<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 SEPTEMBER 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-6959
MITCHELL ENERGY & DEVELOPMENT CORP.
(Exact name of registrant as specified in 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 October 31, 2000 .... 49,513,271
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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................... 11
Part II - Other Information
Item 1. Legal Proceedings......................................... 18
Item 6. Exhibits and Reports on Form 8-K.......................... 18
</TABLE>
DEFINITIONS. As used herein, "MMBtu" means million British thermal units, "Mcf"
means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion
cubic feet, "Tcf" means trillion cubic feet, "Bbl" means barrel, "MMBbls" means
million barrels, "NGL" or "NGLs" means natural gas liquids 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 and pipeline throughput include 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 accounting principles generally accepted in the United States
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 Exhibit 99 to the Company's Transition Report on Form
10-K filed on October 13, 2000 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>
SEPTEMBER 30, DECEMBER 31,
2000 1999
------------- ------------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents ...................................................... $ 21,441 $ 24,024
Trade receivables .............................................................. 124,827 42,895
Inventories .................................................................... 21,250 5,160
Other .......................................................................... 5,629 5,922
----------- -----------
Total current assets ...................................................... 173,147 78,001
----------- -----------
PROPERTY, PLANT AND EQUIPMENT, at cost less accumulated depreciation,
depletion and amortization of $1,553,642 and $1,490,076
Exploration and production
Oil and gas properties ....................................................... 755,775 687,720
Support equipment and facilities ............................................. 12,641 13,217
Gas services (including investments in equity partnerships) (Note 2)
Natural gas processing ....................................................... 90,021 105,527
Natural gas gathering ........................................................ 182,862 153,796
Other ........................................................................ 91,054 86,091
Corporate ...................................................................... 2,891 3,947
----------- -----------
1,135,244 1,050,298
----------- -----------
LONG-TERM INVESTMENTS AND OTHER ASSETS ......................................... 39,932 35,380
----------- -----------
$ 1,348,323 $ 1,163,679
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Oil and gas proceeds payable ................................................... $ 133,881 $ 70,320
Accounts payable ............................................................... 57,375 40,962
Income taxes payable ........................................................... 10,196 5,576
Accrued liabilities ............................................................ 53,385 36,722
----------- -----------
Total current liabilities ................................................. 254,837 153,580
----------- -----------
LONG-TERM DEBT (Note 3) ........................................................ 300,342 379,267
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes .......................................................... 186,134 158,307
Retirement obligations ......................................................... 69,264 71,882
Deferred income and other ...................................................... 15,003 15,469
----------- -----------
270,401 245,658
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 5)
STOCKHOLDERS' EQUITY
Preferred stock, $.10 par value (authorized 10,000,000 shares; none issued)
Common stock, $.10 par value (authorized 200,000,000 shares) ................... 5,386 5,386
Additional paid-in capital ..................................................... 144,448 143,636
Retained earnings .............................................................. 476,424 346,192
Other comprehensive loss ....................................................... (5,890) (5,890)
Treasury stock, at cost ........................................................ (97,625) (104,150)
----------- -----------
522,743 385,174
----------- -----------
$ 1,348,323 $ 1,163,679
=========== ===========
</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 September 30 Ended September 30
-------------------- -----------------------
2000 1999 2000 1999
--------- -------- ----------- ---------
<S> <C> <C> <C> <C>
REVENUES
Exploration and production (including a gain of $11,527 from
sale of Hell's Hole area properties in 1999's second quarter) (Note 6) ..... $147,460 $ 70,788 $ 343,119 $185,668
Gas services (including a gain of $4,884 from an
asset exchange in 2000's first quarter) (Note 2) ........................... 298,630 194,685 778,242 450,033
-------- -------- ---------- --------
446,090 265,473 1,121,361 635,701
-------- -------- ---------- --------
OPERATING COSTS AND EXPENSES (including personnel
reduction program costs of $15,652 in 1999's first quarter) (Note 6)
Exploration and production (net of litigation provision reversals
of $1,200 and $9,000, respectively, in the nine-month periods) (Note 6) .... 63,254 44,094 171,658 133,064
Gas services .................................................................. 264,937 166,957 671,008 402,057
-------- -------- ---------- --------
328,191 211,051 842,666 535,121
-------- -------- ---------- --------
SEGMENT OPERATING EARNINGS (Note 6) ........................................... 117,899 54,422 278,695 100,580
General and administrative expense (including personnel
reduction program costs of $8,848 in 1999's first quarter) ................. 12,758 7,226 29,193 29,549
-------- -------- ---------- --------
TOTAL OPERATING EARNINGS ...................................................... 105,141 47,196 249,502 71,031
-------- -------- ---------- --------
OTHER EXPENSE
Interest expense .............................................................. 7,139 8,141 22,191 26,378
Other, net .................................................................... (4,195) 16 (8,442) (4,582)
-------- -------- ---------- --------
2,944 8,157 13,749 21,796
-------- -------- ---------- --------
EARNINGS BEFORE INCOME TAXES .................................................. 102,197 39,039 235,753 49,235
INCOME TAXES (after $6,293 reversal of certain
prior years' deferred taxes in the 2000 periods) (Note 4) .................. 27,775 13,143 73,910 16,471
-------- -------- ---------- --------
NET EARNINGS .................................................................. $ 74,422 $ 25,896 $ 161,843 $ 32,764
======== ======== ========== ========
NET EARNINGS PER SHARE (Note 9)
Basic ......................................................................... $ 1.51 $ .53 $ 3.29 $ .67
Diluted ....................................................................... 1.48 .53 3.25 .67
AVERAGE COMMON SHARES OUTSTANDING
Basic ......................................................................... 49,296 49,117 49,207 49,117
Diluted ....................................................................... 50,280 49,208 49,809 49,187
</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 September 30, 2000
(dollar amounts in thousands)
<TABLE>
<CAPTION>
Additional Other
Common Paid-in Retained Comprehensive Treasury
DOLLAR AMOUNTS Total Stock Capital Earnings Loss Stock
-------------- ---------- --------- ---------- ---------- ------------- ---------
<S> <C> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1999 .............. $ 385,174 $ 5,386 $ 143,636 $ 346,192 $ (5,890) $(104,150)
Net earnings ............................ 161,843 -- -- 161,843 -- --
Regular cash dividends (cents per share -
25.25 on Class A, 26.5 on Class B and
13.25 on combined shares) (Note 8) ... (19,300) -- -- (19,300) -- --
Special cash dividends (25 cents
per share on Class A and Class B) .... (12,311) -- -- (12,311) -- --
Treasury stock purchases ................ (2,768) -- -- -- -- (2,768)
Exercises of stock options .............. 10,105 -- 812 -- -- 9,293
--------- --------- --------- --------- --------- ---------
BALANCE, SEPTEMBER 30, 2000 ............. $ 522,743 $ 5,386 $ 144,448 $ 476,424 $ (5,890) $ (97,625)
========= ========= ========= ========= ========= =========
</TABLE>
============================
<TABLE>
<CAPTION>
Common Stock Issued Treasury Stock Total
-------------------------- ------------------------- Shares
SHARE AMOUNTS Class A Class B Class A Class B Outstanding
------------- ----------- ------------ ---------- ---------- -----------
<S> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1999 .................. 23,978,072 29,878,072 1,656,437 3,082,450 49,117,257
Treasury stock purchases .................... -- -- 66,800 32,000 (98,800)
Exercises of stock options .................. -- -- (245,978) (167,642) 413,620
Other ....................................... (2) (2) -- -- (4)
Reclassification of common stock (Note 8).... 29,878,070 (29,878,070) 2,946,808 (2,946,808) --
---------- ---------- --------- --------- ----------
BALANCE, SEPTEMBER 30, 2000 ................. 53,856,140 -- 4,424,067 -- 49,432,073
========== ========== ========= ========= ==========
</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
September 30
-----------------------
2000 1999
---------- ----------
<S> <C> <C>
OPERATING ACTIVITIES
Net earnings ........................................................... $ 161,843 $ 32,764
Adjustments to reconcile net earnings to
cash provided by operating activities
Depreciation, depletion and amortization ......................... 105,290 82,112
Deferred income taxes ............................................ 30,157 7,934
Exploration expenses (including exploratory well impairments) .... 8,271 5,822
Distributions in excess of earnings of equity investees .......... 1,641 7,099
Accrued personnel reduction program costs ........................ -- 17,620
Gains from sales of assets ....................................... (4,884) (11,527)
Water well litigation provision reversals ........................ (1,200) (9,000)
Other, net ....................................................... (5,772) (9,760)
--------- ---------
295,346 123,064
Changes in operating assets and liabilities ...................... (15,490) 37,081
--------- ---------
Cash provided by operating activities ............................ 279,856 160,145
--------- ---------
INVESTING ACTIVITIES
Capital and exploratory expenditures
Total on accrual basis .............................................. (214,433) (94,839)
Adjustment to cash basis ............................................ 20,548 (1,667)
--------- ---------
(193,885) (96,506)
Proceeds from dispositions of property, plant and equipment ............ 15,763 40,936
Other, net ............................................................. 896 7,377
--------- ---------
Cash used for investing activities ............................... (177,226) (48,193)
--------- ---------
FINANCING ACTIVITIES
Debt repayments ........................................................ (78,925) (100,000)
Proceeds from issuance of debt ......................................... -- 21,500
Cash dividends paid .................................................... (31,295) (18,687)
Treasury stock purchases ............................................... (2,768) --
Other .................................................................. 7,775 (317)
--------- ---------
Cash used for financing activities ............................... (105,213) (97,504)
--------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS ....................... (2,583) 14,448
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD ......................... 24,024 15,333
--------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD ............................... $ 21,441 $ 29,781
========= =========
</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
September 30, 2000
(1) ACCOUNTING POLICIES
Mitchell Energy & Development Corp. and its majority-owned subsidiaries (the
"Company") constitute a large independent energy company engaged in the
exploration for and development and production of natural gas, natural gas
liquids, and crude oil and condensate. The Company also operates natural gas
gathering systems in Texas and markets natural gas through purchase and resale
activities.
The consolidated financial statements include the accounts of the Company
after elimination of all significant intercompany accounts and transactions. The
equity method of accounting is used for investments in 20%-to-50%-owned
entities.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosures of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
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 nine-month periods ended September 30, 2000 and 1999.
The Financial Accounting Standards Board issued Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" in June 1998. The statement, which the Company must adopt effective
January 1, 2001, generally requires that derivatives be recognized at fair value
as assets or liabilities and that changes in fair value be recorded in earnings
or other comprehensive income. The Company's infrequent use of derivatives makes
it unlikely that the adoption of this statement will have a significant impact
on its financial position or results of operations.
-6-
<PAGE> 9
(2) PARTNERSHIP INVESTMENTS
A summary of the Company's net investments in partnerships at September 30, 2000
and December 31, 1999 and its equity in their pretax earnings for the nine-month
periods ended September 30, 2000 and 1999 follows (in thousands):
<TABLE>
<CAPTION>
Equity in
Net Investment Pretax Earnings
---------------------------- ----------------------------
Percent September 30, December 31, September 30, September 30,
Owned 2000 1999 2000 1999
------- ------------- ------------ ------------- -------------
<S> <C> <C> <C> <C> <C>
NATURAL GAS PROCESSING
C&L Processors Partnership (C&L) .......... 50* $ -- $ 25,353 $ 724 $ 2,802
U.P. Bryan Plant .......................... 45* -- 2,093 4,640 4,748
--------- --------- --------- ---------
-- 27,446 5,364 7,550
--------- --------- --------- ---------
GAS GATHERING AND MARKETING
Austin Chalk Natural Gas
Marketing Services (Austin Chalk) ...... 45* -- (93) 3 905
Ferguson-Burleson County Gas
Gathering System (Ferguson-Burleson) ... 45* -- 36,449 110 3,998
Louisiana Chalk Gathering System .......... 50 15,216 15,987 (771) (649)
Others .................................... 580 448 132 74
--------- --------- --------- ---------
15,796 52,791 (526) 4,328
--------- --------- --------- ---------
OTHER
Belvieu Environmental Fuels ............... 33.33 61,021 56,043 12,704 5,687
Gulf Coast Fractionators .................. 38.75 28,558 28,493 2,243 2,003
--------- --------- --------- ---------
89,579 84,536 14,947 7,690
--------- --------- --------- ---------
$ 105,375 $ 164,773 $ 19,785 $ 19,568
========= ========= ========= =========
</TABLE>
----------
* Prior to the asset exchange on March 31, 2000 discussed below.
For the applicable periods, the Company's net investment in these entities is
reported as property, plant and equipment in the consolidated balance sheets and
its equity in their pretax earnings is reported as revenues in the consolidated
statements of earnings, each under the gas services caption.
During August 1999, C&L distributed the Jameson gas processing plant and
related facilities to its partners, Conoco and a wholly-owned subsidiary of the
Company. Effective October 1, 1999, the Jameson facilities became wholly-owned
when the Company purchased Conoco's 50% interest for approximately $23,900,000.
As a result, these operations were consolidated and ceased being reported as
part of C&L thus reducing C&L's operations to facilities located in Oklahoma.
On March 31, 2000, the Company exchanged its share of the gathering and
processing assets of C&L (non-operated Oklahoma facilities having a net book
value of $26,946,000) for Duke Energy Field Services, Inc.'s share of the
Company-operated gathering and processing assets of the U.P. Bryan Plant, Austin
Chalk and Ferguson-Burleson partnerships and $11,666,000 in cash. Each of the
four partnerships distributed all of their operating assets to their partners
prior to the exchange and ceased operations. A gain of $4,884,000 was recognized
in connection with the exchange.
For the applicable periods during which the Company held partnership
interests in the above-listed entities, summarized earnings information (on a
100% basis) for these entities for the three- and nine-month periods ended
September 30, 2000 and 1999 follows (in thousands):
<TABLE>
<CAPTION>
Three Months Nine Months
-------------------- -------------------
2000 1999 2000 1999
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Revenues......................... $ 88,873 $169,689 $326,753 $431,553
Operating earnings............... 7,855 23,158 54,616 52,339
Pretax earnings.................. 8,162 22,060 55,081 43,620
</TABLE>
-7-
<PAGE> 10
(3) LONG-TERM DEBT
During August 2000, the Company repurchased at a small discount in the open
market $13,925,000 principal amount of its 6 3/4% senior notes due February
2004. At September 30, 2000, the Company's outstanding debt consisted of
$300,342,000 of unsecured parent company senior notes, the proceeds of which
have been advanced to the operating subsidiaries. At that date, no amounts were
outstanding under the Company's $250,000,000 bank revolving credit facility that
terminates in July 2003, when any amounts then outstanding are payable. Interest
rates, which generally are based on spreads over LIBOR, vary based on the
highest of the ratings given the Company's senior notes by two specified rating
agencies. The Company pays commitment fees on the unused portion of this
facility.
The 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 $246,332,000 at September 30, 2000.
(4) INCOME TAXES
Income taxes for the nine-month periods ended September 30, 2000 and 1999
consisted of the following (in thousands):
<TABLE>
<CAPTION>
2000 1999
-------- --------
<S> <C> <C>
Current - Federal ....................................... $ 43,467 $ 8,218
State ......................................... 286 319
-------- --------
43,753 8,537
-------- --------
Deferred - Federal ...................................... 36,191 7,899
State ........................................ 259 35
Reversal of prior years' state taxes, net
of deferred Federal taxes of $3,388 ....... (6,293) --
-------- --------
30,157 7,934
-------- --------
$ 73,910 $ 16,471
======== ========
</TABLE>
The prior-year tax reversal of $6,293,000 set out above resulted from a
reorganization of exploration and production operations' legal structure that
allowed certain previously provided deferred state income taxes to be reversed.
Estimated annual tax rates of 34.02% (excluding the impact of the reversal
discussed above) and 33.45%, respectively, were used in computing the income tax
provisions for the nine-month periods ended September 30, 2000 and 1999. The
differences between those rates and the 35% statutory Federal income tax rate
were principally the result of the interplay of Federal tax credits and charges
for state income taxes.
(5) COMMITMENTS AND CONTINGENCIES
The Company is party to 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 March 1999, the governor
of California ordered that the use of MTBE be phased out in that state over a
four-year period. In July 1999, a national advisory panel formed by the EPA
recommended that the use of MTBE be reduced, and in August 1999 a group of seven
northeastern states took steps that would lead to the phase-out of MTBE usage
over a three-year period. Restrictions on the use of MTBE could significantly
impact future operations of the MTBE plant partially owned by the Company.
However, that facility, which was built in the mid 1990s for approximately
$225,000,000, was originally designed in a manner that allows it - with moderate
expenditures - to be converted to the production of other products. It is not
possible at this time to determine the ultimate impact, if any, of this matter
on the Company's financial position or future results of operations.
-8-
<PAGE> 11
(6) SEGMENT INFORMATION
Selected industry segment data for the indicated periods follows (in thousands):
<TABLE>
<CAPTION>
Segment Total Capital
Outside Intersegment Operating Operating Expenditures
Revenues Revenues Earnings Earnings DD&A (a)
---------- ------------ ----------- -------------- ---------- ------------
<S> <C> <C> <C> <C> <C> <C>
NINE MONTHS ENDED SEPTEMBER 30, 2000
EXPLORATION AND PRODUCTION
Operations ....................................... $ 343,119 $ -- $ 170,261 $ 163,272 $ 85,512 $ 166,794
Water well litigation provision reversal ......... -- -- 1,200 1,200 -- --
---------- ---------- ---------- ---------- ---------- ----------
343,119 -- 171,461 164,472 85,512 166,794
---------- ---------- ---------- ---------- ---------- ----------
GAS SERVICES
Natural gas processing ........................... 475,994 148,493 64,179 61,924 4,813 17,016
Natural gas gathering and marketing .............. 282,407 389,760 23,785 21,237 13,632 28,142
Other ............................................ 14,957 -- 14,386 14,198 80 1,763
Gain from asset exchange (Note 2) ................ 4,884 -- 4,884 4,884 -- --
---------- ---------- ---------- ---------- ---------- ----------
778,242 538,253 107,234 102,243 18,525 46,921
---------- ---------- ---------- ---------- ---------- ----------
CORPORATE ........................................ -- -- -- (17,213)(b) 1,253 718
---------- ---------- ---------- ---------- ---------- ----------
$1,121,361 $ 538,253 $ 278,695 $ 249,502 $ 105,290 $ 214,433
========== ========== ========== ========== ========== ==========
NINE MONTHS ENDED SEPTEMBER 30, 1999
EXPLORATION AND PRODUCTION
Operations ....................................... $ 174,141 $ -- $ 40,601 $ 32,903 $ 69,914 $ 82,041
Gain from sale of Hell's Hole area properties .... 11,527 -- 11,527 11,527 -- --
Water well litigation provision reversal ......... -- -- 9,000 9,000 -- --
Personnel reduction program costs ................ -- -- (8,524) (8,524) -- --
---------- ---------- ---------- ---------- ---------- ----------
185,668 -- 52,604 44,906 69,914 82,041
---------- ---------- ---------- ---------- ---------- ----------
GAS SERVICES
Natural gas processing ........................... 250,060 52,425 26,739 24,570 2,758 4,732
Natural gas gathering and marketing .............. 192,431 164,057 21,427 18,960 7,466 7,638
Other ............................................ 7,542 -- 6,938 6,692 80 184
Personnel reduction program costs ................ -- -- (7,128) (7,128) -- --
---------- ---------- ---------- ---------- ---------- ----------
450,033 216,482 47,976 43,094 10,304 12,554
---------- ---------- ---------- ---------- ---------- ----------
CORPORATE ........................................ -- -- -- (16,969)(b) 1,894 244
---------- ---------- ---------- ---------- ---------- ----------
$ 635,701 $ 216,482 $ 100,580 $ 71,031 $ 82,112 $ 94,839
========== ========== ========== ========== ========== ==========
THREE MONTHS ENDED SEPTEMBER 30, 2000
EXPLORATION AND PRODUCTION ....................... $ 147,460 $ -- $ 84,206 $ 81,820 $ 30,211 $ 69,997
---------- ---------- ---------- ---------- ---------- ----------
GAS SERVICES
Natural gas processing ........................... 170,972 65,686 19,732 19,037 1,593 11,715
Natural gas gathering and marketing .............. 124,365 172,288 10,867 10,054 4,835 14,003
Other ............................................ 3,293 -- 3,094 3,043 27 1,594
---------- ---------- ---------- ---------- ---------- ----------
298,630 237,974 33,693 32,134 6,455 27,312
---------- ---------- ---------- ---------- ---------- ----------
CORPORATE ........................................ -- -- -- (8,813)(b) 389 485
---------- ---------- ---------- ---------- ---------- ----------
$ 446,090 $ 237,974 $ 117,899 $ 105,141 $ 37,055 $ 97,794
========== ========== ========== ========== ========== ==========
THREE MONTHS ENDED SEPTEMBER 30, 1999
EXPLORATION AND PRODUCTION ....................... $ 70,788 $ -- $ 26,694 $ 24,102 $ 22,138 $ 37,832
---------- ---------- ---------- ---------- ---------- ----------
GAS SERVICES
Natural gas processing ........................... 108,602 24,265 17,264 16,572 889 1,957
Natural gas gathering and marketing .............. 83,226 62,373 7,811 7,023 2,396 2,528
Other ............................................ 2,857 -- 2,653 2,574 27 92
---------- ---------- ---------- ---------- ---------- ----------
194,685 86,638 27,728 26,169 3,312 4,577
---------- ---------- ---------- ---------- ---------- ----------
CORPORATE ........................................ -- -- -- (3,075)(b) 580 138
---------- ---------- ---------- ---------- ---------- ----------
$ 265,473 $ 86,638 $ 54,422 $ 47,196 $ 26,030 $ 42,547
========== ========== ========== ========== ========== ==========
</TABLE>
----------
(a) On accrual basis, including exploratory expenses and acquisitions.
(b) General corporate expenses; amount for 1999's nine-month period includes
personnel reduction program costs of $8,848.
-9-
<PAGE> 12
The Company's reported business segments are based on the organizational
structure used by management to assess performance and make resource allocation
decisions. The Company's three principal business segments are: exploration and
production, natural gas processing, and gas gathering and marketing. Exploration
and production segment operations include the exploration for and development
and production of natural gas and oil. Natural gas processing segment operations
include the extraction of natural gas liquids from natural gas processed at
facilities owned by the Company and third parties. The gas gathering and
marketing segment operates Company-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 recorded on the sale.
After entering into defense cost reimbursement agreements with insurance
carriers during January 2000 and March 1999, water well litigation provision
reversals of $1,200,000 and $9,000,000, respectively, were recorded during the
first quarters of 2000 and 1999.
During the first quarter of 1999, the Company completed a personnel
reduction program which reduced its full-time employment level by 235 jobs.
Aggregate pretax costs of this program - including $8,848,000 reported as
general and administrative expense - totaled $24,500,000. Of these costs,
$17,620,000 represented the present value of incremental pension and retiree
medical benefits provided under a voluntary incentive retirement program offered
to 127 employees (114 of whom accepted). Cash costs of severance and other
benefits totaled $6,880,000. The majority of the cash costs had been paid by
March 31, 1999, and no accrued liability for such costs remained at December 31,
1999.
(7) SUPPLEMENTAL CASH FLOW INFORMATION
Interest paid totaled $27,853,000 and $34,627,000 during the nine-month periods
ended September 30, 2000 and 1999. Income taxes paid during the nine-month
period ended September 30, 2000 totaled $39,135,000; income tax refunds totaling
$4,366,000 were collected in the comparable prior-year period. Other than the
asset exchange discussed in Note 2, there were no significant non-cash investing
or financing activities during the nine- month periods ended September 30, 2000
and 1999.
(8) COMMON STOCK
In June 2000, the Company's stockholders voted to combine its two classes of
common stock into a single class of voting common stock by reclassifying each
share of Class B common stock into one share of Class A common stock. Also, the
number of authorized shares of Class A common stock was increased from
100,000,000 to 200,000,000.
(9) EARNINGS PER SHARE
All earnings per share amounts are presented on a single class basis to give
effect to the June 2000 stock reclassification. The following table reconciles
the weighted average shares outstanding used in the basic and diluted earnings
per share computations for the three- and nine-month periods ended September 30,
2000 and 1999 (in thousands):
<TABLE>
<CAPTION>
Three Months Nine Months
----------------- -----------------
2000 1999 2000 1999
------ ------ ------ ------
<S> <C> <C> <C> <C>
Used in basic computations .......... 49,296 49,117 49,207 49,117
Dilutive effect of stock options .... 984 91 602 70
------ ------ ------ ------
Used in diluted computations ........ 50,280 49,208 49,809 49,187
====== ====== ====== ======
</TABLE>
Excluded from these computations because their effect would have been
antidilutive were stock options covering 1,722,633 shares for the three- and
nine-month periods ended September 30, 1999.
(10) STOCK OPTIONS AND BONUS UNITS
On May 1, 2000, stock options covering 453,100 shares and 342,800 bonus units
were issued to employees at option/floor prices of $23.9375. Like previous
grants, these awards vest in three equal annual installments and have ten-year
lives.
-10-
<PAGE> 13
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; and unexpected changes in competitive and economic conditions,
government regulations, technology and other factors.
LIQUIDITY AND CAPITAL RESOURCES
OVERVIEW. The Company's earnings have risen steadily over the last six quarters.
Net earnings for 2000's third quarter were $74.4 million ($1.51 per basic
share), the highest quarterly earnings in the Company's history. Contributing to
these strong upward trends were sharp rises in energy prices and the Company's
natural gas and NGL production volumes and its lower overall cost structure
after a personnel reduction program undertaken early in 1999.
While the Company's earnings and cash flows are affected by many things,
energy prices are clearly one of the most significant. The following table shows
the Company's quarterly average sales prices for the first three quarters of
2000 and the prior two years:
<TABLE>
<CAPTION>
Crude Oil and
Natural Gas (per Mcf) Condensate (per Bbl) NGLs (per Bbl)
--------------------------- --------------------------- ---------------------------
2000 1999 1998 2000 1999 1998 2000 1999 1998
------ ------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
First quarter......... $ 2.89 $ 1.79 $ 2.29 $26.93 $11.06 $14.53 $21.19 $ 9.55 $11.64
Second quarter........ 3.65 2.25 2.25 27.52 15.46 12.92 19.65 12.56 10.63
Third quarter......... 4.50 2.79 2.01 30.29 19.67 12.15 22.20 16.36 9.83
Fourth quarter........ 2.82 2.07 22.91 10.78 17.39 9.63
Fiscal year........... 2.42 2.15 17.17 12.60 14.20 10.48
</TABLE>
Prices fell in 1998 to low points not seen for oil and NGLs since 1986 as
worldwide oil production rose during a period of relatively weak demand and
inventories reached unusually high levels. During 1999, worldwide oil production
fell as OPEC and other countries adopted lower production targets. Excess
inventories were worked down and prices for oil and NGLs rose steadily. This
trend continued in 2000 when oil and NGL prices rose to levels not seen in many
years. Natural gas prices - while not moving steadily upward - were relatively
strong in 1999. As shown in the table above, gas prices continued to strengthen
in 2000 due to reduced deliverability, low storage levels and strong demand.
After taking actions late in 1998 to sharply reduce operating costs and
capital expenditures to position itself to operate in a low-energy-price
environment, the Company began taking steps late in the second quarter of 1999
to substantially increase its development drilling and well recompletion
programs in the Barnett Shale area of North Texas when the Company determined
that its development costs could be lowered through the use of light sand
fracture technology and the price outlook for natural gas improved. Primarily
because of an ongoing acceleration of the Barnett Shale development program, the
Company's natural gas sales have been rising sharply on a quarter-to-quarter
basis. Such sales averaged a record 319.7 MMcf per day in 2000's third quarter,
38% above the level during the prior-year's comparable period. Six rigs were
drilling in the Barnett through September, and the Company drilled 111 wells
there in the first nine months of 2000 versus 66 for all of 1999. Plans call for
increasing to an 8-rig program in the Barnett during November and to a 12-rig
program early in
-11-
<PAGE> 14
2001 to take advantage of the improved price outlook and the Company's large
backlog of undrilled locations. Also, an extensive well rework/refracturing
program is in progress there. Looking forward, the Company's gas sales volumes
are expected to grow at a compounded annual rate of at least 15% over the next
four years. This growth will be achieved almost exclusively through low-risk
development drilling and is not contingent upon realizing the high energy prices
received in recent periods.
With improved NGL economics, the acquisition in October 1999 of the other
50% interest in the Jameson plant and increased gathering throughput, NGL
production volumes increased during 1999 and rose further during 2000. NGL
production averaged 51,500 barrels per day during 2000's first nine months, a
level not reached since the early 1990s when five times as many plants were
being operated. An exchange of the Company's interests in several Oklahoma
systems for Duke Energy's 55% interest in jointly owned processing and gathering
assets in the Austin Chalk area of Central Texas was closed on March 31, 2000.
As a result, the Company's involvement in the operations of four partnerships
ceased, and it now has total ownership and operating control of all its major
gas processing and gathering facilities. This lowered operating costs and gives
the Company more flexibility in using these facilities. NGL production should
increase further with the completion in December of an expansion of the
Bridgeport plant that will increase its processing capacity from 210 to 310 MMcf
per day. With the implementation of the 12-rig drilling program in the Barnett,
the Company expects the Bridgeport plant expansion to be completely loaded
during the first quarter of 2001 when the Company's daily NGL production could
reach the 60,000-barrels-per-day level. Planning currently is underway for
another 100 MMcf per day expansion of the Bridgeport plant to allow it to handle
further expected increases in Barnett Shale production.
The Company grew its gathering and processing volumes in 2000 by capturing
a large portion of the new gas supplies being developed along its systems by the
Company and by third parties. Third quarter pipeline throughput averaged 818
MMcf per day, up 53% from the comparable prior-year period. The increase was
principally due to increased Barnett Shale production, acquisition of Duke's
55% interest in the Texas Chalk systems, addition of quantities for the Jameson
system and added production along the Vanderbilt and Monco systems.
CAPITAL AND EXPLORATORY EXPENDITURES. The Company's original capital budget for
2000 totaled $222.1 million, 58.8% above the $139.9 million spent in 1999
(excluding the Jameson acquisition), or 26% above the annualized spending level
in 1999's last half. Because of the favorable outlook for energy prices, a
desire to further increase drilling in the Barnett Shale and other areas and a
need to further augment gas services' infrastructure in North Texas, the 2000
budget was subsequently raised by $87.6 million to $309.7 million. Exploration
and production budget increases of $40.8 million were primarily for drilling,
recompletion work and acquisitions of additional acreage in North Texas and for
drilling and rework activities in the Lake Creek and Personville areas. The gas
services budget increases of $46.6 million provided for the expansion of the
Bridgeport plant's processing capacity to 310 MMcf per day, construction of a
residue header to allow increased gas sales to intrastate markets, and
improvements to the Bridgeport gathering system to add capacity and reduce
bottlenecking. Third quarter spending totaled $97.8 million, up from $66.9
million and $49.7 million, respectively, in the second and first quarters. A
summary by quarter of 2000's actual capital and exploratory expenditures and the
revised budget for the full year follows (in millions):
<TABLE>
<CAPTION>
Actual Spending
---------------------------------------
Nine- Revised
First Second Third Month Annual
Quarter Quarter Quarter Totals Budget
------- ------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Exploration and production ............... $ 42.5 $ 54.3 $ 70.0 $ 166.8 $ 223.6
Gas services ............................. 7.2 12.4 27.3 46.9 83.9
Corporate ................................ -- .2 .5 .7 2.2
------- ------- -------- -------- --------
$ 49.7 $ 66.9 $ 97.8 $ 214.4 $ 309.7
======= ======= ======== ======== ========
</TABLE>
With the accelerated drilling program and inflation in drilling costs, calendar
2000 capital spending may exceed the current budget somewhat.
-12-
<PAGE> 15
FINANCING MATTERS. Cash provided by operating activities totaled $279.9 million
during the first nine months of 2000. This, coupled with cash proceeds from the
asset exchange with Duke and sales of non-strategic assets, funded the capital
program and allowed long-term debt to be paid down by $79 million, to $300.3
million. During this period, 98,800 shares of treasury stock were repurchased at
an aggregate cost of $2.8 million under the stock buyback program that was
announced in April. At quarter-end, long-term debt comprised 36.5% of total debt
plus stockholders' equity, down from 49.6% at the beginning of the year. The
Company expects cash flows from operations to be sufficient to cover its
increased capital expenditures.
The Company has a $250 million bank revolving credit facility and a $25
million bank money-market facility. At September 30, 2000, no borrowings were
outstanding under these facilities. In August 2000, the Company retired $13.9
million of 6 3/4% senior notes that it repurchased at a small discount in the
open market. While the Company has no immediate plans to issue additional senior
notes or to increase the size of its bank credit facility, it has the borrowing
capacity to do so should business opportunities arise that require funding in
excess of the amount available under the existing bank credit facility ($250
million at September 30, 2000). Because of a receivable sales agreement that
lowers costs and eliminates the need to fund the Company's receivables with bank
borrowings, long-term debt and working capital balances were each $35 million
less at September 30, 2000 than they otherwise would have been.
DISCLOSURES ABOUT MARKET RISK. The Company's major market risk exposure involves
prices for crude oil, natural gas and NGLs. Realized prices for these products
are driven primarily by prevailing world crude oil prices and domestic natural
gas prices. Such prices historically have been volatile (as shown by the table
on page 11), 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 $26 million and its after-tax annual net earnings by $17 million.
The Company is partially hedged with respect to natural gas prices since
besides being a seller it also purchases gas in connection with its gas
processing operations (after the recent asset exchange, such purchases normally
should range from 35% to 40% of gas sales). Since it has this physical hedge,
the Company rarely enters into hedging transactions to manage its exposure to
price fluctuations. It does not hold or issue derivative instruments for trading
purposes. The Company had no open hedge positions at September 30, 2000, and its
hedging activities during the last three years were insignificant.
The Company's exposure to changing interest rates is limited since all its
long-term debt at September 30, 2000 consisted of senior notes with fixed
interest rates.
OPERATING STATISTICS
Certain operating statistics (including, where applicable, proportional
interests in equity partnerships) for the three- and nine-month periods ended
September 30, 2000 and 1999 follow:
<TABLE>
<CAPTION>
Three Months Nine Months
---------------------- ---------------------
2000 1999 2000 1999
-------- -------- -------- --------
<S> <C> <C> <C> <C>
AVERAGE DAILY VOLUMES
Natural gas sales (Mcf)........................... 319,700 231,800 293,700 239,100
Crude oil and condensate sales (Bbls)............. 5,300 5,600 5,500 5,900
Natural gas liquids produced (Bbls)............... 52,300 42,300 51,500 41,900
Pipeline throughput (Mcf) ........................ 818,000 534,000 761,000 519,000
AVERAGE SALES PRICES
Natural gas (per Mcf)............................. $ 4.50 $ 2.79 $ 3.72 $ 2.27
Crude oil and condensate (per Bbl)................ 30.29 19.67 28.20 15.26
Natural gas liquids produced (per Bbl)............ 22.20 16.36 21.02 12.90
</TABLE>
-13-
<PAGE> 16
RESULTS OF OPERATIONS - NINE MONTHS ENDED SEPTEMBER 30, 2000
COMPARED WITH NINE MONTHS ENDED SEPTEMBER 30, 1999
Net earnings for the nine-month periods ended September 30, 2000 and 1999 - both
before and after unusual items - are summarized in the table which follows. For
2000, net earnings totaled $161.8 million, versus $32.8 million during the
comparable prior-year period. Exclusive of unusual items, 2000 after-tax
earnings totaled $151.6 million, versus $35.6 million for the comparable
prior-year period. Higher energy prices and volumes were the principal causes of
the period-to-period earnings improvement. The following table and discussion
identify and explain the major increases (decreases) in earnings for the
nine-month periods (in millions):
<TABLE>
<CAPTION>
Segment
Operating Earnings
----------------------
Exploration
and Gas Pretax Net
Production Services Other* Earnings Earnings
----------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
1999 AMOUNTS AFTER UNUSUAL ITEMS ................................... $ 52.6 $ 48.0 $(51.4) $ 49.2 $ 32.8
------ ------ ------ ------ ------
ELIMINATE IMPACT OF 1999 UNUSUAL ITEMS (see page 10)
Gain from sale of Hell's Hole area properties ...................... (11.5) -- -- (11.5) (7.2)
Water well litigation provision reversals .......................... (9.0) -- -- (9.0) (5.6)
Personnel reduction program costs .................................. 8.5 7.1 8.9 24.5 15.6
------ ------ ------ ------ ------
(12.0) 7.1 8.9 4.0 2.8
------ ------ ------ ------ ------
1999 AMOUNTS BEFORE UNUSUAL ITEMS .................................. 40.6 55.1 (42.5) 53.2 35.6
------ ------ ------ ------ ------
MAJOR INCREASES (DECREASES)
Higher natural gas sales price ..................................... 91.2 -- -- 91.2 59.3
Higher natural gas sales volumes ................................... 36.8 -- -- 36.8 23.9
Higher oil and condensate sales price .............................. 19.9 -- -- 19.9 12.9
Higher DD&A rate ($.90 versus $.86 per equivalent Mcf produced) .... (3.3) -- -- (3.3) (2.1)
Higher NGL margins ................................................. -- 26.8 -- 26.8 17.4
Higher NGL production volumes ...................................... -- 23.4 -- 23.4 15.2
Higher operating expenses (primarily repairs and maintenance) ...... (4.7) (8.2) -- (12.9) (8.4)
Equity in earnings of MTBE partnership ............................. -- 7.0 -- 7.0 4.6
Increased bonus unit expense accruals .............................. (3.3) (1.6) (5.7) (10.6) (6.9)
Increased incentive compensation expense accruals .................. (2.6) (1.6) (3.3) (7.5) (4.9)
Lower interest expense incurred .................................... -- -- 4.2 4.2 2.7
Lower effective income tax rate .................................... -- -- -- -- 1.3
Other, net ......................................................... (4.3) 1.4 4.4 1.5 1.0
------ ------ ------ ------ ------
129.7 47.2 (.4) 176.5 116.0
------ ------ ------ ------ ------
2000 AMOUNTS BEFORE UNUSUAL ITEMS .................................. 170.3 102.3 (42.9) 229.7 151.6
------ ------ ------ ------ ------
Gain from asset exchange (see page 7) .............................. -- 4.9 -- 4.9 3.2
Water well litigation provision reversal (see page 10) ............. 1.2 -- -- 1.2 .7
Reversal of certain prior years'
deferred state income taxes (see page 8) ........................ -- -- -- -- 6.3
------ ------ ------ ------ ------
1.2 4.9 -- 6.1 10.2
------ ------ ------ ------ ------
2000 AMOUNTS AFTER UNUSUAL ITEMS ................................... $171.5 $107.2 $(42.9) $235.8 $161.8
====== ====== ====== ====== ======
</TABLE>
----------
*Includes general and administrative expense and other expense.
EXPLORATION AND PRODUCTION OVERVIEW
Exclusive of unusual items, exploration and production segment operating
earnings of $170.3 million during 2000's first nine months were $129.7 million
above those of the comparable prior-year period. This improvement was
principally due to higher prices for natural gas and oil and increased natural
gas sales volumes.
-14-
<PAGE> 17
HIGHER NATURAL GAS SALES PRICE ($91.2 MILLION INCREASE). During the first nine
months of 2000, the Company's natural gas sales price averaged $3.72 per Mcf,
$1.45 (64%) above the prior period's $2.27, increasing operating earnings by
$91.2 million.
HIGHER NATURAL GAS SALES VOLUMES ($36.8 MILLION INCREASE). Natural gas sales
averaged 293.7 MMcf per day during 2000's first nine months, 23% above the 239.1
MMcf of the comparable prior-year period, improving operating earnings by $36.8
million. As discussed elsewhere herein, the production increases were largely
due to the Company's activities in the Barnett Shale area of North Texas.
HIGHER OIL AND CONDENSATE SALES PRICE ($19.9 MILLION INCREASE). The Company's
sales price for oil and condensate averaged $28.20 per barrel during 2000's
first nine months, $12.94 (85%) above the prior period's $15.26, increasing
operating earnings by $19.9 million.
GAS SERVICES OVERVIEW
Exclusive of unusual items, gas services segment operating earnings rose $47.2
million to $102.3 million during the first nine months of 2000. The sharply
higher earnings were principally due to price-related margin improvements for
gas processing and increased NGL production volumes.
HIGHER NGL MARGINS ($26.8 MILLION INCREASE). The average price for NGLs produced
during 2000's first nine months of $21.02 per barrel was 63% above the
prior-year period's $12.90, improving NGL revenues by $74.3 million. Because of
the impact of higher NGL and natural gas prices on producer settlement and gas
shrinkage costs, feedstock costs were also higher in 2000, resulting in a net
$26.8 million price-related increase in NGL margins.
HIGHER NGL PRODUCTION VOLUMES ($23.4 MILLION INCREASE). NGL production volumes
averaged 51,500 barrels per day, up 23% from the 41,900 of the corresponding
prior-year period. The increased volumes were principally due to (i) the October
1, 1999 acquisition of full ownership in the Jameson plant, (ii) increased
throughput of the Company's Vanderbilt system that is processed at the Exxon
Katy plant and (iii) restarting of the Huckabay plant to handle the Company's
increasing North Texas gas production. The increased volumes added $23.4 million
to operating earnings.
EQUITY IN EARNINGS OF MTBE PLANT PARTNERSHIP ($7.0 MILLION INCREASE). This
variance occurred both because of fewer downtime days (21 versus 45) and higher
spot market MTBE sales prices during the summer. MTBE prices declined
subsequently and have remained at lower levels.
OTHER
INCREASED BONUS UNIT EXPENSE ACCRUALS ($10.6 MILLION DECREASE). Bonus unit
expense accruals during 2000's first nine months totaled $11.7 million compared
with $1.1 million during the comparable period of the prior year, reducing
pretax earnings by $10.6 million. The expense accruals increased principally due
to a rise in the price of the Company's common stock to $46.625 per share at
September 30, 2000 from $21.81 at December 31, 1999. In the prior year, prices
at the comparable dates were $23.97 and $11.53, respectively.
LOWER INTEREST EXPENSE INCURRED ($4.2 MILLION INCREASE). This favorable variance
was primarily due to a lower average debt balance during the first nine months
of 2000 ($343.1 million versus $442.2 million), lowering interest expense by
$5.4 million. Reducing the year-to-year savings somewhat were 2000's higher
interest rates, which also increased the fees paid under the accounts receivable
securitization program.
-15-
<PAGE> 18
RESULTS OF OPERATIONS - THREE MONTHS ENDED SEPTEMBER 30, 2000
COMPARED WITH THREE MONTHS ENDED SEPTEMBER 30, 1999
Net earnings for the three-month periods ended September 2000 and 1999 are
summarized in the table which follows. Net earnings for 2000's third quarter
totaled $74.4 million, which compares to $25.9 million during the comparable
period of the prior year. Excluding the effects of an unusual item, the current
quarter's earnings totaled $68.1 million. Higher energy prices and volumes were
the principal causes of the quarter-to- quarter earnings improvement. The
following table and discussion identify and explain the major increases
(decreases) in earnings for the three-month periods (in millions):
<TABLE>
<CAPTION>
Segment
Operating Earnings
---------------------
Exploration
and Gas Pretax Net
Production Services Other* Earnings Earnings
----------- -------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
1999 AMOUNTS ....................................................... $ 26.7 $ 27.7 $(15.4) $ 39.0 $ 25.9
------ ------ ------ ------ ------
MAJOR INCREASES (DECREASES)
Higher natural gas sales price ..................................... 35.3 -- -- 35.3 23.0
Higher natural gas sales volumes ................................... 25.3 -- -- 25.3 16.5
Higher oil and condensate sales price .............................. 5.2 -- -- 5.2 3.4
Higher DD&A rate ($.88 versus $.84 per equivalent Mcf produced) .... (1.2) -- -- (1.2) (.8)
Higher NGL production volumes ...................................... -- 4.5 -- 4.5 2.9
Higher NGL margins ................................................. -- 4.1 -- 4.1 2.7
Higher operating expenses (primarily repairs and maintenance) ...... (1.1) (3.2) -- (4.3) (2.8)
Increased bonus unit expense accruals .............................. (2.1) (1.0) (3.8) (6.9) (4.5)
Increased incentive compensation expense accruals .................. (1.3) (.8) (1.5) (3.6) (2.3)
Lower interest expense incurred .................................... -- -- 1.0 1.0 .6
Lower effective income tax rate .................................... -- -- -- -- 1.0
Other, net ......................................................... (2.6) 2.4 4.0 3.8 2.5
------ ------ ------ ------ ------
57.5 6.0 (.3) 63.2 42.2
------ ------ ------ ------ ------
2000 AMOUNTS BEFORE UNUSUAL ITEMS .................................. 84.2 33.7 (15.7) 102.2 68.1
Reversal of certain prior years'
deferred state income taxes (see page 8) ........................ -- -- -- -- 6.3
------ ------ ------ ------ ------
2000 AMOUNTS AFTER UNUSUAL ITEMS ................................... $ 84.2 $ 33.7 $(15.7) $102.2 $ 74.4
====== ====== ====== ====== ======
</TABLE>
----------
*Includes general and administrative expense and other expense.
EXPLORATION AND PRODUCTION OVERVIEW
Exploration and production segment operating earnings of $84.2 million during
2000's third quarter were $57.5 million above those of the comparable prior-year
period principally due to higher prices for natural gas and oil and increased
natural gas sales volumes.
HIGHER NATURAL GAS SALES PRICE ($35.3 MILLION INCREASE). During the third
quarter of 2000, the Company's natural gas sales price averaged $4.50 per Mcf,
$1.71 (61%) above the prior period's $2.79, increasing operating earnings by
$35.3 million.
HIGHER NATURAL GAS SALES VOLUMES ($25.3 MILLION INCREASE). Natural gas sales
averaged 319.7 MMcf per day during 2000's third quarter, 38% above the 231.8
MMcf of the comparable prior-year period, increasing operating earnings by $25.3
million.
-16-
<PAGE> 19
HIGHER OIL AND CONDENSATE SALES PRICE ($5.2 MILLION INCREASE). The Company's
sales price for oil and condensate averaged $30.29 per barrel during 2000's
third quarter, up substantially from the prior period's $19.67, increasing
operating earnings by $5.2 million.
GAS SERVICES OVERVIEW
Gas services segment operating earnings totaled $33.7 million during the third
quarter of 2000, $6.0 million above the amount earned in 1999's third quarter.
The increase was principally the result of higher NGL production volumes and
margins.
HIGHER NGL PRODUCTION VOLUMES ($4.5 MILLION INCREASE). NGL production volumes
averaged 52,300 barrels per day, up 24% from the 42,300 of the corresponding
prior-year period, adding $4.5 million to operating earnings. The volume
increase occurred principally for the reasons mentioned on page 15.
HIGHER NGL MARGINS ($4.1 MILLION INCREASE). The average price for NGLs produced
during 2000's third quarter of $22.20 per barrel was 36% above the prior-year
period's $16.36, improving NGL revenues by $19.8 million. Because of the impact
of the quarter's higher NGL and natural gas prices on producer settlement and
gas shrinkage costs, feedstock costs rose by $15.7 million, resulting in a net
$4.1 million price-related increase in NGL margins.
OTHER
INCREASED BONUS UNIT EXPENSE ACCRUALS ($6.9 MILLION DECREASE). Bonus unit
expense accruals during the third quarter of 2000 totaled $7.9 million compared
with $1.0 million during the comparable period of the prior year, reducing
pretax earnings by $6.9 million. The expense accruals increased principally due
to a rise in the price of the Company's common stock to $46.625 per share at
September 30, 2000 from $32.13 at June 30, 2000. In the prior year, prices at
the comparable dates were $23.97 and $18.38, respectively.
LOWER INTEREST EXPENSE INCURRED ($1.0 MILLION INCREASE). The $1.0 million
decrease in interest expense was primarily due to a lower average debt balance
during the third quarter of 2000 ($317.9 million versus $405.6 million).
Reducing the period-to-period savings somewhat were 2000's higher interest
rates, which also increased the fees paid under the accounts receivable
securitization program.
-17-
<PAGE> 20
Part II - Other Information
ITEM 1. LEGAL PROCEEDINGS
There were no material legal proceedings pending at September 30, 2000.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibit 27. Financial Data Schedule.
Exhibit 99. Supplemental Financial Data
(b) No reports were filed on Form 8-K by Mitchell Energy & Development Corp.
during the three-month period ended September 30, 2000.
-18-
<PAGE> 21
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
MITCHELL ENERGY & DEVELOPMENT CORP.
(Registrant)
Dated: November 8, 2000 By /s/ Philip S. Smith
--------------------------------------
Philip S. Smith
Senior Vice President - Administration
and Chief Financial Officer
<PAGE> 22
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C>
27 Financial Data Schedule
99 Supplemental Financial Data
</TABLE>
