<PAGE> 1
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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, 1995
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. [ ]
The aggregate market value of voting stock held by nonaffiliates
of the registrant at
March 31, 1995 was approximately $152,655,000
Shares of common stock outstanding at March 31, 1995:
Class A - 23,207,425
Class B - 28,815,124
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, 1995 - Parts I and II.
Definitive Proxy Statement to be filed within 120 days after
January 31, 1995 - Part III.
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<PAGE> 2
PART I
ITEM 1 - BUSINESS
Except for a discussion of competition, 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,
1995 furnished to the Commission pursuant to Rule 14a-3(b) under the Securities
Exchange Act of 1934 (Annual Report to Stockholders).
<TABLE>
<CAPTION>
CROSS REFERENCE TO APPLICABLE SECTIONS
OF ANNUAL REPORT TO STOCKHOLDERS PAGE
-------------------------------------- ------------
<S> <C>
Inside
The Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Front Cover
Energy Operations - Exploration and Production Division . . . . . . . . . . . . . . . 10-14, 16
Energy Operations - Gas Services Division . . . . . . . . . . . . . . . . . . . . . . 17 - 20
Real Estate Division . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24-28, 30
Notes to Consolidated Financial Statements
Note 10: Segment Information . . . . . . . . . . . . . . . . . . . . . . . . . . . 62 - 64
</TABLE>
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 nation's largest independent oil and gas producers and is
a leading real estate developer in the Houston-Galveston area. Its
energy-related operations include the exploration for and production of natural
gas and crude oil, production of natural gas liquids (NGLs) and the operation
of gas gathering systems. The Company has substantial real estate holdings,
mostly within a 50-mile radius of Houston, Texas.
Within its energy 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. Due to relatively higher domestic finding costs and
continued unfavorable price levels for oil and gas, many energy companies have
chosen in recent years to focus on international activities and to reduce or
eliminate their U.S. operations. However, the Company intends to retain its
domestic focus and hopes to benefit from lessened competition for prospects and
the availability of opportunities for producing property acquisitions. From a
competitive standpoint, those focusing on international activities have chosen
to seek potentially more prolific opportunities in areas where operations
generally are subject to much greater political risk and other uncertainties.
Alternatively, the Company has chosen to limit these risks by continuing to
operate only in the U.S. Also, the Company's operations and cash flows benefit
from the fact that almost one-half of its natural gas production is sold at
prices well above those that are available currently for market-sensitive
production under a contract extending through December 31, 1997.
-2-
<PAGE> 3
The Company owns or has interests in numerous natural gas processing
plants located in Texas, Oklahoma and New Mexico, and it ranked 13th in daily
domestic NGL production in calendar 1993. The Company also has fractionating
equipment at several of its processing plants and 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 has entered the downstream business through its one-third
interest in a partnership which constructed a plant at Mont Belvieu, Texas, to
produce methyl tertiary butyl ether (MTBE), an oxygenate used in the production
of environmentally cleaner gasoline. The plant, which has a design capacity of
12,500 barrels per day, began start-up operations during the summer of 1994.
The Company owns or has interests in natural gas gathering systems
located in Texas with an overall length of nearly 4,600 miles. These systems,
which tend to be regional systems operating in highly competitive local
markets, intersect with numerous pipeline systems enabling the Company to buy,
sell, transport and exchange gas with other pipeline operators.
The Company's largest real estate development project is The Woodlands,
a 25,000-acre master-planned community with a population approaching 42,000.
During each of the last five years, The Woodlands ranked first among Houston's
residential communities in new home sales. The Woodlands Mall, a
million-square-foot regional shopping center, held its grand opening in October
1994. The Company believes the new mall will be a catalyst for additional
commercial land sales and will enhance residential and commercial land values
in The Woodlands. The number of residential communities competing for new home
buyers in the Houston area is expected to increase, resulting in a reduced
market share (based on the percentage of new homes sold) for the master-planned
communities. However, with the related expansion in the size of the overall
market, the Company anticipates that it will be able to maintain its
residential unit sales volume near the level achieved in recent years. Several
of the Houston area master-planned communities are owned by companies having
substantially greater financial resources than the Company.
The Company's operations have been and may be in the future affected
from time to time 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 by world supply and
demand conditions. Real estate sales, on the other hand, may be affected by
available disposable income, interest rates, availability of financing and
numerous other factors.
Insurance
The Company's business is subject to all the operating risks normally
associated with exploration and production of natural gas and oil; extraction
of natural gas liquids from natural gas streams; natural gas gathering and
transportation; development of real estate and operation of commercial and
recreational facilities. Such risks include well blow-out, fire and explosion,
pollution, flood and other naturally and unnaturally occurring 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,
maintains insurance coverage against most, but not all, 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 revenues and increase its costs.
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<PAGE> 4
ITEM 2 - PROPERTIES
Information required by this item is incorporated by reference from
portions of the Annual Report to Stockholders.
<TABLE>
<CAPTION>
CROSS REFERENCE TO APPLICABLE SECTIONS
OF ANNUAL REPORT TO STOCKHOLDERS PAGE
-------------------------------------- ------------
<S> <C>
Energy Operations - Exploration and Production Division . . . . . . . . . . . . . . . 10-14, 16
Energy Operations - Gas Services Division . . . . . . . . . . . . . . . . . . . . . . 17 - 20
Real Estate Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24-28, 30
Operating Statistics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Supplemental Oil and Gas Information . . . . . . . . . . . . . . . . . . . . . . . . . 69 - 72
</TABLE>
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
---------------------------------
1995 1994(a) 1993(a)
-------- --------- ---------
<S> <C> <C> <C>
Combined natural gas, crude oil and condensate
production (thousand cubic feet per day)(b) . . . . . . . . . 252,000 228,000 186,000
Average production cost per
equivalent thousand cubic feet . . . . . . . . . . . . . . . $ .70 $ .75 $ .88
</TABLE>
- ---------------------------
(a) Includes equity partnership interests.
(b) Expressed in equivalent units of production with barrels of oil
converted to cubic feet of gas based on relative sales value.
<TABLE>
<CAPTION>
UNDEVELOPED ACREAGE Earliest Material
At January 31, 1995 Expiration(a)
------------------
Gross Net Concentration % Net Calendar
Location Acres Acres (County or Area) (b) Acres Year
-------- ------- ------- --------------------- ---- ------- ---------
<S> <C> <C> <C> <C> <C> <C>
Texas . . . . . . . . . 202,600 143,200 North Texas 48 69,200 1995
South Dakota . . . . . . 84,100 24,100 Butte 100 6,600 1999
Utah . . . . . . . . . . 75,300 47,300 Uintah 100 16,100 1995
Ohio . . . . . . . . . . 67,900 67,600 Lawrence 66 26,000 1995
New Mexico . . . . . . . 64,500 58,300 Eddy, Lea 92 15,600 1996
Kansas . . . . . . . . . 21,700 21,500 Jackson, Osage 100 15,700 1996
Colorado . . . . . . . . 21,200 19,000 Moffat, Rio Blanco 69 7,000 1996
Other (c) . . . . . . . 62,500 45,500
--------- ---------
Total undeveloped acreage 599,800 426,500
Producing acreage . . . 809,600 607,400
--------- ---------
Total acreage . . . . . 1,409,400 1,033,900
========= =========
</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 Alabama, Arkansas, Louisiana, Michigan, Mississippi, Montana
Nebraska, New York, Oklahoma, Pennsylvania, West Virginia and Wyoming.
-4-
<PAGE> 5
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
- ------------------------- ----- --- --- --- --- --- --- --- --- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Gross Wells--1995
Texas
North Texas . . . . . . . 70 1 6 - 4 58 1 5 64 1
East Central Texas . . . . 19 - - 1 - 18 - - 18 1
Gulf Coast . . . . . . . . 13 - 3 1 - 7 2 - 10 3
West Texas . . . . . . . . 2 - - - 1 1 - 1 1 -
New Mexico . . . . . . . . . 15 1 2 - 11 - 1 12 2 1
Colorado . . . . . . . . . . 4 - - 1 - 3 - - 3 1
Other (b) . . . . . . . . . 9 2 - 2 2 1 2 4 1 4
---- --- ---- ---- --- --- --- --- --- ---
Total (c) . . . . . . . . . 132 4 11 5 18 88 6 22 99 11
===== ==== === ==== ==== ==== === ==== ==== ====
Net Wells
1995 . . . . . . . . . . . . 109.7 2.2 8.0 2.9 10.2 80.5 5.9 12.4 88.5 8.8
===== ==== === ==== ==== ==== === ==== ==== ====
1994 (d) . . . . . . . . . . 121.4 4.5 5.8 12.0 17.1 77.1 4.9 21.6 82.9 16.9
===== ==== === ==== ==== ==== === ==== ==== ====
1993 (d) . . . . . . . . . . 77.6 2.0 3.1 7.8 18.4 39.2 7.1 20.4 42.3 14.9
===== ==== === ==== ==== ==== === ==== ==== ====
</TABLE>
- ---------------------------
(a) Excludes service wells.
(b) Mississippi, New York, Ohio and Pennsylvania.
(c) An additional 35 wells (28.5 net wells) were in the process
of being drilled or completed on January 31, 1995.
(d) Includes equity partnership interests.
ITEM 3 - LEGAL PROCEEDINGS
Information required by this item is incorporated by reference from Note
7 of Notes to Consolidated Financial Statements on page 60 of the Annual Report
to Stockholders.
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the fourth quarter of fiscal 1995, no matter was submitted to a
vote of security holders, either through the solicitation of proxies or
otherwise.
-5-
<PAGE> 6
EXECUTIVE OFFICERS OF THE REGISTRANT
The following is a list of the executive officers of the Company as of
April 1, 1995.
<TABLE>
<CAPTION>
Held a
Position
Continu-
ously
Name Position Age Since
---- -------- --- ---------
<S> <C> <C> <C>
George P. Mitchell Chairman and Chief Executive Officer 75 1946
Bernard F. Clark Vice Chairman 73 1956
W. D. Stevens President and Chief Operating Officer 60 1994
Roger L. Galatas Senior Vice President, Real Estate Division 59 1979
Philip S. Smith Senior Vice President and Chief Financial Officer 58 1980
Allen J. Tarbutton, Jr. Senior Vice President, Gas Services Division 56 1974
Thomas P. Battle Senior Vice President, 52 1982
General Counsel and Secretary
</TABLE>
All of the executive officers were elected at a Board of Directors
meeting held on June 29, 1994 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.
-6-
<PAGE> 7
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
securities, information required by this item is incorporated by reference from
portions of the Annual Report to Stockholders.
<TABLE>
<CAPTION>
CROSS REFERENCE TO APPLICABLE SECTIONS
OF ANNUAL REPORT TO STOCKHOLDERS PAGE
-------------------------------------- --------
<S> <C>
Quarterly Stock Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
Corporate Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77
</TABLE>
The numbers of holders of Class A Common Stock and of Class B Common Stock at
March 31, 1995 were 2,514 and 2,505, respectively. Including those whose
shares are carried in street names, the Registrant estimates that there are
approximately 9,000 holders of each class of its common stock.
ITEM 6 - SELECTED FINANCIAL DATA
Information required by this item is incorporated by reference from
pages 73 and 74 of the Annual Report to Stockholders under the caption
"Historical Summary." Incorporation by reference from these pages is
restricted to the information provided under the following captions: Revenues,
earnings before extraordinary item and cumulative effect of change in
accounting method, net earnings, earnings before extraordinary item and
cumulative effect of change in accounting method per common share, net earnings
per common share, cash dividends per common share, ratio of earnings to fixed
charges, total assets and long-term debt for the fiscal years 1991 through
1995.
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Information required by this item is incorporated by reference from
pages 31 through 45 of the Annual Report to Stockholders.
ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information required by this item is incorporated by reference from
portions of the Annual Report to Stockholders.
<TABLE>
<CAPTION>
CROSS REFERENCE TO APPLICABLE SECTIONS
OF ANNUAL REPORT TO STOCKHOLDERS PAGE
-------------------------------------- --------
<S> <C>
Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . 48 - 51
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . 52 - 67
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . . . . 68
Supplemental Oil and Gas Information (unaudited) . . . . . . . . . . . . . . . . . . . 69 - 72
Quarterly Financial Data (unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . 46
</TABLE>
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<PAGE> 8
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
No Form 8-K's were filed by the Registrant during its fiscal years ended
January 31, 1995 and 1994 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, 1995
pursuant to Regulation 14A under the Securities Exchange Act of 1934 (Proxy
Statement), under the caption "Election of Directors." See page 6 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, 1995, 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, 1995, under the caption "Voting
Securities and Principal Holders Thereof."
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, 1995, under the caption "Certain
Transactions."
-8-
<PAGE> 9
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
<TABLE>
<CAPTION>
CROSS REFERENCE TO APPLICABLE SECTIONS
OF ANNUAL REPORT TO STOCKHOLDERS PAGE
-------------------------------------- --------
<S> <C>
Quarterly Financial Data (unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . 46
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Consolidated Statements of Earnings . . . . . . . . . . . . . . . . . . . . . . . . . 49
Consolidated Statements of Stockholders' Equity . . . . . . . . . . . . . . . . . . . 50
Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . . . . . . . . 51
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . 52 - 67
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . . . . 68
Supplemental Oil and Gas Information (unaudited) . . . . . . . . . . . . . . . . . . . 69 - 72
</TABLE>
FINANCIAL STATEMENT SCHEDULES
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . . . . S-1
Schedule I - Condensed Financial Information of the Registrant . . . . . . . . . . . . S-2
at January 31, 1995 and 1994 and for the Years . . . . . . . . . . . . . thru
Ended January 31, 1995, 1994 and 1993 . . . . . . . . . . . . . . . . . . S-6
</TABLE>
Schedules not listed above are omitted as the information required to be set
forth therein is included in the consolidated financial statements or the
footnotes thereto, or the schedules are not applicable.
-9-
<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 Restated Bylaws of Mitchell Energy & Development Corp. as
most recently amended February 8, 1989 are incorporated as an
exhibit to this report by reference to exhibit 3(b) of the
Registrant's annual report on Form 10-K dated January 31, 1989.
4(a) The senior indenture dated August 1, 1991 by and between Mitchell
Energy & Development Corp., as Borrower, and First City, Texas -
Houston, National Association (succeeded by Texas Commerce Bank),
as Trustee, are incorporated as exhibits to this report by
reference to exhibits 4(b) and 4(c) of File No. 33-42340.
4(b) The senior and subordinated indentures dated January 1, 1993 by
and between Mitchell Energy & Development Corp., as Borrower, 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. The second
supplement to the senior indenture dated January 20, 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 20, 1994.
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.
10(a) Gas Purchase Contract dated March 29, 1989 between Natural Gas
Pipeline Company of America, Buyer, and Mitchell Energy
Corporation, Seller 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, 1989.
The following exhibits 10(b) through 10(m) filed under paragraph 10 of Item 601
of Regulation S-K are the Company's management contracts and compensation plans
or arrangements.
10(b) Long Term Incentive and 1979 Nonqualified Stock Option Plan, as
amended through the Seventh Amendment 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, 1992. The Eighth
Amendment to such Plan is incorporated as an exhibit to this
report by reference to exhibit 10(b) of the annual report on Form
10-K dated January 31,1993.
-10-
<PAGE> 11
10(c) 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(d) 1991 Bonus Unit Plan 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, 1992. An amendment to such Plan effective as
of June 24, 1992 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, 1993.
10(e) 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.
10(f) 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.
10(g) 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 Janu-ary 31, 1992.
10(h) 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, 1991.
10(i) 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(j) Severance compensation contract dated April 16, 1992 between the
Registrant and Roger L. Galatas 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, 1993.
10(k) Severance compensation contract dated October 31, 1991 between
the Registrant and Philip S. Smith 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, 1993.
10(l) Severance compensation contract dated April 16, 1992 between the
Registrant and Allen J. Tarbutton, Jr. 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, 1993.
-11-
<PAGE> 12
10(m) A written description (in lieu of a formal document) describing
the Registrant's commitment to underwrite a life insurance policy
for the benefit 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, 1993.
12 Computation of Ratio of Earnings to Fixed Charges.
13 Annual Report to Stockholders for the fiscal year ended January
31, 1995.
21 List of Subsidiaries as of January 31, 1995.
23 Consent of Independent Public Accountants.
27 Financial Data Schedules
99(a) Annual Report on Form 11-K for the fiscal year ended January 31,
1995 of Mitchell Energy & Development Corp. Thrift and Savings
Plan.
99(b) Annual Report on Form 11-K for the fiscal year ended January 31,
1995 of MND Hospitality, Inc. Thrift and Savings Plan.
REPORTS FILED ON FORM 8-K
No reports were filed on Form 8-K during the quarter ended January 31, 1995.
-12-
<PAGE> 13
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.
<TABLE>
<S> <C>
/s/ George P. Mitchell April 11, 1995
- ------------------------------------------------------------
George P. Mitchell, Chairman
and Chief Executive Officer
</TABLE>
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.
<TABLE>
<S> <C>
/s/ George P. Mitchell April 11, 1995
- ------------------------------------------------------
George P. Mitchell, Chairman
and Chief Executive Officer
/s/ Bernard F. Clark April 11, 1995
- ------------------------------------------------------
Bernard F. Clark, Vice Chairman
/s/ W. D. Stevens April 11, 1995
- ------------------------------------------------------
W. D. Stevens, Director, President
and Chief Operating Officer
/s/ Philip S. Smith April 11, 1995
- ------------------------------------------------------
Philip S. Smith, Senior Vice President -
Administration, Chief Financial Officer
and Principal Accounting Officer
/s/ Robert W. Baldwin April 11, 1995
- ------------------------------------------------------
Robert W. Baldwin, Director
/s/ William D. Eberle April 11, 1995
- ------------------------------------------------------
William D. Eberle, Director
</TABLE>
-13-
<PAGE> 14
SIGNATURES (continued)
<TABLE>
<S> <C>
/s/ Shaker A. Khayatt April 11, 1995
- ------------------------------------------------------
Shaker A. Khayatt, Director
/s/ Ben F. Love April 11, 1995
- ------------------------------------------------------
Ben F. Love, Director
/s/ Walter A. Lubanko April 11, 1995
- ------------------------------------------------------
Walter A. Lubanko, Director
/s/ J. Todd Mitchell April 11, 1995
- ------------------------------------------------------
J. Todd Mitchell, Director
/s/ M. Kent Mitchell April 11, 1995
- ------------------------------------------------------
M. Kent Mitchell, Director
- ------------------------------------------------------
Michael B. Morris, Director
/s/ Raymond L. Watson April 11, 1995
- ------------------------------------------------------
Raymond L. Watson, Director
- ------------------------------------------------------
J. McDonald Williams, Director
</TABLE>
-14-
<PAGE> 15
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Mitchell Energy & Development Corp.:
We have audited, in accordance with generally accepted auditing
standards, the consolidated financial statements included in Mitchell Energy &
Development Corp.'s Annual Report to Stockholders incorporated by reference in
this Form 10-K, and have issued our report thereon dated April 7, 1995. Our
report on the consolidated financial statements includes an explanatory
paragraph with respect to the change in the method of accounting for oil and
gas producing activities as discussed in Note 1 to the consolidated financial
statements. Our audits were made for the purpose of forming an opinion on the
basic financial statements taken as a whole. The financial statement schedule
listed in Item 14 on page 9 is the responsibility of the Company's management
and is presented for purposes of complying with rules of the Securities and
Exchange Commission, and is not part of the basic financial statements. This
financial statement schedule has been subjected to the auditing procedures
applied in the audits of the basic financial statements and, in our opinion,
fairly states in all material respects the financial data required to be set
forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Houston, Texas
April 7, 1995
S-1
<PAGE> 16
Mitchell Energy & Development Corp. and Subsidiaries
SCHEDULE I - CONDENSED FINANCIAL
INFORMATION OF THE REGISTRANT -- PAGE 1 OF 5
================================================================================
Mitchell Energy & Development Corp.
CONDENSED BALANCE SHEETS
January 31, 1995 and 1994
(in thousands)
<TABLE>
<CAPTION>
1995 1994
----------- -----------
Restated
<S> <C> <C>
ASSETS
Current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,056 $ 2,128
Investment in consolidated subsidiaries,
at cost plus equity in undistributed earnings . . . . . . . . . . . 469,038 450,753
Advances to subsidiaries . . . . . . . . . . . . . . . . . . . . . . . 710,592 927,238
Deferred income taxes (Note C) . . . . . . . . . . . . . . . . . . . . 1,018 2,946
Deferred financing costs . . . . . . . . . . . . . . . . . . . . . . . 4,570 5,247
Other assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157 81
----------- -----------
$ 1,187,431 $ 1,388,393
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . $ 9,051 $ 21,365
Long-term debt (Note D) . . . . . . . . . . . . . . . . . . . . . . . . 700,000 900,000
Deferred credits and other liabilities . . . . . . . . . . . . . . . . 3,350 3,791
Commitments and contingencies (Note E)
Stockholders' equity . . . . . . . . . . . . . . . . . . . . . . . . . 475,030 463,237
----------- -----------
$ 1,187,431 $ 1,388,393
=========== ===========
</TABLE>
================================================================================
Mitchell Energy & Development Corp.
CONDENSED STATEMENTS OF EARNINGS
For the Years Ended January 31, 1995, 1994 and 1993
(in thousands except per share amounts)
<TABLE>
<CAPTION>
1995 1994 1993
-------- -------- --------
Restated
<S> <C> <C> <C>
EQUITY IN NET EARNINGS OF SUBSIDIARIES . . . . . . . . . . . $ 45,785 $ 24,642 $ 28,502
-------- -------- --------
OTHER (INCOME) EXPENSE
Interest expense--third parties . . . . . . . . . . . . . . . 55,597 55,060 53,930
Interest income on subsidiary advances . . . . . . . . . . . (56,353) (55,816) (54,735)
General and administrative expense (Note F) . . . . . . . . . - - -
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . 524 895 2,127
Income tax benefit (Note C) . . . . . . . . . . . . . . . . . 203 (101) (73)
-------- -------- --------
(29) 38 1,249
-------- -------- --------
NET EARNINGS . . . . . . . . . . . . . . . . . . . . . . . . $ 45,814 $ 24,604 $ 27,253
======== ======== ========
EARNINGS PER SHARE . . . . . . . . . . . . . . . . . . . . . $ .87 $ .48 $ .58
===== ===== =====
- ---------------------------
The accompanying notes are an integral part of these condensed financial statements.
</TABLE>
S-2
<PAGE> 17
Mitchell Energy & Development Corp. and Subsidiaries
SCHEDULE I - CONDENSED FINANCIAL
INFORMATION OF THE REGISTRANT -- PAGE 2 OF 5
================================================================================
Mitchell Energy & Development Corp.
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended January 31, 1995, 1994 and 1993
(in thousands)
<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
Restated
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 45,814 $ 24,604 $ 27,253
Adjustments to reconcile net earnings
to cash provided by operating activities
Equity in net earnings of subsidiaries . . . . . . . . . . . . . . (45,785) (24,642) (28,502)
Dividends from consolidated subsidiaries . . . . . . . . . . . . . 30,000 57,500 30,000
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . 1,939 (13) 1,404
Changes in operating assets and liabilities . . . . . . . . . . . . (5,758) (2,932) 4,762
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 457 1,692 1,440
--------- --------- ---------
Cash provided by operating activities . . . . . . . . . . . . . . . 26,667 56,209 36,357
--------- --------- ---------
INVESTING ACTIVITIES
Investments in subsidiaries . . . . . . . . . . . . . . . . . . . . . . (2,500) (153,700) (951)
Advances (to) from subsidiaries, net . . . . . . . . . . . . . . . . . 216,646 (349,240) (107,233)
--------- --------- ---------
Cash provided by (used for) investing activities . . . . . . . . . . 214,146 (502,940) (108,184)
--------- --------- ---------
FINANCING ACTIVITIES
Proceeds from issuance of debt . . . . . . . . . . . . . . . . . . . . - 350,000 350,000
Debt repayments . . . . . . . . . . . . . . . . . . . . . . . . . . . . (200,000) - (250,000)
Stock issuance proceeds . . . . . . . . . . . . . . . . . . . . . . . . - 123,429 -
Cash dividends . . . . . . . . . . . . . . . . . . . . . . . . . . . . (26,738) (25,942) (20,097)
Senior note issuance costs . . . . . . . . . . . . . . . . . . . . . . (320) (2,431) (4,249)
Debt prepayment premium . . . . . . . . . . . . . . . . . . . . . . . . (6,420) - -
Treasury stock purchases . . . . . . . . . . . . . . . . . . . . . . . (7,635) - (4,347)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 364 1,960 520
--------- --------- ---------
Cash provided by (used for) financing activities . . . . . . . . . . (240,749) 447,016 71,827
--------- --------- ---------
CHANGE IN CASH AND CASH EQUIVALENTS . . . . . . . . . . . . . . . . . . 64 285 -
CASH AND CASH EQUIVALENTS, beginning of year . . . . . . . . . . . . . 286 1 1
--------- --------- ---------
CASH AND CASH EQUIVALENTS, end of year . . . . . . . . . . . . . . . . $ 350 $ 286 $ 1
========= ========= =========
___________________________
The accompanying notes are an integral part of these condensed financial statements.
</TABLE>
S-3
<PAGE> 18
Mitchell Energy & Development Corp. and Subsidiaries
SCHEDULE I - CONDENSED FINANCIAL
INFORMATION OF THE REGISTRANT -- PAGE 3 OF 5
================================================================================
Mitchell Energy & Development Corp.
NOTES TO CONDENSED FINANCIAL STATEMENTS
JANUARY 31, 1995, 1994 AND 1993
(A) General. The accompanying condensed financial statements of Mitchell
Energy & Development Corp. (MEDC) should be read in conjunction with the
consolidated financial statements and notes thereto included in the Annual
Report to Stockholders of Mitchell Energy & Development Corp. and subsidiaries
(the Company) for fiscal 1995, which is filed as an exhibit to this annual
report on Form 10-K. For information regarding the components of and an
analysis of the activity in stockholders' equity, refer to the Consolidated
Statements of Stockholders' Equity included in the Company's Annual Report to
Stockholders. For information regarding the issuance of Class B shares in
fiscal 1994, the reclassification of MEDC's common stock in fiscal 1993 and
the Company's stock option and bonus unit plans, see Notes 8 and 11 of Notes to
Consolidated Financial Statements included in the Company's Annual Report to
Stockholders. Also, see Note 5 for information regarding extraordinary losses
from early debt retirements recorded in fiscal 1994 and fiscal 1993 and Note 12
for the cumulative effect of a change in accounting methods for postretirement
benefits recorded in fiscal 1993. These charges reduced the reported equity in
net earnings of subsidiaries for fiscal 1994 by $5,426,000 and for fiscal 1993
by $7,251,000 and $10,551,000, respectively.
(B) Accounting Change By Subsidiary. During the fourth quarter of fiscal
1995, MND Energy Corporation, a wholly-owned subsidiary of MEDC, changed its
method of accounting for oil and gas producing activities from the full cost to
the successful efforts method, for which the Financial Accounting Standards
Board has a stated preference. Management concluded that the successful efforts
method will more timely measure the results of a new exploration strategy
initiated by that company as well as make reported financial results more
comparable to those of other oil and gas producers, most of whom use this
method. Prior-year financial statements, including all applicable information
contained herein, have been retroactively restated to give effect to the
change. As a result of this accounting change, MEDC's equity in net earnings
of subsidiaries was increased by $22,344,000 ($.42 per share) in fiscal 1995;
$4,917,000 ($.09 per share) in fiscal 1994 and $8,766,000 ($.19 per share) in
fiscal 1993. In addition, as of February 1, 1992, MEDC's investment in
consolidated subsidiaries and its retained earnings were each reduced by
$302,400,000.
(C) Income Taxes. MEDC is included in the consolidated tax return of the
Company. As the parent company, MEDC allocates to its subsidiaries amounts
equal to the income taxes that the subsidiaries would pay or receive as a
refund if separate returns were filed.
(D) Long-term Debt. A summary of outstanding long-term debt at January 31,
1995 and 1994 follows (in thousands):
<TABLE>
<CAPTION>
UNSECURED SENIOR NOTES 1995 1994
-------- --------
<S> <C> <C>
5.10%, due February 15, 1997 . . . . . . $100,000 $100,000
8%, due July 15, 1999 . . . . . . . . . 100,000 100,000
9 1/4%, due January 15, 2002 . . . . . . 250,000 250,000
6 3/4%, due February 15, 2004 . . . . . 250,000 250,000
11 1/4% (redeemed in February 1994) . . - 200,000
-------- --------
$700,000 $900,000
======== ========
</TABLE>
S-4
<PAGE> 19
Mitchell Energy & Development Corp. and Subsidiaries
SCHEDULE I - CONDENSED FINANCIAL
INFORMATION OF THE REGISTRANT -- PAGE 4 OF 5
================================================================================
On February 25, 1994, MEDC redeemed its $200,000,000 of 11 1/4% Senior
Notes Due 1999 using a portion of the proceeds of January 1994 offerings of
$250,000,000 of 6 3/4% Senior Notes Due 2004 and $100,000,000 of 5.10% Senior
Notes Due 1997. This redemption was completed at a price of 103.21% of
principal, and the expensing of this premium and related unamortized debt
issuance costs resulted in an extraordinary charge of $5,426,000 (after tax
benefit of $2,921,000), which was recorded in January 1994 when the debt was
called. Because all proceeds of senior note borrowings are advanced to the
operating subsidiaries and all the costs of such indebtedness are rebilled to
the subsidiaries, the extraordinary charge was allocated to MEDC's
subsidiaries.
During January 1994, MEDC issued $250,000,000 of 6 3/4% Senior Notes Due
2004 and $100,000,000 of 5.10% Senior Notes Due 1997. Initially, the loan
proceeds were advanced to MEDC's subsidiaries, which used them to pay down
borrowings under their commercial paper and bank revolving credit agreements.
In February 1994, the subsidiaries reborrowed a portion of the amounts
temporarily paid down and advanced such funds to MEDC to fund the debt
redemption mentioned in the preceding paragraph.
On April 13, 1992, MEDC redeemed its $250,000,000 of 11 1/4% Senior
Notes Due 1997 using the proceeds of a March 1992 offering of $250,000,000 of 9
1/4% Senior Notes Due 2002. This early redemption was completed at a price of
103.21% of principal, and the expensing of this premium and related unamortized
debt issuance costs resulted in an extraordinary charge of $7,251,000 (after
tax benefit of $3,736,000), which was allocated to MEDC's subsidiaries as
previously discussed.
The Company's senior notes have no sinking fund requirements and are not
redeemable prior to their respective maturity dates. The senior note
indentures contain certain restrictions which, among other things, limit cash
dividend payments and additional borrowings, restrict the sale or lease of
certain assets and limit MEDC's right to consolidate or merge with other
companies. Retained earnings available for the payment of cash dividends
totaled $75,030,000 at January 31, 1995.
Certain loan agreements of MEDC's subsidiaries limit the amount of cash
advances and dividends that can be paid to MEDC. At January 31, 1995,
transfers to MEDC of approximately $1,030,000,000 were available under these
agreements.
(E) Debt Guarantees. At January 31, 1995, MEDC was contingently liable for
the repayment of approximately $166,000,000 in outstanding debt of subsidiaries
and certain of their equity investees. Also, MEDC had contingent liabilities
at that date totaling approximately $4,700,000, consisting principally of debt
guarantees for nonprofit institutions located in The Woodlands.
(F) General and Administrative Expense Allocation. General and
administrative expense in the Condensed Statements of Earnings is net of
amounts charged to subsidiaries of $42,225,000; $43,222,000 and $41,398,000 in
fiscal 1995, 1994 and 1993. Such costs are allocated based on estimates of
time spent and benefits derived by the subsidiaries from the services provided.
S-5
<PAGE> 20
Mitchell Energy & Development Corp. and Subsidiaries
SCHEDULE I - CONDENSED FINANCIAL
INFORMATION OF THE REGISTRANT -- PAGE 5 OF 5
================================================================================
(G) Statements of Cash Flows. Short-term investments with a maturity of
three months or less are considered to be cash equivalents. Interest paid
totaled $55,180,000; $53,625,000 and $52,754,000 during the years ended January
31, 1995, 1994 and 1993. Income taxes paid during these same periods totaled
$6,877,000; $12,240,000 and $5,935,000. There were no significant non-cash
investing or financing activities during the three-year period ended January
31,1995.
(H) Financial Instruments. Based on quoted market prices, the aggregate
fair value of MEDC's long-term debt was $674,347,000 at January 31, 1995
(compared with an aggregate balance sheet carrying value of $700,000,000). The
carrying amounts of MEDC's other on-balance-sheet financial instruments
approximate their fair values. The aggregate cost to terminate MEDC's
off-balance-sheet financial instruments is not material. MEDC has no direct
involvement with derivative financial instruments.
S-6
<PAGE> 21
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
EXHIBITS TO FORM 10-K
For the Fiscal Year Ended January 31, 1995
<PAGE> 22
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
INDEX TO EXHIBITS
Exhibit
Number Description
- ------- -----------
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 Restated Bylaws of Mitchell Energy & Development Corp.
as most recently amended February 8, 1989 are incorporated
as an exhibit to this report by reference to exhibit 3(b)
of the Registrant's annual report on Form 10-K dated
January 31, 1989.
4(a) The senior indenture dated August 1, 1991 by and between
Mitchell Energy & Development Corp., as Borrower, and First
City, Texas-Houston, National Association (succeeded by
Texas Commerce Bank), as Trustee, are incorporated as
exhibits to this report by reference to exhibits 4(b)
and 4(c) of File No. 33-42340.
4(b) The senior and subordinated indentures dated January 1,
1993 by and between Mitchell Energy & Development Corp., as
Borrower, 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. The second supplement to the
senior indenture dated January 20, 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 20, 1994.
10(a) Gas Purchase Contract dated March 29, 1989, between Natural
Gas Pipeline Company of America, Buyer, and Mitchell Energy
Corporation, Seller 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, 1989.
10(b) Long Term Incentive and 1979 Nonqualified Stock Option
Plan, as amended through the Seventh Amendment 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, 1992. The Eighth Amendment to such Plan is
incorporated as an exhibit to this report by reference to
exhibit 10(b) of the annual report on Form 10-K dated
January 31, 1993.
<PAGE> 23
INDEX TO EXHIBITS (Continued)
Exhibit
Number Description
- ------- -----------
10(c) 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(d) 1991 Bonus Unit Plan 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, 1992. An amendment to such
Plan effective as of June 24, 1992 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, 1993.
10(e) 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.
.
10(f) 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.
10(g) 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(h) 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, 1991.
10(i) 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(j) Severance compensation contract dated April 16, 1992
between the Registrant and Roger L. Galatas 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, 1993.
<PAGE> 24
INDEX TO EXHIBITS (Continued)
Exhibit
Number Description
- ------- -----------
10(k) Severance compensation contract dated October 31, 1991
between the Registrant and Philip S. Smith is incorporated
as an exhibit to this report by reference to exhibit 10(k)
of the Registrant's annual report on Form 10-K dated
January 31, 1993.
10(l) Severance compensation contract dated April 16, 1992
between the Registrant and Allen J. Tarbutton, Jr. 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, 1993.
10(m) A written description (in lieu of a formal document)
describing the Registrant's commitment to underwrite a life
insurance policy for the benefit 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, 1993.
12 Computation of Ratio of Earnings to Fixed Charges
13 Annual Report to Stockholders for the fiscal year ended
January 31, 1995
21 List of Subsidiaries as of January 31, 1995
23 Consent of Independent Public Accountants
27 Financial Data Schedules
99(a) Annual Report on Form 11-K for the fiscal year ended
January 31, 1995 of Mitchell Energy & Development Corp.
Thrift and Savings Plan
99(b) Annual Report on Form 11-K for the fiscal year ended
January 31, 1995 of MND Hospitality, Inc. Thrift and
Savings Plan
<PAGE> 1
Exhibit 12
Mitchell Energy & Development Corp. and Subsidiaries
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
FOR THE YEARS ENDED JANUARY 31, 1995, 1994, 1993, 1992 AND 1991
(dollar amounts in thousands)
<TABLE>
<CAPTION>
Restated
---------------------------------------------
1995 1994 1993 1992 1991
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
EARNINGS
Pretax earnings . . . . . . . . . . . . . . . $ 70,551 $ 47,376 $ 60,022 $ 73,188 $ 60,484
Add (Deduct)
Previously capitalized interest
charged against pretax earnings . . . . 22,158 11,552 9,545 14,887 8,776
Losses of less-than-50%-owned persons . . 1,104 32 99 26 23
Fixed charges (see below) . . . . . . . . 85,988 84,788 85,169 90,107 98,633
Reverse effect of inclusion of interest
capitalized in fixed charges above . . (33,011) (33,956) (34,161) (37,460) (44,253)
Undistributed earnings of
less-than-50%-owned persons . . . . . . (914) (3,594) (10,305) (10,521) (11,690)
-------- -------- -------- -------- --------
$145,876 $106,198 $110,369 $130,227 $111,973
======== ======== ======== ======== ========
FIXED CHARGES
Interest expense incurred
Consolidated (a) (c) . . . . . . . . . . $ 71,570 $ 75,252 $ 77,451 $ 84,025 $ 92,874
50%-owned persons . . . . . . . . . . . . 7,912 6,236 4,609 3,284 3,670
Less-than-50%-owned persons . . . . . . . 3,032(b) - - - -
-------- -------- -------- -------- --------
82,514 81,488 82,060 87,309 96,544
Portion of rental expense representing
interest (d) . . . . . . . . . . . . . . . 3,474 3,300 3,109 2,798 2,089
-------- -------- -------- -------- --------
$ 85,988 $ 84,788 $ 85,169 $ 90,107 $ 98,633
======== ======== ======== ======== ========
RATIO OF EARNINGS TO FIXED CHARGES . . . . . 1.70 1.25 1.30 1.45 1.14
======== ======== ======== ======== ========
</TABLE>
- ---------------------------
(a) Consists of interest expense as reported in consolidated statements of
earnings and interest expense related to finance operations which is
reported as costs and expenses in the consolidated statements of earnings.
(b) At January 31, 1995, the Company had an outstanding guaranty covering
$58,667,000 of indebtedness of Belvieu Environmental Fuels (BEF), a
33.33%-owned entity, under which it could be required to perform on May 31,
1995. Because of this, interest expense incurred during this period of
$3,032,000 attributable to the Company's share of BEF's debt (all of which
was capitalized by BEF) has been included in the fixed charges of the
Company.
(c) At January 31, 1995, the Company had other outstanding guaranties of
approximately $20,800,000 of indebtedness of less-than-fifty percent owned
partnerships and approximately $4,400,000 of indebtedness of unaffiliated,
nonprofit institutions under which it has not been, nor is it expected that
it will be, required to perform. Fixed charges related to these
outstanding borrowings, estimated at approximately $1,200,000 for fiscal
1995, have been excluded from the reported fixed charges.
(d) Represents one-third of rental expense under operating lease agreements.
<PAGE> 1
EXHIBIT 13
MITCHELL ENERGY & DEVELOPMENT CORP.
FISCAL 1995 ANNUAL REPORT
(Year Ended January 31, 1995)
<PAGE> 2
THE COMPANY
Mitchell Energy & Development Corp. traces its origins to a small wildcatting
firm formed in 1946. Today, the Company is a large independent energy producer.
It also is a major real estate developer, primarily in the Houston region. At
January 31, 1995, the Company had approximately 2,600 full-time employees.
Principal energy operations include the exploration for and production of
natural gas and oil, production of natural gas liquids and operation of gas
gathering systems. In its most recent fiscal year, the Company produced 81.8
billion cubic feet of natural gas and 19.6 million barrels of liquid
hydrocarbons (natural gas liquids, oil and condensate). At year end, it owned
or had interests in 3,280 wells, 1.4 million acres of leases, nearly 4,600
miles of natural gas gathering systems, and processing plants in 34 locations.
The Company's largest land development project is The Woodlands, a
25,000-acre community located 27 miles north of downtown Houston. At year end,
the community had more than 41,900 residents and a non-construction employment
base of 15,500 jobs.
CONTENTS
<TABLE>
<S> <C>
Letter to Shareholders . . . . . . . . . . . . . . . . . . . . . 2
Special Report: Refocusing . . . . . . . . . . . . . . . . . . . 6
Energy Operations . . . . . . . . . . . . . . . . . . . . . . . . 8
Real Estate Operations . . . . . . . . . . . . . . . . . . . . . 22
Management's Discussion and Analysis of
Financial Position and Results of Operations . . . . . . . . . 31
Consolidated Financial Statements . . . . . . . . . . . . . . . . 48
Notes to Consolidated Financial Statements . . . . . . . . . . . 52
Report of Independent Public Accountants . . . . . . . . . . . . 68
Supplemental Oil and Gas Information . . . . . . . . . . . . . . 69
Historical Summary . . . . . . . . . . . . . . . . . . . . . . . 73
Principal Officers . . . . . . . . . . . . . . . . . . . . . . . 75
Board of Directors . . . . . . . . . . . . . . . . . . . . . . . 76
Corporate Information . . . . . . . . . . . . . . . . . . . . . . 77
</TABLE>
DEFINITIONS
<TABLE>
<S> <C>
MMBtu . . . . . . . . . . . . . . . . . . . million British thermal units
Mcf . . . . . . . . . . . . . . . . . . . . thousand cubic feet (measure of gas volume)
Bcf . . . . . . . . . . . . . . . . . . . . billion cubic feet (measure of gas volume)
Bbl . . . . . . . . . . . . . . . . . . . . barrel (measure of liquid hydrocarbon volume)
MMBbls . . . . . . . . . . . . . . . . . . million barrels
NGL or NGLs . . . . . . . . . . . . . . . . natural gas liquids (ethane, propane, butanes and natural gasoline)
DD&A . . . . . . . . . . . . . . . . . . . depreciation, depletion and amortization
</TABLE>
Note: All 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. Where applicable, reported oil, gas and NGL volume, price and
reserve information includes equity partnership interests.
<PAGE> 3
HIGHLIGHTS
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
YEAR ENDED JANUARY 31 (dollars in thousands except per-share data)
<TABLE>
<CAPTION>
1995 1994*
---------- ----------
<S> <C> <C>
Net earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 45,814 $ 24,604
========== ==========
Earnings per share . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ .87 $ .48
========== ==========
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 894,571 $ 952,809
========== ==========
Segment operating earnings
Exploration and production (including a $3,791 gain on
sale of drilling rigs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 87,906 $ 68,186
Natural gas processing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23,253 20,088
Natural gas gathering and marketing . . . . . . . . . . . . . . . . . . . . . . . . 12,335 18,742
Gains on major asset sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48,821 -
Restructuring charges and asset write-downs . . . . . . . . . . . . . . . . . . . . (31,252) -
Other gas services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (846) 3,829
---------- ----------
Total energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 140,217 110,845
Real estate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,793 21,078
Asset write-downs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,661) -
---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 160,349 $ 131,923
========== ==========
Capital and exploratory expenditures . . . . . . . . . . . . . . . . . . . . . . . $ 219,575 $ 354,080
========== ==========
Total assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,855,871 $1,969,292
========== ==========
Estimated present value of future pretax
net revenues from proved energy reserves . . . . . . . . . . . . . . . . . . . . $ 956,000 $ 986,000
========== ==========
Operating statistics (average daily amounts)
Natural gas sales (Mcf ) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 214,100 193,800
Crude oil and condensate sales (Bbls) . . . . . . . . . . . . . . . . . . . . . . . 6,300 6,000
Natural gas liquids production (Bbls) . . . . . . . . . . . . . . . . . . . . . . . 47,500 49,800
Pipeline throughput (Mcf) (excluding Winnie system, sold in fiscal 1995) . . . . . 353,000 386,000
</TABLE>
* Restated for adoption of the successful efforts method of accounting.
See Management's Discussion and Analysis.
ESTIMATED PROVED RESERVES
At January 31
(BAR CHART) (BAR CHART)
<PAGE> 4
LETTER TO SHAREHOLDERS
To say that fiscal 1995 presented a number of difficulties would be a vast
understatement. As the year began, margins for natural gas liquids--one of our
two principal products--were at an all-time low; when the year ended, sales
prices for the other--natural gas--had collapsed. Managing the Company's
natural gas processing and gas production operations with margins and prices
changing so dramatically, as well as conducting a drilling program during such
uncertainty, required an especially concerted effort. Despite this volatility,
fiscal 1995 earnings from operations were about even with those of the prior
year. In many respects, however, operational results were improved. More
importantly, we continued to reposition your Company to do well under whatever
conditions the future may bring.
Two fundamental characteristics of the Company which stand us in good stead
in difficult times are the diversity and balance of our various business lines.
Having a mix of profitable real estate operations to help balance energy
results is beneficial. And within energy, having the diversity of gas
production and natural gas processing operations--which are affected in
opposite ways by changing gas prices--as well as the balance of fixed-versus
spot-priced gas sales and keep-whole versus percent-of-proceeds gas plant
operations helps stabilize our financial results. Even so, fiscal 1995's
roller-coaster price changes mandated a close re-examination of all of our
business segments and firm actions to adapt. The old saw that necessity is the
mother of invention is certainly applicable to this industry and, more
specifically, to the Company. In several areas, we have either instituted or
modified key strategies which are already changing the Company for the
better--and will do so even more in the future. The need to make these changes
is given added importance by the looming expiration at the end of calendar 1997
of the above-market-price sales contract which covers our North Texas natural
gas production.
What we are about is perhaps oversimplified but succinctly captured by the
simple concept of going "back to basics." More resources are now being directed
toward maximizing core asset values. This includes upgrading the mix and
improving the utilization of our asset holdings, focusing the Company's
exploration efforts in areas where we have had a good finding record,
streamlining the organization and reducing costs, and strengthening the
Company's
2
<PAGE> 5
overall financial structure. While many of these directions are not new, the
difficult times of this past year have caused us to accelerate and intensify
the dedication with which they are being pursued. The section of this report
entitled "Special Report: Refocusing," which follows this letter, amplifies
these themes and indicates what sort of company we will be in the future.
Equally important, it outlines the major progress made over the past year in
implementing these strategies. We hope every shareholder will read this special
report closely.
Operationally, the Company had a good year. Exploratory results improved,
leading to a halving of per-barrel finding costs. Overall, we replaced 171
percent of the gas reserves produced during the year, and year-end gas reserves
were up by 9 percent, reaching a record level. This achievement is even more
striking because natural gas production also was at a record level, up 10
percent from the prior year's. While natural gas liquids production volumes were
down 5 percent due to temporary plant shutdowns related to depressed margins
early in the year, we made major progress in rationalizing the Company's
processing facilities and organization and are now benefiting from these steps
in today's improved environment.
Real estate had an outstanding year, capped by the opening of the new
regional shopping mall. This critical step in development of The Woodlands Town
Center has led to a quickening of commercial activity nearby, enhancing the
value of the surrounding 300 acres of Company-owned land. Residential
development continues strong. Lot sales rose to 951 for the year, and The
Woodlands maintained its No. 1 ranking in Houston area home sales.
Following on the progress in improving the Company's financial structure in
the prior year with an equity offering, we refinanced $200 million of 11 1/4
percent senior notes at considerable savings early in fiscal 1995. In addition,
funds raised from major asset sales resulted in a reduction of almost 10
percent in long-term debt.
Net earnings of $45.8 million for fiscal 1995 were up from the preceding
year's $24.6 million, the latter restated for adoption of successful efforts
accounting for oil and gas producing activities. We believe this accounting
method makes the Company's financial results more comparable to those of most
other oil and gas producers and complements our revised approach to exploration
in that earnings will give more timely measure of the results realized.
Several unusual events affected fiscal 1995 earnings: on the plus side,
$52.6 million in pretax gains on energy asset sales; negatives were pretax
restructuring charges and asset write-downs of $36.9 million. The net effect
was an
3
<PAGE> 6
increase of $15.7 million, or $8.6 million after tax. Fiscal 1994 net earnings,
on the other hand, were reduced by $12 million of one-time after-tax charges.
Excluding unusual items, year-to-year earnings were essentially unchanged
because of the effect of offsetting items. Favorable year-to-year variances
included sharply lower nonproductive exploratory costs and impairment charges,
which were largely related to the changed exploration emphasis, and improved
earnings from higher gas production volumes and real estate operations. These
gains were about offset, however, by the negative impact of lower natural gas
liquids prices, reduced gas gathering and marketing margins, a higher effective
income tax rate and nonrecurring gains in the prior year.
If those of us in the oil and gas business have learned anything over
recent years, it is that our companies' present health and progress will not be
determined by OPEC or other outside forces, but rather by management's and
employees' ability and willingness to adapt to difficult and changing economic
conditions. The events of the 1990s have convinced even the most optimistic
that we shouldn't base future strategies and plans on a business climate much
different from what we have been experiencing. This is a sound approach since
it helps us remain healthy through the downturns and positions us to do very
well when prices strengthen.
(PHOTO)
George P. Mitchell & W.D. Stevens
While we cannot separate our results from the industry environment, our
actions are increasingly predicated on the belief that the Company's future
will largely be determined by the initiatives we take internally. This
observation is particularly relevant in that next year marks the 50th
anniversary of the Company's founding. As we look forward to this landmark, the
progress made in refocusing and positioning your Company for the next half
century is particularly noteworthy. Whether these new directions ultimately
mean a smaller or larger enterprise is not very important as long as
profitability and shareholder value are enhanced. We are committed to realizing
these objectives.
George P. Mitchell W. D. Stevens
Chairman and President and
Chief Executive Officer Chief Operating Officer
April 4, 1995
4
<PAGE> 7
EVOLVE AND ADAPT
"WHILE THE SPECIFIC ELEMENTS OF OUR STRATEGY WILL DEPEND ON CIRCUMSTANCES AND
OPPORTUNITIES, THE OVERALL GOAL--TO ENHANCE SHAREHOLDER VALUE--WILL REMAIN
CONSTANT."
5
<PAGE> 8
SPECIAL REPORT: REFOCUSING
Successful companies, like successful organisms, must evolve and adapt to the
changing environment in which they exist. In business, as in nature,
acceleration of the process is sometimes necessitated by external events, and
such has been the case for your Company this past year. The volatile and often
depressed pricing environment for our products put added urgency to finding
ways to improve both the effectiveness and efficiency of operations. The
Company is meeting this overall challenge with a four-part strategy designed to
position it to prosper in good times and cope with the bad.
The strategy basically involves improving asset management, focusing the
exploration program, streamlining the organization, and bolstering financial
capabilities. Major initiatives have been undertaken in each of these areas in
recent years, particularly in fiscal 1995 and on into the current year.
ASSET MANAGEMENT
One of the major strengths of the Company has long been the diversity and
quality of its asset base. Even so, an in-depth asset management study
undertaken in fiscal 1995 identified a number of areas where the value of our
properties can be enhanced by a three-part action plan: (1) directing more
resources, both technical and financial, to maximizing the value of core
holdings; (2) identifying assets that may have greater value to others and
selling these; and (3) disposing of non-core properties not adding to current
profitability. The fundamental objective is to upgrade the overall quality of
our assets, thereby shifting total investment more to those which are now
contributing or have potential to add to the bottom line in the near term.
Significant progress was achieved during the year, including sales of our
unused drilling rig fleet, assets of a wholly owned compression rental-service
company and, most significantly, the Winnie-Spindletop gas distribution-storage
system. In total, proceeds from asset sales in fiscal 1995 amounted to $175
million. Currently, several real estate and energy transactions with aggregate
potential sales proceeds of as much as $50 million are moving toward
completion.
Implementation of the asset management plan is not limited to the sale of
assets, however. An integral component is the strengthening of core operations
through niche acquisition and investment opportunities. While not of the
magnitude of the asset sales, important acquisitions of oil and gas properties
and pipeline interests have been made over the past year or so. In addition,
new partnership ventures were completed: A regional shopping mall at The
Woodlands was opened, a natural gas liquids fractionation facility was
expanded, and a plant to produce the gasoline additive methyl tertiary butyl
ether began operations. The Company will continue to seek opportunities to
strengthen or extend current operations--but, importantly, only when the price
is right.
EXPLORATION
As part of the improved focus on core properties, the Company is concentrating
its exploration talent and dollars more in geographic areas where it
historically has had the greatest success. There are four such core
areas--North Texas, East Texas, onshore along the Gulf Coast, and the Delaware
Basin area of southeastern New Mexico. While we will continue rank wildcat
exploration, greater emphasis will be on development, which should provide
better returns. Some far-flung properties--such as production and undeveloped
leases in the Clinton-Medina trend through parts of Pennsylvania and Ohio--are
to be sold. Others with potential that cannot be
6
<PAGE> 9
tapped in the present economic environment will be retained but at little or no
cost until prices improve.
The fruits of this strategy already are being harvested. Natural gas and
liquid hydrocarbon reserves rose in fiscal 1995, while finding and development
costs dropped. The lower finding costs were mainly due to drilling success in
core areas, but the reduction also was at least partly attributable to
avoidance of higher-risk projects in non-core areas that drove up costs in past
years. With its large resource base, backlog of undrilled locations and
successful track record of reserve replacement, the Company expects to be a
more competitive finder and producer of natural gas.
STREAMLINING
Cost reduction is an essential element of the Company's strategy, and this is
being accomplished mainly by reducing the size of the organization. One
indication of actions already taken is a 10 percent decline in full-time
employment--to 2,600 from 2,900--in fiscal 1995. This resulted mainly from a
voluntary retirement program in the Gas Services segment, asset sales in which
employees joined the buyers, and normal attrition coupled with a year-long
hiring freeze.
Now, early in fiscal 1996, a personnel reduction program is being
implemented with the goal of lowering annual costs by an additional $21 million
through a reduction in force of more than 300 employees. Most, if not all, of
the program is expected to be completed by the end of the first quarter, at
which time employment is anticipated to be less than 2,300. Enhanced retirement
and severance benefits related to the program are estimated to cost $20
million, which will be recovered within a year.
FINANCIAL CAPABILITIES
Several significant steps have been taken in recent years to strengthen the
Company's financial capabilities, including the refinancing of $200 million in
debt at much lower interest rates. That initiative, which contributed $4
million in interest cost savings in fiscal 1995, benefitted from the upgrading
of the Company's debt rating by Moody's Investor Service in January 1994. With
that upgrade, all three of the firms that evaluate the Company's debt
securities had investment-grade ratings on its debt. The earlier establishment
of the dual-class stock arrangement gave the Company increased financial
flexibility, which was used to advantage when $123 million of Class B stock was
sold in fiscal 1994 and a large part of the proceeds was used to buy out the
MEC Development, Ltd., drilling partnership.
More recently, proceeds from fiscal 1995 asset sales were used to make an
almost 10 percent reduction in debt--to $895 million at the end of fiscal 1995
from $988.3 million a year earlier. Additional debt-reduction potential is
inherent in the continued emphasis on improved asset utilization, which will
likely result in other non-core asset sales.
Management believes that each of the individual initiatives above is good
business in its own right and has already begun to add value. Combined, they
comprise the fabric of an overall business strategy for improving the Company's
results, both immediate and long term, and its competitive position. While the
specific elements of our strategy will depend on circumstances and
opportunities, the overall goal--to enhance shareholder value--will remain
constant.
7
<PAGE> 10
GAS RESERVES...A RECORD LEVEL
8
<PAGE> 11
"...WE REPLACED 171 PERCENT OF THE GAS RESERVES PRODUCED, AND YEAR-END GAS
RESERVES WERE UP BY 9 PERCENT, REACHING A RECORD LEVEL."
9
<PAGE> 12
EXPLORATION AND PRODUCTION DIVISION
EXPLORATION AND PRODUCTION'S FISCAL 1995 OPERATING EARNINGS WERE WELL AHEAD
OF THE RESTATED AMOUNTS FOR THE PRIOR YEAR. THE MAIN CONTRIBUTORS WERE
SHARPLY LOWER
10
<PAGE> 13
EXPLORATION AND PRODUCTION DIVISION FINANCIAL HIGHLIGHTS
Year Ended January 31 (in thousands)
<TABLE>
<CAPTION>
1995 1994*
----------- -----------
<S> <C> <C>
Revenues . . . . . . . . . . . . . . . . $ 277,099 $ 266,166
=========== ===========
Segment operating earnings
Operations . . . . . . . . . . . . . . . $ 84,115 $ 68,186
Gain from sale of drilling rigs . . . . . 3,791 -
----------- -----------
$ 87,906 $ 68,186
=========== ===========
Capital and exploratory expenditures
Consolidated . . . . . . . . . . . . . . $ 115,073 $ 158,203
MEC Development, Ltd., buy-out . . . . . - 78,251
----------- -----------
$ 115,073 $ 236,454
=========== ===========
</TABLE>
* Restated for adoption of the successful efforts method of accounting.
See Management's Discussion and Analysis.
(BAR CHART)
charges for exploratory dry holes and impairments of producing
properties--which together totaled $5.8 million in fiscal 1995, compared with
$31.3 million a year earlier--and higher gas volumes. Partly offsetting these
benefits was an increase in DD&A expense, most of which was attributable to the
increased gas production.
Fiscal 1995 capital expenditures for exploration and production activities
were well below those of the prior year, even excluding the buy-out of MEC
Development, Ltd., in fiscal 1994. The lower level is indicative of the
Company's new exploration focus and of a current price environment which does
not encourage drilling.
GAS AND OIL SALES
At $1.90 per Mcf, fiscal 1995's average market-sensitive natural gas price was
24 cents under the prior year's level. Overall, including contract gas and the
leasehold value of gas liquids, natural gas prices fell 15 cents to an average
of $2.71 per Mcf. Contract gas averaged $3.53 per Mcf, about the same as in the
preceding year. In both years, about half of the sales were at market prices
and half at contract prices. Approximately 90 percent of the contract sales
were to Natural Gas Pipeline Company of America, our largest gas customer.
Even with some production curtailment because of depressed market prices,
fiscal 1995 was our second consecutive year of record natural gas sales. Daily
volumes averaged 214,100 Mcf, compared with 193,800 Mcf in the preceding year.
The gain is a direct result of the Company's increased production capacity,
much of which is attributable to successful drilling.
While the fiscal 1995 price trend for natural gas was downward, the op-
11
<PAGE> 14
posite was the case for crude oil and condensate. Prices recovered from the
extremely depressed level of the first quarter and by year end were about $18
per barrel. At $15.75, however, the yearly average was still under fiscal
1994's $16.31. Helping to offset effects of the price decline was an increase
in daily production to 6,300 barrels from the prior year's 6,000 barrels.
EXPLORATION AND PRODUCTION
The Company achieved excellent back-to-back years in the replacement of its
natural gas reserves. On top of a 160 percent replacement rate in fiscal 1994,
171 percent of the gas produced in fiscal 1995 was replaced. Reserves totaled a
record 685.7 Bcf of gas at the end of fiscal 1995--up by 9 percent--on top of
record production of 81.8 Bcf during the year. Over the past five years, the
Company has replaced 137 percent of its gas production.
Crude oil and condensate reserves declined to 14.3 million from 15.3
million barrels. About half of the decline resulted from sales of non-core
properties, while the remainder was largely attributable to a cutback in
drilling.
Indicative of the Company's new strategy to focus wildcatting on its core
areas, finding and development costs improved dramatically in fiscal 1995.
Costs for the year fell to $3.82 per barrel of oil equivalent from fiscal
1994's $7.54. Included in the reserve additions used in these calculations are
natural gas (net of gas lost in processing), natural gas liquids (lease and
plant share), and oil and condensate.
North Texas--and particularly the Barnett Shale--played an important role
in both the gas reserves gain and the finding cost improvement. The
PRINCIPAL PRODUCING AREAS Year Ended January 31
<TABLE>
<CAPTION>
Average Daily Sales
-----------------------
1995 1994
------- -------
<S> <C> <C>
Natural Gas (net Mcf)
North Texas . . . . . . . . . . . . . . . . . 102,000 98,600
Limestone County Area (East Central Texas) . 30,100 32,900
Gulf Coast, Onshore . . . . . . . . . . . . . 33,900 23,400
Gulf Coast, Offshore . . . . . . . . . . . . 9,100 7,800
Southeast New Mexico . . . . . . . . . . . . 17,600 8,200
Rocky Mountain Area . . . . . . . . . . . . . 9,700 11,000
Other . . . . . . . . . . . . . . . . . . . . 11,700 11,900
------- -------
Total . . . . . . . . . . . . . . . . . . . . 214,100 193,800
======= =======
Crude Oil and Condensate (net Bbls)
North Texas . . . . . . . . . . . . . . . . . 1,600 1,800
Gulf Coast . . . . . . . . . . . . . . . . . 1,900 1,300
Southeast New Mexico . . . . . . . . . . . . 1,100 900
Other . . . . . . . . . . . . . . . . . . . . 1,700 2,000
------- -------
Total . . . . . . . . . . . . . . . . . . . . 6,300 6,000
======= =======
</TABLE>
(BAR CHART)
12
<PAGE> 15
Company has pursued an aggressive drilling program in the Barnett but had
postponed formally counting some of the reserves pending completion of internal
studies. Approximately one-quarter of the 141.9 Bcf of gas reserves added
during the year through new discoveries and extensions was attributable to
newly booked but previously discovered gas, mainly in the Barnett.
By finding naturally fractured "sweet spots" and further enhancing their
productive capability with hydraulic fracturing, the Company has made the
Barnett an important new source of gas from our half-million-acre Fort Worth
Basin leaseholdings. During fiscal 1995, most of the 70 wells completed in
North Texas were in that formation. Further adding to the Barnett's potential,
(BAR CHART)
WELL COMPLETIONS(1) Year Ended January 31, 1995
<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>
Texas
North Texas . . . . . . . . . . . . . 70 1 6 - 4 58 1 5 64 1
East Central Texas. . . . . . . . . . 19 - - 1 - 18 - - 18 1
Gulf Coast . . . . . . . . . . . . . 13 - 3 1 - 7 2 - 10 3
West Texas . . . . . . . . . . . . . 2 - - - 1 1 - 1 1 -
New Mexico . . . . . . . . . . . . . . 15 1 2 - 11 - 1 12 2 1
Colorado . . . . . . . . . . . . . . . 4 - - 1 - 3 - - 3 1
Other(2) . . . . . . . . . . . . . . . 9 2 - 2 2 1 2 4 1 4
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Gross Wells(3) . . . . . . . . . . . . 132 4 11 5 18 88 6 22 99 11
===== ===== ===== ===== ===== ===== ===== ===== ===== =====
Net Wells . . . . . . . . . . . . . . . 109.7 2.2 8.0 2.9 10.2 80.5 5.9 12.4 88.5 8.8
===== ===== ===== ===== ===== ===== ===== ===== ===== =====
</TABLE>
- --------------------
(1) Excludes service wells.
(2) Mississippi, New York, Ohio and Pennsylvania.
(3) An additional 35 wells (28.5 net wells) were in the process of drilling or
completion on January 31, 1995.
LEASEHOLDINGS At January 31, 1995
<TABLE>
<CAPTION>
Gross Net
Acres Acres
--------- ---------
<S> <C> <C>
Texas . . . . . . . . . . . . . . . . . . 202,600 143,200
South Dakota . . . . . . . . . . . . . . 84,100 24,100
Utah . . . . . . . . . . . . . . . . . . 75,300 47,300
Ohio . . . . . . . . . . . . . . . . . . 67,900 67,600
New Mexico . . . . . . . . . . . . . . . 64,500 58,300
Kansas . . . . . . . . . . . . . . . . . 21,700 21,500
Colorado . . . . . . . . . . . . . . . . 21,200 19,000
Other*. . . . . . . . . . . . . . . . . . 62,500 45,500
--------- ---------
Total undeveloped acreage . . . . . . . . 599,800 426,500
Producing acreage . . . . . . . . . . . . 809,600 607,400
--------- ---------
Total acreage . . . . . . . . . . . . . . 1,409,400 1,033,900
========= =========
</TABLE>
- --------------------
* Includes Alabama, Arkansas, Louisiana, Michigan, Mississippi, Montana,
Nebraska, New York, Oklahoma, Pennsylvania, West Virginia and Wyoming.
13
<PAGE> 16
the regulatory process has been changed in a way that streamlines approval of
commingling gas from the Barnett with that from uphole completions in other
formations. This, along with the use of larger cooperative units, will cut
costs and help optimize the location of drill sites.
In the Barnett and other plays, technology has an increasingly important
role in our exploration and production efforts. In North Texas, 3-D seismic and
advanced "shear wave" seismic analysis are being employed to select drilling
sites. No other company in the area is using the "shear wave" technology in
day-to-day operations. Similarly, we are using state-of-the-art downhole
fracture analysis as part of the Barnett development program. By determining
the orientation of hydraulically induced fractures through which well
productivity is enhanced, drill sites can be located to maximize drainage of
the formation.
Seismic and downhole fracture analysis also are being employed to
determine the productive boundaries and optimum well density in our
second-largest gas property, the North Personville Field in the Limestone
County area of East Central Texas. Like North Texas, this has been a
"bread-and-butter" play in which we have consistently added natural gas
reserves. A one-rig program is continuing on the 55,000-acre leasehold at North
Personville and is being concentrated on a part of the field covered by an
above-market-price sales contract.
Other significant contributors to gas reserve additions during fiscal
1995 were a South Texas gas discovery and a follow-up well. The wells, both
dually completed with about 150 feet of pay, were drilled in Hidalgo County
using detailed geological studies that detected the potential for deeper Frio
production in an old producing area. We are now evaluating other areas of the
county for this additional potential.
With summer and heating season gas sales contracts as incentives, we
increased production capacity in the Hell's Hole Field area of northwestern
Colorado. Three Dakota formation gas wells were completed there during fiscal
1995. With the expiration of the summer contract, we will again curtail
production there during the current year but will drill at least three wells to
meet contract requirements for the next heating season.
Drilling activity in the Delaware Basin area of southeastern New Mexico was
curtailed pending improvements in spot-market gas prices. We did, however,
participate in the drilling of 10 oil wells in the Pure Gold Field area of Eddy
County during fiscal 1995.
Near the end of the year, the Company participated in a Yegua formation gas
discovery well in Orange County, Texas--another prospect in which 3-D seismic
data played an important role. This property is to be further evaluated with
development drilling.
14
<PAGE> 17
(PICTURE)
NORTH TEXAS DRILLING ACCOUNTED FOR MORE THAN HALF OF THE WELLS IN WHICH THE
COMPANY PARTICIPATED DURING FISCAL 1995.
15
<PAGE> 18
As part of the strategy to concentrate on its core holdings, the Company
sold some marginal oil and gas properties in fiscal 1995 and presently has
other properties on the market. As part of the same general theme, several
small producing property acquisitions were made.
At the end of fiscal 1995, the Company had interests in 2,231 gas producers
and 1,049 oil producers--a total of 3,280 wells, of which 85 were productive in
two or more zones. The interests were equivalent to 2,569 net wells--1,928 gas
and 641 oil--of which 73 were productive in two or more zones.
OTHER
In the first quarter of fiscal 1995, the Company sold 16 drilling rigs
to Nabors Industries, Inc., for $9 million in cash plus warrants to purchase
Nabors stock. This sale effectively completed the Company's withdrawal from the
contract drilling business. The Company continues to operate two rigs for its
own account in North Texas.
MAJOR AREAS OF OPERATION
(MAP)
16
<PAGE> 19
ENERGY OPERATIONS
Gas Services Division
IN GAS SERVICES, GAINS FROM MAJOR ASSET SALES, PARTIALLY OFFSET BY THE COST OF
PLANT AND GATHERING SYSTEM WRITE-DOWNS AND AN EARLY RETIREMENT PROGRAM, BOOSTED
OPERATING
17
<PAGE> 20
GAS SERVICES DIVISION FINANCIAL HIGHLIGHTS
Year Ended January 31 (in thousands)
<TABLE>
<CAPTION>
1995 1994
----------- -----------
<S> <C> <C>
Revenues
Natural gas processing . . . . . . . . . $ 252,159 $ 253,605
Natural gas gathering and marketing . . . 180,038 296,373
Other . . . . . . . . . . . . . . . . . . 6,989 10,559
Gains from major asset sales . . . . . . 48,821 -
----------- -----------
$ 488,007 $ 560,537
=========== ===========
Segment operating earnings
Natural gas processing . . . . . . . . . $ 23,253 $ 20,088
Natural gas gathering and marketing . . . 12,335 18,742
Other . . . . . . . . . . . . . . . . . . (846) 3,829
Gains from major asset sales . . . . . . 48,821 -
Restructuring charges and asset write-downs (31,252) -
----------- -----------
$ 52,311 $ 42,659
=========== ===========
Capital expenditures . . . . . . . . . . $ 35,111 $ 48,628
=========== ===========
</TABLE>
earnings 23 percent in fiscal 1995 to $52.3 million. Excluding the one-time
unusual items, however, earnings declined by 19 percent to $34.7 million,
mainly due to lower profit margins on natural gas that the Company buys from
third parties, transports to market and resells.
(BAR CHART)
During fiscal 1995, the Gas Services Division (formerly the Transmission
and Processing Division) sold approximately $162 million in assets that were
outside its core business areas, were underutilized or had greater value to the
buyers. The largest transaction was the $120 million sale of the Spindletop
Gas Storage Facility near Beaumont, Texas, along with the Winnie Pipeline
intrastate gathering system and a half interest in a gas processing plant at
Port Arthur, Texas. In addition, the assets of the Brazos Gas Compressing Co.
subsidiary were sold for $35 million. Profits from those sales resulted in an
aggregate pretax gain of $48.8 million.
Various restructuring charges, however, largely offset the benefits of the
asset sales. The Company wrote down the value of certain gas processing plants
and gas gathering systems by a total of $23.9 million and took a $7.4 million
charge in connection with an early retirement program. The write-downs will
reduce costs by lowering future DD&A charges. That move and the cost savings
associated with the 10 percent reduction in staff, plus further streamlining
announced in March 1995, are expected to have a significant positive effect on
Gas Services operating earnings.
Fiscal 1995 capital expenditures amounted to $35.1 million. Outlays
included $15.3 million for natural gas gathering, $14.2 million for processing
facilities and $5.6 million for other activities.
18
<PAGE> 21
NATURAL GAS PROCESSING
Operating earnings from gas processing were 16 percent higher than those of
fiscal 1994, thanks to an improvement in profit margins late in fiscal 1995.
Nearly half of the year's operating earnings from gas processing came in the
final quarter. Because gas liquids are used as feedstocks for petrochemicals, a
consumer-driven rebound in petrochemical demand led some manufacturers to
ratchet up olefins production and expand capacity, stimulating the price of
NGLs.
While weighted average NGL prices dropped to as low as $10.86 a barrel in
March 1994, they rebounded later in the year, climbing to a high of $12.87 in
November. For the full fiscal year, NGL prices were 5 percent lower than in the
previous year, averaging $11.57 a barrel. A decline in natural gas feedstock
costs contributed to the increased margins and operating profits. Although low
natural gas prices reduce operating earnings from exploration and production,
they improve margins from gas processing. Under approximately half of the
contractual agreements with producers to extract NGLs from their gas, the
Company buys gas on the spot market to replace volumes consumed through fuel
use and shrinkage when the liquids are recovered. Profit margins from gas
processing were holding up well at the beginning of fiscal 1996, in part
because natural gas costs remained low.
Average daily NGL production was slightly lower in fiscal 1995 than in the
previous year--47,500 barrels versus 49,800 barrels. Poor plant economics early
in the year, caused by weak NGL margins, prompted a production cutback to as
low as 40,000 barrels a day. Profit margins started heading back up in April,
however, and by late in the year, the Company's production rose to as high as
50,000 barrels per day. This was achieved despite the sale of interests in four
processing plants and the consolidation and relocation of several others.
Because of better NGL margins, the Company was able to restore much of the
gas liquids reserves that were uneconomic to produce at the end of the prior
year. NGL reserves increased to 121.3 million barrels at the end of fiscal
1995, up 13 percent.
NATURAL GAS GATHERING AND MARKETING
A 34 percent drop in gas gathering and marketing operating earnings resulted
from weak demand and low margins on natural gas that the Company buys from
producers in North and East Central Texas, transports to market and then
resells.
Excluding the effect of our mid-year sale of the Winnie system, average
daily throughput declined 6 percent to 353,000 Mcf in fiscal 1995. Including
that effect, however, throughput fell 24 percent to 415,000 Mcf from 549,000
Mcf in the prior year.
Increased throughput resulting from the expansion of the joint-venture
(BAR CHART)
19
<PAGE> 22
Ferguson-Burleson gathering system should begin to offset some of the decline
resulting from the Winnie sale. A $35 million expansion of the 45 percent-owned
system, which serves the Austin Chalk area of East Central Texas, was started
in January 1995. The project will bring daily throughput capacity to
approximately 640,000 Mcf, from the current 280,000 Mcf. About 200,000 Mcf a
day of new capacity is expected to be available by the end of fiscal 1996, and
completion of the entire project is targeted for the middle of fiscal 1997.
This 44-mile extension will allow the Company to gather and resell gas that
is being discovered and developed in Washington and Grimes counties by our
partner in the pipeline venture, Union Pacific Resources Co., and by other
operators. Gas from the existing system yields approximately 26,000 barrels per
day of NGLs. Gas from the new wells to be served by the pipeline extension,
however, contains relatively small amounts of NGLs.
(BAR CHART)
OTHER
The MTBE gasoline additive plant at Mont Belvieu, Texas, in which the Company
owns a one-third partnership interest, experienced some start-up problems that
prevented the plant from making an expected contribution to second-half
earnings. As of late March 1995, production from the plant was approaching the
target of 12,500 barrels per day.
Sun Company, one of the partners, buys 100 percent of the MTBE plant's
production under a 10-year contract. We are supplying one-third of the butane
feedstock. The third partner is Enterprise Products, the plant's operator.
The 40,000-barrel-a-day expansion of the Gulf Coast Fractionators
partnership plant, also located at Mont Belvieu, came on stream in late
November. The plant, in which we hold a 38.75 percent interest, separates mixed
gas liquids into their components, which command higher prices than the
unfractionated liquids. A fire in April 1994 damaged the original
65,000-barrel-a-day plant, and its reopening coincided with completion of the
expansion. Insurance covered all but about $1 million of the Company's share of
the repairs and business interruption losses resulting from the six-month
shutdown. Early in fiscal 1996, the facility was operating at approximately
100,000 barrels a day.
Our partners in Gulf Coast Fractionators are Conoco, Inc., and Trident NGL.
The partnership collects a fee to fractionate liquids produced by the three
partners based on the volumes each runs through the plant. It also collects
volume-based fees to fractionate liquids produced by two third-party customers.
The partners share the profits from the plant based on their ownership
percentages, and each markets its own fractionated products.
20
<PAGE> 23
(PICTURE)
THE BRIDGEPORT, TEXAS, GAS PROCESSING PLANT PRODUCED ABOUT ONE-THIRD OF THE
COMPANY'S FISCAL 1995 NATURAL GAS LIQUIDS VOLUME.
21
<PAGE> 24
(PICTURE)
AN OUTSTANDING YEAR
22
<PAGE> 25
(PICTURE)
"...OPENING OF THE NEW REGIONAL SHOPPING MALL ...HAS LED TO A QUICKENING OF
COMMERCIAL ACTIVITY NEARBY, ENHANCING THE VALUE OF THE SURROUNDING 300 ACRES OF
COMPANY-OWNED LAND."
23
<PAGE> 26
REAL ESTATE OPERATIONS
OPENING OF THE WOODLANDS MALL, PASSAGE OF A CRUCIAL SCHOOL BOND ISSUE,
CONTINUATION OF ITS NEW HOME SALES LEADERSHIP POSITION AND RECORD-SETTING JOB
GROWTH
24
<PAGE> 27
REAL ESTATE DIVISION FINANCIAL HIGHLIGHTS
Year Ended January 31 (in thousands)
<TABLE>
<CAPTION>
1995 1994
----------- -----------
<S> <C> <C>
Revenues
The Woodlands . . . . . . . . . . . . . . $ 112,427 $ 108,218
Other . . . . . . . . . . . . . . . . . . 17,038 17,888
----------- -----------
$ 129,465 $ 126,106
=========== ===========
Segment operating earnings
The Woodlands . . . . . . . . . . . . . . $ 27,234 $ 24,601
Other . . . . . . . . . . . . . . . . . . (1,441) (3,523)
----------- -----------
25,793 21,078
Asset write-downs . . . . . . . . . . . . (5,661) -
----------- -----------
$ 20,132 $ 21,078
=========== ===========
Capital expenditures . . . . . . . . . . $ 65,123 $ 65,132
=========== ===========
</TABLE>
contributed to the best year operationally in The Woodlands' history. Exclusive
of asset write-downs, Real Estate Division operating earnings for fiscal
1995--the highest in a decade--were $25.8 million, 22 percent more than the
prior year's $21.1 million. However, segment operating earnings for fiscal 1995
were lowered to $20.1 million due to third-quarter write-downs of properties
outside The Woodlands.
During fiscal 1995, capital expenditures for the Real Estate Division
totaled $65.1 million, the same as in the prior year. More than 90 percent of
that was related to development of The Woodlands, the Company's 25,000-acre
master-planned community.
THE WOODLANDS
The Woodlands' population grew by 3,300 during the year, to more than 41,900.
Fiscal 1995 was the best year since fiscal 1983 in the number of residential
lots sold. For the fifth year in a row, The Woodlands was the top community in
new homes sales in the Houston region.
During the fiscal year just ended, 951 lots were sold to builders, compared
with 844 in the previous year. Due to a market shift in the sales mix to
lower-priced production homes, the average lot price dropped to $37,287 from
$39,055. However, the price per square foot increased by 9 percent.
Leasing remains strong at the Timber Mill and Forest View apartments,
new affordable housing projects located in the community. At year end,
occupancy at Company-owned and -managed apartments stood at 97 percent.
The Woodlands Mall opened in October, attracting an estimated 300,000
people during its grand opening period. The million-square-foot regional shop-
25
<PAGE> 28
ping center has Dillard's, Foley's, Sears and Mervyn's as anchor tenants and
now has more than 120 other shops and specialty retailers; in addition, a Sears
Auto Center opened recently. The Mall is a 50-50 joint venture with Sears'
Homart subsidiary, the operating partner. It was 96 percent leased at fiscal
year end.
As planned, the Mall's success has created added value on approximately 300
acres of adjacent property that is owned solely by the Company. Already opened
or under construction on that acreage are a Blockbuster Music store,
NationsBank, Grady's American Grill and Romano's Macaroni Grill. Also, in the
spring of 1995, agreements were made for creation of a multi-screen movie
(BAR CHART)
REAL ESTATE HOLDINGS At January 31, 1995
<TABLE>
<CAPTION>
Property Description Company-Owned
Acreage
- ----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
The Woodlands Master-planned, 25,000-acre
community located 27 miles north
of downtown Houston. 16,059
Land held for investment, Principally undeveloped properties
development or sale in Galveston, Grimes, Harris,
Montgomery, San Jacinto and
Waller counties, Texas. 37,747
Resort and residential Includes Pirates' Beach, Pirates'
properties Cove and other developed properties
on Galveston Island; Magnolia
Country subdivisions northwest
of Houston; and Cape Royale on
Lake Livingston. 789
------
54,595
======
</TABLE>
THE WOODLANDS STATISTICAL HIGHLIGHTS At January 31, except as noted
<TABLE>
<CAPTION>
1995 1994
----------- -----------
<S> <C> <C>
Population . . . . . . . . . . . . . . . 41,930 38,550
Employment (non-construction) . . . . . . 15,500 11,500
Properties managed by The Woodlands
Corporation Occupancy rates
Office . . . . . . . . . . . . . . . 90% 92%
Retail . . . . . . . . . . . . . . . 81% 66%
Apartments . . . . . . . . . . . . . 97% 92%
Woodlands Executive Conference Center,
Resort and Country Club
(annual average) . . . . . . . . . . 69% 62%
Square feet
Office-industrial . . . . . . . . . . 1,858,000 1,725,000
Retail . . . . . . . . . . . . . . . 633,000 479,000
</TABLE>
26
<PAGE> 29
GROWTH OF THE WOODLANDS TOWN CENTER
Rapid Expansion Over a Three-Year Period
(MAP)
27
<PAGE> 30
complex and a major restaurant on the road ringing the Mall, and for a Drury
Inn motor hotel on property fronting Interstate 45.
At Pinecroft Center, adjacent to the Mall, a Guadalajara Mexican Restaurant
was completed in the spring of 1995, and construction is under way on a Linens
'N Things retail store. During fiscal 1995, Barnes & Noble, Marshall's, Service
Merchandise and Toys R Us retail stores were completed in the
350,000-square-foot center, and Chili's, Jack-in-the-Box and The Black-eyed Pea
opened restaurants there.
The 137,000-square-foot Cochran's Crossing Shopping Center held its grand
opening in November and was 89 percent leased at the end of the fiscal year.
The center features a Kroger "Signature" store, an Eckerd Drug store and a
Shell service station, among other retail stores. Across the street, Burger
King and Boston Market restaurants opened during fiscal 1995.
(BAR CHART)
A major renovation was completed in September at the Wood Ridge Plaza
shopping center, across Interstate 45 from The Woodlands Mall, and both
occupancy and leasing rates have increased dramatically. The property was
purchased by the Company during fiscal 1993.
In the Research Forest, the Company's five Venture Technology Buildings
remained 100 percent leased at year end. During fiscal 1995, GeneMedicine
moved into its 38,000-square-foot facility, and Hughes Christensen announced
plans to expand its manufacturing and world headquarters.
The opening of the Mall, Cochran's Crossing retail center and buildings in
the Research Forest contributed to the addition of 4,000 new non-construction
jobs in The Woodlands--a 35 percent gain--bringing total non-construction
employment at year end to 15,500.
Overall, office building occupancy in The Woodlands stood at 90 percent at
year end. Allstate Insurance moved into 44,000 square feet of office space at
the Company's new 96,000-square-foot Parkwood II building in April, and King
Ranch, Inc., relocated its headquarters into 28,000 square feet there in
December.
During fiscal 1995, commercial and institutional land sales revenues
totaled $12 million from 13 transactions, including the sale of sites for a
park-and-ride facility, a medical specialty hospital and three bank branches.
The Woodlands also received $12.2 million in federal funding commitments for
major transportation improvements.
In Town Center, The Woodlands' cultural, entertainment and business
district, a 3,000-seat expansion is nearly complete at the Cynthia Woods
Mitchell Pavilion, a not-for-profit outdoor amphitheater, that will bring its
28
<PAGE> 31
(PICTURE)
THE WOODLANDS MALL, OPENED IN OCTOBER 1995, HAS BEEN A CATALYST FOR
SUBSTANTIAL ADDITIONAL COMMERCIAL DEVELOPMENT.
29
<PAGE> 32
capacity to 13,000. Since its opening in 1990, the Pavilion has become the
Houston area's premier outdoor entertainment center.
Business at The Woodlands Executive Conference Center, Resort and Country
Club set new records in fiscal 1995. Occupancy rates increased to 69 percent
from 62 percent the year before. In February, Shell Oil Company extended for
three years its sponsorship of the Shell Houston Open PGA golf tournament,
played on The Woodlands TPC Course and televised nationally on ABC.
An $85.5 million bond issue for the Conroe Independent School District
passed in an October special election. With these funds, the school system is
expected to be able to meet the needs of The Woodlands' growing population to
the year 2000. Also, the 3,500-student North Harris Montgomery Community
College campus is under development, with opening scheduled for August 1995.
During fiscal 1995, The Woodlands won an Award for Excellence from The
Urban Land Institute. It was the second consecutive year in which the community
was honored with a major international award.
OTHER
In Galveston, a 500-seat Landry's restaurant opened last May on Company-owned
property adjacent to The San Luis Resort and Conference Center. In Colorado,
the last remaining lot at Owl Creek was sold for $1.8 million, and at the close
of the fiscal year, outside funding was being sought for the Lake Catamount
development.
30
<PAGE> 33
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL POSITION AND RESULTS OF
OPERATIONS
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
LIQUIDITY AND CAPITAL RESOURCES
Refocusing of the Company's Operations. For many years now, the principal
strategy of the Company has been to acquire well-positioned energy and real
estate assets and to enhance their value through long-term development
programs. This strategy requires major front-end capital investments, which are
recovered over extended periods of time as energy reserves are produced and
real estate assets are developed and operated or sold. While it is not
anticipated that the overall nature of the Company's business or this strategy
will be altered, a significant refocusing of the Company's operations was begun
in fiscal 1995 and will continue in fiscal 1996.
Because of recurring softness in energy prices and the approaching
expiration in December 1997 of a favorably priced North Texas gas sales
contract, management has undertaken an extensive review of the Company's
operations and business strategies. The objective of this review is to position
the Company to better compete in the market-sensitive environment in which it
expects soon to be operating. Actions involved in this continuing process
include streamlining operations by concentrating activities on core businesses
with an appropriate mix of near-and long-term profit potential in which the
Company has a strong competitive position and by eliminating other activities
and the costs associated with them. Consistent with this, capital spending is
being directed almost exclusively to the drilling and recompletion of wells and
acquisitions of oil and gas properties in core areas, expanding gas processing
plants serving core areas, expansion of an Austin Chalk gas gathering system
and continued development of The Woodlands. In addition, beginning in fiscal
1995, the Company refocused its oil and gas exploration program by
concentrating more on development activities in core areas where it has had the
greatest success.
During fiscal 1995, as part of the refocusing initiative, a companywide
asset review was begun to identify and sell underutilized assets or non-core
holdings that have greater value to others. Three major energy assets were sold
for a total consideration of $164 million--$120 million for Winnie/Spindletop,
$35 million for the assets of Brazos Gas Compressing Company and $9 million for
drilling rigs. A cumulative pretax gain of $52.6 million was earned on these
transactions. As part of the ongoing study, the Company has identified certain
other assets that it plans to dispose of. These include marginally profitable
oil and gas properties, certain underutilized gas processing plants and gas
gathering systems, and a few real estate assets located outside The Woodlands.
Asset write-downs and restructuring charges totaling $36.9 million were
recorded in the second and third quarters to, among other things, reduce the
carrying values of the assets to be disposed of to their estimated sales values
(see Note 10 of Notes to Consolidated Financial Statements for additional
information). Since the asset study has not been completed, it is expected that
additional assets will be identified for disposal in the future.
The Financial Accounting Standards Board (FASB) issued a statement on March
31, 1995 that is intended to establish more consistent accounting standards for
measuring the recoverability of long-lived assets. In certain instances, the
statement specifies that carrying values of assets be written down to fair
values, which would result in larger charges than previously would have been
required. The Company believes that the adoption of this statement and the
completion of its ongoing asset management study are most likely to impact its
real estate located outside The Woodlands, particularly any which management
might subsequently conclude will not continue to be held for long-term
investment and development. The Company must adopt the proposed statement no
later than for its quarter ending April 30, 1996.
In a related activity, the Company's Gas Services Division (formerly known
as the Transmission and Processing Division) undertook a re-evaluation of its
operations. Resultant operational changes included the consolidation of certain
gas processing operations at larger, more efficient plants and the idling of
several smaller plants. Further, a voluntary incentive retirement program,
which reduced the number of full-time
31
<PAGE> 34
employees by approximately 70, was completed in June. And, the
Winnie/Spindletop operations were sold in the second quarter and the
compression operations in the third quarter. Although the Company is pursuing
the disposition or relocation of certain idle gas processing plants, these
actions are not expected to reduce its NGL production volumes.
To further reduce the Company's future costs, the Board of Directors
approved a companywide personnel reduction program in February 1995 that will
result in the elimination of at least 300 jobs by April 30, 1995. The Company
has offered a voluntary incentive retirement program to approximately 130
qualifying employees and will pay severance benefits to terminated employees
not eligible for that program. The aggregate pretax cost of these incremental
benefits (estimated at approximately $20 million) will be accrued during the
first quarter of fiscal 1996. The Company expects to recover this cost in
approximately one year.
During the fourth quarter of fiscal 1995, the Company changed its method of
accounting for oil and gas producing activities from the full cost method to
the successful efforts method and retroactively restated its financial
statements for prior periods. This accounting change complements the new
exploration strategy initiated during fiscal 1995. Since the successful efforts
method requires that nonproductive exploration costs be expensed, it provides a
more timely measurement of the effect of the exploration program changes than
would the full cost method, under which such costs are capitalized and
amortized. Also, use of successful efforts--for which the FASB has a stated
preference--will make the Company's results more comparable to those of other
oil and gas producers, most of whom use this method.
The retroactive expensing of nonproductive exploratory costs and
recognition of impairments on a field--rather than an overall--basis under
successful efforts reduced the net book value of the Company's oil and gas
properties and resulted in an after-tax reduction in stockholders' equity at
January 31, 1995 of $266.4 million. The Company's cash flows and borrowing
capacity were not affected by the change.
The reduced net book value of oil and gas properties resulted in lower DD&A
charges under the successful efforts method. Because of this, and since there
were not substantial nonproductive exploration costs or impairment charges,
fiscal 1995's net earnings were almost double what they would have been under
full cost accounting. See Note 1 of Notes to Consolidated Financial Statements
for additional information concerning the impact of this change on the
Company's financial statements.
Funding of the Company's Operations. The Company generally has funded its
investing activities using cash provided from operating activities and sales of
varying interests in mature real estate assets, supplemented to the extent
necessary with proceeds from long-term borrowings. Because of the previously
mentioned refocusing, it is expected that the Company's near-term need for
incremental borrowings will be lessened. And, depending on the timing of
planned asset sales, cost reductions, etc., the level of outstanding
indebtedness may decline, as it did in fiscal 1995. The primary sources of
borrowed funds in recent years have been bank credit agreements of the energy
and real estate subsidiaries and senior notes of the parent company. Needed
funds initially have been borrowed under the bank credit agreements, and the
credit availability under these facilities periodically has been restored by
paying down outstanding borrowings using proceeds from public offerings of
parent company senior notes. Additionally, during May 1993, the Company sold
5.9 million shares of its Class B common stock. The $123.4 million net proceeds
of this offering were used to fund the Company's buy-out of MEC Development,
Ltd., and drilling costs that otherwise would have been expenditures of that
partnership.
During January 1994, the Company issued $250 million of 6 3/4% Senior
Notes Due 2004 and $100 million of 5.10% Senior Notes Due 1997. The proceeds of
these borrowings were used to prepay $200 million of 11 1/4% Senior Notes Due
1999 and to pay down outstanding borrowings under the Company's bank credit
agreements. The 11 1/4% senior notes were redeemed on February 25, 1994 at a
price of 103.21% of principal. The $6.4 million debt prepayment premium paid in
connection with this redemption was expensed in January 1994 when the Company
gave notice that the notes would be redeemed. In addition to lowering
32
<PAGE> 35
interest costs, these transactions increased the Company's credit availability,
extended the maturities of indebtedness, reduced exposure to floating interest
rates and increased the percentage of indebtedness that is parent company debt.
The Company's committed bank revolving credit and commercial paper
facilities provide for an aggregate borrowing capacity of approximately $558
million, of which approximately $400 million was unused at January 31, 1995.
Exclusive of maturities under its bank credit facilities and commercial paper
program, the Company's aggregate five-year debt maturities totaled
approximately $235 million at January 31, 1995.
Effective November 30, 1994, the Company's $250 million Energy bank
revolving credit agreement was split into two parts--a $150 million five-year
facility maturing in November 1999 and a $100 million 364-day facility, which
the Company plans to extend annually with the banks' approval. The Company's
$165 million, five-year Real Estate revolving credit facility was also revised
and extended. During the last year of the Real Estate agreement, which
commences on November 30, 1998, the facility is to be reduced to 75% of its
initial size. During October 1994, the term of the Company's $125 million
commercial paper program was extended through June 1998 and the term of a
mortgage subsidiary's $18 million bank credit facility was extended through
July 1997.
The Company's business plan includes the use of energy and real estate
partnerships and sales in the normal course of business of mature real estate
properties to provide for some of its funding needs. The Company believes that
these resources, together with operating cash flows and additional borrowings
supported by cash flows and asset values, will be sufficient to allow it to
provide for its short-and long-term liquidity needs. Such short-term needs,
if any, can be met by supplementing operating cash flows with borrowings under
existing committed bank credit facilities while public debt and equity markets
can be accessed to provide for longer-term needs.
A portion of the cash proceeds received in connection with fiscal 1995
energy asset sales was used to pay down outstanding borrowings under the
Company's revolving credit and commercial paper facilities. At January 31,
1995, long-term debt totaled $895 million, $93.3 million below the balance at
the beginning of the year. This debt reduction would have been larger had it
not been for an April 1994 fire at Gulf Coast Fractionators' (GCF's) facility
in Mont Belvieu, Texas, at which much of the Company's NGL production is
fractionated. Because of the resultant shutdown of this facility, the Company
had approximately 1.4 million barrels of unfractionated NGLs at January 31,
1995. The GCF plant resumed operations during October 1994, and these
inventories began to be worked down during fiscal 1995's fourth quarter. It is
expected that the unfractionated quantities will be reduced to normal levels
during the first quarter of fiscal 1996. At January 31, 1995, the cost of the
Company's unfractionated NGLs totaled $15 million.
For the past two years, the Company has paid dividends of 48 cents and 53
cents per share, respectively, on its Class A and Class B common stock. The
Company has paid regular quarterly cash dividends on its common stock for an
uninterrupted period of 18 years. In December 1994, the Board of Directors
authorized open market repurchases of up to one million shares of the Company's
common stock. Through March 31, 1995, a total of 750,600 shares had been so
purchased at an aggregate cost of $11.8 million.
The estimated present value of pretax future net revenues of the Company's
energy reserves, calculated in accordance with Securities and Exchange
Commission regulations, totaled $956 million at January 31, 1995--$708 million
for natural gas and oil and $248 million for plant NGLs. At January 31, 1994,
these amounts totaled $986 million--$790 million for natural gas and oil and
$196 million for plant NGLs. The estimated future net revenues for gas and oil
were lower principally because of an 18% decline in market-sensitive natural
gas prices and the reduction by one year of the remaining term of the Company's
North Texas gas sales contract. Improved margins, which allowed the restoration
of NGL reserves that were not economic at the
33
<PAGE> 36
end of the prior year, were the primary cause of the increase in estimated
future net revenues for plant NGLs. Largely because of the exploration program
refocusing and downsizing, the Company's finding cost per barrel of oil
equivalent declined to $3.82 in fiscal 1995 from the prior year's $7.54.
CAPITAL AND EXPLORATORY EXPENDITURES
The following table compares the Company's fiscal 1996 budget for capital and
exploratory expenditures with its actual expenditures for fiscal 1995 and 1994
(in millions):
<TABLE>
<CAPTION>
1996 Budget 1995 1994
------------------- --------------------- --------------------
Amount % Amount % Amount %
----------- ----- ----------- ----- ----------- -----
Restated
<S> <C> <C> <C> <C> <C> <C>
Exploration and Production . . . . . . . $117.2 51.3 $115.1 52.4 $158.2 44.7
MEC Development, Ltd. buy-out . . . . . - - - - 78.3 22.1
Gas Services . . . . . . . . . . . . . . 41.6 18.2 35.1 16.0 48.6 13.7
Real Estate . . . . . . . . . . . . . . . 65.5 28.6 65.1 29.6 65.1 18.4
Corporate . . . . . . . . . . . . . . . . 4.4 1.9 4.3 2.0 3.9 1.1
------ ----- ------ ----- ------ -----
$228.7 100.0 $219.6 100.0 $354.1 100.0
====== ===== ====== ===== ====== =====
</TABLE>
The consolidated budget for fiscal 1995 expenditures, initially set at
$230.8 million, was later revised to $242.6 million. Fiscal 1995 spending
ultimately totaled $219.6 million, 9.5% below the revised budget, largely
because of reduced drilling expenditures late in the year in response to
depressed natural gas prices.
The Company's fiscal 1996 budget has been set at $228.7 million, 4.1% above
fiscal 1995's actual spending. The planned increase is attributable to larger
expenditures for the Company's 45% share of construction costs for a $35
million natural gas gathering system being built to serve an eastward extension
of Austin Chalk drilling activities by Union Pacific Resources Company, 55%
owner of this system, and others.
The fiscal 1996 budgeted outlays for exploration and production, real
estate and corporate activities are essentially unchanged from the prior-year
amounts. The Company replaced 171% of the natural gas reserves it produced in
fiscal 1995 and expects, even at the relatively low planned drilling level, to
more than replace the reserves it will produce in fiscal 1996. Real estate
expenditures, more than 90% of which are earmarked for The Woodlands, will
consist largely of spending for residential lot development and commercial
properties.
In addition to its consolidated budget, the Company participated through
partnerships in several significant construction projects in fiscal 1995. These
projects, which were funded principally with proceeds of loan agreements of the
partnerships, included an MTBE plant, expansion of GCF's fractionation facility
and construction of a regional mall in The Woodlands.
A partnership in which the Company has a one-third interest constructed an
MTBE (methyl tertiary butyl ether) plant at Mont Belvieu, Texas, with a design
capacity of 12,600 barrels per day. MTBE is an oxygenate used in the production
of environmentally cleaner gasoline. Each of the three partners in this venture
provides one-third of the plant's isobutane feedstock, and one of the partners,
Sun Company, Inc., is contractually obligated to purchase all of the MTBE
production for a period of 10 years. Plant construction costs, which totaled
$225 million, were funded through the partnership's $176 million loan agreement
and capital contributions from the partners. The plant commenced production in
June 1994 and, primarily because of start-up problems, has operated below its
design capacity (such volumes averaged 7,900 barrels per day during January
1995). Because of the plant's start-up problems, the partnership's loan will
not be converted to a nonrecourse term loan status by a May 31, 1995 deadline.
Because of this, the lenders could require the partners to repay the
partnership's debt. If this occurs, the Company has sufficient unused committed
lines of credit to fund its $58.7 million share of the partnership's debt.
34
<PAGE> 37
Through its 38.75% ownership interest in GCF, the Company participated in a
40,000 barrel-per-day expansion of an NGL fractionation plant at Mont Belvieu,
Texas. As previously noted, the plant resumed operations in October after an
April 1994 fire. The expansion portion of the plant began operating late in
October and reached full production during fiscal 1995's fourth quarter. In
connection with the $40 million expansion project and the entrance of Conoco,
Inc., into the partnership, GCF arranged an $85 million term loan in June 1993.
Of the loan proceeds, $40 million was distributed to the partners in fiscal
1994 (the Company's share of which was $15.5 million) and the remainder was
used to fund the expansion expenditures and to provide needed working capital.
Each of the partners has executed long-term contracts with GCF for the
fractionation of production from certain of their gas processing plants.
The Woodlands Mall, a one million square foot regional mall that opened in
October 1994, was developed by a partnership equally owned by the Company and
Homart Development Co., a subsidiary of Sears, Roebuck and Co. Costs of the
345,000-square-foot gross leasable area constructed by the partnership,
together with site development and other general costs, were funded with
proceeds of the partnership's $65 million loan agreement. This partnership
contributed positively to the Company's fourth-quarter operating earnings.
ENVIRONMENTAL AND OTHER 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 in
recent years, new environmental regulations and laws have been enacted, and the
enforcement of existing laws has been strengthened. The Company considers
compliance with environmental protection regulations and laws, and the related
costs, to be a necessary and manageable part of its business. To date, the
Company has not been faced with major clean-up obligations and has been able to
conform with environmental regulations without materially altering its
operating strategies.
However, complying with environmental regulations involves financial
responsibilities beyond the level the Company as an environmentally conscious
operator likely would otherwise incur and imposes additional constraints on the
manner in which its operations are conducted. Certain projects, such as the
real estate developments at Laffite's Cove in Galveston and at Lake Catamount
in Colorado, were significantly delayed while costly studies were performed to
satisfy regulatorily imposed demands. Additionally, the Company estimates that
it will spend approximately $5 million annually over the next two or three
years on environmental testing and compliance for its energy and real estate
operations that it likely would not spend absent the regulations. Of these
annual expenditures, approximately $1 million is related solely to compliance
with the Federal Clean Air Act. An estimated additional $1.4 million one-time
expenditure related to this Act is planned for fiscal 1996 to implement an
enhanced monitoring program for natural-gas-fired engines.
Nevertheless, 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.
Real estate development activities also are affected by regulations,
policies and actions of various governmental agencies and other entities
relating to essential public services, including utilities, telephone service
and schools. To date, these public services have been obtained in a manner
that has enhanced the Company's development activities, and management expects
that this will continue to be the case for the foreseeable future.
35
<PAGE> 38
OPERATING STATISTICS
Certain operating statistics (including, where applicable, proportional
interests in equity partnerships) for fiscal 1995, 1994 and 1993 follow:
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Average daily volumes
Natural gas sales (Mcf) . . . . . . . . . 214,100 193,800 149,000
Crude oil and condensate sales (Bbls) . . 6,300 6,000 5,600
Natural gas liquids produced (Bbls) . . . 47,500 49,800 47,200
Pipeline throughput (Mcf)
Total . . . . . . . . . . . . . . . . . 415,000 549,000 566,000
Exclusive of Winnie Pipeline . . . . . 353,000 386,000 398,000
Average sales prices
Natural gas (per Mcf) . . . . . . . . . . $2.71 $2.86 $2.84
Crude oil and condensate (per Bbl) . . . 15.75 16.31 18.49
Natural gas liquids produced (per Bbl) . 11.57 12.18 13.41
Residential lot sales - The Woodlands
Lots sold . . . . . . . . . . . . . . . . 951 844 911
Average price . . . . . . . . . . . . . . $37,287 $39,055 $38,196
Average price per square foot . . . . . . 3.70 3.38 3.14
</TABLE>
RESULTS OF OPERATIONS - FISCAL 1995 COMPARED WITH FISCAL 1994 (RESTATED)
As previously noted, the Company's financial statements have been restated to
give effect to its recent change to the successful efforts method of accounting
for oil and gas producing activities. The information included in this section
has been so restated for all periods shown.
The Company's results for fiscal 1995 and 1994--both before and after
unusual items--are summarized on the table on the following page. Largely
because of the impact of unusual items, fiscal 1995 net earnings exceeded those
of the previous year by approximately $21.2 million. Fiscal 1995 earnings
included $52.6 million in pretax gains from major energy asset sales but were
reduced by charges totaling $36.9 million associated with restructuring and
asset write-downs. The net effect was an increase of $15.7 million, or $8.6
million after tax. Fiscal 1994's net earnings were reduced $12 million (after
tax) by an extraordinary charge for early debt retirement and a deferred tax
provision related to the August 1993 Federal corporate income tax rate
increase.
Excluding the unusual items, fiscal 1995's earnings were almost unchanged
from those of the prior year. Favorable year-to-year earnings variances
included sharply lower fiscal 1995 exploratory dry hole costs and impairment
charges--largely related to the Company's refocused exploration emphasis--and
improved earnings from higher natural gas production and real estate
operations. These gains were essentially offset, however, by the negative
impact of fiscal 1995's lower natural gas liquids prices, reduced gas gathering
and marketing margins, a higher effective income tax rate and fiscal 1994's
one-time Exploration and Production earnings items.
36
<PAGE> 39
The following table and discussion identify and explain the major increases
(decreases) in earnings (in millions):
<TABLE>
<CAPTION>
Segment Operating Earnings
------------------------------------------
Exploration
and Gas Real Pretax Net
Production Services Estate Other* Earnings Earnings
------------ ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Fiscal 1994 amounts (restated) . . . . . $ 68.2 $ 42.6 $ 21.1 $ (84.5) $ 47.4 $ 24.6
Add back fiscal 1994 unusual items
Deferred tax charge caused by
increase in Federal income tax rate . . - - - - - 6.6
Extraordinary item . . . . . . . . . . . - - - - - 5.4
------------ ----------- ----------- ----------- ----------- -----------
Fiscal 1994 amounts
before unusual items . . . . . . . . . 68.2 42.6 21.1 (84.5) 47.4 36.6
------------ ----------- ----------- ----------- ----------- -----------
Major increases (decreases)
Lower exploratory dry hole costs . . . . 16.6 - - - 16.6 10.8
Reduced proved property impairments . . . 8.9 - - - 8.9 5.8
Natural gas production
Market-sensitive sales price . . . . . (8.7) - - - (8.7) (5.7)
Market-sensitive sales volumes . . . . 3.8 - - - 3.8 2.5
Sales under fixed-price contracts . . . 3.1 - - - 3.1 2.0
Natural gas processing
NGL price . . . . . . . . . . . . . . . - (10.3) - - (10.3) (6.7)
Production volumes . . . . . . . . . . - (1.4) - - (1.4) (.9)
Reduced feedstock costs due to
Lower market-sensitive gas prices . . - 8.5 - - 8.5 5.5
Lower NGL prices . . . . . . . . . . - 1.4 - - 1.4 .9
Natural gas gathering and marketing . . . - (6.4) - - (6.4) (4.2)
Real estate . . . . . . . . . . . . . . . - - 3.6 - 3.6 2.3
Interest expense incurred . . . . . . . . - - - 4.1 4.1 2.7
Capitalized interest . . . . . . . . . . - - - (5.1) (5.1) (3.3)
Other
Fiscal 1994 one-time earnings items . . (6.9) - - - (6.9) (4.5)
SAR/Bonus unit expense accruals . . . . 1.8 .8 1.1 2.1 5.8 3.8
Venture capital investments . . . . . . - - - (4.8) (4.8) (3.1)
Fiscal 1994 excise tax refunds . . . . (1.0) - - (1.9) (2.9) (1.9)
Miscellaneous . . . . . . . . . . . . . (1.7) (.5) - .3 (1.9) (1.3)
Higher effective income tax rate . . . . - - - - - (4.2)
------------ ----------- ----------- ----------- ----------- -----------
15.9 (7.9) 4.7 (5.3) 7.4 .5
------------ ----------- ----------- ----------- ----------- -----------
Fiscal 1995 amounts
before unusual items . . . . . . . . . 84.1 34.7 25.8 (89.8) 54.8 37.1
------------ ----------- ----------- ----------- ----------- -----------
Fiscal 1995 unusual items (see Note 10 of
Notes to Consolidated Financial Statements)
Gains on major energy asset sales . . . . 3.8 48.8 - - 52.6 32.7
Restructuring charges/asset write-downs . - (31.2) - - (31.2) (20.3)
Real estate asset write-downs . . . . . . - - (5.7) - (5.7) (3.7)
------------ ----------- ----------- ----------- ----------- -----------
3.8 17.6 (5.7) - 15.7 8.7
------------ ----------- ----------- ----------- ----------- -----------
Fiscal 1995 amounts
after unusual items . . . . . . . . . . $ 87.9 $ 52.3 $ 20.1 $ (89.8) $ 70.5 $ 45.8
============ =========== =========== =========== =========== ===========
</TABLE>
- --------------------
* Includes general and administrative expense and other expense.
37
<PAGE> 40
FISCAL 1994 UNUSUAL ITEMS
Deferred tax charge caused by increase in Federal income tax rate. Deferred
Federal income tax expense for the third quarter of fiscal 1994 included $6.6
million attributable to an increase enacted in August 1993 in the corporate
statutory Federal income tax rate from 34% to 35%. Because of the rate change,
it was necessary to increase the Company's deferred tax liability by an amount
equal to 1% of the aggregate (restated) cumulative difference between the book
and tax bases of its assets and liabilities.
Extraordinary item. In January 1994, the Company called for redemption of its
$200 million of 11 1/4% Senior Notes Due 1999. The redemption price was 103.21%
of principal, and the premium and related unamortized debt issuance costs were
expensed, resulting in an extraordinary loss on the early retirement of debt of
$5.4 million (after tax benefits of $2.9 million).
EXPLORATION AND PRODUCTION OVERVIEW
Exploration and Production Division operating earnings before unusual items
increased $15.9 million during fiscal 1995, to $84.1 million. This improvement
was the result of lower expenses for exploratory dry holes and proved property
impairments, the impact of which was partially offset by lower market-
sensitive natural gas prices in the last half of fiscal 1995 and the
nonrecurrence of one-time earnings items which added $6.9 million to the prior
year's operating earnings. Average daily natural gas sales volumes rose to
214,100 Mcf from 193,800 in the prior year. This occurred primarily as a result
of the Company's increased fiscal 1994 drilling program and, to a lesser
extent, the buy-out of MEC Development, Ltd., effective May 1, 1993.
Lower exploratory dry hole costs ($16.6 million increase). Exploratory dry hole
costs totaled $1 million in fiscal 1995, down from $17.6 million in fiscal
1994, improving operating earnings by $16.6 million. The reduced costs were the
result of a new exploration strategy initiated during fiscal 1995 under which
spending was reduced and focused more on core areas where the Company has a
good finding record. Also, the prior-year expense was adversely affected by the
Company's participation in an unsuccessful five-well offshore program operated
by a third party.
Reduced proved property impairments ($8.9 million increase). Expenses for
property impairments declined to $4.7 million in fiscal 1995 from $13.6 million
in the prior year, increasing operating earnings by $8.9 million. Downward
revisions of reserve estimates for certain oil and gas properties caused fiscal
1994 impairments to be unusually large.
Natural Gas - Market-sensitive sales price ($8.7 million decrease). The
Company's market-sensitive realizations averaged $1.90 per Mcf during fiscal
1995, down from $2.14 in the prior year, reducing operating earnings by $8.7
million. Market-sensitive natural gas prices were sharply lower during the
last half of fiscal 1995 as demand declined largely because of mild weather and
full storage caverns.
Natural Gas - Market-sensitive sales volume ($3.8 million increase).
Market-sensitive sales volumes increased 18% to 108,800 Mcf per day from the
prior year's 92,000. After related operating costs and DD&A, this increased
operating earnings by $3.8 million. Production rose primarily due to wells
drilled in fiscal 1994; production from the Calhoun Unit, where the Company
ceased reinjecting gas and began selling it in August 1993; and the previously
mentioned MEC Development, Ltd. buy-out, which added 1,500 Mcf per day to the
average volume. This increase would have been larger had the Company not
curtailed certain market-sensitive production late in the year because of low
prices.
Natural Gas - Sales under fixed-price contracts ($3.1 million increase).
Production under fixed-price contracts averaged 105,300 Mcf per day at a price
of $3.53 per Mcf; such amounts were 101,800 Mcf and $3.52, respectively, in
fiscal 1994. Almost 90% of these volumes consist of sales under a long-term
contract with Natural Gas Pipeline Company of America (NGPL), which covers most
of the Company's North Texas production and provides for annual increases of
$.25 per MMBtu in the fixed sales price on January 1 of each year. After
expiration of this contract in December 1997, it is expected that this
production will be sold at the then-existing prices for market-sensitive gas.
The fiscal 1995 volume increase resulted largely from the
38
<PAGE> 41
partnership buy-out, which added approximately 2,800 Mcf per day to the
period's volumes. The positive impact of fiscal 1995's higher production
volumes and the annual price increase under the NGPL contract was largely
offset by lower realizations for leasehold NGLs and the lack in fiscal 1995 of
any amortization of price-related deferred contract restructuring proceeds
since this amortization was completed during the prior year (such amortization
added $.12 per Mcf to the prior-period's average price for sales under
fixed-price contracts). Certain volume-related deferred contract restructuring
proceeds continue to be amortized. Although not increasing cash flows, such
amortization, after related DD&A expense, added $12.1 million and $12.6 million
to operating earnings in fiscal 1995 and 1994. This amortization will continue
to decline annually through fiscal 1998 when the deferred proceeds will be
fully amortized.
GAS SERVICES OVERVIEW
Gas Services Division operating earnings before unusual items declined $7.9
million during fiscal 1995 largely because of lower NGL sales prices and
reduced earnings from gas gathering and marketing activities. The unfavorable
impact of lower NGL prices on natural gas processing earnings was largely
offset, however, by reduced feedstock costs, most of which was related to
fiscal 1995's lower market-sensitive natural gas prices. NGL production
volumes averaged 47,500 Bbls per day--down from 49,800 during the prior
year--as facilities were idled early in the year in response to inadequate
margins for most plants operating principally under keep-whole processing
arrangements. NGL margins improved subsequently, and certain plants that were
idle in the first quarter resumed operations.
Natural Gas Processing - NGL price ($10.3 million decrease). The average price
for NGLs produced of $11.57 per barrel was $.61 per barrel below the average
for fiscal 1994, reducing operating earnings by $10.3 million. The lower
prices, principally in the first half of the year, were largely the result of
lower prices for crude oil--which adversely affected NGL prices--and a soft
world economy, which reduced the demand for chemical feedstocks. The Company's
average NGL transfer price for the fourth quarter was $12.22 per barrel, $1.63
above the average for the comparable prior-year period.
Natural Gas Processing - Production volumes ($1.4 million decrease). NGL
production volumes averaged 47,500 barrels per day, down 5% from the previous
year's 49,800. As a result of the relatively high market-sensitive feedstock
costs during fiscal 1995's first quarter, when NGL prices were severely
depressed, most plants operating under keep-whole processing agreements were
uneconomical to operate and were shut down during that period. Certain of these
plants resumed operations in the second quarter, and production volumes
averaged 48,800 barrels per day during the subsequent nine months, up from the
first quarter's 43,200.
Natural Gas Processing - Reduced feedstock costs ($9.9 million increase).
Feedstock costs consist primarily of amounts paid to the natural gas producers.
Such amounts are based either on the value of natural gas consumed in
processing under keep-whole agreements or on a percentage of the value of NGLs
produced under percent-of-proceeds agreements. Accordingly, feedstock costs
under keep-whole agreements vary directly with market-sensitive natural gas
prices, while costs under percentage-of-proceeds agreements vary directly with
NGL prices. Consequently, fiscal 1995's lower market-sensitive gas prices
caused feedstock costs to decline, increasing operating earnings by $8.5
million, while the lower NGL realizations also reduced feedstock costs,
increasing operating earnings by $1.4 million.
Natural Gas Gathering and Marketing ($6.4 million decrease). Excluding the
impact of lower SAR/Bonus unit expense accruals, operating earnings (exclusive
of unusual items) from natural gas gathering and marketing activities were $6.4
million below those of the prior year. This decline was primarily the result of
lower volumes and margins for the wholly owned North Texas system and the
45%-owned venture with Union Pacific Resources Company (UPRC). For the last
several years, throughput on the North Texas system has declined because
drilling activity in its service area has been too low to offset normal
production declines on existing wells. This system's lower fiscal 1995 margins
occurred primarily as a result of the expiration late last year of certain
favorable contracts. Fiscal 1995 volumes and margins for the UPRC venture were
lower largely because of revisions effective late in the prior fiscal year of
natural gas sales contracts with Texas
39
<PAGE> 42
Utilities Fuel Company (TUFCO). Purchases under these contracts by TUFCO during
fiscal 1995 averaged 50,000 MMBtu per day (22,500 for the Company's 45%
interest) at a price of $2.99, contrasted with 58,900 (26,500) at $3.42 during
the prior year. System volumes not sold to TUFCO were sold to other purchasers
at substantially lower margins.
REAL ESTATE AND OTHER
Real Estate ($3.6 million increase). Excluding the impact of lower SAR/Bonus
unit expense accruals, Real Estate Division operating earnings before unusual
items rose by $3.6 million during fiscal 1995. The improvement, which was
concentrated in The Woodlands, was largely due to increased profits from
residential lot sales and improved earnings from commercial activities.
Earnings from residential lot sales were $1 million above those of fiscal
1994 due to a 13% increase in the number of lots sold (951 vs. 844) and a 9%
increase in the average sales price for production lots. Production lot sales
were 29% higher than in the prior year both because of the community's strong
competitive position in the Houston-area market and because lot sales early
last year were adversely affected by inventory shortages related to delays in
the opening of the Village of Alden Bridge. Despite sharp rises in 30-year
mortgage interest rates, production lot sales were strong during the year as
The Woodlands became a more attractive community to new homebuyers because of
the new retail centers and improved traffic access. However, the number of
estate and custom lots sold declined in fiscal 1995. This decline corresponded
with a national downward trend for larger home sales as upper-income buyers'
concerns about job security reportedly made them more conservative in their
home purchases.
Earnings from commercial and institutional land sales were essentially
equal in fiscal 1995 and 1994, but the nature of the transactions changed
substantially. Fiscal 1995 sales included a sizable number of retail sites
while much of fiscal 1994's earnings was related to the fourth quarter sale of
a large tract for a funeral home and cemetery. Higher earnings from other
commercial activities in The Woodlands accounted for $2.1 million of the
increase in real estate operating earnings. Several factors contributed to this
increase, including greater corporate conference activity at The Woodlands
Executive Conference Center and Resort and higher earnings from office and
research/technology buildings, most of which was related to increased
occupancy.
Interest expense incurred. Interest expense incurred during fiscal 1995 was
$4.1 million below that of the prior year partially due to a decline in the
Company's effective interest rate (to 7.4% from 7.7%). This was caused by a
decline of two percentage points (from 9.8% to 7.8%) in the average rate for
the Company's fixed-rate debt, which occurred because of the refunding in
February 1994 of $200 million of 11 1/4% Senior Notes with proceeds from
January 1994 sales of $250 million of 6 3/4% Senior Notes and $100 million of
5.10% Senior Notes. Excess proceeds were used to pay down outstanding
borrowings under the Company's bank credit agreements. The beneficial impact of
the senior note refunding was partially offset by a decline (from 37% to 19%)
in the percentage of debt that is lower-cost, floating-rate debt and a rise in
short-term (variable) interest rates.
Also contributing to the decline in interest expense incurred was a slight
reduction in the Company's average debt balance in fiscal 1995 which
principally resulted from receipts of proceeds from major energy asset sales.
Capitalized interest. The amount of interest capitalized fell by $5.1 million
in fiscal 1995 because of a decline in the average energy and real estate asset
balances subject to capitalization and, to a lesser extent, the Company's lower
effective interest rate during that period.
40
<PAGE> 43
Other - Fiscal 1994 one-time earnings items ($6.9 million decrease). One-time
items added a total of $6.9 million to Exploration and Production Division
operating earnings in fiscal 1994's first and second quarters. During the
second quarter, the Company recognized certain natural gas revenues ($3.9
million) which previously had been deferred because of future obligations for
which the Company was no longer liable and recorded a gain of $1.1 million on
the sale of certain assets. During the first quarter of fiscal 1994, a $1.9
million contingent liability related to contractual matters--which had been
recorded several years earlier--was reversed when it was determined that it was
no longer needed.
Other - SAR/Bonus unit expense accruals ($5.8 million increase). During fiscal
1995, $1.9 million in SAR/Bonus unit expense accrual reversals were recorded as
the average market price of the Company's common stock declined $4.94 per
share. Conversely, in the prior year, expense accruals of $3.9 million were
recorded as the average stock price rose by $5.00 per share. Also contributing
to this variance were fiscal 1994 exercises at higher mid-year prices of
SARs/Bonus units, many of which had January 1994 expiration dates. The impact
of stock price changes was less in fiscal 1995 because substantially fewer
units were outstanding.
Other - Fiscal 1994 excise tax refunds ($2.9 million decrease). During last
year's fourth quarter, the Company recognized excise tax refunds applicable to
prior years, of which $1 million was for taxes previously charged to oil and
gas operating earnings and $1.9 million was for accrued interest on these tax
overpayments.
Other - Venture capital investments ($4.8 million decrease). The Company has
investments in venture capital companies (many located in The Woodlands'
Research Forest), several of which have gone public in recent years. In
accordance with industry practice, these investments are carried at estimated
fair values. Because of sharp declines in the stock market prices for start-up
biotechnology companies, the estimated values of these investments declined
substantially in fiscal 1995. This resulted in the recording of charges
aggregating $3.8 million during fiscal 1995. Conversely, unrealized
appreciation of $1 million was recognized during the third quarter of fiscal
1994 because of increases in the estimated values of these investments.
Higher effective income tax rate. The Company's effective income tax rate in
fiscal 1995 of 35.1% was up sharply from fiscal 1994's 22.7% (exclusive of the
impact of the August 1993 increase in the corporate statutory Federal income
tax rate). This occurred because of an increased provision for deferred state
income taxes in fiscal 1995 and a decline in available Federal tax credits for
natural gas produced from wells qualifying under Section 29 of the Internal
Revenue Code as production from those wells declined.
RESULTS OF OPERATIONS - FISCAL 1994 COMPARED WITH FISCAL 1993 (BOTH RESTATED)
The Company's results for fiscal 1994 and 1993--both before and after unusual
items which affected each year's earnings--are shown on the table on the
following page. Exclusive of the unusual items, the Company earned $36.6
million in fiscal 1994, compared with $58.8 million in the prior year. After
the unusual items, net earnings were $24.6 million ($.48 per share on
51,004,000 shares) in fiscal 1994 and $27.3 million ($.58 per share on
46,858,000 shares) in fiscal 1993. The average number of outstanding shares
rose primarily because of the May 1993 sale of 5.9 million Class B shares.
41
<PAGE> 44
Exclusive of unusual items, fiscal 1994 net earnings were $22.2 million
below those of the previous year as Gas Services earnings were down sharply,
particularly in the last half of the year when softening NGL sales prices and
rising natural gas feedstock costs combined to eliminate gas processing margins
for many keep-whole plants. This was partially offset by higher earnings from
Exploration and Production activities. The following table and discussion
identify and explain the major increases (decreases) in earnings (in millions):
<TABLE>
<CAPTION>
Segment Operating Earnings
-----------------------------------------
Exploration
and Gas Real Pretax Net
Production Services Estate Other* Earnings Earnings
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Fiscal 1993 amounts (restated) . . . . . $ 37.3 $ 88.5 $ 22.8 $ (88.6) $ 60.0 $ 27.3
Add back fiscal 1993 unusual items
Restructuring charges . . . . . . . . . . 20.7 - - .5 21.2 13.7
Extraordinary item . . . . . . . . . . . - - - - - 7.3
Cumulative effect of change
in accounting methods . . . . . . . . . - - - - - 10.5
----------- ----------- ----------- ----------- ----------- -----------
Fiscal 1993 amounts
before unusual items . . . . . . . . . 58.0 88.5 22.8 (88.1) 81.2 58.8
----------- ----------- ----------- ----------- ----------- -----------
Major increases (decreases)
Natural gas
Sales under fixed-price contracts . . . 13.7 - - - 13.7 8.9
Market-sensitive sales . . . . . . . . 13.5 - - - 13.5 8.8
Higher exploratory dry hole costs . . . . (13.2) - - - (13.2) (8.6)
Increased proved property impairments . . (11.3) - - - (11.3) (7.3)
Oil and condensate sales . . . . . . . . (2.8) - - - (2.8) (1.8)
Natural gas processing
NGL price . . . . . . . . . . . . . . . - (16.4) - - (16.4) (10.7)
Marketing activities . . . . . . . . . - (6.9) - - (6.9) (4.5)
Increased cost of sales . . . . . . . . - (10.6) - - (10.6) (6.9)
Full year's ownership of
C&L Processors' (C&L) plants . . . . - 3.0 - - 3.0 2.0
Production volumes (excluding
impact of C&L plant acquisitions) . . - (1.9) - - (1.9) (1.2)
Natural gas gathering and marketing . . . - (6.6) - - (6.6) (4.3)
Real estate . . . . . . . . . . . . . . . - - (1.1) - (1.1) (.7)
Interest expense incurred . . . . . . . . - - - 1.2 1.2 .8
Other
One-time earnings items (see page 41) . 6.9 - - - 6.9 4.5
Excise tax refunds (see page 41) . . . 1.0 - - 1.9 2.9 1.9
SAR/Bonus unit expense accruals . . . . (1.0) (.4) (.6) (1.1) (3.1) (2.0)
Miscellaneous . . . . . . . . . . . . . 3.4 (6.1) - 1.6 (1.1) (1.1)
----------- ----------- ----------- ----------- ----------- -----------
10.2 (45.9) (1.7) 3.6 (33.8) (22.2)
----------- ----------- ----------- ----------- ----------- -----------
Fiscal 1994 amounts
before unusual items (restated) . . . . 68.2 42.6 21.1 (84.5) 47.4 36.6
Fiscal 1994 unusual items (see page 38) . - - - - - (12.0)
----------- ----------- ----------- ----------- ----------- -----------
Fiscal 1994 amounts
after unusual items (restated) . . . . $ 68.2 $ 42.6 $ 21.1 $ (84.5) $ 47.4 $ 24.6
=========== =========== =========== =========== =========== ===========
</TABLE>
________________
* Includes general and administrative expense and other expense.
42
<PAGE> 45
FISCAL 1993 UNUSUAL ITEMS
Restructuring charges. Pretax restructuring charges of approximately $21.2
million ($8 million of cash costs and $13.2 million of additional DD&A and
asset write-downs) were recorded in fiscal 1993's first quarter, all but $0.5
million of which were related to a reorganization of oil and gas exploration
and production activities. See Note 10 of Notes to Consolidated Financial
Statements for additional information.
Extraordinary item. On April 13, 1992, the Company completed the early
retirement of its $250 million of 11 1/4% Senior Notes Due 1997. The redemption
price was 103.21% of principal, and the premium and related unamortized debt
issuance costs were expensed, resulting in an extraordinary loss of $7.3
million (after tax benefits of $3.7 million).
Cumulative effect of change in accounting methods. Effective February 1, 1992,
the Company adopted SFAS No. 106 concerning postretirement medical benefits by
recording, as the cumulative effect of a change in accounting methods,
prior-service cost of $15.9 million. After a tax benefit of $5.4 million, this
reduced fiscal 1993's net earnings by $10.5 million.
EXPLORATION AND PRODUCTION OVERVIEW
Excluding the effect of the prior year's restructuring charges, Exploration and
Production Division operating earnings rose by $10.2 million in fiscal 1994, to
$68.2 million. This resulted largely because of sharply higher natural gas
volumes and prices (including the impact of the previously mentioned buy-out
of MEC Development, Ltd., effective May 1, 1993) and the previously discussed
$6.9 million of one-time earnings items. The favorable earnings impact of
these variances was partially offset by higher fiscal 1994 expenses for
exploratory dry holes and proved property impairments.
Natural Gas - Sales under fixed-price contracts ($13.7 million increase).
Production under fixed-price contracts averaged 101,700 Mcf per day at a price
of $3.52 per Mcf during fiscal 1994; such amounts were 85,300 and $3.54,
respectively, during the prior year. The volume increase was largely the result
of the acquisition in December 1992 of additional interests in producing
properties that had been owned by MEC Development, Ltd., and the buy-out of the
limited partner's remaining interests in May 1993. The average sales price
received for contract natural gas was virtually unchanged as the positive
impact of a $.25 per MMBtu annual increase under the NGPL sales contract was
essentially offset by lower realizations for leasehold natural gas liquids and
reduced amortization of deferred restructuring proceeds associated with the
NGPL contract.
Natural Gas - Market-sensitive sales ($13.5 million increase). The average
sales price received by the Company for market-sensitive gas during fiscal 1994
was $2.14 per Mcf, up 13% from the previous year's $1.90. Production volumes
rose 45% to 92,100 Mcf per day. The previously discussed acquisitions of
partnership interests contributed to the higher volumes. Also, most of the
Company's properties were at full production during fiscal 1994, whereas
production had been curtailed during the first half of fiscal 1993 in response
to depressed prices.
Higher exploratory dry hole costs ($13.2 million decrease). Exploratory dry
hole costs increased to $17.6 million in fiscal 1994 from $4.4 million in the
prior year, reducing operating earnings by $13.2 million. This unfavorable
variance resulted primarily from the Company's participation in fiscal 1994 in
an unsuccessful five-well exploratory offshore drilling program operated by a
third party.
Increased proved property impairments ($11.3 million decrease). Expenses for
proved property impairments totaled $13.6 million in fiscal 1994, up from $2.3
million in the prior year, reducing operating earnings by $11.3 million. As
discussed on page 38, the Company's fiscal 1994 impairments were unusually
large.
43
<PAGE> 46
Oil and condensate sales ($2.8 million decrease). Fiscal 1994's average sales
price for oil and condensate of $16.31 per barrel was down 12% from the
previous year's $18.49, reducing operating earnings by $4.6 million. Partially
offsetting the effect of the lower prices was an increase in average production
volumes of 400 barrels per day, which added $1.4 million to operating earnings.
GAS SERVICES OVERVIEW
Operating earnings declined $45.9 million (52%) in fiscal 1994 principally
because of sharply lower natural gas processing margins and reduced earnings
from gas gathering and marketing operations. NGL production volumes averaged
49,800 Bbls per day, up from 47,200 during fiscal 1993, largely because of the
acquisition by a 50%-owned partnership of interests in 13 plants effective
August 1, 1992, which more than offset volume declines at other plants.
Natural Gas Processing - NGL price ($16.4 million decrease). The average price
for NGLs produced during fiscal 1994 declined $1.23 per Bbl to $12.18, reducing
operating earnings by $16.4 million. NGL prices were depressed, particularly in
the last half of fiscal 1994, by lower crude oil prices worldwide and excess
NGL inventories across the nation.
Natural Gas Processing - Marketing activities ($6.9 million decrease). Because
of a time lag between the production of unfractionated NGLs and the sale of the
fractionated products (propane, ethane, etc.), the Company's marketing
activities generally benefit from a rising trend in NGL prices and absorb
losses when such prices decline. Principally because NGL prices declined during
much of fiscal 1994 after increasing during most of the previous year, a $6.9
million unfavorable year-to-year operating earnings variance for marketing
activities was reported.
Natural Gas Processing - Increased cost of sales ($10.6 million decrease).
Feedstock costs under keep-whole contracts rose substantially during fiscal
1994 because of the previously mentioned increase in market-sensitive natural
gas prices. Also contributing to the year-to-year rise in costs was the
Company's successful use of futures-market transactions in fiscal 1993 to fix
the price on a portion of its natural gas feedstock requirements, reducing its
costs by $3.5 million; there were no such transactions in fiscal 1994.
Natural Gas Processing - Full year's ownership of C&L Processors' plants ($3
million increase). The acquisition by C&L Processors, a 50%-owned partnership,
of interests in 13 gas processing plants effective August 1, 1992 added $3
million to the Company's gas processing operating earnings during the first
half of fiscal 1994. The comparable prior-year period's results did not include
these plants. Since the partnership is accounted for on an equity basis, these
earnings are after all expenses, including interest charges, which were
substantial since the acquisition was funded entirely by partnership
borrowings.
Natural Gas Processing - Production volumes, excluding impact of C&L plant
acquisitions ($1.9 million decrease). For plants other than those owned by C&L
Processors, the Company's average daily production volumes during fiscal 1994
totaled 41,700 barrels per day, 1,100 barrels per day below the prior-year
level. This decline, which lowered operating earnings by $1.9 million, was
principally the result of reduced throughput for certain plants because of
normal production declines for natural gas wells in their service areas and
fourth-quarter shutdowns of other plants because of inadequate processing
margins.
Natural Gas Gathering and Marketing ($6.6 million decrease). Excluding the
effect of increased SAR/Bonus unit expense accruals, fiscal 1994 operating
earnings from natural gas gathering and marketing activities were $6.6 million
below those of the prior year. The principal causes of this decline were lower
margins for the wholly owned Winnie Pipeline system and for the 45%-owned UPRC
venture. Winnie's margins were lower primarily because of the required
renegotiation of certain contracts in the first quarter of calendar 1993 (when
market-sensitive natural gas prices rose to a level exceeding the equivalent
price for fuel oil) and
44
<PAGE> 47
because of volume declines caused by certain contract terminations which
occurred late in fiscal 1993. The margin decline for the UPRC venture was
largely the result of changes in certain contracts (see page 39 for additional
information). Partially offsetting the effect of the lower margins were
increased fiscal 1994 earnings from the marketing of "off-system" natural gas.
REAL ESTATE AND OTHER
Real estate ($1.1 million decrease). Excluding the effect of increased
SAR/Bonus unit expense accruals, Real Estate Division operating earnings during
fiscal 1994 were $1.1 million below those of the prior year. The absence of a
commercial property transaction similar to fiscal 1993's sale of a half
interest in the Panther Creek Retail Center, a 7% decline in residential lot
sales in The Woodlands and sharply lower sales of resort lots contributed to
the lower earnings. Largely offsetting the negative impact of these items were
increased profits from sales of commercial and institutional land in The
Woodlands.
While The Woodlands continued to lead the Houston area in home sales, the
Company sold 844 residential lots to builders in fiscal 1994, down from 911
during the prior year. This decline occurred both because of softness in the
Houston-area market (due to reduced growth in jobs and fewer corporate
relocations) and as a result of slowed lot development in The Woodlands, which
caused shortages in certain categories of lot inventories during the first half
of the year. Lot sales improved during the second half of fiscal 1994 due, in
part, to low interest rates and to the offering by home builders of a broader
range of housing products. Resort lot sales were substantially lower in fiscal
1994 because of a lack of beach-front inventory in Galveston after a successful
fiscal 1993 sales program.
Operating earnings from sales of commercial and institutional acreage in
The Woodlands rose substantially in fiscal 1994 when the Company sold 144 acres
of such land (versus 58 acres in the previous year). Revenues from such
transactions rose by $8.2 million, to $13.3 million, both as a result of the
increased volume and because the average sales price was higher since a larger
portion of the activity involved prime retail sites.
Interest expense incurred. Interest expense incurred, excluding amounts
reported as cost of sales for finance operations, totaled $74.1 million during
fiscal 1994, down $1.2 million from the prior-year amount. This reduction was
caused by a decline in the Company's average effective interest rate to 7.7%
from 8.1%. Contributing to the rate decline were the refunding at 9-1/4% in
April 1992 of $250 million of 11-1/4% fixed-rate notes and lower market rates
for short-term obligations. The beneficial impact of the lower interest rates
was partially offset by an increase in the Company's average debt balance and a
decrease in the percentage of lower-priced, floating-rate debt because of the
sale of $100 million of 8% Senior Notes in July 1992.
Other - SAR/Bonus unit expense accruals ($3.1 million decrease). SAR/Bonus unit
expense accruals were substantially higher in fiscal 1994 because of larger
year-to-year per-share rises in the Company's common stock prices ($4.38 for
Class A shares and $5.63 for Class B shares versus $2.13 and $1.25 in the prior
year). Also contributing to this expense increase were fiscal 1994 exercises at
higher mid-year prices of options and bonus units, many of which had January
1994 expiration dates.
45
<PAGE> 48
QUARTERLY FINANCIAL DATA
(Unaudited)
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
(in thousands except per share data)
<TABLE>
<CAPTION>
First Second Third Fourth
Quarter Quarter Quarter Quarter
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Under Full Cost Method of Accounting
for Oil and Gas Producing Activities
FISCAL 1995
Revenues . . . . . . . . . . . . . . . . $225,168 $237,775 $207,654 $223,974
Segment operating earnings . . . . . . . 27,151 33,477(a) 34,810(b) 28,357
Net earnings . . . . . . . . . . . . . . 3,884 7,808 8,633 3,145
Earnings per share . . . . . . . . . . . .07 .15 .16 .06
FISCAL 1994
Revenues . . . . . . . . . . . . . . . . $230,846 $243,652 $247,418 $230,893
Segment operating earnings . . . . . . . 36,389 37,679 30,467 25,785
Earnings (loss) before extraordinary item 10,289 10,751 (1,964)(c) 6,037
Extraordinary item (early retirement
of debt) . . . . . . . . . . . . . . . - - - (5,426)
Net earnings (loss) . . . . . . . . . . . 10,289 10,751 (1,964) 611
Earnings (loss) per share
Before extraordinary item . . . . . . . .22 .21 (.04) .11
Net earnings . . . . . . . . . . . . . .22 .21 (.04) .01
As Retroactively Restated for Change to
Successful Efforts Method of Accounting
for Oil and Gas Producing Activities
FISCAL 1995
Revenues . . . . . . . . . . . . . . . . $225,168 $237,775 $207,654 $223,974
Segment operating earnings . . . . . . . 37,792 39,511(a) 45,157(b) 37,889
Net earnings . . . . . . . . . . . . . . 10,418 11,401 15,012 8,983
Earnings per share . . . . . . . . . . . .20 .22 .28 .17
FISCAL 1994
Revenues . . . . . . . . . . . . . . . . $230,846 $243,652 $247,418 $230,893
Segment operating earnings . . . . . . . 37,141 41,260 32,843 20,679(d)
Earnings before extraordinary item . . . 10,589 13,491 4,103(c) 1,847
Extraordinary item (early retirement
of debt) . . . . . . . . . . . . . . . - - - (5,426)
Net earnings (loss) . . . . . . . . . . . 10,589 13,491 4,103 (3,579)
Earnings (loss) per share
Before extraordinary item . . . . . . . .23 .26 .08 .04
Net earnings . . . . . . . . . . . . . .23 .26 .08 (.07)
</TABLE>
____________
(a) Includes a gain of $29,196 from the sale of Winnie/Spindletop and charges
aggregating $25,650 for restructuring and asset write-downs.
(b) Includes a gain of $19,625 from the sale of compression operations which
was partially offset by asset write-downs of $11,263.
(c) Net of a deferred tax provision of $11,000 (under full cost method) and
$6,574 (as retroactivity restated) related to an August 1993 increase in
the corporate statutory Federal income tax rate from 34% to 35%.
(d) Net of a $10,390 charge for impairments of proved oil and gas properties.
46
<PAGE> 49
QUARTERLY STOCK DATA
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
(dollars per share)
<TABLE>
<CAPTION>
First Second Third Fourth
Quarter Quarter Quarter Quarter
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
FISCAL 1995
Class A--Market price
High . . . . . . . . . . . . . . . . $22 7/8 $21 3/8 $19 5/8 $18 5/8
Low . . . . . . . . . . . . . . . . . 16 1/4 18 3/4 16 1/8 14 1/2
Cash dividends . . . . . . . . . . . . . .12 .12 .12 .12
Class B--Market price
High . . . . . . . . . . . . . . . . 23 1/4 21 1/4 19 1/2 18 3/4
Low . . . . . . . . . . . . . . . . . 17 1/4 18 1/2 16 1/2 14 1/2
Cash dividends . . . . . . . . . . . . . .1325 .1325 .1325 .1325
FISCAL 1994
Class A--Market price
High . . . . . . . . . . . . . . . . $25 1/2 $27 1/8 $29 5/8 $24 1/2
Low . . . . . . . . . . . . . . . . . 17 21 24 1/4 17 3/4
Cash dividends . . . . . . . . . . . . . .12 .12 .12 .12
Class B--Market price
High . . . . . . . . . . . . . . . . 23 27 3/8 27 1/4 22
Low . . . . . . . . . . . . . . . . . 16 1/8 20 3/8 21 1/8 16 1/8
Cash dividends . . . . . . . . . . . . . .1325 .1325 .1325 .1325
</TABLE>
47
<PAGE> 50
CONSOLIDATED BALANCE SHEETS
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
January 31, 1995 and 1994 (dollar amounts in thousands)
<TABLE>
<CAPTION>
1995 1994
----------- -----------
ASSETS Restated
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . $ 11,967 $ 21,832
Trade receivables, net of allowance for
doubtful accounts of $2,304 and $2,720 . . . . . . . . 133,995 134,570
Inventories . . . . . . . . . . . . . . . . . . . . . . . 13,068 21,400
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 24,808 11,123
----------- -----------
Total current assets . . . . . . . . . . . . . . . . 183,838 188,925
PROPERTY, PLANT AND EQUIPMENT, at cost less accumulated
depreciation, depletion and amortization of
$1,408,402 and $1,473,729 (Note 2) . . . . . . . . . . 734,099 858,705
REAL ESTATE (Note 3) . . . . . . . . . . . . . . . . . . 917,890 896,652
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . 20,044 25,010
----------- -----------
$ 1,855,871 $ 1,969,292
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Short-term debt . . . . . . . . . . . . . . . . . . . . . $ 11,617 $ 9,955
Oil and gas proceeds payable . . . . . . . . . . . . . . 51,211 64,110
Accounts payable . . . . . . . . . . . . . . . . . . . . 67,452 92,895
Accrued liabilities . . . . . . . . . . . . . . . . . . . 39,962 50,156
----------- -----------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . . . 170,242 217,116
----------- -----------
LONG-TERM DEBT (Note 5)
Energy operations . . . . . . . . . . . . . . . . . . . . 375,869 486,066
Real estate operations . . . . . . . . . . . . . . . . . 519,093 502,252
----------- -----------
894,962 988,318
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes (Note 6) . . . . . . . . . . . . . 200,722 181,989
Natural gas contract restructuring proceeds . . . . . . . 35,017 51,527
Deferred income . . . . . . . . . . . . . . . . . . . . . 29,774 30,731
Other liabilities . . . . . . . . . . . . . . . . . . . . 50,124 36,374
----------- -----------
315,637 300,621
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTES 4 AND 7)
STOCKHOLDERS' EQUITY (Notes 8 and 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 . . . . . . . . . . . . . . . 143,472 143,440
Retained earnings . . . . . . . . . . . . . . . . . . . . 347,573 328,497
Treasury stock, at cost . . . . . . . . . . . . . . . . . (21,401) (14,086)
----------- -----------
475,030 463,237
----------- -----------
$ 1,855,871 $ 1,969,292
=========== ===========
</TABLE>
- --------------------
The accompanying notes are an integral part of these financial statements.
48
<PAGE> 51
CONSOLIDATED STATEMENTS OF EARNINGS
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
For the Years Ended January 31, 1995, 1994 and 1993 (in thousands except
per share amounts)
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
Restated
<S> <C> <C> <C>
REVENUES
Exploration and production . . . . . . . . . . . . . . . $ 277,099 $ 266,166 $ 214,681
Gas services (including gains on major asset
sales of $48,821 in 1995) (Note 10) . . . . . . . . . . 488,007 560,537 566,700
Real estate . . . . . . . . . . . . . . . . . . . . . . . 129,465 126,106 121,453
----------- ----------- -----------
894,571 952,809 902,834
----------- ----------- -----------
OPERATING COSTS AND EXPENSES (including DD&A) (Note 10)
Exploration and production (including
restructuring charges of $20,726 in 1993) . . . . . . . 189,193 197,980 177,347
Gas services (including restructuring charges
and asset write-downs of $31,252 in 1995) . . . . . . . 435,696 517,878 478,196
Real estate (including asset write-downs of $5,661
in 1995) . . . . . . . . . . . . . . . . . . . . . . . 109,333 105,028 98,652
----------- ----------- -----------
734,222 820,886 754,195
----------- ----------- -----------
Segment Operating Earnings (Note 10) . . . . . . . . . . 160,349 131,923 148,639
General and administrative expense . . . . . . . . . . . 42,225 43,222 41,398
----------- ----------- -----------
TOTAL OPERATING EARNINGS . . . . . . . . . . . . . . . . 118,124 88,701 107,241
----------- ----------- -----------
OTHER EXPENSE
Interest expense . . . . . . . . . . . . . . . . . . . . 69,982 74,057 75,284
Capitalized interest . . . . . . . . . . . . . . . . . . (28,816) (33,956) (34,161)
Other, net . . . . . . . . . . . . . . . . . . . . . . . 6,407 1,224 6,096
----------- ----------- -----------
47,573 41,325 47,219
----------- ----------- -----------
EARNINGS BEFORE INCOME TAXES, EXTRAORDINARY ITEM AND
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING METHODS . . . 70,551 47,376 60,022
INCOME TAXES (including $6,574 deferred tax impact
of increase in corporate tax rate in 1994) (Note 6) . 24,737 17,346 14,967
----------- ----------- -----------
EARNINGS BEFORE EXTRAORDINARY ITEM AND CUMU-
LATIVE EFFECT OF CHANGE IN ACCOUNTING METHODS . . . . . 45,814 30,030 45,055
EXTRAORDINARY ITEM--LOSS FROM EARLY RETIREMENT
OF DEBT (net of tax benefit of $2,921 and $3,736)
(Note 5) . . . . . . . . . . . . . . . . . . . . . . . - (5,426) (7,251)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
METHODS (net of tax benefit of $5,435) (Note 12) . . . - - (10,551)
----------- ----------- -----------
NET EARNINGS . . . . . . . . . . . . . . . . . . . . . . $ 45,814 $ 24,604 $ 27,253
=========== =========== ===========
EARNINGS PER SHARE
Earnings before extraordinary item and cumu-
lative effect of change in accounting methods . . . . . $ .87 $ .58 $ .96
Extraordinary item . . . . . . . . . . . . . . . . . . . - (.10) (.15)
Cumulative effect of change in accounting methods . . . . - - (.23)
----------- ----------- -----------
Net earnings . . . . . . . . . . . . . . . . . . . . . . $ .87 $ .48 $ .58
=========== =========== ===========
AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . . . . . 52,696 51,004 46,858
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
49
<PAGE> 52
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
For the Years Ended January 31, 1995, 1994 and 1993
(dollar amounts in thousands)
<TABLE>
<CAPTION>
Additional
Common Paid-in Retained Treasury
Stock Capital Earnings Stock Total
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
DOLLAR AMOUNTS
BALANCE, JANUARY 31, 1992,
AS PREVIOUSLY REPORTED . . . . . . . . . . . . . . . . $ 4,796 $ 20,291 $ 625,079 $ (12,797) $ 637,369
Effect on prior periods of change to
successful efforts method of accounting . . . . . . . . - - (302,400) - (302,400)
----------- ----------- ----------- ----------- -----------
BALANCE, JANUARY 31, 1992, AS RESTATED . . . . . . . . . 4,796 20,291 322,679 (12,797) 334,969
Net earnings . . . . . . . . . . . . . . . . . . . . . . - - 27,253 - 27,253
Cash dividends (20 cents per share prior to
reclassification; 22 cents per share on Class A
and 23.75 cents per share on Class B) . . . . . . . . . - - (20,097) - (20,097)
Purchase and cancellation of fractional shares . . . . . - (8) - - (8)
Treasury stock purchases . . . . . . . . . . . . . . . . - - - (4,347) (4,347)
Exercises of stock options . . . . . . . . . . . . . . . - 64 - 584 648
----------- ----------- ----------- ----------- -----------
BALANCE, JANUARY 31, 1993 . . . . . . . . . . . . . . . . 4,796 20,347 329,835 (16,560) 338,418
Issuance of common stock (Note 8) . . . . . . . . . . . . 590 122,839 - - 123,429
Net earnings . . . . . . . . . . . . . . . . . . . . . . - - 24,604 - 24,604
Cash dividends (48 cents per share on
Class A and 53 cents per share on Class B) . . . . . . - - (25,942) - (25,942)
Exercises of stock options . . . . . . . . . . . . . . . - 254 - 2,474 2,728
----------- ----------- ----------- ----------- -----------
BALANCE, JANUARY 31, 1994 . . . . . . . . . . . . . . . . 5,386 143,440 328,497 (14,086) 463,237
Net earnings . . . . . . . . . . . . . . . . . . . . . . - - 45,814 - 45,814
Cash dividends (48 cents per share on
Class A and 53 cents per share on Class B) . . . . . . - - (26,738) - (26,738)
Treasury stock purchases . . . . . . . . . . . . . . . . - - - (7,635) (7,635)
Exercises of stock options . . . . . . . . . . . . . . . - 32 - 320 352
----------- ----------- ----------- ----------- -----------
BALANCE, JANUARY 31, 1995 . . . . . . . . . . . . . . . . $ 5,386 $ 143,472 $ 347,573 $ (21,401) $ 475,030
=========== =========== =========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
Common Stock Issued Treasury Stock
----------------------------------------- -----------------------------------------
Prior to Prior to
Reclassi- Reclassi-
fication Class A Class B fication Class A Class B
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
SHARE AMOUNTS
BALANCE, JANUARY 31, 1992 . . . . 47,956,869 1,057,537
Exercises of stock options . . . - (23,600)
Reclassification of stock . . . . (47,956,292) 23,978,146 23,978,146 (1,033,936) 516,968 516,968
Cancellation of
fractional shares . . . . . . . (577) - - (1)
Exercises of stock options . . . - - - - (13,000) (11,200)
Treasury stock purchases . . . . - - - - 15,000 281,600
----------- ----------- ----------- ----------- ----------- -----------
BALANCE, JANUARY 31, 1993 . . . . - 23,978,146 23,978,146 - 518,968 787,368
=========== ===========
Issuance of common stock . . . . - 5,900,000 - -
Exercises of stock options . . . - - (101,138) (94,887)
Other . . . . . . . . . . . . . . (29) (29) (353) (353)
----------- ----------- ----------- -----------
BALANCE, JANUARY 31, 1994 . . . . 23,978,117 29,878,117 417,477 692,128
Treasury stock purchases . . . . - - 272,300 216,700
Exercises of stock options . . . - - (12,200) (12,350)
Other . . . . . . . . . . . . . . (13) (13) - -
----------- ----------- ----------- -----------
BALANCE, JANUARY 31, 1995 . . . . 23,978,104 29,878,104 677,577 896,478
=========== =========== =========== ===========
</TABLE>
- --------------------
The accompanying notes are an integral part of these financial statements.
50
<PAGE> 53
CONSOLIDATED STATEMENTS OF CASH FLOWS
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
For the Years Ended January 31, 1995, 1994 and 1993 (in thousands)
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
OPERATING ACTIVITIES Restated
<S> <C> <C> <C>
Earnings before extraordinary item and cumu-
lative effect of change in accounting methods . . . . . $ 45,814 $ 30,030 $ 45,055
Adjustments to reconcile earnings before extraordinary
item and cumulative effect of change in accounting
methods to cash provided by operating activities
Depreciation, depletion and amortization . . . . . . 140,724 121,860 103,250
Exploration expenses, including dry hole . . . . . . 13,307 29,969 13,497
Deferred income taxes . . . . . . . . . . . . . . . . 17,691 5,353 7,630
Cost of land sold . . . . . . . . . . . . . . . . . . 32,449 33,367 28,424
Residential land development costs, net of
reimbursements . . . . . . . . . . . . . . . . . . (16,395) (14,303) (17,333)
Distributions over (under) earnings of equity
investees . . . . . . . . . . . . . . . . . . . . . 19,233 13,849 (16,832)
Amortization of deferred natural gas
contract restructuring proceeds . . . . . . . . . . (16,510) (18,723) (20,360)
Gains on major energy asset sales (Note 10) . . . . . (52,612) - -
Accrued restructuring costs . . . . . . . . . . . . . 9,592 - 3,242
Real estate asset write-downs . . . . . . . . . . . . 5,661 - -
Other . . . . . . . . . . . . . . . . . . . . . . . . 7,002 (5,159) 4,185
----------- ----------- -----------
205,956 196,243 150,758
Changes in operating assets and liabilities
Receivables . . . . . . . . . . . . . . . . . . . . (1,012) 4,071 (3,089)
Inventories . . . . . . . . . . . . . . . . . . . . 3,832 (1,728) 2,754
Payables . . . . . . . . . . . . . . . . . . . . . (32,687) (29,075) 17,895
Accrued liabilities and other . . . . . . . . . . . (6,453) (1,469) 321
----------- ----------- -----------
Cash provided by operating activities . . . . . . . . 169,636 168,042 168,639
----------- ----------- -----------
INVESTING ACTIVITIES
Capital and exploratory expenditures
Total on accrual basis (including $78,251 in 1994
related to the buy-out of MEC Development, Ltd.) . . (219,575) (354,080) (235,624)
Residential land development costs deducted above . . . 16,395 14,303 17,333
Adjustment to cash basis . . . . . . . . . . . . . . . (4,575) 21,125 (206)
----------- ----------- -----------
(207,755) (318,652) (218,497)
Proceeds from major energy asset sales . . . . . . . . . 152,000 - -
Proceeds from sales of commercial properties . . . . . . - - 27,129
Proceeds from sales of notes receivable . . . . . . . . . - - 20,095
Proceeds from other sales of property, plant and equipment 10,920 8,625 5,855
Other . . . . . . . . . . . . . . . . . . . . . . . . . . (1,326) (286) 6,119
----------- ----------- -----------
Cash used for investing activities . . . . . . . . . (46,161) (310,313) (159,299)
----------- ----------- -----------
FINANCING ACTIVITIES
Proceeds from issuance of debt . . . . . . . . . . . . . 117,734 351,728 385,274
Debt repayments . . . . . . . . . . . . . . . . . . . . . (209,428) (311,813) (381,243)
Net proceeds from issuance of Class B common
stock (Note 8) . . . . . . . . . . . . . . . . . . . . - 123,429 -
Cash dividends . . . . . . . . . . . . . . . . . . . . . (26,738) (25,942) (20,097)
Debt prepayment premium . . . . . . . . . . . . . . . . . (6,420) - (8,025)
Treasury stock purchases . . . . . . . . . . . . . . . . (7,635) - (4,347)
Senior note issuance costs and other . . . . . . . . . . (853) (1,396) (4,192)
----------- ----------- -----------
Cash provided by (used for) financing activities . . (133,340) 136,006 (32,630)
----------- ----------- -----------
DECREASE IN CASH AND CASH EQUIVALENTS . . . . . . . . . . (9,865) (6,265) (23,290)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR . . . . . . 21,832 28,097 51,387
----------- ----------- -----------
CASH AND CASH EQUIVALENTS, END OF YEAR . . . . . . . . . $ 11,967 $ 21,832 $ 28,097
=========== =========== ===========
</TABLE>
- --------------------
The accompanying notes are an integral part of these financial statements.
51
<PAGE> 54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
January 31, 1995, 1994 and 1993
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 1
Principles of consolidation. The consolidated financial statements include the
accounts of Mitchell Energy & Development Corp. and its majority-owned
subsidiaries (the "Company"). All significant intercompany accounts and
transactions are eliminated in consolidation. The Company follows the equity
method of accounting for investments in 20% to 50% owned entities. The
Company's net investment in each of these entities is included in the
applicable segment's asset caption of the consolidated balance sheets, and its
equity in the pretax earnings or losses of each entity is included in the
applicable revenues or operating costs and expenses caption of the consolidated
statements of earnings.
Property, plant and equipment. During the fourth quarter of fiscal 1995, the
Company retroactively adopted the successful efforts method of accounting for
oil and gas producing activities; previously the full cost method had been
used. Management concluded that the successful efforts method will provide a
more timely measure of the results of a new exploration strategy initiated by
the Company during fiscal 1995. Also, use of successful efforts--for which the
Financial Accounting Standards Board has a stated preference--makes the
Company's financial results more comparable to those of other oil and gas
producers, most of whom use this method. Prior-period financial statements,
including all applicable information contained herein, were restated to give
effect to this change in accounting methods. As a result of this change, the
Company's net earnings were increased by $22,344,000 ($.42 per share) in fiscal
1995; $4,917,000 ($.09 per share) in fiscal 1994 and $8,766,000 ($.19 per
share) in fiscal 1993. In addition, as of February 1, 1992, the net book value
of the Company's oil and gas properties was reduced by $458,720,000. After a
deferred tax benefit of $156,320,000, retained earnings were reduced by
$302,400,000.
Under 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 expensed. Geological
and geophysical costs and unproved property holding costs are charged to
expense when incurred. The Company currently holds no unproved leases whose
costs are individually significant. The aggregate costs of individually
insignificant unproved leases estimated to be non-productive are amortized on a
straight-line basis over estimated holding periods based on historical
experience. As unproved properties are determined to be productive, the related
costs are transferred to proved oil and gas properties.
Depreciation, depletion and amortization of proved oil and gas properties
is determined on a field-by-field basis using the unit-of-production method.
Estimated future costs of dismantlement, restoration and abandonment are
considered in determining DD&A expense. The carrying amounts of proved oil and
gas properties are reviewed periodically on a field-by-field basis for
impairment. When it is determined that estimated future net cash flows will not
be sufficient to recover the carrying amount of a specific field, an impairment
charge is recorded to reduce the carrying amount for that field to its
estimated fair value. Impairment charges, which are included in DD&A expense,
totaled $4,718,000; $13,649,000 and $2,332,000, respectively, in fiscal 1995,
1994 and 1993.
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.
52
<PAGE> 55
Real estate operations. Costs associated with the acquisition and development
of real estate, including holding costs, are capitalized as incurred.
Capitalization of holding costs, principally interest and ad valorem taxes, is
limited to properties for which active development continues. Where practical,
capitalized costs are specifically assigned to individual assets; otherwise,
such costs are allocated based on estimated values of the affected assets.
Depreciable real estate assets are depreciated on the straight-line method
over estimated useful lives ranging from 3 to 50 years. Real estate is carried
at the lower of historical cost or estimated net realizable value. The impact
of changes in economic conditions and other factors on the realizable values of
real estate are regularly monitored and evaluated. The effect of any
significant changes which adversely impact these carrying values is charged
against earnings in the period such effect can be reasonably estimated.
Earnings from sales of real estate are recognized when a buyer has made an
adequate cash down payment and has attained the attributes of ownership. Notes
received in connection with land sales are discounted when the stated purchase
prices are significantly different from those which would have resulted from
similar cash transactions. The cost of land sold is generally determined as a
specific percentage of the sales revenues recognized for each land development
project. These percentages are based on total estimated development costs and
sales revenues for each project. The specific identification method is used to
determine the cost of land sold for certain land parcels located outside The
Woodlands.
Because they represent the principal revenues and costs for these
activities, interest income and interest expense of the Company's finance
operations are reported, respectively, as revenues and as costs and expenses in
the consolidated statements of earnings.
Environmental expenditures. Liabilities for these expenditures are recognized
when it is probable that obligations have been incurred in amounts that are
material and reasonably estimable.
Deferred natural gas contract restructuring proceeds. The Company has deferred
earnings recognition for certain natural gas contract restructuring proceeds.
These deferred amounts are being amortized to earnings over the periods to
which the consideration relates. Such amortization totaled $16,510,000;
$18,723,000 and $20,360,000, respectively, in fiscal 1995, 1994 and 1993.
Earnings per common share. Earnings per common share have been computed by
dividing net earnings by the weighted average number of common shares
outstanding during each period, which for periods subsequent to June 24, 1992
includes both Class A and Class B shares. After giving effect to the differing
cash dividends paid on these shares, fiscal 1995 net earnings per share were
$.84 for Class A and $.89 for Class B (versus $.87 on a combined basis). For
fiscal 1994, earnings per share before extraordinary item were $.56 for Class A
and $.61 for Class B (versus $.58 on a combined basis) while net earnings per
share for each class were $.46 and $.51 (versus $.48 on a combined basis). The
effect of the differing dividend payments was not significant to earnings per
common share in fiscal 1993. The dilutive effect of outstanding stock options,
which is less than 3%, has not been included in the earnings-per-share
computations.
Statements of Cash Flows. Short-term investments with maturities of three
months or less are considered to be cash equivalents. Proceeds and repayments
of commercial paper and bank revolving credit agreement borrowings with terms
of three months or less are reported net. Interest paid--excluding amounts
capitalized, but including amounts reported as cost of sales for finance
operations--totaled $40,058,000; $38,052,000 and $40,556,000 during fiscal
1995, 1994 and 1993. Income taxes paid during these periods totaled $9,760,000;
$12,840,000 and $6,619,000. There were no significant non-cash investing or
financing activities during the three-year period ended January 31, 1995.
Reclassifications. Certain reclassifications of amounts previously reported
have been made to conform to the current year's presentation.
53
<PAGE> 56
PROPERTY, PLANT AND EQUIPMENT 2
The cost and net book value of property, plant and equipment consisted of the
following at January 31, 1995 and 1994 (in thousands):
<TABLE>
<CAPTION>
Cost Net Book Value
-------------------------- --------------------------
1995 1994 1995 1994
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
EXPLORATION AND PRODUCTION
Oil and gas properties . . . . . . . . . $ 1,606,066 $ 1,595,004 $ 487,981 $ 487,218
Support equipment and facilities . . . . 68,941 70,893 28,340 29,686
----------- ----------- ----------- -----------
1,675,007 1,665,897 516,321 516,904
Other . . . . . . . . . . . . . . . . . . - 39,765 - 2,684
----------- ----------- ----------- -----------
1,675,007 1,705,662 516,321 519,588
----------- ----------- ----------- -----------
GAS SERVICES
Natural gas processing . . . . . . . . . 222,755 230,251 100,139 115,253
Natural gas gathering . . . . . . . . . . 184,728 289,109 92,725 183,862
Other . . . . . . . . . . . . . . . . . . 18,544 65,247 17,794 32,651
----------- ----------- ----------- -----------
426,027 584,607 210,658 331,766
----------- ----------- ----------- -----------
CORPORATE . . . . . . . . . . . . . . . . 15,042 15,740 7,120 7,351
----------- ----------- ----------- -----------
$ 2,116,076 $ 2,306,009 $ 734,099 $ 858,705
=========== =========== =========== ===========
</TABLE>
See Note 10 for information concerning asset write-downs and major asset sales.
REAL ESTATE 3
In accordance with industry accounting practice, real estate assets are
reported as long-term assets in the consolidated balance sheets. Such assets
consisted of the following at January 31, 1995 and 1994 (in thousands):
<TABLE>
<CAPTION>
1995 1994
----------- -----------
<S> <C> <C>
The Woodlands
Land and improvements . . . . . . . . . . . . . . . . . $ 489,863 $ 479,461
Commercial properties, net of accumulated
depreciation of $47,752 and $47,135 . . . . . . . . . 165,018 148,301
----------- -----------
654,881 627,762
Land held for investment, development or sale . . . . . . 157,446 159,949
Resort and other operating properties, net of
accumulated depreciation of $7,889 and $7,648 . . . . . 65,249 65,956
Notes and contracts receivable, at cost, net of allowance
for doubtful accounts of $515 and $507 . . . . . . . . 40,314 42,985
----------- -----------
$ 917,890 $ 896,652
=========== ===========
</TABLE>
The Company's real estate activities are concentrated in the area surrounding
Houston, Texas. Consequently, these operations and the associated credit risks
may be affected, either positively or negatively, by changes in economic
conditions in this geographical area. The Company's principal real estate
property is a master-planned community located north of Houston known as "The
Woodlands," which is being developed on approximately 25,000 acres. Activities
associated with this development include residential and commercial land sales;
the construction and operation of office and industrial buildings, apartments,
retail shopping centers, golf courses and a conference center; and the mortgage
banking operations of a wholly owned subsidiary, Mitchell Mortgage Company.
Other real estate assets include large landholdings northwest of Houston and
certain resort properties.
54
<PAGE> 57
EQUITY INVESTMENTS 4
Entities accounted for on the equity method include approximately 30
partnerships engaged in energy or real estate activities. The principal
partnership interests included the following at January 31, 1995:
<TABLE>
<CAPTION>
Ownership
Percentage Nature of Operations
---------- --------------------
<S> <C> <C>
Energy Operations
Austin Chalk Natural Gas Marketing Services 45 Natural gas marketing
Belvieu Environmental Fuels 33.33 Production of MTBE
C&L Processors Partnership 50 Natural gas processing
Ferguson-Burleson County Gas Gathering System 45 Natural gas gathering
Gulf Coast Fractionators 38.75 Fractionation of natural gas liquids
U. P. Bryan 45 Natural gas processing
Real Estate Operations
The Fort Crockett Hotel Limited 50 Resort hotel in Galveston, Texas
Lake Catamount Joint Venture 50 Land held for development
The Woodlands Mall Associates 50 Regional mall in The Woodlands
</TABLE>
Other real estate partnerships own a cable television system serving The
Woodlands and various commercial properties, most of which are located in The
Woodlands. The following paragraphs present summarized financial statement
information, which is generally reported on a one-month lag, for all entities
accounted for on the equity method. Summarized balance sheet information for
these entities at January 31, 1995 and 1994 follows (in thousands):
<TABLE>
<CAPTION>
1995 1994
-------------------------- --------------------------
<S> <C> <C> <C> <C>
Current assets . . . . . . . . . . . . . $ 98,263 $ 83,764
Net noncurrent assets
Energy . . . . . . . . . . . . . . . . 543,203 483,583
Real estate . . . . . . . . . . . . . . 215,037 157,016
Current liabilities . . . . . . . . . . . 87,852 72,281
Debt payable to third parties
The Company's proportionate share
Recourse to the Company . . . . . . . $ 137,287 $ 118,705
Nonrecourse to the Company . . . . . 72,217 59,010
Other parties' proportionate share
($37,568 of which was guaranteed by
the Company at January 31, 1995) . . 297,158 506,662* 245,797 423,512*
----------- -----------
Notes payable to owners (including $13,257
and $9,751 payable to the Company) . . 15,257 9,751
Deferred credits and other . . . . . . . 590 737
Owners' equity . . . . . . . . . . . . . 246,142 218,082
</TABLE>
- ----------------------
* Includes current maturities of $44,542 in 1995 and $25,514 in 1994.
Summarized earnings information for these entities for the years ended
January 31, 1995, 1994 and 1993 follows (in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 417,555 $ 505,374 $ 494,297
Operating earnings . . . . . . . . . . . . . . . . . . . . . . . . . . 20,571 71,271 106,630
Pretax earnings (before interest expense for those entities whose
activities are funded by capital contributions of the owners) . . . . 5,692 56,837 93,586
Proportionate share of pretax earnings included in the
Company's reported operating earnings (including insur-
ance proceeds of $8,570 in 1995 for a Company-owned policy
covering its prorata share of Gulf Coast Fractionators' assets) . . . 5,790 23,249 43,813
</TABLE>
55
<PAGE> 58
Using a portion of the proceeds of a common stock offering (see Note 8), the
Company purchased, effective May 1, 1993, the limited partner's interest in MEC
Development, Ltd. for $52,585,000, from which the partner repaid its
proportionate share of partnership debt. The Company also repaid its share of
the partnership's debt of $25,666,000, and the partnership was liquidated. All
reserves and other assets previously owned by the partnership were transferred
to the Company.
The operations of certain of these partnerships have been funded using term
loans secured by their assets and in some cases by contractual commitments or
guaranties of the partners. Information concerning debt payable to third
parties by these entities at January 31, 1995 and 1994 and the Company's
proportionate share of such debt at January 31, 1995 is summarized as follows
(in thousands):
<TABLE>
<CAPTION>
Entity Total 1995--Company's Share
-------------------------- -----------------------------------------
Non-
1995 1994 Recourse recourse Total
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Energy Activities
Belvieu Environmental Fuels . . . . . . . $ 176,000 $ 136,000 $ 58,667 $ - $ 58,667
C&L Processors Partnership . . . . . . . 101,209 116,719 27,327 23,278 50,605
Gulf Coast Fractionators . . . . . . . . 79,550 64,250 16,829 13,997 30,826
----------- ----------- ----------- ----------- -----------
356,759 316,969 102,823 37,275 140,098
----------- ----------- ----------- ----------- -----------
Real Estate Activities
The Fort Crockett Hotel Limited . . . . . 11,592 12,397 4,035 1,761 5,796
The Woodlands Mall Associates . . . . . . 54,683 18,689 27,342 - 27,342
Apartment partnerships . . . . . . . . . 41,019 37,728 817 15,188 16,005
Others . . . . . . . . . . . . . . . . . 42,609 37,729 2,270 17,993 20,263
----------- ----------- ----------- ----------- -----------
149,903 106,543 34,464 34,942 69,406
----------- ----------- ----------- ----------- -----------
$ 506,662 $ 423,512 $ 137,287 $ 72,217 $ 209,504
=========== =========== =========== =========== ===========
</TABLE>
Belvieu Environmental Fuels (BEF) owns a plant designed to produce 12,500
barrels per day of MTBE, a gasoline additive that reduces carbon monoxide
emissions. The $225,000,000 facility, located at Mont Belvieu, Texas, began
producing MTBE during the summer of 1994. Plant construction costs were funded
using proceeds of the partnership's loan agreement and capital contributions of
the partners. Until converted to term-loan status, the partnership's debt is
severally guaranteed on a prorata basis by its three partners. This conversion,
which the agreements specify is to occur by May 31, 1995, requires among other
things that the plant pass a production test by producing an average of 12,600
barrels per day of a specified quality of MTBE over a continuous 45-day period.
Because of a series of start-up production problems, the plant has been unable
to pass this test, and the partnership's lenders could require the partners to
repay their respective shares of the partnership's indebtedness on May 31,
1995. The Company has available capacity under committed bank credit agreements
to fund its share of BEF's debt should this become necessary. The partnership
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 of 10 years.
The Company and its partner, Conoco, Inc., have each agreed to make
aggregate future cash contributions to C&L Processors Partnership of up to 27%
of the partnership's loan balance should the partnership's operating cash flows
not be sufficient to cover scheduled principal and interest payments. During
the last half of fiscal 1995, the partners loaned the partnership a total of
$4,000,000 on a subordinated basis and made capital contributions of
$5,000,000.
Gulf Coast Fractionators (GCF) executed an $85,000,000 bank term loan
agreement in June 1993. The primary uses of the loan proceeds were to fund a
$40,000,000 expansion of GCF's fractionator and $40,000,000 in cash
distributions to the partners, of which the Company's share was $15,500,000. In
connection with the 40,000-barrel-per-day expansion, Conoco, Inc. became a
22.5% owner of GCF and the Company's ownership was reduced from 50% to 38.75%.
Each of the three partners has severally guaranteed
56
<PAGE> 59
its prorata share of the $40,000,000 expansion financing (until the plant is
satisfactorily completed) and any shortfall in a $10,000,000 reserve fund until
a specified financial ratio is met. The balance of the partnership's debt is
nonrecourse to the partners. Each partner also has executed long-term contracts
with GCF for the fractionation of production from certain of its gas processing
plants.
In connection with its guarantee of certain indebtedness of The Fort
Crockett Hotel Limited, the Company has agreed to make cash advances to fund
the partnership's cash flow deficiencies until certain debt coverage tests are
met. The Company made aggregate advances to this partnership of $2,103,000;
$2,972,000 and $4,747,000 during fiscal 1995, 1994 and 1993, including $469,000
and $2,884,000 in fiscal 1994 and 1993 to cover the costs of an expansion of
the partnership's facilities.
The Woodlands Mall Associates is a partnership owned equally by the Company
and Homart Development Co., a wholly owned subsidiary of Sears, Roebuck and Co.
It was formed to develop a one million square foot regional shopping mall which
opened in October 1994. On January 31, 1994, the partnership entered into a
$65,000,000 five-year bank loan, the proceeds of which were used to fund site
development and other general costs as well as construction costs of the
345,000-square-foot gross leasable area owned by the partnership. The
partnership's loan is secured by the property and the joint and several
guaranties of the partners.
LONG-TERM DEBT 5
The Company's outstanding debt includes parent company borrowings, the proceeds
of which have been advanced to the operating subsidiaries, and the direct
borrowings of certain subsidiaries. Allocation of the parent company advances
among the subsidiaries changes in response to the specific financing needs of
the subsidiaries and the parent company. A summary of outstanding long-term
debt at January 31, 1995 and 1994 follows (in thousands):
<TABLE>
<CAPTION>
1995
-----------------------------------------
Real
Energy Estate 1994
Operations Operations Total Total
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Parent Company Senior Notes, Unsecured
5.10%, due February 15, 1997 . . . . . . . . . . . . . . $ 100,000 $ 100,000
8%, due July 15, 1999 . . . . . . . . . . . . . . . . . . 100,000 100,000
9 1/4%, due January 15, 2002 . . . . . . . . . . . . . . 250,000 250,000
6 3/4 %, due February 15, 2004 . . . . . . . . . . . . . 250,000 250,000
11 1/4% (redeemed in February 1994) . . . . . . . . . . . - 200,000
----------- -----------
$ 286,189* $ 413,811* 700,000 900,000
Subsidiary Borrowings
Bank revolving credit agreements, unsecured
Five-year (Energy $150 million
and Real Estate $165 million) . . . . . . . . . . . . 50,000 70,000 120,000 19,000
364-day (Energy $100 million) . . . . . . . . . . . . . - - - -
Mitchell Mortgage Company, $18 million,
at floating interest rates . . . . . . . . . . . . . - 14,500 14,500 11,300
Commercial paper, at floating interest rates . . . . . . 9,680 12,320 22,000 22,000
Unsecured term loan, 7.98%, due in May 1997 . . . . . . . 30,000 - 30,000 30,000
Mortgages, 9% average rate . . . . . . . . . . . . . . . - 20,079 20,079 15,973
----------- ----------- ----------- -----------
375,869 530,710 906,579 998,273
Less - Amounts reported as short-term debt . . . . . . . - 11,617 11,617 9,955
----------- ----------- ----------- -----------
$ 375,869 $ 519,093 $ 894,962 $ 988,318
=========== =========== =========== ===========
</TABLE>
- -------------------
* Intercompany loans from parent company.
57
<PAGE> 60
On February 25, 1994, the parent company redeemed its $200,000,000 of 11 1/4%
Senior Notes Due 1999 using a portion of the proceeds of January 1994 offerings
of $250,000,000 of 6 3/4% Senior Notes Due 2004 and $100,000,000 of 5.10%
Senior Notes Due 1997. This redemption was completed at a price of 103.21% of
principal, and the expensing of this premium and related unamortized debt
issuance costs resulted in an extraordinary charge of $5,426,000 (after tax
benefit of $2,921,000), which was recorded in January 1994 when the debt was
called.
On April 13, 1992, the parent company redeemed its $250,000,000 of 11 1/4%
Senior Notes Due 1997 using the proceeds of a March 1992 offering of
$250,000,000 of 9 1/4% Senior Notes Due 2002. This early redemption was
completed at a price of 103.21% of principal, and the expensing of this premium
and related unamortized debt issuance costs resulted in an extraordinary charge
of $7,251,000 (after tax benefit of $3,736,000).
The Company's senior notes have no sinking fund requirements and are not
redeemable prior to their respective maturity dates. The terms of the Company's
Energy and Real Estate bank revolving credit agreements were revised during
November 1994. The Energy agreement was split into two parts, a $150 million
five-year facility maturing on November 30, 1999 and a $100 million 364-day
facility which can be extended annually with the approval of the participating
banks. The maturity of the five-year, $165 million Real Estate agreement was
similarly extended to November 30, 1999; for its fifth year, the committed
amount under this facility is to be reduced to 75% of its initial size.
Interest rates on these floating-rate borrowings are based on the London
Interbank Offered Rate, the prevailing certificate of deposit rate or prime.
During October 1994, the maturity of the Company's commercial paper program was
extended through June 1998, and the term of Mitchell Mortgage Company's bank
credit facility was extended through July 1997.
The credit agreements contain certain restrictions which, among other
things, require consolidated stockholders' equity to equal at least
$400,000,000 and require the maintenance of specified financial and oil and gas
reserve and/or asset value-to-debt ratios. The agreements also limit additional
borrowings, restrict the sale or lease of certain assets and limit the right of
the parent company and certain subsidiaries to merge with other companies.
Retained earnings available for the payment of cash dividends totaled
$75,030,000 at January 31, 1995. The credit agreements also limit cash advances
and dividend payments to the parent company by the subsidiaries. At January 31,
1995, transfers to the parent of approximately $1,030,000,000 were allowable
under these agreements.
Long-term debt maturities for the five fiscal years subsequent to January
31, 1995 are as follows (in thousands):
<TABLE>
<CAPTION>
1996 1997 1998 1999 2000
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Senior notes . . . . . . . . . . . . . . $ - $ - $ 100,000 $ - $ 100,000
Bank revolving credit agreements . . . . - - 2,883 - 120,000
Commercial paper . . . . . . . . . . . . - - - 22,000 -
Unsecured term loan . . . . . . . . . . . - - 30,000 - -
Mortgages . . . . . . . . . . . . . . . . 755 702 725 698 578
----------- ----------- ----------- ----------- -----------
$ 755 $ 702 $ 133,608 $ 22,698 $ 220,578
=========== =========== =========== =========== ===========
</TABLE>
Bank revolving credit agreement maturities are based on present conversion
dates, which may be extended. The fiscal 1996 debt maturities shown above are
included in noncurrent liabilities in the accompanying balance sheet since they
can be refunded by borrowing under credit agreements having no fiscal 1996
maturities.
At January 31, 1995, additional borrowings of approximately $400,000,000
were available under existing commercial paper and bank revolving credit
agreements. The Company compensates the banks for these facilities by paying
commitment and other fees and maintaining minimum unrestricted cash deposits of
$3,125,000.
58
<PAGE> 61
INCOME TAXES 6
The Company follows Statement of Financial Accounting Standards (SFAS) No. 109,
"Accounting for Income Taxes." This statement requires deferred tax assets and
liabilities to be determined by applying tax regulations existing at the end of
a reporting period to the cumulative temporary differences between the tax
bases of assets and liabilities and their reported amounts in the financial
statements.
Exclusive of the tax benefits attributable to the extraordinary charges
discussed in Note 5 and the cumulative effect of a change in accounting methods
discussed in Note 12, income taxes for the years ended January 31, 1995, 1994
and 1993 consist of the following (in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
CURRENT
Federal . . . . . . . . . . . . . . . . . $ 3,407 $ 8,805 $ 9,515
State . . . . . . . . . . . . . . . . . . 3,639 3,188 (2,178)
----------- ----------- -----------
7,046 11,993 7,337
----------- ----------- -----------
DEFERRED
Federal . . . . . . . . . . . . . . . . . 15,175 7,749 8,180
State . . . . . . . . . . . . . . . . . . 2,516 (2,396) (550)
----------- ----------- -----------
17,691 5,353 7,630
----------- ----------- -----------
$ 24,737 $ 17,346 $ 14,967
=========== =========== ===========
</TABLE>
The Omnibus Budget Reconciliation Act of 1993, which was signed into law during
August 1993, increased the corporate statutory Federal income tax rate from 34%
to 35%. The principal financial statement impact of this rate change was a
fiscal 1994 charge of $6,574,000 to increase the liability for deferred Federal
income taxes by an amount equal to 1% of the aggregate cumulative difference
between the book and tax bases of the Company's assets and liabilities.
During November 1992, the State of Texas revised its franchise tax rules in
a manner that reduced the retroactive impact of an income-based franchise tax
it had enacted in August 1991. Because of this, the Company reversed a portion
of the liability for such taxes that had been accrued in fiscal 1992, reducing
its current and deferred state income tax provisions for fiscal 1993 by
$2,775,000 and $2,539,000, respectively. Net of the resultant Federal income
tax charge, this lowered the Company's fiscal 1993 net provision for income
taxes by $3,507,000.
Reconciliations from the applicable statutory Federal income tax rates to
the Company's effective income tax rates (exclusive of tax benefits
attributable to extraordinary charges and the cumulative effect of a change in
accounting methods) for the fiscal years 1995, 1994 and 1993 follow:
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Statutory Federal income tax rate . . . . . . . . . . . . 35.0% 35.0% 34.0%
State income taxes, net of Federal income tax benefit . . 5.6 1.1 (3.0)
Federal tax credits . . . . . . . . . . . . . . . . . . . (5.4) (10.8) (5.5)
Utilization of tax carryforwards . . . . . . . . . . . . - (2.2) -
Increase in corporate statutory Federal income tax rate . - 13.9 -
Other, net . . . . . . . . . . . . . . . . . . . . . . . (.1) (.4) (.6)
----------- ----------- -----------
35.1% 36.6% 24.9%
=========== =========== ===========
</TABLE>
Federal tax credits consist principally of amounts available under Section 29
of the Internal Revenue Code for natural gas produced from certain wells. The
fiscal 1994 provision for deferred Federal income taxes was reduced by
$1,054,000 when certain tax carryforwards were estimated to be utilizable that
previously had been expected to expire.
59
<PAGE> 62
The principal components of the Company's deferred income tax liability
include the following at January 31, 1995 and 1994 (in thousands):
<TABLE>
<CAPTION>
1995 1994
----------- -----------
<S> <C> <C>
Real estate holding costs . . . . . . . . . . . . . . . . . . . . . . . $ 183,103 $ 179,790
Oil and gas acquisition, exploration and development costs deducted
for tax purposes in excess of financial statement DD&A . . . . . . . 60,088 40,044
Depreciation of other property, plant and equipment . . . . . . . . . . 60,975 69,727
Business tax credit carryforwards . . . . . . . . . . . . . . . . . . . (33,255) (34,254)
Unused alternative minimum tax credits . . . . . . . . . . . . . . . . (30,105) (25,396)
Natural gas contract restructuring proceeds . . . . . . . . . . . . . . (17,276) (18,034)
Employee benefits expense not currently deductible for tax purposes . . (12,256) (14,249)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (10,552) (15,639)
----------- -----------
$ 200,722 $ 181,989
=========== ===========
</TABLE>
At January 31, 1995, the Company had business tax credit carryforwards
(consisting principally of investment tax credits) of approximately
$33,255,000, substantially all of which expire during the fiscal years 1996
through 2001, and approximately $30,105,000 of unused alternative minimum tax
credits that can be carried forward indefinitely. These carryforwards have been
recognized in the calculation of financial statement tax provisions.
Accordingly, their future utilization will only reduce the amount of taxes then
payable, not the financial statement provision for income taxes.
COMMITMENTS AND CONTINGENCIES 7
Environmental regulations. The Company is considered by the United States
Environmental Protection Agency to be a potentially responsible party with
respect to four 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 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 $290,000 of clean-up
costs. While additional exposure exists for future clean-up and closure costs
of this site, the Company's share of such costs is not likely to be
significant.
While the Company believes it is in substantial compliance with the many
federal, state and local laws and regulations relating to the protection of the
environment and public health, such laws and regulations are continually
monitored by the Company. However, management expects that no such pending
matters, when ultimately resolved, will have a material adverse effect upon the
Company's financial statements.
Litigation and other. The Company is party to various claims and other 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 such matters cannot be predicted with
certainty, management expects that adjustments, if any, resulting from the
ultimate resolution of these matters will not be material to the Company's
financial statements.
Mortgage activities. Mitchell Mortgage Company (MMC) administers approximately
$180,000,000 of securities, backed by Federal Housing Administration (FHA) and
Department of Veterans Affairs (VA) mortgages, on which it has guaranteed
payments of principal and interest to the security holders. These mortgages are
supported by government-sponsored insurance and are collateralized by real
estate. In the event of default by a mortgagor, MMC may incur a loss if
uncollected principal and interest, together with foreclosure and other costs,
exceed established FHA or VA reimbursement limits. Management expects that
losses, if any, incurred in connection with defaults by borrowers under FHA and
VA mortgages serviced by MMC will not be material to the Company's financial
statements.
60
<PAGE> 63
Leases and contingent liabilities. The Company has various noncancelable
equipment and facility operating lease agreements which provide for aggregate
future payments of approximately $82,900,000. Minimum rentals for each of the
five years subsequent to January 31, 1995 total approximately $9,600,000;
$8,700,000; $8,700,000; $8,000,000 and $7,600,000. Rental expense for operating
leases was approximately $10,400,000; $9,900,000 and $9,300,000 in fiscal 1995,
1994 and 1993. Exclusive of obligations described elsewhere in these notes, the
Company had contingent liabilities at January 31, 1995 totaling approximately
$13,700,000, including $4,700,000 of debt guarantees (principally for nonprofit
institutions located in The Woodlands).
COMMON STOCK 8
In May 1993, the Company sold 5,900,000 shares of its nonvoting Class B common
stock at $21.875 per share. After deducting offering costs, the net proceeds
from the sale totaled approximately $123,400,000. Of the net proceeds,
$78,251,000 was used in connection with the buy-out of MEC Development, Ltd.
(see Note 4). The remaining proceeds initially were used to pay down borrowings
under certain Energy Division credit agreements. Such amounts subsequently were
reborrowed to fund drilling costs that otherwise would have been expenditures
of the partnership.
On June 24, 1992, the stockholders approved an amendment to the Articles of
Incorporation which authorized the reclassification of the Company's common
stock into two classes designated Class A and Class B. Each share of the
Company's prior common stock was converted into one-half share of Class A
common stock and one-half share of Class B common stock; any resulting
fractional amounts were redeemed for cash. Both the Class A and Class B common
shares 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 amended 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 protection provisions.
TRANSACTIONS WITH RELATED PARTIES 9
As a result of transactions occurring prior to fiscal 1973, when the Company
became publicly owned, George P. Mitchell, Chairman of the Board and majority
stockholder, holds real estate adjacent to that owned by the Company from which
he could realize substantial personal benefits as a result of the Company's
activities.
61
<PAGE> 64
SEGMENT INFORMATION 10
Industry segment data for the fiscal years ended January 31, 1995, 1994 and
1993 are as follows (in thousands):
<TABLE>
<CAPTION>
Inter- Segment Capital Identi-
Outside segment Operating Expend- fiable
Revenues Revenues Earnings DD&A itures* Assets
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
FISCAL 1995
EXPLORATION AND PRODUCTION (includ-
ing $3,791 gain on sale of
drilling rigs) . . . . . . . . . . . . $ 277,099 $ - $ 87,906 $ 96,369 $ 115,073 $ 560,818
----------- ----------- ----------- ----------- ----------- -----------
GAS SERVICES
Natural gas processing . . . . . . . . . 252,159 21,419 23,253 7,865 14,227 165,647
Natural gas gathering and marketing . . . 180,038 82,875 12,335 7,898 15,279 134,955
Gains from major asset sales . . . . . . 48,821 - 48,821 - - -
Restructuring charges
and asset write-downs . . . . . . . . . - - (31,252) 14,832 - -
Other . . . . . . . . . . . . . . . . . . 6,989 8,509 (846) 1,998 5,605 18,737
----------- ----------- ----------- ----------- ----------- -----------
488,007 112,803 52,311 32,593 35,111 319,339
----------- ----------- ----------- ----------- ----------- -----------
REAL ESTATE
Operations . . . . . . . . . . . . . . . 129,465 6,660 25,793 8,294 65,123 949,219
Asset write-downs . . . . . . . . . . . . - - (5,661) - - -
----------- ----------- ----------- ----------- ----------- -----------
129,465 6,660 20,132 8,294 65,123 949,219
----------- ----------- ----------- ----------- ----------- -----------
CORPORATE . . . . . . . . . . . . . . . . - - - 3,468 4,268 26,495
----------- ----------- ----------- ----------- ----------- -----------
$ 894,571 $ 119,463 $ 160,349 $ 140,724 $ 219,575 $ 1,855,871
=========== =========== =========== =========== =========== ===========
FISCAL 1994 (RESTATED)
EXPLORATION AND PRODUCTION
Oil and gas . . . . . . . . . . . . . . . $ 265,798 $ - $ 68,551 $ 89,793 $ 236,111 $ 568,836
Other . . . . . . . . . . . . . . . . . . 368 5,779 (365) 415 343 4,412
----------- ----------- ----------- ----------- ----------- -----------
266,166 5,779 68,186 90,208 236,454 573,248
----------- ----------- ----------- ----------- ----------- -----------
GAS SERVICES
Natural gas processing . . . . . . . . . 253,605 18,819 20,088 9,705 6,003 144,987
Natural gas gathering and marketing . . . 296,373 88,744 18,742 9,352 30,668 244,932
Other . . . . . . . . . . . . . . . . . . 10,559 12,766 3,829 2,651 11,957 37,526
----------- ----------- ----------- ----------- ----------- -----------
560,537 120,329 42,659 21,708 48,628 427,445
----------- ----------- ----------- ----------- ----------- -----------
REAL ESTATE . . . . . . . . . . . . . . . 126,106 6,620 21,078 7,282 65,132 930,535
----------- ----------- ----------- ----------- ----------- -----------
CORPORATE . . . . . . . . . . . . . . . . - - - 2,662 3,866 38,064
----------- ----------- ----------- ----------- ----------- -----------
$ 952,809 $ 132,728 $ 131,923 $ 121,860 $ 354,080 $ 1,969,292
=========== =========== =========== =========== =========== ===========
FISCAL 1993 (RESTATED)
EXPLORATION AND PRODUCTION
Oil and gas . . . . . . . . . . . . . . . $ 202,692 $ - $ 59,464 $ 59,952 $ 75,353 $ 444,609
Restructuring charges . . . . . . . . . - - (4,990) - - -
Other . . . . . . . . . . . . . . . . . . 11,989 9,017 (1,404) 962 306 13,071
Restructuring charges . . . . . . . . . - - (15,736) 8,713 - -
----------- ----------- ----------- ----------- ----------- -----------
214,681 9,017 37,334 69,627 75,659 457,680
----------- ----------- ----------- ----------- ----------- -----------
GAS SERVICES
Natural gas processing . . . . . . . . . 306,967 18,485 57,466 10,464 7,964 156,161
Natural gas gathering and marketing . . . 248,605 60,596 25,517 10,144 57,325 229,356
Other . . . . . . . . . . . . . . . . . . 11,128 15,035 5,521 3,118 5,184 46,441
----------- ----------- ----------- ----------- ----------- -----------
566,700 94,116 88,504 23,726 70,473 431,958
----------- ----------- ----------- ----------- ----------- -----------
REAL ESTATE . . . . . . . . . . . . . . . 121,453 5,456 22,801 7,143 84,954 893,001
----------- ----------- ----------- ----------- ----------- -----------
CORPORATE . . . . . . . . . . . . . . . . - - - 2,754 4,538 43,138
----------- ----------- ----------- ----------- ----------- -----------
$ 902,834 $ 108,589 $ 148,639 $ 103,250 $ 235,624 $ 1,825,777
=========== =========== =========== =========== =========== ===========
</TABLE>
- --------------------
* On accrual basis, including exploratory expenditures.
62
<PAGE> 65
Intersegment revenues are recorded at prevailing market prices and are
eliminated in consolidation. Substantially all of the Company's operations are
conducted in the United States. The Company's energy 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. The
creditworthiness of this customer base is strong, and the Company has not
experienced significant credit losses. Exploration and Production segment sales
to Natural Gas Pipeline Company of America constituted approximately 15%, 13%
and 12% of consolidated revenues, respectively, during fiscal 1995, 1994 and
1993.
The reported segment operating earnings amounts are net of charges for
administrative expenses directly attributable to the operations of the various
segments, but are not reduced for amounts reported as general and
administrative expenses. Such expenses include the costs of administrative,
accounting, legal, information systems and other general services that are
managed on a companywide basis.
During the first quarter of fiscal 1995, the Company sold 16 land drilling
rigs for $9,000,000 in cash and warrants to acquire common stock of the
purchaser under which as much as an additional $1,000,000 may be realized
during the two-year period following the sale. This sale effectively completed
the Company's withdrawal from the contract drilling business. The $3,791,000
gain from this sale, which did not include any value for the warrants, is
reported as a component of the segment operating earnings of the Exploration
and Production Division.
Fiscal 1995 segment operating earnings for Gas Services include $48,821,000
in gains from major asset sales. During the second quarter of fiscal 1995, the
Company sold its Spindletop gas storage facility, its Winnie Pipeline system
and a 50% interest in a related gas processing plant for $120,000,000. A gain
of $29,196,000 was recorded on this transaction. During fiscal 1995's third
quarter, a gain of $19,625,000 was recorded in connection with the sale for
$35,000,000 in cash of the Company's compression operations, including 370
compressors and associated facilities and parts inventory. The proceeds from
these sales were used to pay down outstanding borrowings under the Company's
revolving credit and commercial paper facilities.
Restructuring charges and asset write-downs totaling $31,252,000 were
recorded during fiscal 1995's second and third quarters in connection with a
restructuring of the Gas Services Division (which previously was known as the
Transmission and Processing Division). This restructuring program was
undertaken because of the adverse economic environment, particularly prices and
margins, experienced during the last half of fiscal 1994 and early in the
current year. The program calls for the sale or disposition of many idle gas
processing plants, including leased equipment associated with certain of them.
In this regard, write-downs of asset carrying values and accruals of future
lease rentals totaling $18,286,000 were recorded. In addition, a voluntary
incentive retirement program was undertaken to bring the division's employment
level in line with expected future needs. The costs associated with this
program aggregated $7,364,000, most of which will be paid in future years as
additional retirement and retiree medical benefits. During the third quarter,
the Company completed a review of its gas gathering systems and determined that
certain of these systems would be disposed of. Asset write-downs of $5,602,000
were recorded to reduce the carrying values of these systems to their estimated
realizable values.
Also during fiscal 1995's third quarter, the Company determined that it
would sell certain largely undeveloped real estate located outside The
Woodlands which had been held for long-term development. Write-downs of
$5,661,000 were recorded to reduce the carrying values of these assets to their
estimated realizable values.
63
<PAGE> 66
During the first quarter of fiscal 1993, the Company recorded pretax
restructuring charges totaling $21,191,000 in connection with a reorganization
of its Exploration and Production Division. The major charges were related to
oil and gas and other operations; the remaining $465,000 was charged to other
expense. The charges consisted principally of costs attributable to an early
retirement program and other personnel reductions, additional depreciation
expense on drilling rigs and asset write-downs (principally inventories)
resulting from the Company's decision to substantially reduce the scope of its
contract drilling and oil field supply operations.
Because of their magnitude and unusual nature, and in accordance with
Accounting Principles Board Opinion No. 30, the items discussed in the
preceding paragraphs have been reported as separate components of segment
operating earnings.
STOCK OPTIONS AND BONUS UNITS 11
The Company's stock option plans authorize the granting of incentive options
and nonqualified options to purchase 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 over a five-year period. Certain of the option grants
have associated stock appreciation rights (SARs) which entitle optionees to
receive cash payments equal to the difference between the market value and the
option price for the number of options being exercised. Summarized stock option
information follows:
<TABLE>
<CAPTION>
Exercisable Options
-------------------------- Shares
Options Average Reserved for
Outstanding Number Price Future Grant
----------- ----------- ----------- ------------
<S> <C> <C> <C> <C>
At January 31, 1992 . . . . . . . . . . . 490,475 422,875 $ 8.83 437,500
Exercised (at average price of $8.78
per share) . . . . . . . . . . . . . . (65,000)
Cancelled . . . . . . . . . . . . . . . . (21,400)
--------
At January 31, 1993 . . . . . . . . . . . 404,075 344,375 $ 8.96 437,500
Granted . . . . . . . . . . . . . . . . . 120,000
Exercised (at average price of $8.82
per share) . . . . . . . . . . . . . . (218,375)
Cancelled . . . . . . . . . . . . . . . . (4,400)
--------
At January 31, 1994 . . . . . . . . . . . 301,300 142,100 $ 9.99 321,900
Exercised (at average price of $8.83
per share) . . . . . . . . . . . . . . (28,650)
--------
At January 31, 1995 . . . . . . . . . . . 272,650 147,350 $ 12.40 321,900
========
</TABLE>
The Company also uses phantom-stock awards, which it calls "bonus units," as a
long-term incentive. Upon the redemption of such awards, grantees receive gross
compensation in amounts equal to the difference between the market price of the
Company's common stock and 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, substantially all of which have been granted.
These units generally vest in equal annual installments over a five-year
period. At January 31, 1995, grants covering 525,450 units with an average
floor price of $15.90 were outstanding (286,650 of which were exercisable). The
Company recognizes compensation expense over the applicable vesting terms of
the SARs and bonus units (or reversals to the extent of previously recorded
appreciation in periods when the market price of the stock declines). Such
expense accruals (reversals) aggregated $(1,954,000); $3,875,000 and $757,000
in fiscal 1995, 1994 and 1993.
64
<PAGE> 67
RETIREMENT BENEFITS 12
Qualified retirement plan. Except for those engaged in leisure industry
activities, 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 10 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
such contributions were required in fiscal 1995, 1994 or 1993.
The projected unit credit actuarial method is used in determining the
Company's required annual contributions to the retirement plan and its
financial statement pension expense. The assumptions used in the computations
include an expected long-term rate of return on plan assets of 9%, annual
increases in salary levels of 5% in fiscal 1995 and 1994 (6% previously) and
discount rates for the projected benefit obligation of 8.5%, 7.25% and 8.5% in
fiscal 1995, 1994 and 1993, respectively. Plan assets consist primarily of
marketable equity securities and long-term U. S. Treasury notes. Components of
financial statement pension expense for the years ended January 31, 1995, 1994
and 1993 were (in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Service cost - benefits accrued during the year . . . . . $ 4,392 $ 4,097 $ 4,554
Interest accrued on projected benefit obligation . . . . 7,528 7,188 6,559
Early retirement benefits accrued . . . . . . . . . . . . 4,126 - 1,586
Return on plan assets . . . . . . . . . . . . . . . . . . (9,783) (8,581) (7,995)
Amortization of unrecognized gains . . . . . . . . . . . (1,400) (1,853) (1,149)
----------- ----------- -----------
Financial statement pension expense . . . . . . . . . . . $ 4,863 $ 851 $ 3,555
=========== =========== ===========
</TABLE>
The following table summarizes the plan's funded status for financial statement
purposes and the related amounts included in the Company's balance sheets at
January 31, 1995 and 1994 (in thousands):
<TABLE>
<CAPTION>
1995 1994
----------- -----------
<S> <C> <C>
ACTUARIAL PRESENT VALUE OF PENSION BENEFIT OBLIGATION
Vested benefits . . . . . . . . . . . . . . . . . . . . . $ 79,997 $ 77,289
Nonvested benefits . . . . . . . . . . . . . . . . . . . 4,222 3,809
----------- -----------
Accumulated benefit obligation . . . . . . . . . . . . . 84,219 81,098
Provision for future salary increases . . . . . . . . . . 18,741 24,637
----------- -----------
Projected benefit obligation . . . . . . . . . . . . . . $ 102,960 $ 105,735
=========== ===========
AMOUNTS AVAILABLE TO SATISFY PENSION BENEFIT OBLIGATION
Plan assets, at market value . . . . . . . . . . . . . . $ 98,584 $ 110,600
Unrecognized actuarial gains . . . . . . . . . . . . . . (12,131) (16,509)
Balance sheet accrual for pension expense . . . . . . . . 16,507 11,644
----------- -----------
$ 102,960 $ 105,735
=========== ===========
</TABLE>
Nonqualified retirement plans. 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. The Company's liability to make these payments is a general
obligation for which a trust fund has not been established. Approximately
$1,330,000; $819,000 and $2,108,000 was expensed in fiscal 1995, 1994 and 1993
related to these plans (the fiscal 1995 and 1993 amounts included $93,000 and
$1,656,000, respectively, of incremental benefits accrued in connection with
voluntary incentive retirement programs). At January 31, 1995, the aggregate
balance sheet liability attributable to these plans totaled $4,206,000.
65
<PAGE> 68
Postretirement medical benefits. Retirees who reach retirement age while
working for the Company and meet certain other eligibility requirements may
elect coverage under the Company's medical plan. The Company's medical 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 Company adopted SFAS No. 106, "Employers' Accounting for Postretirement
Benefits Other Than Pensions," effective February 1, 1992. Accordingly, a
charge for postretirement medical benefits of $10,551,000 ($15,986,000 before
tax) was recorded as the cumulative effect of the change in accounting methods
for periods prior to fiscal 1993. Components of financial statement expense for
postretirement medical benefits for the years ended January 31, 1995, 1994 and
1993 were (in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Service cost - benefits accrued during the year . . . . . $ 814 $ 554 $ 720
Interest accrued on projected benefit obligation . . . . 1,281 1,046 1,323
Early retirement benefits accrued . . . . . . . . . . . . 1,017 - -
Amortization of unrecognized gains . . . . . . . . . . . (70) (291) -
----------- ----------- -----------
$ 3,042 $ 1,309 $ 2,043
=========== =========== ===========
</TABLE>
The plan is unfunded, and benefits are paid as costs are incurred. Such
benefits payments totaled approximately $850,000; $1,200,000 and $900,000 in
fiscal 1995, 1994 and 1993. The following table summarizes the plan's status
for financial statement purposes and the related amounts included in the
Company's balance sheets at January 31, 1995 and 1994 (in thousands):
<TABLE>
<CAPTION>
1995 1994
----------- -----------
<S> <C> <C>
ACTUARIAL PRESENT VALUE OF POSTRETIREMENT BENEFIT OBLIGATION
Retirees . . . . . . . . . . . . . . . . . . . . . . . . $ 12,087 $ 9,463
Fully eligible, active plan participants . . . . . . . . 2,570 2,913
Other active plan participants . . . . . . . . . . . . . 7,385 5,921
Unrecognized actuarial gains . . . . . . . . . . . . . . (2,612) (1,059)
----------- -----------
Balance sheet accrual for postretirement benefits . . . . $ 19,430 $ 17,238
=========== ===========
</TABLE>
The Company's assumed medical cost trend rate starts at 7%, declines gradually
to 5.5% in 2002 and remains at that level thereafter. The medical cost trend
rate assumption has a significant effect on the amount of the obligation and
the periodic cost reported. An increase of 1% in the assumed trend rate for
each year would have increased the actuarial present value of the
postretirement benefit obligation at January 31, 1995 by $3,014,000 and the
aggregate service and interest components of the fiscal 1995 cost by a total of
$361,000. Discount rates of 8.5% and 7.25% were used in determining the present
value of the postretirement benefit obligation at January 31, 1995 and 1994,
respectively.
66
<PAGE> 69
FINANCIAL INSTRUMENTS 13
Fair values of notes and contracts receivable were estimated by discounting
future cash flows using interest rates at which similar loans currently could
be made for similar maturities to borrowers with comparable credit ratings. The
aggregate fair value of the Company's notes and contracts receivable totaled
$37,834,000 at January 31, 1995 (compared with their aggregate balance sheet
carrying value of $40,314,000).
Fair values of fixed-rate, long-term debt were based on quoted market
prices or, where such prices were not available, on current interest rates
offered to the Company for debt with similar remaining maturities. For
floating-rate, long-term debt obligations, carrying amounts and fair values
were assumed to be equal because of the nature of these obligations. At January
31, 1995, the estimated fair value of the Company's long-term debt totaled
$869,093,000 (compared with a balance sheet carrying value of $894,962,000).
The carrying amounts of the Company's other on-balance-sheet financial
instruments approximate their fair values. The aggregate cost to terminate the
Company's off-balance-sheet financial instruments is not material.
The Company has only limited involvement with derivative financial
instruments and does not use them for trading purposes. Such use generally
consists of the use of commodities futures contracts to hedge well-defined
price risks associated with its energy operations. At January 31, 1995 and
1994, the amounts of open transactions under such arrangements were
insignificant.
SUBSEQUENT EVENT 14
In February 1995, the Company's Board of Directors approved a personnel
reduction program that will result in the elimination of at least 300 jobs by
April 30, 1995. The Company has offered a voluntary incentive retirement
program to qualifying employees and will pay severance benefits to terminated
employees not eligible for that program. The aggregate pretax cost of these
incremental benefits, which is estimated at $20,000,000, will be expensed in
the first quarter of fiscal 1996.
67
<PAGE> 70
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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, 1995 and 1994, and the related consolidated statements of earnings,
stockholders' equity and cash flows for each of the three years in the period
ended January 31, 1995. 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 generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, 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, 1995 and 1994, and the
results of their operations and their cash flows for each of the three years in
the period ended January 31, 1995, in conformity with generally accepted
accounting principles.
As explained in Note 1 to the consolidated financial statements, the
Company has given retroactive effect to the change in accounting for oil and
gas producing activities from the full cost to the successful efforts method.
ARTHUR ANDERSEN LLP
Houston, Texas
April 7, 1995
68
<PAGE> 71
SUPPLEMENTAL OIL AND GAS INFORMATION
(Unaudited)
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
Reserve quantities. The following tables summarize changes in total proved
reserve quantities for the fiscal years ended January 31, 1995, 1994 and 1993
and the proved developed reserve quantities at the dates indicated:
<TABLE>
<CAPTION>
Total Proved Reserves
--------------------------------------------------------------------------------------
1995 1994
----------------------------------------- -----------------------------------------
Equity Equity
Consol- Partner- Consol- Partner-
Total idated ships Total idated ships
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
NATURAL GAS (BCF)
Beginning balance . . . . . . . . . . 627.5 627.5 - 583.7 511.7 72.0
Extensions and discoveries . . . . . 141.9 141.9 - 94.5 84.0 10.5
Production marketed . . . . . . . . . (78.1) (78.1) - (70.7) (69.0) (1.7)
Production consumed
in operations . . . . . . . . . . . (3.7) (3.7) - (3.7) (3.6) (.1)
Purchases of minerals in-place . . . 1.5 1.5 - 34.6 34.6 -
Transfers of undeveloped
reserves to partnerships . . . . . - - - (.3) (1.4) 1.1
Purchases of partnership interests . - - - - 79.0 (79.0)
Revision of previous estimates . . . - - - (9.4) (6.7) (2.7)
Sales of minerals in-place . . . . . (3.4) (3.4) - (1.2) (1.1) (.1)
----------- ----------- ----------- ----------- ----------- -----------
Ending balance . . . . . . . . . . . 685.7 685.7 - 627.5 627.5 -
=========== =========== =========== =========== =========== ===========
OIL AND CONDENSATE (MMBBLS)
Beginning balance . . . . . . . . . . 15.3 15.3 - 15.8 14.0 1.8
Extensions and discoveries . . . . . 1.4 1.4 - 1.7 1.6 .1
Production . . . . . . . . . . . . . (2.3) (2.3) - (2.2) (2.1) (.1)
Purchases of minerals in-place . . . - - - .8 .8 -
Sales of minerals in-place . . . . . (.5) (.5) - (.5) (.4) (.1)
Revision of previous estimates . . . - - - (.7) (.7) -
Improved recovery . . . . . . . . . . .4 .4 - .5 .5 -
Transfers and other . . . . . . . . . - - - (.1) 1.6 (1.7)
----------- ----------- ----------- ----------- ----------- -----------
Ending balance . . . . . . . . . . . 14.3 14.3 - 15.3 15.3 -
=========== =========== =========== =========== =========== ===========
PLANT NGLS (MMBBLS)
Beginning balance . . . . . . . . . . 107.4 67.3 40.1 127.4 79.1 48.3
Additions . . . . . . . . . . . . . . 20.4 13.8 6.6 10.7 7.1 3.6
Production . . . . . . . . . . . . . (17.3) (10.4) (6.9) (18.1) (11.3) (6.8)
Purchase of interests in
C&L Processors' plants . . . . . . - - - - - -
Revision of previous estimates . . . 10.8 .9 9.9 (12.6) (7.6) (5.0)
----------- ----------- ----------- ----------- ----------- -----------
Ending balance . . . . . . . . . . . 121.3 71.6 49.7 107.4 67.3 40.1
=========== =========== =========== =========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
Total Proved Reserves
-----------------------------------------
1993
-----------------------------------------
Equity
Consol- Partner-
Total idated ships
----------- ----------- -----------
<S> <C> <C> <C>
NATURAL GAS (BCF)
Beginning balance . . . . . . . . . . 581.7 503.6 78.1
Extensions and discoveries . . . . . 56.6 12.1 44.5
Production marketed . . . . . . . . . (54.6) (47.6) (7.0)
Production consumed
in operations . . . . . . . . . . . (3.0) (2.7) (.3)
Purchases of minerals in-place . . . 15.0 15.0 -
Transfers of undeveloped
reserves to partnerships . . . . . - (.1) .1
Purchases of partnership interests . - 42.5 (42.5)
Revision of previous estimates . . . (2.3) 1.4) (.9)
Sales of minerals in-place . . . . . (9.7) (9.7) -
----------- ----------- -----------
Ending balance . . . . . . . . . . . 583.7 511.7 72.0
=========== =========== ===========
OIL AND CONDENSATE (MMBBLS)
Beginning balance . . . . . . . . . . 15.6 14.1 1.5
Extensions and discoveries . . . . . 1.5 .4 1.1
Production . . . . . . . . . . . . . (2.1) (1.9) (.2)
Purchases of minerals in-place . . . 1.1 1.1 -
Sales of minerals in-place . . . . . (.4) (.4) -
Revision of previous estimates . . . (.4) (.5) .1
Improved recovery . . . . . . . . . . .4 .4 -
Transfers and other . . . . . . . . . .1 .8 (.7)
----------- ----------- -----------
Ending balance . . . . . . . . . . . 15.8 14.0 1.8
=========== =========== ===========
PLANT NGLS (MMBBLS)
Beginning balance . . . . . . . . . . 101.6 84.3 17.3
Additions . . . . . . . . . . . . . . 17.2 6.1 11.1
Production . . . . . . . . . . . . . (17.1) (12.4) (4.7)
Purchase of interests in
C&L Processors' plants . . . . . . 30.2 - 30.2
Revision of previous estimates . . . 4.5) 1.1 (5.6)
----------- ----------- -----------
Ending balance . . . . . . . . . . . 127.4 79.1 48.3
=========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
Proved Developed Reserves at January 31,
--------------------------------------------------------
1995 1994 1993 1992
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
NATURAL GAS (BCF)
Consolidated . . . . . . . . . . . . . . 577.1 558.5 437.7 419.9
Equity partnerships . . . . . . . . . . . - - 72.0 78.1
----------- ----------- ----------- -----------
577.1 558.5 509.7 498.0
=========== =========== =========== ===========
OIL AND CONDENSATE (MMBBLS)
Consolidated . . . . . . . . . . . . . . 12.6 13.8 12.3 11.9
Equity partnerships . . . . . . . . . . . - - 1.8 1.5
----------- ----------- ----------- -----------
12.6 13.8 14.1 13.4
=========== =========== =========== ===========
PLANT NGLS (MMBBLS)
Consolidated . . . . . . . . . . . . . . 60.1 59.2 70.8 77.4
Equity partnerships . . . . . . . . . . . 45.9 37.2 43.1 17.3
----------- ----------- ----------- -----------
106.0 96.4 113.9 94.7
=========== =========== =========== ===========
</TABLE>
69
<PAGE> 72
Future net cash flows. The following table sets forth estimates of the
standardized measure of discounted future net cash flows from total proved
reserves at January 31, 1995, 1994 and 1993 (in millions):
<TABLE>
<CAPTION>
1995 1994
----------------------------------------- -----------------------------------------
Equity Equity
Consol- Partner- Consol- Partner-
Total idated ships Total idated ships
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
Oil and Gas
Future cash inflows . . . . . . . . . $ 1,696 $ 1,696 $ - $ 1,829 $ 1,829 $ -
Future production and
development costs . . . . . . . . . (644) (644) - (620) (620) -
Discount -- 10% annually . . . . . . (344) (344) - (419) (419) -
----------- ----------- ----------- ----------- ----------- -----------
Present value of
future net revenues . . . . . . . . 708 708 - 790 790 -
Future income taxes, dis-
counted at 10% annually . . . . . . (107) (107) - (117) (117) -
----------- ----------- ----------- ----------- ----------- -----------
$ 601 $ 601 $ - $ 673 $ 673 $ -
=========== =========== =========== =========== =========== ===========
Plant NGLs
Future cash inflows . . . . . . . . . $ 1,368 $ 817 $ 551 $ 1,188 $ 762 $ 426
Future production costs . . . . . . . (970) (553) (417) (859) (533) (326)
Discount -- 10% annually . . . . . . (150) (100) (50) (133) (90) (43)
----------- ----------- ----------- ----------- ----------- -----------
Present value of
future net revenues . . . . . . . . 248 164 84 196 139 57
Future income taxes, dis-
counted at 10% annually . . . . . . (70) (39) (31) (50) (30) (20)
----------- ----------- ----------- ----------- ----------- -----------
$ 178 $ 125 $ 53 $ 146 $ 109 $ 37
=========== =========== =========== =========== =========== ===========
<CAPTION>
1993
-----------------------------------------
Equity
Consol- Partner-
Total idated ships
----------- ----------- -----------
<S> <C> <C> <C>
Oil and Gas
Future cash inflows . . . . . . . . . $ 1,868 $ 1,648 $ 220
Future production and
development costs . . . . . . . . . (643) (584) (59)
Discount -- 10% annually . . . . . . (415) (362) (53)
----------- ----------- -----------
Present value of
future net revenues . . . . . . . . 810 702 108
Future income taxes, dis-
counted at 10% annually . . . . . . (170) (140) (30)
----------- ----------- -----------
$ 640 $ 562 $ 78
=========== =========== ===========
Plant NGLs
Future cash inflows . . . . . . . . . $ 1,741 $ 1,086 $ 655
Future production costs . . . . . . . (1,201) (727) (474)
Discount -- 10% annually . . . . . . (200) (132) (68)
----------- ----------- -----------
Present value of
future net revenues . . . . . . . . 340 227 113
Future income taxes, dis-
counted at 10% annually . . . . . . (94) (59) (35)
----------- ----------- -----------
$ 246 $ 168 $ 78
=========== =========== ===========
</TABLE>
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 partnerships engaged in oil and gas
activities were liquidated during fiscal 1994 (see Note 4 for information
concerning the buy-out of MEC Development, Ltd.). During fiscal 1993, the
Company purchased the remaining interests in Phase 6 of that partnership.
The natural gas reserve quantities reported as oil and gas reserves
represent wet gas volumes and include gas quantities that will be converted by
processing to NGLs (both leasehold and plant ownership). The oil and gas future
net cash flows, however, include only the Company's leasehold reimbursement for
natural gas liquids extracted during processing. As discussed below, the
remainder of the cash flows associated with the Company's ownership of NGL
reserves extracted from its wet gas volumes is included in plant NGL future net
cash flows since those cash flows accrue to the Company because of its
ownership of 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 Company-owned NGL
reserves and to NGLs extracted from gas streams owned by third parties. The
Company reimburses the owners of the natural gas streams based either on a
percentage of the value of the liquids produced or on the value of the natural
gas consumed in processing under keep-whole agreements. Such reimbursements,
including amounts attributable to the Company's oil and gas leasehold interests
(included in oil and gas future net cash flows), are deducted as production
costs in determining future net cash flows from plant NGLs.
70
<PAGE> 73
Of the total remaining natural gas reserves at January 31, 1995, 313.9 Bcf
will be processed at Company plants, including 79.1 Bcf of fiscal 1995's
natural gas reserve additions from extensions and discoveries. It is estimated
that 75.8 Bcf of such reserves and 19.1 Bcf of such reserve additions will be
converted by processing into 42.2 MMBbls and 10.4 MMBbls, respectively, of
plant NGL reserves and plant NGL reserve additions.
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 present value of 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.
Excluded from the reported amounts for future net cash flows are deferred
natural gas contract restructuring proceeds. While such proceeds have been
received, they will be reported as oil and gas revenues in future periods. At
January 31, 1995, such deferred revenues totaled $35,017,000.
The following table sets forth the changes in the standardized measure of
discounted future net cash flows for the years ended January 31, 1995, 1994 and
1993 (in millions):
<TABLE>
<CAPTION>
1995 1994
----------------------------------------- -----------------------------------------
Equity Equity
Consol- Partner- Consol- Partner-
Total idated ships Total idated ships
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
OIL AND GAS
Extensions and discoveries,
net of related costs . . . . . . . . $ 103 $ 103 $ - $ 108 $ 92 $ 16
Sales, net of production costs . . . . (183) (183) - (176) (171) (5)
Net changes in prices
and production costs . . . . . . . . (101) (101) - (31) (28) (3)
Accretion of discount . . . . . . . . . 76 76 - 68 64 4
Transfers of undeveloped
reserves to partnerships . . . . . . - - - - (2) 2
Purchase of partner-
ship interests . . . . . . . . . . . - - - - 110 (110)
Production rate
changes and other . . . . . . . . . . 1 1 - (28) (21) (7)
Development costs incurred . . . . . . 28 28 - 13 13 -
Purchases of minerals in-place . . . . 2 2 - 47 47 -
Sales of minerals in-place . . . . . . (8) (8) - (4) (4) -
Revisions of previous
quantity estimates . . . . . . . . . - - - (17) (12) (5)
----------- ----------- ----------- ----------- ----------- -----------
Change in present value
of future net revenues . . . . . . . (82) (82) - (20) 88 (108)
Net change in present value
of future income taxes . . . . . . . 10 10 - 53 23 30
----------- ----------- ----------- ----------- ----------- -----------
$ (72) $ (72) $ - $ 33 $ 111 $ (78)
=========== =========== =========== =========== =========== ===========
PLANT NGLS
Additions, net of related costs . . . . $ 44 $ 33 $ 11 $ 17 $ 15 $ 2
Sales, net of production costs . . . . (23) (8) (15) (30) (16) (14)
Net changes in prices and costs . . . . (8) (19) 11 (144) (97) (47)
Purchase of interests in
C&L Processors' plants . . . . . . . - - - - - -
Accretion of discount . . . . . . . . . 20 14 6 34 23 11
Revisions of previous
quantity estimates . . . . . . . . . 16 1 15 (17) (8) (9)
Other . . . . . . . . . . . . . . . . . 3 4 (1) (4) (5) 1
----------- ----------- ----------- ----------- ----------- -----------
Change in present value
of future net revenues . . . . . . . 52 25 27 (144) (88) (56)
Net change in present value
of future income taxes . . . . . . . (20) (9) (11) 44 29 15
----------- ----------- ----------- ----------- ----------- -----------
$ 32 $ 16 $ 16 $ (100) $ (59) $ (41)
=========== =========== =========== =========== =========== ===========
<CAPTION>
1993
-----------------------------------------
Equity
Consol- Partner-
Total idated ships
----------- ----------- -----------
<S> <C> <C> <C>
OIL AND GAS
Extensions and discoveries,
net of related costs . . . . . . . . $ 88 $ 10 $ 78
Sales, net of production costs . . . . (126) (107) (19)
Net changes in prices
and production costs . . . . . . . . 60 51 9
Accretion of discount . . . . . . . . . 65 55 10
Transfers of undeveloped
reserves to partnerships . . . . . . (1) (2) 1
Purchase of partner-
ship interests . . . . . . . . . . . - 60 (60)
Production rate
changes and other . . . . . . . . . . (26) (16) (10)
Development costs incurred . . . . . . 13 13 -
Purchases of minerals in-place . . . . 27 27 -
Sales of minerals in-place . . . . . . (6) (6) -
Revisions of previous
quantity estimates . . . . . . . . . (7) (6) (1)
----------- ----------- -----------
Change in present value
of future net revenues . . . . . . . 87 79 8
Net change in present value
of future income taxes . . . . . . . (17) (7) (10)
----------- ----------- -----------
$ 70 $ 72 $ (2)
=========== =========== ===========
PLANT NGLS
Additions, net of related costs . . . . $ 47 $ 20 $ 27
Sales, net of production costs . . . . (52) (34) (18)
Net changes in prices and costs . . . . 17 18 (1)
Purchase of interests in
C&L Processors' plants . . . . . . . 72 - 72
Accretion of discount . . . . . . . . . 23 19 4
Revisions of previous
quantity estimates . . . . . . . . . - 14 (14)
Other . . . . . . . . . . . . . . . . . 5 3 2
----------- ----------- -----------
Change in present value
of future net revenues . . . . . . . 112 40 72
Net change in present value
of future income taxes . . . . . . . (41) (17) (24)
----------- ----------- -----------
$ 71 $ 23 $ 48
=========== =========== ===========
</TABLE>
71
<PAGE> 74
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
aformentioned 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.
Oil and gas related costs and operating results. The following tables set forth
capitalized costs at January 31, 1995, 1994 and 1993 and costs incurred and
operating results for oil and gas producing activities for the years then ended
(in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
Capitalized Costs Restated Restated
<S> <C> <C> <C>
Oil and gas properties (including equity
partnership investments of $11,267 in 1993) . . . . . . $ 1,606,066 $ 1,595,004 $ 1,446,433
Support equipment and facilities . . . . . . . . . . . . 68,941 70,893 66,524
Accumulated depreciation, depletion and amortization . . (1,158,686) (1,148,993) (1,114,969)
----------- ----------- -----------
Net capitalized costs . . . . . . . . . . . . . . . . . . $ 516,321 $ 516,904 $ 397,988
=========== =========== ===========
Proportional interest in net capitalized
costs of equity partnerships . . . . . . . . . . . . . $ - $ - $ 38,772
=========== =========== ===========
Costs Incurred
Property acquisition
Unproved . . . . . . . . . . . . . . . . . . . . . . . $ 9,046 $ 8,799 $ 7,986
Proved (including $78,251 in 1994 for the
buy-out of MEC Development, Ltd. properties) . . . . 941 89,972 18,934
Exploration . . . . . . . . . . . . . . . . . . . . . . . 19,221 34,850 18,296
Development . . . . . . . . . . . . . . . . . . . . . . . 81,713 98,326 27,489
----------- ----------- -----------
Costs incurred . . . . . . . . . . . . . . . . . . . . . 110,921 231,947 72,705
Equity partnership investments . . . . . . . . . . . . . - 314 27
Support equipment and facilities . . . . . . . . . . . . 4,152 3,850 2,621
----------- ----------- -----------
Capital and exploratory expenditures . . . . . . . . . . $ 115,073 $ 236,111 $ 75,353
=========== =========== ===========
Proportional interest in costs
incurred by equity partnerships . . . . . . . . . . . . $ - $ 5,470 $ 20,039
=========== =========== ===========
Operating Results*
Production revenues . . . . . . . . . . . . . . . . . . . $ 247,403 $ 231,707 $ 162,897
Amortization of deferred contract restructuring
proceeds . . . . . . . . . . . . . . . . . . . . . . . . 16,510 18,723 20,360
Other revenues . . . . . . . . . . . . . . . . . . . . . 9,395 11,733 5,426
----------- ----------- -----------
273,308 262,163 188,683
Less - Production costs . . . . . . . . . . . . . . . . . 64,203 61,082 55,523
Depreciation, depletion and amortization
(including proved property impairments of
$4,718, $13,649 and $2,332). . . . . . . . . . . 96,369 89,793 59,952
Exploration expenses . . . . . . . . . . . . . . . 12,265 12,356 9,069
Exploratory dry hole costs . . . . . . . . . . . . 1,042 17,613 4,428
Other operating costs. . . . . . . . . . . . . . . 14,621 16,590 12,716
Losses (gains) from sales of proved properties . . 693 (187) 1,540
Restructuring charges . . . . . . . . . . . . . . - - 4,990
----------- ----------- -----------
84,115 64,916 40,465
Equity in earnings of partnerships . . . . . . . . . . . - 3,635 14,009
----------- ----------- -----------
Segment operating earnings . . . . . . . . . . . . . . . 84,115 68,551 54,474
Income taxes . . . . . . . . . . . . . . . . . . . . . . 26,665 19,251 14,092
----------- ----------- -----------
$ 57,450 $ 49,300 $ 40,382
=========== =========== ===========
</TABLE>
- --------------------
* Excluding general and administrative and interest expense.
72
<PAGE> 75
HISTORICAL SUMMARY
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
Five years ended January 31, 1995 (dollar amounts in thousands)
<TABLE>
<CAPTION>
Restated
--------------------------------------------------------
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
FINANCIAL POSITION AT YEAR END
Net property, plant and equipment . . . . $ 734,099 $ 858,705 $ 737,758 $ 688,924 $ 656,575
Real estate . . . . . . . . . . . . . . . 917,890 896,652 864,351 873,326 842,180
Total assets . . . . . . . . . . . . . . 1,855,871 1,969,292 1,825,777 1,793,604 1,752,627
CAPITAL EMPLOYED
Long-term debt . . . . . . . . . . . . $ 894,962 $ 988,318 $ 947,723 $ 954,327 $ 904,997
Deferred income taxes . . . . . . . . . 200,722 181,989 178,375 173,206 162,054
Deferred credits and other
liabilities . . . . . . . . . . . . . 114,915 118,632 141,200 133,488 154,439
Stockholders' equity . . . . . . . . . 475,030 463,237 338,418 334,969 304,964
----------- ----------- ----------- ----------- -----------
$ 1,685,629 $ 1,752,176 $ 1,605,716 $ 1,595,990 $ 1,526,454
=========== =========== =========== =========== ===========
CAPITAL AND EXPLORATORY EXPENDITURES (ACCRUAL BASIS)
Exploration and Production . . . . . . . $ 115,073 $ 158,203 $ 75,659 $ 82,162 $ 98,116
MEC Development, Ltd. buy-out . . . . . - 78,251 - - -
Gas Services . . . . . . . . . . . . . . 35,111 48,628 70,473 50,749 29,662
Real Estate . . . . . . . . . . . . . . . 65,123 65,132 84,954 82,881 94,084
Corporate . . . . . . . . . . . . . . . . 4,268 3,866 4,538 5,854 6,217
----------- ----------- ----------- ----------- -----------
$ 219,575 $ 354,080 $ 235,624 $ 221,646 $ 228,079
=========== =========== =========== =========== ===========
ENERGY OPERATING STATISTICS
Average daily volumes
Natural gas sales (Mcf) . . . . . . . . 214,100 193,800 149,000 157,800 150,600
Crude oil and condensate sales (Bbls) . 6,300 6,000 5,600 5,400 5,200
Natural gas liquids produced (Bbls) . . 47,500 49,800 47,200 44,000 37,600
Pipeline throughput (Mcf) . . . . . . . 415,000 549,000 566,000 581,000 458,000
Average annual sales price (dollars)
Natural gas (per Mcf) . . . . . . . . . $ 2.71 $ 2.86 $ 2.84 $ 2.74 $ 2.88
Crude oil and condensate (per Bbl) . . 15.75 16.31 18.49 18.95 22.89
Natural gas liquids produced (per Bbl). 11.57 12.18 13.41 13.41 14.36
Drilling program (gross wells)
Wells drilled . . . . . . . . . . . . . 132 154 152 163 156
Wells completed . . . . . . . . . . . . 121 127 129 134 133
Well count at year end (gross wells) . . 3,280 3,413 3,532 3,666 3,613
REAL ESTATE OPERATING STATISTICS
The Woodlands
Residential lots sold . . . . . . . . . 951 844 911 910 907
Average price per lot (dollars) . . . 37,287 39,055 38,196 36,400 32,431
Average price per square foot
(dollars) . . . . . . . . . . . . . 3.70 3.38 3.14 2.95 2.59
Commercial and institutional
acreage sold . . . . . . . . . . . . 67 144 58 171 16
Office, industrial and retail space
managed (thousands of square feet) . . 2,491 2,204 2,140 1,798 1,786
Apartment units managed . . . . . . . . . 1,675 1,883 2,055 2,055 1,915
Bulk acreage sold . . . . . . . . . . . . 74 250 - 565 -
STOCKHOLDERS' EQUITY (per share at
year end) . . . . . . . . . . . . . . . $ 9.09 $ 8.78 $ 7.25 $ 7.14 $ 6.51
RATIO OF EARNINGS TO FIXED CHARGES . . . 1.70x 1.25x 1.30x 1.45x 1.14x
</TABLE>
73
<PAGE> 76
HISTORICAL SUMMARY
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
Five years ended January 31, 1995 (in thousands except per share data)
<TABLE>
<CAPTION>
Restated
--------------------------------------------------------
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Revenues
Exploration and Production . . . . . . . $ 277,099 $ 266,166 $ 214,681 $ 231,073 $ 237,301
Gas Services
Natural gas processing . . . . . . . . 252,159 253,605 306,967 268,643 237,971
Natural gas gathering and marketing . . 180,038 296,373 248,605 231,068 203,709
Gains from major asset sales . . . . . 48,821 - - - -
Other . . . . . . . . . . . . . . . . . 6,989 10,559 11,128 12,268 13,493
Real Estate . . . . . . . . . . . . . . . 129,465 126,106 121,453 131,318 98,803
----------- ----------- ----------- ----------- -----------
Total revenues . . . . . . . . . . . $ 894,571 $ 952,809 $ 902,834 $ 874,370 $ 791,277
=========== =========== =========== =========== ===========
Segment Operating Earnings
Exploration and Production
Operations . . . . . . . . . . . . . . $ 84,115 $ 68,186 $ 58,060 $ 48,118 $ 46,122
Restructuring charges . . . . . . . . . - - (20,726) - -
Gains from major asset sales . . . . . 3,791 - - - -
Gas Services
Natural gas processing . . . . . . . . 23,253 20,088 57,466 62,076 71,211
Natural gas gathering and marketing . . 12,335 18,742 25,517 23,212 20,866
Gains from major asset sales . . . . . 48,821 - - - -
Restructuring charges and asset
write-downs . . . . . . . . . . . . . (31,252) - - - -
Other . . . . . . . . . . . . . . . . . (846) 3,829 5,521 4,569 5,968
Real Estate
Operations . . . . . . . . . . . . . . 25,793 21,078 22,801 22,724 15,937
Asset write-downs . . . . . . . . . . . (5,661) - - - (11,624)
----------- ----------- ----------- ----------- -----------
Total segment operating earnings . . 160,349 131,923 148,639 160,699 148,480
General and administrative expense . . . 42,225 43,222 41,398 38,184 37,638
Interest expense . . . . . . . . . . . . 69,982 74,057 75,284 81,169 88,387
Capitalized interest . . . . . . . . . . (28,816) (33,956) (34,161) (37,460) (44,253)
Other expense . . . . . . . . . . . . . . 6,407 1,224 6,096 5,618 6,224
----------- ----------- ----------- ----------- -----------
Earnings Before Income Taxes, Extraordinary
Item and Cumulative Effect of Change
in Accounting Methods . . . . . . . . . 70,551 47,376 60,022 73,188 60,484
Income taxes . . . . . . . . . . . . . . 24,737 17,346* 14,967 25,261 20,564
----------- ----------- ----------- ----------- -----------
Earnings Before Extraordinary Item and
Cumulative Effect of Change in
Accounting Methods . . . . . . . . . . 45,814 30,030 45,055 47,927 39,920
Extraordinary item (early retirement
of debt) . . . . . . . . . . . . . . . - (5,426) (7,251) - -
Cumulative effect of change in accounting
method for postretirement medical
benefits . . . . . . . . . . . . . . . - - (10,551) - -
----------- ----------- ----------- ----------- -----------
Net Earnings . . . . . . . . . . . . . . $ 45,814 $ 24,604 $ 27,253 $ 47,927 $ 39,920
=========== =========== =========== =========== ===========
Per Common Share Amounts
Earnings before extraordinary item and
cumulative effect of change in
accounting methods . . . . . . . . . . $ .87 $ .58 $ .96 $ 1.02 $ .85
Extraordinary item . . . . . . . . . . . - (.10) (.15) - -
Cumulative effect of change in
accounting methods . . . . . . . . . . - - (.23) - -
----------- ----------- ----------- ----------- -----------
Net earnings . . . . . . . . . . . . . . $ .87 $ .48 $ .58 $ 1.02 $ .85
=========== =========== =========== =========== ===========
Cash Dividends (cents per share)
Prior to stock reclassification . . . . . 20.00 40.00 34.00
Class A . . . . . . . . . . . . . . . . . 48.00 48.00 22.00
Class B . . . . . . . . . . . . . . . . . 53.00 53.00 23.75
Average Common Shares Outstanding . . . . 52,696 51,004 46,858 46,849 46,935
</TABLE>
________________
* Includes a $6,574 deferred provision related to an increase in the corporate
statutory Federal income tax rate from 34% to 35%.
74
<PAGE> 77
PRINCIPAL OFFICERS
<TABLE>
<S> <C>
George P. Mitchell Philip S. Smith
Chairman and Chief Executive Officer Corporate Senior Vice President,
Chief Financial Officer, and
Bernard F. Clark President--Administration and Financial Division
Vice Chairman
Allen J. Tarbutton, Jr.
W. D. Stevens Corporate Senior Vice President,
President and Chief Operating Officer, President--Gas Services Division
President--Exploration and Production Division
Thomas P. Battle
Roger L. Galatas Corporate Senior Vice President,
Corporate Senior Vice President, General Counsel and Secretary
President--Real Estate Division
</TABLE>
Left to right: Philip S. Smith, Roger L. Galatas, Allen J. Tarbutton, Jr.,
Bernard F. Clark, Thomas P. Battle
(PICTURE)
75
<PAGE> 78
Board of Directors
<TABLE>
<S> <C>
George P. Mitchell Walter A. Lubanko(2)
Chairman and Chief Executive Officer, Chairman and President,
Mitchell Energy & Development Corp. W.A. Lubanko & Co., Inc. (investment banking),
Brookville, New York
Bernard F. Clark
Vice Chairman, M. Kent Mitchell(1)(3)
Mitchell Energy & Development Corp. President and Chief Executive Officer,
Bald Head Island Management, Inc.
W. D. Stevens(3) (real estate development),
President and Chief Operating Officer, Bald Head Island, North Carolina
President--Exploration and Production Division,
Mitchell Energy & Development Corp. J. Todd Mitchell(3)
President,
Robert W. Baldwin(1) The Discovery Bay Company (seismic software)
Consultant (energy/management); and Dolomite Resources, Inc.
retired President, Gulf Refining (exploration and investments),
and Marketing Company Houston
(a division of Gulf Oil Corp.), Houston
Michael B. Morris(2)
William D. Eberle(1)(3) Petroleum Consultant;
Chairman, retired President of Petroleum Operations,
Greenwich Entertainment Group, Inc. Conoco, Inc., Houston
(movie theater entertainment);
Chairman, Manchester Associates (venture capital Raymond L. Watson(2)
consulting), Boston and Washington, D.C. Chairman,
Executive Committee of the Board of Directors,
Shaker A. Khayatt(1) The Walt Disney Company, Burbank, California;
President and Chief Executive Officer, Vice Chairman, The Irvine Company,
Khayatt and Company, Inc. (investment banking), Newport Beach, California
New York City
J. McDonald Williams(2)
Ben F. Love(2)(3) Chairman,
Consultant; Trammell Crow Company, Dallas
retired Chairman and Chief Executive Officer,
Texas Commerce Bancshares, Houston (1) Compensation Committee
(2) Audit Committee
(3) Executive Committee
</TABLE>
76
<PAGE> 79
CORPORATE INFORMATION
<TABLE>
<S> <C>
STOCK LISTINGS ANNUAL MEETING
New York Stock Exchange 10 a.m. CDT
The Pacific Stock Exchange Wednesday, June 28, 1995
Ticker Symbols: MND A and MND B The Woodlands Executive
Options Trading: The Pacific Stock Exchange Conference Center and Resort
2301 North Millbend
The Woodlands, Texas 77380
TRANSFER AGENT AND REGISTRAR Phone: (713) 367-1100
Chemical Shareholder Services Group, Inc. FORM 10-K
c/o Chemical Bank
450 West 133rd St. Copies of the Company's Form 10-K
New York, New York 10001 are available upon written request to:
Phone: 1-800-635-9270 Public Affairs Department
Mitchell Energy & Development Corp.
P.O. Box 4000
The Woodlands, Texas 77387-4000
Phone: (713) 377-5650
</TABLE>
Design: Gluth, Weaver Design, Houston
Photography: Joe David Cantu, Ted Washington
77
<PAGE> 1
Exhibit 21
MITCHELL ENERGY & DEVELOPMENT CORP.
SUBSIDIARIES
Listings of the Company's major subsidiaries and partnership interests
at January 31, 1995 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 Services, Inc. ("MGS")*
Mitchell Marketing Company (Louisiana)
The Woodlands Corporation (TWC)
Mitchell Catamount, Inc. (Texas)
Mitchell & Mitchell Investment Corp.
Mitchell Mortgage Company (Texas)
MND Hospitality, Inc.
The Woodlands Investment Group, Inc.
MND Service, Inc.
The Woodlands Venture Capital Company
PARTNERSHIP INTERESTS (accounted for on equity basis)
Austin Chalk Natural Gas Marketing Services (45% owned by Mitchell
Marketing Company)
Bee County Joint Venture (50% owned by MGS)
Belvieu Environmental Fuels (33.33% owned by MGS)
Brooks-Hidalgo Pipeline System (50% owned by MGS)
C&L Processors Partnership (50% owned by MGS)
Cochran's Crossing - 94 Limited (50% owned by TWC)
Ferguson-Burleson County Gas Gathering System (45% owned by MGS)
The Fort Crockett Hotel Limited (50% owned by TWC)
Gulf Coast Fractionators (38.75% owned by MGS)
Lake Catamount Joint Venture (50% owned by Mitchell Catamount, Inc.)
PC Retail-93 Limited Partnership (50% owned by TWC)
Southwood Limited I (50% owned by TWC)
The Woodlands Communications Network (50% owned by TWC)
The Woodlands Mall Associates (50% owned by TWC)
UP Bryan Plant (45% owned by MGS)
Woodlands/Durham Enclave, Ltd. (49% owned by TWC,
1% owned by The Woodlands Investment Group, Inc.)
Woodlands Equity Partnership-89 (50% owned by TWC)
- --------------------------
*Does business as Liquid Energy Corporation and Southwestern Gas Pipeline, Inc.
<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.
2-74458, 2-86550, 2-93380, 33-2716, 33-26276 and 33-31446 and into the
previously filed Form S-3 Registration Statement Nos. 33-57332 and 33-61070.
ARTHUR ANDERSEN LLP
Houston, Texas
April 20, 1995
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
consolidated financial statements and related notes of Mitchell Energy &
Development Corp. and subsidiaries at July 31, 1994 and for the six-month
period then ended and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> JAN-31-1995
<PERIOD-START> FEB-1-1994
<PERIOD-END> JUL-31-1994
<CASH> 20,293
<SECURITIES> 0
<RECEIVABLES> 155,135
<ALLOWANCES> 2,753
<INVENTORY> 18,422
<CURRENT-ASSETS> 212,648
<PP&E> 2,196,366
<DEPRECIATION> 1,438,953
<TOTAL-ASSETS> 1,900,879
<CURRENT-LIABILITIES> 189,757
<BONDS> 928,593
<COMMON> 5,386
0
0
<OTHER-SE> 466,452
<TOTAL-LIABILITY-AND-EQUITY> 1,900,879
<SALES> 462,943
<TOTAL-REVENUES> 462,943
<CGS> 385,640
<TOTAL-COSTS> 385,640
<OTHER-EXPENSES> 23,865
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 20,322
<INCOME-PRETAX> 33,116
<INCOME-TAX> 11,297
<INCOME-CONTINUING> 21,819
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 21,819
<EPS-PRIMARY> .41
<EPS-DILUTED> .41
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
consolidated financial statements and related notes of Mitchell Energy &
Development Corp. and subsidiaries at October 31, 1994 and for the nine-month
period then ended and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> JAN-31-1995
<PERIOD-END> OCT-31-1994
<CASH> 13,669
<SECURITIES> 0
<RECEIVABLES> 140,605
<ALLOWANCES> 2,847
<INVENTORY> 24,612
<CURRENT-ASSETS> 201,888
<PP&E> 2,159,119
<DEPRECIATION> 1,419,417
<TOTAL-ASSETS> 1,878,346
<CURRENT-LIABILITIES> 173,193
<BONDS> 913,912
<COMMON> 5,386
0
0
<OTHER-SE> 474,799
<TOTAL-LIABILITY-AND-EQUITY> 1,878,346
<SALES> 670,597
<TOTAL-REVENUES> 670,597
<CGS> 548,137
<TOTAL-COSTS> 548,137
<OTHER-EXPENSES> 35,545
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 30,835
<INCOME-PRETAX> 56,330
<INCOME-TAX> 19,499
<INCOME-CONTINUING> 36,831
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 36,831
<EPS-PRIMARY> .70
<EPS-DILUTED> .70
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
consolidated financial statements and related notes of Mitchell Energy &
Development Corp. and subsidiaries at January 31, 1995 and for the year
then ended and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> JAN-31-1995
<PERIOD-END> JAN-31-1995
<CASH> $11,967
<SECURITIES> 0
<RECEIVABLES> 136,299
<ALLOWANCES> 2,304
<INVENTORY> 13,068
<CURRENT-ASSETS> 183,838
<PP&E> 2,116,076
<DEPRECIATION> 1,408,402
<TOTAL-ASSETS> 1,855,871
<CURRENT-LIABILITIES> 170,242
<BONDS> 894,962
<COMMON> 5,386
0
0
<OTHER-SE> 469,644
<TOTAL-LIABILITY-AND-EQUITY> 1,855,871
<SALES> 894,571
<TOTAL-REVENUES> 894,571
<CGS> 734,222
<TOTAL-COSTS> 734,222
<OTHER-EXPENSES> 48,632
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 41,166
<INCOME-PRETAX> 70,551
<INCOME-TAX> 24,737
<INCOME-CONTINUING> 45,814
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 45,814
<EPS-PRIMARY> .87
<EPS-DILUTED> .87
</TABLE>
<PAGE> 1
Exhibit 99(a)
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, 1995
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.
<PAGE> 1
Exhibit 99(b)
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, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-6959
_______________________
MND HOSPITALITY, INC.
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 MND Hospitality, Inc., 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.
