<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 OCTOBER 31, 1998
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
--- ---
Shares of common stock outstanding at November 30, 1998:
Class A..................... 22,321,640
Class B..................... 26,795,627
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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............................................ 19
Item 6. Exhibits and Reports on Form 8-K............................. 19
</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 1998" and "fiscal 1999" refer, respectively,
to the 12-month periods ended January 31, 1998 and 1999 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 1998 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>
OCTOBER 31, January 31,
1998 1998
---------- ----------
<S> <C> <C>
ASSETS (unaudited)
CURRENT ASSETS
Cash and cash equivalents...................................................... $ 11,496 $ 105,309
Trade receivables.............................................................. 77,416 113,285
Inventories.................................................................... 14,911 14,479
Net assets of discontinued real estate operations (Note 2)..................... - 26,056
Other.......................................................................... 17,275 8,591
---------- ----------
Total current assets...................................................... 121,098 267,720
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, at cost less accumulated depreciation, depletion
and amortization of $1,398,808 and $1,331,139
Exploration and production
Oil and gas properties....................................................... 729,620 613,565
Support equipment and facilities............................................. 17,416 18,407
Gas services (including investments in equity partnerships) (Note 3)
Natural gas processing....................................................... 107,807 106,464
Natural gas gathering........................................................ 144,545 134,779
Other........................................................................ 78,434 73,689
Corporate...................................................................... 7,929 7,763
---------- ----------
1,085,751 954,667
---------- ----------
LONG-TERM INVESTMENTS AND OTHER ASSETS......................................... 31,183 29,586
---------- ----------
$1,238,032 $1,251,973
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt (Note 4).................................. $ 100,000 $ -
Oil and gas proceeds payable................................................... 66,330 94,661
Accounts payable............................................................... 36,465 55,119
Accrued liabilities............................................................ 43,812 48,969
---------- ----------
Total current liabilities................................................. 246,607 198,749
---------- ----------
LONG-TERM DEBT (Note 4)........................................................ 389,267 414,267
---------- ----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes.......................................................... 160,907 167,903
Retirement obligations and other............................................... 55,932 58,128
---------- ----------
216,839 226,031
---------- ----------
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..................................................... 143,299 143,525
Retained earnings.............................................................. 340,805 361,905
Treasury stock, at cost........................................................ (104,171) (97,890)
---------- ----------
385,319 412,926
---------- ----------
$1,238,032 $1,251,973
========== ==========
</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 Nine Months
Ended October 31 Ended October 31
------------------------ -------------------------
1998 1997 1998 1997
---------- ---------- ---------- --------
<S> <C> <C> <C> <C>
REVENUES
Exploration and production.................................... $ 51,718 $ 71,105 $ 169,635 $189,075
Gas services.................................................. 123,616 153,020 358,806 380,383
---------- ---------- ---------- --------
175,334 224,125 528,441 569,458
---------- ---------- ---------- --------
OPERATING COSTS AND EXPENSES
Exploration and production, including water
well litigation provision (reversals) of $(4,000)
and $7,000 in the nine-month periods (Note 6).............. 50,759 51,449 160,854 148,570
Gas services, including royalty litigation settlement pro-
vision of $26,000 in 1997's nine-month period (Note 8)..... 114,980 133,991 332,661 356,915
---------- ---------- ---------- --------
165,739 185,440 493,515 505,485
---------- ---------- ---------- --------
SEGMENT OPERATING EARNINGS (Note 8)........................... 9,595 38,685 34,926 63,973
General and administrative expense............................ 7,493 7,888 23,311 22,906
---------- ---------- ---------- --------
TOTAL OPERATING EARNINGS ..................................... 2,102 30,797 11,615 41,067
---------- ---------- ---------- --------
OTHER EXPENSE
Interest expense, excluding $15,112 attributable to
discontinued operations in the 1997 nine-month period...... 9,336 10,253 25,495 19,534
Interest income............................................... (100) (5,139) (836) (6,448)
Other, net.................................................... (834) (1,832) (3,495) (3,627)
---------- ---------- ---------- --------
8,402 3,282 21,164 9,459
---------- ---------- ---------- --------
EARNINGS (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES ............................ (6,300) 27,515 (9,549) 31,608
INCOME TAXES (Note 5) ........................................ (2,584) 9,780 (3,880) 10,613
---------- ---------- ---------- --------
EARNINGS (LOSS) FROM CONTINUING OPERATIONS ................... (3,716) 17,735 (5,669) 20,995
---------- ---------- ---------- --------
DISCONTINUED REAL ESTATE OPERATIONS (Note 2)
Earnings from operations...................................... - - - 7,440
Loss on sale.................................................. - - 3,250 (67,123)
---------- ---------- ---------- --------
- - 3,250 (59,683)
---------- ---------- ---------- --------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM..................... (3,716) 17,735 (2,419) (38,688)
EXTRAORDINARY ITEM - EARLY RETIREMENT OF DEBT (Note 7)....... - (13,250) - (13,250)
---------- ---------- ---------- --------
NET EARNINGS (LOSS) .......................................... $ (3,716) $ 4,485 $ (2,419) $(51,938)
========== ========== ========== ========
BASIC AND DILUTED EARNINGS (LOSS) PER SHARE (Note 10)
Class A - From continuing operations.......................... $ (.08) $ .35 $ (.14) $ .39
Net earnings (loss)................................. (.08) .08 (.07) (1.03)
Class B - From continuing operations.......................... (.07) .36 (.10) .42
Net earnings (loss)................................. (.07) .09 (.03) (1.00)
AVERAGE COMMON SHARES OUTSTANDING (Basic) - Class A........... 22,321 22,437 22,321 22,847
Class B........... 26,794 27,506 26,781 28,362
</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 Nine Months Ended October 31,1998
(dollar amounts in thousands)
<TABLE>
<CAPTION>
Additional
Common Paid-in Retained Treasury
DOLLAR AMOUNTS Stock Capital Earnings Stock Total
- -------------- ------ -------- -------- --------- --------
<S> <C> <C> <C> <C> <C>
BALANCE, JANUARY 31, 1998 .............................. $5,386 $143,525 $361,905 $ (97,890) $412,926
Net earnings............................................ - - (2,419) - (2,419)
Cash dividends (36 cents per share on
Class A and 39 3/4 cents per share on Class B)....... - - (18,681) - (18,681)
Treasury stock purchases (including
$7,458 adjustment payment on fiscal
1998 accelerated stock purchase transaction) ........ - - - (9,217) (9,217)
Exercises of stock options.............................. - (226) - 2,936 2,710
------ -------- -------- --------- --------
BALANCE, OCTOBER 31, 1998 .............................. $5,386 $143,299 $340,805 $(104,171) $385,319
====== ======== ======== ========= ========
</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, 1998 ...... 23,978,081 29,878,081 1,656,937 3,153,817 22,321,144 26,724,264
Treasury stock purchases........ - - - 65,000 - (65,000)
Exercises of stock options...... - - - (135,867) - 135,867
Other........................... (4) (4) - - (4) (4)
---------- ---------- --------- --------- ---------- ----------
BALANCE, OCTOBER 31, 1998 ...... 23,978,077 29,878,077 1,656,937 3,082,950 22,321,140 26,795,127
========== ========== ========= ========= ========== ==========
</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>
Nine Months
Ended October 31
-----------------------
1998 1997
-------- --------
OPERATING ACTIVITIES
<S> <C> <C>
Earnings (loss) from continuing operations ..................................... $ (5,669) $ 20,995
Adjustments to reconcile earnings (loss) from continuing
operations to cash provided by operating activities
Depreciation, depletion and amortization ................................. 88,718 77,906
Exploration expenses, including exploratory well impairments ............. 23,308 12,422
Deferred income taxes .................................................... 1,107 8,620
Distributions in excess of earnings of equity investees .................. 10,859 38
Water well litigation provision (reversal) ............................... (4,000) 7,000
Royalty litigation settlement provision .................................. - 26,000
Gain from sale of contract drilling assets ............................... - (2,382)
Other, net ............................................................... (1,343) (3,032)
--------- ---------
112,980 147,567
Changes in operating assets and liabilities .............................. (8,311) 46,941
--------- ---------
Cash provided by operating activities .................................... 104,669 194,508
--------- ---------
INVESTING ACTIVITIES
Capital and exploratory expenditures
Total on accrual basis, including asset
acquisitions of $85,046 and $13,910 ...................................... (256,502) (172,234)
Adjustment to cash basis .................................................... (9,100) 908
--------- ---------
(265,602) (171,326)
Net proceeds from sale of The Woodlands Corporation ............................ - 480,994
Property, plant and equipment sales proceeds ................................... 2,326 6,689
Other .......................................................................... 2,508 3,361
--------- ---------
Cash provided by (used for) investing activities ......................... (260,768) 319,718
--------- ---------
FINANCING ACTIVITIES
Proceeds from issuance of debt ................................................. 135,000 -
Debt repayments ................................................................ (60,000) (285,733)
Cash dividends ................................................................. (18,681) (19,459)
Treasury stock purchases ....................................................... (9,217) (60,522)
Debt reacquisition premium ..................................................... - (18,510)
Other .......................................................................... 2,257 556
--------- ---------
Cash provided by (used for) financing activities ......................... 49,359 (383,668)
--------- ---------
INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS FROM CONTINUING OPERATIONS ...................................... (106,740) 130,558
CASH PROVIDED BY DISCONTINUED OPERATIONS ....................................... 12,927 630
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ................................. 105,309 75,825
--------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD ....................................... $ 11,496 $ 207,013
========= =========
</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
October 31, 1998
(1) ACCOUNTING POLICIES
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 equity method of accounting is used for investments in 20%-
to 50%-owned entities.
The Company's exploration and production activities are accounted for
using the "successful efforts" method. Impairment computations for proved oil
and gas properties are made on a field-by-field basis as conditions warrant.
There were no impairment charges during the periods ended October 31, 1998 and
1997.
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.
In June 1998, the Financial Accounting Standards Board adopted SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," which the
Company must adopt by fiscal 2001. 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. 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
On June 12, 1997, the Company entered into an agreement to sell its real estate
subsidiary, The Woodlands Corporation (TWC), to a partnership of Crescent Real
Estate Equities Company and Morgan Stanley Real Estate Fund II, L.P. for
$543,000,000 in cash. The transaction was subsequently closed on July 31, 1997.
In connection with the sale, the parent company forgave intercompany debt
payable to it by TWC. After adjustment for certain net additional amounts
received pursuant to the contract and deductions for income taxes and
transaction costs incurred by the Company in connection with the sale, net cash
proceeds totaled approximately $481,000,000.
The Company decided to withdraw from the real estate business upon
entering into the definitive agreement to sell TWC on June 12, 1997, and
commenced reporting real estate activities as discontinued operations in its
financial statements effective that date. The Company's financial statements
were revised to segregate the net assets associated with discontinued operations
and to separately report their results of operations. Prior-period financial
statements were restated similarly. Interest expense attributable to
discontinued operations was determined in the same manner that historically had
been used to allocate such costs to the Company's real estate operations. After
an income tax benefit of $25,878,000, a net loss of $67,123,000 was recorded in
connection with the discontinuance of the Company's real estate activities.
During the first quarter of fiscal 1999, adjustments were recorded
reducing the $67,123,000 loss on disposition previously recorded in connection
with the discontinuance of real estate operations by $3,250,000 ($5,000,000
pretax). This occurred because actual realizations were higher than originally
estimated and certain contingent obligations were settled for less than the
amounts accrued.
The Company ceased segregating discontinued operations during fiscal
1999's second quarter since the liquidation of the remaining real estate
properties had been substantially completed.
-6-
<PAGE> 9
(3) PARTNERSHIP INVESTMENTS
At October 31, 1998, the Company's principal partnership interests included the
following:
<TABLE>
<CAPTION>
Ownership
Percentage Nature of Operations
---------- --------------------
<S> <C> <C>
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
Louisiana Chalk Gathering System 50 Natural gas gathering
U. P. Bryan Plant 45 Natural gas processing
</TABLE>
The Company's net investment in each of these entities is reported as property,
plant and equipment in the consolidated balance sheets under the gas services
caption. The Company's equity in their pretax earnings is reported as revenues
in the consolidated statements of earnings under the gas services caption.
A summary of the Company's net investments in partnerships at October 31,
1998 and January 31, 1998 and its equity in their pretax earnings (losses) for
the nine-month periods ended October 31, 1998 and 1997 follows (in thousands):
<TABLE>
<CAPTION>
Equity in
Net Investment Pretax Earnings (Loss)
------------------------ ----------------------
October 31, January 31, October 31, October 31,
1998 1998 1998 1997
-------- -------- ------- -------
<S> <C> <C> <C> <C>
Austin Chalk Natural Gas Marketing Services.......... $ 806 $ 670 $ 2,881 $ 2,359
Belvieu Environmental Fuels.......................... 46,185 41,300 7,333 7,743
C&L Processors Partnership........................... 59,987 51,945 (217) 2,152
Ferguson-Burleson County Gas Gathering System........ 40,478 43,863 2,436 2,708
Gulf Coast Fractionators............................. 30,568 30,629 3,873 3,881
Louisiana Chalk Gathering System..................... 17,521 19,053 (551) (214)
U. P. Bryan Plant.................................... 4,996 6,738 900 3,171
Others............................................... 368 138 3,628* 29
-------- -------- ------- -------
$200,909 $194,336 $20,283 $21,829
======== ======== ======= =======
</TABLE>
- ------------------
* Consists principally of a $3,492 gain from the sale by a partnership of the
Brooks-Hidalgo gathering system.
The table which follows provides summarized earnings information (on a
100% basis) for entities accounted for on the equity method for the three- and
nine-month periods ended October 31, 1998 and 1997 (in thousands):
<TABLE>
<CAPTION>
Three Months Nine Months
---------------------- ---------------------
1998 1997 1998 1997
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Revenues............................................................... $146,577 $181,205 $420,769 $567,572
Operating earnings..................................................... 19,379 20,977 48,512 67,555
Pretax earnings (before interest expense for those entities whose
activities are funded by capital contributions of the owners)....... 15,974 16,756 36,383 53,776
</TABLE>
-7-
<PAGE> 10
(4) LONG-TERM DEBT
The Company's outstanding debt at October 31, 1998 consisted of $414,267,000 of
unsecured parent company senior notes, the proceeds of which have been advanced
to the operating subsidiaries, and $75,000,000 borrowed under the revolving
credit facility described in the following paragraph. Included in the senior
notes is a $100,000,000, 8% series due July 15, 1999. The Company has not
decided whether it will fund repayment of these maturing notes by selling
additional senior notes or by borrowing under its existing bank credit
agreement.
On July 29, 1998, the parent company entered into a five-year $250,000,000
bank revolving credit agreement, replacing a $150,000,000 facility of its
primary energy subsidiary. Any amounts then outstanding under the new agreement
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 new 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 $330,000,000 and require the maintenance of
a specified consolidated leverage ratio based on earnings before interest, taxes
and DD&A. Retained earnings available for the payment of cash dividends totaled
$53,229,000 at October 31, 1998.
(5) INCOME TAXES
Income taxes applicable to earnings from continuing operations for the
nine-month periods ended October 31, 1998 and 1997 consist of the following (in
thousands):
<TABLE>
<CAPTION>
1998 1997
-------- -------
<S> <C> <C>
Current - Federal .......... $ (4,974) $ 1,496
State ............ (13) 497
-------- -------
(4,987) 1,993
-------- -------
Deferred - Federal ......... 1,997 7,700
State ........... (890) 920
-------- -------
1,107 8,620
-------- -------
$ (3,880) $10,613
======== =======
</TABLE>
Estimated annual tax rates of 40.6% and 33.6%, respectively, were used in
computing the income tax provisions for the nine-month periods ended October 31,
1998 and 1997. The differences between those rates and the 35% statutory Federal
income tax rate were principally the result of the interplay of Federal
permanent differences 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.
-8-
<PAGE> 11
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. The appeal was
argued before the court on October 21, 1998, and a decision is expected early in
1999. This is the same court that earlier ruled favorably on the Company's
appeal of the Bartlett case.
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 on November 19, 1998
affirmed the trial court's judgment in one of these cases.
With the settlement in September 1998 of the last remaining 25 untried
lawsuits involving similar allegations, this litigation has run its course
except for the plaintiffs' outstanding appeals in the two 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 three of these carriers: one in May 1997 and two in April 1998.
Negotiations continue with additional carriers regarding their participation.
The Company reviews the adequacy of its accrued liability for this
litigation at least quarterly. Provisions totaling $32,000,000 have been
expensed over the years (including $7,000,000 in April 1997). After entering
into the two reimbursement agreements in April 1998 and after agreeing in August
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. Costs incurred - which have 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.
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 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.
(7) EXTRAORDINARY ITEM - EARLY RETIREMENT OF DEBT
During the third quarter of fiscal 1998, the Company repurchased $185,733,000
face amount of its 9.25% senior notes maturing January 15, 2002. In connection
with this early retirement of debt, an extraordinary charge of $13,250,000 was
recorded. Before an income tax benefit of $7,135,000, the costs associated with
this debt retirement consisted of $18,510,000 in reacquisition premiums,
$784,000 of tender offer costs and expenses and the write-off of $1,091,000 of
deferred debt placement costs applicable to the retired notes.
-9-
<PAGE> 12
(8) SEGMENT INFORMATION
Selected industry segment data for the nine- and three-month periods ended
October 31, 1998 and 1997 are as follows (in thousands):
<TABLE>
<CAPTION>
Segment Total
Outside Operating Operating
Revenues Earnings Earnings
------------------- ----------------- -------------------
1998 1997 1998 1997 1998 1997
-------- -------- -------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Nine Months
- -----------
EXPLORATION AND PRODUCTION
Operations........................ $169,635 $186,693 $ 4,781 $45,123 $(4,264) $36,354
Water well litigation (provision)
reversals (see Note 6).......... - - 4,000 (7,000) 4,000 (7,000)
Gain from sale of
contract drilling assets........ - 2,382 - 2,382 - 2,382
-------- -------- -------- ------- ------- -------
169,635 189,075 8,781 40,505 (264) 31,736
-------- -------- -------- ------- ------- -------
GAS SERVICES
Natural gas processing............ 186,745 234,960 (2,108) 24,147 (4,554) 21,877
Royalty litigation
settlement provision............ - - - (26,000) - (26,000)
Natural gas gathering
and marketing................... 160,855 134,299 17,916 15,223 15,013 12,432
Other............................. 11,206 11,124 10,337 10,098 10,036 9,811
-------- -------- -------- ------- ------- -------
358,806 380,383 26,145 23,468 20,495 18,120
-------- -------- -------- ------- ------- -------
CORPORATE......................... - - - - (8,616)(b) (8,789)(b)
-------- -------- -------- ------- ------- -------
$528,441 $569,458 $ 34,926 $63,973 $11,615 $41,067
======== ======== ======== ======= ======= =======
Three Months
- ------------
EXPLORATION AND PRODUCTION........ $ 51,718 $ 71,105 $ 959 $19,656 $(2,112) $16,723
-------- -------- -------- ------- ------- -------
GAS SERVICES
Natural gas processing............ 58,639 84,763 (539) 8,935 (1,367) 8,217
Natural gas gathering
and marketing................... 60,283 64,955 4,755 7,087 3,769 6,131
Other............................. 4,694 3,302 4,420 3,007 4,321 2,906
-------- -------- -------- ------- ------- -------
123,616 153,020 8,636 19,029 6,723 17,254
-------- -------- -------- ------- ------- -------
CORPORATE......................... - - - - (2,509)(b) (3,180)(b)
-------- -------- -------- ------- ------- -------
$175,334 $224,125 $ 9,595 $38,685 $ 2,102 $30,797
======== ======== ======== ======= ======= =======
<CAPTION>
Capital
DD&A Expenditures(a)
----------------- -----------------
1998 1997 1998 1997
------- -------- -------- --------
<S> <C> <C> <C> <C>
Nine Months
- -----------
EXPLORATION AND PRODUCTION
Operations........................ $75,287 $68,248 $215,893 $128,683
Water well litigation (provision)
reversals (see Note 6).......... - - - -
Gain from sale of
contract drilling assets........ - - - -
------- -------- -------- --------
75,287 68,248 215,893 128,683
------- -------- -------- --------
GAS SERVICES
Natural gas processing............ 2,977 2,773 19,060 9,542
Royalty litigation
settlement provision............ - - - -
Natural gas gathering
and marketing................... 8,231 4,515 18,374 30,587
Other............................. 80 80 1,061 57
------- -------- -------- --------
11,288 7,368 38,495 40,186
------- -------- -------- --------
CORPORATE......................... 2,143 2,290 2,114 3,365
------- -------- -------- --------
$88,718 $77,906 $256,502 $172,234
======= ======= ======== ========
Three Months
- ------------
EXPLORATION AND PRODUCTION........ $26,402 $24,241 $ 39,067 $ 51,566
------- -------- -------- --------
GAS SERVICES
Natural gas processing............ 1,014 956 1,970 6,772
Natural gas gathering
and marketing................... 2,426 1,742 4,012 8,346
Other............................. 27 27 461 20
------- -------- -------- --------
3,467 2,725 6,443 15,138
------- -------- -------- --------
CORPORATE......................... 714 635 810 956
------- -------- -------- --------
$30,583 $ 27,601 $ 46,320 $ 67,660
======= ======== ======== ========
</TABLE>
- -----------------------
(a) On accrual basis, including exploratory expenses.
(b) General corporate expenses.
In June 1997, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 131, "Disclosures about Segments of an
Enterprise and Related Information," which the Company must implement by the end
of fiscal 1999. The Company does not expect that the adoption of this statement
will require it to make material changes in the information heretofore disclosed
concerning its operating segments.
In July 1997, the Company recorded a $26,000,000 financial statement
provision for estimated costs to be incurred in connection with settlements of
litigation with certain of its North Texas royalty owners. In October 1997, a
$21,000,000 payment was made to settle class-action litigation brought on behalf
of these royalty owners. Payments totaling approximately $5,000,000 were later
made to royalty owners who chose not to participate in the class-action
litigation.
Effective April 1, 1997, the Company sold its remaining contract drilling
assets for $3,500,000. A gain of $2,382,000 was recorded on this transaction.
-10-
<PAGE> 13
(9) SUPPLEMENTAL CASH FLOW INFORMATION
Interest paid, including amounts applicable to discontinued operations, totaled
$24,804,000 and $38,057,000 during the nine-month periods ended October 31, 1998
and 1997. Income taxes paid during these periods, including amounts applicable
to discontinued operations, totaled $3,972,000 and $56,996,000. There were no
significant non-cash investing or financing activities during the nine-month
periods ended October 31, 1998 and 1997.
(10) EARNINGS (LOSS) PER SHARE
The earnings (loss) per share computations included herein have been made in
accordance with Statement of Financial Accounting Standards No. 128, which the
Company adopted during the fourth quarter of fiscal 1998; prior period amounts
were restated. 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, any excess or shortfall between earnings from
continuing operations and total dividends paid is 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 (loss) per share information for the three- and nine-month
periods ended October 31, 1998 and 1997.
<TABLE>
<CAPTION>
Three Months Nine Months
------------------------------------- ---------------------------------------
1998 1997 1998 1997
----------------- ----------------- ----------------- ------------------
Class A Class B Class A Class B Class A Class B Class A Class B
------- ------- ------- ------- ------- -------- -------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
From continuing operations......... $ (.08) $ (.07) $ .35 $ .36 $ (.14) $ (.10) $ .39 $ .42
------- ------- ------- ------- ------- ------- ------- -------
Discontinued real estate operations
Earnings from operations....... - - - - - - .15 .14
Loss on sale................... - - - - .07 .07 (1.31) (1.30)
------- ------- ------- ------- ------- ------- ------- -------
- - - - (.07) (.03) (1.16) (1.16)
------- ------- ------- ------- ------- ------- ------- -------
Extraordinary item................. - - (.27) (.27) - - (.26) (.26)
------- ------- ------- ------- ------- ------- ------- -------
Net earnings (loss)................ $ (.08) $ (.07) $ .08 $ .09 $ (.07) $ (.03) $ (1.03) $ (1.00)
======= ======= ======= ======= ======= ======= ======= =======
</TABLE>
The basic and diluted per-share amounts were the same because the earnings
(loss) 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 (loss) per-share computations
for the three- and nine-month periods ended October 31, 1998 and 1997 (in
thousands):
<TABLE>
<CAPTION>
Three Months Nine Months
------------------------------------- -------------------------------------
1998 1997 1998 1997
------- ------- ------- ------- ------- ------- ------- -------
Class A Class B Class A Class B Class A Class B Class A Class B
------- ------- ------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Used in basic computations......... 22,321 26,794 22,437 27,506 22,321 26,781 22,847 28,362
Dilutive effect of stock options... - - 15 342 - - 8 186
------ ------ ------ ------ ------ ------ ------ ------
Used in diluted computations....... 22,321 26,794 22,452 27,848 22,321 26,781 22,855 28,548
====== ====== ====== ====== ====== ====== ====== ======
</TABLE>
For the three- and nine-month periods ended October 31, 1998, stock options were
not considered in the diluted computations because their effect would have been
antidilutive.
-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-compliance 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. As previously reported, the Company discontinued its real estate
activities during fiscal 1998 and realized $481 million of after-tax proceeds
from the sale of The Woodlands Corporation (TWC). During the first quarter of
fiscal 1999, the Company essentially completed the disposition of the
discontinued operations by selling most of the remaining properties outside The
Woodlands.
A balanced plan was implemented to reinvest the TWC sales proceeds as
quickly as practical, consistent with the Company's objective of growing its
core energy businesses in a prudent manner. This reinvestment program was
completed during fiscal 1999's first quarter, and the following table summarizes
the uses of those proceeds (dollars in millions):
<TABLE>
<CAPTION>
Fiscal Fiscal
1999 1998 Total
----- ----- -----
<S> <C> <C> <C>
Acquisitions.......................................................... $64.7 $26.3 $ 91.0
Fiscal 1999 capital expenditures in excess of funds from operations .. 23.0 - 23.0
Accelerated fiscal 1998 capital spending
(primarily for oil and gas exploratory activities) ................. - 24.0 24.0
Common stock purchases
Accelerated buyback (700,000 Class A and 1,400,000 Class B shares) . 7.5 49.7 57.2
Open-market purchases (45,000 Class A and 884,200 Class B shares) .. 1.8 22.7 24.5
Repurchase of 9 1/4% senior notes (including
$19.3 for tender offer costs and expenses) ......................... - 205.0 205.0
Repayment of off-balance-sheet partnership indebtedness .............. - 43.8 43.8
December 1997 special common stock dividends
(24 cents on Class A and 26 1/2cents on Class B) ................... - 12.5 12.5
----- ------ ------
$97.0 $384.0 $481.0
===== ====== ======
</TABLE>
The fiscal 1998 amounts were discussed in the Company's Fiscal 1998 Annual
Report. The fiscal 1999 spending was directed almost exclusively towards
expanding the Company's core energy operations via acquisitions and a stepped-up
exploratory program.
After reinvesting the remaining proceeds from the TWC sale during fiscal
1999's first quarter, the Company began using borrowings under a bank credit
agreement to fund portions of its ongoing capital program. Outstanding debt rose
by $48 million and $15 million, respectively, during the second and third
quarters.
The parent company entered into a five-year $250 million bank revolving
credit agreement in July 1998, replacing a $150 million facility of a
subsidiary. During the second quarter of fiscal 1999, $100 million of the
Company's 8% senior notes maturing on July 15, 1999 were reclassified as a
current liability. The Company has not decided whether it will fund the
repayment of the maturing senior notes by selling additional senior notes or by
borrowing under its existing bank credit agreement.
-12-
<PAGE> 15
RECENT ENERGY PRICE TRENDS. As shown by the table on page 15, the Company's
average sales prices for energy products were sharply lower during fiscal 1999.
This was particularly true in the third quarter when the average prices for
natural gas, crude oil and condensate and NGLs were 28.6%, 35.3% and 31.7%,
respectively, below their prior-period levels. The lower prices were largely the
result of last winter's warm weather in the U.S. and resultant increases in
inventory levels, coupled with the effects on demand of an economic slowdown in
several areas of the world. The adverse impact of the lower prices was
particularly evident on NGL margins; as a result, segment operating losses were
reported by the Company's gas processing operations during the second and third
quarters. Prices for crude oil and NGLs have declined further early in December,
and mild weather conditions at the beginning of the winter heating season have
caused natural gas prices to be extremely volatile. With storage facilities
almost full, a continuation of moderate weather would likely push natural gas
prices downward. In any event, it is expected that low energy prices will
continue to negatively impact the Company's results in the fourth quarter and
beyond.
PLANNED SPENDING REDUCTIONS. In recent periods, the Company's plan has been to
invest heavily in its core properties to grow its energy businesses, and its
cash outflows for capital additions and dividends have exceeded its cash flows
from operations. Prior to fiscal 1999's second quarter, these shortfalls were
funded almost exclusively using proceeds from the TWC sale; during the second
and third quarters they were funded using bank credit agreement borrowings. Very
recently, it has become apparent that energy prices may remain at their recent
low levels for an extended period or even decline further. This has caused the
Company to change its business plan by taking actions to reduce its cash outlays
and thereby bring spending levels more in line with the reduced cash inflows.
The nature of the Company's properties makes it possible for its capital
spending levels to be quickly adjusted either upward or downward. As discussed
below, the Company took steps to lower its capital spending beginning in the
third quarter, and the lower activity level likely will be continued until the
energy price environment improves significantly.
The Company has been implementing steps to lower its outlays for
non-essential operating costs and expenses on an ongoing basis, including a
hiring freeze instituted during the third quarter. However, in the current
environment, additional steps are required. To reduce personnel costs, a 45-day
voluntary incentive retirement program (VIRP) window will be opened on December
15, 1998 for eligible employees. Employee layoffs will occur to further reduce
staffing levels. A fourth quarter financial statement provision likely will be
recorded for the costs of this program, including any related restructuring
charges. A substantial portion of the Company's costs for the VIRP will be
non-cash since they will be paid by the Company's well-funded qualified
retirement plan, by a Rabbi Trust for nonqualified retirement benefits or in the
future as incremental retiree medical benefits.
These planned spending reductions are part of a comprehensive program
designed to enhance the Company's profitability and cash flows during this
period of depressed energy prices. The overall objective is to balance cash
flows from operations with the Company's capital and other expenditures.
CAPITAL AND EXPLORATORY EXPENDITURES. Summary information concerning the
Company's fiscal 1999 capital and exploratory expenditures follows (in
millions):
<TABLE>
<CAPTION>
First Second
Original Half Half Annual
Budget Actual Estimate Estimate
-------- ------- -------- --------
<S> <C> <C> <C> <C>
Exploration and production
Capital........................................ $159.0 $ 88.9 $58.5 $147.4
Exploratory expenses........................... 29.0 20.4 5.2 25.6
Gas services..................................... 49.0 18.7 11.0 29.7
Corporate........................................ 4.0 1.3 1.2 2.5
------ ------ ----- ------
$241.0 129.3 75.9 205.2
======
Unbudgeted asset acquisitions
Oil and gas properties......................... 67.6 3.9 71.5
Gas services facilities........................ 13.3 3.7 17.0
------ ----- ------
$210.2 $83.5 $293.7
====== ===== ======
</TABLE>
-13-
<PAGE> 16
The fiscal 1999 budget called for a continuation of the program begun last
year to accelerate drilling of the Company's substantial inventory of
development locations in its core areas. In addition, significant expenditures
were included for seismic work, exploratory acreage acquisitions and exploratory
drilling. More than 90% of the budgeted fiscal 1999 spending for 3-D seismic
surveys was incurred in the first half, as dry weather and the availability of
crews and equipment allowed an acceleration of the planned schedule.
As is its normal practice, the Company reassessed its fiscal 1999 capital
spending plans at mid-year. With no apparent near-term relief in sight from the
current depressed level of energy prices, the fiscal 1999 budget was reduced by
$29.6 million (12%) to $211.4 million. This was accomplished by deferring the
drilling of selected exploratory and development wells until next year and
delaying/eliminating certain gas services projects in response to the downturn
in industry activity. Conversely, planned expenditures were added to develop
recently acquired properties in the Columbus field and the Limestone County area
and thus prove up the values of these properties. As shown in the table above,
spending has been lowered substantially in the second half. For the full year,
expenditures for budgeted items are estimated to be almost 15% below the
original budget.
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 completed by April 30, 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 October 31,
1998, third party costs totaling $600,000 had been incurred in this regard out
of the total estimated $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 has ranked the facilities containing embedded
chips in order of importance and has begun contacting equipment vendors to
determine the steps that will be necessary to make the equipment in which they
are installed capable of properly recognizing dates after December 31, 1999.
Testing of the facilities categorized as important is scheduled to be completed
by April 30, 1999. Third party costs associated with these efforts are estimated
to total $400,000.
Through communications with industry partners and others, the Company is
also evaluating the risk presented by potential Year 2000 non-compliance by
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-compliance. The Company is currently unaware of
situations where material disruptions of its business activities are likely
because of the Year 2000 non-compliance 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-compliance 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-compliance.
-14-
<PAGE> 17
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 reimbursement agreements with the Company's insurance
carriers. Negotiations are in progress with several additional carriers, and it
is expected that agreements covering total dollar amounts in excess of the
recoveries to date will be entered into during the next six months.
OPERATING STATISTICS
Certain operating statistics (including proportional interests in equity
partnerships, where applicable) for the three- and nine-month periods ended
October 31, 1998 and 1997 follow:
<TABLE>
<CAPTION>
Three Months Nine Months
------------------ -----------------
1998 1997 1998 1997
---- ---- ---- ----
AVERAGE DAILY VOLUMES
<S> <C> <C> <C> <C>
Natural gas sales (Mcf)........................... 250,200 239,900 247,300 235,000
Crude oil and condensate sales (Bbls)............. 6,800 5,900 6,800 5,900
Natural gas liquids produced (Bbls)............... 41,900 45,900 42,700 45,700
Pipeline throughput (Mcf) ........................ 567,000* 410,000 558,000* 420,000
AVERAGE SALES PRICES
Natural gas (per Mcf)............................. $ 1.90 $ 2.66 $ 2.14 $ 2.38
Crude oil and condensate (per Bbl)................ 12.22 18.89 12.82 19.09
Natural gas liquids produced (per Bbl)............ 9.79 14.33 10.50 13.52
</TABLE>
* Includes approximately 160,000 Mcf per day for the North Texas gathering
system acquired effective January 1, 1998.
EARNINGS (LOSS) FROM CONTINUING OPERATIONS - NINE MONTHS ENDED OCTOBER 31, 1998
COMPARED WITH NINE MONTHS ENDED OCTOBER 31, 1997
Earnings from continuing operations for the nine-month period ended October 31,
1998 - both before and after unusual items - are summarized in the table on the
following page. The Company had a loss of $5.7 million from continuing
operations during fiscal 1999's first nine months, which compared with earnings
of $21.0 million in the prior-year period. Excluding the effects of unusual
items, a loss of $8.2 million was reported during the fiscal 1999 period, versus
earnings of $40.7 million during the prior-year's comparable period. The
earnings decline occurred largely because of sharply lower prices for natural
gas, oil and condensate and NGLs and increased exploration expenses.
-15-
<PAGE> 18
The following table and discussion identify and explain the major
increases (decreases) in earnings (loss) from continuing operations for the
nine-month periods (in millions):
<TABLE>
<CAPTION>
Segment Earnings (Loss) from
Operating Earnings Continuing Operations
-------------------- ---------------------
Exploration Before
and Gas Income After
Production Services Other* Taxes Tax
----------- -------- ------ ------- ---------
<S> <C> <C> <C> <C> <C>
FISCAL 1998 AMOUNTS AFTER UNUSUAL ITEMS ...................... $ 40.5 $ 23.5 $(32.4) $ 31.6 $ 21.0
------ ------ ------ ------ ------
ELIMINATE IMPACT OF FISCAL 1998 UNUSUAL ITEMS
Water well litigation provision (see page 8) ................. 7.0 -- -- 7.0 4.3
Royalty litigation settlement provision (see page 10) ........ -- 26.0 -- 26.0 16.9
Gain from sale of remaining contract drilling assets ......... (2.4) -- -- (2.4) (1.5)
------ ------ ------ ------ ------
4.6 26.0 -- 30.6 19.7
------ ------ ------ ------ ------
FISCAL 1998 AMOUNTS BEFORE UNUSUAL ITEMS ..................... 45.1 49.5 (32.4) 62.2 40.7
------ ------ ------ ------ ------
MAJOR INCREASES (DECREASES)
Lower natural gas sales price ................................ (15.8) -- -- (15.8) (10.3)
Lower oil and condensate sales price ......................... (11.1) -- -- (11.1) (7.2)
Increased oil and condensate sales volumes ................... 3.2 -- -- 3.2 2.1
Increased natural gas sales volumes .......................... 3.5 -- -- 3.5 2.3
Exploration expenses ......................................... (10.9) -- -- (10.9) (7.1)
Higher DD&A rate ($.89 versus
$.84 per equivalent Mcf produced) ......................... (3.9) -- -- (3.9) (2.5)
Increased E&P operating expenses,
principally maintenance and property taxes ................ (2.6) -- -- (2.6) (1.7)
Lower NGL margins ............................................ -- (20.9) -- (20.9) (13.6)
Gain from a partnership's sale of the
Brooks-Hidalgo gathering system ........................... -- 3.5 -- 3.5 2.3
Depreciation expense on North Texas
gathering system acquired in January 1998 ................. -- (1.8) -- (1.8) (1.2)
Increased interest expense
attributable to continuing operations ..................... -- -- (6.0) (6.0) (3.9)
Reduction in interest income on
unreinvested TWC sales proceeds ........................... -- -- (5.6) (5.6) (3.6)
Performance unit expense accruals ............................ (1.0) (.4) (.6) (2.0) (1.3)
Other, net ................................................... (1.7) (3.7) .1 (5.3) (3.2)
------ ------ ------ ------ ------
(40.3) (23.3) (12.1) (75.7) (48.9)
------ ------ ------ ------ ------
FISCAL 1999 AMOUNTS BEFORE UNUSUAL ITEM ...................... 4.8 26.2 (44.5) (13.5) (8.2)
Water well litigation provision reversal (see page 9) ........ 4.0 -- -- 4.0 2.5
------ ------ ------ ------ ------
FISCAL 1999 AMOUNTS AFTER UNUSUAL ITEM ....................... $ 8.8 $ 26.2 $(44.5) $ (9.5) $ (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 $4.8 million during fiscal 1999's first nine months were sharply
lower than the $45.1 million of the prior-year period primarily because of the
current period's lower prices for natural gas and oil and condensate sales and
increased exploration expenses.
LOWER NATURAL GAS SALES PRICE ($15.8 MILLION DECREASE). During the first nine
months of fiscal 1999, the Company's natural gas sales price averaged $2.14 per
Mcf, $.24 (10%) below the prior period's $2.38, reducing operating earnings by
$15.8 million. Most of this variance occurred in the third quarter when prices
declined in the current year and rose sharply in the prior year.
-16-
<PAGE> 19
LOWER OIL AND CONDENSATE SALES PRICE ($11.1 MILLION DECREASE). The Company's
sales price for oil and condensate averaged $12.82 per barrel during fiscal
1999's first nine months, down sharply from the prior period's $19.09, reducing
operating earnings by $11.1 million. The collapse in world oil prices was
largely the result of overproduction, very mild weather in the U.S. last winter
and an economic downturn in Southeast Asia and other parts of the world.
INCREASED NATURAL GAS SALES VOLUMES ($3.5 MILLION INCREASE). Natural gas sales
volumes averaged 247.3 MMcf per day during fiscal 1999's first nine months, up
from 235.0 MMcf during the comparable period of the prior year, increasing
operating earnings by $3.5 million. This increase was principally due to
drilling and recompletion activity in North Texas, Limestone County and the Lake
Creek field.
INCREASED OIL AND CONDENSATE SALES VOLUMES ($3.2 MILLION INCREASE). Fiscal
1999's production of oil and condensate increased 900 barrels per day (15%) to
6,800, increasing operating earnings by $3.2 million. This occurred largely
because of fiscal 1998 drilling and recompletion activity in Throckmorton County
(North Texas), the Lake Creek field (Southeast Texas) and Calcasieu Parish
(Southwest Louisiana), much of which resulted from the Company's earlier 3-D
seismic surveys.
EXPLORATION EXPENSES ($10.9 MILLION DECREASE). Largely because of a planned
increase in its expenditures for exploratory seismic surveys, the Company's
exploration expenses totaled $23.3 million during fiscal 1999's first nine
months, up from $12.4 million in the prior-year period. Because of dry weather
and the availability of crews and equipment early in the year, the Company
accelerated the performance of these surveys, spending 90% of its budget during
the year's first half.
GAS SERVICES OVERVIEW
Gas services operating earnings declined $23.3 million (to $26.2 million) during
the first nine months of fiscal 1999 principally because of price-related
reductions in gas processing margins. NGL production averaged 42,700 barrels per
day in the fiscal 1999 period, down from 45,700 in the comparable prior-year
period.
LOWER NGL MARGINS ($20.9 MILLION DECREASE). The average price for NGLs produced
during fiscal 1999's first nine months of $10.50 per barrel was 22% below the
prior-year period's $13.52, reducing NGL revenues by $35.1 million. Because of
the impact of the lower NGL and natural gas prices on producer payments,
feedstock costs also fell, reducing the net margin decline to $20.9 million.
OTHER
INTEREST EXPENSE ATTRIBUTABLE TO CONTINUING OPERATIONS ($6.0 MILLION DECREASE).
Because a portion of the proceeds of the TWC sale was reinvested rather than
being used to retire debt related to discontinued operations, interest expense
attributable to continuing operations rose by $6.0 million during the fiscal
1999 period. Total interest expense - including that attributable to
discontinued operations - declined by $9.2 million largely because of the
repurchase during the prior year's third quarter of $185.7 million of 9 1/4%
senior notes using a portion of the TWC sales proceeds.
PERFORMANCE UNIT EXPENSE ACCRUALS ($2.0 MILLION DECREASE). In the fiscal 1999
period, expense accruals totaling $2.0 million were recorded applicable to a
plan adopted in December 1997 that awarded performance units to mid-level
managerial and professional employees. Individuals holding these units on March
31, 1999 are to receive cash compensation equal to the closing price of the
Company's Class B Common Stock on that date times the number of units awarded
them. Compensation expense is being accrued ratably over the life of the
outstanding units based on the Class B stock price at the end of each month.
-17-
<PAGE> 20
EARNINGS (LOSS) FROM CONTINUING OPERATIONS - THREE MONTHS ENDED OCTOBER 31, 1998
COMPARED WITH THREE MONTHS ENDED OCTOBER 31, 1997
Earnings (loss) from continuing operations for the three-month periods ended
October 31, 1998 and 1997 are summarized on the following table. The Company
reported a loss of $3.7 million during fiscal 1999's third quarter versus
earnings of $17.7 million in the comparable prior-year period. The earnings
decline was principally the result of sharply lower prices for natural gas, oil
and condensate and NGLs in the latest period.
The following table and discussion identify and explain the major
increases (decreases) in earnings (loss) from continuing operations for the
three-month periods (in millions):
<TABLE>
<CAPTION>
Segment Earnings (Loss) from
Operating Earnings Continuing Operations
----------------------- ---------------------
Exploration Before
and Gas Income After
Production Services Other* Taxes Tax
----------- -------- ------ ------ -----
<S> <C> <C> <C> <C> <C>
FISCAL 1998 AMOUNTS.................................... $19.6 $19.0 $(11.1) $ 27.5 $17.7
----- ----- ------ ------ -----
MAJOR INCREASES (DECREASES)
Lower natural gas sales price.......................... (16.7) - - (16.7) (10.9)
Lower oil and condensate sales price................... (4.0) - - (4.0) (2.6)
Increased oil and condensate sales volumes............. 1.0 - - 1.0 .7
Price-related decreases in NGL margins................. - (7.5) - (7.5) (4.9)
Gas gathering and marketing............................ - (2.3) - (2.3) (1.5)
Prior-year interest income on
unreinvested TWC sales proceeds..................... - - (5.0) (5.0) (3.2)
Other, net............................................. 1.1 (.6) .2 .7 1.0
----- ----- ------ ------ -----
(18.6) (10.4) (4.8) (33.8) (21.4)
----- ----- ------ ------ -----
FISCAL 1999 AMOUNTS.................................... $ 1.0 $ 8.6 $(15.9) $ (6.3) (3.7)
===== ===== ====== ====== =====
</TABLE>
- ---------------
*Includes general and administrative expense and other expense.
EXPLORATION AND PRODUCTION OVERVIEW
Exploration and production segment operating earnings for the third quarter of
fiscal 1999 were $18.6 million below the $19.6 million of fiscal 1998's third
quarter principally because of lower prices for natural gas and oil and
condensate.
NATURAL GAS SALES PRICE ($16.7 MILLION DECREASE). The Company's natural gas
sales price averaged $1.90 per Mcf during the third quarter of the current year,
$.76 (29%) below the $2.66 average of the corresponding period of the prior
year, reducing operating earnings by $16.7 million. Natural gas sales prices
were volatile during the fiscal 1999's third quarter; the Company's average
price was $1.91 per Mcf in August, $1.75 in September and $2.04 in October.
Conversely, natural gas sales prices rose steadily during the prior-year period
(from $2.24 in August to $3.16 in October).
LOWER OIL AND CONDENSATE SALES PRICES ($4.0 MILLION DECREASE). The Company's oil
and condensate sales price averaged $12.22 per barrel during fiscal 1999's third
quarter, 35% below the $18.89 of the corresponding prior-year period, reducing
operating earnings by $4.0 million.
INCREASED OIL AND CONDENSATE SALES VOLUMES ($1.0 MILLION INCREASE). For the
reasons discussed on page 17, production of oil and condensate during the third
quarter of the current year increased 900 barrels per day (15%) to 6,800,
increasing operating earnings by $1.0 million.
-18-
<PAGE> 21
GAS SERVICES OVERVIEW
Gas services operating earnings declined $10.4 million from the $19.0 million of
the prior year's quarter largely because of much lower NGL margins. NGL
production volumes were 4,000 barrels per day (9%) lower in the fiscal 1999
period largely because of reduced production for plants serving the Austin Chalk
rich gas system because of throughput declines for that system. Also, the
Company rejected ethane at its Bridgeport plant during approximately one-half of
the fiscal 1999 period in response to weak NGL margins.
PRICE-RELATED DECREASES IN NGL MARGINS ($7.5 MILLION DECREASE). The Company's
average price for NGLs was $9.79 per barrel during fiscal 1999's third quarter,
down $4.54 (32%) from the level of the corresponding period of the prior year,
reducing NGL revenues $17.7 million. Feedstock costs fell by $10.2 million
because of the impact of lower natural gas and NGL prices on producer payments,
reducing the net margin decline to $7.5 million.
GAS GATHERING AND MARKETING ($2.3 MILLION DECREASE). Natural gas prices weakened
during fiscal 1999's third quarter, resulting in reduced margins for gas
gathering and marketing activities (after strengthening considerably during the
prior-year period). Substantial portions of the natural gas supply costs for
these activities are based on beginning-of-the-month market index prices, and
sharp upward or downward movements in natural gas prices after these costs have
been set cause the Company's gas gathering and marketing margins to rise or fall
appreciably.
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 nine-month period ended
October 31, 1998.
-19-
<PAGE> 22
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: December 11, 1998 By: /s/ Philip S. Smith
-----------------------------------
Philip S. Smith
Senior Vice President - Administration
and Chief Financial Officer
-20-
<PAGE> 23
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT NO. DESCRIPTION
- ----------- -----------
<S> <C>
27 Financial Data Schedule
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> JAN-31-1999
<PERIOD-END> OCT-31-1998
<CASH> 11,496
<SECURITIES> 0
<RECEIVABLES> 77,416
<ALLOWANCES> 0
<INVENTORY> 14,911
<CURRENT-ASSETS> 121,098
<PP&E> 2,484,559
<DEPRECIATION> 1,389,808
<TOTAL-ASSETS> 1,238,032
<CURRENT-LIABILITIES> 246,607
<BONDS> 389,267
0
0
<COMMON> 5,386
<OTHER-SE> 379,933
<TOTAL-LIABILITY-AND-EQUITY> 1,238,032
<SALES> 528,441
<TOTAL-REVENUES> 528,441
<CGS> 0
<TOTAL-COSTS> 493,515
<OTHER-EXPENSES> 18,980
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 25,495
<INCOME-PRETAX> (9,549)
<INCOME-TAX> (3,880)
<INCOME-CONTINUING> (5,669)
<DISCONTINUED> 3,250
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (2,419)
<EPS-PRIMARY> (.07)<F1>
<EPS-DILUTED> (.07)<F2>
<FN>
<F1>
CLASS A BASIC (.07)
CLASS B BASIC (.03)
<F2>
CLASS A DILUTED (.07)
CLASS B DILUTED (.03)
</FN>
</TABLE>
