<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 JULY 31, 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
--- ---
Shares of common stock outstanding at August 31, 1999:
Class A......................... 22,321,635
Class B......................... 26,795,622
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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...................................... 20
Item 4. Submission of Matters to Vote of Security Holders...... 20
Item 6. Exhibits and Reports on Form 8-K....................... 20
</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>
JULY 31, January 31,
1999 1999
----------- -----------
ASSETS (unaudited)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents ................................................. $ 19,157 $ 20,300
Trade receivables ......................................................... 40,561 34,078
Inventories ............................................................... 10,311 10,734
Income taxes receivable ................................................... 4,365 5,944
Other ..................................................................... 6,869 8,576
----------- -----------
Total current assets ................................................. 81,263 79,632
----------- -----------
PROPERTY, PLANT AND EQUIPMENT, at cost less accumulated
depreciation, depletion and amortization of $1,452,921 and $1,450,685
Exploration and production
Oil and gas properties .................................................. 672,552 683,946
Support equipment and facilities ........................................ 14,543 16,253
Gas services (including investments in equity partnerships) (Note 3)
Natural gas processing .................................................. 101,832 102,761
Natural gas gathering ................................................... 135,027 145,488
Other ................................................................... 81,185 79,678
Corporate ................................................................. 4,702 5,612
----------- -----------
1,009,841 1,033,738
----------- -----------
LONG-TERM INVESTMENTS AND OTHER ASSETS .................................... 34,166 33,106
----------- -----------
$ 1,125,270 $ 1,146,476
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt (Note 4) ............................. $ -- $ 100,000
Oil and gas proceeds payable .............................................. 77,181 68,658
Accounts payable .......................................................... 30,801 32,868
Accrued liabilities ....................................................... 41,157 40,269
----------- -----------
Total current liabilities ............................................ 149,139 241,795
----------- -----------
LONG-TERM DEBT (Note 4) ................................................... 400,267 362,467
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes ..................................................... 139,916 130,069
Retirement obligations and other .......................................... 91,141 87,371
----------- -----------
231,057 217,440
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 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 ......................................................... 307,316 287,283
Other comprehensive loss .................................................. (7,381) (7,381)
Treasury stock, at cost ................................................... (104,150) (104,150)
----------- -----------
344,807 324,774
----------- -----------
$ 1,125,270 $ 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 Six Months
Ended July 31 Ended July 31
---------------------- -----------------------
1999 1998 1999 1998
--------- --------- ---------- ---------
<S> <C> <C> <C> <C>
REVENUES
Exploration and production (including a gain of $11,527
from sale of Hell's Hole area properties in the 1999 periods) ...... $ 74,107 $ 58,921 $ 120,856 $ 117,917
Gas services .......................................................... 153,824 121,794 267,031 235,190
--------- --------- --------- ---------
227,931 180,715 387,887 353,107
--------- --------- --------- ---------
OPERATING COSTS AND EXPENSES
Exploration and production (net of water well litigation
provision reversals of none, $1,000, $9,000 and $4,000) (Note 6) ... 43,398 55,707 78,837 110,095
Gas services .......................................................... 131,045 117,120 232,757 217,681
--------- --------- --------- ---------
174,443 172,827 311,594 327,776
--------- --------- --------- ---------
SEGMENT OPERATING EARNINGS (Note 7) ................................... 53,488 7,888 76,293 25,331
General and administrative expense .................................... 6,462 7,613 12,731 15,818
--------- --------- --------- ---------
TOTAL OPERATING EARNINGS .............................................. 47,026 275 63,562 9,513
--------- --------- --------- ---------
OTHER EXPENSE
Interest expense ...................................................... 8,863 8,510 17,902 16,159
Interest income ....................................................... (68) (118) (108) (736)
Other, net ............................................................ (2,437) (1,247) (4,003) (2,661)
--------- --------- --------- ---------
6,358 7,145 13,791 12,762
--------- --------- --------- ---------
EARNINGS (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES ..................................... 40,668 (6,870) 49,771 (3,249)
INCOME TAXES (Note 5) ................................................. 13,861 (2,622) 17,280 (1,296)
--------- --------- --------- ---------
EARNINGS (LOSS) FROM CONTINUING OPERATIONS ............................ 26,807 (4,248) 32,491 (1,953)
DISCONTINUED REAL ESTATE OPERATIONS (Note 2)
Adjustment to loss on sale, net of income taxes of $1,750 ............. -- -- -- 3,250
--------- --------- --------- ---------
NET EARNINGS (LOSS) ................................................... 26,807 $ (4,248) $ 32,491 $ 1,297
========= ========= ========= =========
BASIC AND DILUTED EARNINGS (LOSS) PER SHARE (Note 9)
Class A - From continuing operations................................... $ .54 $ (.09) $ .65 $ (.05)
Net earnings................................................ .54 (.09) .65 .01
Class B - From continuing operations................................... .55 (.08) .67 (.03)
Net earnings................................................ .55 (.08) .67 .04
AVERAGE COMMON SHARES OUTSTANDING (Basic) - Class A.................... 22,322 22,321 22,322 22,321
Class B.................... 26,796 26,795 26,796 26,776
</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 Six Months Ended July 31,1999
(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 ................................ 32,491 -- -- 32,491 -- --
Cash dividends (24 cents per share on Class A
and 26.5 cents per share on Class B) ..... (12,458) -- -- (12,458) -- --
--------- --------- --------- --------- --------- ---------
BALANCE, JULY 31, 1999 ...................... $ 344,807 $ 5,386 $ 143,636 $ 307,316 $ (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 ...................... (5) (5) -- -- (5) (5)
---------- ---------- --------- --------- ---------- ----------
BALANCE, JULY 31, 1999 ..... 23,978,072 29,878,072 1,656,437 3,082,450 22,321,635 26,795,622
========== ========== ========= ========= ========== ==========
</TABLE>
- ---------------------
The accompanying notes are an integral part of these financial statements.
-4-
<PAGE> 7
MITCHELL ENERGY & DEVELOPMENT CORP. AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
Six Months Ended
July 31
----------------------
1999 1998
--------- ---------
<S> <C> <C>
OPERATING ACTIVITIES
Earnings from continuing operations ........................................... $ 32,491 $ (1,953)
Adjustments to reconcile earnings from continuing
operations to cash provided by operating activities
Depreciation, depletion and amortization ................................ 54,737 58,135
Exploration expenses (including exploratory well impairments) ........... 3,764 20,417
Deferred income taxes ................................................... 9,847 304
Distributions in excess of earnings of equity investees ................. 3,348 9,179
Gain from sale of Hell's Hole area properties ........................... (11,527) --
Water well litigation provision reversals ............................... (9,000) (4,000)
Other, net .............................................................. (6,901) (1,884)
--------- ---------
76,759 80,198
Changes in operating assets and liabilities ............................. 17,605 (3,205)
--------- ---------
Cash provided by operating activities ................................... 94,364 76,993
--------- ---------
INVESTING ACTIVITIES
Capital and exploratory expenditures
Total on accrual basis (including asset acquisitions of $80,916 in 1998) ... (54,705) (210,182)
Adjustment to cash basis ................................................... (3,484) (4,200)
--------- ---------
(58,189) (214,382)
Property, plant and equipment sales proceeds .................................. 34,681 --
Other, net .................................................................... 2,976 1,656
--------- ---------
Cash used for investing activities ...................................... (20,532) (212,726)
--------- ---------
FINANCING ACTIVITIES
Proceeds from issuance of debt ................................................ 37,800 120,000
Debt repayments ............................................................... (100,000) (60,000)
Cash dividends ................................................................ (12,458) (12,452)
Treasury stock purchases ...................................................... -- (9,217)
Other ......................................................................... (317) 2,341
--------- ---------
Cash provided by (used for) financing activities ........................ (74,975) 40,672
--------- ---------
DECREASE IN CASH AND CASH EQUIVALENTS
FROM CONTINUING OPERATIONS ................................................. (1,143) (95,061)
CASH PROVIDED BY DISCONTINUED OPERATIONS ...................................... -- 12,927
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ................................ 20,300 105,309
--------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD ...................................... $ 19,157 $ 23,175
========= =========
</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
July 31, 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 six-month periods ended July 31, 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 1998. The statement, which the
Company must adopt for fiscal 2002, requires that all derivatives be recognized
at fair value as assets or liabilities and that changes in fair value be
recorded in earnings or other comprehensive income. 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 July 31, 1999 and
January 31, 1999 and its equity in their pretax earnings for the six-month
periods ended July 31, 1999 and 1998 follows (in thousands):
<TABLE>
<CAPTION>
Equity in
Net Investment Pretax Earnings
--------------------- ----------------------
Percent July 31, January 31, July 31, July 31,
Owned 1999 1999 1999 1998
------- ------- ----------- --------- --------
<S> <C> <C> <C> <C> <C>
NATURAL GAS PROCESSING
C&L Processors Partnership ..... 50 $ 59,689 $ 60,130 $ 903 $ 361
U.P. Bryan Plant ............... 45 2,171 2,244 2,939 470
-------- -------- -------- --------
61,860 62,374 3,842 831
-------- -------- -------- --------
GAS GATHERING AND MARKETING
Austin Chalk Natural Gas
Marketing Services .......... 45 610 739 897 1,288
Ferguson-Burleson County
Gas Gathering System ........ 45 38,686 40,151 2,707 1,610
Louisiana Chalk Gathering System 50 16,869 17,346 (477) (367)
Others ......................... 412 353 59 3,599*
-------- -------- -------- --------
56,577 58,589 3,186 6,130
-------- -------- -------- --------
OTHER
Belvieu Environmental Fuels .... 33.33 50,061 47,660 2,401 3,891
Gulf Coast Fractionators ....... 38.75 29,523 30,364 878 2,621
-------- -------- -------- --------
79,584 78,024 3,279 6,512
-------- -------- -------- --------
$198,021 $198,987 $ 10,307 $ 13,473
======== ======== ======== ========
</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- and six-month periods ended July
31, 1999 and 1998 (in thousands):
<TABLE>
<CAPTION>
Three Months Six Months
-------------------- ---------------------
1999 1998 1999 1998
--------- --------- --------- --------
<S> <C> <C> <C> <C>
Revenues ............................................................. $148,312 $142,443 $268,185 $274,192
Operating earnings ................................................... 17,993 16,151 32,280 29,133
Pretax earnings (before interest expense for those entities
whose activities are funded by capital contributions
of the owners)..................................................... 16,693 11,548 24,839 20,409
</TABLE>
(4) LONG-TERM DEBT
At July 31, 1999, the Company's outstanding debt consisted of $314,267,000 of
unsecured parent company senior notes, the proceeds of which have been advanced
to the operating subsidiaries, and borrowings of $80,000,000 under a
$250,000,000 bank revolving credit facility and $6,000,000 under an uncommitted
money market facility. During July 1999, the Company repaid $100,000,000 of
maturing 8% senior notes using proceeds of borrowings under its revolving
credit agreement and available cash.
-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 $67,772,000 at July 31, 1999.
(5) INCOME TAXES
Income taxes applicable to earnings from continuing operations for the
six-month periods ended July 31, 1999 and 1998 consist of the following (in
thousands):
<TABLE>
<CAPTION>
1999 1998
---------- ----------
<S> <C> <C>
Current - Federal...................... $ 7,317 $(1,757)
State........................ 116 157
-------- -------
7,433 (1,600)
-------- -------
Deferred - Federal..................... 8,787 864
State....................... 1,060 (560)
-------- -------
9,847 304
-------- -------
$17,280 $(1,296)
======= =======
</TABLE>
Estimated annual tax rates of 34.7% and 39.9%, respectively, were used in
computing the income tax provisions for the six-month periods ended July 31,
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 which denied that request on August
26, 1999.
-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. Subsequently, the Texas Supreme Court denied the
plaintiffs' petitions for review and motions for rehearing, and these cases are
now over.
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 paragraph will not result in charges that are material to the Company's
financial position. It is possible, however, that charges could be required that
would be significant to the operating results of a particular period.
The Company holds a one-third interest in a partnership which owns a plant
that manufactures a gasoline additive known as MTBE. In July 1999, a national
advisory panel formed by the EPA recommended that the use of MTBE be reduced
substantially, and several states have commenced reviews of the use of MTBE in
gasoline. In March 1999 the governor of California ordered that the use of MTBE
be phased out in that state over a four-year period, and in August 1999 a group
of seven northeastern states took steps that would lead to the phase-out of MTBE
usage over a three-year period. Restrictions on the use of MTBE could
significantly impact future operations of the MTBE plant partially owned by the
Company. However, that facility, which was built in the mid 1990s for
approximately $225,000,000, was originally designed in a manner that allows it -
with moderate expenditures - to be converted to the production of other
products. It is not possible at this time to determine the ultimate impact, if
any, of this matter on the Company's financial position or future results of
operations.
-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>
SIX MONTHS ENDED JULY 31, 1999
EXPLORATION AND PRODUCTION
Operations .......................................... $109,329 $ -- $ 21,492 $ 16,734 $ 46,705 $ 46,925
Gain from sale of Hell's Hole area properties ....... 11,527 -- 11,527 11,527 -- --
Water well litigation provision reversal (Note 6) ... -- -- 9,000 9,000 -- --
-------- -------- -------- -------- -------- --------
120,856 -- 42,019 37,261 46,705 46,925
-------- -------- -------- -------- -------- --------
GAS SERVICES
Natural gas processing .............................. 145,933 38,038 16,283 14,897 1,832 2,687
Natural gas gathering and marketing ................. 117,968 98,110 15,244 13,668 4,949 4,737
Other ............................................... 3,130 -- 2,747 2,589 53 130
-------- -------- -------- -------- -------- --------
267,031 136,148 34,274 31,154 6,834 7,554
-------- -------- -------- -------- -------- --------
CORPORATE ........................................... -- -- -- (4,853)(b) 1,198 226
-------- -------- -------- -------- -------- --------
$387,887 $136,148 $ 76,293 $ 63,562 $ 54,737 $ 54,705
======== ======== ======== ======== ======== ========
SIX MONTHS ENDED JULY 31, 1998
EXPLORATION AND PRODUCTION
Operations .......................................... $117,917 -- $ 3,822 $ (2,152) $ 48,885 $176,826
Water well litigation provision reversal (Note 6) ... -- -- 4,000 4,000 -- --
-------- -------- -------- -------- -------- --------
117,917 -- 7,822 1,848 48,885 176,826
-------- -------- -------- -------- -------- --------
GAS SERVICES
Natural gas processing .............................. 128,106 42,001 (1,569) (3,187) 1,963 17,090
Natural gas gathering and marketing ................. 100,572 119,826 13,161 11,244 5,805 14,362
Other ............................................... 6,512 -- 5,917 5,715 53 600
-------- -------- -------- -------- -------- --------
235,190 161,827 17,509 13,772 7,821 32,052
-------- -------- -------- -------- -------- --------
CORPORATE ........................................... -- -- -- (6,107)(b) 1,429 1,304
-------- -------- -------- -------- -------- --------
$353,107 $161,827 $ 25,331 $ 9,513 $ 58,135 $210,182
======== ======== ======== ======== ======== ========
THREE MONTHS ENDED JULY 31, 1999
EXPLORATION AND PRODUCTION
Operations .......................................... $ 62,580 $ -- $ 19,182 $ 16,991 $ 23,079 $ 25,773
Gain on sale of Hell's Hole properties .............. 11,527 -- 11,527 11,527 -- --
-------- -------- -------- -------- -------- --------
74,107 -- 30,709 28,518 23,079 25,773
-------- -------- -------- -------- -------- --------
GAS SERVICES
Natural gas processing .............................. 84,764 21,657 12,387 11,691 907 629
Natural gas gathering and marketing ................. 67,334 55,772 8,852 8,060 2,387 1,802
Other ............................................... 1,726 -- 1,540 1,462 26 59
-------- -------- -------- -------- -------- --------
153,824 77,429 22,779 21,213 3,320 2,490
-------- -------- -------- -------- -------- --------
CORPORATE ........................................... -- -- -- (2,705)(b) 606 119
-------- -------- -------- -------- -------- --------
$227,931 $ 77,429 $ 53,488 $ 47,026 $ 27,005 $ 28,382
======== ======== ======== ======== ======== ========
THREE MONTHS ENDED JULY 31, 1998
EXPLORATION AND PRODUCTION
Operations .......................................... $ 58,921 $ -- $ 2,214 $ (790) $ 25,150 $ 85,951
Water well litigation provision reversal (Note 6) ... -- -- 1,000 1,000 -- --
-------- -------- -------- -------- -------- --------
58,921 -- 3,214 210 25,150 85,951
-------- -------- -------- -------- -------- --------
GAS SERVICES
Natural gas processing .............................. 60,448 20,978 (2,504) (3,287) 1,002 2,630
Natural gas gathering and marketing ................. 57,830 61,329 3,951 3,021 2,912 6,269
Other ............................................... 3,516 -- 3,227 3,134 26 466
-------- -------- -------- -------- -------- --------
121,794 82,307 4,674 2,868 3,940 9,365
-------- -------- -------- -------- -------- --------
CORPORATE ........................................... -- -- -- (2,803)(b) 720 1,049
-------- -------- -------- -------- -------- --------
$180,715 $ 82,307 $ 7,888 $ 275 $ 29,810 $ 96,365
======== ======== ======== ======== ======== ========
</TABLE>
- ---------------------
(a) On accrual basis, including exploratory expenses and acquisitions.
(b) General corporate expenses.
-10-
<PAGE> 13
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.
During June 1999, the Company sold for cash all its oil and gas
properties in the Hell's Hole and Park Mountain fields in Colorado and Utah,
which consisted of 24,000 net leasehold acres with 36 producing wells and
associated pipelines, gathering systems and production facilities. A pretax
gain of $11,527,000 ($7,190,000 after tax) was recognized on this sale.
(8) SUPPLEMENTAL CASH FLOW INFORMATION
Interest paid totaled $16,791,000 and $16,002,000 during the six-month periods
ended July 31, 1999 and 1998. Income taxes paid during those periods totaled
none and $3,783,000. There were no significant non-cash investing or financing
activities during the six-month periods ended July 31, 1999 and 1998.
(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 prorata 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- and six-month periods ended July 31, 1999 and 1998.
<TABLE>
<CAPTION>
Three Months Six Months
-------------------------------------- --------------------------------------
1999 1998 1999 1998
------------------ ------------------ ------------------ ------------------
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 .......... $ .54 $ .55 $ (.09) $ (.08) $ .65 $ .67 $ (.05) $ (.03)
Discontinued real estate operations -
Adjustment to loss on sale ...... -- -- -- -- -- -- .06 .07
------- ------- ------- ------- ------- ------- ------- -------
Net earnings ........................ $ .54 $ .55 $ (.09) $ (.08) $ .65 $ .67 $ .01 $ .04
======= ======= ======= ======= ======= ======= ======= =======
</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- and six-month periods ended July 31, 1999 and 1998
(in thousands):
<TABLE>
<CAPTION>
Three Months Six Months
-------------------------------------- --------------------------------------
1999 1998 1999 1998
------------------ ------------------ ------------------ ------------------
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 ........... 22,322 26,796 22,321 26,795 22,322 26,796 22,321 26,776
Dilutive effect of stock options ..... -- 112 -- -- -- 63 -- --
------- ------- ------- ------- ------- ------- ------- ------
Used in diluted computations ......... 22,322 26,908 22,321 26,795 22,322 26,859 22,321 26,776
======= ======= ======= ======= ======= ======= ======= ======
</TABLE>
Excluded from these computations because their effect would have been
antidilutive were stock options covering 73,258 Class A and 1,649,375 Class B
shares for the three- and six-month periods ended July 31, 1999 and 606,240
Class B shares for the six months ended July 31, 1998. There were no
antidilutive stock options for the three-month period ended July 31, 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. After being adversely impacted by unusually low prices for its
products in fiscal 1999 and early this year, the Company's results for the
second quarter of fiscal 2000 dramatically improved as energy prices rose. Also,
contributing substantially to this improvement were sharp reductions in costs
and expenses that resulted from a personnel reduction program implemented by the
Company late last year and other cost-cutting strategies it employed.
While the Company's earnings and cash flows are affected by many things,
fluctuating energy prices are clearly one of the most significant. The following
table shows the Company's quarterly average sales prices during fiscal 2000's
first half and for the three prior 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... 2.40 2.25 2.24 2.40 16.44 12.33 18.48 20.28 13.33 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 during
fiscal 1999's last half 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 curtail capital spending
and to take various steps to sharply 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.
-12-
<PAGE> 15
The Company went into fiscal 2000 well-positioned to operate in a
low-energy-price environment and conducted its activities on that basis
throughout the first half of the year. Capital spending was intentionally
deferred causing natural gas production levels to cease their growth and to fall
somewhat. The nature of the Company's properties and its large backlog of
undrilled well locations make it possible for development drilling activity and
capital spending levels to be quickly raised or lowered. As the outlook for
energy prices improved in the first half, the Company began taking steps to
substantially increase its development drilling and well recompletion programs
during the last half of fiscal 2000. As a result, it is expected that the
Company's natural gas production will be restored to the 250,000 Mcf per day
range by the end of this fiscal year.
CAPITAL AND EXPLORATORY EXPENDITURES. A comparison of the Company's original
and revised budgets for fiscal 2000 capital and exploratory expenditures
follows (in millions):
<TABLE>
<CAPTION>
Revised Budget
-------------------------------------
First Second
Original Half Half
Budget Actual Estimate Total
-------- -------- --------- -------
<S> <C> <C> <C> <C>
Exploration and production....................... $112.4 $46.9 $ 90.9 $137.8
Gas services..................................... 21.0 7.6 18.7 26.3
Corporate........................................ 2.8 .2 2.6 2.8
------ ------ ------ ------
$136.2 $ 54.7 $112.2 $166.9
====== ====== ====== ======
</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. During much of the first
half, capital spending was intentionally restrained to keep the Company's cash
outflows in line with its inflows. However, in response to improving prices,
steps began to be taken late in the period to increase activity. As a result of
this and other planned actions, second half spending will be substantially
increased as shown in the table above. The exploration and production
expenditures are being directed toward accelerated drilling of development wells
and well recompletions that will add to the Company's natural gas production
late this year and next.
In gas services, the planned second half spending includes substantial
improvements involving the Bridgeport gas processing plant and the North Texas
gathering system. Also, many relatively small projects are planned that should
add to the throughput and production volumes of the Company's pipelines and gas
processing plants. With the improved outlook for NGL margins, completion of the
planned capital projects and the expected acquisition of full ownership in the
now 50%-owned Jameson plant, the Company's average fourth quarter NGL production
volume could exceed 50,000 barrels per day.
FINANCING MATTERS. The parent company has a $250 million bank revolving credit
facility and a $25 million bank money-market facility. At July 31, 1999,
borrowings of $86 million were outstanding under these facilities. The Company
funded its first half liquidity needs using cash inflows from operations and
proceeds from nonstrategic asset sales and reduced its outstanding debt by
$62.2 million. The Company expects that its cash inflows and outflows will be
essentially balanced in the second half of fiscal 2000, even with that period's
sharply higher capital spending.
The Company retired $100 million of 8% senior notes that matured on July
15, 1999 using borrowings under its revolving credit facility and available
cash. While the Company has no immediate plans to issue additional senior
notes, it has the ability to do so should business opportunities arise
requiring funding in excess of that which is currently available under the
Company's bank credit facilities.
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. Negotiations continue with other carriers, and it is
expected that an additional agreement or two will be executed during the third
quarter.
-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). Largely
because of this hedge, the Company only infrequently enters into hedging
activities to manage its exposure to price fluctuations. The Company does not
hold or issue derivative instruments for trading purposes. It had no open
hedging positions at July 31, 1999, and its hedging activity during the last
three years was not significant.
The Company's exposure to changing interest rates is limited since almost
80% of its outstanding debt at July 31, 1999 consisted of senior notes with
fixed interest rates.
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. This work now
has been substantially completed. Since this work was accomplished principally
by reallocating internal resources, the Company did not incur incremental costs
that significantly impacted its results of operations or cash flows. Through
July 31, 1999, third party costs totaling $670,000 had been incurred in this
regard out of total estimated costs of less than $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 nonreadiness 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- and six-month periods ended July
31, 1999 and 1998 follow:
<TABLE>
<CAPTION>
Three Months Six Months
------------------------ ------------------------
1999 1998 1999 1998
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
AVERAGE DAILY VOLUMES
Natural gas sales (Mcf)........................... 236,900 245,200 240,300 245,800
Crude oil and condensate sales (Bbls)............. 5,700 6,600 5,900 6,800
Natural gas liquids produced (Bbls)............... 43,500 40,800 42,800 43,100
Pipeline throughput (Mcf) ........................ 518,000 565,000 512,000 554,000
AVERAGE SALES PRICES
Natural gas (per Mcf)............................. $ 2.40 $ 2.25 $ 2.12 $ 2.27
Crude oil and condensate (per Bbl)................ 16.44 12.33 14.47 13.13
Natural gas liquids produced (per Bbl)............ 13.33 10.22 12.05 10.85
</TABLE>
EARNINGS FROM CONTINUING OPERATIONS - SIX MONTHS ENDED JULY 31, 1999
COMPARED WITH SIX MONTHS ENDED JULY 31, 1998
Earnings from continuing operations for the six-month periods ended July 31,
1999 and 1998 - both before and after unusual items - are summarized in the
table on the following page. Earnings from continuing operations for fiscal
2000's first half totaled $32.5 million, which compares with a loss of $1.9
million during the comparable prior-year period. Exclusive of unusual items,
fiscal 2000 after-tax earnings totaled $19.7 million compared with the
prior-year period's loss of $4.4 million. Substantially reduced geological and
geophysical expenses, price-related improvements in NGL margins and sharp
reductions in personnel and other operating costs were the principal reasons
for the substantial year-to-year earnings improvement.
-15-
<PAGE> 18
The following table and discussion identify and explain the major
increases (decreases) in earnings from continuing operations for the six-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 ..................... $ 7.8 $17.5 $(28.6) $(3.3) $(1.9)
ELIMINATE IMPACT OF FISCAL 1999 UNUSUAL ITEM -
Water well litigation provision reversals (see page 9) ... (4.0) -- -- (4.0) (2.5)
----- ----- ------ ----- -----
FISCAL 1999 AMOUNTS BEFORE UNUSUAL ITEMS .................... 3.8 17.5 (28.6) (7.3) (4.4)
----- ----- ------ ----- -----
MAJOR INCREASES (DECREASES)
Reduced geological and geophysical expenses ................. 14.4 -- -- 14.4 9.4
Lower natural gas sales price ............................... (4.8) -- -- (4.8) (3.1)
Lower natural gas sales volume .............................. (2.3) -- -- (2.3) (1.5)
Higher oil and condensate sales price ....................... 1.4 -- -- 1.4 .9
Lower oil and condensate sales volume ....................... (1.1) -- -- (1.1) (.7)
Decreased exploratory well impairments ($.9 versus $3.2) .... 2.3 -- -- 2.3 1.5
Improved NGL margins ........................................ -- 9.2 -- 9.2 6.0
Increased NGL marketing earnings ............................ -- 2.2 -- 2.2 1.4
Reduced operating expenses
Salary and benefits savings from personnel reductions .... 2.7 2.8 1.6 7.1 4.6
Lower repairs and maintenance and other .................. 3.9 2.9 -- 6.8 4.4
Performance unit expense accruals ........................... .7 .3 .4 1.4 .9
Fidelity insurance proceeds ................................. -- -- 1.8 1.8 1.2
Interest expense incurred ................................... -- -- (1.7) (1.7) (1.1)
Other, net .................................................. .5 (.6) -- (.1) .2
----- ----- ------ ----- -----
17.7 16.8 2.1 36.6 24.1
----- ----- ------ ----- -----
FISCAL 2000 AMOUNTS BEFORE UNUSUAL ITEMS .................... 21.5 34.3 (26.5) 29.3 19.7
----- ----- ------ ----- -----
Gain from sale of Hell's Hole
area properties (see page 11) ............................ 11.5 -- -- 11.5 7.2
Water well litigation provision reversal (see page 9) ....... 9.0 -- -- 9.0 5.6
----- ----- ------ ----- -----
20.5 -- -- 20.5 12.8
----- ----- ------ ----- -----
FISCAL 2000 AMOUNTS AFTER UNUSUAL ITEMS ..................... $42.0 $34.3 $(26.5) $49.8 $32.5
===== ===== ====== ===== =====
</TABLE>
- -----------------------------
*Includes general and administrative expense and other expense.
EXPLORATION AND PRODUCTION OVERVIEW
Exclusive of unusual items, exploration and production segment operating
earnings of $21.5 million during fiscal 2000's first six months were $17.7
million higher than those of the comparable prior-year period as sharp
reductions in geological and geophysical expenses and personnel costs and other
operating expenses more than offset the negative impact of year-to-year
declines in production volumes and natural gas prices.
LOWER GEOLOGICAL AND GEOPHYSICAL EXPENSES ($14.4 MILLION INCREASE). During the
first six months of fiscal 2000, geological and geophysical expenses totaled
$2.9 million versus $17.3 million during the comparable prior-year period,
improving operating earnings by $14.4 million. During the prior year's first
six months, the Company undertook an aggressive 3-D seismic program which was
not repeated in fiscal 2000.
LOWER NATURAL GAS SALES PRICE ($4.8 MILLION DECREASE). During the first half of
fiscal 2000, the Company's natural gas sales price averaged $2.12 per Mcf, $.15
(7%) below the prior period's $2.27, reducing operating earnings by $4.8
million. As shown on the table on page 12, natural gas prices were
substantially higher during fiscal 2000's second quarter, averaging $2.40 per
Mcf.
-16-
<PAGE> 19
LOWER NATURAL GAS SALES VOLUME ($2.3 MILLION DECREASE). Natural gas sales
averaged 240.3 MMcf per day during fiscal 2000's first half, marginally lower
than the 245.8 MMcf of the comparable prior-year period, reducing operating
earnings by $2.3 million.
HIGHER OIL AND CONDENSATE PRICE ($1.4 MILLION INCREASE). The Company's sales
price for oil and condensate averaged $14.47 per barrel during fiscal 1999's
first half, up $1.34 from the prior period's $13.13, increasing operating
earnings by $1.4 million.
LOWER OIL AND CONDENSATE SALES VOLUME ($1.1 MILLION DECREASE). First half
production of oil and condensate declined 900 barrels per day (13%) to 5,900,
reducing operating earnings by $1.1 million. Production fell primarily because
of curtailed 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 rose $16.8 million (to $34.3 million) during
the first six months of fiscal 2000 principally due to price-related
improvements in gas processing margins and to reductions in personnel costs and
other operating expenses.
IMPROVED NGL MARGINS ($9.2 MILLION INCREASE). The average price for NGLs
produced during fiscal 2000's first six months of $12.05 per barrel was 11%
above the prior-year period's $10.85, improving NGL revenues by $9.2 million.
Production costs were flat, resulting in a net margin improvement of $9.2
million. Year-to-year, overall costs were essentially unchanged because the
impact of the current period's higher NGL prices on pro ducer payments was
offset by reduced gas shrinkage costs due to the period's lower natural gas
prices and reductions in transportation and fractionation costs resulting from
actions taken by the Company late in fiscal 1999.
INCREASED NGL MARKETING EARNINGS ($2.2 MILLION INCREASE). Because of the time
increment between the production of NGLs and the sale of fractionated products,
NGL marketing operations generally benefit from rising product prices. The
steady increase in these prices during the first half of the current year,
compared with declines over the same period last year, caused a year-to-year
increase in marketing earnings
OTHER
PERSONNEL-REDUCTION-RELATED SALARY AND BENEFIT SAVINGS ($7.1 MILLION INCREASE).
These savings resulted from a personnel reduction program implemented during
fiscal 1999's fourth quarter.
PERFORMANCE UNIT EXPENSE ACCRUALS ($1.4 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 - were $1.4 million less than the
accruals during the first six months of the prior year.
FIDELITY INSURANCE PROCEEDS ($1.8 MILLION INCREASE). During the second quarter
of fiscal 2000, the Company collected $1.8 million of fidelity insurance
proceeds that related to losses incurred over a several-year period that ended
in 1993.
INTEREST EXPENSE INCURRED ($1.7 MILLION DECREASE). Interest expense incurred
rose $1.7 million during the first half of fiscal 2000 due to an increase in
the average debt balance and fees attributable to an ongoing program to
securitize accounts receivable that was begun in fiscal 1999's fourth quarter.
-17-
<PAGE> 20
EARNINGS FROM CONTINUING OPERATIONS - THREE MONTHS ENDED JULY 31, 1999
COMPARED WITH THREE MONTHS ENDED JULY 31, 1998
Earnings from continuing operations for the three-month periods ended July 31,
1999 and 1998 - both before and after unusual items - are summarized in the
table which follows. Earnings from continuing operations for fiscal 2000's
second quarter totaled $26.8 million, which compares with a loss of $4.2
million in the comparable prior-year period. Excluding the effects of unusual
items in both years, the current quarter's earnings totaled $19.6 million,
versus the prior-year period's loss of $4.8 million. The quarter-to-quarter
improvement was largely due to the factors discussed on page 15 coupled with a
period-to-period increase in natural gas sales prices.
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 .................... $ 3.2 $ 4.7 $ (14.8) $ (6.9) $ (4.2)
ELIMINATE IMPACT OF FISCAL 1999 UNUSUAL ITEM - Water
well litigation provision reversal (see page 9) ......... (1.0) -- -- (1.0) (.6)
-------- -------- -------- -------- --------
FISCAL 1999 AMOUNTS BEFORE UNUSUAL ITEMS ................... 2.2 4.7 (14.8) (7.9) (4.8)
-------- -------- -------- -------- --------
MAJOR INCREASES (DECREASES)
Lower geological and geophysical expenses .................. 4.9 -- -- 4.9 3.2
Higher natural gas sales price ............................. 3.8 -- -- 3.8 2.5
Lower natural gas sales volume ............................. (1.4) -- -- (1.4) (.9)
Higher oil and condensate sales price ...................... 1.4 -- -- 1.4 .9
Decreased exploratory well impairments ($.1 versus $2.7) ... 2.6 -- -- 2.6 1.7
Improved NGL margins ....................................... -- 6.1 -- 6.1 4.0
Higher NGL production volume ............................... -- .6 -- .6 .4
Increased NGL marketing earnings (see page 17) ............. -- 2.3 -- 2.3 1.5
Price-related increases in pipeline margins ................ -- 1.6 -- 1.6 1.0
Reduced operating expenses
Salary and benefits savings from personnel reductions ... 1.5 1.5 .9 3.9 2.5
Lower repairs and maintenance and other ................. 2.2 1.9 -- 4.1 2.6
Fiscal 2000 gains on compressor sales ...................... -- 1.8 -- 1.8 1.2
Fidelity insurance proceeds (see page 17) .................. -- -- 1.8 1.8 1.2
Other, net ................................................. 2.0 2.3 (.7) 3.6 2.6
-------- -------- -------- -------- --------
17.0 18.1 2.0 37.1 24.4
-------- -------- -------- -------- --------
FISCAL 2000 AMOUNTS BEFORE UNUSUAL ITEMS ................... 19.2 22.8 (12.8) 29.2 19.6
Gain from sale of Hell's Hole
area properties (see page 11) ........................... 11.5 -- -- 11.5 7.2
-------- -------- -------- -------- --------
FISCAL 2000 AMOUNTS AFTER UNUSUAL ITEMS .................... $ 30.7 $ 22.8 $ (12.8) $ 40.7 $ 26.8
======== ======== ======== ======== ========
</TABLE>
- --------------------------------------------------------
*Includes general and administrative expense and other expense.
EXPLORATION AND PRODUCTION OVERVIEW
Exclusive of unusual items, exploration and production segment operating
earnings of $19.2 million during fiscal 2000's second quarter were $17.0
million higher than those of the comparable prior-year period because of higher
natural gas prices, reductions in geological and geophysical expenses and
payroll and other operating expenses and reduced exploratory well impairments.
-18-
<PAGE> 21
LOWER GEOLOGICAL AND GEOPHYSICAL EXPENSES ($4.9 MILLION INCREASE). For the
reasons discussed on page 16, geological and geophysical expenses during the
second quarter of fiscal 2000 of $1.3 million were well below the $6.2 million
of the comparable prior-year period, improving operating earnings by $4.9
million.
HIGHER NATURAL GAS SALES PRICE ($3.8 MILLION INCREASE). During fiscal 2000's
second quarter, the Company's natural gas sales price averaged $2.40 per Mcf,
$.15 (7%) above the prior-year period's $2.25, increasing operating earnings by
$3.8 million.
LOWER NATURAL GAS SALES VOLUME ($1.4 MILLION DECREASE). Largely because of
curtailed drilling activity, natural gas sales averaged 236.9 MMcf per day
during fiscal 2000's second quarter, 8.3 MMcf (3%) below the 245.2 MMcf of the
prior year's comparable period, reducing operating earnings by $1.4 million.
HIGHER OIL AND CONDENSATE PRICE ($1.4 MILLION INCREASE). The Company's sales
price for oil and condensate averaged $16.44 per barrel during fiscal 2000's
second quarter, up from the prior period's $12.33, increasing operating
earnings by $1.4 million.
GAS SERVICES OVERVIEW
Gas services operating earnings increased $18.1 million to $22.8 million during
the second quarter of fiscal 2000. This occurred largely because of
price-related improvements in gas processing and pipeline margins and
reductions in personnel and other operating expenses.
IMPROVED NGL MARGINS ($6.1 MILLION INCREASE). The average price for NGLs
produced during fiscal 2000's second quarter of $13.33 per barrel was 30% above
the prior-year period's $10.22, increasing NGL revenues by $11.5 million.
Because of the impact of the period's higher NGL and natural gas prices on
producer payments, feedstock costs were also higher, increasing production
costs by $5.4 million. The net margin improvement was $6.1 million.
HIGHER NGL PRODUCTION VOLUME ($.6 MILLION INCREASE). NGL production averaged
43,500 barrels per day during fiscal 2000's second quarter, 2,700 barrels (7%)
higher than in the comparable period of the prior year, increasing operating
earnings by $.6 million.
FISCAL 2000 GAINS ON COMPRESSOR SALES ($1.8 MILLION INCREASE). During the
second quarter of fiscal 2000, the Company sold to third parties certain
compression equipment for $8.7 million in cash. Gains on these sales totaled
$1.8 million.
-19-
<PAGE> 22
Part II - Other Information
ITEM 1. LEGAL PROCEEDINGS
See Note 6 of Notes to Unaudited Consolidated Financial Statements.
ITEM 4. SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS
The annual meeting of stockholders of Mitchell Energy & Development Corp.
was held on June 30, 1999 for the purpose of electing a Board of 11 directors
and to consider and act upon proposals to adopt the Company's 1999 Stock Option
Plan and the appointment of independent public accountants. Proxies for the
meeting were solicited pursuant to Section 14A of the Securities Exchange Act
of 1934, and there was no solicitation in opposition to the Company's
solicitations. Each of the nominees for the Board of Directors was elected by
the Class A common stockholders with no nominee receiving fewer than 20,479,508
votes.
Stockholders approved the adoption of the Company's 1999 Stock Option
Plan. The vote was as follows:
<TABLE>
<CAPTION>
Per-
Number cent
---------- -----
<S> <C> <C>
Shares voted "for"................................ 17,441,357 81.70
Shares voted "against"............................ 2,018,643 9.46
Shares abstaining................................. 203,130 .95
Broker non votes.................................. 1,684,056 7.89
</TABLE>
Stockholders also approved the appointment of Arthur Andersen LLP,
independent public accountants, to examine the accounts of the Company for the
fiscal year ending January 31, 2000. The vote was as follows:
<TABLE>
<CAPTION>
Per-
Number cent
---------- -----
<S> <C> <C>
Shares voted "for"................................ 21,330,285 99.92
Shares voted "against"............................ 11,808 .06
Shares abstaining................................. 5,093 .02
</TABLE>
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 six-month period
ended July 31, 1999.
-20-
<PAGE> 23
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: September 13, 1999 By /s/ Philip S. Smith
---------------------------------------
Philip S. Smith
Senior Vice President - Administration
and Chief Financial Officer
-21-
<PAGE> 24
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Description
- ------ -----------
<S> <C>
27 Financial Data Schedule
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> JAN-01-2000
<PERIOD-END> JUL-31-1999
<CASH> 19,157
<SECURITIES> 0
<RECEIVABLES> 40,865
<ALLOWANCES> 304
<INVENTORY> 10,311
<CURRENT-ASSETS> 81,263
<PP&E> 2,462,762
<DEPRECIATION> 1,452,921
<TOTAL-ASSETS> 1,125,270
<CURRENT-LIABILITIES> 149,139
<BONDS> 400,367
0
0
<COMMON> 5,386
<OTHER-SE> 339,421
<TOTAL-LIABILITY-AND-EQUITY> 1,125,270
<SALES> 387,887
<TOTAL-REVENUES> 387,887
<CGS> 0
<TOTAL-COSTS> 311,594
<OTHER-EXPENSES> 8,620
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 17,902
<INCOME-PRETAX> 49,771
<INCOME-TAX> 17,280
<INCOME-CONTINUING> 32,491
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 32,491
<EPS-BASIC> .65<F1>
<EPS-DILUTED> .65<F2>
<FN>
<F1>CLASS A BASIC .65
CLASS B BASIC .67
<F2>CLASS A DILUTED .65
CLASS B DILUTED .67
</FN>
</TABLE>
