<PAGE> 1
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTER ENDED APRIL 30, 1999
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 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
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months, and (2) has been subject to such filing requirements
for the past 90 days. Yes [X] No [ ]
<TABLE>
Shares of common stock outstanding at May 31, 1999:
<S> <C>
Class A......................... 22,321,635
Class B......................... 26,795,622
</TABLE>
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<PAGE> 2
INDEX
<TABLE>
<CAPTION>
Page
Part I - Financial Information Number
------
<S> <C>
Item 1. Financial Statements
Representation............................................................................... 1
Consolidated Balance Sheets.................................................................. 2
Unaudited Consolidated Statements of Earnings................................................ 3
Unaudited Consolidated Statement of Stockholders' Equity..................................... 4
Unaudited Condensed Consolidated Statements of Cash Flows.................................... 5
Notes to Unaudited Consolidated Financial Statements......................................... 6
Item 2. Management's Discussion and Analysis of
Financial Position and Results of Operations................................................. 12
Part II - Other Information
Item 1. Legal Proceedings...................................................................... 18
Item 6. Exhibits and Reports on Form 8-K....................................................... 18
</TABLE>
DEFINITIONS. As used herein, "MMBtu" means million British thermal units, "Mcf"
means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion
cubic feet, "Bbl" means barrel, "MMBbls" means million barrels, "NGL" or "NGLs"
means natural gas liquids, "fiscal 1999" and "fiscal 2000" refer, respectively,
to the 12-month periods ended January 31, 1999 and 2000 and "DD&A" means
depreciation, depletion and amortization. Pipeline throughput volumes are based
on average energy content of 1,000 Btu per cubic foot. Where applicable, NGL
volume, price and reserve information includes equity partnership interests.
<PAGE> 3
Part I - Financial Information
ITEM 1. FINANCIAL STATEMENTS
REPRESENTATION. The consolidated financial statements of Mitchell Energy &
Development Corp. and subsidiaries (the "Company") and related notes included
herein have been prepared by the Company, without audit, pursuant to the rules
and regulations of the Securities and Exchange Commission. Certain information
and footnote disclosures normally included in financial statements prepared in
accordance with generally accepted accounting principles have been condensed or
omitted pursuant to those rules and regulations, although the Company believes
that the disclosures included herein are adequate to make the information
presented not misleading. In the opinion of the Company's management, all
adjustments - which include only normal and recurring adjustments - necessary
for a fair presentation of the financial position and results of operations for
the periods presented have been made. These financial statements should be read
in conjunction with the financial statements and the notes thereto included in
the Company's Fiscal 1999 Annual Report and with the Management's Discussion and
Analysis of Financial Position and Results of Operations sections of that and
this report.
-1-
<PAGE> 4
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollar amounts in thousands)
<TABLE>
<CAPTION>
APRIL 30, January 31,
1999 1999
------------ ------------
<S> <C> <C>
ASSETS (unaudited)
CURRENT ASSETS
Cash and cash equivalents...................................................... $ 13,932 $ 20,300
Trade receivables.............................................................. 39,150 34,078
Inventories.................................................................... 9,670 10,734
Income taxes receivable........................................................ 4,715 5,944
Other.......................................................................... 8,140 8,576
------------ ------------
Total current assets...................................................... 75,607 79,632
------------ ------------
PROPERTY, PLANT AND EQUIPMENT, at cost less accumulated depreciation,
depletion and amortization of $1,467,217 and $1,450,685
Exploration and production
Oil and gas properties....................................................... 679,556 683,946
Support equipment and facilities............................................. 15,486 16,253
Gas services (including investments in equity partnerships) (Note 3)
Natural gas processing....................................................... 102,624 102,761
Natural gas gathering........................................................ 138,860 145,488
Other........................................................................ 79,862 79,678
Corporate...................................................................... 5,123 5,612
------------ ------------
1,021,511 1,033,738
------------ ------------
LONG-TERM INVESTMENTS AND OTHER ASSETS......................................... 33,501 33,106
------------ ------------
$ 1,130,619 $ 1,146,476
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt (Note 4).................................. $ 100,000 $ 100,000
Oil and gas proceeds payable................................................... 63,738 68,658
Accounts payable............................................................... 30,799 32,868
Accrued liabilities............................................................ 33,842 40,269
------------ ------------
Total current liabilities................................................. 228,379 241,795
------------ ------------
LONG-TERM DEBT (Note 4)........................................................ 356,367 362,467
------------ ------------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes.......................................................... 133,206 130,069
Retirement obligations and other............................................... 88,438 87,371
------------ ------------
221,644 217,440
------------ ------------
COMMITMENTS AND CONTINGENCIES (Notes 3 and 6)
STOCKHOLDERS' EQUITY
Preferred stock, $.10 par value (authorized 10,000,000 shares; none issued)
Common stock, $.10 par value
(authorized 100,000,000 Class A and 100,000,000 Class B shares).............. 5,386 5,386
Additional paid-in capital..................................................... 143,636 143,636
Retained earnings.............................................................. 286,738 287,283
Other comprehensive loss....................................................... (7,381) (7,381)
Treasury stock, at cost........................................................ (104,150) (104,150)
------------ ------------
324,229 324,774
------------ ------------
$ 1,130,619 $ 1,146,476
============ ============
</TABLE>
- ------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
-2-
<PAGE> 5
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF EARNINGS
(in thousands except per-share amounts)
<TABLE>
<CAPTION>
Three Months Ended
April 30
------------------------
1999 1998
--------- ---------
<S> <C> <C>
REVENUES
Exploration and production ......................................... $ 46,749 $ 58,996
Gas services ....................................................... 113,207 113,396
--------- ---------
159,956 172,392
--------- ---------
OPERATING COSTS AND EXPENSES
Exploration and production, net of water well
litigation provision reversals of $9,000 and $3,000 (Note 6) .... 35,439 54,388
Gas services ....................................................... 101,712 100,561
--------- ---------
137,151 154,949
--------- ---------
SEGMENT OPERATING EARNINGS (Note 7) ................................ 22,805 17,443
General and administrative expense ................................. 6,269 8,205
--------- ---------
TOTAL OPERATING EARNINGS ........................................... 16,536 9,238
--------- ---------
OTHER EXPENSE
Interest expense ................................................... 9,039 7,649
Interest income .................................................... (40) (618)
Other, net ......................................................... (1,566) (1,414)
--------- ---------
7,433 5,617
--------- ---------
EARNINGS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES ............ 9,103 3,621
INCOME TAXES (Note 5) .............................................. 3,419 1,326
--------- ---------
EARNINGS FROM CONTINUING OPERATIONS ................................ 5,684 2,295
DISCONTINUED REAL ESTATE OPERATIONS (Note 2)
Adjustment to loss on sale, net of income taxes of $1,750 .......... -- 3,250
--------- ---------
NET EARNINGS ....................................................... $ 5,684 $ 5,545
========= =========
BASIC AND DILUTED EARNINGS PER SHARE (Note 9)
Class A - From continuing operations ............................... $ .11 $ .05
Net earnings ............................................. .11 .11
Class B - From continuing operations ............................... .12 .05
Net earnings ............................................. .12 .12
AVERAGE COMMON SHARES OUTSTANDING (Basic) - Class A ................ 22,322 22,321
Class B ................ 26,796 26,757
</TABLE>
- ------------------------------------------------
The accompanying notes are an integral part of these financial statements.
-3-
<PAGE> 6
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENT OF
STOCKHOLDERS' EQUITY
For the Three Months Ended April 30,1999
(dollar amounts in thousands)
<TABLE>
<CAPTION>
Other
Additional Compre-
Common Paid-in Retained hensive Treasury
DOLLAR AMOUNTS Total Stock Capital Earnings Loss Stock
- -------------- --------- --------- ---------- ----------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
BALANCE, JANUARY 31, 1999 ........................ $ 324,774 $ 5,386 $ 143,636 $ 287,283 $ (7,381) $(104,150)
Net earnings ..................................... 5,684 -- -- 5,684 -- --
Cash dividends (12 cents per share on Class A
and 13.25 cents per share on Class B) ......... (6,229) -- -- (6,229) -- --
--------- --------- ---------- ----------- ---------- ---------
BALANCE, APRIL 30, 1999 .......................... $ 324,229 $ 5,386 $ 143,636 $ 286,738 $ (7,381) $(104,150)
========= ========= ========== =========== ========== ==========
</TABLE>
======================================
<TABLE>
<CAPTION>
Common Stock Issued Treasury Stock Outstanding Shares
------------------------ ------------------------ ------------------------
SHARE AMOUNTS Class A Class B Class A Class B Class A Class B
- ------------- ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
BALANCE, JANUARY 31, 1999 ..... 23,978,077 29,878,077 1,656,437 3,082,450 22,321,640 26,795,627
Other ......................... (3) (3) -- -- (3) (3)
---------- ---------- --------- --------- ---------- ----------
BALANCE, APRIL 30, 1999 ....... 23,978,074 29,878,074 1,656,437 3,082,450 22,321,637 26,795,624
========== ========== ========= ========= ========== ==========
</TABLE>
- ------------------------------
The accompanying notes are an integral part of these financial statements.
-4-
<PAGE> 7
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
Three Months Ended
April 30
------------------------
1999 1998
--------- ---------
<S> <C> <C>
OPERATING ACTIVITIES
Earnings from continuing operations ............................................ $ 5,684 $ 2,295
Adjustments to reconcile earnings from continuing
operations to cash provided by operating activities
Depreciation, depletion and amortization ................................. 27,732 28,325
Exploration expenses (including exploratory well impairments) ............ 2,298 11,415
Deferred income taxes .................................................... 3,137 (218)
Distributions in excess of earnings of equity investees .................. 4,420 4,821
Water well litigation provision reversals ................................ (9,000) (3,000)
Other, net ............................................................... (3,829) (1,387)
--------- ---------
30,442 42,251
Changes in operating assets and liabilities .............................. (1,199) (3,620)
--------- ---------
Cash provided by operating activities .................................... 29,243 38,631
--------- ---------
INVESTING ACTIVITIES
Capital and exploratory expenditures
Total on accrual basis (including asset acquisitions of $47,694 in 1998) .... (26,323) (113,817)
Adjustment to cash basis .................................................... (5,603) (9,162)
--------- ---------
(31,926) (122,979)
Property, plant and equipment sales proceeds ................................... 7,379 --
Other, net ..................................................................... 1,582 820
--------- ---------
Cash used for investing activities ....................................... (22,965) (122,159)
--------- ---------
FINANCING ACTIVITIES
Proceeds from issuance of debt ................................................. -- 12,000
Debt repayments ................................................................ (6,100) --
Cash dividends ................................................................. (6,229) (6,223)
Treasury stock purchases ....................................................... -- (9,217)
Other .......................................................................... (317) 2,698
--------- ---------
Cash used for financing activities ....................................... (12,646) (742)
--------- ---------
DECREASE IN CASH AND CASH EQUIVALENTS
FROM CONTINUING OPERATIONS .................................................. (6,368) (84,270)
CASH PROVIDED BY DISCONTINUED OPERATIONS ....................................... -- 5,506
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ................................. 20,300 105,309
--------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD ....................................... $ 13,932 $ 26,545
========= =========
</TABLE>
- --------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
-5-
<PAGE> 8
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
April 30, 1999
(1) ACCOUNTING POLICIES
Mitchell Energy & Development Corp. together with its majority-owned
subsidiaries (the "Company") is a large independent energy company engaged in
the exploration for and development and production of natural gas, natural gas
liquids, and crude oil and condensate. The Company also operates natural gas
gathering systems in Texas and markets natural gas through purchase and resale
activities.
The consolidated financial statements include the accounts of the Company
after elimination of all significant intercompany accounts and transactions. The
equity method of accounting is used for investments in 20%-to-50%-owned
entities.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosures of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
The Company's exploration and production activities are accounted for
using the "successful efforts" method. Long-lived assets held and used by the
Company are reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset may not be recoverable. When it is
determined that an asset's estimated future net cash flows will not be
sufficient to recover its carrying amount, an impairment charge is recorded to
reduce the carrying amount for that asset to its estimated fair value.
Impairment assessments for proved oil and gas properties are made on a
field-by-field basis. There were no charges for proved-property impairments
during the three-month periods ended April 30, 1999 and 1998.
The Financial Accounting Standards Board (FASB) adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," in June 1999. The statement requires that
all derivatives be recognized at fair value as assets or liabilities and that
changes in fair value be recorded in earnings or other comprehensive income. In
May 1999, the FASB proposed an amendment to SFAS No. 133 that would defer its
required adoption date by one year, to fiscal 2002 for the Company. While the
Company's analysis of the potential impact of this statement has not been
completed, its infrequent use of derivatives - particularly those which are not
hedges - makes it unlikely that the adoption of this statement will have a
significant impact on the Company's financial statements.
(2) DISCONTINUED REAL ESTATE OPERATIONS
The Company decided to withdraw from the real estate business during fiscal 1998
and commenced reporting real estate activities as discontinued operations in its
financial statements at that time. During the first quarter of fiscal 1999,
adjustments were recorded reducing by $3,250,000 ($5,000,000 pretax) the
$67,123,000 loss on disposition previously recorded in connection with the
discontinuance of those activities. The reduction occurred because actual
realizations were higher than originally estimated and certain contingent
obligations were settled for less than the amounts accrued.
-6-
<PAGE> 9
(3) PARTNERSHIP INVESTMENTS
A summary of the Company's net investments in partnerships at April 30, 1999 and
January 31, 1999 and its equity in their pretax earnings for the three-month
periods ended April 30, 1999 and 1998 follows (in thousands):
<TABLE>
<CAPTION>
Equity in
Net Investment Pretax Earnings
------------------------- ----------------------
Percent April 30, January 31, April 30, April 30,
Owned 1999 1999 1999 1998
-------- --------- ----------- --------- ---------
<S> <C> <C> <C> <C> <C>
NATURAL GAS PROCESSING
C&L Processors Partnership ........... 50 $ 59,193 $ 60,130 $ (723) $ 26
U.P. Bryan Plant ..................... 45 2,200 2,244 1,172 424
--------- ----------- --------- ---------
61,393 62,374 449 450
--------- ----------- --------- ---------
GAS GATHERING AND MARKETING
Austin Chalk Natural Gas
Marketing Services ................ 45 199 739 391 849
Ferguson-Burleson County
Gas Gathering System .............. 45 38,509 40,151 808 850
Louisiana Chalk Gathering System ..... 50 17,109 17,346 (237) (221)
Others ............................... 388 353 35 3,496*
--------- ----------- --------- ---------
56,205 58,589 997 4,974
--------- ----------- --------- ---------
OTHER
Belvieu Environmental Fuels .......... 33.33 48,397 47,660 737 1,552
Gulf Coast Fractionators ............. 38.75 29,838 30,364 667 1,444
--------- ----------- --------- ---------
78,235 78,024 1,404 2,996
--------- ----------- --------- ---------
$ 195,833 $ 198,987 $ 2,850 $ 8,420
========= =========== ========= =========
</TABLE>
- ----------------
*Includes $3,492 gain on a partnership's sale of the Brooks-Hidalgo gathering
system.
The Company's net investment in each of these entities is reported as property,
plant and equipment in the consolidated balance sheets and its equity in their
pretax earnings is reported as revenues in the consolidated statements of
earnings, each under the gas services caption.
The table which follows provides summarized earnings information (on a
100% basis) for these entities for the three-month periods ended April 30, 1999
and 1998 (in thousands):
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
Revenues ............................................................. $119,873 $131,749
Operating earnings ................................................... 14,287 12,982
Pretax earnings (before interest expense for those entities whose
activities are funded by capital contributions of the owners) .... 8,146 8,861
</TABLE>
(4) LONG-TERM DEBT
At April 30, 1999, the Company's outstanding debt consisted of $414,267,000 of
unsecured parent company senior notes, the proceeds of which have been advanced
to the operating subsidiaries, and borrowings of $35,000,000 under a
$250,000,000 bank revolving credit facility and $7,100,000 under an uncommitted
money market facility. Included in the senior notes is a $100,000,000 8% series
due July 15, 1999. The Company currently plans to fund the repayment of the
maturing notes by borrowing under its bank revolving credit agreement.
-7-
<PAGE> 10
Any amounts then outstanding under the bank revolving credit facility are
payable in July 2003. Interest rates, which generally are based on spreads over
LIBOR, vary based on the highest of the ratings given the Company's senior notes
by two specified rating agencies. The Company pays commitment fees on the unused
portion of this facility.
The bank revolving credit agreement contains certain restrictions which,
among other things, limit the payment of dividends by requiring consolidated
tangible net worth, as defined, to equal at least $275,000,000 and require the
maintenance of a specified consolidated leverage ratio based on earnings before
interest, taxes and DD&A and excluding extraordinary, unusual non-recurring and
non-cash charges and credits. Retained earnings available for the payment of
cash dividends totaled $47,024,000 at April 30, 1999.
(5) INCOME TAXES
Income taxes applicable to earnings from continuing operations for the
three-month periods ended April 30, 1999 and 1998 consist of the following (in
thousands):
<TABLE>
<CAPTION>
1999 1998
------- -------
<S> <C> <C>
Current - Federal.................. $ 232 $ 1,493
State.................... 50 51
------- -------
282 1,544
------- -------
Deferred - Federal................. 2,975 (132)
State................... 162 (86)
------- -------
3,137 (218)
------- -------
$ 3,419 $ 1,326
======= =======
</TABLE>
Estimated annual tax rates of 37.6% and 36.6%, respectively, were used in
computing the income tax provisions for the three-month periods ended April 30,
1999 and 1998. The differences between those rates and the 35% statutory Federal
income tax rate were principally the result of the interplay of the benefit of
Federal tax credits and the impact of state income taxes.
(6) COMMITMENTS AND CONTINGENCIES
NORTH TEXAS WATER WELL LITIGATION. On March 1, 1996, in a trial known as the
Bartlett case, a judgment was entered against a wholly owned subsidiary of the
Company by a Wise County, Texas court. The judgment awarded $4,051,760 in actual
damages (consisting of $339,266 for economic damages and $3,712,494 for pain,
mental anguish, inconvenience, etc.) and $200,000,000 in exemplary damages to
eight plaintiff groups, who claimed that the natural gas operations of the
subsidiary had affected their water wells.
The Company appealed this judgment to the Second Court of Appeals in Fort
Worth, Texas, and in November 1997 the court's three-judge panel unanimously
reversed the previous decision, finding that the plaintiffs failed to prove that
the Company's actions were the cause of their alleged damages and that the
claims of most plaintiffs were time-barred by statutes of limitations. The
appeals court subsequently denied the plaintiffs' request for a reconsideration
of its decision. Plaintiffs' requests that the Texas Supreme Court review and
overturn this decision were subsequently denied, and this case is now over.
In May 1997, in the Bailey case - which involved allegations similar to
those in the Bartlett case another jury in the Wise County court found
unanimously on all counts that the Company was not responsible for damages
claimed by 17 other plaintiff groups (and that most of their claims were
time-barred by statutes of limitations, in any event). The court entered the
judgment on July 15, 1997. After their motion for a new trial was denied, the
plaintiffs appealed this decision to the Second Court of Appeals, which affirmed
the trial court's decision on February 25, 1999. After their motion for a
rehearing was overruled by the Court of Appeals, the plaintiffs filed a petition
for review with the Supreme Court of Texas on May 21, 1999. That court is
expected to deny the request.
-8-
<PAGE> 11
In three other cases involving allegations similar to those in the
Bartlett case, judges in the Wise County court issued summary judgments in favor
of the Company during January, April and July 1998. The plaintiffs appealed two
of these judgments to the Second Court of Appeals, which affirmed the trial
court's judgment in one of these cases on November 19, 1998 and in the other on
January 7, 1999. After their petitions for review of these decisions by the
Texas Supreme Court were denied, the plaintiffs filed motions for rehearing on
May 7, 1999 with that court which are expected to be denied.
This litigation now has run its course except for the plaintiffs'
outstanding motions with the Texas Supreme Court in the three cases discussed
above.
The Company believes that a number of its insurance carriers have
responsibilities for participating in the defense costs incurred by the Company
in connection with this litigation. Reimbursement agreements have been entered
into with five of these carriers: one in May 1997, two in April 1998, and two in
March 1999. Negotiations continue with additional carriers regarding their
participation.
The Company reviews the adequacy of its accrued liability for this
litigation at least quarterly, and provisions totaling $32,000,000 were expensed
over the years. Costs incurred - which consisted principally of attorneys' fees
and other defense costs for the Bartlett and Bailey trials and costs of bonds,
etc., related to the appeal of the Bartlett judgment - were charged against the
reserve. Insurance reimbursements are included in the determination of the
adequacy of the accrued liability only after reimbursement agreements have been
executed. After entering into the two reimbursement agreements in April 1998 and
after agreeing in August 1998 to settle the last 25 untried cases, the Company
recorded reversals of the previous provisions of $3,000,000 and $1,000,000,
respectively, in the first and second quarters of fiscal 1999. After entering
into the two reimbursement agreements during March 1999, a $9,000,000 reversal
was recorded in the first quarter of fiscal 2000.
OTHER. The Company also is party to other claims and legal actions arising in
the ordinary course of its business and to recurring examinations performed by
the Internal Revenue Service and other regulatory agencies. While the outcome of
all such matters cannot be predicted with certainty, management expects that
losses, if any, resulting from the ultimate resolution of the matters discussed
in this and the preceding paragraphs of this footnote will not result in charges
that are material to the Company's financial position. It is possible, however,
that charges could be required that would be significant to the operating
results of a particular period.
The Company holds a one-third interest in a partnership which owns a plant
that manufactures a gasoline additive known as MTBE. The EPA has formed a
national advisory panel to review public health and environmental issues that
have been raised by the use of MTBE in gasoline, specifically the discovery of
MTBE in water supplies. That panel is expected to make recommendations to the
EPA in mid- 1999. Also, several states have commenced reviews of the use of MTBE
in gasoline, and in March 1999 the governor of California ordered that the use
of MTBE be phased out in that state over a four-year period. Restrictions on the
use of MTBE could significantly impact future operations of the MTBE plant
partially owned by the Company. However, that facility, which was built for
approximately $225,000,000, was originally designed in a manner that allows it -
with moderate expenditures - to be converted to the production of other
products. It is not possible at this time to determine the ultimate impact, if
any, of this matter on the Company's financial position or future results of
operations.
-9-
<PAGE> 12
(7) SEGMENT INFORMATION
Selected industry segment data for the indicated periods follows (in thousands):
<TABLE>
<CAPTION>
Inter- Segment Total Capital
Outside segment Operating Operating Expendi-
Revenues Revenues Earnings Earnings DD&A tures(a)
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
THREE MONTHS ENDED APRIL 30, 1999
EXPLORATION AND PRODUCTION
Operations ........................................... $ 46,749 $ -- $ 2,310 $ (257) $ 23,626 $ 21,152
Water well litigation provision reversal (Note 6) .... -- -- 9,000 9,000 -- --
--------- --------- --------- --------- --------- ---------
46,749 -- 11,310 8,743 23,626 21,152
--------- --------- --------- --------- --------- ---------
GAS SERVICES
Natural gas processing ............................... 61,169 16,381 3,896 3,206 925 2,058
Natural gas gathering and marketing .................. 50,634 42,338 6,392 5,608 2,562 2,935
Other ................................................ 1,404 -- 1,207 1,127 27 71
--------- --------- --------- --------- --------- ---------
113,207 58,719 11,495 9,941 3,514 5,064
--------- --------- --------- --------- --------- ---------
CORPORATE ............................................ -- -- -- (2,148)(b) 592 107
--------- --------- --------- --------- --------- ---------
$ 159,956 $ 58,719 $ 22,805 $ 16,536 $ 27,732 $ 26,323
========= ========= ========= ========= ========= =========
THREE MONTHS ENDED APRIL 30, 1998
EXPLORATION AND PRODUCTION
Operations ........................................... $ 58,996 $ -- $ 1,608 $ (1,362) $ 23,735 $ 90,875
Water well litigation provision reversal (Note 6) .... -- -- 3,000 3,000 -- --
--------- --------- --------- --------- --------- ---------
58,996 -- 4,608 1,638 23,735 90,875
--------- --------- --------- --------- --------- ---------
GAS SERVICES
Natural gas processing ............................... 67,658 21,023 935 100 961 14,460
Natural gas gathering and marketing .................. 42,742 58,497 9,210 8,223 2,893 8,093
Other ................................................ 2,996 -- 2,690 2,581 27 134
--------- --------- --------- --------- --------- ---------
113,396 79,520 12,835 10,904 3,881 22,687
--------- --------- --------- --------- --------- ---------
CORPORATE ............................................ -- -- -- (3,304)(b) 709 255
--------- --------- --------- --------- --------- ---------
$ 172,392 $ 79,520 $ 17,443 $ 9,238 $ 28,325 $ 113,817
========= ========= ========= ========= ========= =========
</TABLE>
- -------------------------------------------
(a) On accrual basis, including exploratory expenses and acquisitions.
(b) General corporate expenses.
The Company's reported business segments are based on the organizational
structure used by management to assess performance and make resource allocation
decisions. The Company's three principal business segments are: exploration and
production, natural gas processing, and gas gathering and marketing. Exploration
and production segment operations include the exploration for and development
and production of natural gas and oil. Natural gas processing segment operations
include the extraction of natural gas liquids from natural gas processed at
Company- and partnership-owned processing facilities. The gas gathering and
marketing segment operates Company- and partnership-owned natural gas gathering
systems and markets natural gas through purchase and resale transactions.
(8) SUPPLEMENTAL CASH FLOW INFORMATION
Interest paid totaled $9,225,000 and $8,438,000 during the three-month periods
ended April 30, 1999 and 1998. Income tax refunds totaling $1,335,000 were
collected during the three-month period ended April 30, 1999; income taxes paid
during the comparable prior-year period totaled $3,554,000. There were no
significant non-cash investing or financing activities during the three-month
periods ended April 30, 1999 and 1998.
-10-
<PAGE> 13
(9) EARNINGS PER SHARE
The Company is required to make separate per-share computations for its Class A
and Class B common stock since the shares are not convertible into each other
and different per share cash dividends are paid on the separate classes. In
these computations, differences between earnings from continuing operations and
total dividends paid are apportioned between the classes on a pro rata per-share
basis and then added to the respective dividends paid to each class of common
stock. Accordingly, the differences in the per-share earnings amounts for Class
A and Class B shares occur because of the dividend premium on the Class B
shares. The following table sets forth basic and diluted earnings per share
information for the three-month periods ended April 30, 1999 and 1998.
<TABLE>
<CAPTION>
1999 1998
--------------------- ---------------------
Class A Class B Class A Class B
-------- -------- -------- --------
<S> <C> <C> <C> <C>
From continuing operations ........................ $ .11 $ .12 $ .05 $ .05
Discontinued real estate operations -
Adjustment to loss on sale .................... -- -- .06 .07
-------- -------- -------- --------
Net earnings ...................................... $ .11 $ .12 $ .11 $ .12
========= ======== ======== ========
</TABLE>
The basic and diluted per-share amounts were the same because the earnings
amounts for the diluted computations were no different than the ones used in the
basic computations, and - as shown in the table below - the dilutive effect of
stock options did not significantly increase the weighted average shares
outstanding. The following table reconciles the weighted average shares
outstanding used in the basic and diluted earnings per-share computations for
the three-month periods ended April 30, 1999 and 1998 (in thousands):
<TABLE>
<CAPTION>
1999 1998
--------------------- ---------------------
Class A Class B Class A Class B
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Used in basic computations............................. 22,322 26,796 22,321 26,757
Dilutive effect of stock options....................... - 20 18 383
-------- -------- -------- --------
Used in diluted computations........................... 22,322 26,816 22,339 27,140
======== ======== ======== ========
</TABLE>
Stock options covering 78,258 Class A and 1,678,735 Class B shares were excluded
from these computations for the period ended April 30, 1999, because their
effect would have been antidilutive; there were no antidilutive stock options
for the period ended April 30, 1998.
-11-
<PAGE> 14
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
POSITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING INFORMATION
All statements included in this Form 10-Q, other than statements of historical
fact, are forward-looking statements. These include, but are not limited to,
strategies, goals and expectations set forth herein concerning exploration and
production and gas services operations and the discussions below concerning the
Company's liquidity and capital resources. Although the Company believes that
its expectations are based on reasonable assumptions, it can give no assurances
that its goals will be achieved. Important factors that could cause actual
results to differ materially from those in the forward-looking statements
include the timing and extent of changes in commodity prices for natural gas,
NGLs and crude oil; the attainment of forecasted operating levels and reserve
replacement; Year 2000 non-readiness of third parties of business importance to
the Company; and unexpected changes in competitive and economic conditions,
government regulations, technology and other factors.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW. A downward trend in energy prices was the primary driver affecting the
Company's financial results in fiscal 1999. This trend began reversing during
fiscal 2000's first quarter. The following table shows the Company's average
sales prices for the first quarter of fiscal 2000 and the prior three fiscal
years:
<TABLE>
<CAPTION>
Crude Oil and
Natural Gas (per Mcf) Condensate (per Bbl) NGLs (per Bbl)
------------------------------ ------------------------------- --------------------------------
2000 1999 1998 1997 2000 1999 1998 1997 2000 1999 1998 1997
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
First quarter.... $1.84 $2.29 $2.23 $2.27 $12.56 $13.93 $19.99 $19.45 $10.68 $11.44 $13.46 $14.15
Second quarter... 2.25 2.24 2.40 12.33 18.48 20.28 10.22 12.76 13.62
Third quarter.... 1.90 2.66 2.21 12.22 18.89 22.62 9.79 14.33 16.55
Fourth quarter... 1.99 2.71 3.65 10.25 17.02 23.39 9.27 12.93 19.97
Fiscal year...... 2.11 2.47 2.64 12.18 18.50 21.50 10.23 13.38 16.13
</TABLE>
During fiscal 1997's fourth quarter, prices rose to levels not seen in many
years. Then after remaining relatively stable in fiscal 1998, they fell
throughout fiscal 1999 to low points not seen for oil and NGLs since 1986. The
depressed NGL prices, coupled with the relatively higher natural gas prices,
caused the Company's normally very profitable gas processing activities to
report segment operating losses for the second, third and fourth quarters of
fiscal 1999. The depressed energy price environment led to fiscal 1999 fourth
quarter impairments of certain oil and gas proved properties - primarily oil
fields - and gas services assets.
The Company's activities have consisted exclusively of energy operations
since its sale of The Woodlands Corporation (TWC) in July 1997. While the
Company's operating plans are not generally modified in response to normal
volatility in energy prices, the downward price swings were so extreme in recent
periods that they could not be ignored. Accordingly, after using a substantial
portion of the TWC sales proceeds to grow its energy businesses early in fiscal
1999, the Company began to sharply curtail capital spending in the second half
of the year and to take steps to reduce operating costs, including a personnel
reduction program at year's end. These actions were taken to enhance the
Company's profitability and to bring its cash outflows more in line with its
price-dampened revenues and thereby mitigate the need for incremental borrowings
going forward.
The Company believes that it has positioned itself to operate in a
low-energy-price environment. Even with its reduced capital budget, the Company
expects to maintain its production volumes for natural gas and to replace the
reserves it will produce in fiscal 2000. The nature of the Company's gas and oil
properties allows it to quickly adjust its capital spending levels either upward
or downward. With its large backlog of 1,000 undrilled well locations, the
Company's drilling program can be quickly increased to add to its production
capabilities.
-12-
<PAGE> 15
Oil prices began to improve late in the first quarter because of announced
production cutbacks by several major oil producing countries, and NGL prices
followed them upward as expected. The Company's May 1999 average sales prices
for oil and NGLs were $15.29 and $12.52 per barrel, significantly above the
first quarter's averages of $12.56 and $10.68. Natural gas prices began moving
upward in April in response to production declines resulting from curtailed
drilling activity in last year's second half. If the more favorable pricing
environment holds - as current futures market prices indicate it will - the
Company's earnings and cash flows for the second quarter and the rest of the
year will be substantially above their first quarter levels.
CAPITAL AND EXPLORATORY EXPENDITURES. A comparison of the Company's fiscal 2000
budget for capital and exploratory expenditures and its actual first quarter
spending follows (in millions):
<TABLE>
<CAPTION>
First
Annual Quarter
Budget Spending
------ --------
<S> <C> <C>
Exploration and production........................ $112.4 $ 21.1
Gas services...................................... 21.0 5.1
Corporate......................................... 2.8 .1
------ --------
$136.2 $ 26.3
====== ========
</TABLE>
The Company's fiscal 2000 budget was set at $136.2 million, 32% below the
$200.1 million spent in the prior year and roughly in line with the reduced
spending pace adopted for fiscal 1999's last half. Of the exploration and
production budget, approximately $75 million is planned for drilling primarily
low-risk gas development wells. The gas services planned spending is limited
almost exclusively to new well connections to maintain pipeline throughput and
gathering system and processing plant improvement projects.
First quarter capital spending was intentionally restrained to keep the
Company's cash outflows in line with its inflows. However, in response to
improving prices, another rig is being added in July to increase drilling in the
North Texas area, and it is expected over the full year that the originally
budgeted expenditures will be made. Further - as it normally does - the Company
will review its capital spending plans at mid-year. If the improved environment
for energy prices continues, the budget likely will be increased at that time to
cover the addition of another rig or two in the second half.
FINANCING MATTERS. The parent company has a $250 million bank revolving credit
facility and a $25 million bank money-market facility. Borrowings of $42.1
million were outstanding under these credit facilities at April 30, 1999. The
Company funded its first quarter liquidity needs using cash inflows from
operations and reduced its outstanding debt by $6.1 million. It intends at least
in the near term to conduct its business in a similar manner.
Of the Company's outstanding debt, $100 million of 8% senior notes mature
on July 15, 1999. The Company has tentatively concluded that repayment of the
maturing senior notes will be funded by borrowing under the bank revolving
credit agreement. Since long-term interest rate spreads for energy independents
are not attractive currently, this alternative is considerably less expensive
than the sale of $100 million of senior notes. Also, $100 million is a
relatively small size for a public note offering. The Company expects at a more
appropriate time that it will issue additional senior notes to pay down its bank
credit agreement borrowings.
NORTH TEXAS WATER WELL LITIGATION. See Note 6 of Notes to Unaudited Consolidated
Financial Statements for information concerning this litigation and recoveries
of defense costs under agreements with the Company's insurance carriers.
Reimbursement agreements were reached with two additional carriers late in March
1999, which led to the recording of a $9 million provision reversal in April
1999. While negotiations continue with other carriers, the timing for
completing any additional reimbursement agreements is currently uncertain.
-13-
<PAGE> 16
DISCLOSURES ABOUT MARKET RISK. The Company's major market risk exposure involves
prices for crude oil, natural gas and NGLs. Realized prices for these products
are driven primarily by prevailing world crude oil and domestic natural gas
markets. Such markets historically have been volatile (see the table on page 12,
for example), and this is expected to continue. In general, a $1.00 change in
the per-barrel price of oil, together with an equivalent change in the prices
for natural gas and NGLs based on Btu content (16.7 cents for gas and 67 cents
for NGLs), changes the Company's annual segment operating earnings and cash
flows by approximately $23 million and its after-tax annual net earnings by
almost $15 million.
The Company has a "natural" hedge in that while it is a seller of natural
gas, it also purchases natural gas in connection with its gas processing
operations (such purchases equal approximately one-third of gas sales). Also, it
infrequently enters into hedging activities to manage certain exposures to price
fluctuations. The Company does not hold or issue derivative instruments for
trading purposes. It had no open hedging positions at April 30, 1999, and its
hedging activity during the last three years was not significant.
The Company's interest rate risk exposure is minimal since approximately
90% of its outstanding debt at April 30, 1999 consisted of senior notes with
fixed interest rates. Of these notes, $100 million mature in July 1999. As
mentioned above, these notes likely will be refunded using floating-rate debt.
YEAR 2000 ISSUE. Like others, the Company is facing computer systems problems
caused by the approaching turn of the century, which has been dubbed the "Year
2000 problem." In addition to affecting mainframe and mid-range computer
systems, this problem potentially impacts computer chips integrated into
security, plant automation and pipeline control systems. Beginning in late 1996,
the Company conducted a study to determine the Year 2000 readiness of its
mainframe and mid-range financial and operating systems and established a
timetable for reprogramming, replacing and testing these systems to see that
they properly recognize dates subsequent to December 31, 1999. The Company's
schedule, which calls for these efforts to be substantially completed by July
31, 1999, is currently being met. Since this work is being accomplished
principally by reallocating internal resources, this effort is not expected to
significantly impact the Company's results of operations or cash flows. Through
April 30, 1999, third party costs totaling $630,000 had been incurred in this
regard out of total estimated costs of $800,000.
During August 1998, the Company completed an inventory of embedded chips
integrated into its security, plant automation and pipeline control systems. As
part of this process, the Company ranked the facilities containing embedded
chips in order of importance and contacted equipment vendors to determine the
steps necessary to make the equipment in which they are installed capable of
operating properly after December 31, 1999. Testing of the facilities
categorized as important essentially has been completed, and needed upgrades are
scheduled to be completed by October 31, 1999. Third party costs generally are
not being incurred in connection with these efforts.
Through communications with industry partners and others, the Company is
also evaluating the risks presented by potential Year 2000 non-compliance of
third parties. Since such risks vary substantially, companies are being
contacted based on the estimated magnitude of the risk posed to the Company by
their potential Year 2000 non-readiness. The Company is currently not aware of
any situations where material disruptions of its business activities are likely
because of the Year 2000 non-readiness of third parties.
The timetable for the Company's planned completion of its own Year 2000
modifications and the estimated costs to accomplish this are management's best
estimates. These assessments involve many assumptions concerning future events,
including the continued availability of certain resources, particularly
personnel able to locate, reprogram or replace, and test the Company's hardware
and software in accordance with the Company's established schedule. There can be
no guarantee that the Company's estimates will prove accurate, and actual
results could differ significantly from the estimates. Finally, there can be no
guarantee that the Year 2000 non-readiness of third parties of business
importance to the Company will not adversely affect its operations in a future
period. Although it is not currently aware of any such situations, the Company
is developing contingency plans to alter business relationships in the event of
such non-readiness.
-14-
<PAGE> 17
OPERATING STATISTICS
Certain operating statistics (including proportional interests in equity
partnerships, where applicable) for the three-month periods ended April 30, 1999
and 1998 follow:
<TABLE>
<CAPTION>
1999 1998
---------- ----------
<S> <C> <C>
AVERAGE DAILY VOLUMES
Natural gas sales (Mcf)..................................... 243,900 246,400
Crude oil and condensate sales (Bbls)....................... 6,100 6,900
Natural gas liquids produced (Bbls)......................... 42,100 45,500
Pipeline throughput (Mcf) .................................. 505,000 542,000
AVERAGE SALES PRICES
Natural gas (per Mcf)....................................... $ 1.84 $ 2.29
Crude oil and condensate (per Bbl).......................... 12.56 13.93
Natural gas liquids produced (per Bbl)...................... 10.68 11.44
</TABLE>
EARNINGS FROM CONTINUING OPERATIONS - THREE MONTHS ENDED APRIL 30, 1999
COMPARED WITH THREE MONTHS ENDED APRIL 30, 1998
Earnings from continuing operations for the three-month period ended April 30,
1999 - both before and after unusual items - are summarized in the table on the
following page. Earnings from continuing operations for fiscal 2000's first
quarter of $5.7 million were above the prior-year period's $2.3 million largely
because of the recording of a larger reversal of previous water well litigation
provisions ($9 million versus $3 million). Excluding the effects of unusual
items in both years, first quarter earnings totaled $.1 million, versus $.4
million in the prior-year's comparable period. These amounts were essentially
unchanged because Company-implemented cost reductions were sufficient to offset
the impact of period-to-period declines in energy prices and average daily sales
volumes.
-15-
<PAGE> 18
The following table and discussion identify and explain the major
increases (decreases) in earnings from continuing operations for the three-month
periods (in millions):
<TABLE>
<CAPTION>
Segment Earnings from Con-
Operating Earnings tinuing Operations
---------------------- ------------------
Exploration Before
and Gas Income After
Production Services Other* Taxes Tax
---------- -------- ------- ------ --------
<S> <C> <C> <C> <C> <C>
FISCAL 1999 AMOUNTS AFTER UNUSUAL ITEMS .................... $ 4.6 $ 12.8 $ (13.8) $ 3.6 $ 2.3
ELIMINATE IMPACT OF FISCAL 1999 UNUSUAL ITEM - Water
well litigation provision reversal (see page 8) ......... 3.0 -- -- 3.0 1.9
---------- -------- ------- ------ --------
FISCAL 1999 AMOUNTS BEFORE UNUSUAL ITEMS ................... 1.6 12.8 (13.8) .6 .4
---------- -------- ------- ------ --------
MAJOR INCREASES (DECREASES)
Lower natural gas sales price .............................. (8.6) -- -- (8.6) (5.6)
Lower geological and geophysical expenses .................. 9.5 -- -- 9.5 6.2
Lower natural gas sales volume ............................. (.9) -- -- (.9) (.6)
Lower oil and condensate sales price ....................... (.7) -- -- (.7) (.4)
Lower oil and condensate sales volume ...................... (.6) -- -- (.6) (.4)
Improved NGL margins ....................................... -- 1.9 -- 1.9 1.2
Gain from a partnership's fiscal 1999 sale
of the Brooks-Hidalgo gathering system .................. -- (3.5) -- (3.5) (2.3)
Personnel-reduction-related salary and benefits savings .... 1.2 1.3 .8 3.3 2.1
Performance unit expense accruals .......................... .5 .2 .3 1.0 .7
Interest expense incurred .................................. -- -- (1.4) (1.4) (.9)
Other, net ................................................. .3 (1.2) .4 (.5) (.3)
---------- -------- ------- ------ --------
.7 (1.3) .1 (.5) (.3)
---------- -------- ------- ------ --------
FISCAL 2000 AMOUNTS BEFORE UNUSUAL ITEMS ................... 2.3 11.5 (13.7) .1 .1
Water well litigation provision reversal (see page 8) ...... 9.0 -- -- 9.0 5.6
---------- -------- ------- ------ --------
FISCAL 2000 AMOUNTS AFTER UNUSUAL ITEMS .................... $ 11.3 $ 11.5 $ (13.7) $ 9.1 $ 5.7
========== ======== ======= ====== ========
</TABLE>
- ------------------------------------------
*Includes general and administrative expense and other expense.
EXPLORATION AND PRODUCTION OVERVIEW
Exclusive of unusual items, exploration and production segment operating
earnings of $2.3 million during fiscal 2000's first quarter were $.7 million
higher than those of the comparable prior-year period because the favorable
impact of lower geological and geophysical cost and operating expenses more than
offset the negative impact of lower prices and volumes.
LOWER NATURAL GAS SALES PRICE ($8.6 MILLION DECREASE). During the first quarter
of fiscal 2000, the Company's natural gas sales price averaged $1.84 per Mcf,
$.45 (20%) below the prior period's $2.29, reducing operating earnings by $8.6
million.
LOWER GEOLOGICAL AND GEOPHYSICAL EXPENSES ($9.5 MILLION INCREASE). During the
first quarter of fiscal 2000, geological and geophysical expenses totaled $1.5
million versus $11.0 million during the comparable prior-year period, improving
operating earnings by $9.5 million. During the prior year's first quarter, the
Company expended 51% of its $21.6 million geological and geophysical expense
total for fiscal 1999. In contrast, the total fiscal 2000 budget for such
expenses is only $9.7 million.
-16-
<PAGE> 19
LOWER NATURAL GAS SALES VOLUME ($.9 MILLION DECREASE). Natural gas sales
averaged 243.9 MMcf per day during fiscal 1999's first quarter, marginally lower
than the 246.4 MMcf of the prior year's comparable period, reducing operating
earnings by $.9 million. As previously indicated, the Company expects that its
average natural gas production volume for the full year will approximate the
fiscal 1999 level.
LOWER OIL AND CONDENSATE PRICE ($.7 MILLION DECREASE). The Company's sales price
for oil and condensate averaged $12.56 per barrel during fiscal 1999's first
three months, down from the prior period's $13.93, reducing operating earnings
by $.7 million. Oil prices improved late in the recent quarter, and the
Company's sales price averaged $15.03 during April 1999.
LOWER OIL AND CONDENSATE SALES VOLUME ($.6 MILLION DECREASE). First quarter
production of oil and condensate declined 800 barrels per day (12%) to 6,100,
reducing operating earnings by $.6 million. Production fell primarily because
the Company curtailed the drilling of oil wells beginning in the last half of
fiscal 1999 in response to extremely low prices for crude oil.
GAS SERVICES OVERVIEW
Gas services operating earnings declined $1.3 million (to $11.5 million) during
the first three months of fiscal 2000. This occurred largely because there was
not an item in the current period similar to the prior year's $3.5 million gain
from a partnership's sale of the Brooks-Hidalgo gathering system. NGL production
averaged 42,100 barrels per day in the fiscal 2000 period, down from 45,500 in
the comparable prior-year period.
HIGHER NGL MARGINS ($1.9 MILLION INCREASE). The average price for NGLs produced
during fiscal 2000's first quarter of $10.68 per barrel was 7% below the
prior-year period's $11.44, reducing NGL revenues by $3.0 million. Because of
the impact of the period's lower NGL and natural gas prices on producer
payments, feedstock costs also fell, reducing production costs by $4.9 million
and resulting in a net margin improvement of $1.9 million.
OTHER
PERSONNEL-REDUCTION-RELATED SALARY AND BENEFIT SAVINGS ($3.3 MILLION INCREASE).
These savings resulted from the personnel reduction program implemented during
fiscal 1999's fourth quarter. Primarily because some of the reductions did not
occur until early in fiscal 2000, the year-to-year expense reductions will not
exactly equal the $17 million annualized savings that resulted from the actions
taken by the Company.
PERFORMANCE UNIT EXPENSE ACCRUALS ($1.0 MILLION INCREASE). In December 1997, the
Company awarded performance units to mid-level managerial and professional
employees. Holders of these units on March 31, 1999 received cash compensation
equal to the closing price of the Company's Class B common stock on that date
times the number of units awarded them. Compensation expense accruals - which
totaled $.4 million during fiscal 2000's first quarter - were $1.0 million less
than the accruals during the prior-year period.
INTEREST EXPENSE INCURRED ($1.4 MILLION DECREASE). Interest expense incurred
rose $1.4 million during the first quarter of fiscal 2000 due to an increase in
the average debt balance and the fees attributable to an ongoing program to
securitize accounts receivable that was begun in fiscal 1999's fourth quarter.
-17-
<PAGE> 20
Part II - Other Information
ITEM 1. LEGAL PROCEEDINGS
See Note 6 of Notes to Unaudited Consolidated Financial Statements.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
No exhibits are filed with this report.
(b) No reports were filed on Form 8-K during the three-month period ended
April 30, 1999.
-18-
<PAGE> 21
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
MITCHELL ENERGY & DEVELOPMENT CORP.
-----------------------------------
(Registrant)
Dated: June 14, 1999 By: /s/ Philip S. Smith
-------------------------------
Philip S. Smith
Senior Vice President - Administration
and Chief Financial Officer
-19-
<PAGE> 22
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
27 Financial Data Schedule
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> JAN-31-2000
<PERIOD-END> APR-30-1999
<CASH> 13,932
<SECURITIES> 0
<RECEIVABLES> 39,468
<ALLOWANCES> 318
<INVENTORY> 9,670
<CURRENT-ASSETS> 75,607
<PP&E> 2,488,728
<DEPRECIATION> 1,467,217
<TOTAL-ASSETS> 1,130,619
<CURRENT-LIABILITIES> 228,379
<BONDS> 356,367
0
0
<COMMON> 5,386
<OTHER-SE> 318,843
<TOTAL-LIABILITY-AND-EQUITY> 1,130,619
<SALES> 159,956
<TOTAL-REVENUES> 159,956
<CGS> 0
<TOTAL-COSTS> 137,151
<OTHER-EXPENSES> 4,663
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 9,039
<INCOME-PRETAX> 9,103
<INCOME-TAX> 3,419
<INCOME-CONTINUING> 5,684
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 5,684
<EPS-BASIC> .11<F1>
<EPS-DILUTED> .11<F2>
<FN>
<F1>CLASS A BASIC .11
CLASS B BASIC .12
<F2>CLASS A DILUTED .11
CLASS B DILUTED .12
</FN>
</TABLE>
