<PAGE> 1
EXHIBIT 99
MITCHELL ENERGY & DEVELOPMENT CORP.
1999 ANNUAL REPORT TO STOCKHOLDERS
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<S> <C>
Transition Form 10-K ................................................................................... 1
Forward-Looking Information ............................................................................ 2
Definitions ............................................................................................ 2
The Company ............................................................................................ 2
Financial Highlights ................................................................................... 3
Letter to Shareholders ................................................................................. 4
Exploration and Production ............................................................................. 6
Gas Services ........................................................................................... 11
Management's Discussion and Analysis of Financial Position and Results of Operations ................... 15
Consolidated Financial Statements ...................................................................... 27
Notes to Consolidated Financial Statements ............................................................. 31
Report of Independent Public Accountants ............................................................... 47
Unaudited Quarterly Financial Data ..................................................................... 48
Quarterly Stock Data ................................................................................... 49
Supplemental Oil and Gas Information ................................................................... 50
Historical Summary ..................................................................................... 54
Board of Directors ..................................................................................... 56
Principal Officers ..................................................................................... 57
Corporate Information .................................................................................. 58
</TABLE>
<PAGE> 3
THE COMPANY
Mitchell Energy & Development Corp., one of the nation's largest
independent producers of natural gas and natural gas liquids, traces its origins
to a small wildcatting firm formed in 1946.
The Company's two primary businesses are (i) exploration, development and
production of natural gas and oil, and (ii) gathering, processing and marketing
of natural gas and natural gas liquids. In 1999, the Company produced 94 billion
cubic feet of natural gas and 18.2 million barrels of liquid hydrocarbons
(natural gas liquids, oil and condensate). At year end, it owned or had
interests in 3,352 wells and 1.1 million acres of leases. In March 2000, the
Company exchanged its non-operated Oklahoma assets for the remaining interests
in operated assets in central Texas. After this exchange, the Company owned and
operated six gas processing plants and approximately 8,800 miles of gas
gathering pipelines.
At December 31, 1999, the Company had approximately 875 full-time
employees.
TRANSITION FORM 10-K
On September 1, 2000, the Company decided to change its year end to
December 31; the fiscal year end previously was January 31. The change was made
to conform the timing of the Company's financial reporting with that of
virtually all its peer group of independent energy companies and thus eliminate
investor confusion caused by a one month reporting difference and facilitate the
timely comparison by the investment community of the Company's results with
those of its competitors. A Transition Form 10-K is being filed in connection
with that change.
To provide users of the Company's financial information with complete,
comparable historical calendar year information, this annual report includes
audited financial statements for previously reported fiscal periods recast to a
calendar year basis for the years ended December 31, 1999, 1998 and 1997. The
eleven-month period ended December 31, 1996 was selected by the Company as the
transition period (a transition period is required by SEC regulations), and the
January 31 fiscal year end was retained for January 31, 1996 and prior years.
Except for summary information for the transition period and fiscal 1996, all
financial information and statistical data included in this annual report were
recasted from a fiscal to a calendar year basis.
Effective September 30, 2000, quarterly financial results will be reported
on a calendar quarter basis, and the earnings release and Form 10-Q for that
period will include (i) results for the three- and nine-month periods ended
September 30, 2000 and (ii) recasted results for calendar 2000's first two
quarters, replacing the previous reports for the April 30, and July 31 fiscal
quarters.
Since there is only a one-month difference between the respective ends of
the old and new reporting periods (January 31, 2000 versus December 31, 1999),
it was not necessary to extensively modify the narrative discussions, comments
and other information included in the previously filed report. However, because
this report was prepared nine months after the latest period reported herein,
parenthetical disclosures have been added to the Letter to Shareholders,
Exploration and Production, Gas Services and Management's Discussion and
Analysis of Financial Position and Results of Operations sections to provide
updated information and thereby facilitate the use of this document. Such
disclosures were placed in brackets so they can be easily distinguished.
Finally, because of the relatively short period before the Company's next
printed annual report will be published, time constraints and cost/benefit
considerations, this recasted 1999 Annual Report excludes color pictures and
other cosmetic enhancements normally present in annual reports.
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<PAGE> 4
FORWARD-LOOKING INFORMATION
All statements included in this annual report, other than statements of
historical fact, are forward-looking statements. These include, but are not
limited to, certain statements made in the Letter to Shareholders; strategies,
goals and expectations set forth in the Exploration and Production and Gas
Services sections; and discussions of liquidity and capital resources and other
matters included in Management's Discussion and Analysis of Financial Position
and Results of Operations. 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.
DEFINITIONS
<TABLE>
<S> <C>
MMBtu ................................ million British thermal units
Mcf .................................. thousand cubic feet (measure of gas volume)
Mmcf ................................. million cubic feet
Bcf .................................. billion cubic feet
Tcf .................................. trillion cubic feet
Bbl .................................. barrel (measure of liquid hydrocarbon volume)
MMBbls ............................... million barrels
NGL or NGLs .......................... natural gas liquids (ethane, propane, butanes and natural gasoline)
</TABLE>
Note: Natural gas volumes in this report are stated at the legal pressure base
of the area in which the reserves are located and at 60 degrees
Fahrenheit. Pipeline throughput volumes are based on an 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.
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<PAGE> 5
Mitchell Energy & Development Corp. and Subsidiaries
FINANCIAL HIGHLIGHTS
YEAR ENDED DECEMBER 31
(dollar amounts in thousands)
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
EARNINGS (LOSS) FROM CONTINUING OPERATIONS ......... $ 67,334 $ (32,854)
========= =========
NET EARNINGS (LOSS) ................................ $ 67,334 $ (29,604)
========= =========
BASIC AND DILUTED EARNINGS (LOSS) PER SHARE
From continuing operations ......................... $ 1.37 $ (.67)
Net earnings ....................................... 1.37 (.60)
REVENUES ........................................... $ 894,356 $ 720,260
========= =========
SEGMENT OPERATING EARNINGS (LOSS)
Exploration and production ......................... $ 71,023 $ 10,376
Natural gas processing ............................. 47,266 (925)
Natural gas gathering and marketing ................ 28,077 23,549
Other gas services ................................. 11,720 13,387
--------- ---------
158,086 46,387
Unusual items
Water well litigation provision reversals ........ 14,000 4,000
Gain from sale of Hell's Hole area properties .... 11,527 --
Personnel reduction program costs ................ (15,652) --
Proved property impairments ...................... -- (42,250)
Gas services asset write-downs ................... -- (7,560)
--------- ---------
$ 167,961 $ 577
========= =========
CAPITAL AND EXPLORATORY EXPENDITURES* .............. $ 164,031 $ 305,234
========= =========
LONG-TERM DEBT (including current maturities) ...... $ 379,267 $ 472,767
========= =========
STOCKHOLDERS' EQUITY ............................... $ 385,174 $ 341,282
========= =========
OPERATING STATISTICS (average daily amounts)
Natural gas sales (Mcf) ............................ 244,700 247,500
Crude oil and condensate sales (Bbls) .............. 5,900 6,800
Natural gas liquids production (Bbls) .............. 44,000 41,800
Pipeline throughput (Mcf) .......................... 555,000 554,000
</TABLE>
----------
*Includes asset acquisitions of $24,071 and $89,012
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<PAGE> 6
LETTER TO SHAREHOLDERS
================================================================================
EARNINGS OF $67 MILLION PROVIDED AN
18.5% RETURN ON STOCKHOLDERS' EQUITY.
--------------------------------------------------------------------------------
By virtually every measure, 1999 was a banner year for Mitchell Energy &
Development Corp. An increased focus on core operations, the application of new
completion technology, and greater operating efficiency have put your Company in
its best shape ever, setting the stage for even stronger earnings. The rapid
rebound in oil and gas prices experienced last year only amplified these
improvements. [Record per share earnings were reported for the quarters ended
April 30, 2000 and July 31, 2000.]
We entered the year with weak energy prices and had just completed a
program of personnel and spending reductions to ensure financial balance. By
mid-year, strengthening prices justified a stepped-up level of capital spending
which by year end, led to higher natural gas production, NGL processing volumes
and pipeline throughput.
As a result, annual net earnings rebounded to $67 million, with a return
on stockholders' equity of 18.5%. This return ranked among the highest in the
industry and was more than twice the five-year average. Higher operating cash
flows also improved the Company's financial strength. Long-term debt was reduced
by $93 million and stood at less than 50% of total capitalization. [By July 31,
2000, long-term debt had been reduced by another $65 million, to $314.3
million.]
The combination of stronger prices for all of our products - natural gas,
NGLs and oil - and internal improvements have put your Company in position to
add shareholder value as never before. We have a backlog of over 1,200
undeveloped locations and have moved aggressively to grow the production from
our long-lived gas fields, particularly the Barnett Shale. Even after last
year's breakthrough in the application of light sand fracture technology in the
Barnett, studies indicate that only a small portion of the gas in place is being
recovered. The full potential of the Barnett will be better defined as we
complete ongoing pilot tests evaluating the viability of closer well spacing,
which could add at least another 1,000 wells to the undrilled inventory. [At
July 31, 2000, the backlog had grown to 2,500 undeveloped locations with the
potential that closer well spacing could double that number.]
Perhaps the best indication of the Company's potential has been our
consecutive 12-year history of adding more proven natural gas reserves than were
produced each year, while still growing the significant backlog of undrilled
prospects. At year end, we reached a record reserve base of 1.1 Tcf of natural
gas equivalents and are confident of our ability to add substantially to that
amount with work now underway to determine the ultimate reserve potential of the
Barnett. [Mid-year additions announced in July 2000 increased total proved
natural gas reserves to a record 1.467 Tcf.]
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<PAGE> 7
Growth of the gas services business was led by the expansion and
upgrading of North Texas facilities to accommodate accelerated Barnett drilling.
In addition, two transactions were completed to further concentrate and increase
control over our core gathering and processing facilities. These included the
purchase of the remaining 50% interest in the Jameson plant and a swap of
non-operated interests in Oklahoma pipeline and processing assets for the
outstanding interests in similar assets that we operate in central Texas.
The outcome is full ownership and operation of all of our major midstream
facilities. The Company currently produces more NGLs with just six processing
plants than it did when it had interests in 31 plants five years ago. NGL
reserves reached a record 179 million barrels and are expected to continue
growing in the years to come due to the strategic location of our midstream
assets. [Mid-year additions announced in July 2000 increased total proved NGL
reserves to 210 million barrels.]
Although your Company's stock price nearly doubled in 1999, we were
disappointed that its valuation lagged behind many of our peers - as measured by
such common yardsticks as P/E ratios and cash flow multiples. For that reason,
we initiated a review of strategic alternatives that contemplated, among various
options, the possible sale or merger of the Company. In the final analysis, our
Board of Directors concluded that shareholder interests would best be met as a
stand-alone company with an increased focus on its core upstream operations.
The Board also approved two steps aimed at improving stock price
performance. With your approval at the June 2000 shareholders meeting, the Class
A and Class B shares will be combined into a single voting class of stock to
increase liquidity and eliminate confusion in the marketplace over the dual
class structure. [Approval was obtained and the stock was reclassified in June
2000.] Furthermore, the Board authorized a balanced program of debt reduction
and the repurchasing of as many as 2.5 million shares of stock. This program is
to be funded by expected excess operating cash flows, even after a 50% increase
in capital spending. [Through September 30, 2000, 98,800 shares had been
repurchased at an aggregate cost of almost $2.8 million and outstanding
long-term debt had been reduced to $300.3 million.] These proposals have been
well received by major institutional shareholders and financial analysts.
[During September 2000, the Company's stock price rose above $45 per share,
double its level early in the year.]
Last year's progress in all dimensions of the Company enables us to enter
2000 in the best shape ever - both operationally and financially. Supported by
the strong improvement in energy price fundamentals, we expect to increase
production of both natural gas and NGLs by 15% this year and maintain a higher
level of growth than in the past. [In August 2000, the Company reported that
this year's annual growth level for natural gas would exceed 20%.] Our focus -
and commitment to you, our shareholders - is to not only add to the Company's
fundamental value, but to its share price as well.
/s/ George P. Mitchell /s/ W. D. Stevens
---------------------------------- ----------------------------
Chairman and President and
Chief Executive Officer Chief Operating Officer
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<PAGE> 8
EXPLORATION AND PRODUCTION
FINANCIAL HIGHLIGHTS
Year Ended December 31 (in thousands)
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
REVENUES ............................................. $ 265,888 $ 227,440
========= =========
SEGMENT OPERATING EARNINGS (LOSS)
Operations ........................................... $ 71,023 $ 10,376
Unusual items
Water well litigation provision reversals ........ 14,000 4,000
Gain from sale of Hell's Hole area properties .... 11,527 --
Proved property impairments ...................... -- (42,250)
Personnel reduction program costs ................ (8,524) --
--------- ---------
$ 88,026 $ (27,874)
========= =========
CAPITAL AND EXPLORATORY EXPENDITURES,
excluding acquisitions ........................... $ 118,414 $ 182,995
========= =========
</TABLE>
The expansion of the North Texas Barnett shale development program and a
complete turnaround of oil and natural gas prices resulted in one of the most
profitable years in the history of Mitchell's exploration and production
operations and provides a solid platform for future volume growth. Higher prices
combined with reduced exploration and personnel expenses caused segment
operating earnings before unusual items to rise seven-fold to $71.0 million from
the $10.4 million earned in the prior year.
Given the severely depressed levels of energy prices a year ago, the
rebound in prices that started in early 1999 and continued into 2000 was not
unexpected. However, the speed at which prices raced from historic lows to near
record highs came as somewhat of a surprise. The corresponding rapid rise in
earnings reflects the Company's leverage to natural gas and NGL prices, and the
actions already taken to ensure profitability even during periods of low prices,
allowed the benefit of higher prices to go straight to the bottom line.
Continued successful application of recently developed "light sand
fracture" technology in the Barnett shale led to the largest single increase of
natural gas reserves in the history of the Company. Light sand fracture
technology replaced the heavy gels previously used to prop open subsurface
fractures in the formation. This not only improved the ability of the gas to
flow to the well bore, but also significantly reduced well costs.
As a result of this new completion technology, the Company increased net
oil and gas reserves in 1999 by 240 Bcf equivalent and replaced 224% of the
equivalent gas produced. This pushed total year-end proved reserves up to a
record 1.1 Tcf of natural gas equivalents and marked the twelfth consecutive
year the Company more than replaced its production of natural gas reserves.
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<PAGE> 9
This record level of reserve additions drove finding costs in 1999 down to
37 cents per Mcf equivalent from $1.24 in the prior year. Since expenditures for
seismic and exploratory costs usually do not coincide with the ultimate
recording of reserves associated with a drilling program, a five-year average of
finding costs is a better benchmark. For 1995 through 1999, the Company's
finding costs averaged 79 cents per Mcf equivalent.
OIL AND GAS SALES
Natural gas sales averaged 244.7 MMcf per day in 1999. This was
essentially flat with sales of the prior year, reflecting the constrained
capital program in the second half of 1998 and first half of 1999. However, with
the mid-year increase in the drilling program, natural gas sales rose to 261.3
MMcf per day by the fourth quarter, a 6% increase over sales in the prior year's
fourth quarter.
The growth in gas sales came primarily from accelerated drilling in the
North Texas Barnett shale. Partially offsetting the gains were the sale of the
non-core properties in the Hell's Hole area - with the proceeds being deployed
into higher yielding development projects - and production declines in East
Texas and Gulf Coast areas that were not offset by incremental drilling.
Annual sales of natural gas are expected to increase approximately 15% in
2000 as the Company accelerates the drilling of its inventory of over 1,200
development well locations. [As was reported in August 2000, the Company expects
this year's natural gas sales to increase by more than 20% while 2001's should
grow another 20%. At July 31, 2000, the well backlog had grown to 2,500 with the
potential that closer well spacing could ultimately double that number.]
The shifting balance between worldwide energy production and consumption
drove the dramatic improvement in oil and gas prices. In the United States,
natural gas production capabilities have decreased due to an overall lower level
of reinvestment by the industry. This decrease comes at a time when demand by
gas-fired electric plants is increasing and homeowners continue converting to
environmentally friendly natural gas. Even though 1999 was the warmest winter on
record for North America, natural gas storage inventories dropped to 1 Tcf at
the end of the traditional heating season, indicating that gas supplies will be
tight in the near future as gas storage facilities and consumers compete for
available production. These factors contributed to a 13% increase in Mitchell's
1999 natural gas sales price that averaged $2.42 per Mcf, and set a bullish
outlook for gas prices going forward.
Oil production decreased as expected to 5,900 barrels per day, as a
reduced level of investment in oil prospects allowed natural decline in older
wells to exceed production from new wells. Average oil realizations rose to
$17.17 per barrel, a 36% increase over last year's $12.60 per barrel.
CAPITAL SPENDING
The capital budget for 1999 was originally set within expected cash flows
based on the poor outlook for prices at the beginning of the year. Although
capital spending was increased at mid-year in light of strengthening prices,
restricted drilling activity early in the year limited total year expenditures
to $118.4 million. Of that total, $80.4 million was spent to drill or
participate in 103 development and 18 exploratory wells and another $6 million
was incurred to recomplete 40 wells in the Upper Barnett.
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<PAGE> 10
Entering 2000, budgeted capital spending has been raised to $182.9
million, 54% more than in the prior year. The majority of the increase will be
spent on drilling projects, with approximately 200 wells slated to be drilled -
65% more than the number drilled last year. Additional funds have been earmarked
for continuation of the Barnett well recompletion program and extension of the
light sand fracture technology to wells located in the Limestone and Freestone
County areas.
At December 31, 1999, Mitchell had interests in 2,266 producing gas wells
and 1,086 oil wells, of which 85 were productive in two or more zones. Excluding
interests held by others, Mitchell's net interests totaled 2,004 gas and 609 oil
wells, of which 73 were productive in two or more zones.
NORTH TEXAS - BARNETT SHALE
The Company's largest acreage position is in North Texas where 597,000
gross acres account for approximately 55% of the Company's gas equivalent
production. For the past seven years, development has been focused on the
Barnett shale formation which is the source rock for the natural gas and oil
contained in numerous producing horizons in the Ft. Worth Basin. Although the
Barnett is known to have vast quantities of natural gas, its low porosity and
permeability has made it difficult to achieve economic success outside the known
"sweet spot," or core area.
Last year's breakthrough in light sand fracture technology not only
significantly reduced development costs, but "unlocked" the Upper Barnett zone
within the core area and increased the estimated recoverable reserves per well
by 25%. The core area of the Barnett shale is separated into two sections by a
layer of impervious rock, and the upper section was previously uneconomical to
develop using higher-cost gel fracs. More importantly though, the improved
technology has converted marginally economic locations to the south and east of
the sweet spot into viable opportunities. These expansion-area prospects will
now generate a very attractive return on investment with natural gas prices of
$2.00, and an outstanding return at $3.00.
Accelerated development of the core and expansion areas of the Barnett
shale will continue in the current year. Plans call for the drilling of 135
wells, versus the 66 that were drilled in 1999. Six drilling rigs are now
working in the area and the aggressive rework program initiated last year to add
the upper Barnett to approximately 300 existing core area wells continues. At
the current 55-acre well spacing, the Company has an identified undrilled
backlog of over 1,000 wells in the Barnett, each with an estimated reserve
potential ranging from 1.0 to 1.25 Bcf.
Additional studies using state-of-the-art pressure core and gas-in-place
analyses have indicated that only a small portion of the reservoir's gas is
recovered based on current well spacing. Testing is underway in three pilot
areas to determine how 27-acre well spacing coupled with refracturing of
existing wells will improve drainage of the reservoir without negatively
affecting the production of neighboring wells. If successful, this program could
add another 1,000 additional locations to the Barnett undrilled inventory and at
least double the recovery of the gas in place.
EAST TEXAS
The Company's second largest leaseblock of 67,000 acres lies primarily in
Limestone County and includes the North Personville, Oaks and Dew Fields.
Massive hydraulic fracturing technology in the Cotton Valley limestone formation
was first pioneered by the Company in 1978 and has been the
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<PAGE> 11
primary method of opening this dense rock to improve drainage of the field.
Application of the new light sand fracture technology in this area, coupled with
other recent drilling improvements, reduced per well development costs in the
limestone formation by 30%, or roughly $350,000. These improved field economics
should enable a reduced spacing pattern of less than 160 acres per well which
would prove the existence of significant additional reserves.
In the same area, six Bossier sandstone play wells were drilled and
completed in the Dew Field. The production of these Bossier wells averaged 10
MMcf per day in February. For 2000, twenty-six wells are planned in this area.
Eighteen will target the Bossier, Cotton Valley and Travis Peak sandstone
objectives and another eight wells are planned for the Cotton Valley limestone.
GULF COAST
In the Pinehurst, Lake Creek and East Lake Creek fields located in
Montgomery County, development of the multi-pay Wilcox section continued last
year with the completion of seven new wells, including one 14,500 foot deep test
of the Lower Wilcox sands. That well encountered four sandstone gas pay zones
and is producing 3.5 MMcf per day of natural gas. A one-mile step-out of this
well is planned for the first quarter of 2000 and two exploratory tests will be
drilled into the Frio and Yegua sandstone formations. Six additional development
wells will target the Upper and Middle Wilcox and 16 recompletions of existing
wells are also planned.
The Lower Wilcox has long been recognized to contain a large amount of
gas, and a 54-square-mile 3-D seismic survey shot in late 1998 indicated that
the Lower Wilcox pay zones extend over 1,200 acres on leases held in the area.
This year, the Company will experiment with completion techniques that aim to
repeat the success achieved in the Upper Wilcox.
EXPLORATORY ACTIVITIES
Following up the 77-square mile Cottonwood 3-D seismic survey in Ft. Bend
County, Texas, two exploratory dry holes with a net 61% working interest were
drilled in 1999 that targeted seismic anomalies. Drilling of the survey's
largest structural feature will begin in April 2000 to test a 10,000-foot Yegua
prospect. Mitchell has a 100% interest in this prospect and could possibly drill
eight additional wells depending on the results of the first test.
Interpretation of the 92-square-mile Franklin Ranch 3-D survey in McMullen
County revealed a number of pinnacle reefs in the 12,000-foot Sligo section and
multiple small Wilcox sandstone prospects at shallower depths. Three of the
Wilcox prospects were drilled in 1999 and all were dry. The first test of the
Sligo interval with a 50% working interest partner is scheduled for May 2000.
The Company has over 16,000 acres under lease in the area.
Last year's planned drilling of the 54-square-mile Pine Island 3-D survey
in Jefferson Davis Parish, Louisiana, was delayed when the Company's 50% partner
was acquired by a third party. A new partner was found recently and up to eight
wells could be drilled this year to evaluate the Frio Hackberry seismic anomaly
prospects. The initial 11,200-foot exploratory well is expected to spud in April
2000, east of the Company's successful wells drilled in Calcasieu Parish,
Louisiana, and Orange County, Texas.
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<PAGE> 12
PRINCIPAL PRODUCING AREAS (average daily sales)
Year Ended December 31
<TABLE>
<CAPTION>
1999 1998
-------- --------
<S> <C> <C>
NATURAL GAS (Mcf)
North Texas ........................ 126,700 121,900
East Texas ......................... 57,300 61,300
Gulf Coast ......................... 50,600 49,200
Other .............................. 10,100 15,100
-------- --------
244,700 247,500
======== ========
CRUDE OIL AND CONDENSATE (Bbls)
North Texas ........................ 1,200 1,700
East Texas ......................... 1,200 1,300
Gulf Coast ......................... 2,200 2,400
Other .............................. 1,300 1,400
-------- --------
5,900 6,800
======== ========
</TABLE>
================================================================================
WELL COMPLETIONS (excluding service wells)
Year Ended December 31, 1999
<TABLE>
<CAPTION>
Exploratory Development Total
--------------------- --------------------- ---------------------
Total Oil Gas Dry Oil Gas Dry Oil Gas Dry
------ ----- ----- ----- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
North Texas ............... 80 4 -- 4 3 67 2 7 67 6
East Texas ................ 17 -- -- -- 1 16 -- 1 16 --
Gulf Coast ................ 19 -- -- 5 3 10 1 3 10 6
Other(1) .................. 5 3 -- 2 -- -- -- 3 -- 2
------ ----- ----- ----- ----- ----- ----- ----- ----- -----
Gross wells(2) ............ 121 7 -- 11 7 93 3 14 93 14
====== ===== ===== ===== ===== ===== ===== ===== ===== =====
Net wells ................. 104.4 3.2 -- 5.7 6.5 86.0 3.0 9.7 86.0 8.7
====== ===== ===== ===== ===== ===== ===== ===== ===== =====
</TABLE>
----------
(1) Includes Louisiana and West Texas.
(2) An additional 33 wells (29.1 net wells) were in progress at December 31,
1999.
================================================================================
LEASEHOLDINGS
At December 31, 1999
<TABLE>
<CAPTION>
Gross Net
Acres Acres
---------- --------
<S> <C> <C>
Texas ................................................ 294,100 202,600
Mississippi .......................................... 16,700 7,000
Louisiana ............................................ 13,600 8,800
New Mexico ........................................... 12,500 11,000
Alabama .............................................. 11,300 4,800
Other* ............................................... 15,400 9,600
---------- --------
Total undeveloped acreage ............................ 363,600 243,800
Producing acreage .................................... 713,400 533,300
---------- --------
Total acreage ........................................ 1,077,000 777,100
========== ========
</TABLE>
*Includes Colorado, Michigan, Oklahoma and Utah.
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<PAGE> 13
GAS SERVICES
FINANCIAL HIGHLIGHTS
Year Ended December 31 (in thousands)
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
REVENUES
Natural gas processing .......................... $ 384,692 $ 262,595
Natural gas gathering and marketing ............. 231,275 215,688
Other ........................................... 12,501 14,537
--------- ---------
$ 628,468 $ 492,820
========= =========
SEGMENT OPERATING EARNINGS (LOSS)
Natural gas processing .......................... $ 47,266 $ (925)
Natural gas gathering and marketing ............. 28,077 23,549
Other ........................................... 11,720 13,387
--------- ---------
87,063 36,011
Unusual items
Personnel reduction program costs ............ (7,128) --
Asset write-downs ............................ -- (7,560)
--------- ---------
$ 79,935 $ 28,451
========= =========
CAPITAL EXPENDITURES, excluding acquisitions .... $ 21,066 $ 30,309
========= =========
</TABLE>
Gas Services operating earnings, excluding unusual items, increased 142% to
$87.1 million in 1999 primarily due to the significant improvement in gas
processing margins driven by sharply higher NGL prices. Other factors
contributing to the turnaround were increased NGL production volumes and lower
operating costs and expenses resulting from a personnel reduction program and
other streamlining actions.
The Company intentionally restrained capital spending during the first
half of 1999 because of reduced industry drilling activity. As a result,
expenditures for the year declined to $21.1 million. Because of improved
industry fundamentals, the capital budget for 2000 has been increased to $36
million. Capital outlays in 2000 will be directed toward expanding and upgrading
core facilities, primarily in north and southeast Texas, and covering an
anticipated increase in new well connections to the Company's gathering systems.
At December 31, 1999, Mitchell's NGL reserves totaled a record 179.1
million barrels, up 55% from the prior year. Expanded drilling activities,
especially the Company's Barnett shale program in North Texas, accounted for
approximately 22% of this increase. Another 24% came from the acquisition of the
remaining 50% interest in the Jameson plant. Also, with improved processing
margins, approximately 34 million barrels that were uneconomic a year ago were
added back to the reserve base.
-11-
<PAGE> 14
VOLUMES AND PRICES
Natural gas liquids production increased 5% in 1999 to 44,000 barrels per
day, propelled by a rebound in the energy industry from the depressed conditions
prevailing a year ago. Most of the improvement came in the second half of the
year as more gas became available for processing from stepped-up drilling
activity along the Company's gathering systems. In addition, the Jameson
acquisition in October 1999 added 3,700 barrels to daily production, increasing
the fourth-quarter average to 50,300 barrels per day. Annual NGL volumes are
expected to increase 15% this year, exclusive of any upside potential from
acquisition opportunities.
NGL prices rose 35% to $14.20 per barrel in 1999 from $10.48 in the prior
year. Prices especially strengthened in the second half of the year due to
strong petrochemical feedstock demand for NGLs, below-average ethane and propane
inventories, and increased propane exports. These factors pushed Mitchell's
average price to over $17 per barrel in the fourth quarter and are expected to
continue having a favorable impact on NGL realizations in 2000. Through March,
NGL prices have averaged over $21 per barrel.
Although average daily pipeline throughput was relatively flat year on
year, pipeline activity was a story of two halves. First-half volumes were down
as drilling constraints implemented by oil and gas producers in the prior year
carried into 1999. But drilling increased dramatically in the second half. As a
result, fourth-quarter pipeline volumes climbed 21% to 660 MMcf per day from 546
MMcf per day in the prior year's comparable quarter. This increase included 43
MMcf per day (100% system throughput) from the Jameson system, which volumes
were reported in pipeline statistics beginning in October 1999. With almost 60
rigs currently drilling along its gathering systems, the Company expects to add
substantial new gas volumes for both gathering and processing in 2000.
Pipeline gross margins averaged 16 cents per Mcf, down from 20 cents in
the prior year. This decrease resulted primarily from a higher mix of
transported volumes versus sales volumes.
NORTH TEXAS
A ramp up of the Company's Barnett development program, together with
increased drilling by other operators in the area, pushed throughput volumes on
the Bridgeport gathering system to 202 MMcf per day in the fourth quarter, up
29% from a year earlier. Anticipating this increased activity, Mitchell shut
down the Bridgeport plant for six days in early August 1999 for major
maintenance and upgrades. This work included the installation of
state-of-the-art control systems, improving plant operating efficiency by 5%.
In the fall of 1999, Mitchell completed construction of a new field gas
sales outlet in Denton County. This sales point - with a daily capacity of 40
MMcf - allows the Company to sell relatively dry gas production in this area
directly into intrastate markets. More importantly, this freed up capacity on
the Bridgeport Gathering system to move additional rich gas to the Bridgeport
plant, increasing NGL production. Mitchell plans to increase the capacity of
this sales point to 60 MMcf per day in 2000. [The capacity was later increased
to 80 MMcf per day, and daily sales were at the 70 MMcf per day level early in
October.]
-12-
<PAGE> 15
With rich gas volumes in North Texas expected to increase significantly
over the foreseeable future, the Company has initiated a study to evaluate
expanding processing capacity at the Bridgeport plant by 100 MMcf per day. In
the interim, Mitchell has entered into agreements to use spare capacity at
nearby third-party processing plants. [Construction of the Bridgeport plant
expansion is expected to be completed in December 2000.]
One of the Company's primary operating strategies is to maintain balance
and flexibility between intrastate and interstate gas market outlets. In this
regard, Mitchell is working with a power plant developer to build a pipeline
header system to deliver gas to an 800 megawatt plant scheduled for completion
in southwest Wise County in 2003. Mitchell expects to provide a significant
portion of the plant's 120 MMcf per day fuel requirement from its own
production.
SOUTHEAST TEXAS
Mitchell continues to build its gathering, processing and marketing
operations at the Katy hub in southeast Texas. Katy is one of the largest market
hubs in the United States, providing access to industrial markets along the
Houston Ship Channel and the Texas Gulf Coast. In addition, the Company has a
favorable gas processing contract at the Exxon Katy plant, which has excess
capacity to handle further growth in the area.
At year-end, deliveries from Mitchell-operated pipelines to the inlet of
the Katy plant had climbed to 172 MMcf per day, up 32% from the prior-year
level. Mitchell is the largest supplier of natural gas to the Katy plant,
accounting for approximately 85% of the plant's production.
Much of the growth at Katy comes from Mitchell's Vanderbilt system, which
is capturing substantial new gas supplies from active drilling in the Wilcox and
Yegua trends. When this system was first connected in August 1998, its daily
throughput was less than 5 MMcf per day with associated NGL production of 1,300
barrels per day. Early in 2000, volumes are running 65 MMcf and 3,500 barrels
per day, respectively, and are expected to grow to 125 MMcf and 6,000 barrels
per day by December 31, 2000.
CENTRAL TEXAS
In March 2000, the Company completed an exchange of its non-operated
Oklahoma gathering and processing assets for (i) Duke Energy Services' interests
in Mitchell-operated gathering and processing assets located in the Austin Chalk
area of Central Texas and (ii) approximately $11.7 million in cash. This
transaction eliminated four partnerships - one with Conoco in Oklahoma and three
in the Austin Chalk with Duke - streamlining the Company's midstream operations.
Mitchell now owns and operates all of its major gathering and processing assets.
Also, the Company produces more NGLs today with only six processing plants than
it produced five years ago when it owned interests in 31 plants.
After several years of field declines, drilling activity in the rich gas
area of the Austin Chalk picked up significantly during the last half of 1999.
In the coming year, a large independent plans to drill nine new oil wells and
rework 27 producing wells. Since the associated gas produced from these wells is
rich in gas liquids, liquids production from this area should level out, if not
increase, in the coming year.
-13-
<PAGE> 16
WEST TEXAS
With NGL demand increasing, the Company added quality assets in this core
area. Effective October 1, 1999, the Company purchased its partner's 50%
interest in the Jameson processing plant and associated gathering systems for
$23.9 million. This transaction added approximately 21 MMcf per day of gathering
volumes and 3,700 barrels per day of NGL production.
OTHER
Operating earnings from the Company's downstream assets - a one-third
interest in an MTBE gasoline additive plant and a 38.75% interest in an NGL
fractionator - declined to $11.7 million from $13.4 million in the prior year.
This decline was due primarily to two unplanned MTBE plant shutdowns (totaling
34 days) for repairs and reduced fees on certain fractionation contracts.
The demand for MTBE as a gasoline additive is likely to diminish during
the next few years due to regulatory pressures. However, the plant can be
retrofitted at a relatively modest capital cost to produce other gasoline blend
stocks such as alkylates. The partners are currently reviewing plant
alternatives and expect to reach a decision by December 31, 2001.
-14-
<PAGE> 17
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL POSITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING INFORMATION
All statements included herein or incorporated into this filing, 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
STRATEGIC ALTERNATIVES. On April 6, 2000, the Company announced that, as a
result of its review of strategic alternatives, it plans to continue operating
as an independent oil and gas company and to take several steps to improve its
stock price performance and thus enhance shareholder value.
To improve the market liquidity of the Company's stock and eliminate
confusion resulting from its two-class common stock structure, the Class A and
Class B shares are to be combined into a single voting class. This is expected
to occur in late June after approval by the Company's stockholders. [Approval
was obtained and the stock was reclassified in June 2000.]
The Company also initiated a balanced program to repurchase some of its
common stock and to further reduce outstanding debt. Stock repurchases - for
which the Board of Directors' authorization covers up to 2.5 million shares -
will be made from time to time in the open market while the debt reductions most
likely will consist of pay downs of outstanding bank revolving credit agreement
borrowings. Since the program is to be funded using excess operating cash flows,
the total amount to be spent and the split between stock repurchases and debt
reductions ultimately will be dependent, among other things, on future energy
prices, cash flow levels and prices of the Company's stock. The Company intends
to maintain or enhance the investment grade rating of its senior notes as this
program proceeds. [Through September 30, 2000, 98,800 shares had been
repurchased at an aggregate cost of almost $2.8 million.]
While the strategic alternatives study was in progress, the Company took
substantive actions to grow its core energy businesses and thus add to
stockholder value. Energy reserves were significantly increased by applying (i)
new technology that lowered well costs and (ii) an increasing understanding of
reservoir performance. Moreover, there is substantial upside potential in North
Texas where an accelerated exploitation program was begun in 1999 and was
further expanded recently. Also, the Company's natural gas gathering and
processing operations were further consolidated adding to the cost effectiveness
of the midstream operations.
-15-
<PAGE> 18
OVERVIEW. After being adversely impacted by unusually low prices for its
products in 1998 and early 1999, the Company's results for the final three
quarters of 1999 improved dramatically as energy prices rose sharply. Also,
contributing to the earnings improvement were reduced costs and expenses
resulting from the personnel reduction program undertaken early in 1999, a
lowering of geological and geophysical expenses, and other actions taken by the
Company.
The Company's energy operations have returned an average 11% on
stockholders' equity over the last five years, one of the best returns in the
independent oil and gas sector. With improved pricing and the aggressive steps
taken by the Company in recent periods, the return was 18.5% for 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 during the years ended December 31,
1999, 1998 and 1997:
<TABLE>
<CAPTION>
Crude Oil and
Natural Gas (per Mcf) Condensate (per Bbl) NGLs (per Bbl)
--------------------------- ---------------------------- ----------------------------
1999 1998 1997 1999 1998 1997 1999 1998 1997
------ ------ ------ ------ ------ ------ ------- ------ -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
First quarter .... $ 1.79 $ 2.29 $ 2.96 $11.06 $14.53 $21.69 $ 9.55 $11.64 $15.68
Second quarter ... 2.25 2.25 2.16 15.46 12.92 18.73 12.56 10.63 12.64
Third quarter .... 2.79 2.01 2.34 19.67 12.15 18.24 16.36 9.83 13.59
Fourth quarter ... 2.82 2.07 2.98 22.91 10.78 18.50 17.39 9.63 13.89
Full year ........ 2.42 2.15 2.62 17.17 12.60 19.27 14.20 10.48 13.96
</TABLE>
After being relatively strong in 1997 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. 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
1998. The depressed energy price environment led to 1998 fourth quarter
impairments of certain oil and gas proved properties - primarily oil fields -
and gas services assets.
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. After being at record lows early in 1999, oil
and NGL prices early in 2000 reached highs not seen in many years. Natural gas
prices were also relatively strong in 1999. Relatively high energy prices have
continued into the current year; the Company's average sales prices in February
2000 were $3.00 per Mcf for natural gas and $28.28 and $22.86 per barrel,
respectively, for crude oil and condensate and NGLs.
While the Company generally does not modify its operating plans for normal
volatility in energy prices, the downward price swings were so extreme during
1998's last half that they could not be ignored. Accordingly, after taking many
actions early in 1998 to grow its energy businesses, the Company found it
necessary late in the year to curtail capital spending and to take various
steps, including a personnel reduction program, to sharply reduce operating
costs. As a result, early in 1999 the Company was well-positioned to operate in
a low-energy-price environment and conducted its activities on that basis during
the first half of the year. Capital spending was intentionally deferred
-16-
<PAGE> 19
causing natural gas production levels to cease their growth and to fall
somewhat. As the outlook for energy prices improved in the first half of 1999,
the Company began taking steps to substantially increase its development
drilling and well recompletion programs, particularly in the Barnett Shale area
of North Texas.
The Company's accelerated Barnett Shale development program begun in the
last half of 1999 pushed natural gas production to a record 261.3 MMcf per day
in the fourth quarter. Early in April, six rigs were drilling in the Barnett,
and the Company plans to drill as many wells there in the first half of 2000 as
were drilled in all of 1999 (and twice as many for the full year). With its
expanded drilling activities and an extensive ongoing rework program, the
Company's overall gas production is expected to increase by more than 10% per
year for the foreseeable future.
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. In the fourth quarter, NGL production
averaged 50,300 barrels per day, a level not reached since the early 1990s when
more than twice as many plants were being operated. The previously announced
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. The Company now
has total ownership and operating control of all its major gas processing and
gathering facilities. This should lower operating costs and increase the
Company's flexibility in using these facilities. Over the next year, NGL
production is expected to increase 5% or more from the fourth quarter level.
And, after a likely upcoming expansion of the Bridgeport plant to handle the
increasing North Texas gas production, NGL production could rise further.
By capturing a large portion of the new gas supplies being developed along
its systems, the Company expects to further grow its gathering and processing
volumes in 2000 and beyond. By the end of 2000, volumes on the Vanderbilt system
are expected to equal 125,000 Mcf per day with 6,000 barrels of associated NGLs,
up from 20,000 Mcf and 1,300 barrels early in 1999 (and none prior to August
1998). [Later indications are that volumes will approximate 90,000 Mcf per day
at the end of 2000.]
2000 EARNINGS. As discussed elsewhere herein, the Company's earnings rose
sharply during 1999, and energy prices have strengthened even further early in
2000. Based on remainder of the year futures market strip prices quoted in late
March, the Company's net earnings and cash flows for 2000 - even after
considering the items noted in the following paragraph - would exceed those of
any year in its history, excluding unusual items. [With subsequent production
volume increases and further strengthening of energy prices in 2000, it is clear
that this will be achieved.]
The possible record earnings and cash flows for 2000 would be achieved in
spite of the negative year-to-year impact of two expiring contracts and adverse
changes in another. The expiration in December 1999 and March 2000 of gas
gathering and marketing contracts covering almost 6% of the Company's throughput
will impact the Company's results in 2000. Even after considering the favorable
impact of volume increases, a $7 million year-to-year decrease in gas gathering
and marketing operating earnings could occur. Furthermore, effective June 1,
2000, the terms of the MTBE partnership's sales contract will change. Until that
time, the contract calls for MTBE revenues to be determined using formula prices
covering production costs and debt service payments retiring
-17-
<PAGE> 20
the partnership's indebtedness over a five-year term ending in May 2000.
Effective with the change, MTBE sales are to be at market prices, which in March
are below the formula prices received during 1999. Market conditions in
mid-March 2000 pointed toward a $4 million year-to-year reduction in the
Company's equity in the earnings of the MTBE partnership. However, with the
concurrent elimination of the Company's $3.3 million share of quarterly debt
principal payments, operating cash flows from the partnership should increase
somewhat. [Because of increasing natural gas prices and seasonal increases in
MTBE prices during the summer, the above-mentioned potential earnings reductions
have not occurred.]
CAPITAL AND EXPLORATORY EXPENDITURES. The following table compares the budget
for capital and exploratory expenditures the Company established for the year
ending January 31, 2001 with its actual expenditures during the years ended
December 31, 1999 and 1998 (dollars in millions):
<TABLE>
<CAPTION>
2000 Budget 1999 Actual 1998 Actual
---------------- ------------------------------------- ----------------
First Last Total
Amount % Half Half Amount % Amount %
------ ------ ------ ------- ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Exploration and production ....... $182.9 82.4 $ 44.1 $ 74.3 $118.4 84.6 $183.0 84.7
Gas services ..................... 37.2 16.7 7.7 13.3 21.0 15.0 30.3 14.0
Corporate ........................ 2.0 .9 .1 .4 .5 .4 2.9 1.3
------ ------ ------ ------- ------ ------ ------ ------
$222.1 100.0 51.9 88.0 139.9 100.0 216.2 100.0
====== ====== ====== ======
Asset acquisitions
Exploration and production ....................... -- -- -- 71.7
Gas services ..................................... .3 23.8 24.1 17.3
------ ------- ------ ------
$ 52.2 $ 111.8 $164.0 $305.2
====== ======= ====== ======
</TABLE>
The Company's budget for 1999 totaled $143.5 million, well below the
amount spent in the prior year and roughly in line with the reduced spending
pace adopted for 1998's last half. During 1999's 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
during the second quarter to increase activity. As shown in the table above,
capital spending was sharply higher in the last half of 1999, largely due to the
previously mentioned acceleration of the Barnett Shale development program.
In gas services, substantial improvements involving the Bridgeport gas
processing plant and gathering system were completed in the last half of 1999.
And, in October 1999, the Company acquired Conoco's 50% interest in the Jameson
facilities. During the fourth quarter, projects were completed that added to the
throughput volumes of the Company's gathering systems, particularly the North
Texas and Vanderbilt systems.
The Company's 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. Of the exploration and
production budget, approximately $108.5 million is planned for drilling
primarily low-risk gas development wells. In gas services, planned spending
primarily involves expansion of facilities in North Texas around the Bridgeport
plant, new well connections to add to pipeline throughput and various gathering
system and processing plant improvements. [As subsequently reported, the budget
was later increased to just over $300 million.]
-18-
<PAGE> 21
FINANCING MATTERS. Cash provided by operating activities increased 70% to $244
million in 1999. This increase, coupled with proceeds from sales of
non-strategic assets, funded the accelerating capital program and allowed
long-term debt to be paid down by $93.5 million, to $379.3 million. A further
debt reduction is expected in 2000 even with the planned increase in capital
spending. [Long-term debt totaled $314.3 million at July 31, 2000.]
The Company has a $250 million bank revolving credit facility and a $25
million bank money-market facility. At December 31, 1999, borrowings of $65
million were outstanding under the revolving credit facility. While the Company
has no immediate plans to issue additional senior notes or to increase the size
of its bank revolving 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 ($185 million at December 31,
1999). Because of a receivable sales agreement that lowered costs and eliminated
the need to fund the Company's receivables with bank borrowings, the Company's
long-term debt and working capital balances were each $60 million less at
December 31, 1999 than they otherwise would have been.
DIVIDEND POLICY. The Company has paid regular quarterly cash dividends on its
common stock for an uninterrupted period of 21 years. Since fiscal 1994, annual
regular dividends totaling 48 cents and 53 cents per share have been paid on the
Company's Class A and Class B common stock.
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 16), 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 $15 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 (such purchases generally equal from 35% to 40% of gas
sales). Since it has this "natural" hedge, the Company only infrequently 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 December 31, 1999, and its hedging activities during
the last three years were insignificant.
The Company's exposure to changing interest rates is limited since 83%
of its long-term debt at December 31, 1999 consisted of senior notes with fixed
interest rates.
ENVIRONMENTAL MATTERS. Concern for the environment has been a fundamental part
of the Company's operating philosophy for many years. In the ordinary course of
conducting its business, the Company incurs costs - both expensed and
capitalized - to preserve and protect the environment. As public concern for the
environment has grown, new environmental laws have been enacted, more stringent
regulations have been implemented and enforcement of existing controls has been
strengthened. The Company considers the cost of environmental protection a
necessary and manageable part of its business. The Company has not been faced
with major cleanup obligations and has been able to conform with environmental
regulations without materially altering its operating strategies.
-19-
<PAGE> 22
Over the next two or three years, the Company estimates that its
expenditures to comply with environmental regulations will total approximately
$6 million per year. These costs consist principally of third-party charges for
water and waste disposal associated with oil and gas wells but also include
non-routine expenses for remediation of old sites, storm water control projects
and emission controls. The Company's annual compliance expenditures could
increase by one-third in 2002 when new Federal Clean Air Act regulations become
effective.
While it is not possible to fully anticipate all of the financial
obligations or operating constraints that might ultimately result from
increasingly stringent environmental regulations and enforcement programs,
management believes the Company is well-positioned within the industries in
which it competes to deal with environmental protection requirements.
Furthermore, demand for clean-burning natural gas, the cornerstone of the
Company's energy operations, is likely to benefit from increasing environmental
awareness.
YEAR 2000 ISSUE. Because of its efforts and those of its business partners over
an extended period, the Company experienced "business as usual" in January 2000
and on February 29, 2000. Most of the Company's efforts in this regard were
accomplished by reallocating internal resources; related third party costs
totaled $820,000. While it is possible that as-yet undetected Year 2000 problems
could become known, no significant problems or additional costs are anticipated.
OPERATING STATISTICS
Certain operating statistics (including, where applicable, proportional
interests in equity partnerships) for the years ended December 31, 1999, 1998
and 1997 follow:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
AVERAGE DAILY VOLUMES
Natural gas sales (Mcf) ........................ 244,700 247,500 236,100
Crude oil and condensate sales (Bbls) .......... 5,900 6,800 6,100
Natural gas liquids produced (Bbls) ............ 44,000 41,800 45,500
Pipeline throughput (Mcf) ...................... 555,000 554,000 411,000
AVERAGE SALES PRICES
Natural gas (per Mcf) .......................... $ 2.42 $ 2.15 $ 2.62
Crude oil and condensate (per Bbl) ............. 17.17 12.60 19.27
Natural gas liquids produced (per Bbl) ......... 14.20 10.48 13.96
</TABLE>
-20-
<PAGE> 23
RESULTS OF OPERATIONS - 1999 COMPARED WITH 1998
OVERVIEW. Earnings from continuing operations for 1999 and 1998 - both before
and after unusual items - are summarized in the table that follows. Earnings
from continuing operations totaled $67.3 million in 1999, compared to the prior
year's loss of $32.9 million. Exclusive of unusual items in both periods, 1999
after-tax earnings totaled $67.1 million, versus 1998's $4.1 million loss.
Higher energy prices, reduced personnel costs and lower geological and
geophysical expenses were the principal causes of the year-to-year earnings
turnaround. The following table and discussion identify and explain the major
increases (decreases) in earnings (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>
1998 AMOUNTS AFTER UNUSUAL ITEMS .................................. $ (27.8) $ 28.4 $ (58.7) $ (58.1) $ (32.9)
ELIMINATE IMPACT OF 1998 UNUSUAL ITEMS
(see bottom section of table on page 24) ....................... 38.2 7.6 -- 45.8 28.8
------- -------- ------- ------- -------
1998 AMOUNTS BEFORE UNUSUAL ITEMS ................................. 10.4 36.0 (58.7) (12.3) (4.1)
------- -------- ------- ------- -------
MAJOR INCREASES (DECREASES)
Higher natural gas sales price .................................... 22.7 -- -- 22.7 14.8
Higher crude oil and condensate sales price ....................... 9.4 -- -- 9.4 6.1
Reduced geological and geophysical expenses ....................... 19.3 -- -- 19.3 12.5
Decreased exploratory well
impairments ($3.0 versus $5.1) ................................. 2.1 -- -- 2.1 1.4
Lower DD&A rate ($.85 versus
$.88 per equivalent Mcf produced) .............................. 2.2 -- -- 2.2 1.4
Price-related increases in NGL margins ............................ -- 29.2 -- 29.2 19.0
Higher NGL production volumes ..................................... -- 2.3 -- 2.3 1.5
Increased NGL marketing earnings .................................. -- 6.5 -- 6.5 4.2
Lower Bridgeport plant repairs and maintenance .................... -- 2.5 -- 2.5 1.6
Salary and benefit savings
from personnel reductions ...................................... 5.6 5.3 3.3 14.2 9.2
Higher bonus accruals ............................................. (.9) (.6) (1.4) (2.9) (1.9)
1998 state income tax credit ...................................... -- -- -- -- (3.7)
Lower effective income tax rate ................................... -- -- -- -- 1.3
Other, net ........................................................ .2 5.9 (.3) 5.8 3.8
------- -------- ------- ------- -------
60.6 51.1 1.6 113.3 71.2
------- -------- ------- ------- -------
1999 AMOUNTS BEFORE UNUSUAL ITEMS ................................. 71.0 87.1 (57.1) 101.0 67.1
------- -------- ------- ------- -------
<CAPTION>
See
Page
----
<S> <C> <C> <C> <C> <C> <C>
1999 UNUSUAL ITEMS
Personnel reduction program costs............................ 42 (8.5) (7.1) (8.9) (24.5) (15.7)
Water well litigation provision reversals.................... 36 14.0 -- -- 14.0 8.7
Gain from sale of Hell's Hole area properties................ 42 11.5 -- -- 11.5 7.2
------- -------- ------- ------- -------
17.0 (7.1) (8.9) 1.0 .2
------- -------- ------- ------- -------
1999 AMOUNTS AFTER UNUSUAL ITEMS............................. $ 88.0 $ 80.0 $ (66.0) $ 102.0 $ 67.3
======= ======== ======= ======= =======
</TABLE>
----------
* Includes general and administrative expense and other expense.
-21-
<PAGE> 24
EXPLORATION AND PRODUCTION OVERVIEW. Exclusive of unusual items, exploration and
production segment operating earnings of $71.0 million during 1999 were $60.6
million above those of the prior year. This improvement was principally due to
higher prices for natural gas and oil and reductions in geological and
geophysical and other operating costs. Natural gas sales volumes averaged 244.7
MMcf per day in 1999, down slightly from the prior year's 247.5 MMcf per day
because of curtailed drilling during the last half of 1998 and early in 1999.
Natural gas sales volumes increased steadily over the last four months of 1999
because of a mid-year acceleration of the Barnett Shale development program.
Fourth quarter production averaged 261.3 MMcf per day, 6% above the prior year's
fourth quarter.
Higher natural gas sales price ($22.7 million increase). During 1999, the
Company's natural gas sales price averaged $2.42 per Mcf, $.27 (13%) above the
prior period's $2.15, increasing operating earnings by $22.7 million.
Higher oil and condensate sales price ($9.4 million increase). The Company's
sales price for oil and condensate averaged $17.17 per barrel during 1999, up
$4.57 from the prior period's $12.60, increasing operating earnings by $9.4
million.
Lower geological and geophysical expenses ($19.3 million increase). During 1999,
geological and geophysical expenses totaled $6.1 million, down from $25.4
million during the prior year, improving operating earnings by $19.3 million.
During 1998, the Company completed an aggressive 3-D seismic program that was
not repeated in 1999.
GAS SERVICES OVERVIEW. Gas services operating earnings rose $51.1 million to
$87.1 million during 1999 principally due to price-related increases in gas
processing margins and earnings from NGL marketing operations. Also contributing
to the increase were reductions in personnel costs and other operating expenses.
For the reasons discussed below, the Company's NGL volumes grew by 5% in 1999,
to 44,000 barrels per day; during the fourth quarter, such production averaged
50,300 barrels per day.
Improved NGL margins ($29.2 million increase). The average price for NGLs
produced during 1999 of $14.20 per barrel was 35% above the prior year's $10.48,
improving NGL revenues by $51.6 million. Because of the impact of the year's
higher NGL and natural gas prices on producer settlement and gas shrinkage
costs, feedstock costs also increased, resulting in a net $29.2 million
price-related increase in NGL margins.
Higher NGL production volumes ($2.3 million increase). NGL production volumes
averaged 44,000 barrels per day, up 5% from 1998's 41,800, improving operating
earnings by $2.3 million. Poor NGL economics caused prior year volumes to be
reduced when ethane was rejected (and sold as natural gas) at the Bridgeport
plant and other gas was not processed. Also contributing to the year-to-year
volume increase was the acquisition of our partner's 50% interest in the Jameson
plant in October 1999 and increased throughput of the Company's Vanderbilt
system that is processed at the Exxon Katy plant.
-22-
<PAGE> 25
Increased NGL marketing earnings ($6.5 million increase). Because of the passage
of time between the production of NGLs and the sale of fractionated products,
NGL marketing operations generally benefit from rising product prices. NGL
prices rose during the current year (particularly in the third and fourth
quarters) after declining during much of the prior year. As a result, there was
a $6.5 million year-to-year increase in NGL marketing earnings.
OTHER
Salary and benefit savings from personnel reductions ($14.2 million increase).
These savings were the result of the personnel reduction program undertaken
early in 1999.
RESULTS OF OPERATIONS - 1998 COMPARED WITH 1997
OVERVIEW. Earnings from continuing operations for 1998 and 1997 - both before
and after unusual items - are summarized in the table that follows. The Company
incurred a loss of $32.9 million from continuing operations during 1998, which
compared with the prior year's earnings of $44.3 million. Excluding the effects
of unusual items in both years, 1998's loss was $4.1 million, versus earnings of
$64.0 million in 1997. The earnings decline was primarily caused by lower energy
sales prices, increased interest expense attributable to continuing operations
and reduced interest income on excess cash balances.
-23-
<PAGE> 26
The following table and discussion identify and explain the major
increases (decreases) in earnings (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>
1997 AMOUNTS AFTER UNUSUAL ITEMS ................................. $ 73.0 $ 41.0 $ (48.1) $ 65.9 $ 44.3
------ ------ ------- ------- -------
See
ELIMINATE IMPACT OF 1997 UNUSUAL ITEMS Page
----
Royalty litigation settlement provision ....... 43 -- 26.0 -- 26.0 16.9
Water well litigation provision ............... 36 7.0 -- -- 7.0 4.3
Gain from sale of contract drilling assets .... 43 (2.4) -- -- (2.4) (1.5)
------ ------ ------- ------- -------
................................................................. 4.6 26.0 -- 30.6 19.7
------ ------ ------- ------- -------
1997 AMOUNTS BEFORE UNUSUAL ITEMS ................................ 77.6 67.0 (48.1) 96.5 64.0
------ ------ ------- ------- -------
MAJOR INCREASES (DECREASES)
Lower natural gas sales price .................................... (40.3) -- -- (40.3) (26.2)
Lower crude oil and condensate sales price ....................... (15.8) -- -- (15.8) (10.3)
Higher natural gas sales volumes ................................. 6.2 -- -- 6.2 4.0
Higher oil and condensate sales volumes .......................... 3.4 -- -- 3.4 2.2
Increased geological and geophysical expenses .................... (11.4) -- -- (11.4) (7.4)
Higher DD&A rate ($.88 versus
$.84 per equivalent Mcf produced) ............................. (4.4) -- -- (4.4) (2.9)
Price-related decreases in NGL margins ........................... -- (24.8) -- (24.8) (16.1)
Lower NGL volumes ................................................ -- (2.9) -- (2.9) (1.9)
Gain from a partnership's sale of the
Brooks-Hidalgo gathering system ............................... -- 3.5 -- 3.5 2.3
Depreciation expense on North Texas
gathering system acquired in January 1998 ..................... -- (3.0) -- (3.0) (2.0)
Increased interest expense
attributable to continuing operations ......................... -- -- (7.8) (7.8) (5.1)
Interest income on excess cash balances .......................... -- -- (6.7) (6.7) (4.4)
Performance unit expense accruals ................................ (1.1) (.5) (.6) (2.2) (1.4)
State income tax credit .......................................... -- -- -- -- 3.7
Higher effective income tax rate ................................. -- -- -- -- (.9)
Other, net ....................................................... (3.8) (3.3) 4.5 (2.6) (1.7)
------ ------ ------- ------- -------
(67.2) (31.0) (10.6) (108.8) (68.1)
------ ------ ------- ------- -------
1998 AMOUNTS BEFORE UNUSUAL ITEMS ................................ 10.4 36.0 (58.7) (12.3) (4.1)
------ ------ ------- ------- -------
See
1998 UNUSUAL ITEMS Page
----
Proved property impairments ................... 43 (42.2) -- -- (42.2) (26.4)
Gas services asset write-downs ................ 43 -- (7.6) -- (7.6) (4.9)
Water well litigation provision reversals ..... 36 4.0 -- -- 4.0 2.5
------ ------ ------- ------- -------
(38.2) (7.6) -- (45.8) (28.8)
------ ------ ------- ------- -------
1998 AMOUNTS AFTER UNUSUAL ITEMS ................................. $(27.8) $ 28.4 $ (58.7) $ (58.1) $ (32.9)
====== ====== ======= ======= =======
</TABLE>
----------
* Includes general and administrative expense and other expense.
-24-
<PAGE> 27
EXPLORATION AND PRODUCTION OVERVIEW. Exclusive of unusual items, exploration and
production 1998 segment operating earnings of $10.4 million were sharply lower
than the $77.6 million of the prior year primarily because of 1998's lower
prices for natural gas and oil and condensate sales. Daily natural gas
production increased 5% during 1998, to 247.5 MMcf, and oil and condensate
production increased 11% to 6,800 barrels per day.
Lower natural gas sales price ($40.3 million decrease). The Company's natural
gas sales price averaged $2.15 per Mcf in 1998, $.47 (18%) below the $2.62
realized in the prior year, reducing operating earnings by $40.3 million. As
shown by the table on page 16, natural gas prices were substantially higher in
the fourth quarter of 1997 than they were in 1998.
Lower oil and condensate sales price ($15.8 million decrease). The Company's
sales price for oil and condensate averaged $12.60 per barrel during 1998, down
sharply from the prior year's $19.27, reducing operating earnings by $15.8
million. The collapse in world oil prices was largely the result of
overproduction, very mild winter weather in the U.S. and an economic downturn in
Southeast Asia and other parts of the world.
Higher natural gas sales volumes ($6.2 million increase). Natural gas sales
volumes averaged 247.5 MMcf per day during 1998, up from 236.1 MMcf during the
prior year, increasing operating earnings by $6.2 million. This increase was
principally due to drilling and recompletion activity in North Texas, Limestone
County, the Lake Creek field and the Columbus field - which was purchased early
in 1998.
Higher oil and condensate sales volumes ($3.4 million increase). Production of
oil and condensate increased 700 barrels per day in 1998 to 6,800, increasing
operating earnings by $3.4 million. This resulted largely from 1997 drilling and
recompletion activity in Throckmorton County (North Texas), the Lake Creek field
(Southeast Texas) and Calcasieu Parish (Southwest Louisiana). Drilling and
recompletion activity in the Columbus field during 1998 also contributed to this
increase.
Increased geological and geophysical expenses ($11.4 million decrease). Largely
because of a planned increase in 3-D exploratory seismic survey expenditures,
the Company incurred $11.4 million more in geological and geophysical expenses
in 1998 when it conducted surveys in McMullen County, Texas (Franklin Ranch
area), Wise County, Texas (Frazier area) and Throckmorton County, Texas
(McCluskey area).
GAS SERVICES OVERVIEW. Gas services operating earnings declined $31.0 million
(to $36.0 million) during 1998 principally because of price-related reductions
in gas processing margins and volumes. NGL production averaged 41,800 barrels
per day, down 8% from 1997's 45,500. The production decline was largely the
result of decisions not to recover ethane or to bypass the processing of certain
natural gas when these actions increased the Company's overall profitability.
-25-
<PAGE> 28
Price-related decreases in NGL margins ($24.8 million decrease). The average
price for NGLs produced during 1998 of $10.48 per barrel was 25% below the prior
year's $13.96, reducing NGL revenues by $52.6 million. Because of the impact of
the lower NGL and natural gas prices on producer payments, feedstock costs also
fell, reducing the net margin decline to $24.8 million.
OTHER
Interest expense attributable to continuing operations ($7.8 million decrease).
Because a portion of the proceeds from the sale of The Woodlands Corporation
(TWC) was reinvested in continuing operations rather than being used to retire
debt related to discontinued operations, interest expense attributable to
continuing operations rose by $7.8 million during 1998. Total interest expense -
including that attributable to discontinued operations - declined by $9.9
million largely because of the repurchase during September and October 1997 of
$185.7 million of 9 1/4% senior notes.
Performance unit expense accruals ($2.2 million decrease). In December 1997, the
Company awarded performance units to mid-level managerial and professional
employees that entitled holders of those units on March 31, 1999 to receive cash
compensation equal to the closing price of the Company's Class B Common Stock on
that date times the number of units awarded to them. Compensation expense -
which was accrued ratably over the 15.5-month life of the units - was $2.2
million higher in 1998 ($2.5 million versus $.3 million).
1997 state income tax credit ($3.7 million net earnings increase). The Company's
1997 effective income tax rate on earnings from continuing operations (32.8%)
benefitted from a deferred state income tax credit related to a reorganization
of the legal structure under which gas services operations are conducted.
-26-
<PAGE> 29
Mitchell Energy & Development Corp. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
(dollar amounts in thousands)
<TABLE>
<CAPTION>
1999 1998
----------- -----------
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash and cash equivalents ....................................................... $ 24,024 $ 15,333
Trade receivables (net of allowance for doubtful accounts of $303 and $318) ..... 42,895 50,842
Inventories ..................................................................... 5,160 14,488
Income taxes receivable ......................................................... -- 4,294
Other ........................................................................... 5,922 9,706
----------- -----------
Total current assets ....................................................... 78,001 94,663
PROPERTY, PLANT AND EQUIPMENT (at cost less accumulated depre-
ciation, depletion and amortization of $1,490,076 and $1,458,742 - Note 2) .... 1,050,298 1,035,696
LONG-TERM INVESTMENTS AND OTHER ASSETS .......................................... 35,380 33,056
----------- -----------
$ 1,163,679 $ 1,163,415
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Current maturities of long-term debt ............................................ $ -- $ 100,000
Oil and gas proceeds payable .................................................... 70,320 63,259
Accounts payable ................................................................ 40,962 38,041
Accrued liabilities ............................................................. 42,298 43,126
----------- -----------
Total current liabilities .................................................. 153,580 244,426
----------- -----------
LONG-TERM DEBT (Note 4) ......................................................... 379,267 372,767
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES
Deferred income taxes (Note 5) .................................................. 158,307 137,961
Retirement obligations (Note 8) ................................................. 71,883 58,179
Deferred income and other ....................................................... 15,468 8,800
----------- -----------
245,658 204,940
----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 6 and 8)
STOCKHOLDERS' EQUITY
Preferred stock, $.10 par value (authorized 10,000,000 shares; none issued)
Common stock, $.10 par value (authorized 200,000,000 shares) (Note 10) .......... 5,386 5,386
Additional paid-in capital ...................................................... 143,636 143,636
Retained earnings ............................................................... 346,192 303,774
Other comprehensive loss ........................................................ (5,890) (7,364)
Treasury stock, at cost ......................................................... (104,150) (104,150)
----------- -----------
385,174 341,282
----------- -----------
$ 1,163,679 $ 1,163,415
=========== ===========
</TABLE>
----------
The accompanying notes are an integral part of these financial statements.
-27-
<PAGE> 30
Mitchell Energy & Development Corp. and Subsidiaries
CONSOLIDATED STATEMENTS OF EARNINGS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(in thousands except per-share amounts)
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
REVENUES
Exploration and production (including a gain of $11,527
from sale of Hell's Hole area properties in 1999 - Note 9) .................................. $ 265,888 $ 227,440 $ 273,953
Gas services ................................................................................... 628,468 492,820 536,791
--------- --------- ---------
894,356 720,260 810,744
--------- --------- ---------
OPERATING COSTS AND EXPENSES (including personnel
reduction program costs of $15,652 in 1999 - Note 9)
Exploration and production (including proved property impairments of $42,250
in 1998 and litigation provision (reversals) of $(14,000); $(4,000) and $7,000 - Note 6) .... 177,862 255,314 200,914
Gas services (including asset write-downs of $7,560
in 1998 and litigation provision of $26,000 in 1997) ........................................ 548,533 464,369 495,834
--------- --------- ---------
726,395 719,683 696,748
--------- --------- ---------
SEGMENT OPERATING EARNINGS (Note 9) ............................................................ 167,961 577 113,996
General and administrative expense (including
personnel reduction program costs of $8,848 in 1999) ........................................ 37,626 30,410 31,623
--------- --------- ---------
TOTAL OPERATING EARNINGS (LOSS) ................................................................ 130,335 (29,833) 82,373
--------- --------- ---------
OTHER EXPENSE
Interest expense (excluding $17,765 attributable to discontinued operations in 1997) ........... 34,499 34,572 26,733
Other (income) expense, net .................................................................... (6,162) (6,281) (10,261)
--------- --------- ---------
28,337 28,291 16,472
--------- --------- ---------
EARNINGS (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES ................................. 101,998 (58,124) 65,901
INCOME TAXES (Note 5) .......................................................................... 34,664 (25,270) 21,610
--------- --------- ---------
EARNINGS (LOSS) FROM CONTINUING OPERATIONS ..................................................... 67,334 (32,854) 44,291
--------- --------- ---------
DISCONTINUED REAL ESTATE OPERATIONS (Note 13)
Earnings from operations, net of income taxes of $4,748 ........................................ -- -- 8,608
Loss on sale, net of income taxes of $1,750
in 1998 and income tax benefit of $25,878 in 1997 ........................................... -- 3,250 (67,123)
--------- --------- ---------
-- 3,250 (58,515)
--------- --------- ---------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM ...................................................... 67,334 (29,604) (14,224)
EXTRAORDINARY ITEM - Extinguishment of debt,
net of income tax benefit of $7,135 (Note 14) ............................................... -- -- (13,250)
--------- --------- ---------
NET EARNINGS (LOSS) ............................................................................ $ 67,334 $ (29,604) $ (27,474)
========= ========= =========
BASIC AND DILUTED EARNINGS (LOSS) PER SHARE (Note 12)
From continuing operations .................................................................. $ 1.37 $ (.67) $ .87
Net earnings ................................................................................ 1.37 (.60) (.54)
AVERAGE COMMON SHARES OUTSTANDING (Basic) ...................................................... 49,117 49,100 50,925
</TABLE>
----------
The accompanying notes are an integral part of these financial statements.
-28-
<PAGE> 31
Mitchell Energy & Development Corp. and Subsidiaries
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(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, DECEMBER 31, 1996 ............................ $ 543,812 $ 5,386 $ 143,299 $ 423,915 $ -- $ (28,788)
Net loss .............................................. (27,474) -- -- (27,474) -- --
Regular cash dividends (48 cents per share
on Class A and 53 cents per share on Class B) ...... (25,691) -- -- (25,691) -- --
Special cash dividends (24 cents per share
on Class A and 26.5 cents per share on Class B) .... (12,462) -- -- (12,462) -- --
Treasury stock purchases .............................. (69,517) -- -- -- -- (69,517)
Exercises of stock options ............................ 3,337 -- 253 -- -- 3,084
--------- --------- ---------- --------- --------- ---------
BALANCE, DECEMBER 31, 1997 ............................ 412,005 5,386 143,552 358,288 -- (95,221)
Net loss .............................................. (29,604) -- -- (29,604) -- --
Minimum pension liability adjustment
(net of income tax benefit of $3,975) .............. (7,364) -- -- -- (7,364) --
---------
Comprehensive loss .............................. (36,968)
Cash dividends (48 cents per share on
Class A and 53 cents per share on Class B) ......... (24,910) -- -- (24,910) -- --
Treasury stock purchases (including
$7,458 adjustment payment on 1997
accelerated stock purchase transaction) ............ (12,165) -- -- -- -- (12,165)
Exercises of stock options ............................ 3,320 -- 84 -- -- 3,236
--------- --------- ---------- --------- --------- ---------
BALANCE, DECEMBER 31, 1998 ............................ 341,282 5,386 143,636 303,774 (7,364) (104,150)
Net earnings .......................................... 67,334 -- -- 67,334 -- --
Minimum pension liability adjustment
(net of income taxes of $780) ...................... 1,474 -- -- -- 1,474 --
---------
Comprehensive income ............................ 68,808
Cash dividends (48 cents per share on
Class A and 53 cents per share on Class B) ......... (24,916) -- -- (24,916) -- --
--------- --------- ---------- --------- --------- ---------
BALANCE, DECEMBER 31, 1999 ............................ $ 385,174 $ 5,386 $ 143,636 $ 346,192 $ (5,890) $(104,150)
========= ========= ========== ========= ========= =========
</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, 1996 .... 23,978,091 29,878,091 924,529 1,103,624 51,828,029
Treasury stock purchases ...... -- -- 745,000 2,110,000 (2,855,000)
Exercises of stock options .... -- -- (12,592) (155,858) 168,450
Other ......................... (8) (8) -- -- (16)
----------- ----------- ------------ ---------- ------------
BALANCE, DECEMBER 31, 1997 .... 23,978,083 29,878,083 1,656,937 3,057,766 49,141,463
Treasury stock purchases ...... -- -- -- 174,200 (174,200)
Exercises of stock options .... -- -- (500) (149,516) 150,016
Other ......................... (6) (6) -- -- (12)
----------- ----------- ------------ ---------- ------------
BALANCE, DECEMBER 31, 1998 .... 23,978,077 29,878,077 1,656,437 3,082,450 49,117,267
Other ......................... (5) (5) -- -- (10)
----------- ----------- ------------ ---------- ------------
BALANCE, DECEMBER 31, 1999 .... 23,978,072 29,878,072 1,656,437 3,082,450 49,117,257
=========== =========== ============ ========== ============
</TABLE>
----------
The accompanying notes are an integral part of these financial statements.
-29-
<PAGE> 32
Mitchell Energy & Development Corp. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
(in thousands)
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Earnings (loss) from continuing operations ............................................. $ 67,334 $ (32,854) $ 44,291
Adjustments to reconcile earnings (loss) from continuing
operations to cash provided by operating activities
Depreciation, depletion and amortization (including producing property
impairments of $42,250 and gas services asset write-downs of $7,560 in 1998) .... 111,641 167,438 104,808
Exploration expenses (including exploratory well impairments) ..................... 9,022 30,488 19,258
Deferred income taxes ............................................................. 19,552 (15,229) 18,031
Distributions in excess of earnings of equity investees ........................... 4,289 10,606 997
Accrued personnel reduction program costs ......................................... 17,620 -- --
Litigation provisions (reversals) ................................................. (14,000) (4,000) 33,000
Gain from sales of assets ......................................................... (11,527) -- (2,382)
Other, net ........................................................................ (8,249) (3,008) (3,880)
--------- --------- ---------
195,682 153,441 214,123
Changes in operating assets and liabilities
Receivables ..................................................................... 13,012 36,957 131,192
Inventories ..................................................................... 9,328 75 (5,052)
Payables ........................................................................ 10,421 (31,619) (37,583)
Accrued liabilities and other ................................................... 15,521 (15,240) (33,229)
--------- --------- ---------
Cash provided by operating activities ............................................. 243,964 143,614 269,451
--------- --------- ---------
INVESTING ACTIVITIES
Capital and exploratory expenditures
Total on accrual basis (including asset
acquisitions of $24,071; $89,012 and $26,694) ..................................... (164,031) (305,234) (256,395)
Adjustment to cash basis ............................................................ (439) (544) 1,932
--------- --------- ---------
(164,470) (305,778) (254,463)
Proceeds from sales of assets .......................................................... 44,220 2,388 7,065
Net proceeds from sale of The Woodlands Corporation .................................... -- -- 480,994
Repayments of off-balance-sheet partnership debt ....................................... -- (43,827) --
Other, net ............................................................................. 3,710 3,644 (3,536)
--------- --------- ---------
Cash provided by (used for) investing activities .................................. (116,540) (343,573) 230,060
--------- --------- ---------
FINANCING ACTIVITIES
Debt repayments ........................................................................ (100,000) (60,000) (315,733)
Proceeds from issuance of debt ......................................................... 6,500 118,500 --
Cash dividends (including special dividends of $12,462 in 1997) ........................ (24,916) (24,913) (38,500)
Treasury stock purchases ............................................................... -- (12,165) (69,517)
Other (including debt reacquisition costs of $19,294 in 1997) .......................... (317) 2,520 (17,619)
--------- --------- ---------
Cash provided by (used for) financing activities .................................. (118,733) 23,942 (441,369)
--------- --------- ---------
INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS FROM CONTINUING OPERATIONS .............................................. 8,691 (176,017) 58,142
CASH PROVIDED BY DISCONTINUED OPERATIONS ............................................... -- 15,397 39,727
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR ........................................... 15,333 175,953 78,084
--------- --------- ---------
CASH AND CASH EQUIVALENTS, END OF YEAR ................................................. $ 24,024 $ 15,333 $ 175,953
========= ========= =========
</TABLE>
----------
The accompanying notes are an integral part of these financial statements.
-30-
<PAGE> 33
Mitchell Energy & Development Corp. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1999, 1998 AND 1997
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of operations and principles of consolidation. 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.
Use of estimates. 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.
Property, plant and equipment. The Company's exploration and production
activities are accounted for using the "successful efforts" method. Lease
acquisition costs are capitalized as are costs to drill and equip development
wells, including unsuccessful ones. Exploratory drilling costs are initially
capitalized; if proved reserves are not found, such costs are subsequently
impaired. Geological and geophysical costs and other exploration costs are
charged to expense as incurred. Depreciation, depletion and amortization (DD&A)
of proved oil and gas properties is determined on a field-by-field basis using
physical units of production. Estimated future costs of dismantlement,
restoration and abandonment are considered in determining DD&A expense.
The Company holds no unproved leases whose costs are individually
significant. Costs of unproved leaseholds are charged to expense over estimated
holding periods based on historical experience. Leasehold costs for properties
determined to be productive are transferred to proved oil and gas properties.
Other property, plant and equipment additions are recorded at cost and
depreciated on the straight-line method over their estimated service lives,
which range from 3 to 25 years. Maintenance and repair costs are charged to
expense; costs of renewals and betterments are capitalized.
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. Charges for such impairments,
which are included in DD&A expense, totaled none; $42,250,000 (see Note 9) and
$1,640,000 in 1999, 1998 and 1997.
-31-
<PAGE> 34
Environmental expenditures. Liabilities for environmental expenditures are
recognized when it is probable that obligations have been incurred in amounts
that are material and reasonably estimable.
Statements of Cash Flows. Short-term investments with maturities of three months
or less are considered to be cash equivalents. The reported amounts for proceeds
from issuance of debt and debt repayments exclude the impact of borrowings with
initial terms of three months or less. Interest paid, including amounts
attributable to discontinued operations in 1997, totaled $37,211,000;
$33,837,000 and $53,620,000 during 1999, 1998 and 1997. Income taxes paid during
those periods, including amounts applicable to discontinued operations, totaled
$5,591,000; $9,624,000 and $58,449,000 (a substantial portion of which was
related to the taxable gain on the sale of The Woodlands Corporation). There
were no significant non-cash investing or financing activities during the
three-year period ended December 31, 1999.
Accounting for derivatives. The Financial Accounting Standards Board issued
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 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.
(2) PROPERTY, PLANT AND EQUIPMENT
The cost and net book value of property, plant and equipment consisted of the
following at December 31, 1999 and 1998 (in thousands):
<TABLE>
<CAPTION>
Cost Net Book Value
------------------------- -------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
EXPLORATION AND PRODUCTION
Oil and gas properties ...................... $ 1,881,846 $ 1,867,809 $ 687,720 $ 684,083
Support equipment and facilities ............ 50,138 50,670 13,217 16,721
----------- ----------- ----------- -----------
1,931,984 1,918,479 700,937 700,804
----------- ----------- ----------- -----------
GAS SERVICES (including invest-
ments in equity partnerships - Note 3)
Natural gas processing ...................... 203,542 190,641 105,527 102,981
Natural gas gathering ....................... 302,001 289,916 153,796 147,397
Other ....................................... 87,364 79,761 86,091 78,595
----------- ----------- ----------- -----------
592,907 560,318 345,414 328,973
----------- ----------- ----------- -----------
CORPORATE ................................... 15,483 15,641 3,947 5,919
----------- ----------- ----------- -----------
$ 2,540,374 $ 2,494,438 $ 1,050,298 $ 1,035,696
=========== =========== =========== ===========
</TABLE>
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<PAGE> 35
(3) PARTNERSHIP INVESTMENTS
A summary of the Company's net investments in partnerships at December 31, 1999
and 1998 and its equity in their pretax earnings for the years ended December
31, 1999, 1998 and 1997 follows (in thousands):
<TABLE>
<CAPTION>
Net Investment Equity in Pretax Earnings
Percent ---------------------- -------------------------------------
Owned 1999 1998 1999 1998 1997
------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
NATURAL GAS PROCESSING
C&L Processors Partnership (C&L) ........... 50* $ 25,353 $ 60,450 $ 4,596 $ 173 $ 3,843
U.P. Bryan Plant ........................... 45* 2,093 2,267 7,419 1,086 3,300
Others ..................................... -- -- -- -- 40
--------- --------- --------- --------- ---------
27,446 62,717 12,015 1,259 7,183
--------- --------- --------- --------- ---------
GAS GATHERING AND MARKETING
Austin Chalk Natural Gas
Marketing Services (Austin Chalk) ....... 45* (93) 414 899 3,023 2,425
Ferguson-Burleson County Gas
Gathering System (Ferguson-Burleson) .... 45* 36,449 40,344 5,223 3,138 4,373
Louisiana Chalk Gathering System ........... 50 15,987 17,344 (908) (790) (305)
Others ..................................... 448 361 84 3,672** (30)
--------- --------- --------- --------- ---------
52,791 58,463 5,298 9,043 6,463
--------- --------- --------- --------- ---------
OTHER
Belvieu Environmental Fuels (BEF) .......... 33.33 56,043 47,010 9,293 8,588 10,095
Gulf Coast Fractionators ................... 38.75 28,493 29,921 3,357 4,556 4,791
--------- --------- --------- --------- ---------
84,536 76,931 12,650 13,144 14,886
--------- --------- --------- --------- ---------
$ 164,773 $ 198,111 $ 29,963 $ 23,446 $ 28,532
========= ========= ========= ========= =========
</TABLE>
----------
* Prior to the asset exchange on March 31, 2000 discussed below.
** 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.
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. The Company subsequently purchased Conoco's 50% interest for
approximately $23,900,000, and the Jameson facilities became wholly owned and
ceased being reported as part of C&L's operations effective October 1, 1999.
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 the first quarter of 2000 in connection with the exchange.
-33-
<PAGE> 36
Of the partnerships, only BEF had outstanding debt that was recourse to
the Company at December 31, 1999. At that date, BEF's bank loan had an
outstanding balance of $19,556,000, the Company's share of which totaled
$6,519,000. The loan, which bore interest at floating rates based on spreads
over LIBOR, was due in quarterly installments of $9,778,000 plus interest
through May 2000, when it was repaid. BEF owns a plant located at Mont Belvieu,
Texas with the capacity to produce up to 17,000 barrels per day of MTBE, a
gasoline additive that reduces carbon monoxide emissions. BEF has entered into
agreements which require each of the three partners to provide one-third of the
plant's isobutane feedstock and one of the partners, Sun Company, Inc., to
purchase all of its production for a period extending through September 2004.
Summarized balance sheet information (on a 100% basis) for these entities
at December 31, 1999 and 1998 follows (in thousands):
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
Current assets ......................................................................... $ 103,106 $ 92,427
Net noncurrent assets .................................................................. 401,880 501,043
Current liabilities .................................................................... 75,906 59,112
Debt payable to third parties (including current maturities of $25,588 and $60,350)..... 25,588 92,542
Notes payable to owners (including $5,000 payable to the Company in 1998) .............. -- 10,000
Owners' equity ......................................................................... 403,492 431,816
</TABLE>
Summarized earnings information (on a 100% basis) for these entities for
the years ended December 31, 1999, 1998 and 1997 follows (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Revenues ......................... $ 594,795 $ 557,659 $ 775,107
Operating earnings ............... 70,805 59,611 89,451
Pretax earnings .................. 61,542 44,545 71,446
</TABLE>
(4) LONG-TERM DEBT
The Company's outstanding debt consists of unsecured parent company senior
notes, the proceeds of which have been advanced to the operating subsidiaries,
and borrowings under bank revolving credit and money market facilities. A
summary of outstanding debt at December 31, 1999 and 1998 follows (in
thousands):
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
Unsecured senior notes
9 1/4%, due January 15, 2002 .................................. $ 64,267 $ 64,267
6 3/4%, due February 15, 2004 ................................. 250,000 250,000
8%, repaid on July 15, 1999 ................................... -- 100,000
Committed bank revolving credit agreement, unsecured ............. 65,000 55,000
Uncommitted money market facility, at floating interest rates..... -- 3,500
--------- ---------
379,267 472,767
Less - Current maturities ........................................ -- 100,000
--------- ---------
$ 379,267 $ 372,767
========= =========
</TABLE>
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<PAGE> 37
The Company has a five-year $250,000,000 committed bank revolving credit
facility that terminates in July 2003, when any borrowings 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 senior notes have no sinking fund requirements and are not redeemable
prior to their respective maturity dates. 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 $108,329,000 at
December 31, 1999. The bank credit agreement and/or the senior notes indentures
also limit the amounts of additional borrowings and letters of credit, restrict
the sale or lease of certain assets and limit the right of the parent company
and certain subsidiaries to merge with other companies.
(5) INCOME TAXES
Income taxes applicable to earnings from continuing operations for the years
ended December 31, 1999, 1998 and 1997 consisted of the following (in
thousands):
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
CURRENT - Federal ............... $ 14,782 $ (9,501) $ 2,701
State ................. 330 (540) 878
-------- -------- --------
15,112 (10,041) 3,579
-------- -------- --------
DEFERRED - Federal .............. 18,309 (9,568) 17,738
State ................ 1,243 (5,661) 293
-------- -------- --------
19,552 (15,229) 18,031
-------- -------- --------
$ 34,664 $(25,270) $ 21,610
======== ======== ========
</TABLE>
The deferred state income tax credit of $5,661,000 in 1998 resulted primarily
from a legal reorganization of gas services operations that allowed previously
recorded liabilities for such taxes to be reduced.
Reconciliations between the 35% statutory Federal income tax rate and the
Company's effective income tax rate for 1999, 1998 and 1997 follow:
<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Statutory Federal income tax rate ............................... 35.0% 35.0% 35.0%
State income taxes, net of Federal income tax effect ............ 1.0 6.9 1.2
Federal tax credits under Section 29 of the Internal Reve-
nue Code for natural gas produced from certain wells .......... (2.7) .3 (3.1)
Other, net ...................................................... .7 1.3 (.3)
------ ------ ------
34.0% 43.5% 32.8%
====== ====== ======
</TABLE>
-35-
<PAGE> 38
The principal components of the Company's deferred income tax liability
consisted of the following at December 31, 1999 and 1998 (in thousands):
<TABLE>
<CAPTION>
1999 1998
--------- ---------
<S> <C> <C>
Oil and gas acquisition, exploration and development costs
deducted for tax purposes in excess of financial statement DD&A ........ $ 136,635 $ 120,746
Depreciation of other property, plant and equipment ...................... 48,263 48,683
Unused alternative minimum tax credits ................................... (8,109) (13,952)
Accrued employee benefits expense not yet deductible for tax purposes .... (30,215) (25,798)
Other, net ............................................................... 11,733 8,282
--------- ---------
$ 158,307 $ 137,961
========= =========
</TABLE>
At December 31, 1999, the Company had $8,109,000 of unused alternative minimum
tax credits that can be carried forward indefinitely. These credits have been
recognized in the calculation of the Company's financial statement income tax
provisions. Accordingly, their future utilization would only reduce the amount
of taxes currently payable, not the financial statement income tax provision.
(6) COMMITMENTS AND CONTINGENCIES
North Texas water well litigation. In March 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 for $4,051,760 in actual damages 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, and in November 1997 the Second Court of Appeals
in Fort Worth, Texas, reversed the previous decision. Several plaintiffs'
attempts to appeal the reversal, including petitions to the Texas Supreme Court,
were subsequently denied, and the Bartlett case has concluded.
Several cases that involved allegations similar to those in the Bartlett
case were also brought, and the Company was victorious in each case. At December
31, 1999, no such ongoing litigation was outstanding, and this was no longer a
contingent liability of the Company.
Provisions totaling $32,000,000 were expensed over the years in connection
with this litigation, including a $7,000,000 charge in 1997. Costs incurred -
which consisted principally of attorneys' fees and other defense costs for the
Bartlett and other trials and costs of bonds, etc., related to the appeal of the
Bartlett judgment - were charged against the reserve.
Between May 1997 and January 2000, the Company entered into agreements
with seven insurance carriers reimbursing it for a total of $24,700,000 of the
defense costs incurred in connection with this litigation, all of which
reimbursements have been received. After entering into 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 second and third quarters of
1998. After entering into reimbursement agreements during March 1999 and October
1999, accrual reversals of $9,000,000 and $5,000,000, respectively, were
recorded in the first and fourth quarters of 1999. A final reversal of
$1,200,000 was recorded during the first quarter of 2000 when a final
reimbursement was received.
-36-
<PAGE> 39
Leases and contingent liabilities. The Company has various noncancellable
equipment and facility operating lease agreements which provide for aggregate
future payments of approximately $29,400,000. Minimum rentals for each of the
five years subsequent to 1999 total approximately $10,300,000; $9,000,000;
$4,900,000; $4,300,000 and $1,000,000. Rental expense for operating leases
totaled approximately $10,800,000; $6,200,000 and $6,400,000 in 1999, 1998 and
1997. In addition to obligations described elsewhere in these notes, the Company
had contingent liabilities totaling approximately $16,900,000 at December 31,
1999, consisting of guarantees of third-party debt. During May 2000, one of the
Company's guarantees in the amount of $8,000,000 was released.
Environmental regulations. The Company is considered by the United States
Environmental Protection Agency (the EPA) to be a potentially responsible party
with respect to two Superfund waste disposal sites. The only site involving more
than minimal potential exposure to the Company is the Operating Industries, Inc.
site located in Monterey Park, California, where small amounts of non-toxic
drilling fluids were deposited from Company-operated oil and gas wells. Although
the Company believes that it should be exempt from liability with respect to
this site, through December 31, 1999 it had paid and expensed approximately
$620,000 of costs. While additional exposure exists for future cleanup and
closure costs of this site, the Company's share of such costs is not expected to
be significant.
The Company continually monitors the many Federal, state and local laws
and regulations relating to the protection of the environment and public health
and believes it is in substantial compliance with such rules. Also, it expects
to continue to be able to conform with environmental regulations without
materially altering its operating strategies.
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.
As indicated in Note 3, 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.
-37-
<PAGE> 40
(7) FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair values of the Company's financial
instruments at December 31, 1999 and 1998 were as follows (in thousands):
<TABLE>
<CAPTION>
1999 1998
------------------------- -------------------------
Carrying Estimated Carrying Estimated
Amounts Fair Values Amounts Fair Values
--------- ----------- --------- -----------
<S> <C> <C> <C> <C>
Long-term debt (including current maturities) $ 379,267 $ 366,508 $ 472,767 $ 466,974
</TABLE>
Fair values of the Company's fixed-rate senior notes are based on quoted market
prices. For floating-rate debt, carrying amounts and fair values are assumed to
be equal because of the nature of these obligations. The carrying amounts of
other on-balance-sheet financial instruments approximate their fair values. The
aggregate cost to terminate off-balance-sheet financial instruments is not
significant.
In November 1998, Mitchell Receivables, Inc. (MRC), a wholly owned
subsidiary, entered into a securitization agreement which provides for ongoing
sales of up to $75,000,000 of energy accounts receivable. Proceeds from
outstanding sales under this program, which totaled $60,000,000 at December 31,
1999, were used to pay down revolving credit agreement borrowings. MRC is a
special purpose subsidiary whose assets must first be used to satisfy its
creditors and are not available to satisfy creditors of the parent company.
The Company has only limited involvement with derivative financial
instruments. It does not hold or issue derivative instruments for trading
purposes. The Company had no open hedge positions at December 31, 1999.
(8) RETIREMENT BENEFITS
Substantially all full-time employees of the Company who meet specified age and
service requirements are covered by a defined benefit retirement plan which is
maintained without cost to the employees. Pension benefits are based on years of
service and average earnings for the three highest consecutive years during the
ten years immediately preceding retirement. The Company's funding policy is to
make contributions to the plan of at least the minimum amounts required by
applicable Federal laws and regulations. No contributions were made to the plan
during 1999, 1998 or 1997.
Internal Revenue Service regulations limit the benefits that may be paid
to certain employees under the Company's qualified retirement plan. Nonqualified
plans are maintained to make the basis on which those individuals' retirement
benefits are determined the same as is used for other employees. A Rabbi trust
fund is maintained from which these benefits are paid. That fund's assets -
which under accounting principles generally accepted in the United States must
be reported as an asset of the Company rather than being offset against the
accrued benefit costs - totaled $20,566,000 and $15,054,000 at December 31, 1999
and 1998. These assets are included in Long-term Investments and Other Assets in
the accompanying balance sheets.
-38-
<PAGE> 41
Retirees who reach retirement age while working for the Company and meet
certain other eligibility requirements may elect coverage under the Company's
postretirement medical benefits plan. This plan incorporates a
scheduled-reimbursements methodology under which the Company and providers agree
to specified rates for individual services. The Company has the right to amend
or terminate medical benefits for active employees and retirees or to change the
required level of participant contributions. The cost of providing these
postretirement health care benefits is reduced by available Medicare coverage
and retiree contributions. The plan is unfunded, and benefits are paid as costs
are incurred.
The following table provides the indicated information for the years ended
December 31, 1999 and 1998 concerning the Company's retirement plans and its
postretirement medical benefits plan (dollar amounts in thousands):
<TABLE>
<CAPTION>
Qualified Nonqualified Retiree Medical
Retirement Plan Retirement Plans Benefits Plan
---------------------- ---------------------- ----------------------
1999 1998 1999 1998 1999 1998
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year ............... $ 153,992 $ 125,409 $ 19,500 $ 12,597 $ 24,698 $ 20,417
Service cost ........................................ 3,269 3,385 359 358 622 668
Interest cost ....................................... 11,219 8,813 1,322 870 1,875 1,428
Benefits paid ....................................... (12,899) (7,715) (1,492) (1,191) (2,352) (1,661)
Special termination benefits ........................ 15,611 -- 827 -- 2,873 --
Actuarial (gains) losses ............................ (18,952) 24,100 (1,517) 6,866 (464) 3,626
Curtailments ........................................ (2,973) -- -- -- 2,416 --
Plan amendments ..................................... 548 -- (548) -- -- --
Contributions by plan participants .................. -- -- -- -- 289 220
--------- --------- --------- --------- --------- ---------
Benefit obligation, end of year ..................... $ 149,815 $ 153,992 $ 18,451 $ 19,500 $ 29,957 $ 24,698
========= ========= ========= ========= ========= =========
CHANGE IN PLAN ASSETS
Plan assets at fair value,
beginning of year ................................ $ 172,114 $ 148,527
Actual return on plan assets ........................ 23,319 31,302
Benefits paid ....................................... (12,899) (7,715)
--------- ---------
Plan assets at fair value, end of year .............. $ 182,534 $ 172,114
========= =========
FUNDED STATUS AT YEAR END
Plan assets over (under) benefit obligation ......... $ 32,719 $ 18,122 $ (18,451) $ (19,500) $ (29,957) $ (24,698)
Unrecognized (gains) losses ......................... (58,981) (33,136) 9,575 12,002 7,479 7,057
Unrecognized prior service cost ..................... 636 235 114 814 (5,977) (6,768)
Unrecognized net transition obligation .............. -- -- 90 173 -- --
Minimum pension liability adjustment ................ -- -- (9,265) (12,316) -- --
--------- --------- --------- --------- --------- ---------
Accrued balance sheet liability ..................... $ (25,626) $ (14,779) $ (17,937) $ (18,827) $ (28,455) $ (24,409)
========= ========= ========= ========= ========= =========
MINIMUM PENSION LIABILITY ADJUSTMENT
Additional minimum liability ........................ $ 9,265 $ 12,316
Offsetting intangible asset ......................... 204 987
--------- ---------
$ 9,469 $ 13,303
========= =========
</TABLE>
The actuarial assumptions used in computing the amounts disclosed herein
included discount rates of 7.75%, 6.75% and 7.25% in 1999, 1998 and 1997, an
expected annual rate of return on plan assets of 9% and age-graded annual salary
increases ranging from 3.5% to 5.5%.
-39-
<PAGE> 42
Components of financial statement expense for the Company's retirement
plans and its retiree medical benefits plan for the years ended December 31,
1999, 1998 and 1997 were (in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
QUALIFIED RETIREMENT PLAN
Service cost ......................................... $ 3,269 $ 3,385 $ 3,421
Interest cost ........................................ 11,050 8,813 8,758
Return on plan assets (expected) ..................... (14,889) (13,021) (11,783)
Amortization of prior service cost ................... 80 95 103
Amortization of unrecognized gains ................... (1,350) (2,340) (1,568)
--------- --------- ---------
Net periodic benefit cost (credit) ................... (1,840) (3,068) (1,069)
Additional charges (credits) due to curtailments,
settlements and special termination benefits ....... 12,687(a) -- (4,031)(b)
--------- --------- ---------
Financial statement expense (credit) ................. $ 10,847 $ (3,068) $ (5,100)
========= ========= =========
NONQUALIFIED RETIREMENT PLANS
Service cost ......................................... $ 359 $ 358 $ 361
Interest cost ........................................ 1,322 870 850
Amortization of prior service cost ................... 83 83 91
Amortization of transition obligation ................ 142 142 155
Amortization of unrecognized losses .................. 837 359 414
--------- --------- ---------
Net periodic benefit cost ............................ 2,743 1,812 1,871
Additional charges due to curtailments,
settlements and special termination benefits ....... 827(a) -- 247(b)
--------- --------- ---------
Financial statement expense .......................... $ 3,570 $ 1,812 $ 2,118
========= ========= =========
RETIREE MEDICAL PLAN
Service cost ......................................... $ 622 $ 668 $ 713
Interest cost ........................................ 1,875 1,428 1,842
Amortization of prior service cost credit ............ (791) (931) (500)
Amortization of unrecognized losses .................. 298 225 286
--------- --------- ---------
Net periodic benefit cost ............................ 2,004 1,390 2,341
Additional charges (credits) due to curtail-
ments and special termination benefits ............. 4,106(a) -- (1,930)(b)
--------- --------- ---------
Financial statement expense .......................... $ 6,110 $ 1,390 $ 411
========= ========= =========
</TABLE>
----------
(a) These expenses - which totaled $17,620 - were related to a personnel
reduction program (see Note 9).
(b) These items - which totaled $(5,714) - related to the sale of The Woodlands
Corporation and were included in the calculation of the loss on that sale.
The Company's assumed health care cost trend rate equals 6% for 2000,
declines to 5.5% in 2001 and remains at that level thereafter. The health care
cost trend rate assumption has a significant effect on the amount of the retiree
medical benefit obligation and the periodic financial statement expense. An
increase of 1% in the assumed trend rate would have increased the retiree
medical benefit obligation at December 31, 1999 by $3,887,000 and the service
and interest cost components of the 1999 financial statement expense by a total
of $418,000. A decrease of 1% in the trend rate would have reduced these amounts
by $3,966,000 and $426,000, respectively.
The Company maintains a defined contribution plan in which eligible
employees may participate on a voluntary basis. The Company's contributions -
which match each employee's contributions on a dollar-for-dollar basis up to 6%
of eligible compensation - totaled $2,617,000; $2,953,000 and $3,056,000 in
1999, 1998 and 1997.
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<PAGE> 43
(9) SEGMENT INFORMATION
Industry segment data for the years ended December 31, 1999, 1998 and 1997
follows (in thousands):
<TABLE>
<CAPTION>
Inter- Segment Total Capital
Outside segment Operating Operating Expendi- Segment
Revenues Revenues Earnings Earnings DD&A tures(a) Assets
---------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
1999
EXPLORATION AND PRODUCTION
Operations .............................. $ 254,361 $ -- $ 71,023 $ 60,890 $ 94,667 $ 118,414 $ 717,787
Water well litigation
provision reversals (Note 6) .......... -- -- 14,000 14,000 -- -- --
Personnel reduction program costs ....... -- -- (8,524) (8,524) -- -- --
Gain from sale of Hell's
Hole area properties .................. 11,527 -- 11,527 11,527 -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
265,888 -- 88,026 77,893 94,667 118,414 717,787
---------- ---------- ---------- ---------- ---------- ---------- ----------
GAS SERVICES
Natural gas processing .................. 384,692 83,664 47,266 44,398 4,070 23,871 115,300
Natural gas gathering and marketing ..... 231,275 263,874 28,077 24,821 10,341 21,067 156,141
Other ................................... 12,501 -- 11,720 11,389 107 199 86,323
Personnel reduction program costs ....... -- -- (7,128)(c) (7,128) -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
628,468 347,538 79,935 73,480 14,518 45,137 357,764
---------- ---------- ---------- ---------- ---------- ---------- ----------
CORPORATE ............................... -- -- -- (21,038)(b) 2,456 480 88,128
---------- ---------- ---------- ---------- ---------- ---------- ----------
$ 894,356 $ 347,538 $ 167,961 $ 130,335 $ 111,641 $ 164,031 $1,163,679
========== ========== ========== ========== ========== ========== ==========
1998
EXPLORATION AND PRODUCTION
Operations .............................. $ 227,440 $ -- $ 10,376 $ (1,652) $ 99,942 $ 254,703 $ 713,375
Proved property impairments ............. -- -- (42,250) (42,250) 42,250 -- --
Water well litigation
provision reversals (Note 6) .......... -- -- 4,000 4,000 -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
227,440 -- (27,874) (39,902) 142,192 254,703 713,375
---------- ---------- ---------- ---------- ---------- ---------- ----------
GAS SERVICES
Natural gas processing .................. 262,595 76,212 (925) (4,180) 3,980 21,480 113,139
Natural gas gathering and marketing ..... 215,688 230,464 23,549 19,720 10,719 25,472 172,258
Other ................................... 14,537 -- 13,387 12,992 107 661 67,884
Asset write-downs ....................... -- -- (7,560)(d) (7,560) 7,560 -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
492,820 306,676 28,451 20,972 22,366 47,613 353,281
---------- ---------- ---------- ---------- ---------- ---------- ----------
CORPORATE ............................... -- -- -- (10,903)(b) 2,880 2,918 96,759
---------- ---------- ---------- ---------- ---------- ---------- ----------
$ 720,260 $ 306,676 $ 577 $ (29,833) $ 167,438 $ 305,234 $1,163,415
========== ========== ========== ========== ========== ========== ==========
1997
EXPLORATION AND PRODUCTION
Operations .............................. $ 271,571 $ -- $ 77,657 $ 65,088 $ 91,809 $ 184,708 $ 668,982
Water well litigation provision
(Note 6) .............................. -- -- (7,000) (7,000) -- -- --
Gain from sale of contract drilling
assets ................................ 2,382 -- 2,382 2,382 -- -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
273,953 -- 73,039 60,470 91,809 184,708 668,982
---------- ---------- ---------- ---------- ---------- ---------- ----------
GAS SERVICES
Natural gas processing .................. 331,875 27,867 32,817 29,639 3,717 13,963 132,549
Natural gas gathering and marketing ..... 190,530 261,742 21,097 17,262 6,258 52,275 175,759
Other ................................... 14,386 -- 13,043 12,657 -- 70 57,051
Royalty litigation provision ............ -- -- (26,000) (26,000) 107 -- --
---------- ---------- ---------- ---------- ---------- ---------- ----------
536,791 289,609 40,957 33,558 10,082 66,308 365,359
---------- ---------- ---------- ---------- ---------- ---------- ----------
CORPORATE ............................... -- -- -- (11,655)(b) 2,917 5,379 239,618
---------- ---------- ---------- ---------- ---------- ---------- ----------
$ 810,744 $ 289,609 $ 113,996 $ 82,373 $ 104,808 $ 256,395 $1,273,959
========== ========== ========== ========== ========== ========== ==========
</TABLE>
----------
(a) On accrual basis, including exploratory expenditures and acquisitions.
(b) General corporate expenses; 1999 amount includes personnel reduction program
costs of $8,848.
(c) Natural gas processing $1,753; natural gas gathering and marketing $5,375.
(d) Natural gas processing $6,167; other $1,393.
-41-
<PAGE> 44
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, its partnerships and third parties. The gas
gathering and marketing segment operates Company- and partnership-owned natural
gas gathering systems and markets natural gas through purchase and resale
transactions.
All of the Company's operations are conducted in the United States. Its
revenues are derived principally from uncollateralized sales to customers in the
electrical generation, gas distribution, petrochemical and oil and gas
industries. These industry concentrations have the potential to impact the
Company's exposure to credit risk, either positively or negatively, because
customers may be similarly affected by changes in economic or other conditions.
Intersegment revenues are recorded at prevailing market prices and are
eliminated in consolidation. Gas gathering and marketing sales to a single
customer constituted approximately 13% of consolidated revenues during 1998.
Sales to no single customer constituted as much as 10% of consolidated revenues
in 1999 or 1997. Segment assets excluded net assets of discontinued real estate
operations of $28,856,000 at December 31, 1997.
The reported segment operating earnings amounts represent the operating
earnings of the Company's various industry segments before charges for
administrative, accounting, legal, information systems and other costs that are
managed on a companywide basis. In the reported total operating earnings
disclosures, all general and administrative expenses except for general
corporate expenses incurred in connection with the overall management of the
Company and the operation of the parent company have been allocated to the
industry segments based on their estimated use of these services.
Because of their magnitude and unusual nature, and in accordance with
Accounting Principles Board (APB) Opinion No. 30, the items discussed in the
following paragraphs have been reported as separate components of segment
operating earnings.
1999 items. 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.
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.
-42-
<PAGE> 45
1998 items. Principally because of a prolonged depressed market for energy
products - particularly oil and NGLs - and forecasts that these conditions would
continue, the Company reviewed its proved oil and gas properties for impairment
and determined that impairments totaling $42,250,000 were necessary at December
31, 1998 to reduce the carrying values of four fields to their estimated fair
values (the present values of their estimated future net cash flows).
During 1998's fourth quarter, gas services asset write-downs totaling
$7,560,000 were recorded. These charges principally involved impairments of two
plants that were shut down when their gas throughput was redirected to other
plants to improve the Company's overall profitability. The resultant reduction
of future cash flows for these plants required that their carrying values be
reduced to their estimated fair values - the salvage values of the processing
equipment.
1997 items. Effective April 1, 1997, the Company sold its remaining contract
drilling assets for $3,500,000. A gain of $2,382,000 was recorded on this
transaction.
In July 1997, the Company recorded a $26,000,000 financial statement
provision for estimated costs to be incurred in connection with settlements of
litigation with its North Texas royalty owners. In October 1997, a $21,000,000
payment was made to settle class-action litigation brought on behalf of these
royalty owners. Payments totaling approximately $5,000,000 were subsequently
made to royalty owners who chose not to participate in the class-action
litigation.
(10) COMMON STOCK AND STOCK OPTIONS
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.
The Company's 1995 Stock Option Plan and 1999 Stock Option Plan authorize
the granting of incentive and nonqualified options to purchase common stock at
prices not less than the market value on the date of grant. The options have
maximum terms of 10 years and become exercisable ratably over three-year
periods. Grants covering a total of 2,500,000 and 1,750,000 shares,
respectively, may be made under the plans. At December 31, 1999, grants covering
an additional 219,268 shares could be issued under the 1995 Plan, and the
weighted average remaining contractual life of stock options outstanding under
this plan was 7.2 years. Through December 31, 1999, no options had been granted
under the 1999 Plan. Previously, the Company had granted options under 1979 and
1989 Stock Option Plans, under which no further grants can be made. Summarized
stock option information follows:
-43-
<PAGE> 46
<TABLE>
<CAPTION>
1995 Plan 1979 and 1989 Plans
------------------------------------------- ----------------------------------------
Options Exercisable Options Exercisable
Options Outstanding at Year End Options Outstanding at Year End
--------------------- -------------------- ------------------- -------------------
Average Average Average Average
Number Price Number Price Number Price Number Price
---------- -------- ---------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
At December 31, 1996 ........ 963,867 $ 17.884 151,597 $ 17.625 180,600 $ 19.498 100,600 $ 18,751
February 21, 1997 grants .... 602,490 21.750 --
December 17, 1997 grants .... 347,050 26.125 --
Exercised ................... (140,520) 17.780 (27,930) 17.476
Cancelled ................... (15,383) 19.680 --
---------- --------
At December 31, 1997 ....... 1,757,504 20.836 382,818 18.084 152,670 19.868 92,670 19,499
Exercised ................... (149,016) 19.865 (1,000) 10.250
---------- --------
At December 31, 1998 ........ 1,608,488 20.926 911,607 19.722 151,670 19.931 111,670 19,750
March 5, 1999 grants ........ 405,400 12.312 --
Exercised -- -- (10,000) 17.250
Cancelled ................... (27,525) 19.714 --
---------- --------
At December 31, 1999 ........ 1,986,363 19.185 1,331,294 20.454 141,670 20.120 141,670 20,120
========== ========
</TABLE>
On May 1, 2000, options covering 453,100 shares at a price of $23.9375
were issued to employees under the Company's 1995 and 1999 Stock Option Plans.
Stock options are accounted for under the provisions of APB Opinion No.
25. As a result, the Company generally does not recognize compensation expense
in its financial statements for outstanding stock options. Had grants under the
1995 Plan been accounted for on the estimated fair-value basis promulgated by
SFAS No. 123, the Company would have recorded additional compensation expense of
$2,159,000; $3,626,000 and $3,977,000 in 1999, 1998 and 1997. On a proforma
basis, earnings from continuing operations would have been reduced by
$1,404,000; $2,357,000 and $2,585,000 in 1999, 1998 and 1997, and basic earnings
per share from continuing operations would have been lowered by 3 cents, 5 cents
and 5 cents, respectively. The additional compensation expense under the
estimated fair-value basis was computed using the Black-Scholes option-pricing
model, expected lives of seven years, annual cash dividends of $.53 per share
(the regular rate paid for the last several years) and the following interest
and volatility rates, which were determined at the dates of the individual
grants:
<TABLE>
<CAPTION>
2/21/97 12/17/97 3/05/99
------- -------- -------
<S> <C> <C> <C>
Risk-free interest rate (%)............................ 6.27 5.82 5.34
Stock price volatility rate (%)........................ 28.6 28.0 29.7
Computed value per option share........................ $7.55 $9.15 $3.17
</TABLE>
(11) INCENTIVE COMPENSATION PLANS
As long-term incentives, the Company periodically has issued awards that it
calls "bonus units" under which employees can earn compensation based on
increases in the market price of the Company's stock. Upon the redemption of
such awards, grantees receive gross compensation in amounts equal to the excess
of the market price of the Company's common stock over a floor price (the market
price of the stock when the units were awarded). The Company's 1991 Bonus Unit
Plan authorized the issuance of up to 700,000 units, all of which had been
granted and exercised by December 31, 1997. Up to 1,500,000 units may be granted
under the 1997 Bonus Unit Plan. A total of 227,950 ten-year bonus units - which
vest in three equal annual installments - were issued in December 1997 at a
floor
-44-
<PAGE> 47
price of $26.125. In March 1999, a total of 249,600 similar bonus units were
issued at a floor price of $12.3125. At December 31, 1999, all such units were
still outstanding. On May 1, 2000, 342,800 bonus units with a floor price of
$23.975 were issued to employees.
Compensation expense is recognized over the applicable vesting terms of
the bonus units in amounts equal to the appreciation in the market price of the
stock over the applicable floor prices. Reversals are recognized to the extent
of previously recorded appreciation in periods when the market price of the
stock declines. Expense accruals (reversals) for bonus units aggregated
$1,293,000; $(8,000) and $1,132,000 in 1999, 1998 and 1997.
In December 1997, the Board of Directors approved the Company's 1997
Performance Unit Plan to help the Company retain key personnel in a very
competitive employment market, and a total of 296,543 performance units were
awarded to mid-level managerial and professional employees. Some units were paid
off in connection with 1999's personnel reduction program, and individuals
holding the remaining 235,584 units on March 31, 1999 received cash compensation
equal to the closing price of the Company's Class B stock on that day times the
number of units awarded them. Compensation expense, which was accrued ratably
over the life of the outstanding units, totaled $864,000; $2,434,000 and
$279,000 in 1999, 1998 and 1997.
(12) EARNINGS (LOSS) 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 sets forth
basic and diluted earnings (loss) per share information for the years ended
December 31, 1999, 1998 and 1997:
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
From continuing operations ............. $ 1.37 $ (.67) $ .87
-------- -------- --------
Discontinued real estate operations
Earnings from operations ............ -- -- .17
Loss on sale ........................ -- .07 (1.32)
-------- -------- --------
-- .07 (1.15)
-------- -------- --------
Extraordinary item ..................... -- -- (.26)
-------- -------- --------
Net earnings (loss) .................... $ 1.37 $ (.60) $ (.54)
======== ======== ========
</TABLE>
There were no differences in the reported basic and diluted earnings per share
because the earnings (loss) amounts were the same in the basic and diluted
computations, and the dilutive effect of stock options did not significantly
increase the number of weighted average shares outstanding. The following table
reconciles the weighted average shares outstanding used in the basic and diluted
computations for the years ended December 31, 1999, 1998 and 1997 (in
thousands):
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Used in basic computations .......... 49,117 49,100 50,925
Dilutive effect of stock options .... 106 -- 248
-------- -------- --------
Used in diluted computations ........ 49,223 49,100 51,173
======== ======== ========
</TABLE>
Excluded from these computations because their effect would have been
antidilutive were stock options covering 1,388,233 shares in 1999; 1,760,158
shares in 1998 and 347,050 shares in 1997.
-45-
<PAGE> 48
(13) DISCONTINUED REAL ESTATE OPERATIONS
The Company decided to withdraw from the real estate business during 1997 and
commenced reporting real estate activities as discontinued operations at that
time. On June 12, 1997, the Company entered into an agreement to sell its real
estate subsidiary, The Woodlands Corporation (TWC), to a partnership of Crescent
Real Estate Equities Company and Morgan Stanley Real Estate Fund II, L.P. for
$543,000,000 in cash. The transaction was subsequently closed on July 31, 1997.
In connection with the sale, the parent company forgave intercompany debt
payable to it by TWC. After adjustment for certain net additional amounts
received pursuant to the contract and deductions for income taxes and
transaction costs incurred by the Company in connection with the sale, net cash
sales proceeds totaled $480,994,000.
The Company's financial statements were revised to segregate the net
assets associated with the discontinued operations and to separately report
their results of operations. Interest expense attributable to discontinued
operations was determined in the same manner that historically had been used to
allocate such costs to the Company's real estate operations. After an income tax
benefit of $25,878,000, a net loss of $67,123,000 was recorded in connection
with the discontinuance of the Company's real estate activities.
During the first quarter of 1998, 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 real estate operations. The
reduction occurred because actual realizations were higher than originally
estimated and certain contingent obligations were settled for less than the
amounts accrued. The Company ceased segregating discontinued operations in 1998
since the liquidation of the remaining real estate properties had been
substantially completed.
(14) EXTRAORDINARY ITEM
During 1997, the Company repurchased $185,733,000 face amount of its 9 1/4%
senior notes due January 15, 2002. In connection with the repurchase, costs of
$20,385,000 were expensed, including cash costs of $19,294,000 associated with a
tender offer for these notes and the write-off of $1,091,000 in deferred
financing costs. After an income tax benefit of $7,135,000, an extraordinary
charge of $13,250,000 was recorded in connection with this extinguishment of
debt.
-46-
<PAGE> 49
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Mitchell Energy & Development Corp.:
We have audited the accompanying consolidated balance sheets of Mitchell
Energy & Development Corp. (a Texas corporation) and subsidiaries as of December
31, 1999 and 1998, and the related consolidated statements of earnings,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1999. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Mitchell Energy &
Development Corp. and subsidiaries as of December 31, 1999 and 1998, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
October 10, 2000
-47-
<PAGE> 50
UNAUDITED QUARTERLY FINANCIAL DATA
(in thousands except per-share data)
<TABLE>
<CAPTION>
First Second Third Fourth
Quarter Quarter Quarter Quarter
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
1999
Revenues ....................................... $ 162,614 $ 207,614 $ 265,473 $ 258,655
Segment operating earnings ..................... 5,408(a) 40,750(b) 54,422 67,381(a)
Net earnings (loss) ............................ (11,515) 18,383 25,896 34,570
Basic and diluted earnings (loss) per share .... (.23) .37 .53 .70
1998
Revenues ....................................... $ 193,459 $ 174,237 $ 180,792 $ 171,772
Segment operating earnings (loss) .............. 17,253 7,788(c) 11,260(c) (35,724)(d)
Earnings (loss) from continuing operations ..... 5,556 (4,437) (2,797) (31,176)
Discontinued real estate operations ............ -- 3,250 -- --
Net earnings (loss) ............................ 5,556 (1,187) (2,797) (31,176)
Basic and diluted earnings (loss) per share
From continuing operations .................. $ .11 $ (.09) $ (.06) $ (.63)
Net earnings ................................ .11 (.02) (.06) (.63)
</TABLE>
----------
(a) After personnel reduction program charges of $15,652 in the first quarter;
includes water well litigation provision reversals of $9,000 in the first
quarter and $5,000 in the fourth.
(b) Includes gain of $11,527 from sale of Hell's Hole area properties.
(c) Includes water well litigation provision reversals of $3,000 in the second
quarter and $1,000 in the third.
(d) After charges for exploration and production proved property impairments of
$42,250 and gas services asset write-downs of $7,560.
-48-
<PAGE> 51
QUARTERLY STOCK DATA
(per-share amounts)
<TABLE>
<CAPTION>
Market Price Range
------------------------------------------
Class A Class B Cash Dividends
------------------ -------------------- --------------------
High Low High Low Class A Class B
------ ------- -------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
1999
First ................................. $14.38 $ 10.56 $ 14.88 $ 11.00 $.12 $ .1325
Second ................................ 19.31 13.19 18.50 13.69 .12 .1325
Third ................................. 24.44 17.69 23.50 17.31 .12 .1325
Fourth ................................ 24.69 21.94 24.50 21.19 .12 .1325
1998
First ................................. $28.44 $ 25.21 $ 28.50 $ 25.02 $.12 $ .1325
Second ................................ 26.23 20.00 26.10 19.25 .12 .1325
Third ................................. 21.00 12.25 20.50 13.13 .12 .1325
Fourth ................................ 14.94 9.81 14.88 10.13 .12 .1325
</TABLE>
-49-
<PAGE> 52
Mitchell Energy & Development Corp. and Subsidiaries
UNAUDITED SUPPLEMENTAL OIL AND GAS INFORMATION
Reserve quantities. Proved reserves are the estimated quantities which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under economic and operating
conditions at each year end. Proved developed reserves are expected to be
recovered from existing wells using existing equipment and operating methods.
Consolidated reserves represent the Company's net interest in oil and gas
properties or in reserves committed to Company-owned gas processing plants.
Equity partnership reserves represent the Company's proportional interest in the
reserves of partnerships that are accounted for using the equity method.
The following tables summarize changes in the Company's natural gas
(gas), crude oil and condensate (oil) and plant NGL reserve quantities during
the indicated years and the proved developed reserve quantities at the dates
indicated:
<TABLE>
<CAPTION>
1999 1998 1997
----------------------------- --------------------------- ---------------------------
Gas Oil Gas Oil Gas Oil
MBOE* (Bcf) (MMBbls) MBOE* (Bcf) (MMBbls) MBOE* (Bcf) (MMBbls)
------- --------- -------- ------- ------ -------- ------- ------ --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PROVED GAS AND OIL RESERVES
Beginning balance ................... 162.3 875.2 16.4 146.9 786.1 15.9 131.7 709.0 13.5
Extensions and discoveries .......... 49.5 289.8 1.2 21.5 121.3 1.3 32.9 177.5 3.3
Production marketed ................. (17.0) (89.3) (2.1) (17.6) (90.3) (2.5) (16.6) (86.2) (2.2)
Production consumed in operations ... (.8) (4.5) -- (.6) (3.6) -- (.6) (3.6) --
Purchases in place .................. -- .1 -- 15.2 73.8 2.9 .9 1.8 .6
Revisions of previous estimates ..... (8.0) (39.9) (1.3) (2.7) (11.2) (.9) (2.6) (12.3) (.5)
Sales in place ...................... (1.6) (8.6) (.2) (.4) (1.0) (.3) (.4) (1.5) (.2)
Improved recovery ................... -- -- -- -- .1 -- 1.6 1.4 1.4
------- --------- -------- ------- ------ -------- ------- ------ --------
Ending balance ...................... 184.4 1,022.8 14.0 162.3 875.2 16.4 146.9 786.1 15.9
======= ========= ======== ======= ====== ======== ======= ====== ========
</TABLE>
----------
* Million barrels of oil equivalent using a 6-to-1 conversion factor for gas.
<TABLE>
<CAPTION>
1999 1998 1997
--------------------------- --------------------------- -----------------------------
Equity Equity Equity
Consol- Partner- Consol- Partner- Consol- Partner-
Total idated ships Total idated ships Total idated ships
------- -------- -------- ------- -------- -------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PROVED PLANT NGL RESERVES (MMBBLS)
Beginning balance .................. 115.8 75.9 39.9 130.8 84.5 46.3 113.5 73.6 39.9
Additions .......................... 28.2 27.1 1.1 13.2 13.2 -- 18.5 18.5 --
Production ......................... (16.1) (12.2) (3.9) (15.3) (10.6) (4.7) (16.6) (11.4) (5.2)
Purchases of plant interests ....... 15.2 15.2 -- 4.1 -- 4.1 2.7 2.7 --
Transfer of partnership reserves ... -- 15.2 (15.2) -- -- -- -- -- --
Revisions of previous estimates .... 36.0 27.6 8.4 (17.0) (11.2) (5.8) 12.7 1.1 11.6
------- -------- -------- ------- -------- -------- ------- ------- --------
Ending balance ..................... 179.1 148.8 30.3 115.8 75.9 39.9 130.8 84.5 46.3
======= ======== ======== ======= ======== ======== ======= ======= ========
</TABLE>
<TABLE>
<CAPTION>
PROVED DEVELOPED RESERVES AT DECEMBER 31 1999 1998 1997 1996
------ ------ ------ ------
<S> <C> <C> <C> <C>
Gas (Bcf) ........................................... 667.1 692.3 648.6 618.8
====== ====== ====== ======
Oil (MMBbls) ........................................ 13.5 15.2 14.7 12.7
====== ====== ====== ======
Plant NGLs (MMBbls)
Consolidated ..................................... 119.3 58.7 72.6 66.9
Equity partnerships .............................. 24.4 33.3 45.1 38.9
====== ====== ====== ======
143.7 92.0 117.7 105.8
====== ====== ====== ======
</TABLE>
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<PAGE> 53
Future net cash flows from natural gas and oil reserves. The following tables
set forth estimates of the standardized measure of discounted future net cash
flows from proved gas and oil reserves at December 31, 1999, 1998 and 1997 and a
summary of the changes in those amounts for the years then ended (in millions):
<TABLE>
<CAPTION>
1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
STANDARDIZED MEASURE
Future cash inflows ................................. $ 2,792 $ 1,769 $ 2,216
Future production and development costs ............. (1,455) (1,040) (939)
Future income taxes ................................. (374) (147) (380)
Discount - 10% annually ............................. (385) (190) (362)
------- ------- -------
$ 578 $ 392 $ 535
======= ======= =======
CHANGES IN STANDARDIZED MEASURE
Extensions and discoveries, net of related costs .... $ 188 $ 50 $ 120
Sales, net of production costs ...................... (184) (151) (200)
Net changes in prices and production costs .......... 340 (352) (568)
Accretion of discount ............................... 42 63 129
Production rate changes and other ................... (28) 19 (1)
Development costs incurred .......................... 26 25 13
Purchases in place .................................. -- 71 5
Sales in place ...................................... (13) (2) (2)
Revisions of previous quantity estimates ............ (63) (9) (13)
Net changes in future income taxes .................. (122) 143 154
------- ------- -------
$ 186 $ (143) $ (363)
======= ======= =======
</TABLE>
Future net cash flows from plant NGL reserves. The following tables set forth
estimates of the standardized measure of discounted future net cash flows from
proved NGL reserves at December 31, 1999, 1998 and 1997 and a summary of the
changes in those amounts for the years then ended (in millions):
<TABLE>
<CAPTION>
1999 1998 1997
--------------------------- --------------------------- -----------------------------
Equity Equity Equity
Consol- Partner- Consol- Partner- Consol- Partner-
Total idated ships Total idated ships Total idated ships
------- -------- -------- ------- -------- -------- ------- ------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
STANDARDIZED MEASURE
Future cash inflows ................ $ 2,976 $ 2,508 $ 468 $ 1,054 $ 682 $ 372 $ 1,671 $ 1,090 $ 581
Future production costs ............ (2,281) (1,978) (303) (861) (568) (293) (1,318) (848) (470)
Future income taxes ................ (228) (168) (60) (56) (33) (23) (116) (78) (38)
Discount - 10% annually ............ (202) (153) (49) (58) (35) (23) (98) (68) (30)
------- ------- ------- ------- ------- ------- ------- ------- --------
$ 265 $ 209 $ 56 $ 79 $ 46 $ 33 $ 139 $ 96 $ 43
======= ======= ======= ======= ======= ======= ======= ======= ========
CHANGES IN STANDARDIZED MEASURE
Additions, net of related costs .... $ 57 $ 54 $ 3 $ 11 $ 11 $ -- $ 30 $ 30 $ --
Sales, net of production costs ..... 139 83 56 (95) (83) (12) (234) (164) (70)
Net changes in prices and costs .... (45) (30) (15) (11) (4) (7) (38) (24) (14)
Accretion of discount .............. 10 6 4 20 14 6 40 28 12
Purchases of plant interests ....... 30 30 -- 5 -- 5 1 1 --
Transfer of partnership reserves ... -- 30 (30) -- -- -- -- -- --
Revisions of previous quantity
estimates ......................... 80 55 25 (16) (9) (7) 18 2 16
Other .............................. 9 5 4 (11) (5) (6) (15) (12) (3)
Net changes in future income taxes . (94) (70) (24) 37 26 11 67 43 24
------- ------- ------- ------- ------- ------- ------- ------- --------
$ 186 $ 163 $ 23 $ (60) $ (50) $ (10) $ (131) $ (96) $ (35)
======= ======= ======= ======= ======= ======= ======= ======= ========
</TABLE>
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<PAGE> 54
The natural gas reserve quantities reported as gas and oil reserves represent
wet gas volumes, including quantities that will be converted to NGLs by
processing. As it relates to NGLs to be extracted in processing, the gas and oil
future net cash flows include only the leasehold reimbursements for such NGLs;
the other cash flows (amounts in excess of the leasehold reimbursements)
associated with NGLs to be extracted from the Company's wet gas reserves are
included in plant NGL amounts since those cash flows are attributable to the
Company's gas processing plants.
The quantities reported herein for plant NGLs include all liquids that
will be extracted from gas streams contractually committed to Company-owned gas
processing plants since the Company, as plant owner, generally has beneficial
ownership of all the NGLs so produced. Accordingly, the plant NGL reserves and
future net cash flows include amounts attributable to NGLs extracted from gas
streams owned by the Company and by third parties. The Company reimburses the
owners of the natural gas streams for associated NGLs in accordance with the
applicable contract provisions. Such reimbursements - including amounts
attributable to the Company's oil and gas leasehold interests that are included
in oil and gas future net cash flows - are deducted as production costs in
determining future net cash flows from plant NGLs.
Of the total remaining natural gas reserves at December 31, 1999, an
estimated 592.1 Bcf will be processed at Company plants, including 161.1 Bcf of
1999's natural gas reserve additions from extensions and discoveries. It is
estimated that 93.9 Bcf of such reserves and 21.7 Bcf of such reserve additions
will be converted by processing into 51.1 MMBbls and 11.8 MMBbls of plant NGLs,
respectively.
Except where otherwise specified by contractual agreement, future cash
inflows are estimated using year-end prices. Future production and development
cost estimates are based on economic conditions at the respective year ends.
Future income taxes are computed by applying applicable statutory tax rates to
the difference between the estimated future net revenues and the tax basis of
proved oil and gas properties after considering tax credit carryforwards,
estimated future percentage depletion deductions and energy tax credits.
Reserve estimates are subject to numerous uncertainties inherent in
estimating quantities of proved reserves and in the projection of future rates
of production and the timing of development expenditures. The accuracy of such
estimates is a function of the quality of available data and of engineering and
geological interpretation and judgment. Results of subsequent drilling, testing
and production may cause either upward or downward revisions of previous
estimates. Further, the volumes considered to be commercially recoverable
fluctuate with changes in prices and operating costs. Because of the
aforementioned factors, reserve estimates are generally less precise than other
financial statement disclosures.
Discounted future cash flow estimates such as those shown herein are not
intended to represent estimates of the fair market value of oil and gas
properties. Estimates of fair market value also should consider probable
reserves, anticipated future oil and gas prices and interest rates, changes in
development and production costs and risks associated with future production.
Because of these and other considerations, any estimate of fair market value is
necessarily subjective and imprecise.
-52-
<PAGE> 55
Gas and oil related costs and operating results. The following tables set forth
capitalized costs at December 31, 1999, 1998 and 1997 and costs incurred and
operating results for oil and gas producing activities for the years then ended
(in thousands):
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
CAPITALIZED COSTS
Oil and gas properties .................................................. $ 1,881,846 $ 1,867,809 $ 1,675,134
Support equipment and facilities ........................................ 50,138 50,670 56,988
Accumulated depreciation, depletion and amortization .................... (1,231,047) (1,217,675) (1,109,922)
----------- ----------- -----------
Net capitalized costs ................................................... $ 700,937 $ 700,804 $ 622,200
=========== =========== ===========
COSTS INCURRED (including exploration expenses and
exploratory well impairments of $9,022, $30,488 and $19,258)
Property acquisitions
Unproved ............................................................. $ 6,450 $ 12,965 $ 15,903
Proved ............................................................... -- 71,708 5,052
Exploration ............................................................. 9,646 35,663 30,610
Development ............................................................. 101,589 131,395 130,977
----------- ----------- -----------
Costs incurred .......................................................... 117,685 251,731 182,542
Support equipment and facilities ........................................ 729 2,972 2,166
----------- ----------- -----------
Capital and exploratory expenditures .................................... $ 118,414 $ 254,703 $ 184,708
=========== =========== ===========
OPERATING RESULTS (before charges for
general and administrative and interest expense)
Production revenues ..................................................... $ 252,899 $ 225,835 $ 268,678
Other revenues .......................................................... 1,462 1,605 2,893
----------- ----------- -----------
254,361 227,440 271,571
Less - Production costs
Operating expenses ............................................ 52,044 58,364 52,864
Production taxes .............................................. 16,371 16,568 15,928
Depreciation, depletion and amortization (including
proved-property impairments of none, $42,250 and $1,640) .... 94,667 142,192 91,809
Exploration expenses ............................................. 6,062 25,400 14,049
Exploratory well impairments ..................................... 2,960 5,088 5,209
Other operating costs ............................................ 11,234 11,702 14,055
----------- ----------- -----------
Segment operating earnings .............................................. 71,023 (31,874) 77,657
Income taxes ............................................................ 23,009 (12,197) 27,059
----------- ----------- -----------
$ 48,014 $ (19,677) $ 50,598
=========== =========== ===========
</TABLE>
-53-
<PAGE> 56
Mitchell Energy & Development Corp. and Subsidiaries
HISTORICAL SUMMARY
(in thousands except where otherwise indicated)
<TABLE>
<CAPTION>
Calendar Calendar Calendar Transition Fiscal
1999 1998 1997 Period (a) 1996(b)
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
FINANCIAL POSITION AT YEAR END
Net property, plant and equipment ................. $ 1,050,298 $ 1,035,696 $ 887,026 $ 764,405 $ 719,535
Total assets ...................................... 1,163,679 1,163,415 1,273,959 1,691,271 1,599,183
Capital employed
Long-term debt ................................. $ 379,267 $ 372,767(c) $ 414,267 $ 600,000(c) $ 795,000
Deferred income taxes .......................... 158,307 137,961 163,836 104,478 66,696
Retirement obligations and other ............... 87,351 66,979 59,346 57,272 72,832
Stockholders' equity ........................... 385,174 341,282 412,005 543,812 481,903
----------- ----------- ----------- ----------- -----------
$ 1,010,099 $ 918,989 $ 1,049,454 $ 1,305,562 $ 1,416,431
=========== =========== =========== =========== ===========
CAPITAL AND EXPLORATORY
EXPENDITURES (accrual basis)
Exploration and production
Capital ........................................ $ 109,392 $ 224,215 $ 165,450 $ 101,033 $ 126,915
Exploratory expenses/impairments ............... 9,022 30,488 19,258 15,389 14,752
Gas services ...................................... 45,137 47,613 66,308 27,653 38,358
Corporate ......................................... 480 2,918 5,379 6,572 6,068
----------- ----------- ----------- ----------- -----------
$ 164,031 $ 305,234 $ 256,395 $ 150,647 $ 186,093
=========== =========== =========== =========== ===========
OPERATING STATISTICS
Average daily volumes
Natural gas sales (Mcf) ........................ 244,700 247,500 236,100 228,700 216,200
Crude oil and condensate sales (Bbls) .......... 5,900 6,800 6,100 5,400 5,400
Natural gas liquids produced (Bbls) ............ 44,000 41,800 45,500 46,000 44,500
Pipeline throughput (Mcf) ...................... 555,000 554,000 411,000 414,000 354,000
Average annual sales price (dollars)
Natural gas (per Mcf) .......................... $ 2.42 $ 2.15 $ 2.62 $ 2.50 $ 2.16
Crude oil and condensate (per Bbl) ............. 17.17 12.60 19.27 21.26 16.91
Natural gas liquids produced (per Bbl) ......... 14.20 10.48 13.96 15.88 11.55
Drilling program (gross wells)
Wells drilled .................................. 121 195 256 183 116
Wells completed ................................ 107 167 242 160 107
Well count at period end (gross wells) ............ 3,352 3,298 3,257 3,090 3,047
STOCKHOLDERS' EQUITY (per share at period end) .... $ 7.84 $ 6.94 $ 8.38 $ 10.49 $ 9.26
CASH DIVIDENDS PER SHARE
Class A (includes special
dividend of 24 cents in 1998) .................. $ .48 $ .48 $ .72 $ .48 $ .48
Class B (includes special
dividend of 26.5 cents in 1998) ................ .53 .53 .795 .53 .53
AVERAGE COMMON SHARES OUTSTANDING(d). ............. 49,117 49,100 50,925 51,882 52,044
</TABLE>
----------
(a) At December 31, 1996 and for the eleven-month period then ended.
(b) At January 31, 1996 and for the twelve-month period then ended.
(c) Excludes current maturities of $100,000 in 1998 and $130,000 in the
Transition Period.
(d) Basic shares on a single-class basis to give effect to June 2000 stock
reclassification.
-54-
<PAGE> 57
Mitchell Energy & Development Corp. and Subsidiaries
HISTORICAL SUMMARY
(in thousands except per-share data)
<TABLE>
<CAPTION>
Calendar Calendar Calendar Transition Fiscal
1999 1998 1997 Period (a) 1996(b)
--------- --------- --------- ---------- ---------
<S> <C> <C> <C> <C> <C>
REVENUES
Exploration and Production .......................... $ 265,888 $ 227,440 $ 273,953 $ 236,177 $ 424,661(c)
Gas Services
Natural gas processing ........................... 384,692 262,595 331,875 337,763 283,378
Natural gas gathering and marketing .............. 231,275 215,688 190,530 220,341 184,584
Other ............................................ 12,501 14,537 14,386 11,946 10,296
--------- --------- --------- --------- ---------
Total revenues ................................. $ 894,356 $ 720,260 $ 810,744 $ 806,227 $ 902,919
========= ========= ========= ========= =========
SEGMENT OPERATING EARNINGS
Exploration and Production
Operations ....................................... $ 71,023 $ 10,376 $ 77,657 $ 65,186 $ 35,775
Litigation (provisions) reversals ................ 14,000 4,000 (7,000) (10,000) (15,000)
Gains from asset sales ........................... 11,527 -- 2,382 -- 5,338
Proved property impairments ...................... -- (42,250) -- -- --
Gain from natural gas contract buyout ............ -- -- -- -- 205,256
Personnel reduction program costs ................ (8,524) -- -- -- (7,935)
Severance tax refunds ............................ -- -- -- 5,935 --
Columbia Gas contract settlement proceeds ........ -- -- -- 3,444 --
Gas Services
Natural gas processing ........................... 47,266 (925) 32,817 64,143 30,994
Natural gas gathering and marketing .............. 28,077 23,549 21,097 25,474 14,063
Other ............................................ 11,720 13,387 13,043 10,837 9,059
--------- --------- --------- --------- ---------
Operations subtotal ............................ 87,063 36,011 66,957 100,454 54,116
Asset write-downs ................................ -- (7,560) -- -- (52,715)
Personnel reduction program costs ................ (7,128) -- -- -- (3,600)
Litigation provision ............................. -- -- (26,000) -- --
--------- --------- --------- --------- ---------
Total segment operating earnings ............... 167,961 577 113,996 165,019 221,235
General and administrative expense (including
personnel reduction program costs of $8,848
in 1999 and $4,532 in fiscal 1996) ............... 37,626 30,410 31,623 28,198 35,760
Interest expense attributable
to continuing operations ......................... 34,499 34,572 26,733 20,801 27,341
Other (income) expense, net ......................... (6,162) (6,281) (10,261) (2,111) 2,002
--------- --------- --------- --------- ---------
EARNINGS (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES ................... 101,998 (58,124) 65,901 118,131 156,132
Income taxes ........................................ 34,664 (25,270) 21,610 41,912 55,420
--------- --------- --------- --------- ---------
EARNINGS (LOSS) FROM CONTINUING OPERATIONS .......... 67,334 (32,854) 44,291 76,219 100,712
AFTER-TAX EARNINGS (LOSS) FROM DISCONTINUED
OPERATIONS (includes $67,123 loss on disposal
in 1997) ......................................... -- 3,250 (58,515) 15,757 (63,583)
--------- --------- --------- --------- ---------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM ........... 67,334 (29,604) (14,224) 91,976 37,129
Extraordinary item (extinguishment of debt) ......... -- -- (13,250) -- --
--------- --------- --------- --------- ---------
NET EARNINGS (LOSS) ................................. $ 67,334 $ (29,604) $ (27,474) $ 91,976 $ 37,129
========= ========= ========= ========= =========
EARNINGS (LOSS) PER SHARE (d)
From continuing operations .......................... $ 1.37 $ (.67) $ .87 $ 1.47 $ 1.91
Net earnings ........................................ 1.37 (.60) (.54) 1.77 .69
</TABLE>
----------
(a) For the eleven-month period ended December 31, 1996.
(b) For the twelve-month period ended January 31, 1996.
(c) Includes gain of $205,256 from natural gas contract buyout.
(d) Basic shares on a single-class basis to give effect to June 2000 stock
reclassification.
-55-
<PAGE> 58
BOARD OF DIRECTORS
================================================================================
GEORGE P. MITCHELL
Chairman and Chief Executive Officer,
Mitchell Energy & Development Corp.
BERNARD F. CLARK
Vice Chairman,
Mitchell Energy & Development Corp.
W. D. STEVENS (3)
President and Chief Operating Officer,
President-Exploration and Production,
Mitchell Energy & Development Corp.
ROBERT W. BALDWIN (1) (2)
Consultant (energy/management);
retired President, Gulf Refining
and Marketing Company
(a division of Gulf Oil Corp.), Houston
WILLIAM D. EBERLE (1) (3)
Chairman,
Manchester Associates, Ltd.
(international business consulting),
Boston; Of Counsel on trade issues to
Kaye, Scholer, Fierman, Hays and
Handler (attorneys), Washington, D.C.
SHAKER A. KHAYATT (2)
President and Chief Executive Officer,
Khayatt and Company, Inc.
(investment banking), New York City
BEN F. LOVE (2) (3)
Advisory Director,
Chase Bank of Texas, N.A., and retired
Chairman and Chief Executive Officer,
Texas Commerce Bancshares
(now Chase Bank of Texas), Houston
J. TODD MITCHELL (3)
President,
GPM, Inc. (private investments),
The Discovery Bay Company
(seismic software) and
Dolomite Resources, Inc.
(exploration and investments), Houston
M. KENT MITCHELL (1) (3)
President and Chief Executive Officer,
Bald Head Island Management, Inc.
(real estate development),
Bald Head Island, North Carolina
----------
(1) Compensation Committee
(2) Audit Committee
(3) Executive Committee
-56-
<PAGE> 59
PRINCIPAL OFFICERS
================================================================================
GEORGE P. MITCHELL
Chairman and Chief Executive Officer
W. D. STEVENS
President and Chief Operating Officer,
President-Exploration and Production Division
BERNARD F. CLARK
Vice Chairman
PHILIP S. SMITH
Corporate Senior Vice President,
Chief Financial Officer and
President-Administration and
Financial Division
ALLEN J. TARBUTTON, JR.
Corporate Senior Vice President,
President-Gas Services Division
THOMAS P. BATTLE
Corporate Senior Vice President,
General Counsel and Secretary
-57-
<PAGE> 60
CORPORATE INFORMATION
================================================================================
STOCK LISTINGS
New York Stock Exchange
Pacific Exchange
Ticker Symbol: MND
Options Trading: Pacific Exchange
TRANSFER AGENT AND REGISTRAR
ChaseMellon Shareholder Services, L.L.C.
85 Challenger Road
Overpeck Centre
Ridgefield, NJ 07660-2104
Toll-free: (800) 635-9270
www.chasemellon.com
ANNUAL MEETING
10 a.m. CDT
Wednesday, June 28, 2000
Mitchell Learning Center Auditorium
2002 Timberloch Place, 3rd Floor
The Woodlands, TX 77380-1148
FORM 10-K
Copies of the Company's
Form 10-K are available upon request to:
Public Affairs Department
Mitchell Energy & Development Corp.
P. O. Box 4000
The Woodlands, TX 77387-4000
Phone: (713) 377-5650
WORLDWIDE WEB
www.mitchellenergy.com
-58-
