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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED JANUARY 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-6959
MITCHELL ENERGY & DEVELOPMENT CORP.
(Exact name of registrant as specified in its charter)
TEXAS 74-1032912
(State of Incorporation) (I.R.S. Employer Identification No.)
2001 TIMBERLOCH PLACE
THE WOODLANDS, TEXAS 77380
(Address of Principal Executive Offices) (Zip Code)
Registrant's telephone number including area code: (713) 377-5500
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
------------------- ---------------------
Class A Common Stock, $.10 Par Value New York and Pacific
Class B Common Stock, $.10 Par Value New York and Pacific
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or Section 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of voting stock held by
nonaffiliates of the registrant at
March 31, 2000 was approximately $175,835,888.
Shares of common stock outstanding at March 31, 2000:
Class A - 22,321,634
Class B - 26,811,769
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents are incorporated by reference into the
indicated parts of this report:
Annual Report to Stockholders for the fiscal year ended January 31, 2000 -
Parts I and II.
Definitive Proxy Statement to be filed within 120 days after January 31, 2000 -
Part III.
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PART I
ITEM 1 - BUSINESS
Except for discussions of competition and insurance, information required
by this item is incorporated by reference from portions of Mitchell Energy &
Development Corp.'s Annual Report to Stockholders for the fiscal year ended
January 31, 2000 furnished to the Commission pursuant to Rule 14a-3(b) under the
Securities Exchange Act of 1934 (Annual Report to Stockholders).
CROSS REFERENCE TO APPLICABLE SECTIONS
OF ANNUAL REPORT TO STOCKHOLDERS PAGE
-----------
Inside
The Company................................................ Front Cover
Exploration and Production................................. 4 - 9
Gas Services............................................... 10 - 14
Management's Discussion and Analysis of
Financial Position and Results of Operations............. 15 - 22
Notes to Consolidated Financial Statements
Note 9: Segment Information............................. 36 - 38
Competition
The Registrant is a holding company which conducts all of its operations
through its subsidiaries, collectively referred to as "the Company." The Company
is one of the country's largest independent producers of natural gas and natural
gas liquids.
Its operations include the exploration, development and production of
natural gas and crude oil, the operation of natural gas gathering systems and
the production of natural gas liquids (NGLs). Within these businesses, the
Company competes with many companies that have substantially larger financial
and other resources or whose operations are more fully integrated than the
Company's. The oil and gas industry is highly competitive. There is competition
within the industry and also with other industries in supplying the fuel and
energy needs of commerce, industry and individuals.
The Company owns or has interests in natural gas processing plants located
in Texas, and it ranked 16th in daily domestic NGL production in calendar 1998.
The Company has fractionating equipment at several of its processing plants and
also owns a 38.75% interest in a large fractionating plant near Mont Belvieu on
the upper Texas Gulf Coast. After being fractionated into ethane, propane,
butanes and natural gasoline, the NGLs are used by others in the production of
plastics, paints, solvents, synthetic rubber, gasoline and a wide variety of
other products. Propane also is widely used as a fuel in rural areas for
cooking, home heating and crop drying. The Company participates in the
petrochemical business through its one-third interest in a plant at Mont
Belvieu, Texas that produces methyl tertiary butyl ether (MTBE), an oxygenate
used in the production of environmentally cleaner gasoline. That plant has a
daily capacity of approximately 17,000 barrels.
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The Company owns or operates approximately 8,800 miles of natural gas
gathering systems substantially all of which are located in Texas. Those systems
operate in highly competitive local markets and intersect with numerous pipeline
systems enabling the Company to buy, sell, transport and exchange gas with other
pipeline operators.
The Company's operations have been and in the future may be affected in
varying degree by general economic conditions and by laws and regulations,
including restrictions on production, price controls, tax increases and
environmental regulations. The Company's energy price realizations are often
volatile and generally are affected both by domestic and world supply and demand
conditions.
Insurance
The Company's business is subject to all the operating risks normally
associated with the exploration and production of natural gas and oil; natural
gas gathering and transportation and the extraction of NGLs from natural gas
streams. Such risks include well blow-out, fire and explosion, pollution, flood
and other events which could result in the damage to or destruction of assets
owned by the Company or third parties and the injury of employees and other
persons. The Company, following practices customary within the industries in
which it operates, purchases insurance coverage against most, but not all, of
these operating risks as protection against financial loss and believes it is
adequately insured against public liability claims and physical damage losses.
Losses and liabilities, to the extent not covered by insurance, could reduce the
Company's cash flows and increase its costs.
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ITEM 2 - PROPERTIES
Information required by this item is incorporated by reference from
portions of the Annual Report to Stockholders.
CROSS REFERENCE TO APPLICABLE SECTIONS
OF ANNUAL REPORT TO STOCKHOLDERS PAGE
-------
Exploration and Production................................... 4 - 9
Gas Services................................................. 10 - 14
Operating Statistics......................................... 19
Unaudited Supplemental Oil and Gas Information............... 42 - 44
OTHER OIL AND GAS RELATED DATA
The following information is required by Sections 3, 5 and 6 of the
Securities Act Industry Guide 2, Disclosure of Oil and Gas Operations.
AVERAGE PRODUCTION COST IN EQUIVALENT UNITS
<TABLE>
<CAPTION>
Year Ended January 31
-------------------------------
2000 1999 1998
------- ------- -------
<S> <C> <C> <C>
Combined natural gas, crude oil and condensate
production (thousand cubic feet per day)*............................ 294,000 298,000 285,000
Average production cost per
equivalent thousand cubic feet....................................... $ .65 $ .68 $ .68
</TABLE>
- -------------------------------------------------------------
*Expressed in equivalent units of production with barrels of oil
converted to cubic feet of gas on a 6-to-1 basis.
UNDEVELOPED ACREAGE AT JANUARY 31, 2000
<TABLE>
<CAPTION>
Earliest Material
Expiration by State (a) Areas of Concentration
----------------------- ------------------------
Gross Net Net Calendar %
Location Acres Acres Acres Year County or Area (b)
- -------- --------- ------- ------ -------- ----------------- ---
<S> <C> <C> <C> <C> <C> <C>
Texas......................... 293,100 203,100 43,300 2000 North Texas 63
Mississippi................... 16,100 6,800 2,100 2001 Yazoo 60
Louisiana..................... 12,500 8,200 4,300 2000 Jackson,
Jefferson Davis 90
New Mexico.................... 12,500 11,000 6,100 2004 Lea 92
Alabama....................... 11,300 4,800 1,800 2000 Conecuh 57
Others (c).................... 13,500 9,300
--------- -------
Total undeveloped acreage..... 359,000 243,200
Producing acreage............. 713,400 533,300
--------- -------
Total acreage................. 1,072,400 776,500
========= =======
</TABLE>
- ----------------------------------------
(a) Expiring leases may be renewed if conditions warrant.
(b) Percentage of the state's net acres located in the indicated areas of
concentration.
(c) Includes Colorado, Michigan, Oklahoma and Utah.
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DRILLING ACTIVITY (a)
For the year ended January 31
<TABLE>
<CAPTION>
Exploratory Development Total
------------------ ------------------ ------------------
Well Completions Total Oil Gas Dry Oil Gas Dry Oil Gas Dry
- ------------------------- ----- --- --- --- --- --- --- --- --- ---
Gross Wells - 2000
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
North Texas..................... 85 3 - 4 3 73 2 6 73 6
East Texas...................... 19 - - - 1 18 - 1 18 -
Gulf Coast...................... 19 - - 5 4 9 1 4 9 6
Other (b)....................... 4 2 - 2 - - - 2 - 2
----- ---- --- ---- ---- ----- --- ---- ----- ----
Total (c)..................... 127 5 - 11 8 100 3 13 100 14
===== ==== === ==== ==== ===== === ==== ===== ====
Net Wells
2000............................ 110.7 2.3 - 5.7 7.5 92.2 3.0 9.8 92.2 8.7
===== ==== === ==== ==== ===== === ==== ===== ====
1999............................ 120.5 4.2 2.0 5.5 12.3 90.3 6.2 16.5 92.3 11.7
===== ==== === ==== ==== ===== === ==== ===== ====
1998............................ 162.1 15.0 5.5 10.2 23.2 106.7 1.5 38.2 112.2 11.7
===== ==== === ==== ==== ===== === ==== ===== ====
</TABLE>
- ----------------------------
(a) Excludes service wells.
(b) Includes West Texas and Louisiana.
(c) An additional 25 wells (22.1 net wells) were in the process of being
drilled or completed at January 31, 2000.
ITEM 3 - LEGAL PROCEEDINGS
The information required by this item is incorporated by reference from
Note 6 of Notes to Consolidated Financial Statements included in the Company's
Annual Report to Stockholders.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of fiscal 2000, no matter was submitted to a
vote of security holders, either through solicitation of proxies or otherwise.
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EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of the executive officers of the Company as of
March 31, 2000.
<TABLE>
<CAPTION>
Officer
Name Position Age Since
---- -------- --- -------
<S> <C> <C> <C>
George P. Mitchell Chairman and Chief Executive Officer 80 1946
Bernard F. Clark Vice Chairman 78 1956
W. D. Stevens President and Chief Operating Officer 65 1994
Philip S. Smith Senior Vice President and Chief Financial Officer 63 1980
Allen J. Tarbutton, Jr. Senior Vice President, Gas Services 61 1974
Thomas P. Battle Senior Vice President, Legal and Governmental 57 1982
Affairs, General Counsel and Secretary
</TABLE>
The year in the "Officer Since" column is the beginning of the period during
which the indicated individual has continuously served as an officer of the
Company (although not necessarily as an "executive officer").
All of the executive officers were elected at a Board of Directors meeting
held on June 30, 1999 for a term of one year, or until their respective
successors are qualified.
There are no significant family relationships among the officers of the
Company, either by blood, marriage or adoption.
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PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Except for the approximate number of holders of record of common stock,
information required by this item is incorporated by reference from portions of
the Annual Report to Stockholders.
CROSS REFERENCE TO APPLICABLE SECTIONS
OF ANNUAL REPORT TO STOCKHOLDERS PAGE
-----------
Quarterly Stock Data.......................... 23
Corporate Information......................... Inside
Back Cover
The numbers of holders of record of Class A Common Stock and of Class B Common
Stock at March 31, 2000 were 1,413 and 1,397, respectively. Including those
whose shares are carried in street names, the Registrant estimates that there
are approximately 5,000 holders each of its Class A and B common stock.
ITEM 6 - SELECTED FINANCIAL DATA
Information required by this item is incorporated by reference from pages
45 and 46 of the Annual Report to Stockholders under the caption "Historical
Summary." Incorporation by reference from these pages is restricted to the
information for the fiscal years 1996 through 2000 provided under the following
captions: Revenues, earnings (loss) from continuing operations, net earnings
(loss), earnings (loss) per share (basic and diluted), cash dividends per share,
total assets and long-term debt.
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
POSITION AND RESULTS OF OPERATIONS
Information required by this item is incorporated by reference from pages
15 through 22 of the Annual Report to Stockholders.
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information required by this item is incorporated by reference from page
18 of the Annual Report to Stockholders.
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<PAGE> 8
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information required by this item is incorporated by reference from
portions of the Annual Report to Stockholders.
CROSS REFERENCE TO APPLICABLE SECTIONS
OF ANNUAL REPORT TO STOCKHOLDERS PAGE
-------
Consolidated Financial Statements............................. 24 - 27
Notes to Consolidated Financial Statements.................... 28 - 40
Report of Independent Public Accountants...................... 41
Unaudited Supplemental Oil and Gas Information................ 42 - 44
Unaudited Quarterly Financial Data............................ 23
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
No Form 8-K was filed by the Registrant during its fiscal years ended
January 31, 2000 and 1999 or any subsequent period reporting a change of
accountants or any disagreement on any matter of accounting principles,
practices or financial statement disclosure.
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by this item is incorporated by reference from
portions of the Registrant's definitive Proxy Statement to be filed with the
Securities and Exchange Commission within 120 days after January 31, 2000
pursuant to Regulation 14A under the Securities Exchange Act of 1934 (Proxy
Statement), under the caption "Election of Directors." See page 5 of this Form
10-K for information regarding Executive Officers of the Registrant.
ITEM 11 - EXECUTIVE COMPENSATION
Information required by this item is incorporated by reference from
portions of the Proxy Statement to be filed with the Securities and Exchange
Commission within 120 days after January 31, 2000, under the captions "Executive
Compensation" and "Compensation Committee Interlocks and Insider Participation."
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information required by this item is incorporated by reference from
portions of the Proxy Statement to be filed with the Securities and Exchange
Commission within 120 days after January 31, 2000, under the caption "Voting
Securities and Principal Holders Thereof."
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ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information required by this item is incorporated by reference from
portions of the Proxy Statement to be filed with the Securities and Exchange
Commission within 120 days after January 31, 2000, under the caption "Certain
Transactions."
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) DOCUMENTS FILED AS PART OF THIS REPORT:
FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
<TABLE>
<CAPTION>
CROSS REFERENCE TO APPLICABLE SECTIONS
OF ANNUAL REPORT TO STOCKHOLDERS PAGE
-------------------------------------- -------
<S> <C>
Unaudited Quarterly Financial Data - Fiscal 2000 and 1999............................ 23
Consolidated Balance Sheets - At January 31, 2000 and 1999........................... 24
Consolidated Statements of Earnings - Fiscal Years
Ended January 31, 2000, 1999 and 1998............................................ 25
Consolidated Statements of Stockholders' Equity - Fiscal Years
Ended January 31, 2000, 1999 and 1998............................................ 26
Consolidated Statements of Cash Flows - Fiscal Years
Ended January 31, 2000, 1999 and 1998............................................ 27
Notes to Consolidated Financial Statements........................................... 28 - 40
Report of Independent Public Accountants............................................. 41
Unaudited Supplemental Oil and Gas Information....................................... 42 - 44
</TABLE>
FINANCIAL STATEMENT SCHEDULES
All schedules are omitted because they are not applicable or the
information required to be set forth therein is included in the
consolidated financial statements or the footnotes thereto.
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<PAGE> 10
EXHIBITS
3(a) Restated Articles of Incorporation of Mitchell Energy &
Development Corp., as amended through July 2, 1990 are
incorporated as an exhibit to this report by reference to exhibit
3(a) of the annual report on Form 10-K dated January 31, 1992.
The Certificate of Amendment dated June 24, 1992 is incorporated
as an exhibit to this report by reference to exhibit 3 of the
quarterly report on Form 10-Q for the quarter ended July 31,
1992.
3(b) The Bylaws of Mitchell Energy & Development Corp. are
incorporated as an exhibit to this report by reference to
exhibit 3(b) of the annual report on Form 10-K dated January 31,
1996.
4(a) The senior indenture dated August 1, 1991 by and between Mitchell
Energy & Development Corp., as Issuer, and First City, Texas -
Houston, National Association (succeeded by Chase Bank of Texas,
N.A.), as Trustee, is incorporated as an exhibit to this report
by reference to exhibit 4(b) of File No. 33-42340.
4(b) The senior and subordinated indentures dated January 1, 1993 by
and between Mitchell Energy & Development Corp., as Issuer, and
NationsBank of Texas, National Association, as Trustee, are
incorporated as exhibits to this report by reference to exhibits
4(b) and 4(c) of File No. 33-61070. The first supplement to the
senior indenture dated January 15, 1994 is incorporated as an
exhibit to this report by reference to exhibit 4(a) of the
current report on Form 8-K dated January 18, 1994.
4(c) The revolving credit agreement dated as of July 28, 1998 among
Mitchell Energy & Development Corp., the several banks which are
parties thereto and The Chase Manhattan Bank, as administrative
agent for the banks, is incorporated as an exhibit to this report
by reference to exhibit 4 of the quarterly report on Form 10-Q
for the quarter ended July 31, 1998. The first amendment to this
agreement dated March 15, 1999 is incorporated as an exhibit to
this report by reference to exhibit 4(c) of the annual report on
Form 10-K dated January 31, 1999.
Upon request, the Registrant will provide to the Securities and
Exchange Commission copies of all other instruments defining the
rights of holders of long-term debt of Mitchell Energy &
Development Corp. and its consolidated subsidiaries.
The following exhibits 10(a) through 10(q) filed under paragraph 10 of Item 601
of Regulation S-K are the Company's management contracts and compensation plans
or arrangements.
10(a) 1989 Stock Option Plan is incorporated as an exhibit to this
report by reference to exhibit 10(d) of the annual report on Form
10-K dated January 31, 1992. The first amendment to such Plan is
incorporated as an exhibit to this report by reference to exhibit
10(c) of the annual report on Form 10-K dated January 31, 1993.
10(b) 1995 Stock Option Plan is incorporated as an exhibit to this
report by reference to File No. 333-06981.
10(c) 1997 Bonus Unit Plan is incorporated as an exhibit to this report
by reference to exhibit 10(e) of the annual report on Form 10-K
dated January 31, 1999. The first amendment to this Plan
effective December 9, 1998 is attached hereto as exhibit 10(c).
10(d) 1999 Stock Option Plan.
10(e) 1998 Mutual Fund Option Plan is incorporated as an exhibit to
this report by reference to exhibit 10 of the quarterly report on
Form 10-Q for the quarter ended July 31, 1998. The first
amendment to this Plan effective January 1, 1999 is incorporated
as an exhibit to this report by reference to exhibit 10(d) of the
annual report on Form 10-K dated January 31, 1999.
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<PAGE> 11
10(f) Mitchell Energy & Development Corp. Restoration Benefit Plan
effective January 1, 1992 is incorporated as an exhibit to this
report by reference to exhibit 10(f) of the annual report on Form
10-K dated January 31, 1994. The first amendment to this Plan
effective July 1, 1998 is incorporated as an exhibit to this
report by reference to exhibit 10(e) of the annual report on Form
10-K dated January 31, 1999.
10(g) Mitchell Energy & Development Corp. Excess Benefit Plan (formerly
the Supplemental Retirement Plan) amended and restated effective
as of January 1, 1992 is incorporated as an exhibit to this
report by reference to exhibit 10(g) of the annual report on Form
10-K dated January 31, 1994. The first amendment to this Plan
effective July 1, 1998 is incorporated as an exhibit to this
report by reference to exhibit 10(f) of the annual report on Form
10-K dated January 31, 1999.
10(h) Executive Excess Benefit Plan effective July 1, 1998 is
incorporated as an exhibit to this report by reference to exhibit
10(g) of the annual report on Form 10-K dated January 31, 1999.
10(i) Deferred compensation/supplementary life insurance arrangement
between the Registrant and certain of its executive officers is
incorporated as an exhibit to this report by reference to exhibit
10(h) of the annual report on Form 10-K dated January 31, 1992.
10(j) The Supplemental Benefit Agreement dated August 17, 1990 between
the Registrant and George P. Mitchell is incorporated as an
exhibit to this report by reference to exhibit 10(h) of the
Annual Report on Form 10-K dated January 31, 1997.
10(k) Employment agreement between the Registrant and W. D. Stevens
dated January 3, 1994 is incorporated as an exhibit to this
report by reference to exhibit 10(j) of the annual report on Form
10-K dated January 31, 1994.
10(l) Severance compensation agreement between the Registrant and
Thomas P. Battle is incorporated as an exhibit to this report by
reference to exhibit 10(k) of the annual report on Form 10-K
dated January 31, 1999.
10(m) Severance compensation agreement between the Registrant and
George P. Mitchell is incorporated as an exhibit to this report
by reference to exhibit 10(l) of the annual report on Form 10-K
dated January 31, 1999.
10(n) Severance compensation agreement between the Registrant and W. D.
Stevens is incorporated as an exhibit to this report by reference
to exhibit 10(m) of the annual report on Form 10-K dated January
31, 1999.
10(o) Severance compensation agreement between the Registrant and
Philip S. Smith is incorporated as an exhibit to this report by
reference to exhibit 10(n) of the annual report on Form 10-K
dated January 31, 1999.
10(p) Severance compensation agreement between the Registrant and Allen
J. Tarbutton, Jr. is incorporated as an exhibit to this report
by reference to exhibit 10(o) of the annual report on Form 10-K
dated January 31, 1999.
10(q) A written description (in lieu of a formal document) describing
the Registrant's commitment to contribute to the life insurance
program of George P. Mitchell is incorporated as an exhibit to
this report by reference to exhibit 10(m) of the annual report on
Form 10-K dated January 31, 1996.
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<PAGE> 12
12 Computation of Ratio of Earnings to Fixed Charges.
13 Annual Report to Stockholders for the fiscal year ended January
31, 2000.
21 List of Subsidiaries as of January 31, 2000.
23 Consent of Independent Public Accountants.
27 Financial Data Schedule
99 Mitchell Energy & Development Corp. Thrift and Savings Plan -
Annual Report on Form 11-K for the fiscal year ended January 31,
2000.
(b) REPORTS ON FORM 8-K
No such reports were filed by Mitchell Energy & Development Corp. during
the fiscal quarter ended January 31, 2000.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Mitchell Energy & Development Corp.
/s/ George P. Mitchell April 17, 2000
- ---------------------------------------------------
George P. Mitchell, Chairman
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the date indicated.
/s/ George P. Mitchell April 17, 2000
- ---------------------------------------------------
George P. Mitchell, Chairman
and Chief Executive Officer
/s/ Bernard F. Clark April 17, 2000
- ---------------------------------------------------
Bernard F. Clark, Vice Chairman
/s/ W. D. Stevens April 17, 2000
- ---------------------------------------------------
W. D. Stevens, Director, President
and Chief Operating Officer
/s/ Philip S. Smith April 17, 2000
- ---------------------------------------------------
Philip S. Smith, Senior Vice President -
Administration, Chief Financial Officer
and Principal Accounting Officer
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<PAGE> 14
SIGNATURES (continued)
/s/ Robert W. Baldwin April 17, 2000
- ---------------------------------------------------
Robert W. Baldwin, Director
/s/ William D. Eberle April 17, 2000
- ---------------------------------------------------
William D. Eberle, Director
/s/ Shaker A. Khayatt April 17, 2000
- ---------------------------------------------------
Shaker A. Khayatt, Director
/s/ Ben F. Love April 17, 2000
- ---------------------------------------------------
Ben F. Love, Director
/s/ J. Todd Mitchell April 17, 2000
- ---------------------------------------------------
J. Todd Mitchell, Director
/s/ M. Kent Mitchell April 17, 2000
- ---------------------------------------------------
M. Kent Mitchell, Director
-13-
<PAGE> 15
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
EXHIBITS TO FORM 10-K
For the Fiscal Year Ended January 31, 2000
<PAGE> 16
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
3(a) Restated Articles of Incorporation of Mitchell Energy &
Development Corp., as amended through July 2, 1990 are
incorporated as an exhibit to this report by reference to exhibit
3(a) of the annual report on Form 10-K dated January 31, 1992.
The Certificate of Amendment dated June 24, 1992 is incorporated
as an exhibit to this report by reference to exhibit 3 of the
quarterly report on Form 10-Q for the quarter ended July 31,
1992.
3(b) The Bylaws of Mitchell Energy & Development Corp are incorporated
as an exhibit to this report by reference to exhibit 3(b) of the
annual report on Form 10-K dated January 31, 1996.
4(a) The senior indenture dated August 1, 1991 by and between Mitchell
Energy & Development Corp., as Issuer, and First City, Texas -
Houston, National Association (succeeded by Chase Bank of Texas,
N.A.), as Trustee, is incorporated as an exhibit to this report
by reference to exhibit 4(b) of File No. 33-42340.
4(b) The senior and subordinated indentures dated January 1, 1993 by
and between Mitchell Energy & Development Corp., as Issuer, and
NationsBank of Texas, National Association, as Trustee, is
incorporated as an exhibit to this report by reference to exhibit
4(b) of File No. 33-61070. The first supplement to the senior
indenture dated January 15, 1994 is incorporated as an exhibit to
this report by reference to exhibit 4(a) of the current report on
Form 8-K dated January 18, 1994.
4(c) The revolving credit agreement dated as of July 28, 1998 among
Mitchell Energy & Development Corp., the several banks which are
parties thereto and The Chase Manhattan Bank, as administrative
agent for the banks, is incorporated as an exhibit to this report
by reference to exhibit 4 of the quarterly report on Form 10-Q
for the quarter ended July 31, 1998. The first amendment to this
agreement dated March 15, 1999 is incorporated as an exhibit to
this report by reference to exhibit 4(c) of the annual report on
Form 10-K dated January 31, 1999.
10(a) 1989 Stock Option Plan is incorporated as an exhibit to this
report by reference to exhibit 10(d) of the annual report on Form
10-K dated January 31, 1992. The first amendment to such Plan is
incorporated as an exhibit to this report by reference to exhibit
10(c) of the annual report on Form 10-K dated January 31, 1993.
10(b) 1995 Stock Option Plan is incorporated as an exhibit to this
report by reference to File No. 333-06981.
10(c) 1997 Bonus Unit Plan is incorporated as an exhibit to this report
by reference to exhibit 10(e) of the annual report on Form 10-K
dated January 31, 1999. The first amendment to this Plan
effective December 9, 1998 is attached hereto as exhibit 10(c).
10(d) 1999 Stock Option Plan.
10(e) 1998 Mutual Fund Option Plan is incorporated as an exhibit to
this report by reference to exhibit 10 of the quarterly report on
Form 10-Q for the quarter ended July 31, 1998. The first
amendment to this Plan effective January 1, 1999 is incorporated
as an exhibit to this report by reference to exhibit 10(d) of the
annual report on Form 10-K dated January 31, 1999.
</TABLE>
<PAGE> 17
INDEX TO EXHIBITS (Continued)
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
10(f) Mitchell Energy & Development Corp. Restoration Benefit Plan
effective January 1, 1992 is incorporated as an exhibit to this
report by reference to exhibit 10(f) of the annual report on Form
10-K dated January 31, 1994. The first amendment to this Plan
effective July 1, 1998 is incorporated as an exhibit to this
report by reference to exhibit 10(e) of the annual report on Form
10-K dated January 31, 1999.
10(g) Mitchell Energy & Development Corp. Excess Benefit Plan (formerly
the Supplemental Retirement Plan) amended and restated effective
as of January 1, 1992 is incorporated as an exhibit to this
report by reference to exhibit 10(g) of the annual report on Form
10-K dated January 31, 1994. The first amendment to this Plan
effective July 1, 1998 is incorporated as an exhibit to this
report by reference to exhibit 10(f) of the annual report on Form
10-K dated January 31, 1999.
10(h) Executive Excess Benefit Plan effective July 1, 1998 is
incorporated as an exhibit to this report by reference to exhibit
10(g) of the annual report on Form 10-K dated January 31, 1999.
10(i) Deferred compensation/supplementary life insurance arrangement
between the Registrant and certain of its executive officers is
incorporated as an exhibit to this report by reference to exhibit
10(h) of the annual report on Form 10-K dated January 31, 1992
10(j) The Supplemental Benefit Agreement dated August 17, 1990 between
the Registrant and George P. Mitchell is incorporated as an
exhibit to this report by reference to exhibit 10(h) of the
Annual Report on Form 10-K dated January 31, 1997.
10(k) Employment agreement between the Registrant and W. D. Stevens
dated January 3, 1994 is incorporated as an exhibit to this
report by reference to exhibit 10(j) of the annual report on Form
10-K dated January 31, 1994.
10(l) Severance compensation agreement between the Registrant and
Thomas P. Battle is incorporated as an exhibit to this report by
reference to exhibit 10(k) of the annual report on Form 10-K
dated January 31, 1999.
10(m) Severance compensation agreement between the Registrant and
George P. Mitchell is incorporated as an exhibit to this report
by reference to exhibit 10(l) of the annual report on Form 10-K
dated January 31, 1999.
10(n) Severance compensation agreement between the Registrant and W. D.
Stevens is incorporated as an exhibit to this report by reference
to exhibit 10(m) of the annual report on Form 10-K dated January
31, 1999.
10(o) Severance compensation agreement between the Registrant and
Philip S. Smith is incorporated as an exhibit to this report by
reference to exhibit 10(n) of the annual report on Form 10-K
dated January 31, 1999.
10(p) Severance compensation agreement between the Registrant and Allen
J. Tarbutton, Jr. is incorporated as an exhibit to this report
by reference to exhibit 10(o) of the annual report on Form 10-K
dated January 31, 1999.
</TABLE>
<PAGE> 18
INDEX TO EXHIBITS (Continued)
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
10(q) A written description (in lieu of a formal document) describing
the Registrant's commitment to contribute to the life insurance
program of George P. Mitchell is incorporated as an exhibit to
this report by reference to exhibit 10(m) of the annual report on
Form 10-K dated January 31, 1996.
12 Computation of Ratio of Earnings to Fixed Charges
13 Annual Report to Stockholders for the fiscal year ended January
31, 2000
21 List of Subsidiaries as of January 31, 2000
23 Consent of Independent Public Accountants
27 Financial Data Schedule
99 Mitchell Energy & Development Corp. Thrift and Savings Plan -
Annual Report on Form 11-K for the fiscal year ended January 31,
2000
</TABLE>
<PAGE> 1
EXHIBIT 10(d)
MITCHELL ENERGY & DEVELOPMENT CORP.
1999 STOCK OPTION PLAN
I. PURPOSE OF THE PLAN
The MITCHELL ENERGY & DEVELOPMENT CORP. 1999 STOCK OPTION PLAN (the "Plan")
is intended to provide a means whereby certain employees of MITCHELL ENERGY &
DEVELOPMENT CORP., a Texas corporation (the "Company"), and its subsidiaries may
develop a sense of proprietorship and personal involvement in the development
and financial success of the Company, and to encourage them to remain with and
devote their best efforts to the business of the Company, thereby advancing the
interests of the Company and its shareholders. Accordingly, the Company may
grant to certain employees ("Optionees") the option ("Option") to purchase
shares of Class B Common Stock, par value $0.10, of the Company ("Stock"), as
hereinafter set forth. Options granted under the Plan may be either incentive
stock options, within the meaning of section 422(b) of the Internal Revenue Code
of 1986, as amended (the "Code"), ("Incentive Stock Options") or options which
do not constitute Incentive Stock Options ("Non-Qualified Stock Options").
II. ADMINISTRATION
The Plan shall be administered by a committee (the "Committee") of, and
appointed by, the Board of Directors of the Company (the "Board"), and the
Committee shall be (a) comprised solely of two or more outside directors (within
the meaning of section 162(m) of the Code and applicable interpretive authority
thereunder), and (b) constituted so as to permit the Plan to comply with Rule
16b-3 ("Rule 16b-3"), promulgated under the Securities Exchange Act of 1934, as
amended (the "1934 Act"). The Committee shall have sole authority to select the
Optionees from among those individuals eligible hereunder and to establish the
number of shares which may be issued under each Option; provided, however, that,
notwithstanding any provision in the Plan to the contrary, the maximum number of
shares that may be subject to Options granted under the Plan to an individual
Optionee during any calendar year may not exceed 250,000 (subject to adjustment
in the same manner as provided in Paragraph VIII hereof with respect to shares
of Stock subject to Options then outstanding). The limitation set forth in the
preceding sentence shall be applied in a manner which will permit compensation
generated under the Plan to constitute "performance-based" compensation for
purposes of section 162(m) of the Code, including, without limitation, counting
against such maximum number of shares, to the extent required under section
162(m) of the Code and applicable interpretive authority thereunder, any shares
subject to Options that are cancelled or repriced. In selecting the Optionees
from among individuals eligible hereunder and in establishing the number of
shares that may be issued under each Option, the Committee may take into account
the nature of the services rendered by such individuals, their present and
potential contributions to the Company's success and such other factors as the
Committee in its discretion shall deem relevant. The Committee is authorized to
interpret the Plan and may from time to time adopt such rules and regulations,
consistent with the provisions of the Plan, as it may deem advisable to carry
out the Plan. All decisions made by the Committee in selecting the Optionees, in
establishing the number of shares which may be issued under each Option and in
construing the provisions of the Plan shall be final.
III. OPTION AGREEMENTS
(a) Each Option shall be evidenced by a written agreement between the
Company and the Optionee ("Option Agreement") which shall contain such
terms and conditions as may be approved by the Committee. The terms and
conditions of the respective Option Agreements need not be identical.
Specifically, an Option Agreement may provide for the surrender of the
right to purchase shares under the Option in return for a payment in cash
or shares of Stock or a combination of cash and shares of Stock equal in
value to the excess of the fair market value of the shares with respect to
which the right to purchase is surrendered over the option price therefor
("Stock Appreciation Rights"), on such terms and
<PAGE> 2
conditions as the Committee in its sole discretion may prescribe; provided,
that, except as provided in Subparagraph VIII(c) hereof, the Committee may
retain final authority (i) to determine whether an Optionee shall be
permitted, or (ii) to approve an election by an Optionee, to receive cash
in full or partial settlement of Stock Appreciation Rights. Further, an
Option Agreement may authorize and provide for an Optionee to exercise the
Option and direct immediate market sale of any treasury Stock thereby
acquired pursuant to an extension of credit by the Company to such Optionee
for the aggregate exercise price and upon such other terms and conditions
as the Committee may determine. Moreover, an Option Agreement may provide
for the payment of the option price, in whole or in part, by the delivery
of a number of shares of Stock (plus cash if necessary) having a fair
market value equal to such option price.
(b) For all purposes under the Plan, the fair market value of a share
of Stock on a particular date shall be equal to the closing price of the
Stock reported on the New York Stock Exchange Composite Tape on that date;
or, if no prices are reported on that date, on the last preceding date on
which such prices of the Stock are so reported. If the Stock is traded over
the counter at the time a determination of its fair market value is
required to be made hereunder, its fair market value shall be deemed to be
equal to the average between the reported high and low or closing bid and
asked prices of Stock on the most recent date on which Stock was publicly
traded. In the event Stock is not publicly traded at the time a
determination of its value is required to be made hereunder, the
determination of its fair market value shall be made by the Committee in
such manner as it deems appropriate.
(c) Each Option and all rights granted thereunder shall not be
transferable other than by will or the laws of descent and distribution and
shall be exercisable during the Optionee's lifetime only by the Optionee or
the Optionee's guardian or legal representative.
IV. ELIGIBILITY OF OPTIONEE
Options may be granted only to individuals who are employees on a full-time
basis (including officers and directors who are also employees) of the Company
or any parent or subsidiary corporation (as defined in section 424 of the Code)
of the Company at the time the Option is granted. Options may be granted to the
same individual on more than one occasion. No Incentive Stock Option shall be
granted to an individual if, at the time the Option is granted, such individual
owns stock possessing more than 10% of the total combined voting power of all
classes of stock of the Company or of its parent or subsidiary corporation,
within the meaning of section 422(b)(6) of the Code, unless (i) at the time such
Option is granted the option price is at least 110% of the fair market value of
the Stock subject to the Option and (ii) such Option by its terms is not
exercisable after the expiration of five years from the date of grant. To the
extent that the aggregate fair market value (determined at the time the
respective Incentive Stock Option is granted) of stock with respect to which
Incentive Stock Options are exercisable for the first time by an individual
during any calendar year under all incentive stock option plans of the Company
and its parent and subsidiary corporations exceeds $100,000, such excess
Incentive Stock Options shall be treated as Non-Qualified Stock Options. The
Committee shall determine, in accordance with applicable provisions of the Code,
Treasury Regulations and other administrative pronouncements, which of an
Optionee's Incentive Stock Options will not constitute Incentive Stock Options
because of such limitation and shall notify the Optionee of such determination
as soon as practicable after such determination.
V. SHARES SUBJECT TO THE PLAN
The aggregate number of shares which may be issued under Options granted
under the Plan shall not exceed 1,750,000 shares of Stock. Such shares may
consist of authorized but unissued shares of Stock or previously issued shares
of Stock reacquired by the Company. Any of such shares which remain unissued and
which are not subject to outstanding Options at the termination of the Plan
shall cease to be subject to the Plan, but, until termination of the Plan, the
Company shall at all times make available a sufficient number of shares to meet
the requirements of the Plan. Should any Option hereunder expire or terminate
prior to its exercise in full, the shares theretofore subject to such Option may
again be subject to an Option granted under the Plan to the extent permitted
under Rule 16b-3. The aggregate number of shares which may be issued
<PAGE> 3
under the Plan shall be subject to adjustment in the same manner as provided in
Paragraph VIII hereof with respect to shares of Stock subject to Options then
outstanding. Exercise of an Option in any manner, including an exercise
involving a Stock Appreciation Right, shall result in a decrease in the number
of shares of Stock which may thereafter be available, both for purposes of the
Plan and for sale to any one individual, by the number of shares as to which the
Option is exercised. Separate stock certificates shall be issued by the Company
for those shares acquired pursuant to the exercise of an Incentive Stock Option
and for those shares acquired pursuant to the exercise of any Option which does
not constitute an Incentive Stock Option.
VI. OPTION PRICE
The purchase price of Stock issued under each Option shall be determined by
the Committee, but such purchase price shall not be less than the fair market
value of Stock subject to the Option on the date the Option is granted.
VII. TERM OF PLAN
The Plan shall be effective upon the date of its adoption by the Board,
provided the Plan is approved by the shareholders of the Company within twelve
months thereafter. Notwithstanding any provision in this Plan or in any Option
Agreement, no Option shall be exercisable prior to such shareholder approval.
Except with respect to Options then outstanding, if not sooner terminated under
the provisions of Paragraph IX, the Plan shall terminate upon and no further
Options shall be granted after the expiration of ten years from the date of its
adoption by the Board.
VIII. RECAPITALIZATION OR REORGANIZATION
(a) The existence of the Plan and the Options granted hereunder shall
not affect in any way the right or power of the Board or the shareholders
of the Company to make or authorize any adjustment, recapitalization,
reorganization or other change in the Company's capital structure or its
business, any merger or consolidation of the Company, any issue of debt or
equity securities, the dissolution or liquidation of the Company or any
sale, lease, exchange or other disposition of all or any part of its assets
or business or any other corporate act or proceeding.
(b) The shares with respect to which Options may be granted are shares
of Stock as presently constituted, but if, and whenever, prior to the
expiration of an Option theretofore granted, the Company shall effect a
subdivision or consolidation of shares of Stock or the payment of a stock
dividend on Stock without receipt of consideration by the Company, the
number of shares of Stock with respect to which such Option may thereafter
be exercised (i) in the event of an increase in the number of outstanding
shares shall be proportionately increased, and the purchase price per share
shall be proportionately reduced, and (ii) in the event of a reduction in
the number of outstanding shares shall be proportionately reduced, and the
purchase price per share shall be proportionately increased. If prior to
the expiration of an Option theretofore granted, the Company shall effect a
spinoff of a subsidiary by issuance of shares of stock in the subsidiary to
shareholders of the Company or effect any other transaction which
essentially accomplishes the same result, the Committee shall adjust the
exercise price of an Option to reflect any decrease in the value of the
Stock resulting from such spinoff or transaction.
(c) If the Company recapitalizes, reclassifies its capital stock, or
otherwise changes its capital structure (a "recapitalization"), the number
and class of shares of Stock covered by an Option theretofore granted shall
be adjusted so that such Option shall thereafter cover the number and class
of shares of stock and securities to which the Optionee would have been
entitled pursuant to the terms of the recapitalization if, immediately
prior to the recapitalization, the Optionee had been the holder of record
of the number of shares of Stock then covered by such Option. If (i) the
Company shall not be the surviving entity in any merger, consolidation or
other reorganization (or survives only as a subsidiary of an entity other
than a previously wholly-owned subsidiary of the Company), (ii) the Company
sells, leases or exchanges all or substantially all of its assets to any
other person or entity (other than a wholly-owned subsidiary of the
Company), (iii) the Company is to be dissolved and liquidated, (iv) any
person or
<PAGE> 4
entity, including a "group" as contemplated by Section 13(d)(3) of the 1934
Act, acquires or gains ownership or control (including, without limitation,
power to vote) of more than 50% of the outstanding shares of the Company's
voting stock (based upon voting power), or (v) as a result of or in
connection with a contested election of directors, the persons who were
directors of the Company before such election shall cease to constitute a
majority of the Board (each such event is referred to herein as a
"Corporate Change"), provided, however, in the event of the death of George
P. Mitchell, the majority shareholder of the Company and the Chief
Executive Officer of the Company, the transfer of George P. Mitchell's
shares of the Company's stock upon his death shall not result in or
constitute a Corporate Change, no later than (a) ten days after the
approval by the shareholders of the Company of such merger, consolidation,
reorganization, sale, lease or exchange of assets or dissolution or such
election of directors or (b) thirty days after a change of control of the
type described in clause (iv), the Committee, acting in its sole discretion
without the consent or approval of any Optionee, shall act to effect one or
more of the following alternatives, which may vary among individual
Optionees and which may vary among Options held by any individual Optionee:
(1) accelerate the time at which Options then outstanding may be exercised
so that such Options may be exercised in full for a limited period of time
on or before a specified date (before or after such Corporate Change) fixed
by the Committee, after which specified date all unexercised Options and
all rights of Optionees thereunder shall terminate, (2) require the
mandatory surrender to the Company by selected Optionees of some or all of
the outstanding Options held by such Optionees (irrespective of whether
such Options are then exercisable under the provisions of the Plan) as of a
date, before or after such Corporate Change, specified by the Committee, in
which event the Committee shall thereupon cancel such Options and the
Company shall pay to each Optionee an amount of cash per share equal to the
excess, if any, of the amount calculated in Subparagraph (d) below (the
"Change of Control Value") of the shares subject to such Option over the
exercise price(s) under such Options for such shares, (3) make such
adjustments to Options then outstanding as the Committee deems appropriate
to reflect such Corporate Change (provided, however, that the Committee may
determine in its sole discretion that no adjustment is necessary to Options
then outstanding) or (4) provide that the number and class of shares of
Stock covered by an Option theretofore granted shall be adjusted so that
such Option shall thereafter cover the number and class of shares of stock
or other securities or property (including, without limitation, cash) to
which the Optionee would have been entitled pursuant to the terms of the
agreement of merger, consolidation or sale of assets and dissolution if,
immediately prior to such merger, consolidation or sale of assets and
dissolution, the Optionee had been the holder of record of the number of
shares of Stock then covered by such Option.
(d) For the purposes of clause (2) in Subparagraph (c) above, the
"Change of Control Value" shall equal the amount determined in clause (i),
(ii) or (iii), whichever is applicable, as follows: (i) the price per share
offered to shareholders of the Company in any such merger, consolidation,
reorganization, sale of assets or dissolution transaction, (ii) the price
per share offered to shareholders of the Company in any tender offer or
exchange offer whereby a Corporate Change takes place, or (iii) if such
Corporate Change occurs other than pursuant to a tender or exchange offer,
the fair market value per share of the shares into which such Options being
surrendered are exercisable, as determined by the Committee as of the date
determined by the Committee to be the date of cancellation and surrender of
such Options. In the event that the consideration offered to shareholders
of the Company in any transaction described in this Subparagraph (d) or
Subparagraph (c) above consists of anything other than cash, the Committee
shall determine the fair cash equivalent of the portion of the
consideration offered which is other than cash.
(e) Any adjustment provided for in Subparagraphs (b) or (c) above
shall be subject to any required shareholder action.
(f) Except as hereinbefore expressly provided, the issuance by the
Company of shares of stock of any class or securities convertible into
shares of stock of any class, for cash, property, labor or services, upon
direct sale, upon the exercise of rights or warrants to subscribe therefor,
or upon conversion of shares or obligations of the Company convertible into
such shares or other securities, and in any case whether or not for fair
value, shall not affect, and no adjustment by reason thereof shall be made
with
<PAGE> 5
respect to, the number of shares of Stock subject to Options theretofore
granted or the purchase price per share.
IX. AMENDMENT OR TERMINATION OF THE PLAN
The Board in its discretion may terminate the Plan at any time with respect
to any shares for which Options have not theretofore been granted. The Board
shall have the right to alter or amend the Plan or any part thereof from time to
time; provided, that no change in any Option theretofore granted may be made
which would impair the rights of the Optionee without the consent of such
Optionee; and provided, further, that (i) the Board may not make any alteration
or amendment which would decrease any authority granted to the Committee
hereunder in contravention of Rule 16b-3 and (ii) the Board may not make any
alteration or amendment which would materially increase the benefits accruing to
participants under the Plan, increase the aggregate number of shares which may
be issued pursuant to the provisions of the Plan, change the class of
individuals eligible to receive Options under the Plan or extend the term of the
Plan, without the approval of the shareholders of the Company.
X. SECURITIES LAWS
(a) The Company shall not be obligated to issue any Stock pursuant to
any Option granted under the Plan at any time when the offering of the
shares covered by such Option have not been registered under the Securities
Act of 1933 and such other state and federal laws, rules or regulations as
the Company or the Committee deems applicable and, in the opinion of legal
counsel for the Company, there is no exemption from the registration
requirements of such laws, rules or regulations available for the offering
and sale of such shares.
(b) It is intended that the Plan and any grant of an Option made to a
person subject to Section 16 of the 1934 Act meet all of the requirements
of Rule 16b-3. If any provision of the Plan or any such Option would
disqualify the Plan or such Option under, or would otherwise not comply
with, Rule 16b-3, such provision or Option shall be construed or deemed
amended to conform to Rule 16b-3.
<PAGE> 1
Exhibit 12
Mitchell Energy & Development Corp. and Subsidiaries
COMPUTATION OF RATIO OF EARNINGS TO FIXED
CHARGES FOR THE YEARS ENDED JANUARY 31, 1996, 1997,
1998, 1999 AND 2000
(dollar amounts in thousands)
<TABLE>
<CAPTION>
Fiscal Year Ended January 31
-------------------------------------------------------------
1996 1997 1998 1999 2000
-------- -------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
EARNINGS
Pretax (loss) earnings from
continuing operations ......................... $156,132 $133,757 $50,735 $(84,593) $146,565
Add (Deduct):
Previously capitalized interest
charged against pretax earnings............. 1,281 231 232 323 252
Fixed charges (see below)...................... 68,234 61,664 46,944 37,103 37,803
Reverse effect of inclusion of interest
capitalized in fixed charges above.......... (1,333) (835) (1,283) (2,569) (1,980)
Undistributed earnings of
less-than-50%-owned persons................. (4,321) (2,024) (13,900) (6,215) (7,255)
-------- -------- ------- -------- --------
$219,993 $182,793 $82,728 $(55,951) $175,385
======== ======== ======= ======== ========
FIXED CHARGES
Interest expense incurred
Consolidated (a)............................... $ 60,759 $ 56,782 $42,531 $ 35,070 34,036
50%-owned persons.............................. 4,008 2,715 2,246 - -
-------- -------- ------- -------- --------
64,767 59,497 44,777 35,070 34,036
Portion of rental expense
representing interest (b)...................... 3,467 2,167 2,167 2,033 3,767
-------- -------- ------- -------- --------
$ 68,234 $ 61,664 $46,944 $ 37,103 37,803
======== ======== ======= ======== ========
RATIO OF EARNINGS TO FIXED CHARGES................ 3.22 2.96 1.76 * 4.64
======== ======== ======= ======== ========
</TABLE>
* Additional earnings of $93,054 would have been necessary to bring ratio to
1.0x.
- ---------------
(a) At January 31, 2000, the Company had outstanding guaranties of the
indebtedness of third parties and less-than-50%-owned equity investees
totaling approximately $15,419,000 under which it has not been, nor is it
expected that it will be, required to perform. Fixed charges related to
such outstanding borrowings, estimated to total $800,000 for the fiscal
year ended January 31, 2000, have been excluded from the reported fixed
charges.
(b) Represents one-third of rental expense under operating lease agreements.
<PAGE> 1
EXHIBIT 13
MITCHELL ENERGY & DEVELOPMENT CORP.
BEST SHAPE EVER!
FISCAL 2000 ANNUAL REPORT / YEAR ENDED JANUARY 31, 2000
<PAGE> 2
THE COMPANY
Mitchell Energy & Development Corp., one of the nation's largest independent
producers of natural gas and natural gas liquids, traces its origins to a small
wildcatting firm formed in 1946.
The Company's two primary businesses are (i) exploration, development and
production of natural gas and oil, and (ii) gathering, processing and marketing
of natural gas and natural gas liquids. In fiscal 2000, the Company produced 94
billion cubic feet of natural gas and 18.6 million barrels of liquid
hydrocarbons (natural gas liquids, oil and condensate). At year end, it owned or
had interests in 3,368 wells and 1.1 million acres of leases. In March 2000, the
Company exchanged its non-operated Oklahoma assets for the remaining interests
in operated assets in central Texas. After this exchange, the Company owned and
operated six gas processing plants and 8,800 miles of gas gathering pipelines.
At January 31, 2000, the Company had approximately 875 full-time employees.
FORWARD-LOOKING INFORMATION
All statements included in this annual report, other than statements of
historical fact, are forward-looking statements. These include, but are not
limited to, certain statements made in the Letter to Shareholders; strategies,
goals and expectations set forth in the Exploration and Production and Gas
Services sections; and discussions of liquidity and capital resources and other
matters included in Management's Discussion and Analysis of Financial Position
and Results of Operations. Although the Company believes that its expectations
are based on reasonable assumptions, it can give no assurances that its goals
will be achieved. Important factors that could cause actual results to differ
materially from those in the forward-looking statements include the timing and
extent of changes in commodity prices for natural gas, NGLs and crude oil; the
attainment of forecasted operating levels and reserve replacement and unexpected
changes in competitive and economic conditions, government regulations,
technology and other factors.
CONTENTS
<TABLE>
<S> <C>
Letter to Shareholders . . . . . . . . . . . . . . . . . . . . 2
Exploration and Production . . . . . . . . . . . . . . . . . . 4
Gas Services . . . . . . . . . . . . . . . . . . . . . . . . . 10
Management's Discussion and Analysis of
Financial Position and Results of Operations. . . . . . . . 15
Consolidated Financial Statements. . . . . . . . . . . . . . . 24
Notes to Consolidated Financial Statements . . . . . . . . . . 28
Report of Independent Public Accountants . . . . . . . . . . . 41
Supplemental Oil and Gas Information . . . . . . . . . . . . . 42
Historical Summary . . . . . . . . . . . . . . . . . . . . . . 45
Board of Directors . . . . . . . . . . . . . . . . . . . . . . 47
Principal Officers . . . . . . . . . . . . . . . . . . . . . . 48
Corporate Information . . . . . . . . . . . . . . Inside Back Cover
</TABLE>
DEFINITIONS
MMBtu million British thermal units
Mcf thousand cubic feet (measure of gas volume)
MMcf million cubic feet
Bcf billion cubic feet
Tcf trillion cubic feet
Bbl barrel (measure of liquid hydrocarbon volume)
MMBbls million barrels
NGL or NGLs natural gas liquids (ethane, propane, butanes and natural gasoline)
Note: Natural gas volumes in this report are stated at the legal pressure
base of the area in which the reserves are located and at 60 degrees
Fahrenheit. Pipeline throughput volumes are based on an average energy
content of 1,000 Btu per cubic foot. Where applicable, NGL volume,
price and reserve information and pipeline throughput include equity
partnership interests.
<PAGE> 3
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
FINANCIAL HIGHLIGHTS
================================================================================
Year Ended January 31 (in thousands except per-share data)
<TABLE>
<CAPTION>
2000 1999
------------ ------------
<S> <C> <C>
EARNINGS (LOSS) FROM CONTINUING OPERATIONS ............ $ 97,236 $ (52,962)
============ ============
NET EARNINGS (LOSS) ................................... $ 97,236 $ (49,712)
============ ============
BASIC/DILUTED EARNINGS (LOSS) PER SHARE
From continuing operations
Class A ............................................ $ 1.95 $ (1.11)
Class B ............................................ 2.00 (1.05)
Net earnings
Class A ............................................ 1.95 (1.04)
Class B ............................................ 2.00 (.99)
REVENUES .............................................. $ 934,013 $ 701,390
============ ============
SEGMENT OPERATING EARNINGS (LOSS)
Exploration and production ............................ $ 81,224 $ 9,234
Natural gas processing ................................ 55,860 (2,083)
Natural gas gathering and marketing ................... 27,029 23,483
Other gas services .................................... 10,577 13,949
------------ ------------
174,690 44,583
Unusual items
Water well litigation provision reversals .......... 15,200 4,000
Gain from sale of Hell's Hole area properties ...... 11,527 --
Proved property impairments ........................ -- (42,250)
Personnel reduction program costs .................. -- (15,652)
Gas services asset write-downs ..................... -- (7,560)
------------ ------------
$ 201,417 $ (16,879)
============ ============
CAPITAL AND EXPLORATORY EXPENDITURES* ................. $ 171,723 $ 289,402
============ ============
LONG-TERM DEBT (INCLUDING CURRENT MATURITIES) ......... $ 369,267 $ 462,467
============ ============
STOCKHOLDERS' EQUITY .................................. $ 398,542 $ 324,774
============ ============
OPERATING STATISTICS (AVERAGE DAILY AMOUNTS)
Natural gas sales (Mcf) ............................... 246,100 247,600
Crude oil and condensate sales (Bbls) ................. 5,900 6,800
Natural gas liquids production (Bbls) ................. 45,100 41,100
Pipeline throughput (Mcf) ............................. 567,000 554,000
</TABLE>
- --------------------
* Includes asset acquisitions of $23,874 and $89,266.
ESTIMATED PROVED RESERVES
YEAR ENDED JANUARY 31
Natural Gas (Bcf)
<TABLE>
<S> <C>
'00 1,014
'99 867
'98 778
'97 701
'96 697
</TABLE>
Liquid Hydrocarbons (MMBbls)
[ ] Natural Gas Liquids
[ ] Oil & Condensate
<TABLE>
<S> <C>
'00 192
'99 155
'98 162
'97 140
'96 139
</TABLE>
1
<PAGE> 4
LETTER TO SHAREHOLDERS
================================================================================
NEAR RECORD EARNINGS OF $97 MILLION PROVIDED AN INDUSTRY LEADING 27 PERCENT
RETURN ON STOCKHOLDERS' EQUITY.
- --------------------------------------------------------------------------------
By virtually every measure, fiscal 2000 was a banner year for Mitchell Energy &
Development Corp. An increased focus on core operations, the application of new
completion technology, and greater operating efficiency have put your Company in
its best shape ever, setting the stage for even stronger earnings. The rapid
rebound in oil and gas prices experienced last year only amplified these
improvements.
We entered the year with weak energy prices and had just completed a
program of personnel and spending reductions to ensure financial balance. By
mid-year, strengthening prices justified a stepped-up level of capital spending
which by year end, led to higher natural gas production, NGL processing volumes
and pipeline throughput.
As a result, annual net earnings rebounded to a near record $97 million,
with a return on stockholders' equity of 27 percent. This return ranked among
the highest in the industry and was more than twice the five-year average.
Higher operating cash flows also improved the Company's financial strength.
Long-term debt was reduced by $93 million and now stands at less than 50 percent
of total capitalization.
The combination of stronger prices for all of our products - natural gas,
NGLs and oil - and internal improvements have put your Company in position to
add shareholder value as never before. We have a backlog of over 1,200
undeveloped locations and have moved aggressively to grow the production from
our long-lived gas fields, particularly the Barnett shale. Even after last
year's breakthrough in the application of light sand fracture technology in the
Barnett, studies indicate that only a small portion of the gas in place is being
recovered. The full potential of the Barnett will be better defined as we
complete ongoing pilot tests evaluating the viability of closer well spacing,
which could add at least another 1,000 wells to the undrilled inventory.
Perhaps the best indication of the Company's potential has been our
consecutive 12-year history of adding more proven natural gas reserves than were
produced each year, while still growing the significant backlog of undrilled
prospects. At year end, we reached a record reserve base of 1.1 Tcf of natural
gas equivalents and are confident of our ability to add substantially to that
amount with work now underway to determine the ultimate reserve potential of the
Barnett.
Growth of the gas services business was led by the expansion and upgrading
of North Texas facilities to accommodate accelerated Barnett drilling. In
addition, two transactions were completed to further concentrate and increase
control over our core gathering and processing facilities. These included the
purchase of the remaining 50-percent interest in the Jameson plant and a swap of
non-operated interests in Oklahoma pipeline and processing assets for the
outstanding interests in similar assets that we operate in central Texas.
The outcome is full ownership and operation of all of our major midstream
facilities. The Company currently
2
<PAGE> 5
================================================================================
produces more NGLs with just six processing plants than it did when it had
interests in 31 plants five years ago. NGL reserves have now reached a record
178 million barrels and are expected to continue growing in the years to come
due to the strategic location of our midstream assets.
Although your Company's stock price nearly doubled in fiscal 2000, we were
disappointed that its valuation lagged behind many of our peers - as measured by
such common yardsticks as P/E ratios and cash flow multiples. For that reason,
we initiated a review of strategic alternatives that contemplated, among various
options, the possible sale or merger of the Company. In the final analysis, our
Board of Directors concluded that shareholder interests would best be met as a
stand-alone company with an increased focus on its core upstream operations.
The Board also approved two steps aimed at improving stock price
performance. With your approval at the June shareholders meeting, the Class A
and Class B shares will be combined into a single voting class of stock to
increase liquidity and eliminate confusion in the marketplace over the dual
class structure. Furthermore, the Board authorized a balanced program of debt
reduction and the repurchasing of as many as 2.5 million shares of stock. This
program is to be funded by expected excess operating cash flows, even after a 50
percent increase in capital spending. These proposals have been well received by
major institutional shareholders and financial analysts.
Last year's progress in all dimensions of the Company enables us to enter
fiscal 2001 in the best shape ever - both operationally and financially.
Supported by the strong improvement in energy price fundamentals, we expect to
increase production of both natural gas and NGLs by 15 percent this year and
maintain a higher level of growth than in the past. Our focus - and commitment
to you, our shareholders - is to not only add to the Company's fundamental
value, but to its share price as well.
[PICTURE OF GEORGE P. MITCHELL] [PICTURE OF W. D. STEVENS]
/s/ GEORGE P. MITCHELL /s/ W. D. STEVENS
George P. Mitchell W. D. Stevens
Chairman and President and
Chief Executive Officer Chief Operating Officer
April 17, 2000
3
<PAGE> 6
EXPLORATION AND PRODUCTION
================================================================================
FINANCIAL HIGHLIGHTS
Year Ended January 31 (in thousands)
<TABLE>
<CAPTION>
2000 1999
------------ ------------
<S> <C> <C>
REVENUES .............................................. $ 277,344 $ 221,634
------------ ------------
SEGMENT OPERATING EARNINGS (LOSS)
Operations ............................................ $ 81,224 $ 9,234
Unusual items
Water well litigation provision reversals ........ 15,200 4,000
Gain from sale of Hell's Hole area properties .... 11,527 --
Proved property impairments ...................... -- (42,250)
Personnel reduction program costs ................ -- (8,524)
------------ ------------
$ 107,951 $ (37,540)
============ ============
CAPITAL AND EXPLORATORY EXPENDITURES,
excluding acquisitions ........................... $ 124,911 $ 169,046
============ ============
</TABLE>
The expansion of the North Texas Barnett shale development program and a
complete turnaround of oil and natural gas prices resulted in one of the most
profitable years in the history of Mitchell's exploration and production
operations and provides a solid platform for future volume growth. Higher prices
combined with reduced exploration and personnel expenses caused segment
operating earnings before unusual items to rise eight-fold to $81.2 million from
the $9.2 million earned in the prior year.
Given the severely depressed levels of energy prices a year ago, the
rebound in prices that started in early 1999 and continued into 2000 was not
unexpected. However, the speed at which prices raced from historic lows to near
record highs came as somewhat of a surprise. The corresponding rapid rise in
earnings reflects the Company's leverage to natural gas and NGL prices, and the
actions already taken to ensure profitability even during periods of low prices,
allowed the benefit of higher prices to go straight to the bottom line.
Continued successful application of recently developed "light sand
fracture" technology in the Barnett shale led to the largest single increase of
natural gas reserves in the history of the Company. Light sand fracture
technology replaced the heavy gels previously used to prop open subsurface
fractures in the formation. This not only improved the ability of the gas to
flow to the well bore, but also significantly reduced well costs.
As a result of this new completion technology, the Company increased net
oil and gas reserves in fiscal 2000 by 240 Bcf equivalent and replaced 224
percent of the equivalent gas produced. This pushed total year-end proved
reserves up to a record 1.1 Tcf of natural gas equivalents and marked the
twelfth consecutive year the Company more than replaced its production of
natural gas reserves.
This record level of reserve additions drove finding costs in fiscal 2000
down to 39 cents per Mcf equivalent from $1.15 in the prior year. Since
expenditures for seismic and exploratory costs usually do not coincide with the
ultimate recording of reserves associated with a
NATURAL GAS SALES
YEAR ENDED JANUARY 31
Average Daily Sales (MMcf)
<TABLE>
<S> <C>
'00 246.1
'99 247.6
'98 238.2
'97 228.5
'96 216.2
</TABLE>
Average Price (per Mcf)
<TABLE>
<S> <C>
'00 $2.50
'99 $2.11
'98 $2.47
'97 $2.64
'96 $2.16
</TABLE>
Accelerated drilling is expected to increase natural gas production 10 percent
annually. Two rig operators break pipe on a drilling rig in Wise County.
photo right -->
4
<PAGE> 7
An accelerated drilling program is expected to increase natural gas sales by 15
percent next year.
[PHOTO]
5
<PAGE> 8
drilling program, a five-year average of finding costs is a better benchmark.
For fiscal 1996 through 2000, the Company's finding costs averaged 79 cents per
Mcf equivalent.
OIL AND GAS SALES
Natural gas sales averaged 246.1 MMcf per day in fiscal 2000. This was
essentially flat with sales of the prior year, reflecting the constrained
capital program in the second half of fiscal 1999 and first half of fiscal 2000.
However, with the mid-year increase in the drilling program, natural gas sales
rose to 266.1 MMcf per day by the fourth quarter, a seven-percent increase over
sales in the prior year's fourth quarter.
The growth in gas sales came primarily from accelerated drilling in the
North Texas Barnett shale. Partially offsetting the gains were the sale of the
non-core properties in the Hell's Hole area - with the proceeds being deployed
into higher yielding development projects - and production declines in East
Texas and Gulf Coast areas that were not offset by incremental drilling.
In fiscal 2001, annual sales of natural gas are expected to increase
approximately 15 percent as the Company accelerates the drilling of its
inventory of over 1,200 development well locations.
The shifting balance between worldwide energy production and consumption
drove the dramatic improvement in oil and gas prices. In the United States,
natural gas production capabilities has decreased due to an overall lower level
of reinvestment by the industry. This decrease comes at a time when demand by
gas-fired electric plants is increasing and homeowners continue converting to
environmentally friendly natural gas. Even with this year's warmest winter on
record for North America, natural gas storage inventories dropped to 1 Tcf at
the end of the traditional heating season, indicating that gas supplies will be
tight in the near future as gas storage facilities and consumers compete for
available production. These factors contributed to an 18 percent increase in
Mitchell's fiscal 2000 natural gas sales price that averaged $2.50 per Mcf, and
set a bullish outlook for gas prices going forward.
Oil production decreased as expected to 5,900 barrels per day, as a reduced
level of investment in oil prospects allowed natural decline in older wells to
exceed production from new wells. Average oil realizations shot up to $18.49 per
barrel, a 52 percent increase over last year's $12.18 per barrel.
CAPITAL SPENDING
The capital budget for fiscal 2000 was originally set within expected cash flows
based on the poor outlook for prices at the beginning of the year. Although
capital spending was increased at mid-year in light of strengthening prices,
restricted drilling activity early in the year limited total year expenditures
to $124.9 million. Of the total, $85.1 million was spent to drill or participate
in 111 development and 16 exploratory wells and another $7 million was incurred
to recomplete 47 wells in the Upper Barnett.
Entering fiscal 2001, budgeted capital spending has been raised to $183.1
million, 47 percent more than the prior year. The majority of the increase will
be spent on drilling projects, with approximately 200 wells slated to be drilled
- - nearly 60 percent more than the number drilled last year. Additional funds
have been earmarked for continuation of the Barnett well recompletion program
and extension of the light sand fracture technology to wells located in the
Limestone and Freestone County areas.
At year end, Mitchell had interests in 2,285 producing gas wells and 1,083
oil wells, of which 85 were productive in two or more zones. Excluding interests
held by others, Mitchell's net interests totaled 2,020 gas and 605 oil wells, of
which 73 were productive in two or more zones.
CRUDE OIL AND
CONDENSATE SALES
YEAR ENDED JANUARY 31
Average Daily Sales (Bbls)
<TABLE>
<S> <C>
'00 5,900
'99 6,800
'98 6,200
'97 5,500
'96 5,400
</TABLE>
Average Price (per Bbl)
<TABLE>
<S> <C>
'00 $18.49
'99 $12.18
'98 $18.50
'97 $21.50
'96 $16.91
</TABLE>
6
<PAGE> 9
NORTH TEXAS - BARNETT SHALE
The Company's largest acreage position is in North Texas where 597,000 gross
acres account for approximately 55 percent of the Company's gas equivalent
production. For the past seven years, development has been focused on the
Barnett shale formation which is the source rock for the natural gas and oil
contained in numerous producing horizons in the Ft. Worth Basin. Although the
Barnett is known to have vast quantities of natural gas, its low porosity and
permeability has made it difficult to achieve economic success outside the known
"sweet spot," or core area.
Last year's breakthrough in light sand fracture technology not only
significantly reduced development costs, but "unlocked" the Upper Barnett zone
within the core area and increased the estimated recoverable reserves per well
by 25 percent. The core area of the Barnett shale is separated into two sections
by a layer of impervious rock, and the upper section was previously uneconomical
to develop using higher-cost gel fracs. More importantly though, the improved
technology has converted marginally economic locations to the south and east of
the sweet spot into viable opportunities. These expansion-area prospects will
now generate a very attractive return on investment with natural gas prices of
$2.00, and an outstanding return at $3.00.
Accelerated development of the core and expansion areas of the Barnett
shale will continue in the current year. Plans call for the drilling of 135
wells, versus the 70 that were drilled in fiscal 2000. Six drilling rigs are now
working in the area and the aggressive rework program initiated last year to add
the upper Barnett to approximately 300 existing core area wells continues. At
the current 55-acre well spacing, the Company has an identified undrilled
backlog of over 1,000 wells in the Barnett, each with an estimated reserve
potential ranging from 1.0 to 1.25 Bcf.
Additional studies using state-of-the-art pressure core and gas-in-place
analyses have indicated that only a small portion of the reservoir's gas is
recovered based on current well spacing. Testing is underway in three pilot
areas to determine how 27-acre well spacing coupled with refracturing of
existing wells will improve drainage of the reservoir without negatively
affecting the production of neighboring wells. If successful, this program could
add another 1,000 additional locations to the Barnett undrilled inventory and at
least double the recovery of the gas in place.
EAST TEXAS
The Company's second largest leaseblock of 67,000 acres lies primarily in
Limestone County and includes the North Personville, Oaks and Dew Fields.
Massive hydraulic fracturing technology in the Cotton Valley limestone formation
was first pioneered by the Company in 1978 and has been the primary method of
opening this dense rock to improve drainage of the field. Application of the new
light sand fracture technology in this area, coupled with other recent drilling
improvements, reduced per well development costs in the limestone formation by
30 percent, or roughly $350,000. These improved field economics should enable a
reduced spacing pattern of less than 160 acres per well which could prove the
existence of significant additional reserves.
In the same area, six Bossier sandstone play wells were drilled and
completed in the Dew Field. These Bossier wells are currently producing a total
of 10 MMcf per day of natural gas.
For fiscal 2001, twenty-six wells are planned in this area. Eighteen will
target the Bossier, Cotton Valley and Travis Peak sandstone objectives and
another eight wells are planned for the Cotton Valley limestone.
PRODUCTION REPLACED
YEAR ENDED JANUARY 31
Natural Gas (Equivalent)
<TABLE>
<S> <C>
'00 224%
'99 185%
'98 187%
'97 105%
'96 105%
</TABLE>
[PHOTO]
Light sand fracture technology helped add over 200 Bcf of proved reserves in
North Texas.
7
<PAGE> 10
GULF COAST
In the Pinehurst, Lake Creek and East Lake Creek fields located in Montgomery
County, development of the multi-pay Wilcox section continued last year with the
completion of seven new wells, including one 14,500 foot deep test of the Lower
Wilcox sands. That well encountered four sandstone gas pay zones and is
producing 3.5 MMcf per day of natural gas. A one-mile step-out of this well is
planned for the first quarter of fiscal 2001 and two exploratory tests will be
drilled into the Frio and Yegua sandstone formations. Six additional development
wells will target the Upper and Middle Wilcox and 16 recompletions of existing
wells are also planned.
The Lower Wilcox has long been recognized to contain a large amount of gas,
and a 54-square-mile 3-D seismic survey shot in late 1998 indicated that the
Lower Wilcox pay zones extend over 1,200 acres on leases held in the area. This
year, the Company will experiment with completion techniques that aim to repeat
the success achieved in the Upper Wilcox.
EXPLORATORY ACTIVITIES
Following up the 77-square mile Cottonwood 3-D seismic survey in Ft. Bend
County, Texas, two exploratory dry holes with a net 61 percent working interest
were drilled in fiscal 2000 that targeted seismic anomalies. Drilling of the
survey's largest structural feature will begin in April 2000 to test a
10,000-foot Yegua prospect. Mitchell has a 100 percent interest in this prospect
and could possibly drill eight additional wells depending on the results of the
first test.
Interpretation of the 92-square-mile Franklin Ranch 3-D survey in McMullen
County revealed a number of pinnacle reefs in the 12,000-foot Sligo section and
multiple small Wilcox sandstone prospects at shallower depths. Three of the
Wilcox prospects were drilled in fiscal 2000 and all were dry. The first test of
the Sligo interval with a 50 percent working interest partner is scheduled for
May 2000. The Company has over 16,000 acres under lease in the area.
Last year's planned drilling of the 54-square-mile Pine Island 3-D survey
in Jefferson Davis Parish, Louisiana, was delayed when the Company's 50 percent
partner was acquired by a third party. A new partner was found recently and up
to eight wells could be drilled this year to evaluate the Frio Hackberry seismic
anomaly prospects. The initial 11,200-foot exploratory well is expected to spud
in April 2000, east of the Company's successful wells drilled in Calcasieu
Parish, Louisiana, and Orange County, Texas.
[PHOTO]
The first test of the Sligo interval in McMullen County is scheduled for May
2000. Mitchell has a 50-percent working interest in the exploratory well.
MAJOR AREAS OF OPERATIONS
[MAP]
8
<PAGE> 11
================================================================================
PRINCIPAL PRODUCING AREAS
(Average Daily Sales)
Year Ended January 31
<TABLE>
<CAPTION>
2000 1999
---------- ----------
<S> <C> <C>
NATURAL GAS (Mcf)
North Texas ................................. 129,100 122,100
East Texas .................................. 57,600 61,500
Gulf Coast .................................. 50,100 49,700
Other ....................................... 9,300 14,300
---------- ----------
246,100 247,600
========== ==========
RUDE OIL AND CONDENSATE (Bbls)
North Texas ................................. 1,200 1,700
East Texas .................................. 1,200 1,200
Gulf Coast .................................. 2,200 2,400
Other ....................................... 1,300 1,500
---------- ----------
5,900 6,800
========== ==========
</TABLE>
================================================================================
WELL COMPLETIONS
(excluding service wells)
Year Ended January 31, 2000
<TABLE>
<CAPTION>
Exploratory Development Total
------------------------ ------------------------ -----------------------
Total Oil Gas Dry Oil Gas Dry Oil Gas Dry
------ ------ ------ ------ ------ ------ ------ ------ ------ -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
North Texas ............. 85 3 -- 4 3 73 2 6 73 6
East Texas .............. 19 -- -- -- 1 18 -- 1 18 --
Gulf Coast .............. 19 -- -- 5 4 9 1 4 9 6
Other (1) ............... 4 2 -- 2 -- -- -- 2 -- 2
------ ------ ------ ------ ------ ------ ------ ------ ------ -----
Gross wells (2) ......... 127 5 -- 11 8 100 3 13 100 14
====== ====== ====== ====== ====== ====== ====== ====== ====== =====
Net wells ............... 110.7 2.3 -- 5.7 7.5 92.2 3.0 9.8 92.2 8.7
====== ====== ====== ====== ====== ====== ====== ====== ====== =====
</TABLE>
- --------------------
(1) Includes Louisiana and West Texas.
(2) An additional 25 wells (22.1 net wells) were in progress at January 31,
2000.
================================================================================
LEASEHOLDINGS
At January 31, 2000
<TABLE>
<CAPTION>
Gross Net
Acres Acres
------------ ------------
<S> <C> <C>
Texas ....................................... 293,100 203,100
Mississippi ................................. 16,100 6,800
Louisiana ................................... 12,500 8,200
New Mexico .................................. 12,500 11,000
Alabama ..................................... 11,300 4,800
Other* ...................................... 13,500 9,300
------------ ------------
Total undeveloped acreage ................... 359,000 243,200
Producing acreage ........................... 713,400 533,300
------------ ------------
Total acreage ............................... 1,072,400 776,500
============ ============
</TABLE>
- --------------------
* Includes Colorado, Michigan, Oklahoma and Utah.
9
<PAGE> 12
GAS SERVICES
================================================================================
FINANCIAL HIGHLIGHTS
Year Ended January 31 (in thousands)
<TABLE>
<CAPTION>
2000 1999
------------ ------------
<S> <C> <C>
REVENUES
Natural gas processing ...................... $ 409,448 $ 253,295
Natural gas gathering and marketing ......... 235,886 211,387
Other ....................................... 11,335 15,074
------------ ------------
$ 656,669 $ 479,756
============ ============
SEGMENT OPERATING EARNINGS (LOSS)
Natural gas processing ...................... $ 55,860 $ (2,083)
Natural gas gathering and marketing ......... 27,029 23,483
Other ....................................... 10,577 13,949
------------ ------------
93,466 35,349
Unusual items
Personnel reduction program costs ........ -- (7,128)
Asset write-downs ........................ -- (7,560)
------------ ------------
$ 93,466 $ 20,661
============ ============
CAPITAL EXPENDITURES,
excluding acquisitions ................... $ 22,344 $ 28,822
============ ============
</TABLE>
Gas services operating earnings, excluding unusual items, increased 164 percent
to $93.5 million in fiscal 2000 primarily due to the significant improvement in
gas processing margins driven by sharply higher NGL prices. Other factors
contributing to the turnaround were increased NGL production volumes and lower
operating costs and expenses resulting from last year's personnel reduction
program and other streamlining actions.
The Company intentionally restrained capital spending during the first half
of fiscal 2000 because of reduced industry drilling activity. As a result,
expenditures for the year declined to $22.3 million. Given today's improved
industry fundamentals, the capital budget for the current year has been
increased to $36 million. Capital outlays in fiscal 2001 will be directed toward
expanding and upgrading core facilities, primarily in north and southeast Texas,
and covering an anticipated increase in new well connections to the Company's
gathering systems.
At January 31, 2000, Mitchell's NGL reserves totaled a record 177.8 million
barrels, up 28 percent from the prior year. Expanded drilling activities,
especially the Company's Barnett shale program in North Texas, accounted for
approximately 40 percent of this increase. Another 35 percent came from the
acquisition of the remaining 50 percent interest in the Jameson plant. Also,
with improved processing margins, approximately 10 million barrels that were
uneconomic a year ago were added back to the reserve base.
NATURAL GAS LIQUIDS
PRODUCED
Year Ended January 31
Average Daily Production (Bbls)
<TABLE>
<S> <C>
'00 45,100
'99 41,100
'98 45,300
'97 46,100
'96 44,500
</TABLE>
Average Price (per Bbl)
<TABLE>
<S> <C>
'00 $15.07
'99 $10.23
'98 $13.38
'97 $16.13
'96 $11.55
</TABLE>
A welder works on a new pipeline connection in North Texas. Increased drilling
along the Company's gathering systems is expected to add substantial new gas
volumes for both gathering and processing in the current year.
photo right -->
10
<PAGE> 13
Natural gas liquids reserves rose 28 percent to a record 178 million barrels.
[PHOTO]
11
<PAGE> 14
VOLUMES AND PRICES
Natural gas liquids production increased 10 percent in fiscal 2000 to 45,100
barrels per day, propelled by a rebound in the energy industry from the
depressed conditions prevailing a year ago. Most of the improvement came in the
second half of the year as more gas became available for processing from
stepped-up drilling activity along the Company's gathering systems. In addition,
the Jameson acquisition in October 1999 added 3,700 barrels to daily production,
increasing the fourth-quarter average to 50,400 barrels per day. Annual NGL
volumes are expected to increase 15 percent this year, exclusive of any upside
potential from acquisition opportunities.
NGL prices rose 47 percent to $15.07 per barrel in fiscal 2000 from $10.23
in the prior year. Prices especially strengthened in the second half of the year
due to strong petrochemical feedstock demand for NGLs, below-average ethane and
propane inventories, and increased propane exports. These factors pushed
Mitchell's average price to almost $18 per barrel in the fourth quarter and are
expected to continue having a favorable impact on NGL realizations well into the
current fiscal year. Through March, NGL prices have averaged almost $22 per
barrel.
Although average daily pipeline throughput was relatively flat year on
year, pipeline activity was a story of two halves. First-half volumes were down
as drilling constraints implemented by oil and gas producers in the prior year
carried into fiscal 2000. But drilling increased dramatically in the second
half. As a result, fourth-quarter pipeline volumes climbed 26 percent to 679
MMcf per day from 541 MMcf per day in the prior year's comparable quarter. This
increase included 43 MMcf per day (100 percent system throughput) from the
Jameson system, which volumes were reported in pipeline statistics beginning in
October 1999. With almost 60 rigs currently drilling along its gathering
systems, the Company expects to add substantial new gas volumes for both
gathering and processing in fiscal 2001.
Pipeline gross margins averaged 16 cents per Mcf, down from 19 cents in the
prior year. This decrease resulted primarily from a higher mix of transported
volumes versus sales volumes.
NORTH TEXAS
A ramp up of the Company's Barnett development program, together with increased
drilling by other operators in the area, pushed throughput volumes on the
Bridgeport gathering system to 206 MMcf per day in the fourth quarter, up 34
percent from a year earlier. Anticipating this increased activity, Mitchell shut
down the Bridgeport plant for six days in early August 1999 for major
maintenance and upgrades. This work included the installation of
state-of-the-art control systems, improving plant operating efficiency by five
percent.
In the fall of 1999, Mitchell completed construction of a new field gas
sales outlet in Denton County. This sales point - which currently has a daily
capacity of 40 MMcf - allows the Company to sell relatively dry gas production
in this area directly into intrastate markets. More importantly, this freed up
capacity on the Bridgeport gathering system to move additional rich gas to the
Bridgeport plant, increasing NGL production. Mitchell plans to increase the
capacity of this sales point to 60 MMcf per day this year.
With rich gas volumes in North Texas expected to increase significantly
over the foreseeable future, the Company has initiated a study to evaluate
expanding processing capacity at the Bridgeport plant by 100 MMcf per day. In
the interim, Mitchell has entered into agreements to use spare capacity at
nearby third-party processing plants.
[PHOTO]
Gas gathering volumes on the Vanderbilt system in southeast Texas are expected
to grow to 125 MMcf and 6,000 barrels per day by year end from less than 5 Mcf
in August 1998.
[PHOTO]
More NGLs are produced from only six processing facilities like this one in
Madison County, than the Company produced five years ago when it owned interests
in 31 plants.
12
<PAGE> 15
One of the Company's primary operating strategies is to maintain balance
and flexibility between intrastate and interstate gas market outlets. In this
regard, Mitchell is working with a power plant developer to build a pipeline
header system to deliver gas to an 800 megawatt plant scheduled for completion
in southwest Wise County in 2003. Mitchell expects to provide a significant
portion of the plant's 120 MMcf per day gas fuel requirement from its own
production, as well as generate new pipeline revenues by transporting
third-party gas to the plant.
SOUTHEAST TEXAS
Mitchell continues to build its gathering, processing and marketing operations
at the Katy hub in southeast Texas. Katy is one of the largest market hubs in
the United States, providing access to industrial markets along the Houston Ship
Channel and the Texas Gulf Coast. In addition, the Company has a favorable gas
processing contract at the Exxon Katy plant, which has excess capacity to handle
further growth in the area.
At year end, deliveries from Mitchell-operated pipelines to the inlet of
the Katy plant had climbed to 172 MMcf per day, up 32 percent from the
prior-year level. Mitchell is the largest supplier of natural gas to the Katy
plant, accounting for approximately 85 percent of the plant's NGL production.
Much of the growth at Katy comes from Mitchell's Vanderbilt system, which
is capturing substantial new gas supplies from active drilling in the Wilcox and
Yegua trends. When this system was first connected in August 1998, its daily
throughput was less than 5 MMcf. By early fiscal 2000, gas gathering volumes on
this line had reached 20 MMcf per day with associated NGL production of 1,300
barrels per day. Today, volumes are running 65 MMcf and 3,500 barrels per day,
respectively, and are expected to grow to 125 MMcf and 6,000 barrels per day by
the end of the current year.
CENTRAL TEXAS
In March 2000, the Company completed an exchange of its non-operated Oklahoma
gathering and processing assets for (i) Duke Energy Services' interests in
Mitchell-operated gathering and processing assets located in the Austin Chalk
area of Central Texas and (ii) approximately $11.7 million in cash. This
transaction eliminated four partnerships - one with Conoco in Oklahoma and three
in the Austin Chalk with Duke - streamlining the Company's midstream operations.
Mitchell now owns and operates all of its major gathering and processing assets.
Also, the Company produces more NGLs today with only six processing plants than
it produced five years ago when it owned interests in 31 plants.
After several years of field declines, drilling activity in the rich gas
area of the Austin Chalk picked up significantly during the last half of fiscal
2000. In the coming year, a large independent plans to drill nine new oil wells
and rework 27 producing wells. Since the associated gas produced from these
wells is rich in gas liquids, liquids production from this area should level
out, if not increase, in the coming year.
WEST TEXAS
With NGL demand increasing, the Company added quality assets in this core area.
Effective October 1, 1999, the Company purchased its partner's 50 percent
interest in the Jameson processing plant and associated gathering systems for
$23.9 million. This transaction added approximately 21 MMcf per day of gathering
volumes and 3,700 barrels per day of NGL production.
PIPELINE THROUGHPUT
(MMcf per day)
Year Ended January 31
<TABLE>
<S> <C>
'00 567
'99 554
'98 426
'97 410
'96 354
</TABLE>
[PHOTO]
A pipeline operator inserts a "pig" to clean the inside of a 10-inch gathering
line in North Texas.
13
<PAGE> 16
OTHER
Operating earnings from the Company's downstream assets - a one-third interest
in an MTBE gasoline additive plant and a 38.75 percent interest in an NGL
fractionator - declined to $10.6 million from $13.9 million in the prior year.
This decline was due primarily to two unplanned MTBE plant shutdowns (totaling
34 days) for repairs and reduced fees on certain fractionation contracts.
The demand for MTBE as a gasoline additive is likely to diminish during the
next few years due to regulatory pressures. However, the plant can be
retrofitted at a relatively modest capital cost to produce other gasoline blend
stocks such as alkylates. The partners are currently reviewing plant
alternatives and expect to reach a decision in the next 12 to 24 months.
Bridgeport Plant: A study is underway to evaluate expanding the processing
capacity by 100 MMcf per day.
[PHOTO]
14
<PAGE> 17
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL POSITION AND RESULTS
OF OPERATIONS
FORWARD-LOOKING INFORMATION
The discussion which follows includes forward-looking statements. Reference is
made to the inside front cover of this report for information concerning these
statements, including factors that could cause actual results to differ
materially from those in the forward-looking statements.
LIQUIDITY AND CAPITAL RESOURCES
Strategic Alternatives. On April 6, 2000, the Company announced that, as a
result of its review of strategic alternatives, it plans to continue operating
as an independent oil and gas company and to take several steps to improve its
stock price performance and thus enhance shareholder value.
To improve the market liquidity of the Company's stock and eliminate
confusion resulting from its two-class common stock structure, the Class A and
Class B shares are to be combined into a single voting class. This is expected
to occur in late June after approval by the Company's stockholders.
The Company also initiated a balanced program to repurchase some of its
common stock and to further reduce outstanding debt. Stock repurchases - for
which the Board of Directors' authorization covers up to 2.5 million shares -
will be made from time to time in the open market while the debt reductions most
likely will consist of pay downs of outstanding bank revolving credit agreement
borrowings. Since the program is to be funded using excess operating cash flows,
the total amount to be spent and the split between stock repurchases and debt
reductions ultimately will be dependent, among other things, on future energy
prices, cash flow levels and prices of the Company's stock. The Company intends
to maintain or enhance the investment grade rating of its senior notes as this
program proceeds.
While the strategic alternatives study was in progress, the Company took
substantive actions to grow its core energy businesses and thus add to
stockholder value. Energy reserves were significantly increased by applying (i)
new technology that lowered well costs and (ii) an increasing understanding of
reservoir performance. Moreover, there is substantial upside potential in North
Texas where an accelerated exploitation program was begun in fiscal 2000 and was
further expanded recently. Also, the Company's natural gas gathering and
processing operations were further consolidated adding to the cost effectiveness
of the midstream operations.
Overview. After being adversely impacted by unusually low prices for its
products in fiscal 1999 and early fiscal 2000, the Company's results for the
final three quarters of fiscal 2000 improved dramatically as energy prices rose
sharply. Also, contributing to the earnings improvement were reduced costs and
expenses resulting from the personnel reduction program undertaken late in
fiscal 1999, a lowering of geological and geophysical expenses, and other
actions taken by the Company.
The Company's energy operations have returned an average 11.6% on
stockholders' equity over the last five years, one of the best returns in the
independent oil and gas sector. With improved pricing and the aggressive steps
taken by the Company in recent periods, the return was 26.9% for fiscal 2000.
While the Company's earnings and cash flows are affected by many things,
energy prices are clearly one of the most significant. The following table shows
the Company's quarterly average sales prices during the last three fiscal years:
<TABLE>
<CAPTION>
Crude Oil and
Natural Gas (per Mcf) Condensate (per Bbl) NGLs (per Bbl)
------------------------------------ ------------------------------------ -----------------------------------
2000 1999 1998 2000 1999 1998 2000 1999 1998
---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
First quarter ... $ 1.84 $ 2.29 $ 2.23 $ 12.56 $ 13.93 $ 19.99 $ 10.68 $ 11.44 $ 13.46
Second quarter .. 2.40 2.25 2.24 16.44 12.33 18.48 13.33 10.22 12.76
Third quarter ... 2.94 1.90 2.66 20.67 12.22 18.89 17.52 9.79 14.33
Fourth quarter .. 2.78 1.99 2.71 24.32 10.25 17.02 17.96 9.27 12.93
Fiscal year ..... 2.50 2.11 2.47 18.49 12.18 18.50 15.07 10.23 13.38
</TABLE>
15
<PAGE> 18
After being relatively strong in fiscal 1998, prices fell throughout fiscal 1999
to low points not seen for oil and NGLs since 1986 as worldwide oil production
rose during a period of relatively weak demand and inventories reached unusually
high levels. The depressed NGL prices, coupled with the relatively higher
natural gas prices, caused the Company's normally very profitable gas processing
activities to report segment operating losses for the second, third and fourth
quarters of fiscal 1999. The depressed energy price environment led to fiscal
1999 fourth quarter impairments of certain oil and gas proved properties -
primarily oil fields - and gas services assets.
During fiscal 2000, worldwide oil production fell as OPEC and other
countries adopted lower production targets. Excess inventories were worked down
and prices for oil and NGLs rose steadily. After being at record lows early in
1999, oil and NGL prices early in fiscal 2001 reached highs not seen in many
years. Natural gas prices - while not moving steadily upward - were relatively
strong in fiscal 2000. Relatively high energy prices have continued into the
current year; the Company's average sales prices in February 2000 were $3.00 per
Mcf for natural gas and $28.28 and $22.86 per barrel, respectively, for crude
oil and condensate and NGLs.
While the Company generally does not modify its operating plans for normal
volatility in energy prices, the downward price swings were so extreme during
fiscal 1999's last half that they could not be ignored. Accordingly, after
taking many actions early in fiscal 1999 to grow its energy businesses, the
Company found it necessary late in the year to curtail capital spending and to
take various steps, including a personnel reduction program, to sharply reduce
operating costs. As a result, the Company went into fiscal 2000 well-positioned
to operate in a low-energy-price environment and conducted its activities on
that basis during the first half of the year. Capital spending was intentionally
deferred causing natural gas production levels to cease their growth and to fall
somewhat. As the outlook for energy prices improved in the first half of fiscal
2000, the Company began taking steps to substantially increase its development
drilling and well recompletion programs, particularly in the Barnett Shale area
of North Texas.
The Company's accelerated Barnett Shale development program begun in the
last half of fiscal 2000 pushed natural gas production to a record 266 MMcf per
day in the fourth quarter. Six rigs are currently drilling in the Barnett, and
the Company plans to drill as many wells there in the first half of fiscal 2001
as were drilled in all of fiscal 2000 (and twice as many for the full year).
With its expanded drilling activities and an extensive ongoing rework program,
the Company expects to increase its overall gas production by 15% in fiscal
2001.
With improved NGL economics, the acquisition in October 1999 of the other
50% interest in the Jameson plant and increased gathering throughput, NGL
production volumes increased during fiscal 2000. In the fourth quarter, NGL
production averaged 50,400 barrels per day, a level not reached since the early
1990s when more than twice as many plants were being operated. The previously
announced exchange of the Company's interests in several Oklahoma systems for
Duke Energy's 55% interest in jointly owned processing and gathering assets in
the Austin Chalk area of Central Texas was closed on March 31, 2000. The Company
now has total ownership and operating control of all its major gas processing
and gathering facilities. This should lower operating costs and increase the
Company's flexibility in using these facilities. Over the next year, NGL
production is expected to increase 5% or more from the fourth quarter level.
And, after a likely upcoming expansion of the Bridgeport plant to handle the
increasing North Texas gas production, NGL production could rise further.
By capturing a large portion of the new gas supplies being developed along
its systems, the Company expects to further grow its gathering and processing
volumes in fiscal 2001 and beyond. By the end of fiscal 2001, volumes on the
Vanderbilt system are expected to equal 125,000 Mcf per day with 6,000 barrels
of associated NGLs, up from 20,000 Mcf and 1,300 barrels early in fiscal 2000
(and none prior to August 1998).
Fiscal 2001 Earnings. As discussed elsewhere herein, the Company's earnings rose
sharply during fiscal 2000, after a break-even first quarter, and energy prices
have strengthened even further early in fiscal 2001. Based on remainder of the
year futures market strip prices quoted in late March, the Company's net
earnings and cash flows for fiscal 2001 - even after considering the items noted
in the following paragraph - would exceed those of any year in its history
(excluding unusual items).
16
<PAGE> 19
The possible record earnings and cash flows for fiscal 2001 would be
achieved in spite of the negative year-to-year impact of two now-expired
contracts and adverse changes in another. Fiscal 2001 results will be impacted
by the expiration in December 1999 and March 2000 of gas gathering contracts
covering almost 6% of the Company's throughput. Even after considering the
favorable impact of volume increases, a $7 million year-to-year decrease in gas
gathering and marketing operating earnings could occur. Furthermore, effective
June 1, 2000, the terms of the MTBE partnership's sales contract will change.
Until that time, the contract calls for MTBE revenues to be determined using
formula prices covering production costs and debt service payments retiring the
partnership's indebtedness over a five-year term ending in May 2000. Effective
with the change, MTBE sales are to be at market prices, which currently are
below the formula prices received during fiscal 2000. Market conditions in
mid-March 2000 pointed toward a $4 million year-to-year reduction in the
Company's equity in the earnings of the MTBE partnership. However, with the
concurrent elimination of the Company's $3.3 million share of quarterly debt
principal payments, operating cash flows from the partnership should increase
somewhat.
Capital and Exploratory Expenditures. The following table compares the Company's
fiscal 2001 budget for capital and exploratory expenditures with its actual
expenditures during fiscal 2000 and 1999 (in millions):
<TABLE>
<CAPTION>
Fiscal 2001 Budget Fiscal 2000 Actual Fiscal 1999 Actual
------------------- ----------------------------------------- -------------------
First Last Total
Amount % Half Half Amount % Amount %
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Exploration and production ........ $ 183.1 82.7 $ 46.9 $ 78.0 $ 124.9 84.5 $ 169.0 84.4
Gas services ...................... 36.2 16.3 7.6 14.7 22.3 15.1 28.8 14.4
Corporate ......................... 2.2 1.0 .2 .4 .6 .4 2.3 1.2
-------- -------- -------- -------- -------- -------- -------- --------
$ 221.5 100.0 54.7 93.1 147.8 100.0 200.1 100.0
======== ======== ======== ========
Asset acquisitions
Exploration and production ........................... -- -- -- 71.7
Gas services ......................................... -- 23.9 23.9 17.6
-------- -------- -------- --------
$ 54.7 $ 117.0 $ 171.7 $ 289.4
======== ======== ======== ========
</TABLE>
The Company's fiscal 2000 budget originally was set at $136.2 million, 32%
below the $200.1 million spent in the prior year and roughly in line with the
reduced spending pace adopted for fiscal 1999's last half. During fiscal 2000's
first half, capital spending was intentionally restrained to keep the Company's
cash outflows in line with its inflows. However, in response to improving
prices, steps began to be taken during the second quarter to increase activity.
As shown in the table above, capital spending was sharply higher in the last
half of the year. For the year, spending (before asset acquisitions) totaled
$147.8 million. In exploration and production, this was largely due to the
previously mentioned acceleration of the Barnett Shale development program.
In gas services, substantial improvements involving the Bridgeport gas
processing plant and gathering system were completed in the last half of fiscal
2000. And, in October 1999, the Company acquired Conoco's 50% interest in the
Jameson facilities. During the fourth quarter, projects were completed that
added to the throughput volumes of the Company's gathering systems, particularly
the North Texas and Vanderbilt systems.
The Company's fiscal 2001 budget has been set at $221.5 million, 49.9%
above the $147.8 million spent in fiscal 2000 (excluding the Jameson
acquisition), or almost 20% above the annualized spending level in fiscal 2000's
last half. Of the exploration and production budget, approximately $108.5
million is planned for drilling primarily low-risk gas development wells. In gas
services, planned spending primarily involves expansion of facilities in North
Texas around the Bridgeport plant, new well connections to add to pipeline
throughput and various gathering system and processing plant improvements.
Financing Matters. Cash provided by operating activities increased 39% to $240.7
million in fiscal 2000. This increase, coupled with proceeds from sales of
non-strategic assets, funded the accelerating capital program and allowed
long-term debt to be paid down by $93.2 million, to $369.3 million. A further
debt reduction is expected in fiscal 2001 even with the planned increase in
capital spending.
17
<PAGE> 20
The Company has a $250 million bank revolving credit facility and a $25
million bank money-market facility. At January 31, 2000, borrowings of $55
million were outstanding under the revolving credit facility. While the Company
has no immediate plans to issue additional senior notes or to increase the size
of its bank revolving credit facility, it has the borrowing capacity to do so
should business opportunities arise that require funding in excess of the amount
available under the existing bank credit facility ($195 million at January 31,
2000). Because of a receivable sales agreement that lowered costs and eliminated
the need to fund the Company's receivables with bank borrowings, the Company's
long-term debt and working capital balances were each $60 million less at
January 31, 2000 than they otherwise would have been.
Dividend Policy. The Company has paid regular quarterly cash dividends on its
common stock for an uninterrupted period of 21 years. Since fiscal 1994, annual
regular dividends totaling 48 cents and 53 cents per share have been paid on the
Company's Class A and Class B common stock.
Disclosures About Market Risk. The Company's major market risk exposure involves
prices for crude oil, natural gas and NGLs. Realized prices for these products
are driven primarily by prevailing world crude oil prices and domestic natural
gas prices. Such prices historically have been volatile (as shown by the table
on page 15), and this is expected to continue. In general, a $1.00 change in the
per-barrel price of oil, together with an equivalent change in the prices for
natural gas and NGLs based on Btu content (16.7 cents for gas and 67 cents for
NGLs), changes the Company's annual segment operating earnings and cash flows by
approximately $23 million and its after-tax annual net earnings by $15 million.
The Company is partially hedged with respect to natural gas prices since
besides being a seller it also purchases gas in connection with its gas
processing operations (such purchases generally equal from 35% to 40% of gas
sales). Since it has this "natural" hedge, the Company only infrequently enters
into hedging transactions to manage its exposure to price fluctuations. It does
not hold or issue derivative instruments for trading purposes. The Company had
no open hedge positions at January 31, 2000, and its hedging activities during
the last three years were insignificant.
The Company's exposure to changing interest rates is limited since 85% of
its long-term debt at January 31, 2000 consisted of senior notes with fixed
interest rates.
Environmental Matters. Concern for the environment has been a fundamental part
of the Company's operating philosophy for many years. In the ordinary course of
conducting its business, the Company incurs costs - both expensed and
capitalized - to preserve and protect the environment. As public concern for the
environment has grown, new environmental laws have been enacted, more stringent
regulations have been implemented and enforcement of existing controls has been
strengthened. The Company considers the cost of environmental protection a
necessary and manageable part of its business. To date, the Company has not been
faced with major cleanup obligations and has been able to conform with
environmental regulations without materially altering its operating strategies.
Over the next two or three years, the Company estimates that its
expenditures to comply with environmental regulations will total approximately
$6 million per year. These costs consist principally of third-party charges for
water and waste disposal associated with oil and gas wells but also include
non-routine expenses for remediation of old sites, storm water control projects
and emission controls. The Company's annual compliance expenditures could
increase by one-third in fiscal 2003 when new Federal Clean Air Act regulations
become effective.
While it is not possible to fully anticipate all of the financial
obligations or operating constraints that might ultimately result from
increasingly stringent environmental regulations and enforcement programs,
management believes the Company is well-positioned within the industries in
which it competes to deal with environmental protection requirements.
Furthermore, demand for clean-burning natural gas, the cornerstone of the
Company's energy operations, is likely to benefit from increasing environmental
awareness.
Year 2000 Issue. Because of its efforts and those of its business partners over
an extended period, the Company experienced "business as usual" in January 2000
and on February 29, 2000. Most of the Company's efforts in this regard were
accomplished by reallocating internal resources; related third party costs
totaled $820,000. While it is possible that as-yet undetected Year 2000 problems
could become known, no significant problems or additional costs are anticipated.
18
<PAGE> 21
OPERATING STATISTICS
Certain operating statistics (including, where applicable, proportional
interests in equity partnerships) for fiscal 2000, 1999 and 1998 follow:
<TABLE>
<CAPTION>
2000 1999 1998
------------ ------------ ------------
<S> <C> <C> <C>
AVERAGE DAILY VOLUMES
Natural gas sales (Mcf) ..................... 246,100 247,600 238,200
Crude oil and condensate sales (Bbls) ....... 5,900 6,800 6,200
Natural gas liquids produced (Bbls) ......... 45,100 41,100 45,300
Pipeline throughput (Mcf) ................... 567,000 554,000 426,000
AVERAGE SALES PRICES
Natural gas (per Mcf) ....................... $ 2.50 $ 2.11 $ 2.47
Crude oil and condensate (per Bbl) .......... 18.49 12.18 18.50
Natural gas liquids produced (per Bbl) ...... 15.07 10.23 13.38
</TABLE>
RESULTS OF OPERATIONS - FISCAL 2000 COMPARED WITH FISCAL 1999
Overview. Earnings from continuing operations for fiscal 2000 and 1999 - both
before and after unusual items - are summarized in the table that follows.
Earnings from continuing operations totaled $97.2 million in fiscal 2000,
compared to the prior year's $53.0 million loss. Exclusive of unusual items in
both periods, fiscal 2000 after-tax earnings totaled $80.5 million, versus
fiscal 1999's $8.5 million loss. Higher energy prices, reduced personnel costs
and lower geological and geophysical expenses were the principal causes of the
year-to-year earnings turnaround. The following table and discussion identify
and explain the major increases (decreases) in earnings (in millions):
<TABLE>
<CAPTION>
Segment Earnings from Con-
Operating Earnings tinuing Operations
--------------------- --------------------
Exploration Before
and Gas Income After
Production Services Other* Taxes Tax
---------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
FISCAL 1999 AMOUNTS AFTER UNUSUAL ITEMS .............................. $ (37.5) $ 20.6 $ (67.7) $ (84.6) $ (53.0)
ELIMINATE IMPACT OF FISCAL 1999 UNUSUAL ITEMS
(see bottom section of table on page 21) .......................... 46.7 14.7 8.9 70.3 44.5
-------- -------- -------- -------- --------
FISCAL 1999 AMOUNTS BEFORE UNUSUAL ITEMS ............................. 9.2 35.3 (58.8) (14.3) (8.5)
-------- -------- -------- -------- --------
MAJOR INCREASES (DECREASES)
Higher natural gas sales price ....................................... 34.4 -- -- 34.4 22.4
Higher crude oil and condensate sales price .......................... 12.9 -- -- 12.9 8.4
Reduced geological and geophysical expenses .......................... 15.6 -- -- 15.6 10.1
Decreased exploratory well impairments ($2.5 versus $4.2) ............ 1.7 -- -- 1.7 1.1
Lower DD&A rate ($.86 versus $.89 per equivalent Mcf produced) ....... 2.5 -- -- 2.5 1.6
Price-related increases in NGL margins ............................... -- 40.3 -- 40.3 26.2
Higher NGL production volumes ........................................ -- 1.6 -- 1.6 1.0
Increased NGL marketing earnings ..................................... -- 6.5 -- 6.5 4.2
Lower Bridgeport plant repairs and maintenance ....................... -- 2.0 -- 2.0 1.3
Salary and benefit savings from personnel reductions ................. 6.1 5.7 3.7 15.5 10.1
Fiscal 2000 bonus accruals (none in prior year) ...................... (1.3) (.9) (1.9) (4.1) (2.7)
Lower interest expense incurred ...................................... -- -- 1.0 1.0 .7
Lower effective income tax rate ...................................... -- -- -- -- 1.9
Other, net ........................................................... .1 3.0 1.1 4.2 2.7
-------- -------- -------- -------- --------
72.0 58.2 3.9 134.1 89.0
-------- -------- -------- -------- --------
FISCAL 2000 AMOUNTS BEFORE UNUSUAL ITEMS ............................. 81.2 93.5 (54.9) 119.8 80.5
-------- -------- -------- -------- --------
See
Page
FISCAL 2000 UNUSUAL ITEMS ----
Water well litigation provision reversals ..................... 32 15.2 -- -- 15.2 9.5
Gain from sale of Hell's Hole area properties ................. 37 11.5 -- -- 11.5 7.2
-------- -------- -------- -------- --------
26.7 -- -- 26.7 16.7
-------- -------- -------- -------- --------
FISCAL 2000 AMOUNTS AFTER UNUSUAL ITEMS .............................. $ 107.9 $ 93.5 $ (54.9) $ 146.5 $ 97.2
======== ======== ======== ======== ========
</TABLE>
- ----------------------
* Includes general and administrative expense and other expense.
19
<PAGE> 22
Exploration and Production Overview. Exclusive of unusual items, exploration and
production segment operating earnings of $81.2 million during fiscal 2000 were
$72.0 million above those of the prior year. This improvement was principally
due to higher prices for natural gas and oil and reductions in geological and
geophysical and other operating costs. Natural gas sales volumes averaged 246.1
MMcf per day in fiscal 2000, down slightly from the prior year's 247.6 MMcf per
day because of curtailed drilling during the last half of fiscal 1999 and early
this year. Natural gas sales volumes increased steadily over the last five
months of fiscal 2000 because of a mid-year acceleration of the Barnett Shale
development program. Fourth quarter production averaged 266.1 MMcf per day, 7%
above the prior year's fourth quarter.
Higher natural gas sales price ($34.4 million increase). During fiscal 2000, the
Company's natural gas sales price averaged $2.50 per Mcf, $.39 (18%) above the
prior period's $2.11, increasing operating earnings by $34.4 million.
Higher oil and condensate sales price ($12.9 million increase). The Company's
sales price for oil and condensate averaged $18.49 per barrel during fiscal
2000, up $6.31 from the prior period's $12.18, increasing operating earnings by
$12.9 million.
Lower geological and geophysical expenses ($15.6 million increase). During
fiscal 2000, geological and geophysical expenses totaled $6.0 million, down from
$21.6 million during the prior year, improving operating earnings by $15.6
million. During fiscal 1999, the Company completed an aggressive 3-D seismic
program that was not repeated in fiscal 2000.
Gas Services Overview. Gas services operating earnings rose $58.2 million to
$93.5 million during fiscal 2000 principally due to price-related increases in
gas processing margins and earnings from NGL marketing operations. Also
contributing to the improvements were reductions in personnel costs and other
operating expenses. For the reasons discussed below, the Company's NGL volumes
grew by 10% in fiscal 2000, to 45,100 barrels per day; during the fourth
quarter, such production averaged 50,400 barrels per day.
Improved NGL margins ($40.3 million increase). The average price for NGLs
produced during fiscal 2000 of $15.07 per barrel was 47% above the prior year's
$10.23, improving NGL revenues by $72.1 million. Because of the impact of the
year's higher NGL and natural gas prices on producer settlement and gas
shrinkage costs, feedstock costs also increased, resulting in a net $40.3
million price-related increase in NGL margins.
Higher NGL production volumes ($1.6 million increase). NGL production volumes
averaged 45,100 barrels per day, up 10% from fiscal 1999's 41,100, improving
operating earnings by $1.6 million. Poor NGL economics caused prior year volumes
to be reduced when ethane was rejected (and sold as natural gas) at the
Bridgeport plant and other gas was not processed. Also contributing to the
year-to-year volume increase was the acquisition of our partner's 50% interest
in the Jameson plant in October 1999 and increased throughput of the Company's
Vanderbilt system that is processed at the Exxon Katy plant.
Increased NGL marketing earnings ($6.5 million increase). Because of the passage
of time between the production of NGLs and the sale of fractionated products,
NGL marketing operations generally benefit from rising product prices. NGL
prices rose during the current year (particularly in the third and fourth
quarters) after declining during much of the prior year. As a result, there was
a $6.5 million year-to-year increase in NGL marketing earnings.
OTHER
Salary and benefit savings from personnel reductions ($15.5 million increase).
These savings were the result of the personnel reduction program undertaken in
fiscal 1999's fourth quarter.
Interest expense incurred ($1.0 million decrease). Interest expense incurred,
which includes fees attributable to an accounts receivable securitization
program begun in fiscal 1999's fourth quarter, declined $1.0 million during
fiscal 2000. This was largely due to debt paydowns starting in the second
quarter of fiscal 2000; at January 31, 2000, long-term debt totaled $369.3
million, $93.2 million below the level at the beginning of the fiscal year.
20
<PAGE> 23
RESULTS OF OPERATIONS - FISCAL 1999 COMPARED WITH FISCAL 1998
Overview. Earnings from continuing operations for fiscal 1999 and 1998 - both
before and after unusual items - are summarized in the table which follows. The
Company incurred a loss of $53 million from continuing operations during fiscal
1999, which compared with the prior year's earnings of $37.8 million. Excluding
the effects of unusual items in both years, fiscal 1999's loss was $8.5 million,
versus earnings of $57.5 million in fiscal 1998. The earnings decline was
primarily caused by lower energy sales prices, increased interest expense
attributable to continuing operations and reduced interest income on excess cash
balances. The following table and discussion identify and explain the major
increases (decreases) in earnings (in millions):
<TABLE>
<CAPTION>
Segment Earnings from Con-
Operating Earnings tinuing Operations
--------------------- --------------------
Exploration Before
and Gas Income After
Production Services Other* Taxes Tax
----------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
FISCAL 1998 AMOUNTS AFTER UNUSUAL ITEMS .............................. $ 57.9 $ 37.5 $ (44.7) $ 50.7 $ 37.8
-------- -------- -------- -------- --------
See
Page
ELIMINATE IMPACT OF FISCAL 1998 UNUSUAL ITEMS ----
Royalty litigation settlement provision .............. 38 -- 26.0 -- 26.0 16.9
Water well litigation provision ...................... 32 7.0 -- -- 7.0 4.3
Gain from sale of contract drilling assets ........... 38 (2.4) -- -- (2.4) (1.5)
-------- -------- -------- -------- --------
4.6 26.0 -- 30.6 19.7
-------- -------- -------- -------- --------
FISCAL 1998 AMOUNTS BEFORE UNUSUAL ITEMS ............................. 62.5 63.5 (44.7) 81.3 57.5
-------- -------- -------- -------- --------
MAJOR INCREASES (DECREASES)
Lower natural gas sales price ........................................ (31.3) -- -- (31.3) (20.3)
Lower crude oil and condensate sales price ........................... (14.9) -- -- (14.9) (9.7)
Higher natural gas sales volumes ..................................... 3.5 -- -- 3.5 2.3
Higher oil and condensate sales volumes .............................. 2.8 -- -- 2.8 1.8
Increased geological and geophysical expenses ........................ (4.5) -- -- (4.5) (2.9)
Higher DD&A rate ($.89 versus $.84 per equivalent Mcf produced) ...... (5.6) -- -- (5.6) (3.6)
Price-related decreases in NGL margins ............................... -- (22.9) -- (22.9) (15.0)
Lower NGL volumes .................................................... -- (3.6) -- (3.6) (2.3)
Gain from a partnership's sale of the
Brooks-Hidalgo gathering system ................................... -- 3.5 -- 3.5 2.3
Depreciation expense on North Texas
gathering system acquired in January 1998 ......................... -- (1.8) -- (1.8) (1.2)
Increased interest expense
attributable to continuing operations ............................. -- -- (7.7) (7.7) (5.0)
Interest income on excess cash balances .............................. -- -- (8.0) (8.0) (5.2)
Performance unit expense accruals .................................... (.8) (.4) (.4) (1.6) (1.0)
Fiscal 1998 state income tax credit .................................. -- -- -- -- (3.7)
Other, net ........................................................... (2.5) (3.0) 2.0 (3.5) (2.5)
-------- -------- -------- -------- --------
(53.3) (28.2) (14.1) (95.6) (66.0)
-------- -------- -------- -------- --------
FISCAL 1999 AMOUNTS BEFORE UNUSUAL ITEMS ............................. 9.2 35.3 (58.8) (14.3) (8.5)
-------- -------- -------- -------- --------
See
Page
FISCAL 1999 UNUSUAL ITEMS ----
Proved property impairments .......................... 37 (42.2) -- -- (42.2) (26.4)
Personnel reduction program costs .................... 37 (8.5) (7.1) (8.9) (24.5) (15.7)
Gas services asset write-downs ....................... 37 -- (7.6) -- (7.6) (4.9)
Water well litigation provision reversals ............ 32 4.0 -- -- 4.0 2.5
-------- -------- -------- -------- --------
(46.7) (14.7) (8.9) (70.3) (44.5)
-------- -------- -------- -------- --------
FISCAL 1999 AMOUNTS AFTER UNUSUAL ITEMS .............................. $ (37.5) $ 20.6 $ (67.7) $ (84.6) $ (53.0)
======== ======== ======== ======== ========
</TABLE>
- --------------------
* Includes general and administrative expense and other expense.
21
<PAGE> 24
Exploration and Production Overview. Exclusive of unusual items, exploration and
production fiscal 1999 segment operating earnings of $9.2 million were sharply
lower than the $62.5 million of the prior year primarily because of fiscal
1999's lower prices for natural gas and oil and condensate sales. Daily natural
gas production increased 4% during fiscal 1999, to a record 247.6 MMcf, and oil
and condensate production increased 10% to 6,800 barrels per day.
Lower natural gas sales price ($31.3 million decrease). The Company's natural
gas sales price averaged $2.11 per Mcf in fiscal 1999, $.36 (15%) below the
$2.47 realized in the prior year, reducing operating earnings by $31.3 million.
As shown by the table on page 15, natural gas prices were substantially higher
in the last half of fiscal 1998 than they were in fiscal 1999.
Lower oil and condensate sales price ($14.9 million decrease). The Company's
sales price for oil and condensate averaged $12.18 per barrel during fiscal
1999, down sharply from the prior year's $18.50, reducing operating earnings by
$14.9 million. The collapse in world oil prices was largely the result of
overproduction, very mild winter weather in the U.S. and an economic downturn in
Southeast Asia and other parts of the world.
Higher natural gas sales volumes ($3.5 million increase). Natural gas sales
volumes averaged 247.6 MMcf per day during fiscal 1999, up from 238.2 MMcf
during the prior year, increasing operating earnings by $3.5 million. This
increase was principally due to drilling and recompletion activity in North
Texas, Limestone County, the Lake Creek field and the Columbus field - which was
purchased during fiscal 1999's first quarter.
Higher oil and condensate sales volumes ($2.8 million increase). Fiscal 1999's
production of oil and condensate increased 600 barrels per day to 6,800,
increasing operating earnings by $2.8 million. This resulted largely from fiscal
1998 drilling and recompletion activity in Throckmorton County (North Texas),
the Lake Creek field (Southeast Texas) and Calcasieu Parish (Southwest
Louisiana). Drilling and recompletion activity in the Columbus field during
fiscal 1999 also contributed to this increase.
Increased geological and geophysical expenses ($4.5 million decrease). Largely
because of a planned increase in 3-D exploratory seismic survey expenditures,
the Company incurred $4.5 million more in geological and geophysical expenses in
fiscal 1999. Fiscal 1999's activity included surveys in McMullen County, Texas
(Franklin Ranch area), Wise County, Texas (Frazier area) and Throckmorton
County, Texas (McCluskey area).
Gas Services Overview. Gas services operating earnings declined $28.2 million
(to $35.3 million) during fiscal 1999 principally because of price-related
reductions in gas processing margins and volumes. NGL production averaged 41,100
barrels per day, down 9% from fiscal 1998's 45,300. The production decline was
largely the result of decisions not to recover ethane or to bypass the
processing of certain natural gas when these actions increased the Company's
overall profitability.
Price-related decreases in NGL margins ($22.9 million decrease). The average
price for NGLs produced during fiscal 1999 of $10.23 per barrel was 24% below
the prior year's $13.38, reducing NGL revenues by $47.4 million. Because of the
impact of the lower NGL and natural gas prices on producer payments, feedstock
costs also fell, reducing the net margin decline to $22.9 million.
OTHER
Interest expense attributable to continuing operations ($7.7 million decrease).
Because a portion of the proceeds from the sale of The Woodlands Corporation
(TWC) was reinvested in continuing operations rather than being used to retire
debt related to discontinued operations, interest expense attributable to
continuing operations rose by $7.7 million during fiscal 1999. Total interest
expense - including that attributable to discontinued operations - declined by
$7.5 million largely because of the repurchase during fiscal 1998's third
quarter of $185.7 million of 9 1/4% senior notes.
Performance unit expense accruals ($1.6 million decrease). In December 1997, the
Company awarded performance units to mid-level managerial and professional
employees that entitled holders of those units on March 31, 1999 to receive cash
compensation equal to the closing price of the Company's Class B Common Stock on
that date times the number of units awarded to them. Compensation expense -
which was accrued ratably over the 15.5-month life of the units - was $1.6
million higher in fiscal 1999 ($2.4 million versus $.8 million).
Fiscal 1998 state income tax credit ($3.7 million net earnings increase). The
Company's fiscal 1998 effective income tax rate on earnings from continuing
operations (25.4%) benefitted from a deferred state income tax credit related to
a reorganization of the legal structure under which gas services operations are
conducted.
22
<PAGE> 25
QUARTERLY STOCK DATA
(per-share amounts)
<TABLE>
<CAPTION>
Market Price Range
-----------------------------------------
Class A Class B Cash Dividends
------------------- ------------------- -------------------
High Low High Low Class A Class B
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
FISCAL 2000
First .............. $ 15.31 $ 10.56 $ 15.50 $ 11.75 $ .12 $ .1325
Second ............. 19.31 15.25 18.56 15.94 .12 .1325
Third .............. 24.56 17.69 24.50 17.31 .12 .1325
Fourth ............. 24.69 20.50 24.31 20.44 .12 .1325
FISCAL 1999
First .............. $ 28.25 $ 24.56 $ 28.50 $ 24.38 $ .12 $ .1325
Second ............. 25.25 18.31 25.38 18.00 .12 .1325
Third .............. 18.06 10.94 18.00 12.06 .12 .1325
Fourth ............. 14.94 9.63 15.25 9.88 .12 .1325
</TABLE>
UNAUDITED QUARTERLY FINANCIAL DATA
(in thousands except per-share data)
<TABLE>
<CAPTION>
First Second Third Fourth
Quarter Quarter Quarter Quarter
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
FISCAL 2000
Revenues ......................................... $ 159,956 $ 227,931 $ 265,635 $ 280,491
Segment operating earnings ....................... 22,805(a) 53,488(b) 62,367(a) 62,757(a)
Net earnings ..................................... 5,684 26,807 29,458 35,287
Basic and diluted net earnings per share
Class A ....................................... $ .11 $ .54 $ .59 $ .71
Class B ....................................... .12 .55 .60 .72
FISCAL 1999
Revenues ......................................... $ 172,392 $ 180,715 $ 175,334 $ 172,949
Segment operating earnings (loss) ................ 17,443(c) 7,888(c) 9,595 (51,805)(d)
Earnings (loss) from continuing operations ....... 2,295 (4,248) (3,716) (47,293)
Discontinued real estate operations .............. 3,250 -- -- --
Net earnings (loss) .............................. 5,545 (4,248) (3,716) (47,293)
Basic and diluted earnings (loss) per share
Class A - From continuing operations .......... $ .05 $ (.09) $ (.08) $ (.97)
Net earnings ........................ .11 (.09) (.08) (.97)
Class B - From continuing operations .......... .05 (.08) (.07) (.96)
Net earnings ........................ .12 (.08) (.07) (.96)
</TABLE>
- -------------------
(a) Includes water well litigation provision reversals of $9,000 in the first
quarter, $5,000 in the third, and $1,200 in the fourth.
(b) Includes gain of $11,527 from sale of Hell's Hole area properties.
(c) Includes water well litigation provision reversals of $3,000 in the first
quarter and $1,000 in the second.
(d) After charges for exploration and production proved property impairments
of $42,250, gas services asset write-downs of $7,560 and personnel
reduction program costs of $15,652.
23
<PAGE> 26
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
January 31, 2000 and 1999 (dollar amounts in thousands)
<TABLE>
<CAPTION>
2000 1999
------------ ------------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents ...................................................... $ 15,957 $ 20,300
Trade receivables (net of allowance for doubtful accounts of $303 and $318) .... 46,103 34,078
Inventories .................................................................... 7,178 10,734
Income taxes receivable ........................................................ -- 5,944
Other .......................................................................... 6,194 8,576
------------ ------------
Total current assets ........................................................ 75,432 79,632
PROPERTY, PLANT AND EQUIPMENT (at cost less accumulated depreciation,
depletion and amortization of $1,492,640 and $1,450,685 - Note 2) ........... 1,055,439 1,033,738
LONG-TERM INVESTMENTS AND OTHER ASSETS ......................................... 37,197 33,106
------------ ------------
$ 1,168,068 $ 1,146,476
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt ........................................... $ -- $ 100,000
Oil and gas proceeds payable ................................................... 83,526 68,658
Accounts payable ............................................................... 36,411 32,868
Accrued liabilities ............................................................ 32,345 40,269
------------ ------------
Total current liabilities ................................................... 152,282 241,795
------------ ------------
LONG-TERM DEBT (Note 4) ........................................................ 369,267 362,467
------------ ------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes (Note 5) ................................................. 161,338 130,069
Retirement obligations (Note 8) ................................................ 70,411 75,220
Deferred income and other ...................................................... 16,228 12,151
------------ ------------
247,977 217,440
------------ ------------
COMMITMENTS AND CONTINGENCIES (NOTES 6 AND 8)
STOCKHOLDERS' EQUITY (Note 11)
Preferred stock, $.10 par value (authorized 10,000,000 shares; none issued)
Common stock, $.10 par value
(authorized 100,000,000 Class A and 100,000,000 Class B shares) ............. 5,386 5,386
Additional paid-in capital ..................................................... 143,636 143,636
Retained earnings .............................................................. 359,603 287,283
Other comprehensive loss ....................................................... (5,933) (7,381)
Treasury stock, at cost ........................................................ (104,150) (104,150)
------------ ------------
398,542 324,774
------------ ------------
$ 1,168,068 $ 1,146,476
============ ============
</TABLE>
- -------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
24
<PAGE> 27
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
For the Years Ended January 31, 2000, 1999 and 1998 (in thousands except
per-share amounts)
<TABLE>
<CAPTION>
2000 1999 1998
------------ ------------ ------------
<S> <C> <C> <C>
REVENUES
Exploration and production (including a gain of $11,527
from sale of Hell's Hole area properties in 2000 - Note 9) ....... $ 277,344 $ 221,634 $ 262,432
Gas services ........................................................ 656,669 479,756 528,070
------------ ------------ ------------
934,013 701,390 790,502
------------ ------------ ------------
OPERATING COSTS AND EXPENSES (including personnel
reduction program costs of $15,652 in 1999 - Note 9)
Exploration and production (including proved property
impairments of $42,250 in 1999 and litigation provision
(reversals) of $(15,200); $(4,000) and $7,000 - Note 6) .......... 169,393 259,174 204,522
Gas services (including asset write-downs of $7,560
in 1999 and litigation provision of $26,000 in 1998) ............. 563,203 459,095 490,566
------------ ------------ ------------
732,596 718,269 695,088
------------ ------------ ------------
SEGMENT OPERATING EARNINGS (LOSS) (Note 9) .......................... 201,417 (16,879) 95,414
General and administrative expense (including
personnel reduction program costs of $8,848 in 1999) ............. 28,613 39,166 31,978
------------ ------------ ------------
TOTAL OPERATING EARNINGS (LOSS) ..................................... 172,804 (56,045) 63,436
------------ ------------ ------------
OTHER EXPENSE
Interest expense (excluding $15,112
attributable to discontinued operations in 1998) ................. 34,036 35,070 27,419
Interest income ..................................................... (284) (885) (8,899)
Other, net .......................................................... (7,513) (5,637) (5,819)
------------ ------------ ------------
26,239 28,548 12,701
------------ ------------ ------------
EARNINGS (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES ................................... 146,565 (84,593) 50,735
INCOME TAXES (Note 5) ............................................... 49,329 (31,631) 12,909
------------ ------------ ------------
EARNINGS (LOSS) FROM CONTINUING OPERATIONS .......................... 97,236 (52,962) 37,826
------------ ------------ ------------
DISCONTINUED REAL ESTATE OPERATIONS (Note 13)
Earnings from operations, net of income taxes of $4,071 ............. -- -- 7,440
Loss on sale, net of income taxes of $1,750 in
1999 and income tax benefit of $25,878 in 1998 ................... -- 3,250 (67,123)
------------ ------------ ------------
-- 3,250 (59,683)
------------ ------------ ------------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM ........................... 97,236 (49,712) (21,857)
EXTRAORDINARY ITEM - Extinguishment of debt,
net of income tax benefit of $7,135 (Note 14) .................... -- -- (13,250)
------------ ------------ ------------
NET EARNINGS (LOSS) ................................................. $ 97,236 $ (49,712) $ (35,107)
============ ============ ============
BASIC AND DILUTED EARNINGS (LOSS) PER SHARE (Note 12)
Class A -- From continuing operations ............................... $ 1.95 $ (1.11) $ .71
Net earnings ............................................. 1.95 (1.04) (.66)
Class B -- From continuing operations ............................... 2.00 (1.05) .77
Net earnings ............................................. 2.00 (.99) (.72)
AVERAGE COMMON SHARES OUTSTANDING (Basic) -- Class A ................ 22,322 22,321 22,714
-- Class B ................ 26,796 26,785 27,989
</TABLE>
- -------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
25
<PAGE> 28
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
For the Years Ended January 31, 2000, 1999 and 1998
(dollar amounts in thousands)
<TABLE>
<CAPTION>
Other
Additional Compre-
Common Paid-in Retained hensive Treasury
DOLLAR AMOUNTS Total Stock Capital Earnings Loss Stock
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
BALANCE, JANUARY 31, 1997 ........................ $ 555,287 $ 5,386 $ 143,343 $ 435,165 $ -- $ (28,607)
Net loss ......................................... (35,107) -- -- (35,107) -- --
Regular cash dividends (48 cents per share on
Class A and 53 cents per share on Class B) .... (25,691) -- -- (25,691) -- --
Special cash dividends (24 cents per share on
Class A and 26.5 cents per share on Class B) .. (12,462) -- -- (12,462) -- --
Treasury stock purchases ......................... (72,465) -- -- -- -- (72,465)
Exercises of stock options ....................... 3,364 -- 182 -- -- 3,182
---------- ---------- ---------- ---------- ---------- ----------
BALANCE, JANUARY 31, 1998 ........................ 412,926 5,386 143,525 361,905 -- (97,890)
Net loss ......................................... (49,712) -- -- (49,712) -- --
Minimum pension liability adjustment
(net of income tax benefit of $3,975) ......... (7,381) -- -- -- (7,381) --
----------
Comprehensive loss ............................... (57,093)
Cash dividends (48 cents per share on
Class A and 53 cents per share on Class B) .... (24,910) -- -- (24,910) -- --
Treasury stock purchases (including
$7,458 adjustment payment on fiscal 1998
accelerated stock purchase transaction) ....... (9,217) -- -- -- -- (9,217)
Exercises of stock options ....................... 3,068 -- 111 -- -- 2,957
---------- ---------- ---------- ---------- ---------- ----------
BALANCE, JANUARY 31, 1999 ........................ 324,774 5,386 143,636 287,283 (7,381) (104,150)
Net earnings ..................................... 97,236 -- -- 97,236 -- --
Minimum pension liability adjustment
(net of income taxes of $780) ................. 1,448 -- -- -- 1,448 --
----------
Comprehensive income ............................. 98,684
Cash dividends (48 cents per share on
Class A and 53 cents per share on Class B) .... (24,916) -- -- (24,916) -- --
---------- ---------- ---------- ---------- ---------- ----------
BALANCE, JANUARY 31, 2000 ........................ $ 398,542 $ 5,386 $ 143,636 $ 359,603 $ (5,933) $ (104,150)
========== ========== ========== ========== ========== ==========
</TABLE>
<TABLE>
<CAPTION>
Common Stock Issued Treasury Stock Outstanding Shares
---------------------------- ---------------------------- ----------------------------
SHARE AMOUNTS Class A Class B Class A Class B Class A Class B
------------ ------------ ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE, JANUARY 31, 1997 ...... 23,978,088 29,878,088 922,429 1,092,958 23,055,659 28,785,130
Treasury stock purchases ....... -- -- 745,000 2,219,200 (745,000) (2,219,200)
Exercises of stock options ..... -- -- (10,492) (158,341) 10,492 158,341
Other .......................... (7) (7) -- -- (7) (7)
------------ ------------ ------------ ------------ ------------ ------------
BALANCE, JANUARY 31, 1998 ...... 23,978,081 29,878,081 1,656,937 3,153,817 22,321,144 26,724,264
Treasury stock purchases ....... -- -- -- 65,000 -- (65,000)
Exercises of stock options ..... -- -- (500) (136,367) 500 136,367
Other .......................... (4) (4) -- -- (4) (4)
------------ ------------ ------------ ------------ ------------ ------------
BALANCE, JANUARY 31, 1999 ...... 23,978,077 29,878,077 1,656,437 3,082,450 22,321,640 26,795,627
Other .......................... (5) (5) -- -- (5) (5)
------------ ------------ ------------ ------------ ------------ ------------
BALANCE, JANUARY 31, 2000 ...... 23,978,072 29,878,072 1,656,437 3,082,450 22,321,635 26,795,622
============ ============ ============ ============ ============ ============
</TABLE>
- -------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
26
<PAGE> 29
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended January 31, 2000, 1999 and 1998 (in thousands)
<TABLE>
<CAPTION>
2000 1999 1998
----------- ----------- -----------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Earnings (loss) from continuing operations .......................................... $ 97,236 $ (52,962) $ 37,826
Adjustments to reconcile earnings (loss) from continuing operations to cash
provided by operating activities
Depreciation, depletion and amortization (including producing property
impairments of $42,250 and gas services asset write-downs of $7,560 in 1999) ... 112,528 168,431 105,613
Exploration expenses (including exploratory well impairments) .................... 8,517 25,807 22,376
Deferred income taxes ............................................................ 30,489 (25,408) 15,329
Distributions in excess of (less than) earnings of equity investees .............. 6,935 9,609 (554)
Litigation provisions (reversals) ................................................ (15,200) (4,000) 33,000
Gain from sale of Hell's Hole area properties .................................... (11,527) -- --
Accrued personnel reduction program costs ........................................ -- 17,620 --
Other, net ....................................................................... (8,145) (5,323) (7,235)
----------- ----------- -----------
220,833 133,774 206,355
Changes in operating assets and liabilities
Receivables .................................................................... (6,960) 50,944 127,586
Inventories .................................................................... 3,556 3,745 (4,407)
Payables ....................................................................... 14,101 (19,271) (44,753)
Accrued liabilities and other .................................................. 9,163 4,526 (46,464)
----------- ----------- -----------
Cash provided by operating activities ............................................ 240,693 173,718 238,317
----------- ----------- -----------
INVESTING ACTIVITIES
Capital and exploratory expenditures
Total on accrual basis (including asset
acquisitions of $23,874; $89,266 and $26,280) .................................. (171,723) (289,402) (258,292)
Adjustment to cash basis ......................................................... 4,298 (11,635) 6,762
----------- ----------- -----------
(167,425) (301,037) (251,530)
Property, plant and equipment sales proceeds ........................................ 38,194 8,581 6,903
Net proceeds from sale of The Woodlands Corporation ................................. -- -- 480,994
Repayments of off-balance-sheet partnership debt .................................... -- -- (43,827)
Other, net .......................................................................... 2,628 4,462 6,930
----------- ----------- -----------
Cash provided by (used for) investing activities ................................. (126,603) (287,994) 199,470
----------- ----------- -----------
FINANCING ACTIVITIES
Debt repayments ..................................................................... (100,000) (60,000) (285,733)
Proceeds from issuance of debt ...................................................... 6,800 108,200 --
Cash dividends (including special dividends of $12,462 in 1998) ..................... (24,916) (24,910) (38,153)
Treasury stock purchases ............................................................ -- (9,217) (72,465)
Other (including debt reacquisition costs of $19,294 in 1998) ....................... (317) 2,267 (17,487)
----------- ----------- -----------
Cash provided by (used for) financing activities ................................. (118,433) 16,340 (413,838)
----------- ----------- -----------
INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS FROM CONTINUING OPERATIONS ........................................... (4,343) (97,936) 23,949
CASH PROVIDED BY DISCONTINUED OPERATIONS ............................................ -- 12,927 5,535
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR ........................................ 20,300 105,309 75,825
----------- ----------- -----------
CASH AND CASH EQUIVALENTS, END OF YEAR .............................................. $ 15,957 $ 20,300 $ 105,309
=========== =========== ===========
</TABLE>
- -------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
27
<PAGE> 30
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
January 31, 2000, 1999 and 1998
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of operations and principles of consolidation. Mitchell Energy &
Development Corp. and its majority-owned subsidiaries (the "Company") constitute
a large independent energy company engaged in the exploration for and
development and production of natural gas, natural gas liquids, and crude oil
and condensate. The Company also operates natural gas gathering systems in Texas
and markets natural gas through purchase and resale activities.
The consolidated financial statements include the accounts of the Company
after elimination of all significant intercompany accounts and transactions. The
equity method of accounting is used for investments in 20%-to-50%-owned
entities.
Use of estimates. The preparation of financial statements in conformity with
accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosures 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.
Property, plant and equipment. The Company's exploration and production
activities are accounted for using the "successful efforts" method. Lease
acquisition costs are capitalized as are costs to drill and equip development
wells, including unsuccessful ones. Exploratory drilling costs are initially
capitalized; if proved reserves are not found, such costs are subsequently
impaired. Geological and geophysical costs and other exploration costs are
charged to expense as incurred. Depreciation, depletion and amortization (DD&A)
of proved oil and gas properties is determined on a field-by-field basis using
physical units of production. Estimated future costs of dismantlement,
restoration and abandonment are considered in determining DD&A expense.
The Company holds no unproved leases whose costs are individually
significant. Costs of unproved leaseholds are charged to expense over estimated
holding periods based on historical experience. Leasehold costs for properties
determined to be productive are transferred to proved oil and gas properties.
Other property, plant and equipment additions are recorded at cost and
depreciated on the straight-line method over the estimated service lives of the
various assets, which range from 3 to 25 years. Maintenance and repair costs are
charged to expense; costs of renewals and betterments are capitalized.
Long-lived assets held and used by the Company are reviewed for impairment
whenever events or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable. When it is determined that an asset's estimated
future net cash flows will not be sufficient to recover its carrying amount, an
impairment charge is recorded to reduce the carrying amount for that asset to
its estimated fair value. Impairment assessments for proved oil and gas
properties are made on a field-by-field basis. Charges for such impairments,
which are included in DD&A expense, totaled none; $42,250,000 (see Note 9) and
$1,640,000 in fiscal 2000, 1999 and 1998.
Environmental expenditures. Liabilities for environmental expenditures are
recognized when it is probable that obligations have been incurred in amounts
that are material and reasonably estimable.
Statements of Cash Flows. Short-term investments with maturities of three months
or less are considered to be cash equivalents. The reported amounts for proceeds
from issuance of debt and debt repayments exclude the impact of borrowings with
initial terms of three months or less. Interest paid, including amounts
attributable to discontinued operations in 1998, totaled $33,497,000;
$34,450,000 and $45,030,000 during fiscal 2000, 1999 and 1998. Income taxes paid
during those periods, including amounts applicable to discontinued operations,
totaled $12,889,000; $2,110,000 and $64,500,000 (a substantial portion of which
was related to the taxable gain on the sale of The Woodlands Corporation). There
were no significant non-cash investing or financing activities during the
three-year period ended January 31, 2000.
28
<PAGE> 31
Accounting for derivatives. The Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities," in June 1998. The statement,
which the Company must adopt for fiscal 2002, requires that all derivatives be
recognized at fair value as assets or liabilities and that changes in fair value
be recorded in earnings or other comprehensive income. The Company's infrequent
use of derivatives makes it unlikely that the adoption of this statement will
have a significant impact on its financial position or results of operations.
NOTE 2 - PROPERTY, PLANT AND EQUIPMENT
The cost and net book value of property, plant and equipment consisted of the
following at January 31, 2000 and 1999 (in thousands):
<TABLE>
<CAPTION>
Cost Net Book Value
----------------------- -----------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
EXPLORATION AND PRODUCTION
Oil and gas properties ...................... $1,893,057 $1,863,422 $ 694,064 $ 683,946
Support equipment and facilities ............ 50,241 50,612 13,025 16,253
---------- ---------- ---------- ----------
1,943,298 1,914,034 707,089 700,199
---------- ---------- ---------- ----------
GAS SERVICES (including invest-
ments in equity partnerships - Note 3)
Natural gas processing ...................... 200,135 187,300 105,489 102,761
Natural gas gathering ....................... 303,348 286,694 153,834 145,488
Other ....................................... 85,839 80,853 85,243 79,678
---------- ---------- ---------- ----------
589,322 554,847 344,566 327,927
---------- ---------- ---------- ----------
CORPORATE ................................... 15,459 15,542 3,784 5,612
---------- ---------- ---------- ----------
$2,548,079 $2,484,423 $1,055,439 $1,033,738
========== ========== ========== ==========
</TABLE>
NOTE 3 - PARTNERSHIP INVESTMENTS
A summary of the Company's net investments in partnerships at January 31, 2000
and 1999 and its equity in their pretax earnings for the years ended January 31,
2000, 1999 and 1998 follows (in thousands):
<TABLE>
<CAPTION>
Net Investment Equity in Pretax Earnings
Percent ----------------------- ---------------------------------------
Owned 2000 1999 2000 1999 1998
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
NATURAL GAS PROCESSING
C&L Processors Partnership ............. 50 $ 25,016 $ 60,130 $ 4,580 $ (301) $ 2,908
U.P. Bryan Plant ....................... 45 2,091 2,244 8,837 1,033 3,525
Others ................................. -- -- -- -- (18)
---------- ---------- ---------- ---------- ----------
27,107 62,374 13,417 732 6,415
---------- ---------- ---------- ---------- ----------
GAS GATHERING AND MARKETING
Austin Chalk Natural Gas
Marketing Services .................. 45 163 739 830 2,814 2,662
Ferguson-Burleson County
Gas Gathering System ................ 45 35,744 40,151 4,869 3,542 3,262
Louisiana Chalk Gathering System ....... 50 15,904 17,346 (993) (726) (367)
Others ................................. 501 353 145 3,613* 57
---------- ---------- ---------- ---------- ----------
52,312 58,589 4,851 9,243 5,614
---------- ---------- ---------- ---------- ----------
OTHER
Belvieu Environmental Fuels (BEF) ...... 33.33 54,988 47,660 8,353 9,068 10,126
Gulf Coast Fractionators ............... 38.75 28,709 30,364 3,131 4,613 4,900
---------- ---------- ---------- ---------- ----------
83,697 78,024 11,484 13,681 15,026
---------- ---------- ---------- ---------- ----------
$ 163,116 $ 198,987 $ 29,752 $ 23,656 $ 27,055
========== ========== ========== ========== ==========
</TABLE>
- ----------------------------------------
* Includes $3,492 gain on a partnership's sale of the Brooks-Hidalgo gathering
system.
29
<PAGE> 32
The Company's net investment in each of these entities is reported as property,
plant and equipment in the consolidated balance sheets and its equity in their
pretax earnings is reported as revenues in the consolidated statements of
earnings, each under the gas services caption.
During the third quarter of fiscal 2000, C&L Processors Partnership (C&L)
distributed the Jameson gas processing plant and related facilities to its
partners, Conoco and a wholly-owned subsidiary of the Company. The Company
subsequently purchased Conoco's 50% interest in these facilities for
approximately $23,900,000. Effective October 1, 1999, the Jameson facilities
became wholly owned and ceased being reported as part of C&L's operations.
On March 31, 2000, the Company exchanged its share of the remaining assets
of C&L for Duke Energy Field Services, Inc.'s share of the assets previously
owned by Ferguson-Burleson County Gas Gathering System, U.P. Bryan Plant and
Austin Chalk Natural Gas Marketing Services and $11,670,000 in cash. Each of the
four partnerships distributed their assets to their partners prior to the
exchange and ceased partnership operations.
Of the partnerships, only BEF has outstanding debt that is recourse to the
Company. At January 31, 2000, BEF's bank loan had an outstanding balance of
$19,556,000, the Company's share of which totaled $6,519,000. The loan bears
interest at floating rates based on spreads over LIBOR and is due in quarterly
installments of $9,778,000 plus interest through May 2000. BEF owns a plant
located at Mont Belvieu, Texas with the capacity to produce up to 17,000 barrels
per day of MTBE, a gasoline additive that reduces carbon monoxide emissions. BEF
has entered into agreements which require each of the three partners to provide
one-third of the plant's isobutane feedstock and one of the partners, Sun
Company, Inc., to purchase all of its production for a period extending through
September 2004.
Summarized balance sheet information (on a 100% basis) for these entities
at January 31, 2000 and 1999 follows (in thousands):
<TABLE>
<CAPTION>
2000 1999
---------- ----------
<S> <C> <C>
Current assets ......................................................................... $ 102,351 $ 94,369
Net noncurrent assets .................................................................. 401,624 499,856
Current liabilities .................................................................... 75,671 60,734
Debt payable to third parties (including current maturities of $25,588 and $60,350) .... 25,588 92,542
Notes payable to owners (including $5,000 payable to the Company in 1999) .............. -- 10,000
Owners' equity ......................................................................... 402,716 430,949
</TABLE>
Summarized earnings information (on a 100% basis) for these entities for
the years ended January 31, 2000, 1999 and 1998 follows (in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
---------- ---------- ----------
<S> <C> <C> <C>
Revenues .................................................................. $ 597,527 $ 553,542 $ 764,272
Operating earnings ........................................................ 79,579 58,474 87,845
Pretax earnings (before interest expense for those entities
whose activities are funded by capital contributions of the owners) .... 70,680 43,365 69,918
</TABLE>
NOTE 4 - LONG-TERM DEBT
The Company's outstanding debt consists of parent company senior notes, the
proceeds of which have been advanced to the operating subsidiaries, and
borrowings under bank revolving credit and money market facilities. A summary of
outstanding debt at January 31, 2000 and 1999 follows (in thousands):
<TABLE>
<CAPTION>
2000 1999
---------- ----------
<S> <C> <C>
Unsecured senior notes
9 1/4%, due January 15, 2002 ...................................... $ 64,267 $ 64,267
6 3/4%, due February 15, 2004 ..................................... 250,000 250,000
8%, repaid on July 15, 1999 ....................................... -- 100,000
Committed bank revolving credit agreement, unsecured ................. 55,000 35,000
Uncommitted money market facility, at floating interest rates ........ -- 13,200
---------- ----------
369,267 462,467
Less - Current maturities ............................................ -- 100,000
---------- ----------
$ 369,267 $ 362,467
========== ==========
</TABLE>
30
<PAGE> 33
The Company has a five-year $250,000,000 committed bank revolving credit
agreement that terminates in July 2003, when any borrowings then outstanding are
payable. Interest rates, which generally are based on spreads over LIBOR, vary
based on the highest of the ratings given the Company's senior notes by two
specified rating agencies. The Company pays commitment fees on the unused
portion of this facility.
The senior notes have no sinking fund requirements and are not redeemable
prior to their respective maturity dates. The bank revolving credit agreement
contains certain restrictions which, among other things, limit the payment of
dividends by requiring consolidated tangible net worth, as defined, to equal at
least $275,000,000 and require the maintenance of a specified consolidated
leverage ratio based on earnings before interest, taxes and DD&A and excluding
extraordinary, unusual, non-recurring and non-cash charges and credits. Retained
earnings available for the payment of cash dividends totaled $121,743,000 at
January 31, 2000. The bank credit agreement and/or the senior notes indentures
also limit the amounts of additional borrowings and letters of credit, restrict
the sale or lease of certain assets and limit the right of the parent company
and certain subsidiaries to merge with other companies.
NOTE 5 - INCOME TAXES
Income taxes applicable to earnings from continuing operations for the years
ended January 31, 2000, 1999 and 1998 consist of the following (in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
---------- ---------- ----------
<S> <C> <C> <C>
Current - Federal ...... $ 18,682 $ (6,361) $ (2,425)
State ........ 158 138 5
---------- ---------- ----------
18,840 (6,223) (2,420)
---------- ---------- ----------
Deferred - Federal ...... 27,470 (21,942) 19,033
State ........ 3,019 (3,466) (3,704)
---------- ---------- ----------
30,489 (25,408) 15,329
---------- ---------- ----------
$ 49,329 $ (31,631) $ 12,909
========== ========== ==========
</TABLE>
The deferred state income tax credit of $3,704,000 in fiscal 1998 resulted
primarily from a legal reorganization of gas services operations that allowed
previously recorded liabilities for such taxes to be reduced.
Reconciliations between the 35% statutory Federal income tax rate and the
Company's effective income tax rate for the fiscal years 2000, 1999 and 1998
follow:
<TABLE>
<CAPTION>
2000 1999 1998
-------- -------- --------
<S> <C> <C> <C>
Statutory Federal income tax rate ............................... 35.0% 35.0% 35.0%
State income taxes, net of Federal income tax effect ............ 1.4 2.6 (4.7)
Federal tax credits under Section 29 of the Internal Revenue
Code for natural gas produced from certain wells ............. (2.3) -- (4.0)
Other, net ...................................................... (.4) (.2) (.9)
-------- -------- --------
33.7% 37.4% 25.4%
======== ======== ========
</TABLE>
The principal components of the Company's deferred income tax liability
consisted of the following at January 31, 2000 and 1999 (in thousands):
<TABLE>
<CAPTION>
2000 1999
------------ ------------
<S> <C> <C>
Oil and gas acquisition, exploration and development costs
deducted for tax purposes in excess of financial statement DD&A ........ $ 138,803 $ 120,769
Depreciation of other property, plant and equipment ....................... 48,958 46,378
Unused alternative minimum tax credits .................................... (6,597) (12,274)
Accrued employee benefits expense not yet deductible for tax purposes ..... (29,100) (32,562)
Other, net ................................................................ 9,274 7,758
------------ ------------
$ 161,338 $ 130,069
============ ============
</TABLE>
31
<PAGE> 34
At January 31, 2000, the Company had $6,597,000 of unused alternative
minimum tax credits that can be carried forward indefinitely. These credits have
been recognized in the calculation of the Company's financial statement income
tax provisions. Accordingly, their future utilization would only reduce the
amount of taxes currently payable, not the financial statement income tax
provision.
NOTE 6 - COMMITMENTS AND CONTINGENCIES
North Texas water well litigation. In March 1996, in a trial known as the
Bartlett case, a judgment was entered against a wholly owned subsidiary of the
Company by a Wise County, Texas court for $4,051,760 in actual damages and
$200,000,000 in exemplary damages to eight plaintiff groups, who claimed that
the natural gas operations of the subsidiary had affected their water wells. The
Company appealed this judgment, and in November 1997 the Second Court of Appeals
in Fort Worth, Texas, reversed the previous decision. Several plaintiffs'
attempts to appeal the reversal, including petitions to the Texas Supreme Court,
were subsequently denied, and the Bartlett case is now over.
Several cases that involved allegations similar to those in the Bartlett
case were also brought, and the Company was victorious in the trials and appeals
for each case. At January 31, 2000, no such ongoing litigation was outstanding,
and this is no longer a contingent liability of the Company.
Provisions totaling $32,000,000 were expensed over the years in connection
with this litigation, including a $7,000,000 charge in fiscal 1998. Costs
incurred - which consisted principally of attorneys' fees and other defense
costs for the Bartlett and other trials and costs of bonds, etc., related to the
appeal of the Bartlett judgment - were charged against the reserve.
Between May 1997 and January 2000, the Company entered into agreements with
seven insurance carriers reimbursing it for a total of $24,700,000 of the
defense costs incurred in connection with this litigation, all of which
reimbursements have been received. After entering into two reimbursement
agreements in April 1998 and after agreeing in August 1998 to settle the last 25
untried cases, the Company recorded reversals of the previous provisions of
$3,000,000 and $1,000,000, respectively, in the first and second quarters of
fiscal 1999. After entering into reimbursement agreements during March 1999,
October 1999 and a final one in January 2000, accrual reversals of $9,000,000;
$5,000,000 and $1,200,000, respectively, were recorded in the first, third and
fourth quarters of fiscal 2000.
Leases and contingent liabilities. The Company has various noncancellable
equipment and facility operating lease agreements which provide for aggregate
future payments of approximately $28,500,000. Minimum rentals for each of the
five years subsequent to fiscal 2000 total approximately $10,200,000;
$8,900,000; $4,600,000; $4,200,000 and $600,000. Rental expense for operating
leases totaled approximately $11,300,000; $6,100,000 and $6,500,000 in fiscal
2000, 1999 and 1998. In addition to obligations described elsewhere in these
notes, the Company had contingent liabilities totaling approximately $16,900,000
at January 31, 2000, consisting of guarantees of third-party debt.
Environmental regulations. The Company is considered by the United States
Environmental Protection Agency (the EPA) to be a potentially responsible party
with respect to two Superfund waste disposal sites. The only site involving more
than minimal potential exposure to the Company is the Operating Industries, Inc.
site located in Monterey Park, California, where small amounts of non-toxic
drilling fluids from Company-operated oil and gas wells were deposited. Although
the Company believes that it should be exempt from liability with respect to
this site, to date it has paid and expensed approximately $620,000 of costs.
While additional exposure exists for future cleanup and closure costs of this
site, the Company's share of such costs is not expected to be significant.
The Company continually monitors the many Federal, state and local laws and
regulations relating to the protection of the environment and public health and
believes it is in substantial compliance with such rules. Also, it expects to
continue to be able to conform with environmental regulations without materially
altering its operating strategies.
Other. The Company also is party to other claims and legal actions arising in
the ordinary course of its business and to recurring examinations performed by
the Internal Revenue Service and other regulatory agencies. While the outcome of
all such matters cannot be predicted with certainty, management expects that
losses, if any, resulting from the ultimate resolution of
32
<PAGE> 35
the matters discussed in this paragraph will not result in charges that are
material to the Company's financial position. It is possible, however, that
charges could be required that would be significant to the operating results of
a particular period.
As indicated in Note 3, the Company holds a one-third interest in a
partnership which owns a plant that manufactures a gasoline additive known as
MTBE. In March 1999, the governor of California ordered that the use of MTBE be
phased out in that state over a four-year period. In July 1999, a national
advisory panel formed by the EPA recommended that the use of MTBE be reduced,
and in August 1999 a group of seven northeastern states took steps that would
lead to the phase-out of MTBE usage over a three-year period. Restrictions on
the use of MTBE could significantly impact future operations of the MTBE plant
partially owned by the Company. However, that facility, which was built in the
mid 1990s for approximately $225,000,000, was originally designed in a manner
that allows it - with moderate expenditures - to be converted to the production
of other products. It is not possible at this time to determine the ultimate
impact, if any, of this matter on the Company's financial position or future
results of operations.
NOTE 7 - FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial
instruments at January 31, 2000 and 1999 were as follows (in thousands):
<TABLE>
<CAPTION>
2000 1999
------------------------ ------------------------
Carrying Estimated Carrying Estimated
Amounts Fair Values Amounts Fair Values
---------- ----------- ---------- -----------
<S> <C> <C> <C> <C>
Long-term debt (including current maturities) .............. $ 369,267 $ 352,731 $ 462,467 $ 449,147
</TABLE>
Fair values of the Company's fixed-rate senior notes were based on quoted market
prices. For floating-rate debt, carrying amounts and fair values are assumed to
be equal because of the nature of these obligations. The carrying amounts of
other on-balance-sheet financial instruments approximate their fair values. The
aggregate cost to terminate off-balance-sheet financial instruments is not
significant.
In November 1998, Mitchell Receivables, Inc. (MRC), a wholly owned
subsidiary, entered into a securitization agreement which provides for ongoing
sales of up to $75,000,000 of energy accounts receivable. Proceeds from
outstanding sales under this program, which totaled $60,000,000 at January 31,
2000, were used to pay down revolving credit agreement borrowings. MRC is a
special purpose subsidiary whose assets must first be used to satisfy its
creditors and are not available to satisfy creditors of the parent company.
The Company has only limited involvement with derivative financial
instruments and does not use them for trading purposes. Such use is limited to
using commodities futures contracts to hedge well-defined energy price risks.
The Company had no such open positions at January 31, 2000.
NOTE 8 - RETIREMENT BENEFITS
Substantially all full-time employees of the Company who meet specified age and
service requirements are covered by a defined benefit retirement plan which is
maintained without cost to the employees. Pension benefits are based on years of
service and average earnings for the three highest consecutive years during the
ten years immediately preceding retirement. The Company's funding policy is to
make contributions to the plan of at least the minimum amounts required by
applicable Federal laws and regulations. No contributions were made to the plan
during the last three fiscal years.
Internal Revenue Service regulations limit the benefits that may be paid to
certain employees under the Company's qualified retirement plan. Nonqualified
plans are maintained to make the basis on which those individuals' retirement
benefits are determined the same as is used for other employees. A Rabbi trust
fund is maintained from which these benefits are paid. That fund's assets -
which under accounting principles generally accepted in the United States must
be reported as an asset of the Company rather than being offset against the
accrued benefit costs - totaled $21,381,000 and $15,050,000 at January 31, 2000
and 1999. These assets are included in Long-term Investments and Other Assets in
the accompanying balance sheets.
33
<PAGE> 36
Retirees who reach retirement age while working for the Company and meet
certain other eligibility requirements may elect coverage under the Company's
postretirement medical benefits plan. This plan incorporates a
scheduled-reimbursements methodology under which the Company and providers agree
to specified rates for individual services. The Company has the right to amend
or terminate medical benefits for active employees and retirees or to change the
required level of participant contributions. The cost of providing these
postretirement health care benefits is reduced by available Medicare coverage
and retiree contributions. The plan is unfunded, and benefits are paid as costs
are incurred.
The following table provides the indicated information for the years ended
January 31, 2000 and 1999 concerning the Company's retirement plans and its
postretirement medical benefits plan (dollar amounts in thousands):
<TABLE>
<CAPTION>
Qualified Nonqualified Retiree Medical
Retirement Plan Retirement Plans Benefits Plan
------------------------ ------------------------ ------------------------
2000 1999 2000 1999 2000 1999
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year ....... $ 167,855 $ 126,432 $ 20,467 $ 12,700 $ 29,014 $ 20,592
Service cost ................................ 3,269 3,385 359 358 618 667
Interest cost ............................... 10,889 8,933 1,329 877 1,909 1,440
Benefits paid ............................... (13,372) (7,701) (1,518) (1,202) (2,414) (1,679)
Special termination benefits ................ -- 15,611 -- 827 -- 2,873
Actuarial (gains) losses .................... (18,183) 24,168 (1,493) 6,907 764 2,488
Curtailments ................................ -- (2,973) -- -- -- 2,416
Plan amendments ............................. 548 -- (548) -- -- --
Contributions by plan participants .......... -- -- -- -- 295 217
---------- ---------- ---------- ---------- ---------- ----------
Benefit obligation, end of year ............. $ 151,006 $ 167,855 $ 18,596 $ 20,467 $ 30,186 $ 29,014
========== ========== ========== ========== ========== ==========
CHANGE IN PLAN ASSETS
Plan assets at fair value,
beginning of year ........................ $ 177,804 $ 150,088
Actual return on plan assets ................ 12,540 35,417
Benefits paid ............................... (13,372) (7,701)
---------- ----------
Plan assets at fair value, end of year ...... $ 176,972 $ 177,804
========== ==========
FUNDED STATUS AT YEAR END
Plan assets over (under)
benefit obligation ....................... $ 25,966 $ 9,950 $ (18,596) $ (20,467) $ (30,186) $ (29,014)
Unrecognized (gains) losses ................. (50,947) (37,293) 9,555 11,881 7,765 7,286
Unrecognized prior service cost ............. 647 179 112 802 (5,911) (6,702)
Unrecognized net transition obligation ...... -- -- 83 166 -- --
Minimum pension liability adjustment ........ -- -- (9,322) (12,324) -- --
---------- ---------- ---------- ---------- ---------- ----------
Accrued balance sheet liability ............. $ (24,334) $ (27,164) $ (18,168) $ (19,942) $ (28,332) $ (28,430)
========== ========== ========== ========== ========== ==========
MINIMUM PENSION LIABILITY ADJUSTMENT
Additional minimum liability ........................................... $ 9,322 $ 12,324
Offsetting intangible asset ............................................ 195 968
---------- ----------
$ 9,127 $ 11,356
========== ==========
</TABLE>
The actuarial assumptions used in computing the amounts disclosed herein
included discount rates of 7.75%, 6.75% and 7.25% in fiscal 2000, 1999 and 1998,
an expected annual rate of return on plan assets of 9% and age-graded annual
salary increases ranging from 3.5% to 5.5%.
34
<PAGE> 37
Components of financial statement expense for the Company's retirement
plans and its retiree medical benefits plan for the years ended January 31,
2000, 1999 and 1998 were (in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
---------- ---------- ----------
<S> <C> <C> <C>
QUALIFIED RETIREMENT PLAN
Service cost .......................................... $ 3,269 $ 3,385 $ 3,420
Interest cost ......................................... 10,889 8,933 8,832
Return on plan assets (expected) ...................... (15,415) (13,218) (12,000)
Amortization of prior service cost .................... 80 95 103
Amortization of unrecognized gains .................... (1,653) (2,355) (1,674)
---------- ---------- ----------
Net periodic benefit cost (credit) .................... (2,830) (3,160) (1,319)
Additional charges (credits) due to curtailments,
settlements and special termination benefits ....... -- 12,687(a) (4,031)(b)
---------- ---------- ----------
Financial statement expense (credit) .................. $ (2,830) $ 9,527 $ (5,350)
========== ========== ==========
NONQUALIFIED RETIREMENT PLANS
Service cost .......................................... $ 359 $ 358 $ 361
Interest cost ......................................... 1,329 877 857
Amortization of prior service cost .................... 142 142 155
Amortization of transition obligation ................. 83 83 91
Amortization of unrecognized losses ................... 834 359 414
---------- ---------- ----------
Net periodic benefit cost ............................. 2,747 1,819 1,878
Additional charges due to curtailments,
settlements and special termination benefits ....... -- 827(a) 247(b)
---------- ---------- ----------
Financial statement expense ........................... $ 2,747 $ 2,646 $ 2,125
========== ========== ==========
RETIREE MEDICAL PLAN
Service cost .......................................... $ 618 $ 667 $ 684
Interest cost ......................................... 1,909 1,440 1,859
Amortization of prior service cost credit ............. (791) (931) (500)
Amortization of unrecognized losses ................... 285 238 305
---------- ---------- ----------
Net periodic benefit cost ............................. 2,021 1,414 2,348
Additional charges (credits) due to curtailments
and special termination benefits ................... -- 4,106(a) (1,930)(b)
---------- ---------- ----------
Financial statement expense ........................... $ 2,021 $ 5,520 $ 418
========== ========== ==========
</TABLE>
- -----------------------------------------------------
(a) These expenses - which totaled $17,620 - were related to a personnel
reduction program (see Note 9).
(b) These items - which totaled $(5,714) - related to the sale of The Woodlands
Corporation and were included in the calculation of the loss on that sale.
The Company's assumed health care cost trend rate equals 6% for fiscal
2001, declines to 5.5% in 2002 and remains at that level thereafter. The health
care cost trend rate assumption has a significant effect on the amount of the
retiree medical benefit obligation and the periodic financial statement expense.
An increase of 1% in the assumed trend rate would have increased the retiree
medical benefit obligation at January 31, 2000 by $3,917,000 and the service and
interest cost components of the fiscal 2000 financial statement expense by a
total of $423,000. A decrease of 1% in the trend rate would have reduced these
amounts by $3,996,000 and $431,000, respectively.
The Company maintains a defined contribution plan in which eligible
employees may participate on a voluntary basis. The Company's contributions -
which match each employee's contributions on a dollar-for-dollar basis up to 6%
of eligible compensation - totaled $2,479,000; $3,075,000 and $2,913,000 in
fiscal 2000, 1999 and 1998.
35
<PAGE> 38
NOTE 9 - SEGMENT INFORMATION
The following table includes industry segment data for the fiscal years ended
January 31, 2000, 1999 and 1998 (in thousands):
<TABLE>
<CAPTION>
Inter- Segment Total Capital
Outside segment Operating Operating Expendi- Segment
Revenues Revenues Earnings Earnings DD&A tures(a) Assets
---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
FISCAL 2000
EXPLORATION AND PRODUCTION
Operations ............................ $ 265,817 $ -- $ 81,224 $ 71,354 $ 95,205 $ 124,911 $ 714,897
Water well litigation
provision reversals (Note 6) ....... -- -- 15,200 15,200 -- -- --
Gain from sale of Hell's
Hole area properties ............... 11,527 -- 11,527 11,527 -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
277,344 -- 107,951 98,081 95,205 124,911 714,897
---------- ---------- ---------- ---------- ---------- ---------- ----------
GAS SERVICES
Natural gas processing ................ 409,448 96,795 55,860 53,059 4,310 24,455 122,334
Natural gas gathering and marketing ... 235,886 268,402 27,029 23,848 10,584 21,560 154,935
Other ................................. 11,335 -- 10,577 10,253 107 203 85,440
---------- ---------- ---------- ---------- ---------- ---------- ----------
656,669 365,197 93,466 87,160 15,001 46,218 362,709
---------- ---------- ---------- ---------- ---------- ---------- ----------
Corporate ............................. -- -- -- (12,437)(b) 2,322 594 90,462
---------- ---------- ---------- ---------- ---------- ---------- ----------
$ 934,013 $ 365,197 $ 201,417 $ 172,804 $ 112,528 $ 171,723 $1,168,068
========== ========== ========== ========== ========== ========== ==========
FISCAL 1999
EXPLORATION AND PRODUCTION
Operations ............................ $ 221,634 $ -- $ 9,234 $ (2,859) $ 100,751 $ 240,708 $ 727,197
Proved property impairments ........... -- -- (42,250) (42,250) 42,250 -- --
Personnel reduction program costs ..... -- -- (8,524) (8,524) -- -- --
Water well litigation
provision reversals (Note 6) ....... -- -- 4,000 4,000 -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
221,634 -- (37,540) (49,633) 143,001 240,708 727,197
---------- ---------- ---------- ---------- ---------- ---------- ----------
GAS SERVICES
Natural gas processing ................ 253,295 72,043 (2,083) (5,357) 3,917 20,897 115,464
Natural gas gathering and marketing ... 211,387 232,377 23,483 19,634 10,900 24,816 143,320
Other ................................. 15,074 -- 13,949 13,551 107 713 79,884
Personnel reduction program costs ..... -- -- (7,128)(c) (7,128) -- -- --
Asset write-downs ..................... -- -- (7,560)(d) (7,560) 7,560 -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
479,756 304,420 20,661 13,140 22,484 46,426 338,668
---------- ---------- ---------- ---------- ---------- ---------- ----------
Corporate ............................. -- -- -- (19,552)(b) 2,946 2,268 80,611
---------- ---------- ---------- ---------- ---------- ---------- ----------
$ 701,390 $ 304,420 $ (16,879) $ (56,045) $ 168,431 $ 289,402 $1,146,476
========== ========== ========== ========== ========== ========== ==========
FISCAL 1998
EXPLORATION AND PRODUCTION
Operations ............................ $ 260,050 $ -- $ 62,528 $ 50,062 $ 91,858 $ 190,449 $ 677,712
Water well litigation
provision (Note 6)................... -- -- (7,000) (7,000) -- -- --
Gain from sale of
contract drilling assets ........... 2,382 -- 2,382 2,382 -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
262,432 -- 57,910 45,444 91,858 190,449 677,712
---------- ---------- ---------- ---------- ---------- ---------- ----------
GAS SERVICES
Natural gas processing ................ 329,990 26,591 28,330 25,178 3,843 13,824 162,429
Natural gas gathering and marketing ... 183,554 254,267 21,982 18,178 6,796 48,792 172,717
Other ................................. 14,526 -- 13,192 12,809 107 39 73,956
Royalty litigation provision .......... -- -- (26,000) (26,000) -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
528,070 280,858 37,504 30,165 10,746 62,655 409,102
---------- ---------- ---------- ---------- ---------- ---------- ----------
Corporate ............................. -- -- -- (12,173)(b) 3,009 5,188 139,103
---------- ---------- ---------- ---------- ---------- ---------- ----------
$ 790,502 $ 280,858 $ 95,414 $ 63,436 $ 105,613 $ 258,292 $1,225,917
========== ========== ========== ========== ========== ========== ==========
</TABLE>
- -----------------------------------
(a) On accrual basis, including exploratory expenditures and acquisitions.
(b) General corporate expenses; 1999 amount includes personnel reduction
program costs of $8,848.
(c) Natural gas processing $1,753; natural gas gathering and marketing $5,375.
(d) Natural gas processing $6,167; other $1,393.
36
<PAGE> 39
The Company's reported business segments are based on the organizational
structure used by management to assess performance and make resource allocation
decisions. The Company's three principal business segments are: exploration and
production, natural gas processing, and gas gathering and marketing. Exploration
and production segment operations include the exploration for and development
and production of natural gas and oil. Natural gas processing segment operations
include the extraction of natural gas liquids from natural gas processed at
facilities owned by the Company, its partnerships and third parties. The gas
gathering and marketing segment operates Company- and partnership-owned natural
gas gathering systems and markets natural gas through purchase and resale
transactions.
All of the Company's operations are conducted in the United States. Its
revenues are derived principally from uncollateralized sales to customers in the
electrical generation, gas distribution, petrochemical and oil and gas
industries. These industry concentrations have the potential to impact the
Company's exposure to credit risk, either positively or negatively, because
customers may be similarly affected by changes in economic or other conditions.
Intersegment revenues are recorded at prevailing market prices and are
eliminated in consolidation. Gas gathering and marketing sales to a single
customer constituted approximately 13% of consolidated revenues during fiscal
1999. Sales to no single customer constituted as much as 10% of consolidated
revenues in fiscal 2000 or 1998. Segment assets excluded net assets of
discontinued real estate operations of $26,056,000 at January 31, 1998.
The reported segment operating earnings amounts represent the operating
earnings of the Company's various industry segments before charges for
administrative, accounting, legal, information systems and other costs that are
managed on a companywide basis. In the reported total operating earnings
disclosures, all general and administrative expenses except for general
corporate expenses incurred in connection with the overall management of the
Company and the operation of the parent company have been allocated to the
industry segments based on their estimated use of these services.
Because of their magnitude and unusual nature, and in accordance with
Accounting Principles Board Opinion No. 30, the items discussed in the following
paragraphs have been reported as separate components of segment operating
earnings.
Fiscal 2000 items. During June 1999, the Company sold for cash all its oil and
gas properties in the Hell's Hole and Park Mountain fields in Colorado and Utah,
which consisted of 24,000 net leasehold acres with 36 producing wells and
associated pipelines, gathering systems and production facilities. A pretax gain
of $11,527,000 ($7,190,000 after tax) was recognized on this sale.
Fiscal 1999 items. Principally because of a prolonged depressed market for
energy products - particularly oil and NGLs - and forecasts that these
conditions would continue, the Company reviewed its proved oil and gas
properties for impairment at January 31, 1999. It was determined that
impairments totaling $42,250,000 were necessary to reduce the carrying values of
four fields to their estimated fair values (the present values of their
estimated future net cash flows).
During the fourth quarter of fiscal 1999, the Company implemented a
personnel reduction program which reduced its full-time employment level by 235
jobs. Aggregate pretax costs of this program - including $8,848,000 reported as
general and administrative expense - totaled $24,500,000. Of these costs,
$17,620,000 represented the present value of incremental pension and retiree
medical benefits provided under a voluntary incentive retirement program offered
to 127 employees (114 of whom accepted). Cash costs of severance and other
benefits totaled $6,880,000. The majority of the cash costs had been paid by
March 31, 1999, and no accrued liability for such costs remained at January 31,
2000.
During fiscal 1999's fourth quarter, gas services asset write-downs
totaling $7,560,000 were recorded. These charges principally involved
impairments of two plants that were shut down when their gas throughput was
redirected to other plants to improve the Company's overall profitability. The
resultant reduction of future cash flows for these plants required that their
carrying values be reduced to their estimated fair values - the salvage values
of the processing equipment.
37
<PAGE> 40
Fiscal 1998 items. In July 1997, the Company recorded a $26,000,000 financial
statement provision for estimated costs to be incurred in connection with
settlements of litigation with its North Texas royalty owners. In October 1997,
a $21,000,000 payment was made to settle class-action litigation brought on
behalf of these royalty owners. Payments totaling approximately $5,000,000 were
subsequently made to royalty owners who chose not to participate in the
class-action litigation.
Effective April 1, 1997, the Company sold its remaining contract drilling
assets for $3,500,000. A gain of $2,382,000 was recorded on this transaction.
NOTE 10 - INCENTIVE COMPENSATION PLANS
As long-term incentives, the Company periodically has issued awards that it
calls "bonus units" under which employees can earn compensation based on
increases in the market price of the Company's stock. Upon the redemption of
such awards, grantees receive gross compensation in amounts equal to the excess
of the market price of the Company's common stock over a floor price (the market
price of the stock when the units were awarded). The Company's 1991 Bonus Unit
Plan authorized the issuance of up to 700,000 units, all of which had been
granted and exercised by January 31, 1999. Up to 1,500,000 units may be granted
under the 1997 Bonus Unit Plan. A total of 227,950 ten-year bonus units - which
vest in three equal annual installments - were issued in December 1997 at a
floor price of $26.125. In March 1999, a total of 249,600 similar bonus units
were issued at a floor price of $12.3125. At January 31, 2000, all such units
were still outstanding.
Compensation expense is recognized over the applicable vesting terms of the
bonus units in amounts equal to the appreciation in the market price of the
stock over the applicable floor prices. Reversals are recognized to the extent
of previously recorded appreciation in periods when the market price of the
stock declines. Expense accruals (reversals) for bonus units aggregated
$1,671,000; $(27,000) and $636,000 in fiscal 2000, 1999 and 1998.
In December 1997, the Board of Directors approved the Company's 1997
Performance Unit Plan to help the Company retain key personnel in a very
competitive employment market. During December 1997, a total of 296,543
performance units were awarded to mid-level managerial and professional
employees. Some units were paid off in connection with fiscal 1999's personnel
reduction program, and individuals holding the remaining 235,584 units on March
31, 1999 received cash compensation equal to the closing price of the Company's
Class B stock on that day times the number of units awarded them. Compensation
expense, which was accrued ratably over the life of the outstanding units,
totaled $389,000; $2,417,000 and $771,000 in fiscal 2000, 1999 and 1998.
NOTE 11 - COMMON STOCK AND STOCK OPTIONS
The Company has two classes of common stock which are designated Class A and
Class B. Both classes are freely transferable and are listed on the New York
Stock Exchange; neither is convertible into the other class of common stock or
any other security of the Company at the option of the holder. The Class A
shares have full voting rights, whereas the Class B shares have no voting
rights, except as provided by law. The Company's Articles of Incorporation allow
cash dividends on Class B shares to be greater, but not less, than those paid on
Class A shares and also contain certain Class B shareholder protection
provisions.
The Company's 1995 Stock Option Plan and 1999 Stock Option Plan authorize
the granting of incentive and nonqualified options to purchase Class B common
stock at prices not less than the market value on the date of grant. The options
have maximum terms of 10 years and become exercisable ratably over three-year
periods. Grants covering a total of 2,500,000 and 1,750,000 Class B shares ,
respectively, may be made under the plans. At January 31, 2000, grants covering
an additional 219,268 shares could be issued under the 1995 Plan, and the
weighted average remaining contractual life of stock options outstanding under
this plan was 7.2 years. No options have been granted under the 1999 Plan.
Previously, the Company had granted options under 1979 and 1989 Stock Option
Plans, under which no further grants can be made. Summarized stock option
information follows.
38
<PAGE> 41
<TABLE>
<CAPTION>
1995 Plan 1979 and 1989 Plans
--------------------------------------------------- ------------------------------------------------
Options Exercisable Options Exercisable
Options Outstanding at Fiscal Year End Options Outstanding at Fiscal Year End
------------------------ ------------------------ ----------------------- ----------------------
Average Average Average Average
Number Price Number Price Number Price Number Price
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
At January 31, 1997 ...... 945,701 $ 17.885 149,098 $ 17.633 178,500 $ 19.624 118,500 $ 19.213
February 21, 1997 grants.. 602,490 21.750 --
December 17, 1997 grants.. 347,050 26.125 --
Exercised ................ (143,003) 17.911 (25,830) 18.186
Cancelled ................ (7,883) 19.680 --
---------- ----------
At January 31, 1998 ...... 1,744,355 20.849 369,669 18.048 152,670 19.868 92,670 19.499
Exercised ................ (135,867) 19.942 (1,000) 10.250
Cancelled ................ (3,165) 21.750 --
---------- ----------
At January 31, 1999 ...... 1,605,323 20.924 908,442 19.715 151,670 19.931 151,670 19.931
March 5, 1999 grants ..... 405,400 12.312 --
Exercised ................ -- -- (10,000) 17.250
Cancelled ................ (24,360) 19.449 --
---------- ----------
At January 31, 2000 ...... 1,986,363 19.185 1,331,294 20.454 141,670 20.120 141,670 20.120
========== ==========
</TABLE>
Stock options are accounted for under the provisions of APB Opinion No. 25.
As a result, the Company generally does not recognize compensation expense in
its financial statements for outstanding stock options. Had grants under the
1995 Plan been accounted for on the estimated fair-value basis promulgated by
SFAS No. 123, the Company would have recorded additional compensation expense of
$2,159,000; $3,620,000 and $3,977,000 in fiscal 2000, 1999 and 1998. On a
proforma basis, earnings from continuing operations would have been reduced by
$1,404,000; $2,353,000 and $2,585,000 in fiscal 2000, 1999 and 1998, and basic
earnings per share from continuing operations for both the Class A and Class B
shares would have been lowered by 3 cents, 5 cents and 5 cents, respectively.
The additional compensation expense under the estimated fair-value basis was
computed using the Black-Scholes option-pricing model, expected lives of seven
years, annual cash dividends of 53 cents per share (the regular rate paid on the
Class B shares for the last several years) and the following interest and
volatility rates, which were determined at the dates of the individual grants:
<TABLE>
<CAPTION>
2/21/97 12/17/97 3/05/99
---------- ---------- ----------
<S> <C> <C> <C>
Risk-free interest rate (%) ............................................ 6.27 5.82 5.34
Stock price volatility rate (%) ........................................ 28.6 28.0 29.7
Computed value per option share ........................................ $ 7.55 $ 9.15 $ 3.17
</TABLE>
NOTE 12 - EARNINGS (LOSS) PER SHARE
The Company is required to make separate earnings per share computations for its
Class A and Class B common stock since the shares are not convertible into each
other and different per share cash dividends are paid on the separate classes.
In those computations, differences between earnings from continuing operations
and total dividends paid are apportioned between the classes on a prorata
per-share basis and then added to the respective dividends paid to each of the
classes. Accordingly, the differences in earnings per share for Class A and
Class B shares occur because of the dividend premium on the Class B shares. The
following table sets forth basic and diluted earnings (loss) per share
information for the years ended January 31, 2000, 1999 and 1998:
<TABLE>
<CAPTION>
2000 1999 1998
------------------- -------------------- --------------------
Class A Class B Class A Class B Class A Class B
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
From continuing operations .................. $ 1.95 $ 2.00 $ (1.11) $ (1.05) $ .71 $ .77
-------- -------- -------- -------- -------- --------
Discontinued real estate operations
Earnings from operations ................. -- -- -- -- .14 .15
Loss on sale ............................. -- -- .07 .06 (1.26) (1.37)
-------- -------- -------- -------- -------- --------
-- -- .07 .06 (1.12) (1.22)
-------- -------- -------- -------- -------- --------
Extraordinary item .......................... -- -- -- -- (.25) (.27)
-------- -------- -------- -------- -------- --------
Net earnings (loss) ......................... $ 1.95 $ 2.00 $ (1.04) $ (.99) $ (.66) $ (.72)
-------- -------- -------- -------- -------- --------
</TABLE>
39
<PAGE> 42
There were no differences in the reported basic and diluted earnings per share
because the earnings (loss) amounts were the same in the basic and diluted
computations, and the dilutive effect of stock options did not significantly
increase the number of weighted average shares outstanding. The following table
reconciles the weighted average shares outstanding used in the basic and diluted
computations for the years ended January 31, 2000, 1999 and 1998 (in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
------------------- ------------------- -------------------
Class A Class B Class A Class B Class A Class B
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Used in basic computations ............. 22,322 26,796 22,321 26,785 22,714 27,989
Dilutive effect of stock options ....... -- 150 -- -- 9 198
-------- -------- -------- -------- -------- --------
Used in diluted computations ........... 22,322 26,946 22,321 26,785 22,723 28,187
======== ======== ======== ======== ======== ========
</TABLE>
Excluded from these computations because their effect would have been
antidilutive were stock options covering 72,008 Class A and 925,136 Class B
shares in 2000; 78,258 Class A and 1,678,735 Class B shares in 1999 and 347,050
Class B shares in 1998.
NOTE 13 - DISCONTINUED REAL ESTATE OPERATIONS
On June 12, 1997, the Company entered into an agreement to sell its real estate
subsidiary, The Woodlands Corporation (TWC), to a partnership of Crescent Real
Estate Equities Company and Morgan Stanley Real Estate Fund II, L.P. for
$543,000,000 in cash. The transaction was subsequently closed on July 31, 1997.
In connection with the sale, the parent company forgave intercompany debt
payable to it by TWC. After adjustment for certain net additional amounts
received pursuant to the contract and deductions for income taxes and
transaction costs incurred by the Company in connection with the sale, net cash
sales proceeds totaled $480,994,000.
The Company decided to withdraw from the real estate business during fiscal
1998 and commenced reporting real estate activities as discontinued operations
at that time. The Company's financial statements were revised to segregate the
net assets associated with the discontinued operations and to separately report
their results of operations. Prior-year financial statements were restated
similarly. Interest expense attributable to discontinued operations was
determined in the same manner that historically had been used to allocate such
costs to the Company's real estate operations. After an income tax benefit of
$25,878,000, a net loss of $67,123,000 was recorded in connection with the
discontinuance of the Company's real estate activities.
During the first quarter of fiscal 1999, adjustments were recorded reducing
by $3,250,000 ($5,000,000 pretax) the $67,123,000 loss on disposition previously
recorded in connection with the discontinuance of real estate operations. The
reduction occurred because actual realizations were higher than originally
estimated and certain contingent obligations were settled for less than the
amounts accrued. The Company ceased segregating discontinued operations during
fiscal 1999 since the liquidation of the remaining real estate properties had
been substantially completed.
NOTE 14 - EXTRAORDINARY ITEM
During fiscal 1998, the Company repurchased $185,733,000 face amount of its
9 1/4% senior notes due January 15, 2002. In connection with the repurchase,
costs of $20,385,000 were expensed, including cash costs of $19,294,000
associated with a tender offer for these notes and the write-off of $1,091,000
in deferred financing costs. After an income tax benefit of $7,135,000, an
extraordinary charge of $13,250,000 was recorded in connection with this
extinguishment of debt.
40
<PAGE> 43
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Mitchell Energy & Development Corp.:
We have audited the accompanying consolidated balance sheets of Mitchell
Energy & Development Corp. (a Texas corporation) and subsidiaries as of January
31, 2000 and 1999, and the related consolidated statements of earnings,
stockholders' equity and cash flows for each of the three years in the period
ended January 31, 2000. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. 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, the financial statements referred to above present fairly,
in all material respects, the financial position of Mitchell Energy &
Development Corp. and subsidiaries as of January 31, 2000 and 1999, and the
results of their operations and their cash flows for each of the three years in
the period ended January 31, 2000, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
April 3, 2000
41
<PAGE> 44
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
Reserve quantities. Proved reserves are the estimated quantities which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under economic and operating
conditions at each year end. Proved developed reserves are expected to be
recovered from existing wells using existing equipment and operating methods.
Consolidated reserves represent the Company's net interest in oil and gas
properties or in reserves committed to Company-owned gas processing plants.
Equity partnership reserves represent the Company's proportional interest in the
reserves of partnerships that are accounted for using the equity method.
The following tables summarize changes in the Company's natural gas (gas),
crude oil and condensate (oil) and plant NGL reserve quantities during the
indicated fiscal years and the proved developed reserve quantities at the dates
indicated:
<TABLE>
<CAPTION>
2000 1999 1998
---------------------------- ---------------------------- ----------------------------
PROVED GAS Gas Oil Gas Oil Gas Oil
AND OIL RESERVES MBOE* (Bcf) (MMBbls) MBOE* (Bcf) (MMBbls) MBOE* (Bcf) (MMBbls)
-------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Beginning balance ................. 160.7 866.5 16.2 145.3 777.5 15.7 130.1 701.2 13.3
Extensions and discoveries ........ 49.5 289.8 1.2 21.5 121.3 1.3 32.9 177.5 3.3
Production marketed ............... (17.1) (89.8) (2.1) (17.6) (90.4) (2.5) (16.7) (87.0) (2.2)
Production consumed in operations.. (.8) (4.5) -- (.6) (3.6) -- (.6) (3.6) --
Purchases in place ................ -- .1 -- 15.2 73.8 2.9 .9 1.8 .6
Revisions of previous estimates ... (8.0) (39.9) (1.3) (2.7) (11.2) (.9) (2.5) (12.3) (.5)
Sales in place .................... (1.6) (8.6) (.2) (.4) (1.0) (.3) (.4) (1.5) (.2)
Improved recovery ................. -- -- -- -- .1 -- 1.6 1.4 1.4
-------- -------- -------- -------- -------- -------- -------- -------- --------
Ending balance .................... 182.7 1,013.6 13.8 160.7 866.5 16.2 145.3 777.5 15.7
======== ======== ======== ======== ======== ======== ======== ======== ========
</TABLE>
- -----------------------------------
* Million barrels of oil equivalent using a 6-to-1 conversion factor for gas.
<TABLE>
<CAPTION>
2000 1999 1998
---------------------------- ---------------------------- ----------------------------
PROVED PLANT NGL Consol- Partner- Consol- Partner- Consol- Partner-
RESERVES (MMBbls) Total idated ships Total idated ships Total idated ships
-------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Beginning balance ................. 139.0 99.2 39.8 146.5 100.5 46.0 126.4 86.3 40.1
Additions ......................... 28.2 27.1 1.1 13.2 13.2 -- 18.5 18.5 --
Production ........................ (16.5) (12.7) (3.8) (15.0) (10.4) (4.6) (16.5) (11.3) (5.2)
Purchase of plant interests ....... 15.2 15.2 -- 4.2 -- 4.2 2.7 2.7 --
Transfer of partnership interest .. -- 15.2 (15.2) -- -- -- -- -- --
Revisions of previous estimates ... 11.9 3.5 8.4 (9.9) (4.1) (5.8) 15.4 4.3 11.1
-------- -------- -------- -------- -------- -------- -------- -------- --------
Ending balance .................... 177.8 147.5 30.3 139.0 99.2 39.8 146.5 100.5 46.0
======== ======== ======== ======== ======== ======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
2000 1999 1998 1997
-------- -------- -------- --------
<S> <C> <C> <C> <C>
PROVED DEVELOPED RESERVES AT FISCAL YEAR END
Gas (Bcf) ................................. 657.9 683.6 640.0 611.0
======== ======== ======== ========
Oil (MMBbls) .............................. 13.3 15.0 14.5 12.5
======== ======== ======== ========
Plant NGLs (MMBbls)
Consolidated ........................... 118.3 76.7 86.3 78.4
Equity partnerships .................... 24.2 33.3 44.8 39.1
-------- -------- -------- --------
142.5 110.0 131.1 117.5
======== ======== ======== ========
</TABLE>
Future net cash flows from natural gas and oil reserves. The following tables
set forth estimates of the standardized measure of discounted future net cash
flows from proved gas and oil reserves at January 31, 2000, 1999 and 1998 and a
summary of the changes in those amounts for the fiscal years then ended (in
millions):
<TABLE>
<CAPTION>
2000 1999 1998
---------- ---------- ----------
<S> <C> <C> <C>
STANDARDIZED MEASURE
Future cash inflows ......................... $ 3,394 $ 1,760 $ 2,060
Future production and development costs ..... (1,491) (1,034) (923)
Future income taxes ......................... (572) (145) (331)
Discount - 10% annually ..................... (529) (190) (325)
---------- ---------- ----------
$ 802 $ 391 $ 481
========== ========== ==========
</TABLE>
42
<PAGE> 45
<TABLE>
<CAPTION>
2000 1999 1998
-------- -------- --------
<S> <C> <C> <C>
CHANGES IN STANDARDIZED MEASURE
Extensions and discoveries, net of related costs ...... $ 188 $ 50 $ 120
Sales, net of production costs ........................ (194) (146) (185)
Net changes in prices and production costs ............ 692 (274) (726)
Accretion of discount ................................. 42 63 129
Production rate changes and other ..................... (23) 18 (7)
Development costs incurred ............................ 26 25 13
Purchases in place .................................... -- 71 5
Sales in place ........................................ (13) (2) (2)
Revisions of previous quantity estimates .............. (63) (9) (13)
Net change in future income taxes ..................... (244) 114 207
-------- -------- --------
$ 411 $ (90) $ (459)
======== ======== ========
</TABLE>
Future net cash flows from plant NGL reserves. The following tables set forth
estimates of the standardized measure of discounted future net cash flows from
proved NGL reserves at January 31, 2000, 1999 and 1998 and a summary of the
changes in those amounts for the fiscal years then ended (in millions):
<TABLE>
<CAPTION>
2000 1999 1998
------------------------------ ------------------------------ ------------------------------
Equity Equity Equity
Consol- Partner- Consol- Partner- Consol- Partner-
Total idated ships Total idated ships Total idated ships
-------- -------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
STANDARDIZED MEASURE
Future cash inflows ............. $ 3,744 $ 3,171 $ 573 $ 1,309 $ 956 $ 353 $ 1,782 $ 1,237 $ 545
Future production costs ......... (2,710) (2,364) (346) (1,108) (809) (299) (1,467) (1,007) (460)
Future income taxes ............. (347) (265) (82) (59) (45) (14) (103) (73) (30)
Discount - 10% annually ......... (299) (231) (68) (56) (41) (15) (88) (65) (23)
-------- -------- -------- -------- -------- -------- -------- -------- --------
$ 388 $ 311 $ 77 $ 86 $ 61 $ 25 $ 124 $ 92 $ 32
======== ======== ======== ======== ======== ======== ======== ======== ========
CHANGES IN STANDARDIZED MEASURE
Additions, net of related costs.. $ 88 $ 83 $ 5 $ 11 $ 11 $ -- $ 25 $ 25 $ --
Sales, net of production costs... (53) (37) (16) (9) (3) (6) (33) (20) (13)
Net changes in prices and costs.. 307 201 106 (73) (58) (15) (161) (113) (48)
Accretion of discount ........... 11 8 3 18 13 5 30 21 9
Purchase of plant interests ..... 44 44 -- 5 -- 5 1 1 --
Transfer of partnership
interest ..................... -- 44 (44) -- -- -- -- -- --
Revisions of previous
quantity estimates ........... 44 11 33 (8) (4) (4) 21 9 12
Other ........................... 18 13 5 (8) (5) (3) (4) (1) (3)
Net change in future
income taxes.................. (157) (117) (40) 26 15 11 39 23 16
-------- -------- -------- -------- -------- -------- -------- -------- --------
$ 302 $ 250 $ 52 $ (38) $ (31) $ (7) $ (82) $ (55) $ (27)
======== ======== ======== ======== ======== ======== ======== ======== ========
</TABLE>
The natural gas reserve quantities reported as gas and oil reserves
represent wet gas volumes, including quantities that will be converted to NGLs
by processing. As it relates to NGLs to be extracted in processing, the gas and
oil future net cash flows include only the leasehold reimbursements for such
NGLs; the other cash flows (amounts in excess of the leasehold reimbursements)
associated with NGLs to be extracted from the Company's wet gas reserves are
included in plant NGL amounts since those cash flows are attributable to the
Company's gas processing plants.
The quantities reported herein for plant NGLs include all liquids that will
be extracted from gas streams contractually committed to Company-owned gas
processing plants since the Company, as plant owner, generally has beneficial
ownership of all the NGLs so produced. Accordingly, the plant NGL reserves and
future net cash flows include amounts attributable to NGLs extracted from gas
streams owned by the Company and by third parties. The Company reimburses the
owners of the natural gas streams for associated NGLs in accordance with the
applicable contract provisions. Such reimbursements - including amounts
attributable to the Company's oil and gas leasehold interests that are included
in oil and gas future net cash flows - are deducted as production costs in
determining future net cash flows from plant NGLs.
Of the total remaining natural gas reserves at January 31, 2000, an
estimated 588.0 Bcf will be processed at Company plants, including 161.1 Bcf of
fiscal 2000's natural gas reserve additions from extensions and discoveries. It
is estimated that
43
<PAGE> 46
93.4 Bcf of such reserves and 21.7 Bcf of such reserve additions will be
converted by processing into 50.8 MMBbls and 11.8 MMBbls of plant NGLs,
respectively.
Except where otherwise specified by contractual agreement, future cash
inflows are estimated using year-end prices. Future production and development
cost estimates are based on economic conditions at the respective year ends.
Future income taxes are computed by applying applicable statutory tax rates to
the difference between the estimated future net revenues and the tax basis of
proved oil and gas properties after considering tax credit carryforwards,
estimated future percentage depletion deductions and energy tax credits.
Reserve estimates are subject to numerous uncertainties inherent in
estimating quantities of proved reserves and in the projection of future rates
of production and the timing of development expenditures. The accuracy of such
estimates is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of subsequent drilling, testing
and production may cause either upward or downward revisions of previous
estimates. Further, the volumes considered to be commercially recoverable
fluctuate with changes in prices and operating costs. Because of the
aforementioned factors, reserve estimates are generally less precise than other
financial statement disclosures.
Discounted future cash flow estimates such as those shown herein are not
intended to represent estimates of the fair market value of oil and gas
properties. Estimates of fair market value also should consider probable
reserves, anticipated future oil and gas prices and interest rates, changes in
development and production costs and risks associated with future production.
Because of these and other considerations, any estimate of fair market value is
necessarily subjective and imprecise.
Gas and oil related costs and operating results. The following tables set forth
capitalized costs at January 31, 2000, 1999 and 1998 and costs incurred and
operating results for oil and gas producing activities for the years then ended
(in thousands):
<TABLE>
<CAPTION>
2000 1999 1998
------------ ------------ ------------
<S> <C> <C> <C>
CAPITALIZED COSTS
Oil and gas properties .................................................... $ 1,893,057 $ 1,863,422 $ 1,690,693
Support equipment and facilities .......................................... 50,241 50,612 48,467
Accumulated depreciation, depletion and amortization ...................... (1,236,209) (1,213,835) (1,107,188)
------------ ------------ ------------
Net capitalized costs ..................................................... $ 707,089 $ 700,199 $ 631,972
============ ============ ============
COSTS INCURRED (including exploration expenses and
exploratory well impairments of $8,517; $25,807 and $22,376)
Unproved property acquisitions ............................................ $ 5,964 $ 11,908 $ 17,099
Proved property acquisitions .............................................. -- 71,662 4,666
Exploration ............................................................... 9,554 29,683 34,297
Development ............................................................... 108,628 124,574 132,167
------------ ------------ ------------
Costs incurred ............................................................ 124,146 237,827 188,229
Support equipment and facilities .......................................... 765 2,881 2,220
------------ ------------ ------------
Capital and exploratory expenditures ...................................... $ 124,911 $ 240,708 $ 190,449
============ ============ ============
OPERATING RESULTS (before charges for
general and administrative and interest expense)
Production revenues ....................................................... $ 264,151 $ 220,416 $ 256,286
Other revenues ............................................................ 1,666 1,218 3,764
------------ ------------ ------------
265,817 221,634 260,050
Less - Production costs ................................................... 69,735 74,193 70,919
Depreciation, depletion and amortization (including
proved-property impairments of none, $42,250 and $1,640) ....... 95,205 143,001 91,858
Exploration expenses ............................................... 6,008 21,620 17,059
Exploratory well impairments ....................................... 2,509 4,187 5,317
Other operating costs .............................................. 11,136 11,649 12,369
------------ ------------ ------------
Segment operating earnings ................................................ 81,224 (33,016) 62,528
Income taxes .............................................................. 26,334 (12,438) 21,399
------------ ------------ ------------
$ 54,890 $ (20,578) $ 41,129
============ ============ ============
</TABLE>
44
<PAGE> 47
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
HISTORICAL SUMMARY
Five Years Ended January 31, 2000 (in thousands except where otherwise
indicated)
<TABLE>
<CAPTION>
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
FINANCIAL POSITION AT YEAR END
Net property, plant and equipment ............................... $1,055,439 $1,033,738 $ 954,667 $ 775,929 $ 719,535
Total assets .................................................... 1,168,068 1,146,476 1,251,973 1,668,272 1,599,183
Capital employed
Long-term debt ............................................... $ 369,267 $ 362,467* $ 414,267 $ 600,000* $ 795,000
Deferred income taxes ........................................ 161,338 130,069 167,903 109,459 66,696
Retirement obligations and other liabilities ................. 86,639 87,371 58,128 54,539 72,832
Stockholders' equity ......................................... 398,542 324,774 412,926 555,287 481,903
---------- ---------- ---------- ---------- ----------
$1,015,786 $ 904,681 $1,053,224 $1,319,285 $1,416,431
========== ========== ========== ========== ==========
CAPITAL AND EXPLORATORY EXPENDITURES (accrual basis)
Exploration and Production
Capital ...................................................... $ 116,394 $ 214,901 $ 168,073 $ 116,224 $ 126,915
Exploratory expenses/impairments ............................. 8,517 25,807 22,376 18,051 14,752
Gas services .................................................... 46,218 46,426 62,655 34,233 38,358
Corporate ....................................................... 594 2,268 5,188 7,318 6,068
---------- ---------- ---------- ---------- ----------
$ 171,723 $ 289,402 $ 258,292 $ 175,826 $ 186,093
========== ========== ========== ========== ==========
OPERATING STATISTICS
Average daily volumes
Natural gas sales (Mcf) ...................................... 246,100 247,600 238,200 228,500 216,200
Crude oil and condensate sales (Bbls) ........................ 5,900 6,800 6,200 5,500 5,400
Natural gas liquids produced (Bbls) .......................... 45,100 41,100 45,300 46,100 44,500
Pipeline throughput (Mcf) .................................... 567,000 554,000 426,000 410,000 354,000
Average annual sales price (dollars)
Natural gas (per Mcf) ........................................ $ 2.50 $ 2.11 $ 2.47 $ 2.64 $ 2.16
Crude oil and condensate (per Bbl) ........................... 18.49 12.18 18.50 21.50 16.91
Natural gas liquids produced (per Bbl) ....................... 15.07 10.23 13.38 16.13 11.55
Drilling program (gross wells)
Wells drilled ................................................ 127 165 272 209 116
Wells completed .............................................. 113 144 252 185 107
Well count at year end (gross wells) ............................ 3,368 3,308 3,273 3,090 3,047
STOCKHOLDERS' EQUITY (per share at year end) .................... $ 8.11 $ 6.61 $ 8.42 $ 10.71 $ 9.26
CASH DIVIDENDS PER SHARE
Class A (including special dividend of 24 cents in 1998) ........ $ .48 $ .48 $ .72 $ .48 $ .48
Class B (including special dividend of 26.5 cents in 1998) ...... .53 .53 .795 .53 .53
AVERAGE COMMON SHARES OUTSTANDING (Basic)
Class A ......................................................... 22,322 22,321 22,714 23,092 23,217
Class B ......................................................... 26,796 26,785 27,989 28,786 28,827
</TABLE>
- ---------------------------------------------------------------
* Excludes current maturities of $100,000.
45
<PAGE> 48
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
HISTORICAL SUMMARY
Five Years Ended January 31, 2000 (in thousands except per-share data)
<TABLE>
<CAPTION>
2000 1999 1998 1997 1996
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
REVENUES
Exploration and Production (including gain
of $205,256 from natural gas contract buyout in 1996) ........ $ 277,344 $ 221,634 $ 262,432 $ 269,862 $ 424,661
Gas Services
Natural gas processing ....................................... 409,448 253,295 329,990 376,980 283,378
Natural gas gathering and marketing .......................... 235,886 211,387 183,554 247,214 184,584
Other ........................................................ 11,335 15,074 14,526 12,621 10,296
--------- --------- --------- --------- ---------
Total revenues ............................................. $ 934,013 $ 701,390 $ 790,502 $ 906,677 $ 902,919
========= ========= ========= ========= =========
SEGMENT OPERATING EARNINGS
Exploration and Production
Operations ................................................... $ 81,224 $ 9,234 $ 62,528 $ 81,432 $ 35,775
Litigation (provisions) reversals ............................ 15,200 4,000 (7,000) (10,000) (15,000)
Gains from asset sales ....................................... 11,527 -- 2,382 -- 5,338
Proved property impairments .................................. -- (42,250) -- -- --
Gain from natural gas contract buyout ........................ -- -- -- -- 205,256
Personnel reduction program costs ............................ -- (8,524) -- -- (7,935)
Severance tax refunds ........................................ -- -- -- 5,935 --
Columbia Gas contract settlement proceeds .................... -- -- -- 3,444 --
Gas Services
Natural gas processing ....................................... 55,860 (2,083) 28,330 69,110 30,994
Natural gas gathering and marketing .......................... 27,029 23,483 21,982 27,589 14,063
Other ........................................................ 10,577 13,949 13,192 11,397 9,059
--------- --------- --------- --------- ---------
Operations subtotal ........................................ 93,466 35,349 63,504 108,096 54,116
Asset write-downs ............................................ -- (7,560) -- -- (52,715)
Personnel reduction program costs ............................ -- (7,128) -- -- (3,600)
Litigation provision ......................................... -- -- (26,000) -- --
--------- --------- --------- --------- ---------
Total segment operating earnings (loss) .................... 201,417 (16,879) 95,414 188,907 221,235
General and administrative expense (including personnel
reduction program costs of $8,848 in 1999
and $4,532 in 1996) .......................................... 28,613 39,166 31,978 30,823 35,760
Interest expense attributable to continuing operations .......... 34,036 35,070 27,419 22,775 27,341
Interest income ................................................. (284) (885) (8,899) (650) (111)
Other (income) expense, net ..................................... (7,513) (5,637) (5,819) 2,202 2,113
--------- --------- --------- --------- ---------
EARNINGS (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES... 146,565 (84,593) 50,735 133,757 156,132
Income taxes .................................................... 49,329 (31,631) 12,909 47,456 55,420
--------- --------- --------- --------- ---------
EARNINGS (LOSS) FROM CONTINUING OPERATIONS ...................... 97,236 (52,962) 37,826 86,301 100,712
--------- --------- --------- --------- ---------
AFTER-TAX EARNINGS (LOSS) FROM DISCONTINUED OPERATIONS
(including $67,123 loss on disposal in 1998) ................. -- 3,250 (59,683) 16,925 (63,583)
--------- --------- --------- --------- ---------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM ....................... 97,236 (49,712) (21,857) 103,226 37,129
Extraordinary item (extinguishment of debt) ..................... -- -- (13,250) -- --
--------- --------- --------- --------- ---------
NET EARNINGS (LOSS) ............................................. $ 97,236 $ (49,712) $ (35,107) $ 103,226 $ 37,129
========= ========= ========= ========= =========
EARNINGS (LOSS) PER SHARE (Basic and Diluted)
Class A - From continuing operations ............................ $ 1.95 $ (1.11) $ .71 $ 1.64 $ 1.91
Net earnings .......................................... 1.95 (1.04) (.66) 1.96 .69
Class B - From continuing operations ............................ 2.00 (1.05) .77 1.68 1.96
Net earnings .......................................... 2.00 (.99) (.72) 2.01 .74
</TABLE>
46
<PAGE> 49
BOARD OF DIRECTORS
================================================================================
GEORGE P. MITCHELL
Chairman and Chief Executive Officer,
Mitchell Energy & Development Corp.
BERNARD F. CLARK
Vice Chairman,
Mitchell Energy & Development Corp.
W. D. STEVENS (3)
President and Chief Operating Officer,
President--Exploration and Production,
Mitchell Energy & Development Corp.
ROBERT W. BALDWIN (1) (2)
Consultant (energy/management);
retired President, Gulf Refining
and Marketing Company
(a division of Gulf Oil Corp.), Houston
WILLIAM D. EBERLE (1) (3)
Chairman,
Manchester Associates, Ltd.
(international business consulting),
Boston; Of Counsel on trade issues to
Kaye, Scholer, Fierman, Hays and
Handler (attorneys), Washington, D.C.
SHAKER A. KHAYATT (2)
President and Chief Executive Officer,
Khayatt and Company, Inc.
(investment banking), New York City
BEN F. LOVE (2) (3)
Advisory Director,
Chase Bank of Texas, N.A., and retired
Chairman and Chief Executive Officer,
Texas Commerce Bancshares
(now Chase Bank of Texas), Houston
J. TODD MITCHELL (3)
President,
GPM, Inc. (private investments),
The Discovery Bay Company
(seismic software) and
Dolomite Resources, Inc.
(exploration and investments), Houston
M. KENT MITCHELL (1) (3)
President and Chief Executive Officer,
Bald Head Island Management, Inc.
(real estate development),
Bald Head Island, North Carolina
- ------------------------------------
(1) Compensation Committee
(2) Audit Committee
(3) Executive Committee
47
<PAGE> 50
PRINCIPAL OFFICERS
================================================================================
GEORGE P. MITCHELL
Chairman and Chief Executive Officer
W. D. STEVENS
President and Chief Operating Officer,
President--Exploration and Production Division
[PHOTO] [PHOTO]
BERNARD F. CLARK ALLEN J. TARBUTTON, JR.
Vice Chairman Corporate Senior Vice President,
President--Gas Services Division
[PHOTO] [PHOTO]
PHILIP S. SMITH THOMAS P. BATTLE
Corporate Senior Vice President, Corporate Senior Vice President,
Chief Financial Officer and General Counsel and Secretary
President--Administration and
Financial Division
48
<PAGE> 51
CORPORATE INFORMATION
================================================================================
STOCK LISTINGS
New York Stock Exchange
Pacific Exchange
Ticker Symbols: MNDA (voting)
MNDB (non-voting)
Options Trading: Pacific Exchange
TRANSFER AGENT AND REGISTRAR
ChaseMellon Shareholder Services, L.L.C.
85 Challenger Road
Overpeck Centre
Ridgefield, NJ 07660-2104
Toll-free: (800) 635-9270
www.chasemellon.com
ANNUAL MEETING
10 a.m. CDT
Wednesday, June 28, 2000
Mitchell Learning Center Auditorium
2002 Timberloch Place, 3rd Floor
The Woodlands, TX 77380-1148
FORM 10-K
Copies of the Company's
Form 10-K are available upon request to:
Public Affairs Department
Mitchell Energy & Development Corp.
P.O. Box 4000
The Woodlands, TX 77387-4000
Phone: (713) 377-5650
WORLDWIDE WEB
www.mitchellenergy.com
Design: John Weaver Design/Houston
<PAGE> 52
[LOGO]
MITCHELL ENERGY & DEVELOPMENT CORP.
P.O. Box 4000
2001 Timberloch Place
The Woodlands, Texas 77387-4000
(713) 377-5500
www.mitchellenergy.com
An Equal Opportunity Employer
<PAGE> 1
Exhibit 21
Mitchell Energy & Development Corp.
SUBSIDIARIES
Listings of the Company's major subsidiaries and partnership interests at
January 31, 2000 follow. These entities, along with others which in the
aggregate are not significant, are included in the financial statements
appearing in the Company's Annual Report to Stockholders. Parent/subsidiary
relationships are indicated by indentions. Except where otherwise indicated,
each subsidiary is incorporated in Delaware and is 100% owned by its parent.
CONSOLIDATED SUBSIDIARIES
MND Energy Corporation
Mitchell Energy Corporation
Mitchell Gas Corporation
Acacia Natural Gas Corporation (Oklahoma)
Bridgeport Gas Header Company
Mitchell Gas Operating, Inc. (MGOI)
Mitchell Louisiana Gas Services, Inc. (MLGS)
MND Gas Services, LLC
Mitchell Gas Services LP (MGSLP) (99% owned by MND Gas Service, LLC
and 1% owned by MGOI)
Southwestern Gas Pipeline, Inc.
MND Service, Inc.
Mitchell Receivables Corporation
Mitchell Resorts, Inc.
The Woodlands Venture Capital Company
PARTNERSHIP INTERESTS (accounted for on equity basis)
Austin Chalk Natural Gas Marketing Services (45% owned by MGSLP)*
Belvieu Environmental Fuels (33.33% owned by MGSLP)
C&L Processors Partnership (50% owned by MGSLP)*
Ferguson-Burleson County Gas Gathering System (45% owned by MGSLP)*
Gulf Coast Fractionators (38.75% owned by MGSLP)
Louisiana Chalk Gathering System (50% owned by MLGS)
UP Bryan Plant (45% owned by MGSLP)*
* As discussed in Note 3 of Notes to Consolidated Financial Statements,
these entities ceased their separate operations on March 31, 2000.
<PAGE> 1
Exhibit 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our reports included or incorporated by reference in this Form 10-K, into the
Company's previously filed Form S-8 Registration Statement Nos. 2-86550,
33-26276, 33-31446, 333-06981, 333-24335 and 333-87047 and into previously filed
Form S-3 Registration Statement Nos. 33-57332 and 33-61070.
ARTHUR ANDERSEN LLP
Houston, Texas
April 26, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> JAN-31-2000
<PERIOD-END> JAN-31-2000
<CASH> 15,957
<SECURITIES> 0
<RECEIVABLES> 46,406
<ALLOWANCES> 303
<INVENTORY> 7,178
<CURRENT-ASSETS> 75,432
<PP&E> 2,548,079
<DEPRECIATION> 1,492,640
<TOTAL-ASSETS> 1,168,068
<CURRENT-LIABILITIES> 152,282
<BONDS> 369,267
0
0
<COMMON> 5,386
<OTHER-SE> 393,156
<TOTAL-LIABILITY-AND-EQUITY> 1,168,068
<SALES> 934,013
<TOTAL-REVENUES> 934,013
<CGS> 0
<TOTAL-COSTS> 732,596
<OTHER-EXPENSES> 20,816
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 34,036
<INCOME-PRETAX> 146,565
<INCOME-TAX> 49,329
<INCOME-CONTINUING> 97,236
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 97,236
<EPS-BASIC> 1.95<F1>
<EPS-DILUTED> 1.95<F2>
<FN>
<F1>Earnings per share - primary
Class A Shares 1.95
Class B Shares 2.00
<F2>Earnings per share - fully diluted
Class A Shares 1.95
Class B Shares 2.00
</FN>
</TABLE>
<PAGE> 1
EXHIBIT 99
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 11-K
[X] ANNUAL REPORT PURSUANT TO SECTION 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED JANUARY 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-6959
----------------------
MITCHELL ENERGY & DEVELOPMENT CORP.
THRIFT AND SAVINGS PLAN
----------------------
MITCHELL ENERGY & DEVELOPMENT CORP.
(Name of issuer of securities held pursuant to the Plan)
P. O. Box 4000, The Woodlands, Texas 77387-4000
(Address of Plan and principal executive office of issuer)
The financial statements and schedules of the Mitchell Energy & Development
Corp. Thrift and Savings Plan required to be filed on Form 11-K by Section 15(d)
of the Securities Exchange Act of 1934 will be filed as an amendment to this
Form 10-K.
