mr. Cruikshank serves as a director of MAXXAM Inc.,
Kaiser Aluminum Corporation, Compass Bank, Texas Biotechnology Corporation,
American Residential Services and Weingarten Realty Investors.
- --------
(2) Baker & Botts, L.L.P. provided legal services to the Company and it
subsidiaries during 1997, and is also providing legal services during
1998.
3
<PAGE>
LINNET F. DEILY, age 52, has been a director since 1993. Ms. Deily is
President, Schwab Institutional Services for Investment Managers of Charles
Schwab & Co., Inc. She previously served as Chairman, Chief Executive Officer
and President of First Interstate Bank of Texas, N.A. until April 1996, having
been Chairman since 1992, Chief Executive Officer since 1991 and President of
First Interstate Bank of Texas since 1988.
LEE W. HOGAN, age 53, has been a director since 1995. Mr. Hogan is Executive
Vice President of the Company and President and Chief Executive Officer of its
HI Retail Energy Group Division, having served in those capacities since
January 1997. He has served since 1990 in various positions as an executive
officer of the Company and its corporate predecessors and subsidiaries.
T. MILTON HONEA, age 65, has been a director since 1997. Mr. Honea was
Chairman of the Board, President and Chief Executive Officer of NorAm Energy
Corp. (NorAm) until its acquisition by the Company in 1997, having served in
that capacity since December 1992. He was Executive Vice President of NorAm
from October 1991 until July 1992 and President and Chief Operating Officer of
Arkansas Louisiana Gas Company, a division of NorAm, from October 1984 to
October 1991.
ALEXANDER F. SCHILT, PH.D., age 57, has been a director since 1992. Dr.
Schilt is the President of the InterAmerican University Council for Economic
and Social Development. He served as Chancellor of the University of Houston
until August 1995. Prior to 1990, he was President of Eastern Washington
University in Cheney and Spokane, Washington.
ORGANIZATION OF THE BOARD OF DIRECTORS
The business of the Company is managed under the direction of the Board of
Directors. Several committees established by the Board of Directors oversee
specific matters affecting the Company, including an Executive and Nominating
Committee, an Audit Committee, a Finance Committee, a Compensation Committee,
a Nuclear Committee and other committees.
The EXECUTIVE AND NOMINATING COMMITTEE, currently composed of Mr. Carroll,
Mr. Cater, Mr. Cruikshank, Ms. Deily, Mr. Honea, Mr. Jordan and Mr. Letbetter,
reviews management recommendations for organizational changes, provides
consultation regarding duties of executive officers and recommends potential
candidates for election to the Board of Directors. See "Director Nominations
for 1999 Annual Meeting of Shareholders."
The AUDIT COMMITTEE, which is composed entirely of non-employee directors,
currently consists of Mr. Carroll, Mr. Crosswell, Mr. Cruikshank, Mr. Grant
and Dr. Schilt. The Audit Committee reviews the Company's accounting and
financial practices and advises the Board of Directors of any needed changes
in such practices, recommends to the Board of Directors the firm of
independent public accountants to be engaged to examine the financial
statements of the Company and its subsidiaries, reviews and approves the plan
and scope of the independent public accountants' audit and non-audit services
and related fees, reviews the Company's internal accounting controls, and has
general responsibility for related matters.
The FINANCE COMMITTEE, currently composed of Mr. Cater, Ms. Deily, Mr.
Grant, Mr. Hogan and Mr. Jordan, reviews management forecasts of the Company's
financial needs and policies, acts on management recommendations concerning
the Company's capital structure, amounts and sources of permanent financing,
lines of credit, loan agreements and dividend policies and approves terms
relevant to specific debt and equity offerings of the Company.
The COMPENSATION COMMITTEE is composed entirely of non-employee directors.
The current members are Mr. Cruikshank, Ms. Deily, Mr. Hanna and Dr.
Balzhiser. Mr. Cater and former director Howard W. Horne were also members of
the Compensation Committee during early 1997. The Compensation Committee makes
recommendations to the Board of Directors concerning compensation and benefits
for officers of the Company and reviews human resource programs regarding
manpower forecasts and training. The Compensation Committee also monitors and,
in certain cases, administers employee benefit plans.
4
<PAGE>
The NUCLEAR COMMITTEE currently consists of Dr. Balzhiser, Dr. Schilt and
Dr. Wolfe, all of whom are non-employee directors. The Nuclear Committee
reviews the activities of the Company in all areas of nuclear development and
operations, and reports to and makes recommendations to the Board of Directors
on such matters as nuclear regulatory reports and licensing requirements,
management evaluations of nuclear engineering, construction and operations
progress and performance and monitoring of budgetary requirements.
The UNREGULATED BUSINESS COMMITTEE, currently composed of Dr. Balzhiser, Ms.
Deily, Mr. Honea, Mr. Jordan and Dr. Wolfe, reviews strategy and activities of
the Company and its subsidiaries in the areas of domestic and foreign
independent power generation projects and the privatization of foreign
generating and distribution facilities.
The Board of Directors of the Company held seven meetings during 1997.
During 1997, the Executive and Nominating Committee met one time, the Audit
Committee met four times, the Finance Committee met six times, the
Compensation Committee met five times, the Nuclear Committee met four times
and the Unregulated Business Committee met five times. Each director attended
at least 75% of the aggregate number of meetings of the Board of Directors and
of committees on which he or she served.
COMPENSATION OF DIRECTORS
Each non-employee director receives an annual retainer fee of $20,000, a fee
of $1,000 for each board and committee meeting attended and 500 shares of
Common Stock annually pursuant to the terms of the Company's Stock Plan for
Outside Directors. Directors may defer all or part of their annual retainer
fees and meeting fees under the Company's deferred compensation plan. The
deferred compensation plan currently provides for accrual of interest on
deferred director compensation at a rate equal to the average annual yield on
the Moody's Long-Term Corporate Bond Index plus 2%.
Non-employee directors participate in a director benefits plan pursuant to
which a director who serves at least one full year will receive an annual
benefit in cash equal to the annual retainer payable in the year the director
terminates service. Benefits under this plan will be payable to a director,
commencing the January following the later of the director's termination of
service or attainment of age 65, for a period equal to the number of full
years of service of the director.
Non-employee directors may also participate in the Company's executive life
insurance plan described under "Retirement Plans, Related Benefits and Other
Agreements." This plan provides split-dollar life insurance with a death
benefit equal to six times the director's annual retainer with coverage
continuing after termination of service as a director. The plan also permits
the Company to provide for a tax reimbursement payment to make the directors
whole for any imputed income recognized with respect to the term portion of
the annual insurance premiums. Upon death, the Company will receive the
balance of the insurance proceeds payable in excess of the specified death
benefit which, by design, is expected to be at least sufficient to cover the
Company's cumulative outlays to pay premiums and the after-tax cost to the
Company of the tax reimbursement payments.
Mr. Carroll performed consulting services for the Company during 1997 in
connection with deregulation issues, for which he was paid an aggregate of
$240,000.
5
<PAGE>
SECURITIES OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The table below sets forth certain information regarding each person known
by the Company to beneficially own more than 5% of the Company's Common Stock.
<TABLE>
<CAPTION>
AMOUNT AND
NATURE OF PERCENT
BENEFICIAL OF
NAME AND ADDRESS OF BENEFICIAL OWNER OWNERSHIP CLASS
- ------------------------------------ ---------- -------
<S> <C> <C>
Northern Trust Corporation
and subsidiaries......................................... 30,938,267(1) 10.49%
50 South LaSalle Street
Chicago, Illinois 60675
</TABLE>
- --------
(1) This information is based on a Schedule 13G filed with the SEC on February
17, 1998 by Northern Trust Corporation as parent holding company on behalf
of its subsidiaries The Northern Trust Company, Northern Trust Bank of
Arizona, N.A., Northern Trust Bank of California, N.A., Northern Trust
Bank of Florida, N.A., Northern Trust Bank of Texas, N.A. and Northern
Trust Quantitative Advisors, Inc. reporting sole voting power for
1,078,038 shares, shared voting power for 29,837,779 shares, sole
dispositive power for 1,033,040 shares and shared dispositive power for
83,186 shares. The Company understands that the shares reported include
29,794,894 shares held by The Northern Trust Company in its capacity as
trustee under the Company's savings plan.
6
<PAGE>
SECURITIES OWNERSHIP OF MANAGEMENT
The following table sets forth information as of March 1, 1998, with respect
to the beneficial ownership of the Company's Common Stock by each current
director and nominee, the chief executive officer and the four other most
highly compensated executive officers of the Company and, as a group, by such
persons and other executive officers. No person or member of the group listed
owns any equity securities of any subsidiary of the Company. Unless otherwise
indicated, each person or member of the group listed has sole voting and sole
investment power with respect to the shares of Common Stock listed. No
ownership shown in the table represents 1% or more of the outstanding shares
of Common Stock.
<TABLE>
<CAPTION>
SHARES OF
COMMON STOCK
NAME BENEFICIALLY OWNED
- ---- ------------------
<S> <C>
James A. Baker, III...................................... 2,000
Richard E. Balzhiser..................................... 1,100
Milton Carroll........................................... 3,400
John T. Cater............................................ 3,000(1)
O. Holcombe Crosswell.................................... 10,595
Robert J. Cruikshank..................................... 3,000
Linnet F. Deily.......................................... 3,000(2)
Joseph M. Grant.......................................... 4,811
Robert C. Hanna.......................................... 28,347
Lee W. Hogan............................................. 41,246(3)(4)(5)
T. Milton Honea.......................................... 142,296
Don D. Jordan............................................ 345,155(3)(4)(6)
Hugh Rice Kelly.......................................... 87,988(3)(4)(5)
R. Steve Letbetter....................................... 86,731(3)(4)(5)
Stephen W. Naeve......................................... 40,322(3)(4)(5)
Alexander F. Schilt...................................... 1,800
Bertram Wolfe............................................ 1,220
All of the above and other executive officers as a group
(22 persons)............................................. 925,917(3)(4)(5)
</TABLE>
- --------
(1) Mr. Cater disclaims beneficial ownership of 2,000 of these shares, which
are owned by his adult children.
(2) Voting power and investment power with respect to the shares listed for
Ms. Deily are shared with her spouse.
(3) Includes shares held under the Company's savings plan, as to which the
participant has sole voting power (subject to such power being exercised
by the plan's trustee in the same proportion as directed shares in the
savings plan are voted in the event the participant does not exercise
voting power). The shares held under the plan are reported as of December
31, 1997.
(4) The ownership shown in the table includes shares which may be acquired
within 60 days on exercise of outstanding stock options granted under the
Company's long-term incentive compensation plan by each of the persons and
group, as follows: Mr. Hogan--7,668 shares; Mr. Jordan--146,277 shares;
Mr. Kelly--29,266 shares; Mr. Letbetter--33,213 shares; Mr. Naeve--12,269
shares; and the group--264,749 shares.
(5) Includes shares held under the Company's dividend reinvestment and stock
purchase plan as of December 31, 1997.
(6) Voting power and investment power with respect to 1,152 of the shares
listed are shared with Mr. Jordan's spouse.
7
<PAGE>
EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table shows, for the years ended December 31, 1995, 1996 and
1997, the annual, long-term and certain other compensation of the Company's
chief executive officer and each of the four other current executive officers
who were most highly compensated during 1997 (Named Officers).
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM COMPENSATION
---------------------------------
ANNUAL COMPENSATION AWARDS PAYOUTS
--------------------------------------- ---------------------- ----------
RESTRICTED SECURITIES
NAME AND PRINCIPAL OTHER ANNUAL STOCK UNDERLYING LTIP ALL OTHER
POSITION(1)(2) YEAR SALARY(1) BONUS(1) COMPENSATION AWARD (3) OPTIONS (#) PAYOUTS(4) COMPENSATION(5)
------------------ ---- ---------- ---------- ------------ ---------- ----------- ---------- ---------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Don D. Jordan .......... 1997 $1,000,000 $1,080,000 $640,754 $3,525,000 33,803 $621,392 $2,047,142(6)
Chairman and Chief 1996 962,292 1,050,000 13,300 27,985 767,440 819,105
Executive Officer 1995 884,500 907,226 3,969 36,316 407,437 734,023
R. Steve Letbetter...... 1997 481,250 447,525 266 9,938 151,612 77,401
President and Chief 1996 416,000 330,750 228 7,815 138,831 45,151
Operating Officer 1995 363,500 285,750 190 9,746 84,201 47,242
Lee W. Hogan ........... 1997 372,917 324,000 1,616 0 0 43,981
Executive Vice
President 1996 310,000 401,722 1,260 0 42,360 20,913
and Chief Executive
Officer 1995 262,500 123,750 965 0 52,142 18,711
of the Company's Retail
Energy Group
Hugh Rice Kelly ........ 1997 355,417 218,700 782 6,292 141,497 69,091
Executive Vice
President, 1996 344,833 209,400 705 5,563 176,311 37,495
General Counsel and 1995 334,000 195,773 637 7,414 100,925 44,245
Corporate Secretary
Stephen W. Naeve........ 1997 294,167 191,363 55 4,777 55,724 30,128
Executive Vice
President 1996 237,917 159,000 43 2,462 62,457 20,682
and Chief Financial 1995 196,000 85,500 37 3,246 33,449 21,997
Officer
</TABLE>
- --------
(1) The amounts shown include salary and bonus earned as well as earned but
deferred by the Named Officers.
(2) Charles R. Crisp was Senior Vice President of the Company and President of
its HI Power Generation Division until his resignation in January 1998.
Mr. Crisp's salary and bonus for 1997 were $339,583 and $218,152,
respectively. In addition, he had other annual compensation in 1997 of
$300,575 representing loan forgiveness pursuant to an employment contract
and he had $7,546 in other compensation in 1997. He was granted options in
1997 covering (after forfeiture of a portion upon termination) 1,953
shares of Common Stock with an exercise price of $22.1875, and having a
grant date present value of $6,132 and a year-end in-the-money value of
$9,303. These options will expire in January 2001. Mr. Crisp's salary and
bonus for 1996 were $88,636 and $50,004, respectively.
(3) On February 25, 1997 Mr. Jordan received a grant of 150,000 shares of
restricted stock, to vest on June 1, 1999, pursuant to an employment
agreement with the Company described below under "Retirement Plans,
Related Benefits and Other Agreements." The amount shown is the closing
market price of 150,000 shares of Common Stock on February 25, 1997. The
closing market price of 150,000 shares of Common Stock on December 31,
1997 was $4,012,500.
(4) The amounts shown for 1997 represent the dollar value of shares of the
Company's Common Stock paid out in 1997 under the Company's long-term
incentive compensation plan based on the achievement of certain
performance goals for the 1994-1996 performance cycle, plus dividend
equivalent accruals during the performance period.
(5) The amounts shown for 1997 include (i) Company contributions to the
Company's savings plan and accruals under its savings restoration plan on
behalf of the Named Officers, as follows: Mr. Jordan, $113,297; Mr.
Letbetter, $65,778; Mr. Hogan, $39,319; Mr. Kelly, $48,976; and Mr. Naeve,
$22,245; (ii) the term portion of the premiums paid by the Company under
split-dollar life insurance policies purchased in connection with the
Company's executive life insurance plan, as follows: Mr. Jordan, $22,500;
Mr. Letbetter, $381; Mr. Hogan, $2,320; Mr. Kelly, $1,123; and Mr. Naeve,
$79; and (iii) the portion of accrued interest on amounts of compensation
deferred under the Company's deferred compensation plan and executive
incentive compensation plan that exceeds 120% of the applicable federal
long-term rate provided under Section 1274(d) of the Internal Revenue
Code, as follows: Mr. Jordan, $1,013,688; Mr. Letbetter, $11,242; Mr.
Hogan, $2,342; Mr. Kelly, $18,992; and Mr. Naeve, $7,804.
(6) Under the terms of an employment agreement relating to Mr. Jordan's active
employment with the Company after his attainment of normal retirement age
(65), Mr. Jordan has the option to elect at retirement to retain the group
life insurance coverage provided similarly situated active employees. The
Company determined that the most economic manner to provide that coverage
was to purchase a single-premium, whole life insurance policy, and in
connection therewith, Mr. Jordan agreed to continue to pay the Company the
cost he previously has borne for the coverage. The amount shown for Mr.
Jordan under "All Other Compensation" above includes a one-time amount
representing the entire premium for that policy, $897,657, without
reflecting Mr. Jordan's future annual contributions to that cost.
8
<PAGE>
STOCK OPTION GRANTS
The following table contains information concerning grants of stock options
during 1997 under the Company's long-term incentive compensation plan to the
Named Officers. (Mr. Hogan participated in a different incentive compensation
plan which does not provide for option grants.)
OPTION GRANTS IN 1997
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS
-----------------------
NUMBER OF % OF TOTAL EXERCISE
SECURITIES OPTIONS OR BASE GRANT
UNDERLYING GRANTED TO PRICE DATE
OPTIONS EMPLOYEES PER EXPIRATION PRESENT
NAME GRANTED(1) IN FISCAL YEAR SHARE DATE VALUE(2)
---- ---------- -------------- -------- ---------- --------
<S> <C> <C> <C> <C> <C>
Don D. Jordan........... 33,803 8.83% $22.1875 1/6/07 $106,141
R. Steve Letbetter...... 9,938 2.60% 22.1875 1/6/07 31,205
Hugh Rice Kelly......... 6,292 1.64% 22.1875 1/6/07 19,757
Stephen W. Naeve........ 4,777 1.25% 22.1875 1/6/07 15,000
</TABLE>
- --------
(1) The options for shares of Common Stock included in the table were granted
on January 7, 1997, have a ten-year term and generally become exercisable
annually in one-third increments commencing one year after date of grant,
so long as employment with the Company or its subsidiaries continues. A
change in control of the Company would result in all options becoming
immediately exercisable. For the purposes of the long-term incentive
compensation plan, a "change in control" generally is deemed to have
occurred if (i) any person or group becomes the direct or indirect
beneficial owner of 30% or more of the Company's outstanding voting
securities; (ii) the majority of the Board changes as a result of, or in
connection with, certain transactions; (iii) as a result of the Company
merging or consolidating with another corporation, less than 70% of the
surviving corporation's outstanding voting securities is owned by the
former shareholders of the Company (excluding any party to such a
transaction or any affiliates of any such party); (iv) a tender offer or
exchange offer is made and consummated for the ownership of 30% or more of
the Company's outstanding voting securities; or (v) the Company transfers
all or substantially all of its assets to another corporation that is not
wholly-owned by the Company.
(2) The values are based on the Black-Scholes option pricing model adjusted for
the payment of dividends. The calculations were based on the following
assumptions: volatility of 22.06% (based on daily closing prices of Common
Stock for the one-year period prior to grant date); risk-free interest rate
of 6.58% (interest rate on a U.S. Treasury security with a maturity date
corresponding to that of the option term); option price of $22.1875 (fair
market value of the underlying stock on the date of grant); current
dividend rate of $1.50 per share per year; and option term equal to the
full ten-year period until the stated expiration date. No reduction has
been made in the valuations on account of non-transferability of the
options or vesting or forfeiture provisions. Valuations would change if
different assumptions were made. Option values are dependent on general
market conditions and the performance of Common Stock. There can be no
assurance that the values in this table will be realized.
9
<PAGE>
STOCK OPTION VALUES
The following table contains information concerning unexercised options to
purchase Common Stock held by the Named Officers as of December 31, 1997. No
options were exercised by the Named Officers during 1997.
<TABLE>
<CAPTION>
NUMBER OF SECURITIES
UNDERLYING UNEXERCISED VALUE OF UNEXERCISED IN-
OPTIONS AT THE-MONEY OPTIONS AT
DECEMBER 31, 1997 DECEMBER 31, 1997(1)
------------------------- -------------------------
NAME EXERCISABLE/UNEXERCISABLE EXERCISABLE/UNEXERCISABLE
- ---- ------------------------- -------------------------
<S> <C> <C>
Don D. Jordan............... 113,574/ 64,566 $570,080/ $311,526
R. Steve Letbetter.......... 24,047/ 18,396 125,491/ 88,097
Lee W. Hogan................ 7,668/ 0 33,586/ 0
Hugh Rice Kelly............. 22,842/ 12,473 115,126/ 60,545
Stephen W. Naeve............ 8,775/ 7,500 45,160/ 35,900
</TABLE>
- --------
(1) Based on the average of the high and low sales prices of the Common Stock
on the New York Stock Exchange Composite Tape, as reported in The Wall
Street Journal for December 31, 1997.
LONG-TERM INCENTIVE COMPENSATION
The following table sets forth information concerning awards made to the
Named Officers during 1997 for the 1997-1999 performance cycle under the
Company's long-term incentive compensation plan and a separate grant to Mr.
Jordan in connection with an amended employment agreement described below
under "Retirement Plans, Related Benefits and Other Agreements." The amounts
shown represent potential payouts of awards of shares of Common Stock based on
the achievement of performance goals over a three year performance cycle. The
performance goals consist of three objectives weighted equally: (1) growth in
earnings per share; (2) total return to stockholders relative to the Standard
& Poor's (S&P) 500 Electric Utilities Panel; and (3) cash return on
capitalization from electric utility transmission and distribution operations
relative to the same peer group. If a change in control of the Company occurs
before the end of a performance cycle, the payout of awards will be made in
cash at the maximum level without regard to achievement of the performance
goals. See Note 1 to the Option Grants in 1997 table for information regarding
the definition of a change in control under the Company's long-term incentive
compensation plan. There were no grants during 1997 for Mr. Hogan under the
incentive compensation plan established for the Company's subsidiary Houston
Industries Energy, Inc. (HI Energy) for the 1997-1999 performance cycle.
LONG-TERM INCENTIVE PLAN AWARDS IN 1997
<TABLE>
<CAPTION>
ESTIMATED FUTURE PAYOUTS
UNDER
NON-STOCK PRICE-BASED
PLANS(1)
-------------------------
PERFORMANCE
OR OTHER
PERIOD TARGET MAXIMUM
NUMBER UNTIL THRESHOLD NUMBER NUMBER
OF MATURATION NUMBER OF OF
NAME SHARES OR PAYOUT OF SHARES SHARES SHARES
- ---- ------- ----------- --------- ------- -------
<S> <C> <C> <C> <C> <C>
Don D. Jordan(2).................. 150,000 06/01/99 75,000 150,000 150,000
Don D. Jordan..................... 31,816 12/31/99 15,908 31,816 47,724
R. Steve Letbetter................ 10,022 12/31/99 5,011 10,022 15,033
Hugh Rice Kelly................... 6,345 12/31/99 3,173 6,345 9,518
Stephen W. Naeve.................. 4,818 12/31/99 2,409 4,818 7,227
</TABLE>
- --------
(1) The table does not reflect dividend equivalent accruals during the
performance period.
(2) The 150,000 share grant is pursuant to Mr. Jordan's employment agreement.
Other grants listed are under the Company's long-term incentive
compensation plan.
10
<PAGE>
RETIREMENT PLANS, RELATED BENEFITS AND OTHER AGREEMENTS
The following table shows the estimated annual benefit payable under the
Company's retirement plan, benefit restoration plan and, in certain cases,
supplemental agreements, to officers in various compensation classifications
upon retirement at age 65 after the indicated periods of service, determined
on a single-life annuity basis. The benefits listed in the table are not
subject to any deduction for Social Security or other offsetting amounts.
PENSION PLAN TABLE
<TABLE>
<CAPTION>
ESTIMATED ANNUAL PENSION BASED ON SERVICE(1)
FINAL ------------------------------------------------
AVERAGE Greater
ANNUAL than
COMPENSATION or equal
AT AGE 65 15 20 25 30 to 35
- ------------ -------- -------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C>
$400,000 $114,346 $152,461 $190,576 $ 228,691 $ 266,806
$500,000 $143,446 $191,261 $239,076 $ 286,891 $ 334,706
$600,000 $172,546 $230,061 $287,576 $ 345,091 $ 402,606
$700,000 $201,646 $268,861 $336,076 $ 403,291 $ 470,506
$800,000 $230,746 $307,661 $384,576 $ 461,491 $ 538,406
$900,000 $259,846 $346,461 $433,076 $ 519,691 $ 606,306
$1,000,000 $288,946 $385,261 $481,576 $ 577,891 $ 674,206
$1,200,000 $347,146 $462,861 $578,576 $ 694,291 $ 810,006
$1,400,000 $405,346 $540,461 $675,576 $ 810,691 $ 946,806
$1,600,000 $463,546 $618,061 $772,576 $ 927,091 $1,081,606
$1,800,000 $521,746 $695,661 $869,576 $1,043,491 $1,217,406
$2,000,000 $579,946 $773,261 $966,576 $1,159,891 $1,353,206
</TABLE>
- --------
(1) The qualified pension plan limits compensation in accordance with Section
401(a)(17) of the Internal Revenue Code and also limits benefits in
accordance with Section 415 of the Internal Revenue Code. Pension benefits
based on compensation above the qualified plan limit or in excess of the
limit on annual benefits are provided through the benefits restoration
plan.
For the purpose of the pension table above, final average annual
compensation means the average of covered compensation for 36 consecutive
months out of the 120 consecutive months immediately preceding retirement in
which the participant's covered compensation was the highest. Covered
compensation includes only the amounts shown in the "Salary" and "Bonus"
columns of the Summary Compensation Table. At December 31, 1997, the credited
years of service for the following persons were: 35 years for Mr. Jordan; 24
years for Mr. Letbetter; 7 years for Mr. Hogan; 23 years for Mr. Kelly, 10 of
which result from a supplemental agreement; and 25 years for Mr. Naeve. Under
a supplemental agreement with Mr. Hogan, upon the earliest of his normal
retirement, disability or death, Mr. Hogan will be eligible for supplemental
pension benefits determined as if his employment had commenced fifteen years
prior to his first day of actual employment with the Company.
The Company maintains an executive benefits plan that provides certain
salary continuation, disability and death benefits to certain key officers of
the Company and certain of its subsidiaries. Messrs. Jordan, Letbetter, Hogan,
Kelly and Naeve participate in this plan pursuant to individual agreements
that generally provide for (i) a salary continuation benefit of 100% of the
officer's current salary for twelve months after death during active
employment and then 50% of salary for nine years or until the deceased officer
would have attained age 65, if later, and (ii) if the officer retires after
attainment of age 65, an annual post-retirement death benefit of 50% of the
officer's preretirement annual salary payable for six years. Coverage under
this plan has not been provided to persons attaining executive officer status
after July 1, 1996.
The Company has an executive life insurance plan providing split-dollar life
insurance in the form of a death benefit for officers and members of the Board
of Directors. The death benefit coverage varies but in each case is
11
<PAGE>
based on coverage (either single life or second to die) that is available for
the same amount of premium that could purchase coverage equal to four times
current salary for Messrs. Letbetter and Hogan; two times current salary for
Messrs. Kelly and Naeve; thirty million dollars for Mr. Jordan; and six times
the annual retainer for the Company's non-employee directors. The plan also
provides that the Company may make payments to the covered individuals to
compensate for tax consequences of imputed income that they must recognize for
federal income tax purposes based on the term portion of the annual premiums.
If a covered executive retires at age 65 or at an earlier age under
circumstances approved by the Board of Directors, rights under the plan vest
so that coverage is continued based on the same death benefit in effect at the
time of retirement. Upon death, the Company will receive the balance of the
insurance proceeds payable in excess of the specified death benefit which is
expected to be at least sufficient to cover the Company's cumulative outlays
to pay premiums and the after-tax cost to the Company of the tax reimbursement
payments. There is no arrangement or understanding under which any covered
individuals will receive or be allocated any interest in any cash surrender
value under the policy.
Since 1985, the Company has had in effect deferred compensation plans which
permit eligible participants to elect each year to defer a percentage of that
year's salary (prior to December 1, 1993, up to 25% or 40%, depending on age,
and beginning December 1, 1993, 100%) and up to 100% of that year's annual
bonus. Directors may also defer fees payable to them as described under
"Compensation of Directors." In general, employees over the age of 60 who
participate in the deferred compensation plans may elect to have their
deferred compensation amounts repaid in (i) fifteen equal annual installments
commencing at the later of age 65 or termination of employment, or (ii) a lump
sum distribution following termination of employment. Directors participating
in these plans are entitled to receive distributions at age 70 or upon leaving
the Board, whichever is later. Interest generally accrues on deferrals made in
1989 and subsequent years at a rate equal to Moody's Long-Term Corporate Bond
Index plus 2%, determined annually until termination of employment when the
rate is fixed at the greater of the rate in effect at age 64 or at age 65.
Fixed rates of 19% to 24% were established for deferrals made in 1985 through
1988 and some deferrals in 1989, as a result of then higher prevailing rates
and the Company's ability to offset a substantial majority of the related
cost, on an after-tax basis (and substantially all of such cost in excess of
120% of the applicable federal long-term rate) through life insurance policies
purchased by the Company. Current accruals of the above-market portion of the
interest on deferred compensation amounts are included in the "All Other
Compensation" column of the Summary Compensation Table.
The Company and HI Energy are parties to a trust agreement with an
independent trustee establishing a "rabbi trust" for the purpose of funding
benefits payable to participants (which include each of the Named Officers)
under the Company's deferred compensation plans, executive incentive
compensation plans, benefits restoration plan and savings restoration plan
(Designated Plans). The trust is a grantor trust, irrevocable except in the
event of an unfavorable ruling by the Internal Revenue Service as to the tax
status of the trust or certain changes in tax law. It is currently funded with
a nominal amount of cash. The Company and HI Energy are required to make
future contributions to the grantor trust when required by the provisions of
the Designated Plans or when required by the Company's benefits committee. The
benefits committee consists of officers of the Company designated by the Board
of Directors and has general responsibility for funding decisions and
selection of investment managers for the Company's retirement plan and other
administrative matters in connection with other employee benefit plans of the
Company. If there is a change in control (defined in a manner generally the
same as the comparable definition in the Company's long-term incentive
compensation plan), the Company and HI Energy are required to fully fund the
grantor trust, within 15 days following the change in control, with an amount
equal to the entire benefit to which each participant would be entitled under
the Designated Plans as of the date of the change in control (calculated on
the basis of the present value of the projected future benefits payable under
the Designated Plans). The assets of the grantor trust are required to be held
separate and apart from the other funds of the Company and its subsidiaries,
but remain subject to claims of general creditors under applicable state and
federal law.
In accordance with the indemnification provisions of the Company's Bylaws
and Texas law, the Company paid approximately $1,200 in 1997 to cover legal
fees and expenses incurred on behalf of the Company's
12
<PAGE>
directors in connection with the defense of a shareholder derivative suit and
class action filed in April 1994 by two former employees of the Company.
In 1997, the Company entered into an amended and restated employment
agreement with Mr. Jordan extending his employment for two years beyond his
normal retirement date (June 1, 1997). The new agreement, entered into in
February 1997 and subsequently amended in November 1997, replaces an agreement
entered in 1994 which also provided for an extension of Mr. Jordan's
employment period. The 1997 agreement provides for the employment of Mr.
Jordan as Chairman of the Board and Chief Executive Officer of the Company
until June 1, 1999, subject to early termination or extension in certain
circumstances (Employment Period). During the Employment Period, Mr. Jordan
will receive benefits including (i) base salary in an amount not less than his
salary in effect on January 8, 1997, (ii) annual bonus awards based on amounts
payable under the Company's executive incentive compensation plan and long-
term incentive compensation plan, and (iii) participation in other employee
benefit plans and programs on generally the same basis as other peer
executives, except that Mr. Jordan will not receive any long-term incentive
compensation plan award for performance cycles commencing in 1998 and 1999 but
has instead received an award of 300,000 restricted shares of Common Stock.
Mr. Jordan's right to 150,000 shares of the restricted shares of Common
Stock will vest if he continues to be employed by the Company until June 1,
1999, subject to earlier vesting if the Company terminates his employment
without Cause (as defined), if he terminates employment for Good Reason (as
defined) or if his employment terminates by reason of death, disability or
retirement with the consent of the Board of Directors or by reason of the
occurrence of a Change of Control (as defined). His right to the other 150,000
restricted shares of Common Stock is generally subject to vesting provisions
based on achievement of the same performance goals that are applicable to his
performance-based restricted stock award under the long-term incentive
compensation plan for the 1997-1999 performance cycle (as estimated on the
June 1, 1999 vesting date), subject to earlier vesting of the entire award if
the Company terminates his employment without Cause, if he terminates
employment for Good Reason or if his employment terminates by reason of the
occurrence of a Change of Control, or of a prorated, performance-based portion
of the award if his employment terminates by reason of death, disability or
retirement with the consent of the Board of Directors.
Mr. Jordan's employment agreement provides for an extension of the
commencement date of the fifteen annual installment payments of salary and
bonus previously deferred under the Company's deferred compensation plans for
one year following the end of the Employment Period, if Mr. Jordan remains
employed through the end of the Employment Period, in consideration of Mr.
Jordan's agreement to make himself available for up to 40 hours per month as a
consultant during that year.
The employment agreement with Mr. Jordan provided for an election at
retirement to retain the group life insurance coverage normally provided
similarly situated active employees of the Company. In lieu of providing this
coverage through the group program, the Company elected to purchase an
individual policy for Mr. Jordan for a single sum premium, which is included
in the "All Other Compensation" column of the Summary Compensation Table, and
to make an additional payment to him in an amount necessary to make him whole
on an after-tax basis against tax liability incurred by him as a result of the
receipt of the policy, which is included in the "Other Annual Compensation"
column. In connection therewith, Mr. Jordan agreed to continue to pay the
Company the cost he previously has borne for this coverage.
The agreement provides for termination of the Employment Period prior to
June 1, 1999 upon the occurrence of a Change of Control or, if a binding
agreement to effect a Change of Control is in effect on June 1, 1999, for
extension of the Employment Period to the earlier of the date of a Change of
Control occurs or the termination of such agreement.
Upon any termination of the Employment Period by reason of the occurrence of
a Change of Control, or, if while the Company is a party to any agreement to
effect a Change of Control, the Company terminates Mr. Jordan's employment
without Cause or Mr. Jordan terminates his employment for Good Reason or by
reason of death, disability or retirement with the consent of the Company, the
employment agreement provides that the
13
<PAGE>
Company will pay Mr. Jordan a cash payment equal to 2.99 times the sum of his
base salary, target annual bonus (currently 80% of his base salary) and the
fair market value of the shares subject to the restricted stock grant made to
him under his employment agreement that are subject to performance-based
vesting conditions, and will fulfill certain other obligations generally
applicable upon termination of employment. To the extent that payments made to
Mr. Jordan would result in the imposition of an excise tax (and related loss
of deduction to the Company), the agreement provides for additional payments
to Mr. Jordan in an amount necessary to offset the effect of the excise tax
and any consequent income tax. Generally, a Change of Control will be deemed
to occur under the employment agreement if (i) the individuals constituting
the Board of Directors of the Company on September 1, 1997, including their
designated successors (Incumbent Directors) cease to constitute a majority of
the Board, (ii) an individual, entity or group acquires beneficial ownership
of 30% or more of the Company's outstanding voting stock, unless the
acquisition is from the Company in a transaction approved by a majority of the
Incumbent Directors, (iii) a merger or other business combination involving
the Company is consummated unless, immediately following the transaction, (a)
the Company's stockholders prior to the business combination own more than 70%
of the outstanding shares of voting stock of the resulting parent entity in
the same relative proportions, (b) the total fair market value of any
consideration paid to another entity or its stockholders, plus the amount of
long-term debt of the entity acquired does not exceed 50% of the sum
(determined prior to the transaction) of the fair market value of the
Company's outstanding voting stock and the amount of its consolidated long-
term debt, (c) there is not a 30% stockholder of the resulting parent entity
and (d) a majority of the board of the resulting parent entity after the
transaction were Incumbent Directors immediately prior to consummation of the
business combination or (iv) there is a disposition of 70% or more of the
assets of the Company and its consolidated subsidiaries unless, immediately
following the transaction, the Company's stockholders prior to such
transaction own more than 70% of the then outstanding shares of voting stock
of the Company and of the parent entity that acquires the largest portion of
such assets and a majority of the members of the board of directors of the
Company and of such acquiring parent entity were Incumbent Directors
immediately prior to the transaction.
In November 1997, the Company entered into severance agreements with certain
executive officers, including Mr. Letbetter, Mr. Hogan, Mr. Kelly and Mr.
Naeve. The new severance agreements, which provide for the payment of certain
benefits in the event of a covered termination of employment occurring within
three years after the occurrence of a Change of Control, replace severance
agreements that expired in December 1996 providing for similar benefits. The
meaning of a Change of Control in the new severance agreements is generally
the same as in the employment agreement between the Company and Mr. Jordan
described above. Under the new severance agreements, a covered termination
occurs if the officer's employment is terminated for reasons other than death,
disability, termination on or after age 65, termination for Cause (as
defined), or resignation by the officer unless the resignation occurs during a
61-day period commencing on the date the officer experiences a significant
reduction in his duties, remuneration, or principal place of employment
following or in anticipation of a Change of Control. Under the 1997
agreements, as under the former agreements, an officer experiencing a covered
termination of employment will be entitled to payment of three times a
prescribed covered compensation amount as well as certain welfare benefits. An
officer's covered compensation amount for this purpose is the sum of his
annual salary, target annual bonus (currently ranging from 45% to 65% of base
salary) and an amount based on the maximum payout under the officer's grant of
performance-based restricted stock under the Company's long-term incentive
compensation plan (currently based on a percentage of base salary ranging from
60% to 90%). In addition, in the event of a covered termination, the new
agreements provide for certain additional benefits, including reimbursement of
certain expenses associated with obtaining new employment, provision of
financial planning services, provision of benefits under the Company's
supplemental retirement plans calculated as if the affected officer had
remained employed throughout a three-year period following the Change of
Control, and a tax gross-up payment in an amount necessary to make the officer
whole after payment of any excise tax resulting from payments under the
severance agreement and any associated income and other taxes. The term of the
new severance agreements is for three years from September 3, 1997.
14
<PAGE>
REPORT OF THE COMPENSATION COMMITTEE
ON EXECUTIVE COMPENSATION
The Compensation Committee (Committee) is composed entirely of directors who
are not officers or employees of the Company and who are not eligible to
participate in any of the compensation programs that the Committee
administers. The Committee reviews and makes recommendations to the Board
concerning all executive officer salary arrangements, other non-incentive
based compensation for executives and the design of the Company's incentive
compensation plans for executives. The Committee also oversees and administers
the Company's incentive compensation programs including the determination of
the annual and long-term incentive awards to the Company's executive officers.
COMPENSATION POLICY
The Company's executive compensation policy is to have compensation programs
that
. strengthen the relationship between pay and performance;
. attract, retain and encourage the development of highly qualified and
experienced executives;
. promote overall corporate performance; and
. provide compensation that is competitive externally and equitable
internally.
The Company retains independent consulting firms to provide, at least
biennially, data on the executive compensation practices of a peer group of
companies considered comparable to the Company in terms of size, performance,
position and compensation philosophy (Reference Group). Data concerning the
Reference Group is used primarily for establishing ranges for base salary and
target and opportunity levels for annual and long-term incentive awards. (The
Reference Group is not identical to the group of companies identified in the
Standard & Poor's group index of electric utility companies (S&P Electric
Companies Index) used in the creation of the Performance Graph included in
this proxy statement because the Committee believes that the Company's most
direct competitors for executive talent are not in all cases the same as the
companies included in the index chosen for comparing shareholder returns.)
The Committee also obtains peer group data regarding the performance of
groups of companies in the utility industry, the nonregulated power industry
and other industries. This industry-specific data is used primarily in the
formulation of performance measurements related to the Company's individual
subsidiaries or business units.
In addition to considering comparative data for the Reference Group and
other peer groups, the Committee makes its own subjective determination of
executive officer performance. In making such determinations, the Committee
also takes into account the chief executive officer's evaluations of other
executive officers' performance.
The Committee periodically evaluates the Company's executive compensation
programs in light of the provisions of the Internal Revenue Code relating to
the disallowance of deductions for compensation in excess of $1 million for
certain executive officers unless certain requirements are met. The Committee
does not anticipate any payment of compensation in 1998 or 1999 in excess of
that which is deductible under those rules, taking into account expected
deferrals of compensation by affected executive officers. Except for the long-
term performance incentive awards established for the Company's nonregulated
power business, the performance goals for awards under the Company's long-term
incentive awards program qualify for an exception to the deductibility limit
for certain shareholder-approved, performance-based compensation. In order for
this exception to the deductibility limit to continue to be applicable, a
description of the performance goals for long-term incentive awards under this
program and certain limitations on awards to any individual employee was
approved by the Company's shareholders at the Company's 1997 Annual Meeting of
Shareholders. An increase in the aggregate number of shares of Common Stock
available for awards under this program and an increase in the limitations on
awards for any individual have been approved by the Board of Directors at the
recommendation
15
<PAGE>
of the Committee and are being submitted for approval by the Company's
shareholders at the 1998 Annual Meeting. The Committee may consider in the
future whether or not to submit for shareholder approval the performance goals
applicable to the annual incentive awards or the long-term incentive awards
established for the Company's nonregulated power business, or make any
adjustments to the performance goals for those incentive awards that would be
necessary in order to qualify for the performance-based exception of the tax
provisions. The Company reserves the right to structure compensation in a
manner not eligible for exclusion from the deductibility limit.
The Committee will continue to evaluate the effect of the tax provisions and
the exception to the deductibility limit for certain shareholder-approved,
performance-based compensation.
COMPONENTS OF COMPENSATION
The key elements of the Company's executive compensation program are base
salary, annual incentive awards and long-term incentive awards. The Committee
evaluates each element of compensation separately and in relation to the other
elements of an executive's total compensation package, taking into
consideration relevant comparative data for compensation at the 50th
percentile and 75th percentile for companies in the Reference Group. Compared
to companies in the Reference Group, total targeted compensation may vary from
below the 50th percentile to above the 75th percentile depending on an
executive officer's tenure, experience, leadership and level of
responsibility. Because a significant portion of an executive officer's
compensation includes at-risk components based on business performance, if the
performance exceeds that of the relevant peer group, compensation should be
above the targeted levels; likewise, if performance falls below that of the
peer group, compensation should be below the targeted level.
BASE SALARIES
The Committee's annual recommendations to the Board concerning each
executive officer's base salary are based on the Committee's analysis of
salary levels for comparable executive officer positions at companies in the
Reference Group, its subjective evaluation and, except in the case of Mr.
Jordan, management's evaluation of each executive officer's individual
performance and level of responsibility.
ANNUAL INCENTIVE COMPENSATION
The annual incentive awards program provides executive officers with annual
bonuses based on the achievement of Committee-approved performance goals.
Those annually determined performance goals generally are based upon financial
objectives of the Company and its subsidiaries or business units and are
designed to encourage improved operating results and foster achievement of
particular strategic objectives. Performance goals for 1997 generally included
cash flow objectives and achieving certain ratings in a customer value index.
For the nonregulated power business, goals were based on achieving net profit
objectives for that business. Certain executive officers also had goals
related to improvements in productivity and the quality of work within
particular departments, including such matters as controlling various
categories of costs and expenses, promoting safety and reliability and
otherwise optimizing department operations.
Annual incentive awards for executive officers in 1997 had target award
levels that ranged from 30% to 80% of base salary depending on the executive
officer's level of responsibility. A threshold level of performance results in
an award that is 50% of target, and a maximum level of performance results in
an award that is 50% over the target level, except in the case of the
nonregulated power business where a maximum level of performance results in an
award that is 100% over the target level. However, an executive officer's
subsidiary or business unit goals must be met at least at an aggregate
threshold level in order for that officer to receive an annual incentive
award. For 1997, the composite goals for the Company's executive officers were
achieved at levels that resulted in bonuses ranging from 13% over target to
35% over target.
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LONG-TERM INCENTIVE COMPENSATION
The long-term incentive awards program provides stock-based incentive
compensation for executive officers in the form of grants of performance
shares, stock options, stock appreciation rights and, in some instances, share
equivalent or contingent share units. In addition, the Committee has adopted a
stock ownership guideline applicable to all of the Company's officers that
establishes a goal of ownership of the Company's Common Stock representing a
value of at least two times the officer's base salary.
Performance goals for the long-term incentive awards program are generally
based on financial objectives measurable over a three-year performance cycle.
For the performance cycle that ended in 1996, under which payments were made
in 1997, goals included a combination of consolidated and subsidiary or
business unit goals, weighted 25% and 75% of the total, respectively. The
Company's consolidated goal for this performance cycle was based on the
Company's ranking in total return to shareholders compared to a group of other
electric utilities and utility holding companies. The subsidiary or business
unit goals for this performance cycle were based on the following financial
objectives: for the electric utility operations, maintaining certain base
electric rates and achieving certain cash flow performance in relation to a
group of 21 other electric utility companies; for the cable television
operations (sold in 1995), achieving certain increases in operating profit;
and for the nonregulated power business, closing transactions related to
certain projects. The performance goals for the performance cycle that
commenced in 1997 consist of three objectives weighted equally: growth in
earnings per share, total return to shareholders relative to the S&P Electric
Companies Index, and cash return on capitalization from electric utility
transmission and distribution operations relative to the same peer group.
The target number of performance shares granted is based on a percentage of
base salary divided by the average market price of Common Stock over a
prescribed period prior to the beginning of the performance cycle. In
determining the size of the grant, the Committee reviews comparative data for
the companies in the Reference Group, considers the level of responsibility of
each of the Company's executive officers and the recommendations of the chief
executive officer with respect to other executive officers, and then makes a
subjective determination that targets the award within a range of 30% to 70%
of base salary.
Achievement of the performance goals at the target level results in a payout
level of 100% of the performance shares for both the performance cycle that
paid out in 1997 and the performance cycle that commenced in 1997. For both of
these performance cycles, attainment of the threshold level of performance
results in payouts of 50% of the target number of shares and the attainment of
the maximum level results in payouts of up to 50% over the target number of
shares.
For the performance cycle concluding in 1996 that paid out in 1997, the
composite goals for the Company's executive officers were achieved at levels
that resulted in payouts ranging from 1% under target to 4% over target.
Annual grants of stock options are made at an option price not less than the
fair market value of the Common Stock on the date of grant. This design is
intended to focus executive officers on the creation of shareholder value over
the long-term and encourage equity ownership in the Company.
In determining the size of stock option grants to executive officers, the
Committee reviews comparative data for the companies in the Reference Group.
Because the policies of Reference Group companies with respect to stock
options vary widely, the Committee's objective of delivering a competitive
award opportunity based on the dollar value of the award granted necessarily
involves a subjective determination by the Committee. In making its
determination, however, the Committee considers the recommendations of the
chief executive officer with respect to the awards for other executive
officers. For 1997 grants, the grant date value of the shares under option
ranged from 30% to 75% of base salary, depending on the executive officer's
position.
The Committee also grants long-term awards under a long-term incentive plan
established for the Company's nonregulated power business. Awards were made to
one executive officer of the Company under this plan during 1997 in lieu of
the grant of performance shares and stock options as described above. These
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1997 awards have a three-year performance cycle under which payouts in the
year 2000 are to be based on internal rates of return over the performance
cycle that are achieved on projects commenced during that period.
CHIEF EXECUTIVE OFFICER COMPENSATION
Under a new employment contract with Mr. Jordan entered into in February
1997 (and subsequently amended in November) providing for the extension of his
employment for two years beyond his normal retirement date, Mr. Jordan's base
salary will be in an amount not less than his salary in effect in January
1997, which was the same as his 1996 salary rate of $1,000,000 per year. Mr.
Jordan's base salary was not increased during 1997. Mr. Jordan's annual
incentive bonus for 1997 was determined using the criteria described above for
executive officers generally. His target annual incentive award for 1997 was
80% of his base salary, with the payment level based 70% on achievement of
cash flow objectives and 30% on achievement of customer value index ratings.
The 1997 annual incentive award payment (reflected in the Summary Compensation
Table in this proxy statement) was based on achievement of his composite goal
at 35% over the target level. In the case of awards under the long-term
incentive program, the target number of performance shares was valued at 70%
of Mr. Jordan's base salary for the performance cycle that paid out in 1997
and 70% of his base salary for the cycle that commenced in 1997. Mr. Jordan's
performance share awards for the cycle that paid out in 1997 were based 25% on
achievement of the Company's consolidated goal and 75% on achievement of the
subsidiary or business unit goals for the electric utility operations and the
since-sold cable television operations and the nonregulated power business
(60%, 30% and 10%, respectively). For the cycle that commenced in 1997, the
three goals for that cycle described above are weighted equally. Long-term
incentive awards paid out in 1997 are reported in the Summary Compensation
Table in this proxy statement and represent a composite achievement of 4% over
the target level of performance. Long-term incentive awards for the cycle
begun in 1997 are reflected in the table for Long-Term Incentive Plan Awards
in 1997 in this proxy statement. As shown in the table for Option Grants in
1997 in this proxy statement, Mr. Jordan was granted options to purchase
33,803 shares of the Company's Common Stock at an exercise price of $22.1875
per share. This represents a grant date value of the shares under option equal
to approximately 75% of Mr. Jordan's 1996 year-end base salary.
The Committee and the full Board of Directors determined that entering into
a new employment contract with Mr. Jordan extending his employment for two
years beyond his normal retirement date was in the best interests of the
Company and its shareholders because of the extremely rapid pace of change in
the industry and the Committee's subjective evaluation of the benefits of Mr.
Jordan's experience, knowledge and industry leadership in positioning the
Company to best meet the challenges and exploit the opportunities of this
period of transition. In connection with the new agreement, it was agreed that
Mr. Jordan would not participate in the Company's long-term incentive program
for any performance cycle beginning after the one that commenced in 1997.
Instead, he received a grant of 150,000 restricted shares of Common Stock
which vest based solely on his continued service during the extended
employment period, and an additional 150,000 restricted shares of Common Stock
which vest based both on continued service and on achievement of the same
performance goals that are applicable to his award under the long-term
incentive compensation plan for the cycle that commenced in 1997 (as described
in the preceding paragraph). The first 150,000 share grant is shown as a grant
of restricted stock in the Summary Compensation Table and the second grant is
shown as an additional award in the table for Long-Term Incentive Plan awards
for 1997. In addition, the new agreement provides for the extension of the
commencement date of deferred payments under the Company's deferred
compensation plan, providing him the continued benefit of above-market
interest rates on the deferrals during the period of the extension. Additional
details regarding the employment contract are shown elsewhere in this Proxy
Statement.
Robert J. Cruikshank
Richard E. Balzhiser
Linnet F. Deily
Robert C. Hanna
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SHAREHOLDER RETURN PERFORMANCE GRAPH
Set forth below is a line graph comparing the yearly percentage change in
the cumulative total shareholder return on the Common Stock with the
cumulative total return of the S&P 500 Index and the S&P Electric Companies
Index for the period commencing January 1, 1993 and ending December 31, 1997.
COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN
AMONG HOUSTON INDUSTRIES INCORPORATED, S&P 500 INDEX AND
THE S&P ELECTRIC COMPANIES INDEX
FOR FISCAL YEAR ENDED DECEMBER 31(1)(2)
LOGO
[Graph appears here]
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1992 1993 1994 1995 1996 1997
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Houston Industries Incorporated.................. $100 $111 $ 90 $132 $131 $166
S&P 500 Index.................................... $100 $110 $112 $153 $189 $252
S&P Electric Companies Index..................... $100 $113 $ 98 $128 $128 $162
</TABLE>
- --------
(1) Assumes that the value of the investment in Common Stock and each index
was $100 on December 31, 1992 and that all dividends were reinvested.
(2) Historical stock price performance is not necessarily indicative of future
price performance.
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PROPOSAL TO AMEND THE COMPANY'S 1994
LONG-TERM INCENTIVE COMPENSATION PLAN
In 1993, the Company's Board of Directors adopted and the shareholders
approved the 1994 Houston Industries Incorporated Long-Term Incentive
Compensation Plan (Plan). Officers and key employees (collectively, key
employees) of the Company and its subsidiaries are eligible to participate in
the Plan. The maximum number of shares of Common Stock as to which awards can
be granted under the Plan as currently in effect (after adjustment for a two-
for-one stock split in 1995 and after the 1997 amendment described below) is
eight million shares.
The Board of Directors believes that the Plan has been important in securing
for the Company and its shareholders the benefits arising from ownership of
Common Stock by key employees. The objectives of the Plan are to attract and
retain key employees of the Company and its subsidiaries, to award the
outstanding performance of such key employees, to encourage the sense of
proprietorship of such key employees and to stimulate the active interest of
such persons in the development and financial success of the Company and its
subsidiaries. These objectives are to be accomplished by making awards under
the Plan and thereby providing participants with a proprietary interest in the
growth and performance of the Company and its subsidiaries.
In 1997, for purposes of satisfying the requirements under Section 162(m) of
the Internal Revenue Code of 1986, as amended (the "Code") and to increase the
maximum number of shares subject to grant under the Plan, the Board of
Directors adopted, and the shareholders of the Company approved at the 1997
Annual Meeting of Shareholders, an amendment to the Plan. The 1997 amendment
(i) imposed a maximum annual individual limit on the number of shares subject
to an option or subject to a restricted stock award, (ii) described the
general financial and strategic goals utilized as performance-based objectives
under the Plan and (iii) increased the number of shares of Common Stock
available for awards under the Plan to eight million shares.
DESCRIPTION OF PLAN AMENDMENT
On March 4, 1998, the Board of Directors adopted, subject to and effective
upon shareholder approval, an amendment to the Plan (Plan Amendment) which
would increase the number of shares of Common Stock subject to the Plan by an
additional ten million shares and increase the annual limit on the number of
shares subject to grants of stock options to any one individual from 50,000
shares of Common Stock to 500,000 shares. The Plan Amendment would not change
the 50,000 share per year limitation on Common Stock that is the subject of
performance-based restricted stock awards. The following description of the
Plan Amendment is qualified in its entirety by reference to the full text
thereof, a copy of which is attached as Exhibit A to this Proxy Statement.
DISCUSSION OF THE CHANGES
The Plan Amendment reflects the Company's increased emphasis on equity
compensation as a means of aligning the interests of key employees and
shareholders. The increased aggregate number of shares available will allow
for increased annual utilization of shares for awards to a larger group of
participants. The increase in the annual limitation on the number of shares
that may be covered by a stock option granted to any one individual will allow
for weighting compensation more heavily in favor of stock option grants in the
future, in appropriate cases. Under the Plan, the exercise price of a stock
option (and strike price of any related stock appreciation right) may not be
less than the fair market value of the underlying Common Stock on the date of
grant. The Plan Amendment will not increase the annual limitation on grants of
performance-based restricted stock to any individual.
The maximum grant provision in the Plan approved by the 1997 Annual Meeting
of Shareholders was intended to enable the Company to comply with Section
162(m) of the Code. Section 162(m) of the Code (adopted in 1993), disallows
deductions for compensation in excess of $1 million for certain executive
officers of publicly held corporations, unless such compensation meets the
requirements of Section 162(m) as "performance-based compensation." In order
to continue to meet the requirements of Section 162(m), the
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<PAGE>
Company's shareholders must approve changes to certain material terms under
which the compensation is payable. If the Plan Amendment is approved by the
shareholders, the Company will continue to be entitled to deduct for tax
purposes compensation paid under the Plan to its Chief Executive Officer and
other participating officers notwithstanding the $1 million limitation under
Code Section 162(m).
The Plan Amendment, if approved by the Company's shareholders, will increase
the aggregate authorized shares of Common Stock issuable under the Plan by ten
million shares. As of March 23, 1998, 12,351 shares of Common Stock have been
issued under the Plan and 2,680,416 shares were subject to issuance upon
exercise of outstanding options or the vesting of performance-based restricted
stock awards and 5,307,233 shares were subject to issuance pursuant to future
grants. Options covering 125,830 shares have been previously granted under the
Plan to Mr. Jordan, 133,865 shares to Mr. Letbetter, 50,000 shares to Mr.
Hogan, 74,739 shares to Mr. Kelly, 62,639 shares to Mr. Naeve and 663,763
shares to all executive officers as a group and 1,235,321 shares to all
employees other than executive officers. Performance-based restricted stock
awards covering a maximum of 88,763 shares have been previously granted under
the Plan to Mr. Jordan, 46,742 shares to Mr. Letbetter, 27,514 shares to Mr.
Hogan, 27,402 shares to Mr. Kelly, 19,094 shares to Mr. Naeve and 259,768
shares to all executive officers as a group and 388,084 shares to all
employees other than executive officers. The closing market price of Common
Stock on March 23, 1998 as reported in The Wall Street Journal was $27.875 per
share. After giving effect to the proposed ten million share increase, the
number of shares of Common Stock subject to issuance pursuant to future grants
will be 15,307,233.
SUMMARY OF THE PLAN
The Plan is administered solely by the Compensation Committee of the
Company's Board of Directors. The Compensation Committee selects the
participants and determines the type or types of awards and the number of
shares to be optioned or granted to each participant under the Plan.
Participants who may be granted awards under the Plan include all officers and
key employees of the Company and its subsidiary corporations. All or part of
an award may be subject to conditions established by the Committee, which may
include continuous service with the Company and its subsidiaries, achievement
of specific business objectives and other comparable measurements of
performance.
The types of awards that may be made under the Plan are as follows:
Stock Awards. The Plan provides for granting restricted stock awards and for
making additional awards of opportunity shares in connection with such
restricted stock awards. All stock awards are subject to the achievement of
performance-related target objectives (Performance Objectives) by the Company
and its subsidiaries. The degree to which the Company and its subsidiaries
achieve Performance Objectives will serve as the basis for the Compensation
Committee's determination of the portion of shares covered by a restricted
stock award which will become vested by reason of the lapse of restrictions
and the amount of additional opportunity shares, if any, relating to such
restricted stock award which will be awarded. It is anticipated that these
restrictions will lapse and that opportunity shares will be granted as
follows: (1) a threshold (minimum) level of achievement will result in 50% of
the restricted shares being vested but no opportunity shares will vest; (2) a
target level of achievement will result in 100% of the restricted shares being
vested but no opportunity shares will vest; and (3) a maximum level of
achievement will result in both 100% of the restricted shares and 100% of the
opportunity shares being vested. A minimum, or threshold, level of achievement
must be accomplished before any vesting of restricted shares will occur. For
achievement between any two levels, restricted shares or opportunity shares,
as applicable, will vest on a pro rata basis.
The Compensation Committee will establish Performance Objectives for a
specified period of not less than one year nor more than six years
(Performance Cycle). The criteria by which the Company's performance will be
measured for the purpose of awarding restricted stock and opportunity shares
is now based upon targets established by the Committee with respect to one or
more of the following financial factors: earnings per share growth, total
return ranking among S&P Electric Companies Index, and cash return on
capitalization ranking
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<PAGE>
among S&P Electric Companies Index. Restricted stock awards and the allocation
of opportunity shares which may be awarded in connection with such restricted
stock awards will be made not later than 90 days after the beginning of a
Performance Cycle, but may, in the Compensation Committee's discretion, be
made from time to time during a Performance Cycle to an officer or key
employee hired or promoted after the commencement of the Performance Cycle. No
key employee may receive a restricted stock award (including an award of
opportunity shares) during any calendar year for a number of shares in excess
of 50,000 shares.
The grant of a restricted stock award may be implemented by (1) credit to a
bookkeeping account maintained by the Company evidencing the accrual to a key
employee of unsecured and unfunded rights to shares of Common Stock or (2)
delivery of certificates for shares of Common Stock to the key employee, who
must execute appropriate stock powers in blank and return the certificates and
stock powers to the Company to be held in escrow for future delivery in
accordance with the terms of the restricted stock award.
No key employee granted a restricted stock award implemented by credit to a
Company bookkeeping account shall have any rights as a shareholder by virtue
of such grant until shares are actually issued or delivered to such key
employee. The grant of such stock award may provide that the key employee
shall be entitled to receive an amount equivalent to any dividend payable with
respect to the number of shares which, as of the record date for which
dividends are payable, have been credited but not delivered to such key
employee. As provided in the grant, such dividend equivalents may be (1) paid
at such time or times as dividends are paid on shares of Common Stock during
the period when such shares are as yet undelivered, (2) paid at the time the
shares to which the dividend equivalents apply are delivered or (3) reflected
by the credit of additional full or fractional shares in an amount equal to
the amount of such dividend equivalents divided by the fair market value of a
full share of Common Stock on the date of payment of the dividend on which the
dividend equivalent is based. Any arrangement for the payment or credit of
dividend equivalents will terminate if and to the extent that the right to
receive shares of Common Stock pursuant to the terms of the restricted stock
award terminates or lapses.
A key employee granted a restricted stock award that is implemented by
issuance of a stock certificate will have, at the time of such grant, all of
the benefits of ownership in respect of such shares, including the right to
receive dividends thereon and to vote such shares, subject to the restrictions
set forth in the Plan and in the instrument evidencing the grant of such
restricted stock award. Such shares, however, will be held in escrow and,
until the restrictions set forth in the Plan have lapsed, (1) may not be sold
or otherwise disposed of, and (2) are required to be returned to the Company
to the extent that the Compensation Committee determines that the Company did
not achieve the Performance Objectives established for the Performance Cycle
with respect to which the shares were awarded, or if the employment of the key
employee to whom the restricted stock award has been granted is terminated for
any reason other than a reason which causes such restrictions to lapse (as
hereinafter described). Additional restrictions may be imposed by the
Compensation Committee on individual restricted stock awards, which
restrictions will lapse as to all or a portion of the shares covered by a
restricted stock award (and additional opportunity shares may be awarded), as
more fully described in the Plan, (1) if the Compensation Committee determines
that the Performance Objectives established for the Performance Cycle with
respect to which the shares were awarded have been achieved or (2) upon the
key employee's death, long-term disability or retirement on or after age 60 or
if such key employee's employment is terminated by the Company without cause.
In addition, upon a change in control of the Company (as defined in the Plan),
the Company shall pay cash to each key employee to whom a restricted stock
award has been made (and with respect to which the restrictions have not
previously lapsed) in an amount equal to the number of shares granted pursuant
to such restricted stock awards and all related opportunity shares times the
fair market value of the Common Stock on the date of the change in control.
Related Tax Payments. Each key employee who has received shares pursuant to
a restricted stock award with respect to which all of the restrictions set
forth in the Plan have lapsed or pursuant to an award of opportunity shares
related to such restricted stock award may also receive from the Company a
cash payment in an amount, if any, determined by the Compensation Committee,
not to exceed that amount sufficient to pay such
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<PAGE>
key employee's tax liability (assuming the highest rates of tax applicable to
any individual taxpayer in the year in which such payment is made) with
respect to (1) such shares and (2) such cash payment.
Stock Options and SARs. In addition to stock awards, the Plan provides for
granting (1) incentive stock options, (2) nonstatutory stock options and (3)
stock appreciation rights (SARs).
Incentive and nonstatutory stock options may be granted to a key employee
either alone or with an attached SAR. The number of shares, the exercise
price, the terms and conditions of exercise, whether the option will qualify
as an incentive stock option under the Code or a nonqualified stock option,
and other terms of grant will be fixed by the Compensation Committee and set
forth in an option agreement; provided, that no key employee may receive a
stock option grant during any calender year for a number of shares in excess
of 50,000 shares (to be changed to 500,000 shares under the Plan Amendment).
The price payable upon exercise of an option may not be less than the fair
market value per share of the Common Stock at the time of the grant, and may
be paid either in cash or, with the consent of the Compensation Committee,
with shares of Common Stock or a combination thereof.
An option designed as an incentive stock option is intended to qualify as
such under Section 422 of the Code. Thus, the aggregate fair market value,
determined at the time of the grant, of the shares with respect to which
incentive stock options are exercisable for the first time by an individual
during any calendar year may not exceed $100,000. Nonstatutory stock options
are not subject to this limitation.
No stock option may be exercised until at least one year after the date of
the grant, except that this restriction shall cease to apply upon and
simultaneously with a change in control of the Company (as defined in the
Plan). No option may be outstanding for more than ten years after its grant.
If an SAR is granted together with a stock option, such a right will entitle
the holder to receive upon exercise of the SAR cash or, at the election of the
Compensation Committee, shares of Common Stock or a combination thereof in an
amount equal to the difference between the option exercise price and the
market value (on the date of grant) of the shares of Common Stock subject to
such option. The exercise of an SAR shall be in lieu of the exercise of the
related stock option. SARs generally may be exercised only at such times and
to the extent the options to which they relate are exercisable.
Stock options and SARs are nontransferable other than by will or the laws of
descent and distribution. The legal representatives of a deceased key employee
may exercise a stock option or the attached SAR, to the extent it is
exercisable on the date of death, within three years after the death of the
key employee. A stock option and any attached SAR may be exercised, to the
extent it is exercisable on the date of the event, within 90 days, in the case
of an incentive stock option, and three years in the case of a nonstatutory
stock option, following early retirement, disability or termination of
employment of the key employee; provided, however, that a stock option and any
attached SAR will terminate on the date of discharge of such key employee if
the Compensation Committee determines in its discretion that it is not in the
best interests of the Company that the right of such discharged key employee
to exercise the stock option or attached SAR continue. All stock options and
any attached SARs become fully exercisable and may be exercised within 90
days, in the case of an incentive stock option, and three years, in the case
of a nonstatutory stock option, following retirement on or after age 65.
The number and kind of shares covered by the Plan and by outstanding options
under the Plan are subject to adjustment in the event of any reorganization,
recapitalization, reclassification or other changes in the capital stock or
increase or decrease in the number of outstanding shares of Common Stock.
Amendment and Termination. The Plan may be amended, modified, suspended or
terminated by the Board of Directors. No amendment shall be effective prior to
approval of the shareholders to the extent such approval is then required
pursuant to Rule 16b-3 under the Securities Exchange Act of 1934 in order to
preserve the applicability of any exemption provided by such rule to any stock
incentive then outstanding (unless the holder consents) or to the extent
shareholder approval is otherwise required by applicable legal requirements.
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The Board of Directors may terminate the Plan as of any date specified in a
resolution adopted by the Board for that purpose. If not earlier terminated,
the Plan shall terminate on February 2, 2003. No stock incentives may be
granted after the Plan has terminated.
Federal Income Tax Consequences Relating to Options and SARs. Some of the
options issuable under the Plan may constitute incentive stock options within
the meaning of Section 422 of the Code, while other options granted under the
Plan may be non-qualified stock options. The Code provides for tax treatment
of stock options qualifying as incentive stock options which may be more
favorable to employees than the tax treatment accorded non-qualified stock
options. Generally, upon the exercise of an incentive stock option, the
optionee will recognize no income for U.S. federal income tax purposes. The
difference between the exercise price of the incentive stock option and the
fair market value of the stock at the time of exercise is an item of tax
preference that may require payment of an alternative minimum tax. On the sale
of shares acquired by exercise of an incentive stock option (assuming that the
sale does not occur within two years of the date of grant of the option or
within one year from the date of exercise), any gain will be taxed to the
optionee as mid-term or long-term capital gain (depending on the holding
period). In contrast, upon the exercise of a non-qualified option, the
optionee recognizes taxable income (subject to withholding) in an amount equal
to the difference between the then-fair market value of the shares on the date
of exercise and the exercise price. Upon any sale of such shares by the
optionee, any difference between the sale price and the fair market value of
the shares on the date of exercise of the non-qualified option will be treated
generally as capital gain or loss. No deduction is available to the Company
upon the grant or exercise of an incentive stock option (although a deduction
may be available if the employee sells the shares so purchased before the
applicable holding period expires), whereas upon exercise of a non-qualified
stock option, the Company is entitled to a deduction in an amount equal to the
income recognized by the employee. Except with respect to death or disability
of an optionee, an optionee has three months after termination of employment
in which to exercise an incentive stock option and retain favorable tax
treatment at exercise. An option exercised more than three months after an
optionee's termination of employment other than upon death or disability of an
optionee cannot qualify for the tax treatment accorded incentive stock
options. Such option would be treated as a non-qualified stock option instead.
The amount of any cash or the fair market value of any stock received by the
holder upon the exercise of SARs under the Plan will be subject to ordinary
income tax in the year of receipt, and the Company will be entitled to a
deduction for such amount.
A participant's tax basis in shares purchased under the Plan is equal to the
sum of the price paid for the shares, if any, and the amount of ordinary
income recognized by the participant on the transfer of the shares. The
participant's holding period for the shares begins immediately after the
transfer of the shares. If a participant sells shares, any difference between
the amount realized in the sale and the participant's tax basis in the shares
is taxed as long-term, mid-term or short-term capital gain or loss (provided
the shares are held as a capital asset on the date of sale), depending on the
participant's holding period for the shares.
Based on the provisions of the Plan, the Company expects that options and
SARs under the Plan will comply with the requirements of Section 162(m) of the
Code.
REQUISITE VOTE
The vote required for approval of the Plan Amendment is the affirmative vote
of a majority of the shares of Common Stock voted for or against the matter.
In addition, approval of the Plan Amendment requires that the total votes cast
on the matter exceed 50% of the shares of Common Stock outstanding and
entitled to vote. If the requisite vote is not obtained, the amendment will
not become effective.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR APPROVAL OF THE PLAN AMENDMENT.
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RATIFICATION OF APPOINTMENT OF INDEPENDENT ACCOUNTANTS AND AUDITORS
The Board of Directors, upon the recommendation of the Audit Committee, has
appointed Deloitte & Touche LLP as independent accountants and auditors to
conduct the annual audit of the Company's accounts for the year 1998. Deloitte
& Touche LLP (and their predecessors) have served as independent accountants
and auditors for the Company since 1932. Approval of Item 3 requires the
affirmative vote of a majority of shares of Common Stock voted for or against
the matter. If ratification of the appointment is not approved, the Board will
reconsider the appointment.
Representatives of Deloitte & Touche LLP will be present at the Annual
Meeting and will have an opportunity to make a statement if they desire. They
will be available to respond to appropriate questions from shareholders at the
Annual Meeting.
THE BOARD OF DIRECTORS RECOMMENDS A VOTE FOR THE RATIFICATION OF THE
APPOINTMENT OF DELOITTE & TOUCHE LLP AS INDEPENDENT ACCOUNTANTS AND AUDITORS.
OTHER MATTERS
The Board of Directors does not intend to bring any other matters before the
Annual Meeting and has not been informed that any other matters are to be
property presented to the Annual Meeting by others. In the event that other
matters properly come before the Annual Meeting or any adjournments thereof,
it is intended that the persons named in the accompanying proxy will vote
pursuant to the proxy in accordance with their best judgment on such matters.
SHAREHOLDER PROPOSALS FOR 1999 ANNUAL MEETING OF SHAREHOLDERS
Any shareholder who intends to present a proposal at the 1999 annual meeting
of shareholders and who requests inclusion of the proposal in the Company's
proxy statement and form of proxy relating to that meeting in accordance with
applicable rules of the SEC must file such proposal with the Company by
November 27, 1998.
DIRECTOR NOMINATIONS FOR 1999 ANNUAL MEETING OF SHAREHOLDERS
The Company's Bylaws provide for shareholder nominations for the election of
directors, subject to certain procedural requirements. The requirements
include, among other things, the timely delivery to the Company's Corporate
Secretary of (i) notice of the nomination; (ii) evidence of the shareholder's
status as such and the number of shares beneficially owned; and (iii) a list
of the persons (if any) with whom the shareholder is acting in concert and the
number of shares such persons beneficially own. The Bylaws also provide that,
to be timely in connection with an annual meeting of shareholders, a
shareholder's notice shall be delivered to or mailed and received at the
principal executive offices of the Company not less than 90 days nor more than
180 days prior to the date on which the immediately preceding year's annual
meeting of shareholders was held. For the 1999 annual meeting, therefore,
nominations must be received no later than February 5, 1999 nor earlier than
November 7, 1998. The Bylaws further provide that a shareholder wishing to
make a nomination must submit information concerning the nominee such as would
be required by a proxy statement. The Bylaws provide that failure to follow
the required procedures renders the person ineligible for nomination at the
meeting at which such person is proposed to be nominated. Compliance with the
procedures does not require the Company to include the proposed nominee in the
Company's proxy solicitation material. A copy of the Bylaws setting forth the
requirements for the nomination of director candidates by shareholders may be
obtained by writing Mr. Hugh Rice Kelly, Corporate Secretary, at the Company's
address shown above.
25
<PAGE>
ANNUAL REPORT TO SHAREHOLDERS
The Summary Annual Report to Shareholders, together with the enclosed
Appendix A--1997 Financial Statements, which contains the Company's
consolidated financial statements for the year ended December 31, 1997,
accompany the proxy material being mailed to all shareholders. The Summary
Annual Report is not a part of the proxy solicitation material.
By Order of the Board of Directors,
LOGO
/s/ Don D. Jordan
Don D. Jordan
Chairman and Chief Executive Officer
March 27, 1998
26
<PAGE>
EXHIBIT A
1994 HOUSTON INDUSTRIES INCORPORATED
LONG-TERM INCENTIVE COMPENSATION PLAN
PROPOSED AMENDMENT
1. The first two sentences of Section 3.2 of the Plan are hereby amended to
read as follows:
"The aggregate number of shares of Common Stock which may be issued under
this Plan shall not exceed Eighteen Million (18,000,000) shares, subject to
adjustment as hereinafter provided. All or any part of such Eighteen
Million shares may be issued pursuant to Stock Awards."
2. The last sentence of Section 3.2 of the Plan is hereby amended in its
entirety to read as follows:
"Notwithstanding anything herein to the contrary, no Key Employee may be
granted, during any calendar year, (i) Options (including Stock
Appreciation Rights) covering, in the aggregate, more than 500,000 shares
of Common Stock authorized under the Plan or (ii) Restricted Stock Awards
(including "opportunity shares') covering, in the aggregate, more than
50,000 shares of Common Stock authorized under the Plan, in each case
subject to adjustment in the same manner provided in Section 13.3."
A-1
<PAGE>
LOGO
[LOGO OF HOUSTON INDUSTRIES APPEARS HERE]
<PAGE>
[LOGO OF HOUSTON INDUSTRIES APPEARS HERE]
HOUSTON INDUSTRIES INCORPORATED
1997 FINANCIAL STATEMENTS
APPENDIX A
<PAGE>
Table of Contents
Management's Discussion and Analysis of Financial Condition
and Results of Operations......................................... 1
Quantitative and Qualitative Disclosures About Market Risk.......... 24
Statements of Consolidated Income................................... 27
Statements of Consolidated Retained Earnings........................ 29
Consolidated Balance Sheets......................................... 30
Consolidated Statements of Capitalization........................... 32
Statements of Consolidated Cash Flows............................... 35
Notes to Consolidated Financial Statements.......................... 37
Independent Auditors' Report........................................ 73
<PAGE>
HOUSTON INDUSTRIES INCORPORATED
1997 FINANCIAL INFORMATION
This Appendix A is derived from Item 7 (Management's Discussion and Analysis
of Financial Condition and Results of Operations), Item 7A (Quantitative and
Qualitative Disclosures About Market Risk) and Item 8 (Financial Statements and
Supplementary Data) of the Annual Report on Form 10-K of Houston Industries
Incorporated (Company) for the year ended December 31, 1997 (Form 10-K). A copy
of the Form 10-K can be obtained without charge by contacting the Investor
Relations department of the Company at the address set forth in the Company's
1998 Annual Report to Shareholders. Reference is made to the Form 10-K for
additional information about the business and operations of the Company and its
subsidiaries.
FORWARD-LOOKING STATEMENTS
Statements contained in this Appendix A that are not historical facts are
forward-looking statements as defined in the Private Securities Litigation
Reform Act of 1995. Forward-looking statements are based on management's beliefs
as well as assumptions made by and information currently available to
management. Because such statements are based on assumptions as to future
economic performance and are not statements of fact, actual results may differ
materially from those projected. Important factors that could cause future
results to differ include (i) the effects of competition in the electric power
and natural gas industries, (ii) legislative and regulatory changes, (iii)
fluctuations in the weather, (iv) fluctuations in energy commodity prices, (v)
environmental liabilities, (vi) changes in the economy and (vii) other factors
discussed in this and other filings by the Company with the Securities and
Exchange Commission. When used in the documents or oral presentations, the words
"anticipate," "estimate," "expect," "intend," "objective," "projection,"
"forecast," "goal" or similar words are intended to identify forward-looking
statements.
The following sections of this Appendix A contain forward-looking statements:
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Results of Operations by Business Segment -- Energy Marketing,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Results of Operations by Business Segment -- Corporate,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Future Earnings of the Company and its
Subsidiaries," and "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity and Capital Resources -- Company
Consolidated Capital Requirements" and "Quantitative and Qualitative Disclosures
about Market Risk".
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The following discussion and analysis should be read in combination with the
Company's consolidated financial statements and notes contained in Item 8 below
(Company's Consolidated Financial Statements).
HOUSTON INDUSTRIES INCORPORATED
Houston Industries Incorporated (Company) is a diversified international
energy services company. It operates the nation's tenth largest electric utility
in terms of kilowatt-hour (KWH) sales, and its three natural gas distribution
divisions together form the nation's third largest natural gas distribution
operation in terms of customers served. The Company also invests in
international and domestic electric utility privatizations, gas distribution
projects and the development of unregulated power generation projects. The
Company is also a major interstate natural gas pipeline and energy services
company, providing gas transportation, supply, gathering and storage, and
wholesale natural gas and electric power marketing services.
The Company is exempt from regulation as a public utility holding company
pursuant to Section 3(a)(2) of the Public Utility Holding Company Act of 1935,
as amended (1935 Act), except with respect to the acquisition of certain voting
securities of other domestic public utility companies and utility holding
companies.
1
<PAGE>
CONSOLIDATED RESULTS OF OPERATIONS
On August 6, 1997, the Company completed its acquisition (Merger) of NorAm
Energy Corp. (NorAm), a natural gas gathering, transmission, marketing and
distribution company. The Merger was accounted for as a purchase; accordingly,
the Company's results of operations for 1997 include NorAm's results of
operations beginning on August 6, 1997 (Acquisition Date).
To enhance comparability between reporting periods, certain information below
is presented on a pro forma basis and reflects the acquisition of NorAm as if it
had occurred at the beginning of the 1996 and 1997 reporting periods presented.
Pro forma purchase-related adjustments include amortization of goodwill and the
revaluation on a preliminary basis of the fair value of certain NorAm assets and
liabilities. The pro forma results of operations are not necessarily indicative
of the combined results of operations that actually would have occurred had the
acquisition occurred on such dates. The Company, however, believes that the
presentation of pro forma data provides a more meaningful comparative standard
for assessing changes in the Company's consolidated financial condition and
results of operations during the years ended December 31, 1997 and 1996, since
the pro forma presentation combines a full year of results of the Company and
its acquired NorAm operations.
In general, the Company's 1997 results of operations and prior year pro forma
amounts reflect the effects of the acquisition of NorAm, which include (i)
significant increases in amortization attributable to purchase accounting, (ii)
increases in shares outstanding and interest expense, and (iii) the impact of
revenues and operating expenses attributable to the newly acquired NorAm
business units.
CONSOLIDATED RESULTS OF OPERATIONS
<TABLE>
<CAPTION>
UNAUDITED PRO
ACTUAL FORMA
-------------------- -------------
TWELVE MONTHS TWELVE MONTHS
ENDED DECEMBER ENDED DECEMBER
31, 31,
-------------------- -------------
PERCENT PERCENT
1997 1996 CHANGE 1997 1996 CHANGE
---- ---- ------ ---- ---- ------
(IN MILLIONS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Revenues $6,873 $4,095 68% $10,210 $8,884 15%
Operating Expenses 5,809 3,105 87% 8,991 7,612 18%
Operating Income 1,065 990 8% 1,219 1,272 (4%)
Other Expenses, Net(1) 437 385 14% 546 595 (8%)
Income Taxes 206 200 3% 234 245 (4%)
Net Income(2) 421 405 4% 439 432 2%
Basic Earnings Per Share 1.66 1.66 1.56 1.48 5%
Diluted Earnings Per Share 1.66 1.66 1.56 1.48 5%
</TABLE>
__________
(1) Includes a $121 million unrealized accounting loss incurred in the fourth
quarter of 1997 relating to the Company's 7% Automatic Common Exchange
Securities (ACES). See Note 1(n) to the Company's Consolidated Financial
Statements.
(2) Includes $37 million of interest income attributable to a tax refund in
1997.
2
<PAGE>
ACTUAL
--------------
TWELVE MONTHS
ENDED DECEMBER
31,
-------------- PERCENT
1996 1995 CHANGE
------ ------ -------
Revenues............................ $4,095 $3,729 10%
Operating Expenses.................. 3,105 2,824 10%
Operating Income.................... 990 905 9%
Other Expenses, Net................. 385 308 25%
Income Taxes........................ 200 200
Income from Continuing Operations... 405 397 2%
Gain from Discontinued Operations... 708
Net Income.......................... 405 1,105 (63%)
Basic Earnings Per Share............ 1.66 1.60 4%
Diluted Earnings Per Share.......... 1.66 1.60 4%
1997 Compared to 1996 (Actual). The Company's actual consolidated net income
from continuing operations for 1997 was $421 million ($1.66 per share) compared
to $405 million ($1.66 per share) in 1996. Although income increased by $16
million, the Company's basic and diluted earnings per share remained the same
due to the issuance of approximately 47.8 million additional shares of the
Company's common stock as a portion of the consideration paid in connection with
the Merger. The Company's income from continuing operations reflects net non-
recurring and other after-tax charges amounting to $42 million in 1997 and $67
million in 1996. Charges in 1997 included a non-cash, unrealized accounting loss
of $79 million on the ACES, which were issued in July 1997, partially offset by
$37 million of interest income related to a refund of federal income taxes in
1997. For a discussion of the accounting loss in connection with the ACES, see
"-- Certain Factors Affecting Future Earnings of the Company and its
Subsidiaries -- Accounting Treatment of ACES." The non-recurring, after-tax
charges in 1996 included a $62 million charge taken in connection with the
settlement of South Texas Project Electric Generating Station (South Texas
Project) litigation claims and a $5 million loss associated with Houston
Industries Energy, Inc.'s (HI Energy) investment in two tire-to- energy plants
in Illinois.
After adjusting for non-recurring and other charges in both years, income from
continuing operations for 1997 would have been $463 million ($1.83 per share)
compared to $472 million ($1.93 per share) in 1996. The decrease is due in part
to the additional amortization of certain lignite reserves by the Company's
electric operations division (Electric Operations), the amortization of goodwill
recorded upon the Merger and increased interest expense. The increase in
interest on long-term debt and other interest on the Company's Statements of
Consolidated Income reflect both (i) the $1.4 billion indebtedness incurred by
the Company to fund a portion of the cost of the Merger and (ii) the
consolidation of NorAm's existing indebtedness with that of the Company.
Partially offsetting these effects were increased Electric Operations' sales due
to customer growth, improved results at HI Energy and the additional operating
income generated by the new business units acquired in the Merger.
1997 Compared to 1996 (Pro Forma). The Company's pro forma consolidated
earnings for 1997 were $439 million ($1.56 per share) compared with $432 million
($1.48 per share) in 1996.
Excluding the non-recurring and other charges described above, the Company's
1997 pro forma income from continuing operations would have been $481 million
($1.71 per share) compared to $499 million ($1.71 per share) in 1996. This
decrease in pro forma earnings, as adjusted for non-recurring and other charges,
is principally the result of (i) hedging-related losses incurred in the first
quarter of 1997 (prior to the Merger) by a subsidiary of NorAm, which losses are
not reflected in the Company's actual results of operations since they were
incurred prior to the Merger, (ii) a weather-related decline in sales volumes
from the natural gas distribution segment, and (iii) increased administrative
and general expenses associated with increased staffing and marketing in
connection with increasing the scope of energy marketing activities.
3
<PAGE>
Pro forma consolidated net income for 1997 and 1996 exceeds actual
consolidated net income for such years because purchase-related costs were more
than offset on a pro forma basis by NorAm's earnings for the periods prior to
the Acquisition Date. Such earnings were not part of the reported actual
results.
1996 Compared to 1995 (Actual). Consolidated income from continuing operations
was $405 million ($1.66 per share) for 1996, compared to income from continuing
operations of $397 million ($1.60 per share) in 1995. The Company's 1995 net
income was $1.1 billion ($4.46 per share) including a one-time after-tax gain of
$708 million ($2.86 per share) recorded upon the sale of the Company's cable
television subsidiary.
The Company's net income includes non-recurring, after-tax charges amounting
to $67 million described above in 1996 and $24 million primarily related to the
write-down of HI Energy's Illinois tire-to-energy plant investment in 1995.
After adjusting for non-recurring gains and charges in both years, consolidated
basic and diluted per share earnings from continuing operations rose nearly 14%
to $1.93 in 1996 from $1.70 in 1995, while income from continuing operations
rose to $472 million in 1996 from $422 million the previous year. The
improvement in earnings resulted from increased sales at Electric Operations,
improved results at HI Energy and a full year of after-tax dividend income ($37
million in 1996 compared to $18 million in 1995) from the Company's investment
in Time Warner Inc. (Time Warner) securities.
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
In order to reflect the changes in the Company's business resulting from the
acquisition of NorAm, the Company has organized its financial reporting segments
into Electric Operations, Natural Gas Distribution, Interstate Pipeline, Energy
Marketing, International and Corporate. The business and operations of each of
these segments are described below and are shown for comparative purposes on a
pro forma basis.
All business segment data (other than data relating to Electric Operations)
are presented on a pro forma basis as if the acquisition of NorAm had occurred
on January 1 of the period presented. Pro forma results of operations are not
necessarily indicative of the combined results of operations that actually would
have occurred had the acquisition occurred on such date. The Company, however,
believes that the presentation of pro forma data provides a more meaningful
comparative standard for assessing changes in the results of operations of the
business segments, because the pro forma presentation gives retroactive effect
to the purchase-related adjustments, including amortization of goodwill and the
revaluation on a preliminary basis of the fair market value of certain NorAm
assets and liabilities.
The following table presents operating income on (i) an actual basis for the
year ended December 31, 1997 and (ii) a pro forma basis for each of the
Company's business segments for the years ended December 31, 1997 and 1996.
OPERATING INCOME (LOSS) BY BUSINESS SEGMENT
ACTUAL UNAUDITED
YEAR ENDED PRO FORMA
DECEMBER 31, YEAR ENDED
------------ DECEMBER 31,
---------------
1997(1) 1997 1996
------ ------ ------
(IN MILLIONS)
Electric Operations........ $ 995 $ 995 $ 997
Natural Gas Distribution... 55 153 160
Interstate Pipeline........ 32 100 109
Energy Marketing........... 16 15 49
International.............. 20 17 (1)
Corporate.................. (53) (61) (42)
------ ------ ------
Total Consolidated......... $1,065 $1,219 $1,272
====== ====== ======
__________
(1) Includes NorAm business segments beginning on the Acquisition Date.
4
<PAGE>
ELECTRIC OPERATIONS
Electric Operations are conducted under the name "Houston Lighting & Power
Company" or "HL&P" (HL&P), an unincorporated division of the Company. Electric
Operations provides electric generation, transmission, distribution and sales to
approximately 1.6 million customers in a 5,000 square mile area on the Texas
Gulf Coast, including Houston (the nation's fourth largest city). Electric
Operations constitutes the Company's largest business segment, representing 82%
of the Company's consolidated pro forma operating income for 1997.
The following table provides summary data, before income taxes, regarding the
actual results of operations of Electric Operations for 1997, 1996 and 1995.
YEAR ENDED
DECEMBER 31,
-------------- PERCENT
1997 1996 CHANGE
------ ------ ----
(IN MILLIONS)
Base Revenues(1) $2,839 $2,743 3%
Reconcilable Fuel Revenues(2) 1,413 1,282 10%
Fuel and Purchased Power Expense 1,477 1,347 10%
Operation Expense 737 640 15%
Maintenance Expense 228 249 (8%)
Depreciation and Amortization Expense 569 546 4%
Other Operating Expenses 246 246 --
------ ------ ----
Operating Income $ 995 $ 997 --
====== ======
YEAR ENDED
DECEMBER 31,
-------------- PERCENT
1996 1995 CHANGE
------ ------ -----
(IN MILLIONS)
Base Revenues(1) $2,743 $2,645 4%
Reconcilable Fuel Revenues(2) 1,282 1,035 24%
Fuel and Purchased Power Expense 1,347 1,113 21%
Operation Expense 640 616 4%
Maintenance Expense 249 250 --
Depreciation and Amortization Expense 546 475 15%
Other Operating Expense 246 246 --
------ ------
Operating Income $ 997 $ 980 2%
====== ====== =====
__________
(1) Includes miscellaneous revenues, certain non-reconcilable fuel revenues and
certain purchased power-related revenues.
(2) Includes revenues collected through a fixed fuel factor net of adjustment
for over/under recovery. See "-- Operating Revenues -- Electric Operations."
OPERATING INCOME -- ELECTRIC OPERATIONS
1997 Compared to 1996. Electric Operations' operating income (before income
taxes) was $995 million in 1997 compared with $997 million the previous year.
The decrease in operating income was due to increases in operations expense and
depreciation and amortization expense, partially offset by increased revenues
from electric sales growth and decreases in maintenance expense, as described
below. Total KWH sales rose 3% during 1997, with increases of 1% in residential
sales, 6% in commercial sales and 2% in firm industrial sales.
1996 Compared to 1995. Electric Operations' operating income (before income
taxes) was $997 million in 1996 compared with $980 million in 1995. Increased
sales resulting from favorable weather and economic conditions helped offset the
effects of the increases in operations expense and depreciation and amortization
expense discussed below. Total KWH sales rose 6% during 1996, with increases of
4% in residential sales, 3% in commercial sales and 7% in firm industrial sales.
5
<PAGE>
OPERATING REVENUES -- ELECTRIC OPERATIONS
1997 Compared to 1996. Electric Operations' 3% increase in base revenues
(which includes electric sales, miscellaneous revenues and certain non-
reconcilable fuel) is primarily the result of newly recorded transmission
revenues. Electric Operations' transmission revenues (which are considered
miscellaneous revenues) in 1997 were $86 million but were offset by related
transmission expenses of $88 million which are included in operation and
maintenance expenses. For information regarding these transmission revenues, see
"-- Certain Factors Affecting Future Earnings of the Company and its
Subsidiaries -- Competition -- Electric Operations -- Competition in Wholesale
Market" below.
Electric Operations' 10% increase in reconcilable fuel revenue resulted
primarily from increased natural gas prices. The Public Utility Commission of
Texas (Texas Utility Commission) provides for recovery of certain fuel and
purchased power costs through a fixed fuel factor included in electric rates.
The fixed fuel factor is established during either a utility's general rate
proceeding or its fuel factor proceeding and is generally effective for a
minimum of six months. Revenues collected through such factor are adjusted
monthly to equal actual fuel costs; therefore, such revenues and expenses have
no effect on earnings unless fuel costs are determined not to be recoverable.
The adjusted over/under recovery of fuel costs is recorded on the Company's
Consolidated Balance Sheets as fuel-related credits or fuel-related debits,
respectively. Fuel costs are reviewed during periodic fuel reconciliation
proceedings, which are required at least every three years. Electric Operations
filed a fuel reconciliation proceeding with the Texas Utility Commission on
January 30, 1998 for the three year period ending July 31, 1997.
In 1997, Electric Operations implemented (i) a $70 million temporary fuel
surcharge (inclusive of interest) effective for the first six months of 1997 and
(ii) a $62 million temporary fuel surcharge (inclusive of interest) effective
for the last six months of 1997. As of December 31, 1997, Electric Operations'
cumulative under-recovery of fuel costs was $172 million, including interest. In
December 1997, the Texas Utility Commission approved the implementation of a
$102 million (inclusive of interest) temporary fuel surcharge which was
implemented by Electric Operations on January 1, 1998, with recovery extending
from 8 months to 16 months depending on the customer class. Electric Operations
requested the surcharge in order to recover its under-recovery of fuel expenses
for the period March 1997 through August 1997.
FUEL AND PURCHASED POWER EXPENSE -- ELECTRIC OPERATIONS
Fuel costs constitute the single largest expense for Electric Operations. The
mix of fuel sources for generation of electricity is determined primarily by
system load and the unit cost of fuel consumed. The average cost of fuel used by
Electric Operations in 1997 was $1.87 per million British Thermal Units (MMBtu)
($2.60 for natural gas, $2.02 for coal, $1.08 for lignite and $0.54 for
nuclear). In 1996, the average cost of fuel was $1.82 per MMBtu ($2.31 for
natural gas, $2.11 for coal, $1.11 for lignite and $0.62 for nuclear). Fuel
costs are reconciled to fuel revenues resulting in no effect on earnings unless
fuel costs are determined not to be recoverable.
1997 Compared to 1996. Fuel expenses in 1997 increased by $66 million or 6%
over 1996 expenses. The increase was driven by significant increases in the
average unit cost of natural gas, which rose to $2.60 per MMBtu in 1997 from
$2.31 per MMBtu in 1996. Purchased power expenses also increased in 1997 by $63
million or 20% over 1996 expenses. This change was primarily due to higher
prices paid to qualifying facilities for purchased electric energy principally
as a result of increases in gas prices, energy purchased under Electric
Operations' joint dispatching agreement with the City of San Antonio (See Note
12(c) to the Company's Consolidated Financial Statements), and Electric
Operations participating in the newly deregulated Texas wholesale energy market
in order to buy and sell energy at lower costs to its customers.
1996 Compared to 1995. Fuel expenses in 1996 increased by $146 million or 17%
over 1995 expenses. The increase was driven by significant increases in the
average unit cost of natural gas, which rose to $2.31 per MMBtu in 1996 from
$1.69 per MMBtu in 1995. Purchased power expenses also increased in 1996 by $89
million over 1995 expenses. This change was driven primarily by the unit cost
paid for purchased electric energy which rose as a result of the increase in
natural gas prices.
6
<PAGE>
OPERATION AND MAINTENANCE EXPENSES, DEPRECIATION, AMORTIZATION AND OTHER --
ELECTRIC OPERATIONS
1997 Compared to 1996. Operation and maintenance expense increased $76 million
in 1997, including $88 million due to transmission tariffs within the Electric
Reliability Council of Texas (ERCOT). These expenses are largely offset by $86
million of revenue associated with wholesale transmission services. The
additional expenses do not reflect a significant increase in Electric
Operations' cost of providing transmission service, but only a change in the
pricing and billing of wholesale transmission services among providers in Texas.
In 1997, Electric Operations incurred $17.4 million in work force severance
costs as a result of its efforts to streamline and improve certain business
activities. In 1996, Electric Operations incurred severance costs of $30
million.
Depreciation and amortization expense increased $23 million in 1997 compared
to 1996. The increase is primarily due to the additional accelerated
amortization of $16 million over 1996 of Electric Operations' investment in
lignite reserves. In 1996, Electric Operations began amortizing its $153 million
investment in these lignite reserves, which are associated with a canceled
generation project. The lignite reserves will be fully amortized no later than
2002. In each of 1997 and 1996, Electric Operations wrote down its investment in
the South Texas Project by $50 million in addition to ordinary depreciation
associated with the South Texas Project. The additional amortization of the
lignite reserves and the South Texas Project is allowed pursuant to Electric
Operations' most recent rate order. For additional information regarding these
amortizations, see Note 1(f) to the Company's Consolidated Financial Statements.
1996 Compared to 1995. Operations and maintenance expense increased by $23
million or 3% in 1996. This increase is largely attributable to the
implementation of an employee incentive compensation program and an increase in
severance payments paid to former employees. A significant decline in employee
benefits-related expenses partially offset the other increases in operations and
maintenance expense.
In 1995, Electric Operations incurred $15 million in work force severance as a
result of its efforts to streamline and improve certain business activities as
compared to $30 million in 1996.
NATURAL GAS DISTRIBUTION
Domestic natural gas distribution operations (Natural Gas Distribution) are
conducted through the Arkla, Entex and Minnegasco divisions of NorAm and are
included in the Company's actual consolidated results of operations beginning on
the Acquisition Date. These operations consist of natural gas sales to, and
natural gas transportation for, residential, commercial and certain industrial
customers in six states: Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma
and Texas.
7
<PAGE>
The following table provides summary data regarding the unaudited pro forma
financial results of operations of Natural Gas Distribution, including operating
statistics, for 1997 and 1996. Results of operations data for prior periods are
not presented because the Company had no operations in this segment prior to the
Merger.
UNAUDITED
PRO FORMA
YEAR ENDED
DECEMBER 31,
------------- PERCENT
1997 1996 CHANGE
====== ====== ======
($ IN MILLIONS)
Operating Revenues $2,202 $2,113 4%
Operating Expenses:
Natural Gas 1,441 1,348 7%
Operation and Maintenance 247 250 (1%)
Depreciation and Amortization 123 120 3%
Other Operating Expenses(1) 238 235 1%
------ ------ ------
Total Operating Expenses 2,049 1,953 5%
------ ------ ------
Operating Income $ 153 $ 160 (4%)
====== ====== ======
Throughput Data (in Bcf):
Residential and Commercial Sales 326 333 (2%)
Industrial Sales 59 58 2%
Transportation 42 42 -
------ ------
Total Throughput 427 433 (1%)
====== ====== ======
__________
(1) Before a $6 million one-time charge incurred in 1996 for early retirement
and severance costs.
1997 Compared to 1996 (Pro Forma). The increase of approximately $89 million
(4%) in pro forma Natural Gas Distribution operating revenue for the year ended
December 31, 1997 in comparison to the corresponding period of 1996 is
principally due to the increase in purchased gas costs.
Pro forma operating income was $153 million in 1997 compared with $160 million
(before a one-time charge of $6 million for early retirement and severance) in
1996. The decrease of approximately $7 million (4%) in 1997 pro forma operating
income was principally due to decreased Minnegasco customer usage due to warmer
weather and customer conservation, decreased Arkla customer usage due to warmer
weather (primarily in the first quarter of 1997) and Arkla's charges associated
with the applicable state regulatory commission's methodology of calculating the
price of gas charged to customers (the purchased gas adjustment) primarily in
Louisiana. Partially offsetting the decrease is an increase in Minnegasco's
performance based rate incentive recoveries and customer growth and increased
revenues from Entex due to rate relief granted in 1996 and fully reflected in
1997.
The $93 million (7%) increase in gas purchased costs in 1997 compared to 1996
primarily reflects the increase in Natural Gas Distribution's average cost of
gas in 1997 (consistent with the overall increase in the market price of gas)
along with the purchased gas adjustment described above.
INTERSTATE PIPELINE
Interstate natural gas pipeline operations (Interstate Pipeline) are conducted
through NorAm Gas Transmission Company (NGT) and Mississippi River Transmission
Corporation (MRT), two wholly owned subsidiaries of NorAm. The NGT system
consists of approximately 6,200 miles of natural gas transmission lines located
in portions of Arkansas, Kansas, Louisiana, Mississippi, Missouri, Oklahoma,
Tennessee and Texas. The MRT system consists of approximately 2,000 miles of
pipeline serving principally the greater St. Louis metropolitan area in Illinois
and Missouri. The results of operations of Interstate Pipeline are included in
the Company's actual consolidated results of operations beginning on the
Acquisition Date.
8
<PAGE>
The following table provides summary data regarding the unaudited pro forma
results of operations of Interstate Pipeline including operating statistics for
1997 and 1996. Results of operations data for prior periods are not presented
because the Company had no operations in this segment prior to the Merger.
UNAUDITED
PRO FORMA
YEAR ENDED
DECEMBER 31,
----------------- PERCENT
1997 1996 CHANGE
---- ---- ------
($ IN MILLIONS)
Operating Revenues $ 295 $ 347 (15%)
Operating Expenses:
Natural Gas 42 76 (45%)
Operation and Maintenance 45 49 (8%)
Depreciation and Amortization 46 45 2%
Other Operating Expenses(1) 62 68 (9%)
----- ----- -----
Total Operating Expenses 195 238 (18%)
----- ----- -----
Operating Income $ 100 $ 109 (9%)
===== ===== =====
Throughput Data (in million MMBtu):
Natural Gas Sales 18 33 (45%)
Transportation 911 952 (4%)
Elimination(2) (17) (31) 45%
----- -----
Total Throughput 912 954 (4%)
===== ===== =====
__________
(1) Before a $17 million one-time charge incurred in 1996 for early retirement
and severance costs.
(2) Elimination of volumes both transported and sold.
1997 Compared to 1996 (Pro Forma). Pro forma operating revenues for Interstate
Pipeline decreased by $52 million (15%) for the year ended December 31, 1997 in
comparison to the corresponding period of 1996. The decrease in revenues
primarily reflects a decline in natural gas sales revenue resulting from the
expiration in 1996 of an unbundled natural gas sales contract between Interstate
Pipeline and Arkla. Natural gas sales to Natural Gas Distribution were $60
million in 1996 and none in 1997. It is anticipated that substantially all
future revenues for Interstate Pipeline will be from natural gas transportation
only.
Pro forma operating income was $100 million in 1997 compared to $109 million
(before a one-time charge of $17 million for early retirement and severance) in
1996. This decrease of approximately $9 million (9%) in Interstate Pipeline's
pro forma operating income between 1997 and 1996 results primarily from three
factors: (i) a 6% decrease in transportation revenues, (ii) a 43% decrease in
natural gas sales revenue (as described above) and (iii) lower demand for
natural gas transportation as a result of lower natural gas consumption
(primarily weather-related) in the eastern markets served by the segment. These
factors were offset partially by an approximately 18% decline in operating
expenses primarily due to decreases in gas purchased.
The decline in transportation revenues are largely attributable to price
differentials between the average spot price for Mid-continent natural gas
(Interstate Pipeline's primary supply area) and Gulf Coast natural gas in 1997.
When prices of Gulf Coast gas decrease significantly relative to Mid-continent
gas, downward pressure on transportation prices occurs when selling in west to
east markets like those of NGT. This competitive pressure, in turn, results in a
decline in average transportation rates under contracts that contain market-
sensitive pricing provisions.
The $34 million (45%) decrease in gas purchased costs in 1997 compared to 1996
is largely attributable to the expiration of long-term supply contracts entered
into prior to unbundling, as discussed above. Other operating expenses decreased
$4 million (9%) in 1997 compared to 1996 primarily due to the elimination of
9
<PAGE>
non-recurring costs combined with cost reductions related to the 1996 early
retirement and severance program and reductions in costs allocated from NorAm.
During 1997, Interstate Pipeline's largest unaffiliated customer was a natural
gas utility that serves the greater St. Louis metropolitan area. Revenues from
this customer are generated pursuant to several long-term firm transportation
and storage contracts that currently are scheduled to expire at various dates
between October 1999 and May 2000. Interstate Pipeline is currently negotiating
with the natural gas utility to renew these agreements.
ENERGY MARKETING
Energy marketing and gathering business (Energy Marketing) includes the
operations of the Company's wholesale and selected retail energy marketing
businesses and natural gas gathering activities conducted, respectively, by
NorAm Energy Services, Inc. (NES), NorAm Energy Management, Inc. (NEM) and NorAm
Field Services Corp. (NFS), three wholly owned subsidiaries of NorAm.
The following table provides summary data regarding the unaudited pro forma
results of operations of Energy Marketing, including operating statistics for
1997 and 1996. Results of operations data for prior periods are not presented
because the Company had no operations in this segment prior to the Merger.
<TABLE>
<CAPTION>
UNAUDITED PRO
FORMA
YEAR ENDED
DECEMBER 31
--------------- PERCENT
1997 1996 CHANGE
------- ------ ------
(IN MILLIONS)
<S> <C> <C> <C>
Operating Revenues $ 3,589 $2,645 36%
Operating Expenses:
Natural Gas and Purchased Power, net 3,477 2,489 40%
Operation and Maintenance 46 68 (32%)
Depreciation and Amortization 11 10 10%
Other Operating Expenses 40 29 38%
------- ------
Total Operating Expenses 3,574 2,596 38%
------- ------
Operating Income $ 15 $ 49 (69%)
======= ======
Operations Data:
Natural Gas (in Bcf):
Sales 1,185 1,076 10%
Transportation 24 26 (8%)
Gathering 242 231 5%
------- ------
Total 1,451 1,333 9%
======= ======
Electricity (in thousand MWH):
Wholesale Power Sales 24,997 2,776 800%
======= ======
</TABLE>
1997 Compared to 1996 (Pro Forma). Pro forma operating revenues for Energy
Marketing increased by $944 million (36%) for 1997 in comparison to 1996 due to
increased natural gas and electricity trading volumes. Increased volumes in 1997
had minimal effect on operating income due to low operating margins in both
periods.
Pro forma operating income for 1997 was $15 million compared to $49 million in
1996. This decrease of approximately $34 million (69%) was primarily attributed
to: (i) hedging losses associated with anticipated first quarter 1997 sales
under peaking contracts and (ii) losses from the sale of natural gas held in
storage and unhedged in the first quarter of 1997 totaling $17 million. In
addition, other operating expenses increased $11 million largely due to
increased staffing and marketing activities made in support of the increased
sales
10
<PAGE>
and expanded marketing efforts. Partially offsetting these unfavorable
impacts were increased margins from natural gas gathering activities.
Natural gas and purchased power expense increased $988 million (40%) in 1997
compared to 1996 primarily due to increased gas and electricity marketing
activities but also included hedging losses and losses from the sale of natural
gas, as discussed above.
To minimize fluctuations in the price of natural gas and transportation,
NorAm, primarily through NES, enters into futures transactions, swaps and
options in order to hedge against market price changes affecting (i) certain
commitments to buy, sell and transport natural gas, (ii) existing gas storage
inventory and (iii) certain anticipated transactions, some of which carry off-
balance sheet risk. NES also enters into natural gas derivatives for trading
purposes and electricity derivatives for hedging and trading purposes. For a
discussion about the Company's accounting treatment of derivative instruments,
see Note 2 to the Company's Consolidated Financial Statements and "Quantitative
and Qualitative Disclosures About Market Risk" below.
The Company believes that NES' energy marketing and risk management services
have the potential of complementing the Company's strategy of developing and/or
acquiring unregulated generation assets in other markets. As a result, the
Company has made, and expects to continue to make, significant investments in
developing NES' internal software, trading and personnel resources.
INTERNATIONAL
The Company's international business segment (International) includes the
results of operations of HI Energy, a wholly owned subsidiary of the Company
that participates in the development and acquisition of foreign independent
power projects and the privatization of foreign generation and distribution
facilities, and of the international operations of NorAm. Substantially all of
the Company's International operations to date have been in Central and South
America.
Results of operations data for International are presented in the following
table on an unaudited pro forma basis as if the Merger had occurred as of
January 1, 1997 and 1996, as applicable. The primary pro forma adjustment made
to this segment in connection with the Merger is to give effect to the
development costs and other expenditures incurred by certain NorAm subsidiaries
on international projects prior to the Acquisition Date. The adjustment had no
effect on operating revenues. Results of operations for International for the
years ended December 31, 1996 and 1995 are presented on an actual basis as the
related NorAm operations for such years were immaterial.
<TABLE>
<CAPTION>
UNAUDITED
PRO FORMA ACTUAL
YEAR ENDED YEAR ENDED
------------------ PERCENT -------------- PERCENT
1997 1996 CHANGE 1996 1995 CHANGE
----- ----- ----- ----- ----- -----
(IN MILLIONS) (IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues $ 92 $ 62 48% $ 62 $ 47 32%
Operating Expenses:(1)
Fuel 21 19 11% 19 18 6%
Operation and Maintenance 50 42 19% 39 76 (49%)
Depreciation and Amortization 4 2 100% 2 1 100%
----- ----- ----- -----
Total Operating Expenses 75 63 19% 60 95 (37%)
----- ----- ----- -----
Operating Income (Loss) $ 17 $ (1) $ 2 $ (48)
===== ===== ===== =====
</TABLE>
- ----------
(1) International operating expenses are included in other operating expenses on
the Company's Statements of Consolidated Income. The above detail is
provided for informational purposes only.
1997 Compared to 1996 (Pro Forma). Pro forma operating income for 1997 was $17
million compared to an operating loss of approximately $1 million for the same
period in 1996. The first quarter of 1996 includes an $8 million pre-tax non-
recurring charge related to the write-off of a portion of HI Energy's investment
in two
11
<PAGE>
tire-to-energy plants in 1996. Excluding non-recurring charges, International
would have had operating income in 1996 of $7 million. The increase in 1997
operating income is due to increased equity earnings of $32 million partially
offset by higher operation expenses resulting from increased corporate and
project development costs. Equity earnings increased primarily due to
investments in Brazil and Colombia. Light Servicos de Eletricidade S.A. (Light)
reported enhanced results in 1997 and a full year of operations compared to only
eight months in 1996. HI Energy's investment in EPSA, a Colombian electric
utility, in which HI Energy acquired a 28% interest in June 1997, also
contributed to the increase in equity income.
Excluding after-tax nonrecurring charges of $5 million for 1996,
International's pro forma net income was $23 million and $3 million for 1997 and
1996, respectively. Generally, HI Energy's net income exceeds its operating
income because of tax benefits and because equity income is reflected net of
tax. However, in 1996 net income did not exceed operating income primarily due
to lower equity earnings in 1996.
1996 Compared to 1995 (Actual). Operating income for the year ended December
31, 1996 was $2 million compared to an operating loss of $48 million for the
same period in 1995. The increase is primarily due to (i) equity earnings of
approximately $16 million from Light which was acquired in May 1996, (ii) a $20
million reduction in non-recurring charges associated with the investment in two
tire-to-energy plants (included in operation and maintenance expenses) and (iii)
reduced project development costs (included in operation and maintenance
expenses). International's actual net income in 1996 was $.2 million compared to
a loss of $33 million in 1995.
International intends to evaluate and consider a wide array of potential
business strategies, including possible acquisitions, restructurings,
reorganizations and/or dispositions of currently owned properties or
investments. Pursuit of any of the above strategies, or any combination thereof
could have a significant impact on the business operations and financial
condition of International.
For additional information about the accounting treatment of certain of HI
Energy's foreign investments, see Note 5 to the Company's Consolidated Financial
Statements.
CORPORATE
Corporate. The Company's corporate and other business segment (Corporate)
includes the operations of HI Power Generation, Inc. (HIPG), which is engaged in
the acquisition, development, and operation of domestic non-rate regulated power
generation facilities, the Company's unregulated retail electric services
business, certain real estate holdings of the Company, corporate costs and
inter-unit eliminations.
In 1997, Corporate's pro forma operating loss of $61 million which reflects an
increase of $19 million when compared to 1996. The increase in pro forma
operating losses was primarily due to (i) losses associated with the Company's
non-regulated utility services business; (ii) consumer services business; (iii)
unregulated retail electric services business; and (iv) expenses related to the
development of domestic power generation projects.
HIPG. HIPG was formed in March 1997 to pursue the acquisition of domestic
electric generation assets as well as the development of new domestic non-rate
regulated power generation facilities. The Company has invested approximately $3
million in HIPG development activities since its formation. HIPG currently has
entered into commitments associated with various generation projects amounting
to $338 million, including certain commitments that remain subject to due
diligence and other conditions. The Company currently expects to finance these
commitments primarily with the proceeds from bank borrowings obtained by one or
more subsidiaries of the Company. The Company expects that HIPG will continue to
participate as a bidder in future sales of generating assets. Depending on the
timing and success of HIPG's future bidding efforts resulting expenditures could
be substantial.
12
<PAGE>
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
OF THE COMPANY AND ITS SUBSIDIARIES
Earnings for the past three years are not necessarily indicative of future
earnings and results. The level of future earnings depends on numerous factors
including (i) the Company's ability to successfully integrate the operations of
NorAm into the Company's operations; (ii) the future growth in the Company and
its subsidiaries' energy sales; (iii) weather; (iv) the success of the Company's
and its subsidiaries' entry into non-rate regulated businesses such as energy
marketing and international and domestic power projects; (v) the Company's and
its subsidiaries' ability to respond to rapid changes in a competitive
environment and in the legislative and regulatory framework under which it has
traditionally operated; (vi) rates of economic growth in the Company's and its
subsidiaries' service areas; (vii) the ability of the Company and its
subsidiaries to control costs and to maintain pricing structures that are both
attractive to customers and profitable; (viii) the outcome of future rate
proceedings; and (ix) future legislative initiatives.
In order to adapt to the increasingly competitive environment in which the
Company and its subsidiaries operate, the Company intends to evaluate and
consider a wide array of potential business strategies. These may include
business combinations or acquisitions involving other utility or non-utility
businesses or properties, internal restructuring, and reorganizations or
dispositions of currently owned properties or currently operating business
units. Pursuit of any of the above strategies, or any combination thereof, may
significantly affect the business operations and financial condition of the
Company.
RATE PROCEEDINGS -- ELECTRIC OPERATIONS
The Texas Utility Commission has jurisdiction (or, in some cases, appellate
jurisdiction) over the electric rates of Electric Operations and as such
monitors Electric Operations' earnings to ensure that Electric Operations is not
earning in excess of a reasonable rate of return.
In 1997, the Texas legislature considered but did not pass legislation
intended to address various issues concerning the restructuring of the electric
utility industry, including proposals that would permit Texas retail electric
customers to choose their own electric suppliers beginning on December 31, 2001.
The legislative proposals included provisions relating to full stranded cost
recovery; rate reductions; rate freezes; the unbundling of generation
operations, transmission and distribution and customer service operations;
securitization of regulatory assets; and consumer protections. Although the
Company and certain other parties (including the Texas Utility Commission)
supported the bill, it was not enacted prior to the expiration of the
legislative session.
In October 1997, the Company presented a proposed transition to competition
plan intended to address certain aspects of the proposals contained in the
legislation formerly pending before the Texas legislature. By mid-December 1997,
negotiations resulted in a settlement agreement (Settlement Agreement) among the
Company and representatives of the state's consumer and industrial groups, the
staffs of the City of Houston, the Texas Utility Commission and others that was
presented to the Texas Utility Commission, where it is currently under
consideration.
Under the terms of the proposal, residential customers will receive a 4%
credit to the base cost of electricity in 1998, increasing to 6% in 1999. Small
and mid-sized businesses will receive a 2% credit to their base costs beginning
in 1998. The combined effect of these reductions is expected to be a $166
million decrease in base revenues over a two year period. In addition, the
Company (over the next two years) will be permitted to mitigate its potentially
stranded costs by (i) redirecting to production property all of its current
depreciation expenses that would otherwise be credited to accumulated
depreciation for transmission and distribution property, and (ii) applying any
and all earnings above a rate of return cap of 9.95% to additional depreciation
of production property. The Company estimates that redirected depreciation over
the two-year period of 1998 and 1999 will be approximately $364 million. As part
of the Settlement Agreement, the Company will support proposed legislation in
the 1999 Texas legislative session that includes provisions providing for retail
customer choice effective December 31, 2001 and other provisions consistent with
those in the 1997 proposed legislation.
13
<PAGE>
The Settlement Agreement is currently under consideration by the Texas Utility
Commission, the City of Houston and other cities served by HL&P. In December
1997, the Texas Utility Commission approved the petition filed by the Company to
implement the requested base rate credits on a temporary basis beginning January
1, 1998, pending final Texas Utility Commission consideration. The approval also
included the accounting order necessary to permit the Company to begin
redirecting depreciation from its transmission and distribution facilities to
production property on a temporary basis pending final Texas Utility Commission
consideration. A procedural schedule has been developed by the Texas Utility
Commission whereby a final decision regarding the Settlement Agreement would be
reached by the end of March 1998.
Although the Company believes that the proposal has strong support from many
groups active in the debate over deregulation of the electric industry, it is
not in a position at this time to predict whether the proposal will be adopted,
and if adopted, what form it ultimately may take.
COMPETITION -- ELECTRIC OPERATIONS
Due to changing government regulations, technological developments and the
availability of alternative energy sources, the U.S. electric utility industry
has become increasingly competitive.
Long-Term Trends in Electric Utility Industry. Based on a strategic review of
the Company's business and of ongoing developments in the electric utility and
related industries regarding competition, regulation and consolidation, the
Company's management believes that the pace of change affecting the electric
utility industry is likely to accelerate, albeit on a state-by-state basis. As
of December 31, 1997, 16 states are considering legislative proposals to
restructure electricity markets. The Company's management also believes the
businesses of electricity and natural gas are converging and consolidating and
these trends will alter the structure and business practices of companies
serving these markets in the future. In particular, the Company's management has
observed a trend toward performance based ratemaking for regulated transmission
and distribution operations. This trend should provide incentives for electric
utilities to become more efficient.
Competition in Wholesale Market. The Energy Policy Act of 1992 and the Texas
Public Utility Regulatory Act of 1995 (PURA) both contain provisions intended to
facilitate the development of a wholesale energy market. Although HL&P's
wholesale sales traditionally have accounted for less than 1% of its total
revenues, the expansion of competition in the wholesale electric market is
significant in that it has increased the range of nonutility competitors, such
as exempt wholesale generators (EWGs) and power marketers, in the Texas electric
market as well as resulted in fundamental changes in the operation of the state
transmission grid.
In February 1996, the Texas Utility Commission adopted rules granting third-
party users of transmission systems open access to such systems at rates, terms
and conditions comparable to those available to utilities owning such
transmission assets. Under the Texas Utility Commission order implementing the
rule, HL&P was required to separate, on an operational basis, its wholesale
power marketing operations from the operations of the transmission grid and, for
purposes of transmission pricing, to disclose each of its separate costs of
generation, transmission and distribution.
In January 1997, the Texas Utility Commission approved interim transmission
cost of service rates under the new transmission access pricing rules. The
associated 1997 revenue was $86 million offset by transmission expenses of $88
million.
In August 1996, the Texas Utility Commission approved the creation of an
Independent System Operator (ISO) to manage the electric grid of the Electric
Reliability Council of Texas (ERCOT). The ISO is a key component of implementing
the Texas Utility Commission's overall strategy to create a competitive
wholesale market. The ISO is responsible for ensuring that all power producers
and traders have fair access to the ERCOT electric transmission system. The
ERCOT ISO plan is the first ISO proposal to be implemented in the U.S. The ISO
is governed by an equal number of representatives from each of six wholesale
market groups: investor owned utilities, municipally owned utilities, electric
cooperatives and river authorities, transmission dependent utilities,
independent power producers and power marketers.
14
<PAGE>
Competition in Retail Market. The Company has agreed pursuant to the
Settlement Agreement to support legislation in 1999 that is intended to permit
Texas retail electric customers to choose their own suppliers beginning on
December 31, 2000.
In January 1997, the Texas Utility Commission delivered a report to the Texas
legislature on the scope of competition in Texas electric markets and the impact
of competition and industry restructuring on customers in both competitive and
non-competitive markets (including legislative recommendations to promote the
public interest in such markets). In its report, the Texas Utility Commission
recommended that the Texas legislature enact legislation to implement retail
competition in Texas but recommended against any legislation that would
introduce broad-based retail competition before 2000. The Texas Utility
Commission is currently updating this report for the 1999 legislative session.
For information about the Company's proposed transition to competition plan,
see "-- Certain Factors Affecting Future Earnings of the Company and its
Subsidiaries -- Rate Proceedings -- Electric Operations."
Stranded Costs. As the U.S. electric utility industry continues its transition
to a more competitive environment, a substantial amount of fixed costs
previously approved for recovery under traditional utility regulatory practices
(including regulatory assets and liabilities) may become "stranded," i.e.,
unrecoverable at competitive market prices. The issue of stranded costs could be
particularly significant with respect to fixed costs incurred in connection with
the past construction of generation plants, such as nuclear power plants, which
would not command the same price for their output as they have in a regulated
environment.
In January 1997, the Texas Utility Commission delivered a report to the Texas
legislature on stranded investments in the electric utility industry in Texas.
The report estimated that the total amount of stranded costs for all Texas
utilities could be as high as $21 billion, based on one set of assumptions, and
alternatively projected that such costs could be minimal or non-existent, based
on another set of assumptions. Electric Operations' estimated stranded costs as
set forth in the Texas Utility Commission report, calculated based on various
sets of assumptions provided by the Texas Utility Commission, ranged from non-
existent to $6 billion. The broad range of estimates illustrates the inherent
uncertainty in calculating these costs. The Texas Utility Commission is
currently updating this report for the 1999 legislative session.
Regulatory Assets and Liabilities. Electric Operations applies the accounting
policies established in SFAS No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS No. 71). In general, SFAS No. 71 permits a company
with cost-based rates to defer certain costs that would otherwise be expensed to
the extent that the utility is recovering or expects to recover such costs in
rates charged to customers. If, as a result of changes in regulation or
competition, Electric Operations' ability to recover these assets and/or
liabilities would not be assured, then pursuant to SFAS No. 101, "Accounting for
Discontinuation of Application of SFAS No. 71 (SFAS No. 101) and SFAS No. 121,
"Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets
to be Disposed of" (SFAS No. 121), Electric Operations would be required to
write off or write down such net regulatory assets to the extent that they
ultimately were determined not to be recoverable. For further information
concerning regulatory assets or the Company's balance sheet and discussion of
the accounting for regulatory assets and liabilities, see Note 1(c) to the
Company's Consolidated Financial Statements.
COMPETITION -- OTHER OPERATIONS
Natural Gas Distribution competes primarily with alternate energy sources such
as electricity and other fuel sources as well as with providers of energy
conservation products. In addition, as a result of federal regulatory changes
affecting interstate pipelines, it has become possible for other natural gas
suppliers and distributors to bypass Natural Gas Distribution's facilities and
market, sell and/or transport natural gas directly to small commercial and/or
large volume customers.
Interstate Pipeline competes with other interstate and intrastate pipelines in
the transportation and storage of natural gas. The principal elements of
competition among pipelines are rates, terms of service, and flexibility and
reliability of service. Interstate Pipeline competes indirectly with other forms
of energy available to its customers, including electricity, coal and fuel oils.
The primary competitive factor is price. Changes in
15
<PAGE>
the availability of energy and pipeline capacity, the level of business
activity, conservation and governmental regulations, the capability to convert
to alternative fuels, and other factors, including weather, affect the demand
for natural gas in areas served by Interstate Pipeline and the level of
competition for transport and storage services.
Energy Marketing competes for sales in its gas marketing business with other
natural gas merchants, producers and pipelines based on its ability to aggregate
supplies at competitive prices from different sources and locations and to
utilize efficiently transportation from third-party pipelines. Energy Marketing
also competes against other energy marketers on the basis of its relative
financial position and access to credit sources. This competitive factor
reflects the tendency of energy customers, natural gas suppliers and natural gas
transporters to seek financial guarantees and other assurances that their energy
contracts will be satisfied. As pricing information becomes increasingly
available in the energy marketing business and as deregulation in the
electricity markets continues to accelerate, the Company anticipates that Energy
Marketing will experience greater competition and downward pressure on per-unit
profit margins in the energy marketing industry.
Competition for acquisition of international and domestic non-rate regulated
power projects is intense. HI Energy and HIPG compete against a number of other
participants in the non-utility power generation industry, some of which have
greater financial resources and have been engaged in non-utility power projects
for periods longer than the Company and have accumulated greater portfolios of
projects. Competitive factors relevant to the non-utility power industry include
financial resources, access to non-recourse funding and regulatory factors.
FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS
For information regarding the Company's exposure to risk as a result of
fluctuations in commodity prices and derivative instruments, see Item 7A below.
ACCOUNTING TREATMENT OF ACES
The Company accounts for its investment in Time Warner Convertible Preferred
Stock (TW Preferred) under the cost method. As a result of the Company's
issuance of the ACES, certain increases in the market value of Time Warner
common stock (the security into which the TW Preferred is convertible) could
result in an accounting loss to the Company, pending the conversion of the
Company's TW Preferred into Time Warner common stock.
Prior to the conversion of the TW Preferred into Time Warner common stock,
when the market price of Time Warner common stock increases above $55.5844, the
Company records in Other Income (Expense) an accounting loss equal to the
aggregate amount of such increase as applicable to all ACES multiplied by
0.8264. In accordance with generally accepted accounting principles, this
accounting loss (which reflects the unrealized increase in the Company's
indebtedness with respect to the ACES) may not be offset by accounting
recognition of the increase in the market price of the Time Warner common stock
that underlies the TW Preferred. Upon conversion of the TW Preferred, the
Company will begin recording unrealized net changes in the market prices of the
Time Warner common stock and the ACES as a component of common stock equity.
As of December 31, 1997, the market price of Time Warner common stock was
$62.00 per share. Accordingly, the Company recognized an increase of $121
million in the unrealized liability relating to its ACES indebtedness (which
resulted in an after tax earnings reduction of $79 million or $.31 per share).
The Company believes that this unrealized loss for the ACES is more than
economically hedged by the approximately $430 million unrecorded unrealized gain
at December 31, 1997 relating to the increase in the fair value of the Time
Warner common stock underlying the investment in TW Preferred since the date of
its acquisition. Any gain related to the increase in the fair value of Time
Warner Common Stock would be recognized upon the sale of the TW Preferred or the
shares of common stock into which such TW Preferred is converted. As of February
28, 1998, the price of Time Warner common stock was $67.50 per share which would
have resulted in the Company recognizing an additional increase of $104 million
in the unrealized
16
<PAGE>
liability represented by its indebtedness under the ACES. The related unrecorded
unrealized gain as of February 28, 1998 would have been computed as an
additional $126 million.
IMPACT OF THE YEAR 2000 ISSUE AND OTHER SYSTEM IMPLEMENTATION ISSUES
The Company is currently evaluating its computer and software requirements in
light of changes in the electric utility and energy services industries and the
acquisition of NorAm and resulting expansions of the Company into energy trading
activities.
In September 1997, the Company entered into an agreement with SAP America,
Inc. (SAP) to license SAP's proprietary R/3 enterprise software. The licensed
software includes finance and accounting, human resources, materials management
and service delivery components. Based on the current timetable for completion
of the SAP implementation and integration project (Project), the Company
estimates that the third-party cost (including software license fees, fees for
consulting and other services and hardware acquisition costs) plus internal
costs of the Project will be approximately $130 million. It is currently
projected that these costs would be incurred over a three-year period. All
business process reengineering costs associated with the Project will be
expensed by the Company when incurred. It is anticipated that the implementation
of SAP will negate the need to modify many of the Company's computer systems to
accommodate the year 2000. The Company is also considering installing a new
customer information system; expenditures for the installation of such a system
have not been determined but could be significant.
The Company is also evaluating various alternatives intended to permit its
existing computer programs (those not anticipated to be replaced by SAP) to
accommodate the year 2000 and beyond. Based on current internal cost and
productivity studies as well as bids recently solicited from various computer
software contractors, the Company estimates that the cost of resolving the year
2000 issue for its current operations (other than those anticipated to be
replaced by SAP) will range between $20 million to $25 million.
The costs of becoming year 2000 compliant and the dates by which the Company
plans to complete the year 2000 modifications are based on management's
estimates, which were derived utilizing numerous assumptions regarding future
events, including the continued availability of certain resources, third party
modification plans and other factors. However, there can be no guarantee that
these cost or time estimates will be achieved, and actual results could differ
materially. Specific factors that might cause such material differences include,
but are not limited to, the availability of personnel trained in this area and
the ability to locate and correct all relevant computer codes.
RISKS OF OVERSEAS OPERATIONS
As of December 31, 1997, the Company's Consolidated Balance Sheets reflected
$803 million of foreign investments, a substantial portion of which represent
equity investments in foreign utility companies.
Foreign power projects entail certain political and financial risks, distinct
from those associated with domestic power projects. Such risks include (i)
expropriation, (ii) political instability, (iii) currency exchange rate
fluctuations and repatriation restrictions and (iv) regulatory and legal
uncertainties. Although HI Energy seeks to minimize these risks in a variety of
ways, including co-investing with local partners, financing investments with
nonrecourse debt and reviewing the potential return of any investment against
related political and other risks, there can be no assurance that HI Energy's
efforts to minimize overseas operational risks will be successful.
As of December 31, 1997, HI Energy held a 11.35% ownership interest in Light.
Equity earnings from Light constitute a substantial portion of International's
operating income. In December 1997, Light experienced numerous power outages in
its service territory during a period of record peaks in electrical demand. The
Brazilian electricity service regulatory agency (ANEEL) in February 1998
assessed against Light a $1.2 million penalty because of these outages. Light
has protested the assessment of the fines.
In February 1998, HI Energy and certain of its Argentine subsidiaries
initiated an arbitration proceeding before the International Centre for
Settlement of Investment Disputes against the Republic of Argentina, relating to
alleged violations by the Province of Santiago del Estero and others of certain
provisions of the
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concession contract held by EDESE. HI Energy and its subsidiaries are seeking
recovery of damages in an amount to be determined, but estimated to be no less
than $10 million.
ENVIRONMENTAL EXPENDITURES
The Federal Clean Air Act (Clean Air Act) and other federal and state laws and
regulations have required, and will continue to require, the Company to make
significant expenditures in order to comply with environmental standards.
Clean Air Act Expenditures. In 1996, the Company incurred costs of
approximately $1 million and less than $1 million in 1997, in order to comply
with requirements applicable to Electric Operations under the Clean Air Act,
which requirements mandate that electric utilities install continuous emission
monitoring equipment. Installation of the new systems was completed in 1996,
and, based on existing regulatory requirements, the Company forecasts no
additional significant expenditures for the installation of continuous emissions
monitoring systems for 1998.
The Clean Air Act also requires establishing new emission limitations for
oxides of nitrogen (NOx). However, implementation of these limitations has been
delayed until 1999. The Company did not incur NOx reduction costs in 1997 but it
estimates that it will expend up to $10 million between 1998 and 1999 for NOx
reductions. Current Texas Natural Resource Conservation Commission evaluations
indicate NOx reductions will be required subsequent to 1999, however the
magnitude and timing of such reductions have not been established.
Expenditures Associated with Planned HIPG Acquisitions. The California South
Coast Air Quality Management District updated the Air Quality Management Plan
for attainment of the federal ozone standard in 1997. The plan included
provisions for future year reductions in NOx emissions. Various emission
reduction initiatives and emission credit purchases are being evaluated in
association with the proposed acquisitions of generation assets by HIPG in
California. The estimated capital expenditures associated with such reductions
and/or purchases have not yet been determined.
EPA Proceedings. In 1992, the EPA (i) identified the Company, along with
several other parties, as "potentially responsible parties" (PRP) under the
Comprehensive Environmental Response, Compensation and Liability Act for the
costs of cleaning up a site located adjacent to one of the Company's
transmission lines and (ii) issued an administrative order for the remediation
of the site. The Company believes that the EPA took this action solely on the
basis of information indicating that the Company in the 1950s acquired record
title to a portion of the land on which the site is located. The Company does
not believe that it now or previously held any ownership interest in the site
covered by the order and has obtained a judgment to that effect from a court in
Galveston County, Texas. Based on this judgment and other defenses that the
Company believes to be meritorious the Company has elected not to adhere to the
EPA's administrative order, even though the Company understands that other PRPs
are proceeding with site remediation. To date, neither the EPA nor any other PRP
has instituted a claim against the Company for any share of the remediation
costs for the site. However, if the Company was determined to be a responsible
party, the Company could be found to be jointly and severally liable along with
the other PRPs, for the aggregate remediation costs of the site (which the
Company estimates to be approximately $80 million in the aggregate) and could be
subjected to substantial fines and damage claims. Although the ultimate outcome
of this proceeding cannot be predicted at this time, the Company does not
believe that this case will have a material adverse effect on the Company's
financial condition, liquidity or results of operations.
Litigation Involving Site Remediation. The Company is a defendant in
litigation arising out of the environmental remediation of a site in Corpus
Christi, Texas. The site was operated by third parties as a metals reclaiming
operation. Although the Company neither operated nor owned the site, certain
transformers and other equipment originally sold by the Company may have been
delivered to the site by third parties. The Company and others have remediated
the site pursuant to a plan approved by appropriate state agencies and a federal
court. To date, the Company has recovered, or has commitments to recover from
other responsible parties $2.2 million of the more than $3 million it has spent
on remediation.
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In Dumes, et al. v. Company, et al. (filed in December 1991 and pending in the
U.S. District Court for the Southern District of Texas, Corpus Christi
Division), landowners near the Corpus Christi site have asserted claims that
their property has been contaminated as a result of the remediation effort and
are seeking approximately $70 million in compensatory damages, in addition to
punitive damages of $51 million. The Dumes case is currently scheduled for trial
in June 1998. Although the ultimate outcome of this case cannot be predicted at
this time, the Company does not believe that this case will have a material
adverse effect on the Company's financial condition, liquidity or results of
operations.
Manufactured Gas Plant Sites. NorAm and its predecessors operated a
manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota
formerly known as Minneapolis Gas Works (FMGW) until 1960. NorAm has completed
remediation of the main site other than ongoing water monitoring and treatment.
There are six other former MGP sites in the Minnesota service territory.
Remediation has been completed on one site. Of the remaining five sites, NorAm
believes that two were neither owned nor operated by NorAm; two were owned by
NorAm at one time but were operated by others and are currently owned by others;
and one site was previously operated by NorAm but was owned by others. NorAm
believes it has no liability with respect to the sites it neither owned nor
operated.
At December 31, 1997, NorAm had estimated a range of $15 million to $77
million for possible remediation of the Minnesota sites. The low end of the
range was determined based on only those sites presently owned or known to have
been operated by NorAm, assuming use of NorAm's proposed remediation methods.
The upper end of the range was determined based on the sites once owned by
NorAm, whether or not operated by NorAm. The cost estimates for the FMGW site
are based on studies of that site. The remediation costs for other sites are
based on industry average costs for remediation of sites of similar size. The
actual remediation costs will be dependent upon the number of sites remediated,
the participation of other potentially responsible parties, if any, and the
remediation methods used.
In its 1995 rate case, NorAm's Minnegasco division was allowed to recover
approximately $7 million annually for remediation costs. Such costs are subject
to a true-up mechanism whereby any over or under recovered amounts, net of
certain insurance recoveries, plus carrying charges, would be deferred for
recovery or refund in the next rate case. At December 31, 1997 and 1996,
Minnegasco had recorded a liability of $20.6 million and $35.9 million,
respectively, to cover the cost of future remediation. In addition, at December
31, 1997, Minnegasco had receivables from insurance settlements of $2.9 million.
These insurance settlements will be collected through 1999. Minnegasco expects
that approximately half of its accrual as of December 31, 1997 will be expended
within the next five years. The remainder will be expended on an ongoing basis
for an estimated 40 years. In accordance with the provisions of SFAS No. 71, a
regulatory asset has been recorded equal to the liability accrued. Minnegasco is
continuing to pursue recovery of at least a portion of these costs from
insurers. Minnegasco believes the difference between any cash expenditures for
these costs and the amount recovered in rates during any year will not be
material to the Company's or NorAm's overall cash requirements, results of
operations or cash flows.
Issues relating to the identification and remediation of MGPs are common in
the utility industry. NorAm has received notices from the EPA and others
regarding its status as a potentially responsible party for other sites. The
Company and NorAm have not been able to quantify a range of environmental
expenditures for potential remediation expenditures with respect to other MGP
sites.
Mercury Contamination. Like other natural gas pipelines, NorAm's pipeline
operations have in the past employed elemental mercury in meters used on its
pipelines. Although the mercury has now been removed from the meters, it is
possible that small amounts of mercury have been spilled at some of those sites
in the course of normal maintenance and replacement operations and that such
spills have contaminated the immediate area around the meters with elemental
mercury. Such contamination has been found by NorAm at some sites in the past,
and NorAm has conducted remediation at sites found to be contaminated. Although
NorAm is not aware of additional specific sites, it is possible that other
contaminated sites exist and that remediation costs will be incurred for such
sites. Although the total amount of such costs cannot be known at this time,
based on experience by NorAm and others in the natural gas industry to date and
on the current regulations regarding remediation of such sites, the Company and
NorAm believe that the cost of any
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remediation of such sites will not be material to the Company or NorAm's
financial position, results of operation or cash flows.
Other. From time to time the Company and/or its subsidiaries have received
notice from regulatory authorities or others that they are considered to be
potentially responsible parties in connection with sites found to require
remediation due to the presence of environmental contaminants. In addition, the
Company has been named as a defendant in litigation related to such sites and in
recent years has been named, along with numerous others, as a defendant in
several lawsuits filed by a large number of individuals who claim injury due to
exposure to asbestos while working at sites along the Texas Gulf Coast. Most of
these claimants have been workers who participated in construction of various
industrial facilities, including power plants, and some of the claimants have
worked at locations owned by the Company. The Company anticipates that
additional claims like those received may be asserted in the future and intends
to continue its practice of vigorously contesting claims which it does not
consider to have merit. Although their ultimate outcome cannot be predicted at
this time, the Company does not believe, based on its experience to date, that
these matters, either individually or in the aggregate, will have a material
adverse effect on the Company's financial position, results of operation or cash
flows.
There exists the possibility that additional legislation related to global
climate change, electromagnetic fields and other environmental and health issues
may be enacted. Compliance with such legislation could significantly affect the
Company and its subsidiaries. The precise impact of new legislation, if any,
will depend on the form of the legislation and the subsequent development and
implementation of applicable regulations.
OTHER CONTINGENCIES
For a description of certain other legal and regulatory proceedings affecting
the Company and its subsidiaries, see Notes 3, 4, 5 and 12 to the Company's
Consolidated Financial Statements, which notes are incorporated herein by
reference.
LIQUIDITY AND CAPITAL RESOURCES
COMPANY CONSOLIDATED CAPITAL REQUIREMENTS
The liquidity and capital requirements of the Company and its subsidiaries are
affected primarily by capital programs and debt service requirements. The
capital requirements for 1997 were, and as estimated for 1998 through 2000 are,
as follows:
MILLIONS OF DOLLARS
------------------------------
1997 1998 1999 2000
------ ------ ------ ------
Electric capital and nuclear fuel (excluding
Allowance for funds used during construction)
(AFUDC) $ 234 $ 331 $ 343 $ 308
Natural Gas Distribution(1) 61 138 146 150
Interstate Pipeline(1) 16 73 17 17
Energy Marketing(1) 14 8 7 8
International project expenditures (excluding
capitalized
interest)(2) 224 8 2 4
Corporate (excluding HIPG) 20 13 16 12
HIPG project expenditures (excluding capitalized
interest)(2) 3 311 26
Maturities of long-term debt, preferred stock and
minimum capital lease payments 282 233 380 1,430
------ ------ ------ ------
Total(3) $ 854 $1,115 $ 937 $1,929
====== ====== ====== ======
__________
(1) The 1997 capital expenditures for Natural Gas Distribution, Interstate
Pipeline and Energy Marketing are reported on an actual basis and reflect
expenditures only for the period from the effective date of the Merger,
August 6, 1997, through December 31, 1997. On a pro forma basis after giving
effect to the Merger on January 1, 1997, the capital expenditures for these
business segments would have been: Natural Gas Distribution ($131 million),
Interstate Pipeline ($26 million) and Energy Marketing ($24 million).
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(2) Expenditures in the table reflect only expenditures made or to be made under
existing contractual commitments entered into by International and HIPG.
International and HIPG capital requirements are expected to be met through
advances from the Company, the proceeds of project financings and the
proceeds of borrowings at the Company's financial subsidiaries. Additional
capital expenditures are dependent upon the nature and extent of future
project commitments (some of which may be substantial). Expenditures for
1998 include a $237 million commitment by HIPG to purchase four power plants
from Southern California Edison, which commitment was entered into in the
fourth quarter of 1997.
(3) Expenditures in the table do not reflect expenditures associated with the
Year 2000 issue and other system integration issues. For a discussion of
these expenditures, see "-- Certain Factors Affecting Future Earnings of the
Company and its Subsidiaries -- Impact of Year 2000 Issue and Other System
Implementation Issues."
The foregoing estimates are forward looking statements and are based on
numerous assumptions, some of which may prove to be incorrect. Actual liquidity
and capital requirements will also vary because of changes in governmental
regulations, the resolution of various litigation and other contingencies and
changes in economic conditions.
The Company and its subsidiaries generated $1.1 billion in cash flow from
operations in 1997. Substantially all of the Company's and its subsidiaries'
cash flow resulted from $421 million of income from continuing operations and
$652 million of non-cash depreciation and amortization expense. The Company used
this cash flow to reinvest in its existing businesses, to meet its dividend
requirements and to contribute to the financing of business expansion.
Overall, the Company's cash flow from operating activities in 1997 exceeded
its cash flow from non-acquisition investing activities by $787 million. With
respect to acquisition activities, the Company invested $1.4 billion of cash in
the acquisition of NorAm and $235 million of cash in non-rate regulated electric
power project expenditures in 1997.
In the first quarter of 1997, the Company repaid at maturity $40 million
aggregate principal amount of its 5 1/4% first mortgage bonds and $150 million
aggregate principal amount of its 7 5/8% first mortgage bonds.
In April 1997, the Company redeemed all remaining 257,000 shares of its $9.375
cumulative preferred stock pursuant to mandatory sinking fund requirements at a
cost of $25.7 million, plus accrued dividends. For additional information, see
Note 7(a) to the Company's Consolidated Financial Statements.
In June 1997, the Company purchased $57.6 million aggregate principal amount
of its 9.15% first mortgage bonds due 2021 for a total price of $69.6 million,
plus accrued interest. In November 1997, the Company repaid at maturity $35
million aggregate principal amount of its 6 3/4% first mortgage bonds.
In the fourth quarter of 1997, NorAm purchased $101.4 million aggregate
principal amount of its 10% Debentures due 2019 at an average price of 111.976%
plus accrued interest. In December 1997, NorAm repaid at maturity $52 million
aggregate principal amount of its medium term notes.
COMPANY CONSOLIDATED SOURCES OF CAPITAL RESOURCES AND LIQUIDITY
In 1997, two Delaware business trusts established by the Company issued
capital securities and preferred securities aggregating $350 million. The trusts
sold securities to the public ($100 million of 8.257% capital securities and
$250 million of 8.125% preferred securities) and used the proceeds to purchase
subordinated debentures from the Company. The Company used the proceeds from the
sale of the subordinated debentures for general corporate purposes, including
the repayment of short-term debt and the redemption of three series of
cumulative preferred stock having an aggregate liquidation value of $125
million. For further discussion, see Note 9(a) to the Company's Consolidated
Financial Statements.
In 1997, the Company sold in open market transactions 550,000 shares of Time
Warner common stock for approximately $25 million and transferred the remaining
450,000 shares of its Time Warner common stock
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(having a market value of $21.9
million) to Houston Industries Incorporated Foundation, a charitable foundation
not included in the Company's consolidated results, which was formed to fund
certain charitable activities in communities where the Company conducts its
business.
In April 1997, a subsidiary of HI Energy borrowed $162.5 million under a
$167.5 million five-year term loan facility. The proceeds of the loan, net of a
$17.5 million debt reserve account established for the benefit of the lenders,
were used to refinance a portion of the acquisition costs of Light.
In July 1997, the Company issued $1.052 billion aggregate face amount of ACES.
The Company used the proceeds from the sale of ACES for general corporate
purposes, including the retirement of then outstanding commercial paper. For
additional information regarding the ACES, see Note 8(e) to the Company's
Consolidated Financial Statements.
In August 1997, FinanceCo, a limited partnership subsidiary of the Company,
entered into a five-year, $1.6 billion revolving credit facility (FinanceCo
Facility). At December 31, 1997, the FinanceCo Facility supported $1.4 billion
in commercial paper borrowings having a weighted average interest rate of 6.15%.
Proceeds from the initial issuances of commercial paper by FinanceCo were used
to fund the cash portion of the consideration paid to stockholders of NorAm
under the terms of the Merger. For additional information regarding the
FinanceCo Facility, see Note 8(c) to the Company's Consolidated Financial
Statements.
At December 31, 1997, the Company, exclusive of NorAm and other subsidiaries,
had a revolving credit facility of $200 million with no borrowings outstanding.
In addition, at December 31, 1997, the Company had shelf registration statements
providing for the future issuance, subject to market and other conditions, of
$230 million aggregate liquidation value of its preferred stock and $580 million
aggregate principal amount of its debt securities.
At December 31, 1997, NorAm had (i) a $400 million revolving credit facility
under which loans of $340 million were outstanding, (ii) uncommitted lines of
credit under which loans of $50 million were outstanding, (iii) a trade
receivables facility of $300 million under which receivables of $300 million had
been sold and (iv) a shelf registration statement, filed with the Securities and
Exchange Commission in November 1997, providing for the future issuance of debt
securities of up to $500 million (NorAm Shelf Registration). For information
regarding the Company's maturing long-term debt (including NorAm's long-term
debt), see Note 8 to the Company's Consolidated Financial Statements.
In January 1998, pollution control revenue bonds aggregating $104.7 million
were issued on behalf of the Company by the Matagorda County Navigation District
Number One (MCND). Proceeds from the issuance were used in February 1998 to
redeem, at 102% of the aggregate principal amount, pollution control revenue
bonds aggregating $104.7 million.
In February 1998, pursuant to the NorAm Shelf Registration, NorAm issued $300
million of 6.5% debentures due February 1, 2008. The proceeds from the sale of
the debentures were used to repay short-term indebtedness of NorAm, including
the indebtedness incurred in connection with the purchase of $101.4 million of
its 10% debentures and the repayment of $53 million aggregate principal amount
of NorAm debt that matured in December 1997 and January 1998.
In February 1998, pollution control revenue bonds aggregating $290 million
were issued on behalf of the Company by the Brazos River Authority (BRA).
Proceeds from the issuance will be used to redeem, at 102% of the aggregate
principal amount, pollution control revenue bonds aggregating $290 million.
The Company owns 11 million shares of non-publicly traded TW Preferred. The TW
Preferred, which is entitled to cumulative annual dividends of $3.75 per share
until July 6, 1999, is currently convertible at the option of the Company into
22.9 million shares of Time Warner common stock. The Company's ability to
transfer, sell or pledge the shares of TW Preferred is not restricted pursuant
to the terms of the ACES. The Company reviews its investment in Time Warner on a
regular basis and does not expect to maintain its investment in Time Warner
indefinitely. For additional information regarding the Company's investment in
Time Warner securities, see Notes 1(n) and 8(e) to the Company's Consolidated
Financial Statements.
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The Company has consolidated its financing activities in order to provide a
coordinated, cost-effective method of meeting short- and long-term capital
requirements. As part of the consolidated financing program, the Company has
established a "money fund" through which its subsidiaries can borrow or invest
on a short-term basis. The funding requirements of individual subsidiaries are
aggregated and borrowing or investing is based on the net cash position. In
1997, net funding requirements under the money fund were met with commercial
paper.
Although the Company believes that its current level of cash and borrowing
capability along with future cash flows from operations are sufficient to meet
the needs of its existing businesses, the Company may, when it deems necessary,
supplement its available cash resources by seeking funds in the equity or debt
markets.
NEW ACCOUNTING ISSUES
In February 1997, the Financial Accounting Standards Board (FASB) issued SFAS
No. 128, "Earnings per Share" (SFAS No. 128) which is required to be implemented
for financial statements issued for fiscal years ending after December 15, 1997.
In 1997, the Company adopted SFAS No. 128 and retroactively restated prior
periods. For further discussion, see Note 1(j) to the Company's Consolidated
Financial Statements.
The FASB recently issued SFAS No. 130, "Reporting Comprehensive Income" (SFAS
No. 130), SFAS No. 131, "Disclosures about Segments of an Enterprise and Related
Information" (SFAS No. 131) and SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits" (SFAS No. 132) effective for
financial statements issued for fiscal periods beginning after December 15,
1997. SFAS No. 130 requires that all items that meet the definition of a
component of comprehensive income be reported in a financial statement for the
period in which they are recognized and the total amount of comprehensive income
be prominently displayed in that same financial statement. Comprehensive income
is defined as the change in equity of a business enterprise during a period from
transactions and other events and circumstances from non-owner sources.
Currently, the Company does not have any material items which require reporting
of comprehensive income. SFAS No. 131 requires that companies report financial
and descriptive information about reportable operating segments in financial
statements. Segments are to be defined based upon the way in which management
reviews its operations in order to assess performance and allocate its
resources. SFAS No. 132 revises employers' disclosures about pension and other
postretirement benefit plans. The Company will adopt SFAS No. 130, SFAS No. 131
and SFAS No. 132 in 1998.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The following discussion of the Company and its subsidiaries' exposure to
various market risks contains "forward looking statements" that involve risks
and uncertainties. These projected results have been prepared utilizing certain
assumptions considered reasonable in the circumstances and in light of
information currently available to the Company and its subsidiaries.
Nevertheless, because of the inherent unpredictability of interest rates, equity
market prices and energy commodity prices as well as other factors, actual
results could differ materially from those projected in such forward-looking
information. For a description of the Company's significant accounting policies
associated with these activities, see Notes 1 and 2 to the Company's
Consolidated Financial Statements.
INTEREST RATE RISK
The Company and its subsidiaries have long-term debt, Company/NorAm obligated
mandatorily redeemable securities of subsidiary trusts holding solely
subordinated debentures of the Company/NorAm (Trust Securities), securities held
in the Company's nuclear decommissioning trust, short-term credit lines and
facilities, certain lease obligations and interest rate swaps which subject the
Company and certain of its subsidiaries to the risk of loss associated with
movements in market interest rates.
At December 31, 1997, the Company and certain of its subsidiaries had fixed-
rate long-term debt (excluding ACES) and Trust Securities aggregating $4.2
billion in principal amount and having a fair value of $4.4 billion. These
instruments are fixed-rate and, therefore, do not expose the Company and its
subsidiaries to the risk of earnings loss due to changes in market interest
rates (see Notes 8 and 9 to the Company's Consolidated Financial Statements).
However, the fair value of these instruments would increase by approximately
$247.5 million if interest rates were to decline by 10% from their levels at
December 31, 1997. In general, such an increase in fair value would impact
earnings and cash flows only if the Company and its subsidiaries were to
reacquire all or a portion of these instruments in the open market prior to
their maturity.
The Company and certain of its subsidiaries' floating-rate obligations
aggregated $2.6 billion at December 31, 1997 (see Note 8 to the Company's
Consolidated Financial Statements), inclusive of (i) amounts borrowed under
short-term and long-term credit lines and facilities of the Company and its
subsidiaries, (ii) borrowings underlying NorAm's receivables facility and (iii)
amounts subject to a master leasing agreement under which lease payments vary
depending on short-term interest rates, which expose the Company and its
subsidiaries to the risk of increased interest and lease expense in the event of
increases in short-term interest rates. If the floating rates were to increase
by 10% from December 31, 1997 levels, the Company's consolidated interest
expense and expense under operating leases would increase by a total of
approximately $1.4 million each month in which such increase continued.
As discussed in Notes 1, 4 and 13 to the Company's Consolidated Financial
Statements, the Company contributes $14.8 million per year to a trust
established to fund the Company's share of the decommissioning costs for the
South Texas Project. The securities held by the trust for decommissioning costs
had an estimated fair value of $92.9 million as of December 31, 1997, of which
approximately 50 percent were fixed-rate debt securities that subject the
Company to risk of loss of fair value with movements in market interest rates.
If interest rates were to increase by 10% from their levels at December 31,
1997, the decrease in fair value of the fixed-rate debt securities would not be
material to the Company. In addition, the risk of an economic loss is mitigated
as a result of the Company's regulated status. Any unrealized gains or losses
are accounted for in accordance with SFAS No. 71 as a regulatory asset/liability
because the Company believes that its future contributions which are currently
recovered through the rate making process will be adjusted for these gains and
losses.
Certain subsidiaries of the Company have entered into interest rate swaps for
the purpose of decreasing the amount of debt subject to interest rate
fluctuations. At December 31, 1997, these interest rate swaps had an aggregate
notional amount of $281.1 million, which the Company could terminate at a cost
of $2.4 million (see Notes 2 and 13 to the Company's Consolidated Financial
Statements). An increase of 10% in the December 31, 1997 level of interest rates
would not increase the cost of termination of the swaps by a material
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amount to the Company. Swap termination costs would impact the Company and its
subsidiaries' earnings and cash flows only if all or a portion of the swap
instruments were terminated prior to their expiration.
EQUITY MARKET RISK
The Company holds an investment in TW Preferred which is convertible into Time
Warner common stock as described in "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Certain Factors Affecting
Future Earnings of the Company and its Subsidiaries -- Accounting Treatment of
ACES". As a result, the Company is exposed to losses in the fair value of this
security. For purposes of analyzing market risk in this Item 7A, the Company
assumed that the TW Preferred was converted into Time Warner common stock. In
addition, NorAm's investment in the common stock of Itron, Inc. (Itron) exposes
the Company and NorAm to losses in the fair value of Itron Common Stock. A 10%
decline in the per share price of Itron and Time Warner common stock from the
December 31, 1997 levels would result in a loss of approximately $2.7 million
and $142.0 million, respectively, in fair value.
The Company and its subsidiaries' ability to realize gains and losses related
to TW Preferred and Itron is limited by the following: (i) the TW Preferred is
not publicly traded and its sale is subject to certain limitations and (ii) the
market for the common stock of Itron is fairly illiquid.
The ACES expose the Company to accounting losses as the accounting for the
ACES requires the Company to record in Other Income (Expense) an unrealized
accounting loss equal to (i) the aggregate amount of the increase in the market
price of Time Warner common stock above $55.5844 as applicable to all ACES
multiplied by (ii) 0.8264. Prior to the conversion of the TW Preferred into Time
Warner common stock, such loss would effect earnings. After conversion such loss
would be recognized as an adjustment to common stock equity. See further
discussion of the accounting for the ACES in Notes 1 and 8 to the Company's
Consolidated Financial Statements. An increase of 15% in the price of the Time
Warner common stock above its December 31, 1997 market value of $62.00 per
share, would result in the recognition of an additional unrealized accounting
loss (net of tax) of approximately $114.4 million. The Company believes that
this additional unrealized loss for the ACES would be more than economically
hedged by the unrecorded unrealized gain relating to the increase in the fair
value of the Time Warner common stock underlying the investment in TW Preferred
since the date of its acquisition.
As discussed above under "Interest Rate Risk," the Company contributes to a
trust established to fund the Company's share of the decommissioning costs for
the South Texas Project which held debt and equity securities in approximately
equal proportions as of December 31, 1997. The equity securities expose the
Company to losses in fair value. If the market prices of the individual equity
securities were to decrease by 10% from their levels at December 31, 1997, the
resulting loss in fair value of these securities would not be material to the
Company. Currently, the risk of an economic loss is mitigated as a result of the
Company's regulated status as discussed above under "Interest Rate Risk."
ENERGY COMMODITY PRICE RISK
As further described in Note 2 to the Company's Consolidated Financial
Statements, certain of the Company's subsidiaries utilize a variety of
derivative financial instruments (Derivatives), including swaps and exchange-
traded futures and options, as part of the Company's overall risk management
strategies and for trading purposes. To reduce the risk from the adverse effect
of market fluctuations in the price of electric power, natural gas and related
transportation, NorAm and certain of its subsidiaries enter into futures
transactions, swaps and options (Energy Derivatives) in order to hedge certain
natural gas in storage, as well as certain expected purchases, sales and
transportation of natural gas and electric power (a portion of which are firm
commitments at the inception of the hedge). The Company's policies prohibit the
use of leveraged financial instruments. In addition, a subsidiary of NorAm
maintains a portfolio of Energy Derivatives for trading purposes (Trading
Derivatives).
The Company uses a sensitivity analysis method for determining the market risk
of its Energy Derivatives, except for its Trading Derivatives, for which it uses
a value-at-risk method.
25
<PAGE>
With respect to the Energy Derivatives (other than for trading purposes) held
by subsidiaries of NorAm as of December 31, 1997, a decrease of 10% in the
market price of natural gas from the December 31, 1997 levels would decrease the
fair value of these instruments by approximately $7.0 million.
The above analysis of the Energy Derivatives utilized for risk management
purposes does not include the favorable impact that the same hypothetical price
movement would have on the Company and its subsidiaries' physical purchases and
sales of natural gas and electric power. The portfolio of Energy Derivatives
held for risk management purposes approximates the notional quantity of the
expected or committed transaction volume of physical commodities with commodity
price risk for the same time periods. Furthermore, the Energy Derivative
portfolio is managed to complement the physical transaction portfolio, reducing
overall risks within limits. Therefore, the adverse impact to the fair value of
the portfolio of Energy Derivatives held for risk management purposes associated
with the hypothetical changes in commodity prices referenced above would be
offset by a favorable impact on the underlying hedged physical transactions,
assuming (i) the Energy Derivatives are not closed out in advance of their
expected term, (ii) the Energy Derivatives continue to function effectively as
hedges of the underlying risk, and (iii) as applicable, anticipated transactions
occur as expected.
The disclosure with respect to the Energy Derivatives relies on the assumption
that the contracts will exist parallel to the underlying physical transactions.
If the underlying transactions or positions are liquidated prior to the maturity
of the Energy Derivatives, a loss on the financial instruments may occur, or the
options might be worthless as determined by the prevailing market value on their
termination or maturity date, whichever comes first.
With respect to the Trading Derivatives held by a subsidiary of NorAm,
consisting of natural gas and electric power swaps, options and exchange-traded
futures, this subsidiary is exposed to losses in fair value due to price
movement. During the year ended December 31, 1997, the highest, lowest and
average quarterly value-at-risk in the Trading Derivative portfolio was less
than $5.0 million at a 95-percent confidence level and for a holding period of
one business day. The Company uses the variance/covariance method for
calculating the value-at-risk and includes the delta approximation for options
positions.
The Company has established a Corporate Risk Oversight Committee that oversees
all corporate price and credit risk, including derivative trading activities
discussed above. The committee's duties are to establish the Company's policies
and to monitor and ensure compliance with risk management limitations, policies
and procedures.
26
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(THOUSANDS OF DOLLARS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Revenues:
Electric Operations $4,251,243 $4,025,027 $3,680,297
Natural Gas Distribution 892,569
Interstate Pipeline 108,333
Energy Marketing 1,604,999
International 92,028 62,059 46,789
Other 47,851 8,191 2,185
Eliminations (123,638)
---------- ---------- ---------
Total 6,873,385 4,095,277 3,729,271
---------- ---------- ---------
Expenses:
Electric and natural gas utilities:
Fuel and cost of gas sold 2,819,512 1,024,945 879,148
Purchased power 698,823 322,263 233,494
Operation and maintenance 1,205,993 888,699 866,170
Taxes other than income taxes 296,668 246,288 245,890
Depreciation and amortization 651,875 550,038 478,034
Other operating expenses 136,014 72,578 121,085
---------- ---------- ---------
Total 5,808,885 3,104,811 2,823,821
---------- ---------- ---------
Operating Income 1,064,500 990,466 905,450
---------- ---------- ---------
Other Income (Expense):
Unrealized loss on ACES (121,402)
Litigation settlements (95,000)
Time Warner dividend income 41,340 41,610 20,132
Interest income 6,636 6,246 9,774
Interest income -- IRS refund 56,269
Other -- net 3,711 (8,268) (12,061)
---------- ---------- ----------
Total (13,446) (55,412) 17,845
---------- ---------- ----------
Interest and Other Charges:
Interest on long-term debt 320,845 276,242 279,491
Other interest 77,112 33,738 21,586
Distribution on trust securities 26,230
Allowance for borrowed funds used during
construction (2,872) (2,598) (4,692)
Preferred dividends of subsidiary 2,255 22,563 29,955
---------- ---------- ----------
Total 423,570 329,945 326,340
---------- ---------- ----------
Income from Continuing Operations Before Income
Taxes 627,484 605,109 596,955
Income Taxes 206,374 200,165 199,555
---------- ---------- ----------
Income from Continuing Operations 421,110 404,944 397,400
Discontinued Operations (Net of Income Taxes):
Gain on sale of cable television subsidiary 708,124
Preferred Dividends 162
---------- ---------- ----------
Net Income $ 420,948 $ 404,944 $1,105,524
========== ========== ==========
(continued on next page)
</TABLE>
27
<PAGE>
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(CONTINUED)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1997 1996 1995
----- ----- -----
<S> <C> <C> <C>
Basic Earnings Per Common Share:
Continuing Operations $1.66 $1.66 $1.60
Discontinued Operations:
Gain on sale of cable television subsidiary 2.86
----- ----- -----
Basic Earnings Per Common Share $1.66 $1.66 $4.46
===== ===== =====
Diluted Earnings Per Common Share:
Continuing Operations $1.66 $1.66 $1.60
Discontinued Operations:
Gain on sale of cable television subsidiary 2.86
----- ----- -----
Diluted Earnings Per Common Share $1.66 $1.66 $4.46
===== ===== =====
</TABLE>
See Notes to the Company's Consolidated Financial Statements.
28
<PAGE>
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED RETAINED EARNINGS
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Balance at Beginning of Year $1,997,490 $1,953,672 $1,221,221
Add -- Net Income 420,948 404,944 1,105,524
---------- ---------- ----------
Total 2,418,438 2,358,616 2,326,745
Common Stock Dividends:
1997, $1.50; 1996, $1.50; 1995, $1.50 (per share) (405,383) (361,126) (371,760)
Stock Dividend Distribution (1,313)
---------- ---------- ----------
Balance at End of Year $2,013,055 $1,997,490 $1,953,672
========== ========== ==========
</TABLE>
See Notes to the Company's Consolidated Financial Statements.
29
<PAGE>
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------
1997 1996
----------- -----------
<S> <C> <C>
Property, Plant and Equipment -- At Cost:
Electric plant:
Plant in service $12,614,000 $12,387,375
Construction work in progress 224,959 251,497
Nuclear fuel 255,567 241,001
Plant held for future use 48,631 48,631
Gas plant and pipelines:
Natural gas distribution 1,326,442
Interstate pipelines 1,258,087
Energy marketing 162,519
Other property 149,019 86,969
----------- -----------
Total 16,039,224 13,015,473
Less accumulated depreciation and amortization 4,770,179 4,259,050
----------- -----------
Property, plant and equipment -- net 11,269,045 8,756,423
----------- -----------
Current Assets:
Cash and cash equivalents 51,712 8,001
Accounts receivable -- net 962,974 36,277
Accrued unbilled revenues 205,860 77,853
Time Warner dividends receivable 10,313 10,313
Fuel stock and petroleum products 88,819 61,795
Materials and supplies, at average cost 156,160 130,380
Prepayments and other current assets 42,169 19,301
----------- -----------
Total current assets 1,518,007 343,920
----------- -----------
Other Assets:
Goodwill -- net 2,026,395
Investment in Time Warner securities 990,000 1,027,500
Deferred plant costs -- net 561,569 587,352
Fuel-related debits 197,304 84,435
Deferred debits 510,686 306,473
Unamortized debt expense and premium on reacquired debt 202,453 153,823
Regulatory tax asset -- net 356,509 362,310
Recoverable project costs -- net 78,485 163,630
Equity investments in foreign and non-rate regulated
affiliates -- net 704,102 501,991
----------- -----------
Total other assets 5,627,503 3,187,514
----------- -----------
Total $18,414,555 $12,287,857
=========== ===========
</TABLE>
See Notes to the Company's Consolidated Financial Statements.
30
<PAGE>
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
CAPITALIZATION AND LIABILITIES
DECEMBER 31,
------------------------
1997 1996
----------- -----------
Capitalization (statements on following pages):
Common stock equity $4,886,805 $3,827,961
Preference stock, none outstanding
Cumulative preferred stock, not subject to
mandatory redemption 9,740 135,179
Company/NorAm obligated mandatorily redeemable
preferred securities of subsidiary trusts holding
solely junior subordinated debentures of
Company/NorAm 362,172
Long-term debt 5,218,015 3,025,650
----------- -----------
Total capitalization 10,476,732 6,988,790
----------- -----------
Current Liabilities:
Notes payable 2,124,956 1,337,872
Accounts payable 879,612 157,682
Taxes accrued 240,739 191,011
Interest accrued 109,901 67,707
Dividends declared 110,716 92,515
Customer deposits 82,437 53,633
Current portion of long-term debt and preferred stock 251,169 254,463
Other 193,384 89,238
----------- -----------
Total current liabilities 3,992,914 2,244,121
----------- -----------
Deferred Credits:
Accumulated deferred income taxes 2,792,781 2,265,031
Benefit liabilities 397,586 249,875
Unamortized investment tax credit 349,072 373,749
Fuel-related credits 75,956 74,639
Other 329,514 91,652
----------- -----------
Total deferred credits 3,944,909 3,054,946
----------- -----------
Commitments and Contingencies (Note 12)
Total $18,414,555 $12,287,857
=========== ===========
See Notes to the Company's Consolidated Financial Statements
31
<PAGE>
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(THOUSANDS OF DOLLARS)
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------
1997 1996
------------- --------------
<S> <C> <C>
Common Stock Equity:
Common stock, no par; authorized, 700,000,000 shares; issued,
295,357,276 and 262,748,447 shares at December 31, 1997 and
1996, respectively $ 3,112,098 $ 2,447,117
Foreign currency translation loss (821) (363)
Treasury stock, at cost; 93,459 and 16,042,027 shares at December
31, 1997 and 1996, respectively (2,066) (361,196)
Unearned ESOP shares, 12,388,551 and 13,370,939 shares at
December 31, 1997 and 1996, respectively (229,827) (251,350)
Retained earnings 2,013,055 1,997,490
Unrealized loss on marketable equity securities (5,634) (3,737)
----------- -----------
Total common stock equity 4,886,805 3,827,961
----------- -----------
Preference Stock, no par; authorized, 10,000,000 shares; none
outstanding
Cumulative Preferred Stock, no par; authorized, 10,000,000 shares;
outstanding, 97,397 and 1,604,397 shares at December 31, 1997 and
1996, respectively (entitled upon involuntary liquidation to $100
per share):
Not subject to mandatory redemption:
$4.00 series, 97,397 shares 9,740 9,740
$6.72 series, 250,000 shares 25,115
$7.52 series, 500,000 shares 50,226
$8.12 series, 500,000 shares 50,098
----------- -----------
Total 9,740 135,179
----------- -----------
Subject to mandatory redemption:
$9.375 series, 257,000 shares at December 31, 1996 25,700
Current redemptions (25,700)
----------- -----------
Total
----------- -----------
Total cumulative preferred stock 9,740 135,179
----------- -----------
Company/NorAm obligated mandatorily redeemable preferred securities
of subsidiary trusts holding solely junior subordinated
debentures of Company/NorAm:
8.125% Trust Preferred Securities, Series A 250,000
8.257% Trust Capital Securities, Series B 100,000
6 1/4% Convertible Trust Originated Preferred Securities 21,730
Unamortized Issuance Costs (9,558)
----------- -----------
Total Company/NorAm obligated mandatorily redeemable
preferred securities of subsidiary trusts holding
solely junior subordinated debentures of
Company/NorAm-net 362,172
----------- -----------
Long-Term Debt:
7% Automatic common exchange securities, due 2000 1,173,786
----------- -----------
(continued on next page)
</TABLE>
32
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
Debentures:
9 3/8% series, due 2001 $ 250,000 $ 250,000
7 7/8% series, due 2002 100,000 100,000
8.9% series, due 2006 165,055
6% convertible subordinated, due 2012 107,180
10% series, due 2019 47,773
Unamortized discount (717) (902)
----------- -----------
Total debentures 669,291 349,098
----------- -----------
First Mortgage Bonds:
5 1/4% series, due 1997 40,000
7 5/8% series, due 1997 150,000
6 3/4% series, due 1997 35,000
9.15% series, due 2021 102,442 160,000
8 3/4% series, due 2022 62,275 62,275
7 3/4% series, due 2023 250,000 250,000
7 1/2% series, due 2023 200,000 200,000
4.90% pollution control series, due 2003 16,600 16,600
7% pollution control series, due 2008 19,200 19,200
6 3/8% pollution control series, due 2012 33,470 33,470
6 3/8% pollution control series, due 2012 12,100 12,100
8 1/4% pollution control series, due 2015 90,000 90,000
5.80% pollution control series, due 2015 91,945 91,945
7 3/4% pollution control series, due 2015 68,700 68,700
5.80% pollution control series, due 2015 58,905 58,905
7 7/8% pollution control series, due 2016 68,000
6.70% pollution control series, due 2017 43,820 43,820
5.60% pollution control series, due 2017 83,565 83,565
7 7/8% pollution control series, due 2018 50,000
7.20% pollution control series, due 2018 75,000 75,000
7.20% pollution control series, due 2018 100,000 100,000
7 7/8% pollution control series, due 2019 29,685 29,685
7.70% pollution control series, due 2019 75,000 75,000
8 1/4% pollution control series, due 2019 100,000 100,000
8.10% pollution control series, due 2019 100,000 100,000
7 5/8% pollution control series, due 2019 100,000 100,000
7 1/8% pollution control series, due 2019 100,000 100,000
7.60% pollution control series, due 2019 70,315 70,315
6.70% pollution control series, due 2027 56,095 56,095
Medium-term notes, series A, 9.80%-9.85%, due 1999 170,500 170,500
Medium-term notes, series C, 6.10%, due 2000 150,000 150,000
Medium-term notes, series B, 8.15%, due 2002 100,000 100,000
Medium-term notes, series C, 6.50%, due 2003 150,000 150,000
Unamortized discount (14,158) (15,134)
----------- -----------
Total first mortgage bonds 2,495,459 2,895,041
----------- -----------
(Continued on next page)
</TABLE>
33
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C>
Pollution Control Revenue Bonds:
Gulf Coast 1980-T series, floating rate, due 1998 $ 5,000 $ 5,000
1997 pollution control series, variable rate revenue due 2028 68,000
1997 pollution control series, variable rate revenue due 2018 50,000
----------- -----------
Total pollution control revenue bonds 123,000 5,000
----------- -----------
Medium-Term Notes:
Series A, 9.30%-9.39%, due 1998-2000 24,838
Series B, 8.43%-9.23%, due 1998-2001 236,367
----------- -----------
Total medium-term notes 261,205
----------- -----------
Capitalized lease obligations, discount rates of 5.2%-11.7%, due
1998-2018 16,166 4,418
Notes payable 730,277 856
----------- -----------
Subtotal 746,443 5,274
----------- -----------
Total 5,469,184 3,254,413
Current maturities (251,169) (228,763)
----------- -----------
Total long-term debt 5,218,015 3,025,650
----------- -----------
Total capitalization $10,476,732 $ 6,988,790
=========== ===========
</TABLE>
See Notes to the Company's Consolidated Financial Statements.
34
<PAGE>
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
(THOUSANDS OF DOLLARS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
---------- --------- ----------
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Income from continuing operations $421,110 $404,944 $397,400
Adjustments to reconcile income from continuing
operations to net cash provided by operating
activities:
Depreciation and amortization 651,875 550,038 478,034
Amortization of nuclear fuel 28,237 33,875 28,545
Deferred income taxes 35,523 54,098 78,382
Investment tax credit (19,777) (18,404) (19,427)
Unrealized loss on ACES 121,402
Contribution of marketable equity securities to
charitable trust 19,463
Fuel (refund)/surcharge 128,864 (189,571)
Fuel cost over (under) recovery (212,683) (137,362) 76,970
Net cash provided by discontinued cable television
operations 16,391
Changes in other assets and liabilities, net of the
effects of the acquisition:
Accounts receivable -- net (436,580) (15,478) (46,299)
Inventory 55,111 21,624 13,901
Other current assets 6,966 (306) (14,900)
Accounts payable 191,840 21,674 (23,217)
Interest and taxes accrued 18,425 4,413 11,088
Other current liabilities 2,985 (4,135) (9,215)
Other -- net 97,998 (661) 46,813
---------- --------- ----------
Net cash provided by operating activities 1,110,759 914,320 844,895
---------- --------- ----------
Cash Flows from Investing Activities:
Capital expenditures (including allowance for borrowed
funds used during construction) (328,724) (317,532) (301,327)
Purchase of NorAm net of cash acquired (1,422,672)
Non-rate regulated electric power project expenditures
(including capitalized interest) (234,852) (495,379) (49,835)
Settlement of subsidiary debt in connection with sale
of cable television subsidiary 619,345
Sale of investment in Time Warner common stock 25,043
Corporate headquarters expenditures (including
capitalized interest) (6,543) (96,469)
Net cash used in discontinued cable television
operations (47,601)
Other -- net (20,248) (13,446) (4,643)
---------- --------- ----------
Net cash provided by (used in) investing
activities (1,981,453) (832,900) 119,470
---------- --------- ----------
</TABLE>
35
<PAGE>
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Cash Flows from Financing Activities:
Proceeds from sale of ACES -- net $1,020,777
Proceeds from sale of Company obligated mandatorily
redeemable preferred securities of subsidiary trusts
holding solely junior subordinated debentures of
Company -- net 340,785
Purchase of treasury stock $(361,196)
Proceeds from issuance of pollution control bonds 115,739
Proceeds from first mortgage bonds $ 142,972
Payment of matured debt (277,000) (150,000)
Payment of common stock dividends (405,288) (361,126) (371,731)
Redemption of preferred stock (153,628) (271,400) (91,400)
Increase (decrease) in notes payable-net 587,791 1,331,572 (416,991)
Extinguishment of long-term debt (303,893) (285,263) (195,224)
Redemption of convertible securities (9,504)
Net cash used in discontinued cable television
operations (40,798)
Other -- net (1,374) 12,215 10,143
---------- --------- ----------
Net cash provided by (used in) financing
activities 914,405 (85,198) (963,029)
---------- --------- ----------
Net Increase (Decrease) in Cash and Cash Equivalents 43,711 (3,778) 1,336
Cash and Cash Equivalents at Beginning of Year 8,001 11,779 10,443
---------- --------- ----------
Cash and Cash Equivalents at End of Year $ 51,712 $ 8,001 $ 11,779
========== ========= ==========
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest (net of amounts capitalized) $ 437,952 $ 311,792 $ 342,551
Income taxes 171,539 139,898 104,228
</TABLE>
The aggregate consideration paid to Former NorAm stockholders in connection with
the Merger consisted of $1.4 billion in cash and 47.8 million shares of the
Company's common stock valued at approximately $1.0 billion. The overall
transaction was valued at $4.0 billion consisting of $2.4 billion for Former
NorAm's common stock and common stock equivalents and $1.6 billion of Former
NorAm debt.
See Notes to the Company's Consolidated Financial Statements.
36
<PAGE>
HOUSTON INDUSTRIES INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1997
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Nature of Operations.
The Company (defined below), together with its subsidiaries, is a diversified
international energy services company. The Company is both an electric utility
company and a utility holding company. The Company's wholly owned subsidiary,
NorAm, operates in various phases of the natural gas industry, including
distribution, transmission, marketing and gathering.
(b) NorAm Acquisition.
On August 6, 1997 (Acquisition Date), Houston Industries Incorporated (Former
HI) merged with and into Houston Lighting & Power Company, which was renamed
"Houston Industries Incorporated" (Company), and NorAm Energy Corp., a natural
gas gathering, transmission, marketing and distribution company (Former NorAm)
merged with and into a subsidiary of the Company, HI Merger, Inc., which was
renamed "NorAm Energy Corp." (NorAm). Effective upon the mergers (collectively,
the Merger), each outstanding share of common stock of Former HI was converted
into one share of common stock (including associated preference stock purchase
rights) of the Company, and each outstanding share of common stock of Former
NorAm was converted into the right to receive $16.3051 cash or 0.74963 shares of
common stock of the Company. The aggregate consideration paid to Former NorAm
stockholders in connection with the Merger consisted of $1.4 billion in cash and
47.8 million shares of the Company's common stock valued at approximately $1.0
billion. The overall transaction was valued at $4.0 billion consisting of $2.4
billion for Former NorAm's common stock and common stock equivalents and $1.6
billion of Former NorAm debt ($1.3 billion of which was long-term debt).
The Company has recorded the acquisition of NorAm under the purchase method of
accounting with assets and liabilities of NorAm reflected at their estimated
fair values as of the Acquisition Date. The Company has recorded the $2.0
billion excess of the acquisition cost over the fair value of the net assets
acquired as goodwill and is amortizing this amount over 40 years. On a
preliminary basis, the Company's fair value adjustments included increases in
property, plant and equipment, long-term debt, unrecognized pension and
postretirement benefits liabilities and related deferred taxes. The Company
expects to finalize these fair value adjustments during 1998; however, it is not
anticipated that any additional adjustments will be material.
The Company's results of operations incorporate NorAm's results of operations
only for the period beginning on the Acquisition Date. The following table
presents certain unaudited pro forma information for the years ended December
31, 1997 and 1996, as if the Merger had occurred on January 1, 1997 and 1996,
respectively.
PRO FORMA COMBINED RESULTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
1997 1996
-------------------- ------------------
PRO FORMA PRO FORMA
--------- ---------
AS AS
REPORTED REPORTED
-------- --------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C> <C>
Revenues $6,873 $10,210 $4,095 $8,884
Net Income Available for Common Stock $ 421 $ 439 $ 405 $ 432
Basic Earnings Per Share $ 1.66 $ 1.56 $ 1.66 $ 1.48
Diluted Earnings Per Share $ 1.66 $ 1.56 $ 1.66 $ 1.48
</TABLE>
37
<PAGE>
These and other pro forma results appearing in this Form 10-K are based on
assumptions deemed appropriate by the Company's management, have been prepared
for informational purposes only and are not necessarily indicative of the
combined results that would have resulted had the Merger occurred at the
beginning of the 1996 and 1997 reporting periods presented. Purchase related
adjustments to results of operations include amortization of goodwill and the
effects on depreciation, amortization, interest expense and deferred income
taxes of the revaluation, on a preliminary basis, of the fair value of certain
NorAm assets and liabilities.
As a result of the Merger, the Company has organized its financial reporting
into the following segments: Electric Operations, Natural Gas Distribution,
Interstate Pipeline, Energy Marketing, International and Corporate. For segment
information, see Note 15.
(c) Regulatory Assets and Other Long-Lived Assets.
The Company and certain subsidiaries of NorAm apply the accounting policies
established in SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation," to the accounts of Electric Operations, Natural Gas Distribution
and the Interstate Pipeline operations of MRT. In general, SFAS No. 71 permits a
company with cost-based rates to defer certain costs that would otherwise be
expensed to the extent that the rate regulated company is recovering or expects
to recover such costs in rates charged to its customers.
The following is a list of regulatory assets and liabilities reflected on the
Company's Consolidated Balance Sheet as of December 31, 1997, detailed by
Electric Operations and other segments.
OTHER
ELECTRIC ----- TOTAL
OPERATIONS COMPANY
---------- -------
(MILLIONS OF DOLLARS)
Deferred plant costs -- net $ 562 $ 562
Recoverable project costs -- net 78 78
Regulatory tax asset -- net 357 357
Unamortized loss on required debt 127 127
Deferred debits 71 $ 48 119
Accumulated deferred income taxes -- regulatory tax
asset (99) (99)
------ ---- ------
Total $1,096 $ 48 $1,144
====== ==== ======
If, as a result of changes in regulation or competition, the Company and
NorAm's ability to recover these assets and/or liabilities would not be assured,
then pursuant to SFAS No. 101, "Accounting for the Discontinuation of
Application of SFAS No. 71" and SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," the Company and
NorAm would be required to write off or write down such net regulatory assets to
the extent that they ultimately were determined not to be recoverable.
Effective January 1, 1996, the Company and NorAm adopted SFAS No. 121. SFAS
No. 121 requires that long-lived assets and certain identifiable intangibles to
be held and used or disposed of by an entity be reviewed for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. Adoption of the standard did not result in a write-down
of the carrying amount of any asset on the books of the Company or NorAm.
In July 1997, the Emerging Issues Task Force (EITF) of the FASB reached a
consensus on Issue No. 97-4, "Deregulation of the Pricing of Electricity --
Issues Related to the Application of FASB Statements No. 71, Accounting for the
Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises --
Accounting for the Discontinuation of Application of FASB Statement No. 71"
(EITF 97-4). EITF 97-4 concluded that the application of SFAS No. 71 to a
segment which is subject to a deregulation
38
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plan should cease when the legislation and enabling rate order contain
sufficient detail for the utility to reasonably determine what the transition
plan will entail. In addition, EITF 97-4 requires the regulatory assets and
liabilities to be allocated to the applicable portion of the electric utility
from which the source of the regulated cash flows will be derived. On June 2,
1997, the Texas legislature adjourned without having adopted or taken any formal
action with respect to various proposals concerning the restructuring of the
Texas electric utility industry, including proposals related to retail electric
competition and stranded cost recovery. At this time, the Company cannot predict
what, if any, action the Texas legislature may take in the next legislative
session (scheduled to commence in 1999) with respect to any of these proposals
or the ultimate form in which such proposals may be adopted, if at all. Although
the Company has determined that no impairment loss or write-offs of regulatory
assets need be recognized for applicable assets of continuing operations as of
December 31, 1997, this conclusion may change in the future (i) as competition
influences wholesale and retail pricing in the electric utility industry, (ii)
depending on regulatory action, if any and (iii) depending on legislation, if
any, that is passed.
(d) Principles of Consolidation.
The consolidated financial statements include the accounts of the Company and
its wholly owned and majority owned subsidiaries including, effective as of the
Acquisition Date, the accounts of NorAm and its wholly owned and majority owned
subsidiaries.
Investments in entities in which the Company or its subsidiaries have an
ownership interest between 20% and 50% or are able to exercise significant
influence are accounted for using the equity method. For additional information
regarding investments recorded using the equity method or the cost method of
accounting, see Note 5.
All significant intercompany transactions and balances are eliminated in
consolidation.
(e) Property, Plant and Equipment and Goodwill.
Property, plant and equipment are stated at original cost of the acquirer.
Repair and maintenance costs are expensed as incurred. Depreciation is computed
using the straight-line method.
Goodwill is being amortized on a straight-line basis over 40 years. The
Company will periodically compare the carrying value of its goodwill to the
anticipated undiscounted future operating income from the businesses whose
acquisition gave rise to the goodwill and as of yet no impairment is indicated
or expected.
(f) Depreciation and Amortization Expense.
The Company's 1997 depreciation and amortization expenses included $50 million
of additional depreciation in connection with the South Texas Project and $21.6
million for goodwill amortization associated with the acquisition of NorAm. For
additional information regarding the amortization of goodwill in connection with
the Merger, see Note 1(b) above. The amortization expenses recorded in
connection with the South Texas Project are being made pursuant to the terms of
the Company's most recent rate case settlement (1995 Rate Case Settlement),
which permits the Company to write down up to $50 million per year of its
investment in the South Texas Project through December 31, 1999. These write-
downs are treated under the settlement as reasonable and necessary expenses for
purposes of any future earnings reviews or other proceedings. In each of 1997,
1996 and 1995, the Company recorded the maximum $50 million pre-tax write-down
permitted under the 1995 Rate Case Settlement.
In 1996 and 1997, the Company, as permitted by the 1995 Rate Case Settlement,
also amortized $50 million and $66 million (pre-tax), respectively, of its $153
million investment in certain lignite reserves associated with a canceled
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<PAGE>
generating station. The Company's remaining investment in the canceled
generating station and certain lignite reserves ($78 million at December 31,
1997) will be amortized fully no later than December 31, 2000.
The Company's consolidated depreciation expense for 1997 was $475 million
compared to $410 million for 1996 and $399 million for 1995.
(g) Deferred Plant Costs.
Under a "deferred accounting" plan authorized by the Texas Utility Commission,
Electric Operations was permitted for regulatory purposes to accrue carrying
costs in the form of allowance for funds used during construction on its
investment in the South Texas Project and to defer and capitalize depreciation
and other operating costs on its investment after commercial operation until
such costs were reflected in rates. In addition, the Texas Utility Commission
authorized Electric Operations under a "qualified phase-in plan" to capitalize
allowable costs (including return) deferred for future recovery as deferred
charges.
In 1991, Electric Operations ceased all cost deferrals related to the South
Texas Project and began amortizing such amounts on a straight-line basis. The
accumulated deferrals for "deferred accounting" are being amortized over the
estimated depreciable life of the South Texas Project. The accumulated deferrals
for the "qualified phase-in plan" are being amortized over a ten-year phase-in
period that commenced in 1991. The amortization of all deferred plant costs
(which totaled $25.8 million for each of the years 1997, 1996 and 1995) is
included on the Company's Statements of Consolidated Income as depreciation and
amortization expense.
(h) Fuel Stock.
Gas inventory (primarily using the average cost method) was $71.7 million and
$19.6 million at December 31, 1997 and 1996, respectively. Coal, lignite, and
oil inventory balances (using last-in, first-out) were $7.5 million, $6.4
million and $3.3 million, respectively, at December 31, 1997 and $27.3 million,
$11.8 million and $3.0 million, respectively, at December 31, 1996.
(i) Revenues.
The Company records electricity sales under the full accrual method, whereby
unbilled electricity sales are estimated and recorded each month. NorAm's rate-
regulated divisions/subsidiaries bill customers on a monthly cycle billing
basis. Revenues are recorded on an accrual basis, including an estimate for gas
delivered but unbilled at the end of each accounting period. International
revenues include electricity sales of a majority owned foreign electric utility,
which are also recorded under the full accrual method, and equity income (net of
foreign taxes) in unconsolidated investments of HI Energy. Included in other
revenues are management fees and other sales and services, which are recorded
when earned.
Revenue eliminations of $124 million represent intersegment sales of natural
gas and transportation services. For the five month period ended December 31,
1997, Interstate Pipeline had intersegment revenues of $59 million from Natural
Gas Distribution and Energy Marketing. For the same period, Energy Marketing had
intersegment sales of $61 million to Interstate Pipeline and Natural Gas
Distribution. The remaining intercompany revenue balances were between Corporate
and other segments.
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(j) Earnings Per Common Share.
In February 1997, the FASB issued SFAS No. 128, "Earnings per Share", which is
required to be implemented for fiscal years ending after December 15, 1997. This
statement requires restatement of all prior period earnings per share (EPS) data
presented herein. SFAS No. 128 requires dual presentation of basic and diluted
EPS on the face of the Statements of Consolidated Income and requires a
reconciliation of the numerators and denominators used in the basic and diluted
earnings per share calculations.
Following is a reconciliation of the Company's numerators and denominators of
basic and diluted earnings per share calculations:
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
------------------------------
1997 1996 1995
-------- -------- ----------
(IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS)
<S> <C> <C> <C>
Basic EPS Calculation:
Income from continuing operations $421,110 $404,944 $ 397,400
Gain on sale of cable television subsidiary 708,124
Less: Preferred dividends 162
-------- -------- ----------
Net income available for common stock $420,948 $404,944 $1,105,524
======== ======== ==========
Weighted average shares outstanding 253,599 244,443 247,706
Basic EPS:
Income from continuing operations $ 1.66 $ 1.66 $ 1.60
Gain on sale of cable television subsidiary 2.86
Less: Preferred dividends .00
-------- -------- ----------
Net income available for common stock $ 1.66 $ 1.66 $ 4.46
======== ======== ==========
Diluted EPS Calculation:
Income from continuing operations $421,110 $404,944 $ 397,400
Plus: Income impact of assumed conversions
Interest on 6 1/4% convertible debentures 668
-------- -------- ----------
Income from continuing operations assuming dilution 421,778 404,944 397,400
Gain on sale of cable television subsidiary 708,124
Less: Preferred dividends 162
-------- -------- ----------
Net income available for common stock assuming
dilution $421,616 $404,944 $1,105,524
======== ======== ==========
Weighted average shares outstanding 253,599 244,443 247,706
Plus: Incremental shares from assumed conversions:
Stock options 89 33 21
6 1/4% convertible debentures 510
-------- -------- ----------
Weighted average shares assuming dilution 254,198 244,476 247,727
======== ======== ==========
Diluted EPS:
Income from continuing operations $ 1.66 $ 1.66 $ 1.60
Gain on sale of cable television subsidiary 2.86
Less: Preferred dividends .00
-------- -------- ----------
Net income available for common stock $ 1.66 $ 1.66 $ 4.46
======== ======== ==========
</TABLE>
Options to purchase 405,684 shares of common stock at prices ranging from
$22.09 to $35.18 per share were outstanding during 1997 but were not included in
the computation of diluted EPS because,
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<PAGE>
during the reporting period, the options' exercise prices were greater than the
average market price of the common shares of $21.875 and would thus be anti-
dilutive if conversion were assumed.
(k) Statements of Consolidated Cash Flows.
For purposes of reporting cash flows, cash equivalents are considered to be
short-term, highly liquid investments readily convertible to cash.
(l) Derivative Financial Instruments (Risk Management).
For information regarding the Company's accounting for derivative financial
instruments associated with its subsidiaries' natural gas, electric power and
transportation risk management activities, see Note 2.
(m) Income Taxes.
The Company and its subsidiaries file a consolidated federal income tax
return. The Company follows a policy of comprehensive interperiod income tax
allocation. Investment tax credits were deferred and are being amortized over
the estimated lives of the related property. For additional information
regarding income taxes, see Note 11.
(n) Investments in Time Warner Securities.
The Company owns 11 million shares of non-publicly traded Time Warner
convertible preferred stock (TW Preferred). The TW Preferred is redeemable after
July 6, 2000, has an aggregate liquidation preference of $100 per share (plus
accrued and unpaid dividends), is entitled to annual dividends of $3.75 per
share until July 6, 1999, is currently convertible by the Company and after July
6, 1999 is exchangeable by Time Warner into approximately 22.9 million shares of
Time Warner common stock. Each share of preferred stock is entitled to two votes
(voting together with the holders of the Time Warner common stock as a single
class).
The Company has recorded its investment in these securities at a value of $990
million on the Company's Consolidated Balance Sheets. Investment in the TW
Preferred is accounted for under the cost method. Dividends on these securities
are recognized as income at the time they are earned. The Company recorded pre-
tax dividend income with respect to the Time Warner securities of $41.3 million,
$41.6 million and $20.1 million in 1997, 1996 and 1995, respectively.
To monetize its investment in the TW Preferred, the Company sold in July 1997,
22.9 million of its unsecured 7% ACES. For additional information about the
offering of ACES, see Note 8(e). As a result of the issuance of the ACES, a
portion of the increase in the market value above $55.5844 per share of Time
Warner common stock (the security into which the TW Preferred is convertible)
results in unrealized accounting losses to the Company for the ACES, pending the
conversion of the Company's TW Preferred into Time Warner common stock. For
example, prior to the conversion of the TW Preferred into Time Warner common
stock, when the market price of Time Warner common stock increases above
$55.5844, the Company records in Other Income (Expense) an accounting loss for
the ACES equal to (i) the aggregate amount of such increase as applicable to all
ACES multiplied by (ii) 0.8264. In accordance with generally accepted accounting
principles, this accounting loss (which reflects the unrealized increase in the
Company's indebtedness with respect to the ACES) may not be offset by accounting
recognition of the increase in the market value of the Time Warner common stock
that underlies the TW Preferred. Upon conversion of the TW Preferred, the
Company will begin recording unrealized net changes in the market prices of the
Time Warner common stock and the ACES as a component of common stock equity.
As of December 31, 1997, the market price of Time Warner common stock was
$62.00 per share. Accordingly, the Company recognized an increase of $121
million in the unrealized liability relating to its ACES indebtedness (which
resulted in an after-tax earnings reduction of $79 million or $.31 per share).
The
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<PAGE>
Company believes that this unrealized loss for the ACES is more than
economically hedged by the approximately $430 million unrecorded unrealized gain
at December 31, 1997 relating to the increase in the fair value of the Time
Warner common stock underlying the investment in TW Preferred since the date of
its acquisition. As of February 28, 1998, the price of Time Warner common stock
was $67.50 per share which would have resulted in the Company recognizing an
additional increase of $104 million in the unrealized liability represented by
its indebtedness under the ACES. The related unrecorded unrealized gain as of
February 28, 1998 would have been computed as an additional $126 million.
(o) Investment in Other Debt and Equity Securities.
The securities held in the Company's nuclear decommissioning trust are
classified as "available-for-sale" and, in accordance with SFAS No. 115,
"Accounting for Certain Investments in Debt and Equity Securities," (SFAS No.
115) are reported at estimated fair value of $92.9 million as of December 31,
1997 and $67 million as of December 31, 1996 on the Company's Consolidated
Balance Sheets under deferred debits. The liability for nuclear decommissioning
is reported on the Company's Consolidated Balance Sheets under deferred credits.
Any unrealized gains or losses are accounted for in accordance with SFAS No. 71
as a regulatory asset/liability and reported on the Company's Consolidated
Balance Sheets as a deferred debit/ credit.
The Company, through its subsidiary, NorAm, holds certain equity securities
classified as "available-for-sale" and in accordance with SFAS No. 115 reports
such investments at estimated fair values on the Company's Consolidated Balance
Sheets as deferred debits and any unrealized gain or loss, net of tax, as a
separate component of stockholders' equity. At December 31, 1997, the unrealized
loss relating to these equity securities was approximately $5.6 million, net of
tax.
(p) Discontinued Operations.
In July 1995, the Company sold KBLCOM, its cable television subsidiary. The
Company's 1995 earnings include a one-time after-tax gain of $708 million
related to the sale, which includes the net loss for discontinued operations of
KBLCOM through the date of sale (July 6, 1995).
(q) Reclassifications and Use of Estimates.
Certain amounts from the previous years have been reclassified to conform to
the 1997 presentation of financial statements. Such reclassifications do not
affect earnings.
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates.
(r) Other.
For information regarding executive incentive compensation, pensions and other
benefits, see Note 10.
(2) DERIVATIVE FINANCIAL INSTRUMENTS (RISK MANAGEMENT)
(a) Trading Activities.
The Company, through NES, a subsidiary of NorAm, offers price risk management
services primarily in the natural gas and electric industries. NES provides
these services through, and by utilizing, a variety of derivative financial
instruments, including fixed-price swap agreements, variable-price swap
agreements,
43
<PAGE>
exchange-traded energy futures and option contracts, and swaps and options
traded in the over-the-counter financial markets. Fixed-price swap agreements
require payments to, or receipts of payments from, counterparties based on the
differential between a fixed and variable price for the commodity. Variable-
price swap agreements require payments to, or receipts of payments from,
counterparties based on the differential between either industry pricing
publications or exchange quotations.
Certain trading transactions qualify for hedge accounting and accordingly
unrealized gains and losses associated with these transactions are deferred. For
trading transactions that do not qualify for hedge accounting, NES uses mark-to-
market accounting. Accordingly, such financial instruments are recorded at fair
value with realized and unrealized gains (losses) recorded as a component of
operating revenues in the Company's Consolidated Statements of Income. The
recognized, unrealized balance is recorded as a deferred debit on the Company's
Consolidated Balance Sheets.
The notional quantities and maximum terms of derivative financial instruments
held for trading purposes at December 31, 1997 are presented below (volumes in
billions of British thermal units equivalent (Bbtue)):
VOLUME-FIXED VOLUME-FIXED MAXIMUM
PRICE PAYOR PRICE TERM (YEARS)
------------ RECEIVER ------------
--------
Natural gas 85,701 64,890 4
Electricity 40,511 42,976 1
In addition to the fixed-price notional volumes above, NES also has variable-
price swap agreements, as discussed above, totaling 101,465 Bbtue. Notional
amounts reflect the volume of transactions but do not represent the amounts
exchanged by the parties to the financial instruments. Accordingly, notional
amounts do not accurately measure the Company's exposure to market or credit
risks.
The estimated fair value of derivative financial instruments held for trading
purposes at December 31, 1997 are presented below (dollars in millions):
FAIR VALUE AVERAGE FAIR VALUE(A)
--------------------
ASSETS LIABILITIES ASSETS LIABILITIES
------ ----------- ------ -----------
Natural gas $46 $39 $56 $48
Electricity $ 6 $ 6 $ 3 $ 2
__________
(a) Computed using the ending balance of each month.
Substantially all of the fair value shown in the table above at December 31,
1997 has been recognized in income. The fair value as of and for the year ended
December 31, 1997 was estimated using quoted prices where available and
considering the liquidity of the market for the derivative financial
instruments. The prices are subject to significant changes based on changing
market conditions. The derivative financial instruments included in the NES
trading portfolio as of and for the year ended December 31, 1996 were
immaterial.
The weighted-average term of the trading portfolio, based on volumes, is less
than one year. The maximum and average terms disclosed herein are not indicative
of likely future cash flows as these positions may be changed by new
transactions in the trading portfolio at any time in response to changing market
conditions, market liquidity and the Company's risk management portfolio needs
and strategies. Terms regarding cash settlements of these contracts vary with
respect to the actual timing of cash receipts and payments.
44
<PAGE>
(b) Non-Trading Activities.
To reduce the risk from market fluctuations in the price of electric power,
natural gas and related transportation, NorAm and certain of its subsidiaries
enter into futures transactions, swaps and options (Energy Derivatives) in order
to hedge certain natural gas in storage, as well as certain expected purchases,
sales and transportation of natural gas and electric power (a portion of which
are firm commitments at the inception of the hedge). Energy Derivatives are also
utilized to fix the price of compressor fuel or other future operational gas
requirements, although usage to date for this purpose has not been material.
Usage of electricity derivative financial instruments by the Company and its
subsidiaries for purposes other than trading is immaterial.
Certain subsidiaries of the Company also utilize interest-rate derivatives
(principally interest-rate swaps) in order to adjust the portion of its overall
borrowings which are subject to interest-rate risk, and also utilize such
derivatives to effectively fix the interest rate on debt expected to be issued
for refunding purposes.
For transactions involving either Energy Derivatives or interest-rate
derivatives, hedge accounting is applied only if the derivative (i) reduces the
price risk of the underlying hedged item and (ii) is designated as a hedge at
its inception. Additionally, the derivatives must be expected to result in
financial impacts which are inversely correlated to those of the item(s) to be
hedged. This correlation (a measure of hedge effectiveness) is measured both at
the inception of the hedge and on an ongoing basis, with an acceptable level of
a correlation of at least 80% for hedge designation. If and when correlation
ceases to exist at an acceptable level, hedge accounting ceases and mark-to-
market accounting is applied.
In the case of interest-rate swaps associated with existing obligations, cash
flows and expenses associated with the interest-rate derivative transactions are
matched with the cash flows and interest expense of the obligation being hedged,
resulting in an adjustment to the effective interest rate. When interest rate
swaps are utilized to effectively fix the interest rate for an anticipated debt
issuance, changes in the market value of the interest-rate derivatives are
deferred and recognized as an adjustment to the effective interest rate on the
newly issued debt.
Unrealized changes in the market value of Energy Derivatives utilized as
hedges are not generally recognized in the Company's Consolidated Statements of
Income until the underlying hedged transaction occurs. Once it becomes probable
that an anticipated transaction will not occur, deferred gains and losses are
recognized. In general, the financial impact of transactions involving these
Energy Derivatives is included in the Company's Statement of Consolidated Income
under the captions (i) fuel expenses, in the case of natural gas transactions,
and (ii) purchased power, in the case of electric power transactions. Cash flows
resulting from these transactions in Energy Derivatives are included in the
Company's Statements of Consolidated Cash Flows in the same category as the item
being hedged.
At December 31, 1997, subsidiaries of NorAm were fixed-price payors and fixed-
price receivers in Energy Derivatives covering 38,754 Bbtu and 7,647 Bbtu of
natural gas, respectively. Also, at December 31, 1997 subsidiaries of NorAm were
parties to variable-priced Energy Derivatives totaling 3,630 Bbtu of natural
gas. The weighted average maturity of these instruments is less than one year.
The notional amount is intended to be indicative of the Company and its
subsidiaries' level of activity in such derivatives, although the amounts at
risk are significantly smaller because, in view of the price movement
correlation required for hedge accounting, changes in the market value of these
derivatives generally are offset by changes in the value associated with the
underlying physical transactions or in other derivatives. When Energy
Derivatives are closed out in advance of the underlying commitment or
anticipated transaction, however, the market value changes may not offset due to
the fact that price movement correlation ceases to exist when the positions are
closed as further discussed below. Under such circumstances, gains (losses) are
deferred and recognized as a component of income when the underlying hedged item
is recognized in income.
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<PAGE>
The average maturity discussed above and the fair value discussed in Note 13
are not necessarily indicative of likely future cash flows as these positions
may be changed by new transactions in the trading portfolio at any time in
response to changing market conditions, market liquidity and the Company's risk
management portfolio needs and strategies. Terms regarding cash settlements of
these contracts vary with respect to the actual timing of cash receipts and
payments.
(c) Trading and Non-trading -- General Policy.
In addition to the risk associated with price movements, credit risk is also
inherent in the Company and its subsidiaries' risk management activities. Credit
risk relates to the risk of loss resulting from non-performance of contractual
obligations by a counterparty. While, as yet, the Company and its subsidiaries
have experienced no significant losses due to the credit risk associated with
these arrangements, the Company has off-balance sheet risk to the extent that
the counterparties to these transactions may fail to perform as required by the
terms of each such contract. In order to minimize this risk, the Company and/or
its subsidiaries, as the case may be, enter into such contracts primarily with
those counterparties with a minimum Standard & Poor's or Moody's rating of BBB-
or Baa3, respectively. For long-term arrangements, the Company and its
subsidiaries periodically review the financial condition of such firms in
addition to monitoring the effectiveness of these financial contracts in
achieving the Company's objectives. Should the counterparties to these
arrangements fail to perform, the Company would seek to compel performance at
law or otherwise, or obtain compensatory damages in lieu thereof. The Company
might be forced to acquire alternative hedging arrangements or be required to
honor the underlying commitment at then current market prices. In such event,
the Company might incur additional loss to the extent of amounts, if any,
already paid to the counterparties. In view of its criteria for selecting
counterparties, its process for monitoring the financial strength of these
counterparties and its experience to date in successfully completing these
transactions, the Company believes that the risk of incurring a significant
financial statement loss due to the non-performance of counterparties to these
transactions is minimal.
The Company's policies prohibit the use of leveraged financial instruments.
The Company has established a Risk Oversight Committee to oversee all
corporate price and credit risk, including NES' risk management and trading
activities. The Risk Oversight Committee's responsibilities include reviewing
the Company and its subsidiaries' overall risk management strategy and
monitoring risk management activities to ensure compliance with the Company's
risk management limitations, policies and procedures.
(3) RATE MATTERS
(a) Electric Proceedings.
The Texas Utility Commission has original (or in some cases appellate)
jurisdiction over Electric Operations' electric rates and services. Texas
Utility Commission orders may be appealed to a District Court in Travis County,
and from that court's decision an appeal may be taken to the Court of Appeals
for the 3rd District at Austin (Austin Court of Appeals). Discretionary review
by the Supreme Court of Texas may be sought from decisions of the Austin Court
of Appeals. In the event that the courts ultimately reverse actions of the Texas
Utility Commission, such matters are remanded to the Texas Utility Commission
for action in light of the courts' orders.
(b) Transition and Price Reduction Plan.
In 1997, the Texas legislature considered but did not pass legislation
intended to address various issues concerning the restructuring of the electric
utility industry, including proposals that would permit Texas retail electric
customers to choose their own electric suppliers beginning on December 31, 2001.
The legislative proposals included provisions relating to full stranded cost
recovery; rate reductions; rate freezes; the
46
<PAGE>
unbundling of generation operations, transmission and distribution and customer
service operations; securitization of regulatory assets; and consumer
protections. Although the Company and certain other parties (including the Texas
Utility Commission) supported the bill, it was not enacted prior to the
expiration of the legislative session.
In October 1997, the Company announced a proposed transition to competition
plan intended to address certain aspects of the proposals contained in the
legislation formerly pending before the Texas legislature. By mid December 1997,
negotiations resulted in a settlement agreement (Settlement Agreement) executed
by the Company, the staffs of the Texas Utility Commission and the City of
Houston, representatives of the state's principal consumer and industrial groups
and others. The Settlement Agreement was subsequently filed with the Texas
Utility Commission, where it is currently under consideration.
Under the terms of the Settlement Agreement, residential customers will
receive a 4% credit to the base cost of electricity in 1998, increasing to 6% in
1999. Small and mid-sized businesses will receive a 2% credit to their base
costs beginning in 1998. The combined effect of these reductions is expected to
decrease base revenues by $166 million over a two year period. In addition, the
Company (over the next two years) will be permitted, as a way to assist the
Company in mitigating its potentially stranded costs, to (i) redirect to
production property all of its current depreciation expenses that would
otherwise be credited to accumulated depreciation for transmission and
distribution property, and (ii) apply any and all earnings above a rate of
return cap of 9.95% to increase the depreciation of production property. The
Company estimates that redirected depreciation over the two-year period of 1998
and 1999 will be approximately $364 million. As part of the Settlement
Agreement, the Company agreed to support proposed legislation in the 1999 Texas
legislative session that includes provisions providing for retail customer
choice effective December 31, 2001 and other provisions consistent with those in
the 1997 proposed legislation.
The Settlement Agreement is currently under consideration by the Texas Utility
Commission, the City of Houston and other cities served by HL&P. In December
1997, the Texas Utility Commission approved the petition filed by the Company to
implement the requested base rate credits on a temporary basis beginning January
1, 1998, and pending final Texas Utility Commission consideration. The approval
also included the accounting order necessary to permit the Company to begin
redirecting depreciation from its transmission and distribution facilities to
production property on a temporary basis pending final Texas Utility Commission
consideration. A procedural schedule has been developed by the Texas Utility
Commission whereby a final decision regarding the Settlement Agreement would be
reached by the end of March 1998.
(c) 1995 Rate Case.
In August 1995, the Texas Utility Commission unanimously approved a settlement
resolving the Company's most recent rate case (Docket No. 12065) as well as a
separate proceeding (Docket No. 13126) regarding the prudence of operation of
the South Texas Project.
See Note 1(f) regarding additional depreciation and amortization that is
permitted under the 1995 Rate Case Settlement with respect to the South Texas
Project and the Company's investment in certain lignite reserves associated with
a canceled generating station.
(d) Docket No. 6668.
In September 1997, the Company received a judgment dismissing all outstanding
appeals of the Texas Utility Commission's order in Docket No. 6668, an inquiry
into the prudence of the planning and construction of the South Texas Project.
In that order, the Texas Utility Commission had determined that $375.5 million
of the Company's $2.8 billion investment in the South Texas Project had been
imprudently incurred. That ruling was incorporated into Electric Operations'
1988 and 1991 rate cases. As a result of this judgment, all
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outstanding appeals of prior rate cases involving the Company have now been
dismissed and the orders granted in such cases are now final.
(4) JOINTLY OWNED ELECTRIC UTILITY PLANT
(a) Investment in South Texas Project.
The Company has a 30.8% interest in the South Texas Project, which consists of
two 1,250 MW nuclear generating units, and bears a corresponding 30.8% share of
capital and operating costs associated with the project. As of December 31,
1997, the Company's investment in the South Texas Project was $1.8 billion (net
of $714 million accumulated depreciation). The Company's investment in nuclear
fuel (including AFUDC) was $51 million (net of $205 million amortization) as of
such date.
Effective November 1997, the Company and the other three owners of the South
Texas Project completed the transfer of the Company's responsibilities for
operation of the South Texas Project to a new Texas non-profit corporation
formed by the four owners and known as the STP Nuclear Operating Company
(STPNOC). STPNOC was formed exclusively for the purpose of operating the South
Texas Project, and the Company's officers and employees who had been responsible
for day-to-day operation and management of the South Texas Project were
transferred to the operating company in October, 1997 and the related employee
benefit obligations were transferred in December, 1997. The operating company is
managed by a board of directors composed of one director from each of the four
owners, along with the chief executive officer of STPNOC. Formation of STPNOC
did not affect the underlying ownership of the South Texas Project, which
continues as a tenancy in common among the four owners, with each owner
retaining its undivided ownership interest in the two nuclear-fueled generating
units and the electrical output from those units. The four owners continue to
provide overall oversight of the operations of the South Texas Project through
an owners' committee composed of representatives of each of the owners and
through the board of directors of STPNOC.
(b) 1996 Settlement of South Texas Project Litigation.
In 1996, the Company recorded an aggregate $95 million ($62 million net of
tax) charge in connection with various settlements of lawsuits filed by co-
owners of the South Texas Project. The formation of STPNOC by the four co-owners
(including the Company) of the South Texas Project was contemplated by these
settlements. For information about the execution of an operations agreement with
the City of San Antonio in connection with one of these settlements, see Note
12(c).
(c) Nuclear Insurance.
The Company and the other owners of the South Texas Project maintain nuclear
property and nuclear liability insurance coverage as required by law and
periodically review available limits and coverage for additional protection. The
owners of the South Texas Project currently maintain $2.75 billion in property
damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.
This coverage consists of $500 million in primary property damage insurance and
excess property insurance in the amount of $2.25 billion. With respect to excess
property insurance, the Company and the other owners of the South Texas Project
are subject to assessments, the maximum aggregate assessment under current
policies being $11.5 million during any one policy year. The application of the
proceeds of such property insurance is subject to the priorities established by
the Nuclear Regulatory Commission (NRC) regulations relating to the safety of
licensed reactors and decontamination operations.
Pursuant to the Price Anderson Act (Act), the maximum liability to the public
of owners of nuclear power plants, such as the South Texas Project, was $8.72
billion as of December 1997. Owners are required under the Act to insure their
liability for nuclear incidents and protective evacuations by maintaining the
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maximum amount of financial protection available from private sources and by
maintaining secondary financial protection through an industry retrospective
rating plan. The assessment of deferred premiums provided by the plan for each
nuclear incident is up to $79.3 million per reactor, subject to indexing for
inflation, a possible 5% surcharge (but no more than $10 million per reactor per
incident in any one year) and a 3% state premium tax. The Company and the other
owners of the South Texas Project currently maintain the required nuclear
liability insurance and participate in the industry retrospective rating plan.
There can be no assurance that all potential losses or liabilities will be
insurable, or that the amount of insurance will be sufficient to cover them. Any
substantial losses not covered by insurance would have a material effect on the
Company's financial condition and results of operations.
(d) Nuclear Decommissioning.
The Company contributes $14.8 million per year to a trust established to fund
its share of the decommissioning costs for the South Texas Project. For a
discussion of securities held in the Company's nuclear decommissioning trust,
see Note 1(o). In May 1994, an outside consultant estimated the Company's
portion of decommissioning costs to be approximately $318 million (1994
dollars). The consultant's calculation of decommissioning costs for financial
planning purposes used the DECON methodology (prompt removal/dismantling), one
of the three alternatives acceptable to the NRC, and assumed deactivation of
Units Nos. 1 and 2 upon the expiration of their 40-year operating licenses.
While the current and projected funding levels currently exceed minimum NRC
requirements, no assurance can be given that the amounts held in trust will be
adequate to cover the actual decommissioning costs of the South Texas Project.
Such costs may vary because of changes in the assumed date of decommissioning,
changes in regulatory and accounting requirements, changes in technology and
changes in costs of labor, materials and equipment.
(e) Assessment Fees for Spent Fuel Disposal and Enrichment and Decommission
By contract, the United States Department of Energy (DOE) has committed itself
ultimately to take possession of all spent fuel generated by the South Texas
Project. The DOE contract currently requires payment of a spent fuel disposal
fee on nuclear plant-generated electricity of one mill (one-tenth of a cent) per
net KWH sold. This fee is subject to adjustment to ensure full cost recovery by
the DOE. The Energy Policy Act also includes a provision that assesses a fee
upon domestic utilities that purchased nuclear fuel enrichment services from the
DOE before October 24, 1992. The South Texas Project's assessment is
approximately $2 million per year (subject to escalation for inflation). The
Company has a remaining estimated liability of $5.5 million for such
assessments.
(5) EQUITY INVESTMENTS IN FOREIGN AFFILIATES
HI Energy, a wholly owned subsidiary of the Company formed in 1993,
participates primarily in the development and acquisition of foreign independent
power projects and the privatization of foreign generating and distribution
companies.
The Company accounts for affiliate investments of its subsidiaries under the
equity method of accounting where: (i) the subsidiary's ownership interest in
the affiliate ranges from 20% to 50%, (ii) the ownership interest is less than
20% but the subsidiary exercises significant influence over operating and
financial policies of such affiliate or (iii) the subsidiary's ownership
interest in the affiliate exceeds 50% but the subsidiary does not exercise
control over the affiliate. The Company's proportionate share of the equity in
net income in these affiliates for the years ended December 31, 1997, 1996 and
1995 was $48.6 million, $17 million and $.5 million, respectively, which amounts
are included on the Company's Statements of Consolidated Income in Revenues --
International.
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The Company's and its subsidiaries' equity investments in foreign and non-
regulated affiliates at December 31, 1997 and 1996 were $704 million and $502
million, respectively.
(a) Acquisitions.
In May 1996, a subsidiary of HI Energy acquired 11.35% of the common stock of
Light, a publicly held Brazilian corporation, for $393 million which includes
the direct costs of the acquisition. Light is the operator under a 30-year
concession agreement of an integrated electric power and distribution system
that serves a portion of the state of Rio de Janeiro, Brazil, including the city
of Rio de Janeiro. The winning bidders in the government-sponsored auction of
Light, including a subsidiary of HI Energy, formed a consortium whose aggregate
ownership interest of 50.44% represents a controlling interest in Light.
In June 1997, a consortium of investors which included a subsidiary of HI
Energy, acquired for $496 million a 56.7% controlling ownership interest in
Empresa de Energia del Pacifico S.A.E.S.P. (EPSA), an electric utility system
serving the Valle de Cauca region of Colombia, including the area surrounding
the city of Cali. HI Energy contributed $152 million of the purchase price for a
28% ownership interest in EPSA. In addition to its distribution facilities, EPSA
owns 850 MW of electric generation capacity.
In May 1997, HI Energy increased its indirect ownership interest in Empresa de
la Plata S.A. (EDELAP), an Argentina electric utility, from 48% to 63%. The
purchase price of the additional interest was $28 million. HI Energy has
recorded its investment in EDELAP using the equity method because of the
significance of the participatory rights held by a minority shareholder.
HI Energy has accounted for these transactions under purchase accounting and
has recorded its investments and its interest in the affiliates' earnings after
the acquisition dates using the equity method. The purchase prices were
allocated on the basis of the estimated fair market values of the assets
acquired and the liabilities assumed as of the dates of acquisition. The
differences between the amounts paid and the underlying fair values of the net
assets acquired are being amortized as a component of earnings attributable to
unconsolidated affiliates over the estimated lives of the projects ranging from
30 to 40 years. Purchase price adjustments to fixed assets are being amortized
over the underlying assets' estimated useful lives.
(b) Valuation Allowance.
HI Energy is an investor in two waste tire-to-energy projects in the State of
Illinois. The projects had been developed by HI Energy in reliance upon a state
subsidy intended to encourage development of energy project facilities for the
disposal of solid waste. In March 1996, the State of Illinois repealed the
subsidy. As a result of the loss of the subsidy, the Company recorded (i) a $28
million valuation allowance effective in the fourth quarter of 1995 (resulting
in an $18 million after-tax charge in that year) and (ii) an additional $8
million valuation allowance in the first quarter of 1996 (resulting in a $5
million after-tax charge in that year). At the time of the Illinois
legislature's actions, construction work on one of the waste-to-energy projects
had been substantially completed.
The valuation allowance reflects the combined amounts lent to the projects on
a subordinated basis by HI Energy. HI Energy also is a party to two separate
note purchase agreements committing it, under certain circumstances, to lend up
to an additional $16 million. The Company has entered into a support agreement
to enable HI Energy to honor its obligation under these note purchase
agreements. In the Company's opinion, it is unlikely that additional loans would
be required to be made under the note purchase agreements relating to the
facility for which construction had been substantially completed (Ford Heights
Project). In March 1996, a subsidiary of HI Energy purchased from a senior
lending bank all notes relating to the project for which construction had not
yet commenced (Fulton Project) (approximately $4.1 million). As a consequence,
HI Energy has discretion over when, if ever, the construction activities for the
Fulton project will resume and,
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in turn, control over future obligations of HI Energy to acquire additional
subordinated notes for the Fulton project.
The Company and HI Energy are defendants in various lawsuits filed in
connection with the Ford Heights Project. CGE Ford Heights, L.L.C., (CGE Ford
Heights) the owner of the project, has filed for reorganization under Chapter 11
of the Federal Bankruptcy Code. In October 1997, CGE Ford Heights filed a
lawsuit against First Trust National Association, HI Energy and Zurn Industries,
Inc. (Zurn). CGE Ford Heights is seeking a determination of the funding
obligations of HI Energy and Zurn. In addition, the trustee for the holders of
the bonds issued to finance the project has filed suit against the Company, HI
Energy and Zurn. The trustee alleges that the Company and HI Energy are
obligated to contribute to CGE Ford Heights approximately $15 million in the
form of subordinated debt obligations. The Company and HI Energy are vigorously
contesting the matter. The Company does not believe that the litigation will
have a material adverse impact on the Company's or HI Energy's financial
statements.
(6) COMMON STOCK
At December 31, 1997, the Company had 282,875,266 shares of common stock
issued and outstanding (out of a total of 700,000,000 authorized shares). At
December 31, 1996, the number of shares of outstanding common stock of Former HI
was 233,335,481.
Outstanding common shares excluded (i) shares pledged to secure a loan to the
Company's Employee Stock Ownership Plan (12,388,551 and 13,370,939 at December
31, 1997 and 1996, respectively) and (ii) treasury shares (93,459 and 16,042,027
at December 31, 1997 and 1996, respectively). Treasury shares at December 31,
1996 represent shares purchased under a common stock repurchase program prior to
the Merger. In connection with the Merger, these treasury shares were canceled
and retired in August 1997. At December 31, 1997, the Company held 93,459
shares, which shares were received from holders of Company stock options, who
surrendered shares of Company stock as partial payment for the exercise price of
their stock options.
In 1997, the Company paid four regular quarterly dividends aggregating $1.50
per share on its common stock pursuant to dividend declarations made in December
1996, March 1997, June 1997 and September 1997. In December 1997, the Company
declared its regular quarterly dividend of $0.375 per share to be paid in March
1998. For information regarding certain restrictions on payments of dividends,
see Note 8(c).
(7) PREFERRED AND PREFERENCE STOCK
(a) Preferred Stock.
At December 31, 1997, the Company had 10,000,000 authorized shares of
preferred stock, of which 97,397 shares were outstanding. As of such date, the
Company's only outstanding series of preferred stock was its $4.00 Preferred
Stock. The $4.00 Preferred Stock pays an annual dividend of $4.00 per share, is
redeemable at $105 per share and has a liquidation price of $100 per share.
In April 1997, the Company redeemed all remaining 257,000 shares of its $9.375
cumulative preferred stock pursuant to mandatory sinking fund requirements at a
cost of $25.7 million, plus accrued dividends. In February 1997, the Company
redeemed the following three series of its cumulative preferred stock at the
redemption prices, plus accrued dividends, indicated:
SERIES NUMBER REDEMPTION
------ OF PRICE
SHARES PER SHARE
------- ----------
$6.72 250,000 $102.51
$7.52 500,000 $102.35
$8.12 500,000 $102.25
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(b) Preference Stock.
At December 31, 1997, the Company had 10,000,000 authorized shares of
preference stock, of which 700,000 shares are classified as Series A Preference
Stock and 27,000 shares are classified as Series B Preference Stock. As of
December 31, 1997, there were no shares of Series A Preference Stock issued and
outstanding (such shares being issuable in accordance with the Company's
Shareholder Rights Agreement upon the occurrence of certain events). The number
of shares of Series B Preference Stock issued and outstanding as of December 31,
1997 was 17,000. The sole holder of the Series B Preference Stock is a wholly
owned financing subsidiary of the Company. See Note 8(c).
Each share of common stock of the Company includes one associated preference
stock purchase right (Company Right). Under certain circumstances, each Company
Right entitles the registered holder to purchase from the Company a unit
consisting of one-thousandth of a share (Fractional Share) of Series A
Preference Stock, without par value (Series A Preference Stock), at a purchase
price of $42.50 per Fractional Share, subject to adjustments. The shareholder
rights plan was adopted by the shareholders of Former HI in August 1990 and was
assumed by the Company, with certain amendments, effective upon the Merger.
(8) LONG-TERM DEBT AND SHORT-TERM FINANCING
(a) Consolidated Debt.
The Company's consolidated long-term and short-term debt outstanding is
summarized in the following table. Of the amount of long-term and short-term
debt outstanding as of December 31, 1997, $1.8 billion represents debt of NorAm
which was assumed and adjusted to fair market value as of the Acquisition Date.
CONSOLIDATED LONG-TERM DEBT AND SHORT-TERM BORROWINGS
(IN MILLIONS)
<TABLE>
<CAPTION>
DECEMBER 31, 1997 DECEMBER 31, 1996
--------------------------- -----------------
LONG-TERM CURRENT LONG-TERM CURRENT
--------- ------- --------- -------
<S> <C> <C> <C> <C>
Short-Term Borrowings:
Commercial Paper $1,435 $1,338
Lines of Credit 390
NorAm Receivables Facility 300
------ ------
Total Short-Term Borrowings 2,125 1,338
Long-Term Debt -net: ------ ------
ACES $1,174
Debentures(1)(2) 669 $ 349
First Mortgage Bonds(1) 2,495 2,670 225
Pollution Control Bonds 118 5 5
NorAm Medium-Term Notes(2) 182 79
Notes Payable(2) 565 166 1
Capital Leases 15 1 1 4
------ ------ ------ ------
Total Long-Term Debt 5,218 251 3,026 229
------ ------ ------ ------
Total Long-Term and Short-Term Debt $5,218 $2,376 $3,026 $1,567
====== ====== ====== ======
</TABLE>
__________
(1) Includes unamortized discount related to debentures of approximately $1
million at December 31, 1997 and 1996 and unamortized discount related to
first mortgage bonds of approximately $14 million and $15 million at
December 31, 1997 and 1996, respectively.
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(2) Includes unamortized premium related to fair value adjustments of
approximately $15.8 million for Debentures at December 31, 1997. The
unamortized premium for NorAm long-term and current medium-term notes at
December 31, 1997 was approximately $16.7 million and $2.8 million,
respectively. The unamortized premium for long-term and current notes
payable was approximately $13.7 million and $3.3 million, respectively, at
December 31, 1997. See Note 1(b).
Consolidated maturities of long-term debt and sinking fund requirements for
the Company (including NorAm) are approximately $251 million in 1998, $378
million in 1999, $1.430 billion in 2000, $401 million in 2001 and $207 million
in 2002.
(b) First Mortgage Bonds.
As of December 31, 1997, the Company had an aggregate of $2.5 billion
principal amount of its first mortgage bonds issued and outstanding.
In the first quarter of 1997, the Company repaid at maturity $40 million
aggregate principal amount of its 5 1/4% first mortgage bonds and $150 million
aggregate principal amount of its 7 5/8% first mortgage bonds. In June 1997, the
Company purchased $57.6 million aggregate principal amount of its 9.15% first
mortgage bonds due 2021 for a total purchase price of $69.6 million, plus
accrued interest. In November 1997, the Company repaid at maturity $35 million
aggregate principal amount of its 6 3/4% first mortgage bonds.
Sinking or improvement fund requirements of the Company's first mortgage bonds
outstanding will be approximately $28.3 million for each of the years 1998
through 2002. Such requirements may be satisfied by certification of property
additions at 100% of the requirements. Sinking or improvement fund requirements
for 1997 and prior years have been satisfied by certification of property
additions.
The Company has agreed to expend an amount each year for replacements and
improvements in respect of its depreciable mortgaged utility property equal to
$1,450,000 plus 2 1/2% of net additions to such mortgaged property made after
March 31, 1948 and before July 1 of the preceding year. Such requirement may be
met with cash, first mortgage bonds, gross property additions or expenditures
for repairs or replacements, or by taking credit for property additions at 100%
of the requirements. With respect to first mortgage bonds of a series subject to
special redemption, the Company has the option to use deposited cash to redeem
first mortgage bonds of such series at the applicable special redemption price.
The replacement fund requirement to be satisfied in 1998 is approximately $310.3
million.
The amount of the first mortgage bonds that may be issued by the Company is
unlimited as to issuance, but limited by property, earnings and other provisions
of the Mortgage and Deed of Trust dated as of November 1, 1944, between the
Company and South Texas Commercial National Bank of Houston (Chase Bank of
Texas, National Association, as Successor Trustee) and the supplemental
indentures thereto. Substantially all properties used in the conduct of the
business and operations of Electric Operations are subject to liens securing the
long-term debt under the mortgage.
(c) FinanceCo Credit Facility.
In August 1997, a limited partnership special purpose subsidiary of the
Company (FinanceCo) established a five-year, $1.644 billion revolving credit
facility with a consortium of commercial banks (FinanceCo Facility). The
FinanceCo Facility supported $1.435 billion in commercial paper borrowings by
FinanceCo at December 31, 1997 recorded as notes payable on the Consolidated
Balance Sheet. The weighted average interest rate of these borrowings at
December 31, 1997 was 6.15%. Proceeds from the initial issuances of commercial
paper were used to purchase newly issued shares of Series B Preference Stock of
the Company. The Company, in turn, used the proceeds from such stock issuance to
fund the cash portion of the consideration paid to Former NorAm stockholders
under the terms of the Merger.
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Borrowings under the FinanceCo Facility bear interest at a rate based upon the
London interbank offered rate (LIBOR) plus a margin, a base rate or at a rate
determined through a bidding process. The FinanceCo Facility may be used (i) to
support the issuance of commercial paper or other short-term indebtedness of
FinanceCo, (ii) subject to certain limitations, to finance repurchases of
Company common stock and (iii) subject to certain limitations, to provide funds
for general purposes of FinanceCo, including the making of intercompany loans
to, or securing letters of credit for the benefit of, FinanceCo's affiliates.
The FinanceCo Facility requires the Company to maintain a ratio of consolidated
indebtedness for borrowed money to consolidated capitalization (as defined) that
does not exceed 0.62:1.00 from January 1, 1998 through December 31, 1998 and
0.60:1.00 from January 1, 1999 until termination of the FinanceCo Facility. The
FinanceCo Facility also contains restrictions applicable to the Company and
certain of its subsidiaries with respect to, among other things, (i) liens, (ii)
consolidations, mergers and dispositions of assets, (iii) dividends and
repurchases of common stock, (iv) certain types of investments and (v) certain
changes in its business. The FinanceCo Facility contains customary covenants and
default provisions applicable to FinanceCo and its subsidiaries, including
limitations on, among other things, additional indebtedness (other than certain
permitted indebtedness), liens and certain investments or loans.
Subject to certain conditions and limitations, the Company is required to make
cash payments from time to time to FinanceCo from excess cash flow (as defined
in the FinanceCo Facility) to the extent necessary to enable FinanceCo to meet
its financial obligations. At December 31, 1997, commercial paper supported by
the FinanceCo Facility was secured by pledges of (i) the shares of common stock
of NorAm held by the Company, (ii) all of the limited and general partner
interests of FinanceCo and all of the Company's interest in the general partner
of FinanceCo, (iii) the capital stock of HI Energy, (iv) the Series B Preference
Stock and (v) certain intercompany notes held by FinanceCo. The obligations
under the FinanceCo Facility are not secured by the utility assets of the
Company or NorAm or by the Company's investment in Time Warner securities.
The Company's outstanding commercial paper balance at December 31, 1996 was
$1.3 billion. The weighted average interest rate at December 31, 1996 was 5.90%.
(d) Company Bank Facility.
The Company meets its short-term financing needs primarily through sales of
commercial paper supported by a $200 million revolving credit facility.
Borrowings under the facility are unsecured and a facility fee is paid. At
December 31, 1997, there was no outstanding commercial paper and there were no
outstanding borrowings under the bank facility.
(e) ACES.
The Company owns 11 million shares of non-publicly traded TW Preferred. See
Note 1(n). To monetize its investment in these securities, the Company sold in
July 1997, 22,909,040 of its unsecured 7% ACES having a face amount of $45.9375
per security.
At maturity, the principal amount of the ACES will be mandatorily exchangeable
by the Company into either (i) a number of shares of common stock of Time Warner
based on an exchange rate or (ii) cash having an equal value. Subject to
adjustments that may result from certain dilution events, the exchange rate for
each ACES is determined as follows: (i) 0.8264 shares of Time Warner common
stock if the price of Time Warner common stock at maturity (Maturity Price) is
at least $55.5844 per share, (ii) a fractional share of Time Warner common stock
such that the fractional share will have a value equal to $45.9375 if the
Maturity Price is less than $55.5844 but greater than $45.9375 and (iii) one
share of Time Warner common stock if the Maturity Price is not more than
$45.9375.
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Prior to maturity, the Company has the option of redeeming the ACES if (i)
changes in federal tax regulations require recognition of a taxable gain on the
Company's TW Preferred and (ii) the Company could defer such gain by redeeming
the ACES. The redemption price is 105% of the closing sales price of the ACES as
determined over a period prior to the redemption notice. The redemption price
may be paid in cash or in shares of Time Warner common stock or a combination of
the two.
The Company used the net proceeds of the sale of the ACES (approximately
$1.021 billion) to retire in 1997 an equivalent amount of the Company's then
outstanding commercial paper.
For information regarding the Company's accounting treatment of the ACES,
including certain accounting losses that may result upon increases in the price
of Time Warner common stock, see Note 1(n).
(f) Pollution Control Revenue Refunding Bonds.
In January 1997, the Brazos River Authority (BRA) and the Matagorda County
Navigation District Number One (MCND) issued, on behalf of the Company, $118
million aggregate principal amount of pollution control revenue bonds. The BRA
and MCND bonds will mature in 2018 and 2028, respectively. The proceeds from the
sale of these securities were used to redeem all outstanding 7 7/8% BRA Series
1986A pollution control revenue bonds ($50 million) and 7 7/8% MCND Series 1986A
pollution control revenue bonds ($68 million) at a redemption price of 102% of
the aggregate principal amount of each series. In 1997, the bonds bore interest
at a floating rate. The weighted average interest rate at December 31, 1997 was
5.01%. Subject to certain conditions, the Company may change the method of
determining the interest rate on the bonds from a daily to a weekly, commercial
paper or long-term interest rate. The bonds are subject to a mandatory tender
for purchase upon certain events, including changes in the method of determining
interest rates on the bonds. When a daily or weekly rate is in effect for the
bonds, holders of the bonds of such issue have the option to have their bonds
purchased at 100% of their principal amount plus accrued interest to the date of
the purchase. Bonds tendered prior to maturity may be remarketed. Although it is
anticipated that all bonds tendered will be purchased with proceeds from the
subsequent offer and sale of the tendered bonds, the Company has entered into
standby purchase agreements with commercial banks to provide approximately $120
million for the purchase of tendered bonds in the event such proceeds are not
available. Facility fees are payable in connection with these facilities.
(g) NorAm Bank Facilities.
In 1997, NorAm met its short-term financing needs primarily through a bank
facility, bank lines of credit and a receivables facility. NorAm's principal
short-term credit facility (NorAm Credit Facility) of $400 million expires in
December 1998. Unsecured borrowings under the NorAm Credit Facility at December
31, 1997 aggregated $340 million and had a weighted average interest rate of
6.30%. A facility fee of .14% per annum is payable on the $400 million
commitment. In addition, NorAm had $50 million of outstanding loans under
uncommitted lines of credit at December 31, 1997 having a weighted average
interest rate of 6.82%.
Under a trade receivables facility (Receivables Facility) which expires in
August 1999, NorAm sells, with limited recourse, an undivided interest (limited
to a maximum of $300 million) in a designated pool of accounts receivable. The
amount of receivables sold and uncollected was $300 million at December 31,
1997. The weighted average interest rate at December 31, 1997 was approximately
5.65%. Certain of NorAm's remaining receivables serve as collateral for
receivables sold and represent the maximum exposure to NorAm should all
receivables sold prove ultimately uncollectible. NorAm has retained servicing
responsibility under the Receivables Facility for which it is paid a servicing
fee. Beginning in 1997 and pursuant to SFAS No. 125, "Accounting for Transfers
and Servicing of Financial Assets and Extinguishment of Liabilities", NorAm
accounts for amounts transferred pursuant to the Receivables Facility as
collateralized borrowings. As a result, these receivables are recorded as assets
on the Company's December 31, 1997 Consolidated Balance Sheet and amounts
received by NorAm pursuant to this facility are recorded as notes payable.
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In May 1997, NorAm obtained an unsecured, 18-month bank term loan in the
amount of $150 million (included in Notes Payable). The term loan carries a
LIBOR-based floating interest rate. Proceeds from the term loan were used to
refund a portion of NorAm's 9.875% Notes which matured in April 1997. NorAm has
entered into two interest rate swaps, each with a term of 19 months, having an
aggregate notional amount of $150 million which, as of December 31, 1997,
effectively fixed the interest rate on borrowings under the term loan agreement
at approximately 6.775%.
(h) NorAm Long-Term Debt.
At December 31, 1997, NorAm has issued and outstanding $116 million aggregate
principal amount ($107 million after Merger fair value adjustments) of its 6%
Convertible Subordinated Debentures due 2012 (Subordinated Debentures). The
holders of the Subordinated Debentures receive interest quarterly and have the
right at any time on or before the maturity date thereof to convert each
Subordinated Debenture into 0.65 shares of Company common stock and $14.24 in
cash. NorAm 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 up to and including March 15, 2011. NorAm (i) may credit against the
sinking fund requirements any Subordinated Debentures redeemed by NorAm and
Subordinated Debentures which have been converted at the option of the holder
and (ii) may deliver purchased Subordinated Debentures in satisfaction of the
sinking fund requirements. Since the Acquisition Date, Subordinated Debentures
aggregating $27,250 were converted.
In the fourth quarter of 1997, NorAm purchased $101.4 million aggregate
principal amount of its 10% Debentures due 2019 at an average price of 111.98%
plus accrued interest. Because NorAm's debt was stated at fair market value as
of the date of the acquisition, the loss on the reacquisition of these
debentures was not material. In December 1997, NorAm repaid at maturity $52
million aggregate principal amount of its medium-term notes.
(i) Restrictions on NorAm's Stockholders' Equity and Debt.
Under the provisions of NorAm's revolving credit facility or certain other
NorAm financial arrangements, NorAm's total debt is limited to 72% of its total
capitalization and NorAm is required to maintain a minimum level of
stockholders' equity. In addition, NorAm's total debt would be limited to $2.055
billion if its ratio of total debt to total capitalization increased to 60%. The
minimum level of stockholders' equity was initially set at $700 million at
December 31, 1995, increasing annually thereafter by (1) 50% of positive
consolidated net income and (2) 50% of the proceeds from any incremental equity
offering made after June 30, 1996. At December 31, 1997, these provisions did
not significantly restrict NorAm's ability to issue debt or to pay dividends.
(j) HI Energy Notes Payable.
In 1996, a subsidiary of HI Energy entered into a $167.5 million loan
agreement in order to refinance a portion of the acquisition costs of Light. The
full proceeds of the loan, net of a $17.5 million debt reserve account
established for the benefit of the lenders, was funded in April 1997. The loan
(included in Notes Payable) is secured by, among other things, a pledge of the
shares of Light and of a subsidiary of HI Energy that is the indirect holder of
the shares of Light.
(9) TRUST SECURITIES
(a) Company.
In February 1997, two Delaware statutory business trusts (HI Trusts)
established by the Company issued (i) $250 million of preferred securities and
(ii) $100 million of capital securities, respectively. The preferred
56
<PAGE>
securities have a distribution rate of 8.125% payable quarterly in arrears, a
stated liquidation amount of $25 per preferred security and must be redeemed by
March 2046. The capital securities have a distribution rate of 8.257% payable
quarterly in arrears, a stated liquidation amount of $1,000 per capital security
and must be redeemed by February 2037.
The HI Trusts sold the preferred and capital securities to the public and used
the proceeds to purchase $350 million aggregate principal amount of subordinated
debentures (Debentures) from the Company having interest rates corresponding to
the distribution rates of the securities and maturity dates corresponding to the
mandatory redemption dates of the securities. The HI Trusts are accounted for as
wholly owned consolidated subsidiaries of the Company. The Debentures are the HI
Trusts' sole assets. Proceeds from the sale of the Debentures were used by the
Company for general corporate purposes, including the repayment of short-term
debt and the redemption of three series of the Company's outstanding cumulative
preferred stock at the following redemption prices, plus accrued dividends:
SERIES NUMBER REDEMPTION
------ OF PRICE
SHARES PER SHARE
------ ----------
$6.72 250,000 $102.51
$7.52 500,000 $102.35
$8.12 500,000 $102.25
The Company has fully and unconditionally guaranteed, on a subordinated basis,
each Trust's obligations, including the payment of distributions and all other
payments due with respect to the respective preferred and capital securities.
The preferred and capital securities are mandatorily redeemable upon the
repayment of the related Debentures at their stated maturity or earlier
redemption.
Subject to certain limitations, the Company has the option of deferring
payments of interest on the Debentures held by the HI Trusts. If and for as long
as payments on the Debentures have been deferred, or an event of default under
the indenture relating thereto has occurred and is continuing, the Company may
not pay dividends on its capital stock. As of December 31, 1997, no interest
payments on the Debentures had been deferred.
(b) NorAm.
In June 1996, a Delaware statutory business trust (NorAm Trust) established by
NorAm issued $172.5 million of convertible preferred securities and sold
approximately $5.3 million of NorAm Trust common securities (106,720 securities,
representing 100% of the NorAm Trust's common equity) to NorAm . The convertible
preferred securities have a distribution rate of 6.25% payable quarterly in
arrears, a stated liquidation amount of $50 per convertible preferred security
and must be redeemed by 2026. The NorAm Trust sold the convertible preferred
securities to the public and used the proceeds, in addition to the common stock
proceeds, to purchase $177.8 million of 6.25% Convertible Junior Subordinated
Debentures from NorAm having an interest rate corresponding to the distribution
rate of the convertible preferred securities and a maturity date corresponding
to the mandatory redemption date of the convertible preferred securities. The
NorAm Trust is accounted for as a wholly owned consolidated subsidiary of NorAm.
The junior subordinated debentures are the sole assets of the NorAm Trust. NorAm
has fully and unconditionally guaranteed, on a subordinated basis, the NorAm
Trust's obligations, including the payment of distributions and all other
payments, with respect to the convertible preferred securities. The convertible
preferred securities are mandatorily redeemable upon the repayment of the
related junior subordinated debentures at their stated maturity or earlier
redemption. Following the Merger, each convertible preferred security is
convertible at the option of the holder into $33.62 of cash and 1.55 shares of
Company common stock. Since the Acquisition Date, convertible preferred
securities aggregating $14.1 million were converted, leaving $16.4 million
principal
57
<PAGE>
amount (unamortized fair value of $21.3 million, net of issuance costs) of
convertible preferred securities outstanding at December 31, 1997.
(10) STOCK-BASED INCENTIVE COMPENSATION PLANS AND RETIREMENT PLANS
(a) Incentive Compensation Plans.
The Company has Long-Term Incentive Compensation plans (LICP) and other
incentive compensation plans that provide for the issuance of stock-based
incentives (including performance-based stock compensation and restricted
shares, stock options and stock appreciation rights) to key employees of the
Company, including officers. As of December 31, 1997, 96 current and former
employees participated in the plans. A maximum of approximately 9 million shares
of common stock may be issued under these plans. Under the LICP, beginning one
year after the grant date, the options become exercisable in one-third
increments each year. Performance-based stock compensation issued and restricted
shares granted were 704,865 in 1997, 69,905 in 1996, and 49,792 in 1995.
Stock option activity for the years 1995 through 1997 is summarized below:
NUMBER
OF SHARES WEIGHTED AVERAGE
--------- PRICE AT DATE OF
GRANT OR EXERCISE
-----------------
Outstanding at December 31, 1994 302,578 $ 22.7025
Options Granted 133,324 $ 17.8277
Options Canceled (24,560)
Outstanding at December 31, 1995 411,342 $ 21.1414
Options Granted 101,798 $ 24.375
Options Exercised (574) $ 17.75
Options Withheld for Taxes (90)
Options Canceled (13,824)
Outstanding at December 31, 1996 498,652 $ 21.7796
Options Granted 382,954 $ 21.0673
Options Converted at Acquisition(1) 622,504 $ 12.9002
Options Exercised(1) (281,053) $ 9.2063
Options Withheld for Taxes (72)
Options Canceled (148,418)
Outstanding at December 31, 1997 1,074,567 $ 19.0728
Exercisable at:
December 31, 1997 645,304 $ 7.00-35.18
December 31, 1996 280,270 $17.75-23.25
December 31, 1995 181,924 $21.75-23.25
__________
(1) Effective upon the Merger, each holder of an unexpired NorAm stock option,
whether or not then exercisable, was entitled to elect to either (i) have
all or any portion of their NorAm stock options canceled and "cashed out" or
(ii) have all or any portion of their NorAm stock options converted to the
Company's stock options. There were 622,504 NorAm stock options converted
into the Company's stock options at the Acquisition Date. Options exercised
during 1997 included approximately 277,000 shares related to NorAm stock
options which were converted at the Merger.
Effective January 1, 1996, the Company adopted SFAS No. 123, "Accounting for
Stock-Based Compensation." (SFAS No. 123) In accordance with SFAS No. 123, the
Company will continue to apply the
58
<PAGE>
existing rules contained in Accounting Principles Opinion No. 25, "Accounting
for Stock Issued to Employees," and disclose the required pro forma effect on
net income and earnings per share of the fair value based method of accounting
for stock compensation as required by SFAS No. 123.
The following pro forma summary of the Company's consolidated results of
operations have been prepared as if the fair value based method of accounting
for employee stock compensation as required by SFAS No. 123 had been applied:
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- ----------
<S> <C> <C> <C>
(THOUSANDS OF DOLLARS,
EXCEPT PER SHARE DATA)
Net Income as reported $420,948 $404,944 $1,105,524
SFAS No. 123 effect (2,374) (1,098) (244)
-------- -------- ----------
Pro forma Net Income $418,574 $403,846 $1,105,280
======== ======== ==========
Basic and Diluted Earnings per Common Share As
reported $ 1.66 $ 1.66 $ 4.46
$ 1.65 $ 1.66 $ 4.46
</TABLE>
The fair value of options granted during 1995, 1996 and 1997 were calculated
using the Black-Scholes model. The significant assumptions incorporated in the
Black-Scholes model in estimating the fair value of the options include (i) an
interest rate of 7.78% for 1995 and 5.65% for 1996 and an interest rate of 6.58%
for 1997 that represents the interest rate on a U.S. Treasury security with a
maturity date corresponding with the option term, (ii) an option term of ten
years, (iii) volatility of 19.647% for 1995, 15.713% for 1996 and a volatility
of 22.06% for 1997 calculated using daily stock prices for the period prior to
the grant date, and (iv) expected common dividends of $1.50 per share
representing annualized dividends at the date of grant.
(b) Pension.
The Company has a noncontributory retirement plan which covers the employees
of the Company and its subsidiaries other than NorAm. NorAm has two
noncontributory retirement plans: (i) the plan which covers the employees of
NorAm other than Minnegasco employees and (ii) the plan which covers Minnegasco
employees. The plans provide retirement benefits based on years of service and
compensation. The Company and NorAm's funding policy is to contribute amounts
annually in accordance with applicable regulations in order to achieve adequate
funding of projected benefit obligations. The assets of the plans consist
principally of common stocks and high-quality, interest-bearing obligations.
Net pension cost for the Company attributable to continuing operations
includes the following components:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
---------- -------- --------
(THOUSAND OF DOLLARS)
<S> <C> <C> <C>
Service cost -- benefits earned during the
period $ 26,848 $ 24,392 $ 22,852
Interest cost on projected benefit obligation 67,640 51,560 49,317
Actual (return) loss on plan assets (100,390) (75,326) (96,004)
Net amortization and deferrals 14,025 17,514 50,889
---------- -------- --------
Net pension cost 8,123 18,140 27,054
Transfer of obligation to STPNOC (6,077)
SFAS No. 88 -- curtailment expense 12,947 12,698 7,096
---------- -------- --------
Total pension cost $ 14,993 $ 30,838 $ 34,150
========== ======== ========
</TABLE>
59
<PAGE>
<TABLE>
<CAPTION>
The funded status of the Company's retirement plans was as follows:
DECEMBER 31,
---------------------
1997 1996
---------- --------
(THOUSANDS OF DOLLARS)
<S> <C> <C>
Actuarial present value of:
Vested benefit obligation $ 948,017 $542,714
========== ========
Accumulated benefit obligation $1,017,190 $578,786
========== ========
Plan assets at fair value(1) $1,304,023 $675,401
Projected benefit obligation(1) 1,246,582 756,597
---------- --------
Assets in excess of (less than) projected benefit
obligation 57,441 (81,196)
Unrecognized transitional asset (9,008) (11,502)
Unrecognized prior service cost 14,735 31,154
Unrecognized net loss 8,750 19,405
---------- --------
(Accrued) prepaid pension cost $ 71,918 $(42,139)
========== ========
- ----------
</TABLE>
(1) Includes transfer of approximately $40 million of assets and related
liabilities of plans related to STPNOC. See Note 4(a).
The projected benefit obligation was determined using an assumed discount rate
of 7.25% in 1997 and in 1996. A long-term annual rate of compensation increase
ranging from 4% to 6% was assumed for both the Company and NorAm plans in 1997
and 1996. The assumed long-term rate of return on plan assets was 9.5% in 1997
and 1996 (10% for the NorAm plans in 1997). The transitional asset at January 1,
1986, is being recognized over approximately 17 years, and the prior service
cost is being recognized over approximately 15 years for the Company's plan. The
unrecognized transitional asset, prior service cost and net (gain) or loss
related to the NorAm plans were recognized at the Acquisition Date.
In 1995, the Company offered eligible employees (excluding officers) of the
Company and HI Energy, who were 55 years of age or older and had at least 10
years of service as of July 31, 1995, an incentive program to retire early. For
employees electing early retirement, the program added five years of service
credit and five years in age up to 35 years of service and age 65, respectively,
in determining an employee's pension. Each participating employee (under age 62)
would also receive a supplemental benefit to age 62. During July 1995, the early
retirement incentive was accepted by approximately 300 employees.
Pension benefits and supplemental benefits (if applicable) are being paid out
from the Houston Industries Incorporated Retirement Trust. Based on the
projected costs associated with the program, the Company increased its
retirement plan and supplemental benefits in 1995 by approximately $28 million
and $5 million, respectively. Pursuant to SFAS No. 71, the Company deferred the
costs associated with the increases in its benefit obligations and amortized the
costs through the period ending December 31, 1997. In 1997, 1996 and 1995, the
Company amortized $12.9 million, $12.7 million and $7.1 million, respectively,
of those costs as a curtailment under SFAS No. 88, "Employers' Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans and for
Termination Benefits," with regards to the Company's early retirement program.
(c) Savings Plan.
The Company has an employee savings plan that qualifies as cash or deferred
arrangements under Section 401(k) of the Internal Revenue Code of 1986, as
amended (IRC). Under the plan, participating employees may contribute a portion
of their compensation, pretax or after-tax, up to a maximum of 16% of
compensation limited by an annual deferral limit ($9,500 for calendar year 1997)
prescribed by IRC
60
<PAGE>
Section 402(g) and the IRC Section 415 annual additions
limits. The Company matches 70% of the first 6% of each employee's compensation
contributed, subject to a vesting schedule which entitles the employee to a
percentage of the matching contributions depending on years of service.
Substantially all of the Company's match is invested in the Company's common
stock.
In October 1990, the Company amended its savings plan to add a leveraged
Employee Stock Ownership Plan (ESOP) component. The Company may use ESOP shares
to satisfy its obligation to make matching contributions under the savings plan.
Debt service on the ESOP loan is paid using all dividends on shares in the ESOP,
interest earnings on funds held in the ESOP and cash contributions by the
Company. Shares of the Company's common stock are released from the encumbrance
of the ESOP loan based on the proportion of debt service paid during the period.
The Company adopted Statement of Position (SOP) 93-6, effective January 1,
1994, which requires that the Company recognize benefit expense for the ESOP
equal to the fair value of the ESOP shares committed to be released. In
accordance with SOP 93-6, the Company credits to unearned ESOP shares the
original purchase price of ESOP shares committed to be released to plan
participants with the difference between the fair value of the shares and the
original purchase price recorded to common stock. Dividends on allocated ESOP
shares are recorded as a reduction to retained earnings; dividends on
unallocated ESOP shares are recorded as a reduction of debt or accrued interest
on the ESOP loan.
The Company's savings plan benefit expense attributable to continuing
operations was $18.4 million, $16.0 million, and $18.9 million in 1997, 1996 and
1995, respectively. Savings plan benefit expense attributable to discontinued
operations was not material.
The ESOP shares were as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1997 1996
------------ ------------
<S> <C> <C>
Allocated shares transferred/distributed from the
Savings Plan(1) 1,920,406 580,132
Allocated shares 4,453,227 4,811,113
Unearned shares 12,388,551 13,370,939
------------ ------------
Total Original ESOP shares 18,762,184 18,762,184
============ ============
Fair value of unearned ESOP shares $331,393,739 $302,517,495
</TABLE>
__________
(1) 1,102,203 allocated shares transferred are related to shares transferred to
STPNOC in December, 1997.
NorAm has an employee savings plan (NorAm Savings Plan) which covers
substantially all employees other than Minnegasco employees. Under the terms of
the NorAm Savings Plan, employees may contribute up to 12% of total
compensation, which contributions up to 6% are matched by the Company. The
Minnegasco employees are covered by a savings plan, the terms of which are
somewhat similar to the NorAm Savings Plan. Employer contributions related to
the NorAm and Minnegasco Savings Plan of $3.7 million have been expensed since
the Acquisition Date.
(d) Postretirement Benefits.
The Company and NorAm record the liability for post-retirement benefit plans
other than pensions (primarily health care) under SFAS No. 106, "Employer's
Accounting for Postretirement Benefits Other Than Pensions" (SFAS No. 106). The
Company is amortizing over a 22 year period approximately $213 million to cover
the "transition cost" of adopting SFAS No. 106 (i.e., the Company's liability
for postretirement benefits payable with respect to employee service years
accrued prior to the adoption of SFAS
61
<PAGE>
No. 106). The unrecognized transitional asset and net (gain) loss related to the
NorAm plans were recognized at the Acquisition Date.
As provided in the Rate Case Settlement, the Company is required to fund
during each year in an irrevocable external trust approximately $22 million of
postretirement benefit costs which are included in Electric Operations' rates.
In December 1995, the Company commenced funding by contributing a total of $15.1
million to three Voluntary Employees' Beneficiary Association trusts and one
Section 401(h) account of the retirement plan. This contribution represented the
amount of postretirement benefits included in Electric Operations' rates (which
included the Company's interest in the South Texas Project costs) less the
estimated pay-as-you-go amounts for 1995 plus interest as if the contributions
had been made on a monthly basis during the year. Beginning in 1996, the Company
funded postretirement benefits costs on a monthly basis for the amount included
in Electric Operations' rates. Minnegasco is required to fund postretirement
benefit costs for the amount included in its rates. The Company and NorAm,
excluding Electric Operations and Minnegasco, will continue funding their
postretirement benefits on a pay-as-you-go basis. The net postretirement benefit
cost for the Company and its subsidiaries includes the following components:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
(THOUSANDS OF DOLLARS)
Service cost -- benefits earned during the period $ 8,927 $ 8,242 $ 9,093
Interest cost on accumulated benefit obligation 14,176 12,265 11,143
Actual return on plan assets (5,063) (2,342)
Net amortization and deferrals 4,732 5,983 6,061
------- ------- -------
Net postretirement benefit cost $22,772 $24,148 $26,297
======= ======= =======
</TABLE>
The funded status of the Company's and its subsidiaries' postretirement
benefit costs were as follows:
DECEMBER 31,
----------------------
1997 1996
--------- ---------
(THOUSANDS OF DOLLARS)
Accumulated benefit obligation:
Retirees $ 220,436 $ 107,642
Fully eligible active plan participants 22,150 16,340
Other active plan participants 26,945 26,090
--------- ---------
Total 269,531 150,072
Plan assets at fair market value 56,340 38,493
--------- ---------
Assets (less than) accumulated benefit obligation (213,191) (111,579)
Unrecognized transitional obligation 155,107 173,954
Unrecognized net gain (96,463) (99,417)
--------- ---------
(Accrued) postretirement benefit cost $(154,547) $ (37,042)
========= =========
The assumed health care cost trend rates used in measuring the accumulated
postretirement benefit obligation in 1997 are as follows:
Medical -- under 65.............. 6.6%
Medical -- 65 and over........... 7.3%
Dental........................... 6.0%
62
<PAGE>
The assumed health care rates gradually decline to 5.4% for both medical
categories and 3.7% for dental by 2001. The accumulated postretirement benefit
obligation was determined using an assumed discount rate of 7.25% for 1997 and
1996.
If the healthcare cost trend rate assumptions were increased by 1%, the
accumulated postretirement benefit obligation as of December 31, 1997 would be
increased by approximately 8%. The annual effect of the 1% increase on the total
of the service and interest costs would be an increase of approximately 11%.
The discount rate used in determining the accumulated postretirement benefit
obligation for the NorAm plan was 7.25% in 1997. The cost of covered health care
benefits (for those participants entitled to a defined benefit as a result of
having retired prior to July 1, 1992) is assumed to increase by 8.5% per year
initially and then increase at a decreasing rate to an annual and continuing
increase of 4.5% by 2006. Based on these assumptions, a one percentage point
increase in the assumed health care cost trend rate would increase the total of
the service plus interest costs (before any deferral for regulatory reasons) and
the accumulated postretirement benefit obligation related to the NorAm plan at
December 31, 1997 by 9.2% and 10.8%, respectively.
(e) Postemployment Benefits.
Effective January 1, 1994, the Company adopted SFAS No. 112, "Employer's
Accounting for Postemployment Benefits," which requires the recognition of a
liability for benefits, not previously accounted for on the accrual basis,
provided to former or inactive employees, their beneficiaries and covered
dependents, after employment but before retirement (primarily health care and
life insurance benefits for participants in the long-term disability plan). Net
postemployment benefit costs were not material in 1997, 1996 and 1995.
(11) INCOME TAXES
The Company records income taxes under SFAS No. 109, "Accounting for Income
Taxes," (SFAS No. 109) which, among other things, (i) requires the liability
method be used in computing deferred taxes on all temporary differences between
book and tax bases of assets other than nondeductible goodwill; (ii) requires
that deferred tax liabilities and assets be adjusted for an enacted change in
tax laws or rates; and (iii) prohibits net-of-tax accounting and reporting. SFAS
No. 109 requires that regulated enterprises recognize such adjustments as
regulatory assets or liabilities if it is probable that such amounts will be
recovered from or returned to customers in future rates.
The Company's current and deferred components of income tax expense from
continuing operations are as follows:
YEAR ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
-------- -------- --------
(THOUSANDS OF DOLLARS)
Current $199,011 $150,658 $141,076
Deferred 7,363 49,507 58,479
-------- -------- --------
Income taxes for continuing operations $206,374 $200,165 $199,555
======== ======== ========
63
<PAGE>
The Company's effective income tax rates are lower than statutory corporate
rates for each year as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1997 1996 1995
--------- --------- ---------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C>
Income from continuing operations before income
taxes $ 627,484 $ 605,109 $ 596,955
Preferred dividends of subsidiary 2,255 22,563 29,955
--------- --------- ---------
Total 629,739 627,672 626,910
Statutory rate 35% 35% 35%
Income taxes at statutory rate 220,409 219,685 219,419
--------- --------- ---------
Net reduction (addition) in taxes resulting from:
Amortization of investment tax credit 19,777 18,404 19,427
Excess deferred taxes 5,570 4,331 4,384
Difference between book and tax depreciation for
which deferred taxes have not been
normalized (27,466) (22,638) (15,211)
Equity dividend exclusion 5,075 10,194 4,932
Equity income -- foreign affiliates 17,011 5,936
Goodwill (7,242)
Other -- net 1,310 3,293 6,332
--------- --------- ---------
Total 14,035 19,520 19,864
--------- --------- ---------
Income taxes $ 206,374 $ 200,165 $ 199,555
========= ========= =========
Effective rate 32.8% 31.9% 31.8%
</TABLE>
64
<PAGE>
Following are the Company's tax effects of temporary differences attributable
to continuing operations resulting in deferred tax assets and liabilities:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------
1997 1996
---------- ----------
<S> <C> <C>
(THOUSANDS OF DOLLARS)
Deferred Tax Assets:
Alternative minimum tax credit carryforwards $ 60,669 $ 19,014
Employee benefits 145,794 68,078
Internal Revenue Service (IRS) audit assessment 74,966
Disallowed plant cost -- net 22,378 23,237
ACES 42,491
State operating loss carryforwards 29,515
Deferred state income taxes 14,460
Other 69,235 26,061
Valuation allowance (6,353)
---------- ----------
Total deferred tax assets -- net 378,189 211,356
---------- ----------
Deferred Tax Liabilities:
Depreciation 2,115,717 1,450,894
Deferred plant costs -- net 186,472 194,243
Regulatory assets -- net 356,509 362,310
Capitalized taxes, employee benefits and removal costs 46,584 108,530
Gain on sale of cable television subsidiary 222,942 228,449
Deferred state income taxes 70,000
Deferred gas costs 34,113
Other 138,633 131,961
---------- ----------
Total deferred tax liabilities 3,170,970 2,476,387
---------- ----------
Accumulated deferred income taxes -- net $2,792,781 $2,265,031
========== ==========
</TABLE>
Tax Refund Case. In July 1990, Former HI paid approximately $104.5 million to
the Internal Revenue Service (IRS) following an IRS audit of Former HI's 1983
and 1984 federal income tax returns. In November 1991, Former HI filed a refund
suit in the U.S. Court of Federal Claims seeking the return of $52.1 million of
tax and $36.3 million of accrued interest, plus interest on both of those
amounts accruing after July 1990. The major contested issue in the refund case
involved the IRS allegation that certain amounts related to the over-recovery of
fuel costs should have been included as taxable income in 1983 and 1984 even
though the Company had an obligation to refund the over-recoveries to its
ratepayers.
In September 1997, the United States Court of Appeals for the Federal Circuit
upheld a lower court ruling that the Company (as successor corporation to Former
HI) was due a refund of federal income taxes assessed on fuel over-recoveries
during 1983 and 1984 that subsequently were refunded to HL&P's customers.
In February 1998, the Company received a refund of approximately $142 million
in taxes and interest paid by Former HI in July 1990, including interest accrued
since 1990 in the amount of approximately $57 million. After giving effect to
the Company's deferred recognition of the 1990 tax payment and payment of
federal income taxes due on the accrued interest on the refund, the refund had
the effect of increasing the Company's earnings in the fourth quarter of 1997 by
$37 million (after-tax).
Tax Attribute Carryforwards. At December 31, 1997, NorAm has approximately
$439 million of state net operating losses available to offset future state
taxable income through the year 2012. Based on the Company's assessment of its
ability to use such loss carryforwards in future tax years, a valuation
allowance of
65
<PAGE>
$6.4 million was recorded at the Acquisition Date. In addition,
NorAm has approximately $58 million of federal alternative minimum tax credits
which are available to reduce future federal income taxes payable, if any, over
an indefinite period (although not below the tentative minimum tax otherwise due
in any year), and approximately $2.6 million of state alternative minimum tax
credits which are available to reduce future state income taxes payable, if any,
through the year 2001.
(12) COMMITMENTS AND CONTINGENCIES
(a) Commitments.
The Company has various commitments for capital expenditures, fuel, purchased
power, cooling water and operating leases. Commitments in connection with
Electric Operations' capital program are generally revocable by the Company,
subject to reimbursement to manufacturers for expenditures incurred or other
cancellation penalties. The Company's and its subsidiaries' other commitments
have various quantity requirements and durations. However, if these requirements
could not be met, various alternatives are available to mitigate the cost
associated with the contracts' commitments.
(b) Fuel and Purchased Power.
The Company is a party to several long-term coal, lignite and natural gas
contracts which have various quantity requirements and durations. Minimum
payment obligations for coal and transportation agreements are approximately
$200 million in 1998, $203 million in 1999 and $177 million in 2000.
Additionally, minimum payment obligations for lignite mining and lease
agreements are approximately $9 million for 1998, $9 million for 1999 and $10
million for 2000. Minimum payment obligations for both natural gas purchase and
storage contracts associated with Electric Operations are approximately $9
million annually in 1998, 1999 and 2000.
The Company also has commitments to purchase firm capacity from cogenerators
of approximately $22 million in both 1998 and 1999. Texas Utility Commission
rules currently allow recovery of these costs through Electric Operations' base
rates for electric service and additionally authorize the Company to charge or
credit customers through a purchased power cost recovery factor for any
variation in actual purchased power costs from the cost utilized to determine
its base rates. In the event that the Texas Utility Commission, at some future
date, does not allow recovery through rates of any amount of purchased power
payments, the two principal firm capacity contracts contain provisions allowing
the Company to suspend or reduce payments and seek repayment for amounts
disallowed.
(c) Operations Agreement with City of San Antonio.
As part of the settlement with the City of San Antonio, the Company entered
into a 10-year joint operations agreement under which the Company and the City
of San Antonio, acting through the City Public Service Board of San Antonio
(CPS), share savings resulting from the joint dispatching of their respective
generating assets in order to take advantage of each system's lower cost
resources. Under the terms of the joint operations agreement entered into
between CPS and Electric Operations, the Company has guaranteed CPS minimum
annual savings of $10 million and a minimum cumulative savings of $150 million
over the 10-year term of the agreement. Based on current forecasts and other
assumptions regarding the combined operation of the two generating systems, the
Company anticipates that the savings resulting from joint operations will equal
or exceed the minimum savings guaranteed under the joint operating agreement. In
1996, savings generated for CPS' account for a partial year of joint operations
were approximately $14 million. In 1997, savings generated for CPS' account for
a full year of operation were approximately $22 million.
(d) Transportation Agreement.
NorAm had an agreement (the ANR Agreement) with ANR Pipeline Company (ANR)
which contemplated a transfer to ANR of an interest in certain of NorAm's
pipeline and related assets, representing
66
<PAGE>
capacity of 250 Mmcf/day, and pursuant
to which ANR had advanced $125 million to the Company. The ANR Agreement has
been restructured and, after refunds of $84 million through December 31, 1997,
NorAm currently retains $41 million (recorded as a liability) in exchange for
ANR's or its affiliates' use of 130 Mmcf/ day of capacity in certain of NorAm's
transportation facilities. The level of transportation will decline to 100
Mmcf/day in the year 2003 with a refund of $5 million to ANR and the ANR
Agreement will terminate in 2005 with a refund of the remaining balance.
(e) Lease Commitments.
The following table sets forth certain information concerning NorAm's
obligations under operating leases:
Minimum Lease Commitments at December 31, 1997(1)
(MILLIONS OF DOLLARS)
1998 $ 24
1999 19
2000 16
2001 15
2002 9
2003 and beyond 22
----
Total $105
====
__________
(1) Principally consisting of rental agreements for building space and data
processing equipment and vehicles (including major work equipment).
NorAm has a master leasing agreement which provides for the lease of vehicles,
construction equipment, office furniture, data processing equipment and other
property. For accounting purposes, the lease is treated as an operating lease.
At December 31, 1997, NorAm had leased assets with a value of approximately
$58.1 million under this lease with a basic term of one year. NorAm does not
expect to lease additional property under this lease agreement.
Lease payments related to NorAm's master leasing agreement are included in the
preceding table for only their basic term. Total rental expense for all leases
since the Acquisition Date was approximately $15 million in 1997.
(f) Letters of Credit.
At December 31, 1997, NorAm had letters of credit incidental with its ordinary
business operations totaling approximately $42 million under which NorAm is
obligated to reimburse drawings, if any.
(g) Indemnity Provisions.
At December 31, 1997, NorAm has $11.4 million accounting reserve on the
Company's Consolidated Balance Sheet in Other Deferred Credits for possible
indemnity claims asserted in connection with its disposition of NorAm's former
subsidiaries or divisions, including the sale of (i) Louisiana Intrastate Gas
Corporation, a former NorAm subsidiary engaged in the intrastate pipeline and
liquids extraction business; (ii) Arkla Exploration Company, a former NorAm
subsidiary engaged in oil and gas exploration and production activities; and
(iii) Dyco Petroleum Company, a former NorAm subsidiary engaged in oil and gas
exploration and production.
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<PAGE>
(h) Other.
Electric Operations' service area is heavily dependent on oil, gas, refined
products, petrochemicals and related businesses. Significant adverse events
affecting these industries would negatively affect the revenues of the Company.
The Company and NorAm are involved in legal, tax and regulatory proceedings
before various courts, regulatory commissions and governmental agencies
regarding matters arising in the ordinary course of business, some of which
involve substantial amounts. The Company's management regularly analyzes current
information and, as necessary, provides accruals for probable liabilities on the
eventual disposition of these matters. The Company's management believes that
the effect on the Company's and NorAm's respective financial statements, if any,
from the disposition of these matters will not be material.
In February 1996, the cities of Wharton, Galveston and Pasadena filed suit,
for themselves and a proposed class, against the Company and Houston Industries
Finance Inc. (formerly a wholly owned subsidiary of the Company) citing
underpayment of municipal franchise fees. The plaintiffs claim, among other
things, that from 1957 to the present, franchise fees should have been paid on
sales taxes collected by HL&P on non-electric receipts as well as electric
sales. Plaintiffs advance their claims notwithstanding their failure to notice
such claims over the previous four decades. Because all of the franchise
ordinances affecting HL&P expressly impose fees only on electric sales, the
Company regards plaintiffs' allegations as spurious and is vigorously contesting
the matter. The plaintiffs' pleadings assert that their damages exceed $250
million. No trial date is currently set. Although the Company believes the
claims to be without merit, the Company cannot at this time estimate a range of
possible loss, if any, from the lawsuit, nor can any assurance be given as to
its ultimate outcome
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 financial statements, if any, from the
disposition of these matters will not be material.
68
<PAGE>
(13) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------------
1997 1996
---------------------- ----------------------
<S> <C> <C> <C> <C>
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
---------- ---------- ---------- ----------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
Financial Assets:
Company:
Investment in Time Warner securities $ 990,000 $1,420,360 $1,027,500 $1,027,500
NorAm:
Energy derivatives 9,399 13,060
Financial Liabilities:
Company:
First mortgage bonds 2,495,459 2,651,260 2,895,041 3,045,833
Debentures 349,283 379,490 349,098 380,455
ACES 1,173,786 1,307,247 -- --
Cumulative preferred stock (subject to
mandatory redemption) -- -- 25,700 25,957
Trust preferred and capital securities 340,882 366,220 -- --
NorAm:
Long-term debt 1,148,848 1,147,344
Trust preferred securities 21,290 24,569
Interest rate swaps -- 755
HI Energy:
Interest rate swaps -- 1,679 -- --
</TABLE>
The fair values of cash and short-term investments, investment in the
Company's nuclear decommissioning trust, short-term and other notes payable,
floating rate debt of HI Energy, and floating rate pollution control revenue
bonds are estimated to be equivalent to carrying amounts. The remaining fair
values have been determined using quoted market prices of the same or similar
securities when available or other estimation techniques.
(14) UNAUDITED QUARTERLY INFORMATION
The following unaudited quarterly financial information includes, in the
opinion of management, all adjustments (which comprise only normal recurring
accruals) necessary for a fair presentation. Quarterly results are not
necessarily indicative of a full year's operations because of seasonality and
other factors, including rate increases and variations in operating expense
patterns. Results of operations of the newly acquired NorAm businesses are
included beginning on the Acquisition Date.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
---------------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- ---------- ---------- ----------
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE
AMOUNTS)
<S> <C> <C> <C> <C>
Revenues $878,101 $1,064,448 $2,158,551 $2,772,285
Operating Income 156,216 247,172 462,716 198,396
Net Income 59,620 121,463 243,898 (4,033)
Basic Earnings (loss) per common share(a) .26 .52 .93 (.01)
Diluted earnings (loss) per common share(a) .26 .52 .93 (.01)
</TABLE>
69
<PAGE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1996
---------------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- ---------- ---------- ----------
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE
AMOUNTS)
<S> <C> <C> <C> <C>
Revenues $823,507 $1,113,763 $1,251,025 $ 906,982
Operating Income 137,139 286,280 441,069 125,978
Net income (loss) (16,740) 145,334 240,024 36,326
Basic Earnings (loss) per common share(a) (.07) .58 .98 .15
Diluted earnings (loss) per common share(a) (.07) .58 .98 .15
</TABLE>
__________
(a) Quarterly earnings per common share are based on the weighted average
number of shares outstanding during the quarter, and the sum of the
quarters may not equal annual earnings per common share.
70
<PAGE>
(15) REPORTABLE SEGMENTS
Upon the acquisition of NorAm, the Company organized its business into the
following segments: Electric Operations, Natural Gas Distribution, Interstate
Pipeline, Energy Marketing, International and Corporate segments. Consistent
with the purchase accounting treatment of the Merger, financial information for
the Natural Gas Distribution, Interstate Pipeline and Energy Marketing segments
are presented only for periods beginning on the Acquisition Date. In 1996 and
1995, the Company's Electric Operations accounted for in excess of 90% of the
Company's total revenues, income and identifiable assets and as such, the
required segment information for those periods is provided on the face of the
Company's consolidated financial statements and in the related notes thereto.
The Company has presented the following summary of financial information by
business segment for 1997 and has included supplemental comparative information
for 1996.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1997(1) 1996
------------ -----------
<S> <C> <C>
Revenues:
Electric Operations $ 4,251,243 $ 4,025,027
Natural Gas Distribution 892,569
Interstate Pipeline 108,333
Energy Marketing 1,604,999
International 92,028 62,059
Corporate and Other 47,851 8,191
Eliminations (123,638)
------------ -----------
Total Revenues $ 6,873,385 $ 4,095,277
============ ===========
Operating Income (Loss):
Electric Operations $ 994,938 $ 997,147
Natural Gas Distribution 54,502
Interstate Pipeline 31,978
Energy Marketing 16,407
International 19,510 2,339
Corporate and Other (52,835) (9,020)
------------ -----------
Total Operating Income 1,064,500 990,466
------------ -----------
Other income (expenses) (13,446) (55,412)
Interest and Other Charges 423,570 329,945
------------ -----------
Income from Continuing Operations Before Tax $ 627,484 $ 605,109
============ ===========
Depreciation and Amortization:
Electric Operations $ 568,541 $ 545,685
Natural Gas Distribution 51,883
Interstate Pipeline 19,088
Energy Marketing 4,448
International 3,470 1,648
Corporate and Other 4,445 2,705
------------ -----------
Total Depreciation and Amortization $ 651,875 $ 550,038
============ ===========
Identifiable Assets:
Electric Operations $ 10,540,849 $10,596,232
Natural Gas Distribution 3,047,195
Interstate Pipeline 3,055,610
Energy Marketing 1,267,867
International 869,485 607,103
Corporate and Other 12,837,302 5,771,648
Eliminations (13,203,753) (4,687,126)
------------ -----------
Total Identifiable Assets $ 18,414,555 $12,287,857
============ ===========
Capital Expenditures:
Electric Operations $ 236,977 $ 317,532
Natural Gas Distribution 61,078
Interstate Pipeline 16,304
Energy Marketing 14,365
International 231,528 495,379
Corporate and Other 23,572 19,989
------------ -----------
Total Capital Expenditures $ 583,824 $ 832,900
============ ===========
</TABLE>
- ----------
(1) New categories for segments in 1997 result from the NorAm Merger. See Note
1(b).
71
<PAGE>
(16) SUBSEQUENT EVENTS
In January 1998, the MCND issued on behalf of the Company $104.7 million
aggregate principal amount of pollution control revenue refunding bonds with
$29.7 million at 5.25% and $75 million at 5.15%. The MCND bonds will mature in
2029. The Company used the proceeds from the sale of these securities to redeem
all outstanding 7 7/8% MCND Series 1989A pollution control revenue bonds ($29.7
million) and 7.70% MCND Series 1989B pollution control revenue bonds ($75
million) at a redemption price of 102% of the aggregate principal amount of each
series.
In February 1998, the BRA issued on behalf of the Company $290 million
aggregate principal amount of pollution control revenue refunding bonds. The BRA
bonds will mature in May 2019 ($200 million at 5 1/8%) and November 2020 ($90
million at 5 1/8%). The Company will use the proceeds from the sale of these
securities to redeem all the outstanding 8.25% BRA 1988A Series pollution
control revenue bonds ($100 million), the 8.25% BRA 1988B Series pollution
control revenue bonds ($90 million), and the 8.10% BRA 1988C Series pollution
control revenue bonds ($100 million) at a redemption price of 102% of the
aggregate principal amount of each series.
In February 1998, NorAm issued $300 million principal amount of 6.5%
debentures due February 1, 2008. The debentures are not redeemable prior to
maturity and are not subject to any sinking fund requirements. The proceeds from
the sale of the debentures were used to repay short-term indebtedness of NorAm,
including the indebtedness incurred in connection with the 1997 purchase of $101
million aggregate principal amount of its 10% Debentures and the repayment of
$53 million aggregate principal amount of NorAm debt that matured in December
1997 and January 1998. In connection with the issuance of the 6.5% debentures
NorAm received approximately $1 million upon unwinding a $300 million treasury
rate lock agreement, which was tied to the interest rate on 10-year treasury
bonds. The rate lock agreement was executed in January 1998, and proceeds from
the unwind will be amortized over the 10 year life of NorAm's 6.5% debentures.
72
<PAGE>
INDEPENDENT AUDITORS' REPORT
Houston Industries Incorporated:
We have audited the accompanying consolidated balance sheets and the
consolidated statements of capitalization of Houston Industries Incorporated and
its subsidiaries (Company) as of December 31, 1997 and 1996, and the related
statements of consolidated income, consolidated retained earnings and
consolidated cash flows for each of the three years in the period ended December
31, 1997. Our audits also included the Company's financial statement schedule
listed in Item 14(a)(3). These financial statements and the financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and the financial
statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Houston Industries Incorporated and
its subsidiaries at December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997 in conformity with generally accepted accounting principles.
Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Houston, Texas
February 20, 1998
73
<PAGE>
CONSENT OF INDEPENDENT AUDITORS
HOUSTON INDUSTRIES INCORPORATED:
We consent to the incorporation by reference in Houston Industries
Incorporated's (i) Registration Statement on Form S-4 No. 333-11329, (ii)
Registration Statements on Form S-3 Nos. 33-46368, 33-54228, 333-20069,
333-32353, 333-33301, and 333-33303, (iii) Post-Effective Amendment No. 1 to
Registration Statement No. 33-51417 on Form S-3, (iv) Registration Statements on
Form S-8 Nos. 333-32413, and 333-32585 and (v) Post-Effective Amendment No. 1 to
Registration No. 333-11329-99 on Form S-8 of our report dated February 20, 1998
(relating to the consolidated financial statements of Houston Industries
Incorporated) appearing on this Combined Annual Report on Form 10-K of Houston
Industries Incorporated and NorAm Energy Corp. for the year ended December 31,
1997.
DELOITTE & TOUCHE LLP
HOUSTON, TEXAS
MARCH 23, 1998
<PAGE>
HOUSTON INDUSTRIES INCORPORATED
PROXY - COMMON STOCK
THIS PROXY IS SOLICITED ON BEHALF OF THE BOARD OF DIRECTORS
The undersigned hereby appoints D.D. Jordan, R. Steve Letbetter and Lee W.
Hogan, and each of them as proxies, with full power of substitution, to vote as
designated on the reverse side, all shares of common stock held by the
undersigned at the annual meeting of shareholders of Houston Industries
Incorporated to be held May 6, 1998, at 9 AM (CDT) in the Auditorium of Houston
Industries Plaza, 1111 Louisiana Street, Houston, Texas, or any adjournments
thereof, and with discretionary authority to vote on all other matters that may
properly come before the meeting.
IF YOU WISH TO VOTE IN ACCORDANCE WITH THE
RECOMMENDATIONS OF THE BOARD OF DIRECTORS, YOU
MAY JUST SIGN AND DATE BELOW AND MAIL IN THE
POSTAGE-PAID ENVELOPE PROVIDED. SPECIFIC CHOICES
MAY BE MADE ON THE REVERSE SIDE. IN THE ABSENCE
OF INSTRUCTIONS TO THE CONTRARY, THE SHARES
REPRESENTED WILL BE VOTED IN ACCORDANCE WITH THE
BOARD'S RECOMMENDATION.
Dated: , 1998
---------------------------------
Signature:
-----------------------------------
Signature:
-----------------------------------
Note: Please sign exactly as name(s) appears
hereon. Joint owners should each sign. When
signing as attorney, executor, administrator,
trustee or guardian, please give full title.
DO YOU PLAN TO ATTEND THE ANNUAL MEETING?_____
- --------------------------------------------------------------------------------
HOUSTON INDUSTRIES INCORPORATED
PROXY (CONTINUED)
1998 ANNUAL MEETING OF SHAREHOLDERS
The nominees for Class II directors are Milton Carroll, John T. Cater, Robert C.
Hanna and R. Steve Letbetter. Their terms will expire in 2001. Your Board of
Directors recommends that you vote FOR all nominees for director, FOR amendment
of the 1994 Long-Term Incentive Compensation Plan and FOR the appointment of
Deloitte & Touche LLP as independent accountants and auditors for 1998. To
withhold authority to vote for any individual nominee, please write that
nominee's name in the space provided below.
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C> <C>
WITH- FOR ALL
FOR HOLD EXCEPT FOR AGAINST ABSTAIN
1. Election of nominees [_] [_] [_] 2. Amendment of 1994 [_] [_] [_]
for director in Class II Long-Term Incentive
Compensation Plan
Exceptions:_______________________________
__________________________________________ 3. Appoint Deloitte & [_] [_] [_]
__________________________________________ Touche LLP as
independent accountants
and auditors for 1998
</TABLE>
