1
1998 ANNUAL REPORT
BURLINGTON RESOURCES
[Photo Montage]
"We are a global super independent determined to build long-term shareholder
value through value-added growth and effective cost management."
2
CONTENTS
Operational Highlights ............. 1
Shareholder Letter ................. 2
Review of Operations ............... 5
Financial Review ................... 20
BURLINGTON RESOURCES
[Photo of Oil Field Equipment]
Burlington Resources is engaged in the exploration, development, production and
marketing of oil and gas. The Company conducts activities in several strategic
areas, domestically and internationally, and ranks first among U.S. independent
oil and gas companies in terms of proved U.S. reserves. BR combines the
diverse global opportunities, critical mass and financial strength of a major
oil company with the entrepreneurial spirit, flexibility and responsiveness of
an independent operator. Our history dates to the 1800's and represents a
heritage of growth and success.
TERMS USED IN THIS REPORT
Bbls Barrels
BCF Billion Cubic Feet
BCFE Billion Cubic Feet of Gas Equivalent
MBbls Thousands of Barrels
MMBbls Millions of Barrels
MCF Thousand Cubic Feet
MMCF Million Cubic Feet
MCFE Thousand Cubic Feet of Gas Equivalent
MMCFE Million Cubic Feet of Gas Equivalent
MMBTU Million British Thermal Units
TCF Trillion Cubic Feet
TCFE Trillion Cubic Feet of Gas Equivalent
2-D Two Dimensional
3-D Three Dimensional
NGLs Natural Gas Liquids
DD&A Depreciation, Depletion and Amortization
BR Burlington Resources Inc.
LL&E The Louisiana Land and Exploration Company
Shelf Shallow Waters of the Outer Continental Shelf
in the Gulf of Mexico
Deep water Water Depths of 600 Feet or Greater
in the Gulf of Mexico
Proved reserves represent estimated quantities of oil and gas which geological
and engineering data demonstrate, with reasonable certainty, can be recovered in
future years from known reservoirs under existing economic and operating
conditions. Reservoirs are considered proved if shown to be economically
producible by either actual production or conclusive formation tests.
Proved developed reserves are the portion of proved reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.
Proved undeveloped reserves are the portion of proved reserves which can be
expected to be recovered from new wells on undrilled proved acreage, or from
existing wells where a relatively major expenditure is required for completion.
Net acreage and net oil and gas wells are obtained by multiplying gross acreage
and gross oil and gas wells by the Company's working interest percentage in the
properties.
Oil is converted into cubic feet of gas equivalent based on 6 MCF of gas to one
barrel of oil.
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TABLES AND GRAPHS
NATURAL GAS RESERVES
December 31,
(TCF)
[Bar Graph]
6.2
6.4
6.4
NATURAL GAS PRODUCTION
Year Ended December 31,
(MMCF per day)
[Bar Graph]
1996 1,603
1997 1,669
1998 1,647
NATURAL GAS PRICES
Year Ended December 31,
($ per MCF)
[Bar Graph]
1996 $2.05
1997 $2.18
1998 $1.97
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OIL RESERVES
December 31,
(MMBbls)
[Bar Graph]
1996 305.8
1997 253.7
1998 273.2
OIL PRODUCTION
Year Ended December 31,
(MBbls per day)
[Bar Graph]
1996 91.1
1997 87.2
1998 82.7
OIL PRICES
Year Ended December 31,
($ per Bbl)
[Bar Graph]
1996 $20.39
1997 $19.24
1998 $13.28
CAPITAL EXPENDITURES*
Year Ended December 31,
($ Millions)
[Bar Graph]
1996 $804
1997 $1,245
1998 $1,165
RESERVE REPLACEMENT*
Year Ended December 31,
(Percent of Production)
[Bar Graph]
1996 115%
1997 188%
1998 123%
3 yr. avg. 142%
RESERVE REPLACEMENT COSTS*
Year Ended December 31,
($ per MCFE)
[Bar Graph]
1996 $.82
1997 $.77
1998 $1.10
3 yr. avg. $.88
*Includes Acquisitions
5
[Map Graphic]
Permian
San Juan
Anadarko
Wind River
Williston
Deep Water
Onshore Gulf Coast
Shelf
[Globe Graphic] N. America
[Globe Graphic] Venezuela
Colombia
[Globe Graphic] North Sea
East Irish Sea
Egypt
Algeria
[Globe Graphic] Indonesia
STATISTICAL DATA
OPERATIONAL HIGHLIGHTS
OPERATING DATA
1998 1997 1996
Year-end Proved Reserves
Gas (BCF) 6,380 6,418 6,231
Oil (MMBbls) 273.2 253.7 305.8
Total (BCFE) 8,019 7,940 8,066
Production
Gas (MMCF per day) 1,647 1,669 1,603
Oil (MBbls per day) 82.7 87.2 91.1
Total (MMCFE per day) 2,143 2,192 2,150
Average Sales Price
Gas (per MCF) $ 1.97 $ 2.18 $ 2.05
Oil (per Bbl) $13.28 $19.24 $20.39
Average Production Costs (per MCFE) $ .49 $ .51 $ .54
Wells Drilled (Net) 361 317 241
Percentage Successful 88% 89% 90%
Gross Wells Drilling at Year end 30 55 77
Net Wells Drilling at Year end 17 29 32
FINANCIAL DATA
(In Millions, Except per Share Amounts) 1998 1997 1996
Revenues $1,637 $2,000 $2,200
Operating Income 218 503 580
Net Income (a) 86 319 335
Basic Earnings per Common Share (a) $ .48 $ 1.80 $ 1.89
Weighted Average Common Shares 177 177 177
Cash Flows from Operations $ 770 $1,122 $ 995
Capital Expenditures 1,165 1,245 804
Total Assets 5,917 5,821 5,683
Long-term Debt 1,938 1,748 1,853
Stockholders' Equity $3,018 $3,016 $ 2,808
Long-term Debt to Capital Ratio 39% 37% 40%
Cash Dividends per Common Share $ .55 $ .46 $ .44
(a) Included in 1997 is an $80 million pretax charge ($71 million after tax or
$.40 per share) related to the LL&E merger for severance and related exit costs,
and transaction costs. Also included in 1997 is a $50 million pretax gain ($31
million after tax or $.18 per share) related to the sales of oil and gas
properties associated with the divestiture program. Excluding these
non-recurring items, Basic Earnings per Share would have been $2.02 in 1997.
Excluding the non-recurring item related to the reorganization charge of $30
million ($18 million after tax or $.11 per share), Basic Earnings per Common
Share would have been $2.00 in 1996.
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"Even after a challenging year like 1998, BR's mission remains unchanged. Our
objective is to deliver long-term shareholder value through value-added growth
and effective cost management."
TO OUR FELLOW STOCKHOLDERS
SHAREHOLDER LETTER
Nineteen ninety-eight was a year which provided us all a vivid reminder of the
extremely cyclical nature of our business as the industry experienced
considerable volatility, uncertainty and turmoil. Although the year began with a
great deal of optimism, an unseasonably mild winter and economic difficulties in
key areas of the world led to extremely low oil prices and disappointing natural
gas prices by year end. In response to this collapse in commodity prices, the
industry's activity level - which began 1998 at record highs - ended the year
near historical lows. This environment is taking its toll on the industry,
causing many companies severe financial distress, forcing the sale of key
assets, necessitating capital spending curtailments and driving industry
consolidation.
Though BR's financial results have been negatively affected by lower commodity
prices, our solid balance sheet, high quality asset base and operational
efficiency have allowed us to remain profitable and focused on our long-term
value creation strategy. We have made prudent adjustments in our capital program
to keep spending levels in line with expected cash flows. However, we have
maintained funding for the programs and projects which we believe are key to our
goal of delivering sustained value growth over a longer time horizon.
Capital expenditures totaled $1.2 billion in 1998 leading to solid operating
results. We replaced 123% of 1998 production at a cost of $1.10 per MCFE.
Reserve additions included the first reserves bookings from our highly
successful Algerian exploration program, as well as substantial additions from
the San Juan Basin of New Mexico. During 1998, we continued the program we began
several years ago investing significant capital in geological and geophysical
activities and lease acquisitions, investments which form the basis for
substantial reserve additions in future years. In fact, over the past three
years, we have dedicated $477 million to this area of our business. We now
expect to begin to reap the benefits of these prior expenditures with a higher
percentage of our 1999 exploration program targeted for the drill bit.
[Oil and gas platform and other equipment Graphics]
During 1998, our production levels declined 2 percent from the previous year.
While we anticipated the decline in our oil volumes, our gas production for the
year was lower than expected for several reasons: unplanned mechanical
downtime, weather related production interruptions and accelerating decline
rates, primarily in our Gulf of Mexico operations.
Operationally, 1998 was highlighted by a number of successes domestically and
internationally. We achieved a record level of production from our San Juan
operations for the twelfth consecutive year. Development of the Madden Field
in Wyoming moved forward with a successful drilling program in the shallow Lance
and Lower Fort Union Formations, the increase in capacity at the Lost Cabin Gas
Plant and the initiation of production from our third successful Deep Madison
Formation well.
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[PHOTO OF CHAIRMAN, PRESIDENT AND CEO]
In the Northwest European Shelf, we began development of our East Irish Sea
properties, with plans for first production in the fourth quarter of 1999. We
successfully drilled three new wells in Algeria and participated in the
development of the giant Qoubba Field. We also expanded the Company's presence
in North Africa with our entry into Egypt's Offshore North Sinai Block.
Even after a challenging year like 1998, BR's mission remains unchanged. Our
objective is to deliver long-term shareholder value through value-added growth
and effective cost management. We are committed to maintaining our focus on this
goal, irrspective of near-term production gains or commodity price swings, and
we are resolute in maintaining the financial strength of the Company to pursue
this objective. BR's debt to total capital ratio at year end stood at 39
percent, among the strongest in the E & P sector. With our initial 1999 capital
budget set at $750 million, we believe that we will be able to maintain our
solid financial position during 1999. Such strength will enable us to quickly
react to the opportunities that are sure to be generated in the current
operating environment.
Admittedly, we have adopted an aggressive long-term growth target. In order to
position ourselves for success, we have transformed Burlington Resources from a
purely domestic exploitation company into a global Super Independent. Because of
the maturity of the United States from an exploration perspective, we are
building an international exploration and production business where we believe a
number of meaningful growth opportunities exist.
Our strong domestic asset base provides a dependable source of cash flow,
although there are limited opportunities within this business unit to provide
the type of significant growth we desire. The exception, of course, is the Deep
water play in the Gulf of Mexico to which we have made a major commitment.
Growth initiatives such as our Deep water Gulf of Mexico and international
programs require large capital investments and longer lead times. Our strong
balance sheet and stable domestic production base provide us with key advantages
in pursuing this strategy.
We are enthusiastically looking ahead to our 1999 capital program. In North
America, our Deep water exploration program will become fully operational, with
seven to ten wells planned for the year. In light of the current industry
environment, some of our anticipated 1999 Deep water activity may be delayed due
to a lack of partner participation. We are completing a plant expansion at the
Madden Field, doubling capacity to relieve current production constraints and in
preparation for the next Deep Madison well, which is currently drilling. Our San
Juan Basin conventional gas development will intensify in 1999 with an expanded
Mesaverde infill drilling program. Internationally, in addition to new
exploration and appraisal drilling, we will commence development of the MLN
Field in Algeria once we receive government approval for our exploitation plan.
The Company will drill at least one of the high potential exploration prospects
identified on Venezuela's Delta Centro Block in the first half of the year and
initiate the second phase of our East Irish Sea development by mid-year 1999.
1998 PROVED RESERVES
Total: 8.0 TCFE
[Pie Chart]
International Gas 7%
International Oil 3%
Domestic Gas 73%
Domestic Oil 17%
1998 DAILY PRODUCTION
Total: 2.1 BCFE
[Pie Chart]
International Gas 3%
International Oil 5%
Domestic Gas 74%
Domestic Oil 18%
[Photo of a Treating Plant]
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"In pursuing our long-term strategy, we strive to maintain a balance between
near-term production and long-term value growth."
In pursuing our long-term strategy, we strive to maintain a balance between
near-term production and long-term value growth. However, we refuse to fall
prey to the temptation of adding production volumes that do not generate true,
long-term value in order to meet artificially imposed, short-term growth
targets. When we face the inevitable trade-offs in capital allocation, as we
must in today's lower price environment, our choices are driven by what is best
for our shareholders in the long run. Our 1999 capital program reflects this
discipline with our decision to reduce capital spending on the Gulf of Mexico
Shelf where smaller reserve targets and steeper decline rates have made this
area less attractive in relation to other opportunities that can have a
significant impact on the Company's underlying value.
Last year we saw unprecedented deterioration of equity values among E & P
companies and we were certainly not satisfied with the performance of our stock.
Although there is a great deal of pessimism about our industry as we approach
the millennium, at Burlington Resources we are much more optimistic. BR
possesses a high quality domestic asset base that generates considerable cash
flow for reinvestment; a well balanced risk portfolio that includes a large
inventory of exploitation opportunities capable of maintaining stable annual
production without deterioration in overall value; a growing portfolio of high
potential growth oriented exploration projects; and, finally, superior financial
stability and flexibility. These qualities allow us to generate, nurture and
fund high-impact opportunities for the future, even in difficult times.
Reduced industry spending in 1999 will undoubtedly tighten natural gas supply
and create upward pressure on that commodity's price. As one of the largest
holders of U.S. natural gas, we believe our shareholders are superbly positioned
to benefit from the inevitable improvement in this market. And, as one of the
strongest independent E & P companies, both financially and operationally, we
believe our disciplined approach to investment in long-term growth opportunities
will deliver competitive value accretion to our shareholders. On the pages that
follow, we hope to give you insight into our progress, plans for the future and
efforts in positioning ourselves for growth and building long-term shareholder
value.
In closing, this annual report is dedicated to the memory of a friend and former
officer, Hays Warden, retired Senior Vice President and Controller, who recently
lost a battle with cancer. Hays contributed much to BR and will be missed.
/s/ Bobby S. Shackouls
- ----------------------
Bobby S. Shackouls
Chairman, President and
Chief Executive Officer
[Photo Montage]
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REVIEW OF 1998 OPERATIONS
NORTH AMERICA
& INTERNATIONAL
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10
[BURLINGTON RESOURCES NORTH AMERICA GRAPHIC]
BUSINESS AT A GLANCE
Burlington Resources North America (BRNA) was formed as a separate business unit
in 1998 to reinforce the value creation potential of the Company's high quality
domestic assets. With reserves of 7.2 TCFE (81 percent natural gas and 19
percent oil), the size and quality of BRNA's asset base is unparalleled among
independent oil and gas companies. These assets have yielded solid operating
results and a strong production profile since BR's inception and are expected to
be the springboard for the Company's future growth.
BRNA is the largest independent natural gas producer in the U.S. Proved natural
gas reserves at year-end 1998 stood at 5.9 TCF. This reserve base provides an
optimal balance between near-term cash flow generation and long-term stability,
with a reserve-to-production index of ten years.
[Globe Graphic]
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NORTH AMERICA
1998 HIGHLIGHTS
Formed BR North America as a separate business unit.
Added 734 BCFE of proved reserves.
Achieved record gas production levels in the San Juan Basin for the twelfth
consecutive year.
Expanded the Mesaverde 80-acre infill program to two new pilot areas.
Debottlenecked the Lost Cabin Gas Plant at the Madden Field, increasing the
plant inlet capacity to 65 MMCF of gas per day.
Reduced Madden Field shallow formation average drilling costs by over 35
percent.
Completed delineation of Cedar Hills Field in preparation for unitization and
waterflooding.
Drilled 28 successful wells in the onshore Gulf Coast area.
First Deep water Gulf of Mexico production for BR came on stream from the
Cinammon prospect at Green Canyon 89.
NORTH AMERICA
RESERVES
December 31, 1998
GAS OIL TOTAL
(BCF) (MMBbls) (BCFE)
- -------------------------------------
Proved
Developed
Reserves 4,565 199.2 5,760
Proved
Undeveloped
Reserves 1,293 27.4 1,458
- -------------------------------------
Total
Proved
Reserves 5,858 226.6 7,218
- -------------------------------------
"BR North America's primary business objective is to implement a balanced
portfolio of projects which, in aggregate, will contribute to BR's corporate
value growth goals each year."
Technological innovation and cost containment have led to the development of
several core assets in the U.S., where investment repeatability and economies
of scale have allowed the Company to achieve superior returns. A prime example
is the San Juan Basin, where BR is the largest and lowest cost operator. New
business development activities are focused in areas that may become core
assets in the future. One example of this strategy is the Deep water Gulf
of Mexico, where the Company has amassed a 185-block leasehold inventory.
BRNA's primary business objective is to implement a balanced portfolio of
projects which, in aggregate, will contribute to BR's corporate value growth
goals. Activities are organized around core asset and strategic focus areas.
Each focus area develops strategies consistent with its unique strengths and
opportunities. Investment options include exploration, exploitation,
developmentand acquisition projects, as well as other business opportunities
designed to enhance the value of core operations. The Company continuously
evaluates its asset portfolio based on investment performance and anticipated
investment potential. This evaluation drives capital allocation and business
strategies for each asset area.
During 1998, oil and gas capital expenditures related to BRNA's operations
totaled $921 million: $407 million for exploration; $491 million for
development projects; and $23 million related to proved acquisitions. As
a result of these investments, the business unit added
734 BCFE to its proved oil and gas reserves, achieving a reserve replacement
ratio of 102 percent. Reserve replacement costs averaged $1.25 per MCFE.
These 1998 results represent continuing strong operating performance in the
U.S. Over the last three years, BR's U.S. reserve replacement has averaged
131 percent, while its reserve replacement costs have averaged $.89 per MCFE.
SAN JUAN BASIN
The San Juan Basin is the cornerstone of BR, providing significant earnings and
the cash flow to fuel the Company's long-term growth strategy. The assets in
this basin account for approximately half of BR's gas reserves and daily gas
production. These assets generate more than three times the cash flow required
to maintain production levels in this basin.
[Gas Plant and South Louisiana Graphics]
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NORTH AMERICA
1998 PROVED RESERVES
Total: 7.2 TCFE
[PIE CHART GRAPHIC]
Onshore Oil 16%
Offshore Oil 3%
Onshore Gas 75%
Offshore Gas 6%
[PIE CHART GRAPHIC]
North America 1998
Daily Production
Total: 1.9 BCFE
Onshore Oil 15%
Offshore Oil 5%
Onshore Gas 63%
Offshore Gas 17%
As the largest operator and the lowest cost producer in the basin, BR
continually adds significant value by using its technical expertise to optimize
costs.
The San Juan Basin, located in northwest New Mexico and southwest Colorado, is
one of the most prolific hydrocarbon producing basins in the U.S. The four major
gas producing horizons, the Fruitland Coal, Pictured Cliffs, Mesaverde and
Dakota, in the basin range in depth from 1,000 to 8,500 feet.
In 1998, BR achieved a record level of gas production in the basin for the
twelfth consecutive year. At year end, net daily gas production reached over 840
MMCF per day. Over the last ten years, BR has grown production in the San Juan
Basin at an annual compound rate of over 15 percent. While the rate of growth
has moderated in recent years as the coalbed methane play has matured, the
growth rate over the last five years has averaged seven percent.
Contributing approximately half of BR's net gas production from the San Juan
Basin, the Fruitland Coal is the largest producing coalbed methane reservoir
ever discovered worldwide. Because of BR's development of the Fruitland Coal, it
is the world's largest producer of coalbed methane. BR also operates the Val
Verde Plant, the basin's largest treating plant, along with approximately 420
miles of gathering lines and 14 compressor stations. Optimization projects such
as recavitations and wellsite compression have added net incremental coal seam
gas volumes in each of the last five years, to a peak of over 460 MMCF of gas
per day in early 1998. Net annualized coal seam gas volumes remained relatively
constant at 450 MMCF per day for the year.
In the conventional horizons, a major focus
of the efforts has been the Mesaverde Formation which was originally developed
in the 1950's on 320 acre spacing and down spaced in the early 1970's on 160
acre spacing. In 1994, BR undertook an extensive study of the formation across
the entire basin. Results indicated that down-spaced drilling (infill drilling)
on 80 acre spacing could increase gross recoverable gas reserves by
approximately 1.5 TCF across the basin. A pilot infill drilling program begun in
1997 was expanded in 1998 to include two additional pilot areas. To date, BR has
drilled 38 Mesaverde infill wells, investing about $9 million.
New basin-wide increased density pool rules that allow for 80 acre infilling of
the Mesaverde formation were approved by the New Mexico Oil Conservation
Division in February 1999. BR plans to drill 50 new wells in 1999. By 2000, the
development program is planned to level out at 90 wells per year. The Company
plans to spend about $80 million to drill in excess of 400 infill wells over the
next five years. In total, the Mesaverde infill program exposes the Company to
significant gas reserves at a cost to add of about $.32 per MCF.
Another effort started in 1998 was the Lewis Shale project, involving data
gathering from one of the major source rock shales in the basin. Results are
promising, with the average gross production increase for the first 29
completions at 300 MCF of gas per day and a cost to add of around $.30 per MCF
of gas. The project will continue in 1999 by adding Lewis Shale to existing
Mesaverde well bores with 66 completions planned. If results continue to be
favorable, the Company could expand the program to recomplete over 1,000 wells
in the Lewis Shale over the next five years. Total net costs for the expanded
program would be approximately $145 million, resulting in significant increases
in reserves.
[Pipe and gas plant Graphics]
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NORTH AMERICA
PRODUCTION & PRICES
Year Ended December 31,
1998 1997 1996
- ---------------------------------------------------------------
Production
Gas 1,580 1,592 1,520
(MMCF per day)
Oil 66.2 68.3 72.2
(MBbls per day)
- ---------------------------------------------------------------
Average
Sales Prices
Gas (per MCF) $ 1.94 $ 2.16 $ 2.02
Oil (per Bbl) $ 13.31 $ 19.32 $ 20.64
- ---------------------------------------------------------------
In 1997, BR continued its exploratory efforts in the Deep Pennsylvanian
Formation. Two exploratory wells were drilled that confirmed reservoir quality
rock and hydrocarbon sourcing. During 1998, the Company acquired 350 square
miles of 3-D seismic aimed at locating structural or stratigraphic trapping of
hydrocarbons and delineating prospects for 1999. BR holds 815,000 gross acres in
the Pennsylvanian Formation. While this is a risky opportunity, the target sizes
are large enough that success could result in substantial growth in production.
Early in 1998, BR acquired additional interest in the Allison Unit. The
acquisition substantially increased the Company's ownership in the unit and
added proved reserves of 75 BCFE. It allowed BR to accelerate development
activity in the unit in 1998 and into 1999. The Company will continue to pursue
strategic acquisitions that strengthen its significant position in the basin.
PERMIAN BASIN
BR's position in the Permian Basin comprises in excess of 662,000 net acres in
several significant trends. These properties continue to provide a large number
of opportunities to add both oil and gas reserves. Net production in the basin
was approximately 85 MMCF of gas per day and 12,600 Bbls of oil per day in 1998.
The Company's primary asset in the Permian Basin is the Waddell Ranch, where BR
controls nearly 77,000 gross or 37,000 net acres. Since assuming operations in
1991, BR has continuously increased oil production on the Waddell Ranch
primarily through exploitation and optimization. In 1998, approximately 154
total projects were completed on the Waddell Ranch at a cost of $19 million. In
1999, the Company will implement more than 150 projects to increase recoveries
from existing waterfloods through expansion and optimization.
ANADARKO BASIN
[GAS PLANT GRAPHIC]
The Anadarko Basin offers a balanced, diverse inventory of exploitation and
exploration opportunities. During 1998, BR spent $63.5 million in the basin,
completing 55 drilling and workover projects and acquiring 265 square miles of
3-D seismic data surveys. Average net gas production for the year from the basin
was 107 MMCF of gas per day and oil production reached 600 Bbls per day.
A consolidated acreage position of approximately 250,000 net acres, in
conjunction with over 700 square miles of proprietary 3-D seismic data, yields a
significant competitive advantage for growth in the coming years.
In addition, BR's focus on reducing development costs should allow enhanced
economic viability of low-risk exploitation projects in the future.
WILLISTON BASIN
The Williston Basin, located in western North Dakota and northeast Montana, is
one of BR's primary oil producing areas. During 1998, 104 projects were
completed in the basin at a cost of $89 million. At year end, net daily oil
production for the basin was approximately 22,000 Bbls per day.
The Company's activity in 1998 focused on the Cedar Hills and East Lookout Butte
Fields. These fields are located along the Cedar Creek Anticline and are part of
the Red River "B"
"The cornerstone of BR is the San Juan Basin, providing significant earnings
and the cash flow to fuel the Company's long-term growth strategy."
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NORTH AMERICA
WELLS DRILLED
Year Ended December 31,
1998 1997 1996
- ---------------------------------------------
PRODUCTIVE
Exploratory 16.3 29.0 23.3
Development 297.7 247.5 189.3
- ---------------------------------------------
DRY
Exploratory 27.5 26.5 17.5
Development 12.5 8.5 5.9
- ---------------------------------------------
TOTAL NET WELLS 354.0 311.5 236.0
- ---------------------------------------------
NORTH AMERICA
CAPITAL EXPENDITURES
Year Ended December 31,
($ Millions)
1998 1997 1996
- ----------------------------------------------------
OIL AND GAS
ACTIVITIES $ 921 $ 927 $ 676
- ----------------------------------------------------
PLANTS AND
PIPELINES 60 40 45
- ----------------------------------------------------
ADMINISTRATION 45 32 8
- ----------------------------------------------------
TOTAL $1,026 $ 999 $ 729
- ----------------------------------------------------
NORTH AMERICA UNIT COSTS
Year Ended December 31,
($ per MCFE)
1998 1997 1996
- -----------------------------------------------------------
AVERAGE
PRODUCTION
COSTS $ .47 $ .50 $ .52
- -----------------------------------------------------------
DD&A Rates $ .59 $ .58 $ .57
- -----------------------------------------------------------
Trend. During 1998, the Cedar Hills Field delineation was completed in
preparation for unitization and secondary recovery. If unitization of the field
proceeds on schedule, plans for 1999 include constructing waterflood facilities,
infill drilling and converting producing wells into water injectors. Production
response to waterflooding is anticipated in 2001.
In the East Lookout Butte Field, BR is operator of a horizontal waterflood
program. During 1998, BR drilled 24 infill wells and expects to complete infill
drilling by year-end 1999.
With horizontal drilling technology and expertise, BR believes it has a key
technical advantage in the Williston Basin. The Company has drilled over 300
horizontal wells in the basin and over 95 percent of the 1999 drilling budget
for the basin will be spent on approximately 50 horizontal wells. While most E&P
companies use outside directional drilling personnel on their horizontal wells,
BR does all of its directional work with its own wellsite, geoscience and
engineering staff. This has proven to be cost effective and has allowed BR to
develop world class horizontal drilling capabilities, ultimately translating
into higher well productivity and reserve recovery. This technical knowledge
will be even more valuable when applied to other domestic and international
opportunities requiring precision directional drilling skills.
WIND RIVER BASIN
BR's major asset in the Wind River Basin is the Madden Field in central Wyoming,
an asset whose value is being significantly enhanced by applying the Company's
engineering expertise. The field produces natural gas from multiple horizons,
ranging in depth from 5,500 to over 24,000 feet. The Company's working interest
varies by horizon, from 27 to 56 percent. The Madden Deep Unit, operated by BR,
covers 70,000 gross acres. There are currently three well completions in the
prolific deep Madison Formation and 58 producing wells in the shallower
formations.
Increased drilling activity in the shallow horizons in 1998 overcame the natural
field decline and resulted in gross shallow gas production increasing from 72
MMCF of gas per day early in the year to around 92 MMCF of gas per day at year
end. The total year-end field production of 140 MMCF of gas per day is the
highest sustained rate ever recorded in this 30 year old gas field. With
commissioning of additional gas processing capacity in the field, gross field
production is expected to grow to approximately 240 MMCF of gas per day by the
end of 1999.
During 1998, the shallow drilling program was concentrated in the Lower Fort
Union and Lance Formations. These programs were quite successful, with 13 wells
drilled during the year. Completed well costs in Lower Fort Union wells have
been reduced from an average of $1.4 million in late 1997 to under $900 thousand
on the wells drilled in 1998. Additionally, with the average well now being
drilled in 12 to 14 days, drilling time has been cut in half. The 1999 drilling
program includes drilling 20 more Lower Fort Union and shallow Lance wells.
In 1998, BR successfully connected and initiated production from the Bighorn
#4-36, the third well completed in the deeper Madison Formation. Completed in
1997, this well extended the lowest known gas in the pool, increasing proved
gross reserves to approximately 2 TCF of gas.
Unlike the gas produced from the shallow formations, the Madison Formation
contains carbon dioxide and hydrogen sulfide and must be processed prior to
sale. Constructed for this purpose, the Lost Cabin Gas Plant was debottlenecked
during the year, increasing gross inlet capacity from 50 to 65 MMCF of gas per
day. Because production levels continue to be constrained by plant capacity, an
expansion is currently under construction to provide an incremental inlet
capacity of 65 MMCF of gas per day in the third quarter 1999.
10
15
"With horizontal
drilling
technology and
expertise, BR believes it has a key
technical advantage in
the Williston Basin."
NORTH AMERICA
PRODUCTIVE WELLS
December 31, 1998
Gross Net
- -----------------------------------
Oil 5,559 2,920
- -----------------------------------
Gas 10,667 6,004
- -----------------------------------
BR is currently drilling the fourth Madison well. The Bighorn #5-6 was spud in
January 1999, marking the beginning of the next development phase of the Madison
Formation. This well provides a necessary take point to drain existing proved
reserves. With continued encouraging performance of the existing producing
wells, plans are to drill lower on the structure following the Bighorn #5-6. The
Company believes drilling lower on this structure could possibly double proved
reserves in the formation.
In late 1998, BR reached agreement to participate in the construction of
additional gathering capacity to move gas from central Wyoming toward available
transportation and away from the pipeline constraints. This investment by BR is
key to optimizing the value of its current and future Madden natural gas
reserves.
Cost containment, an aggressive development program and an innovative gas
marketing and transportation plan combine to maximize the value of this world
class asset, which should provide BR with steady cash flow and earnings for the
next two decades or more.
ONSHORE GULF COAST
The Company has a long history of exploration and development in south
Louisiana. Its 600,000 acres of fee lands provide a competitive advantage in an
area where acreage costs are high, leasehold positions are difficult to maintain
and seismic data is expensive to gather. Most of the fee lands are now covered
by 3-D seismic data, a significant factor in the Company's successful drilling
program in 1998. In 1998, BR participated in the drilling of 16 successful
wells, which not only sustained net production but increased it from 134 MMCF of
gas per day and 8,300 Bbls of oil per day in 1997 to 160 MMCF of gas per day and
9,600 Bbls of oil per day in 1998.
An example of BR fee land operations is at Four Isle Dome, located in Terrebonne
Parish, about 25 miles southwest of Houma, Louisiana. The field was first
discovered in 1927 and contains 35 pay sands ranging in depth from 5,700 to
17,500 feet. Since 1997, BR has increased its working interest from 25 percent
to 45 percent and assumed operatorship. This has allowed BR to drill
aggressively, resulting in four successful wells and one recompletion, bringing
the total active well count to seven at year end. Gross daily gas production
increased from under one MMCF of gas per day to over 40 MMCF of gas per day over
this period.
Continued interpretation of a 55 square mile 3-D seismic survey has yielded at
least four additional prospects to be drilled in the Four Isle Dome area in the
next 12 to 18 months. The Company is highly optimistic about these prospects
because 3-D seismic data shows amplitude events that correlate well with
productive reservoirs. Successful results could yield additional volume
increases similar to those achieved in 1998. Other unexploited flanks of the
Four Isle Dome remain to be mapped, which should continue the rejuvenation of
the field.
Another area of onshore activity in 1998 was in the Transition Zone, an area
covering five miles of Louisiana coastline from the Sabine River to Vermilion
Bay. The Company's current acreage position includes 9,400 gross acres,
supported by 3-D seismic data of over 1,000 square miles. The Transition Zone
contains objectives in multiple formations ranging from 13,000 to 21,000 feet.
Although the Transition Zone drilling represents higher risk, potential reserve
targets of 20 to 800 BCF of gas led the Company to participate in a venture with
a 50 percent working interest. Two non-commercial wells have been drilled to
date and a third well was in progress at year end.
During 1998, the Gulf Coast program expanded into south Texas where the Company
participated in drilling 12 successful wells. At Armstrong Ranch in Jim Hogg
County, BR has found new opportunities in another older production area. This
field was
11
16
NORTH AMERICA
ACREAGE
December 31, 1998
GROSS NET
- --------------------------------------
DEVELOPED
ACRES 5,658,325 3,017,448
- --------------------------------------
UNDEVELOPED
ACRES 12,074,044 9,697,818
- --------------------------------------
"Most of the
fee lands are now
covered by 3-D
seismic data,
a significant factor
in the Company's
successful drilling program
in 1998."
discovered in 1959 using reflection 2-D seismic data, with first production
occurring in the same year. To date, the field has produced in excess of 650
BCF. In 1998, BR successfully drilled two wells in the Wilcox Formation which
were awaiting final completion at year end. When a pipeline is completed, the
two wells are anticipated to produce at a gross combined rate of 20 MMCF of gas
per day. Three additional Wilcox Formation wells are scheduled for drilling in
1999, as well as a lower Wilcox test.
With a total acreage position of over 860,000 acres in south Louisiana and south
Texas and many exploitation opportunities using 3-D seismic data, BR looks
optimistically to its onshore program to help offset the steep decline on its
Gulf of Mexico Shelf, which is consistent with industry experience in this area.
GULF OF MEXICO SHELF
BR's history on the Gulf of Mexico Shelf dates back to the 1970's. The "Shelf"
is defined as water depths less than 600 feet. BR invested $218 million on the
Shelf in 1998, with net gas production averaging about 307 MMCF of gas per day
and net oil production averaging 14,000 Bbls per day for the year. At year end,
the Company had an interest in a total of 236 Shelf leases, many of which are
held by production. In addition to non-operated interests in numerous blocks, BR
operates 60 platforms and 35 fields.
Although the industry's drilling activity on the Shelf has increased
dramatically over the last ten years and many completion technology improvements
have been made, production has remained fairly constant. Smaller reserve
targets, steeper production decline rates and depressed commodity prices led BR
to reassess the economic viability of exploration and exploitation programs on
the Shelf. As a result, BR is reducing its 1999 capital commitment by almost 80
percent, to around $50 million, focusing on low risk exploitation activities.
Such activities include South Timbalier 148, where the Company owns a 40 percent
working interest. It is located 80 miles south of New Orleans, Louisiana, in 110
feet of water. BR's interpretation of 3-D seismic data has resulted in the
drilling of seven successful wells, with net production on the block increasing
from two MMCF of gas per day and 25 Bbls of oil per day in 1994, to a peak of 54
MMCF of gas per day and 2,100 Bbls of oil per day at mid-year 1998. In 1998, BR
participated in the drilling of the B-2 and A-9/A-9ST wells, recompleted the B-1
well, and achieved an annualized production increase of 10 MMCF of gas per day
and 400 Bbls of oil per day. At year end, the net gas production in the field
had declined to 23 MMCF of gas per day and oil production to 660 Bbls per day,
exemplifying the steep production declines being experienced by all participants
on the Shelf. BR's interpretation of additional 3-D seismic data in the
surrounding area prompted the Company to negotiate a farmin of the adjacent
South Timbalier Block 149. At year end, the E-4 exploratory well was drilling
near the projected total depth of 21,776 feet.
High Island A-371, located 115 miles southeast of Galveston, Texas, in 400 feet
of water, is a 100 percent BR-owned field that first
produced in 1996. At its peak in 1996, High Island A-371 produced at a gross
rate of 100 MMCF of gas per day. At year-end 1998, gross production declined to
around 14 MMCF of gas per day. BR has identified six additional drilling
opportunities on the block and will drill several of these prospects in 1999,
which could help turn around the natural production decline of this field.
[offshore platform graphic]
12
17
"BR will continue
to pursue
opportunities in
the Deep water
in 2000 and
beyond."
NORTH AMERICA
PLANS FOR 1999
Drill 50 wells in the Mesaverde 80-acre infill program.
Accomplish 66 Lewis Shale completions in existing Mesaverde well bores.
Drill approximately 50 horizontal wells in the Williston Basin.
Drill the fourth deep Madison well, the Bighorn #5-6, at the Madden Field and
complete the Lost Cabin Gas Plant expansion, bringing the inlet capacity to 130
MMCF of gas per day.
Drill 7 to 10 wells in the Gulf of Mexico Deep water program, including BR's
first operated prospect, Spoon, at Ewing Bank Block 913.
GULF OF MEXICO DEEP WATER
Hydrocarbon basins in the U.S. have continued to mature, making economically
attractive exploration opportunities increasingly rare. The Deep water Gulf of
Mexico represents one of the last world class exploration opportunities in the
U.S. The Company believes that the Deep water provides an excellent opportunity
for value-added growth in North America. A significant part of BR's future
growth strategy revolves around its
Deep water commitment.
The Company's exploratory Deep water acreage is diverse, covering water depths
from 600 to 8,000 feet, but is focused on several geologic trends. The acreage
position offers a balance of near-term and long-term drilling opportunities,
while also having the scale to provide for repeatable investments. BR has
identified approximately 75 leads or prospects on the basis of 2-D and 3-D
seismic data. At year end, BR had 185 blocks in its inventory, making it one of
the largest leaseholders in the Deep water.
In December 1998, production came on stream at Green Canyon Block 89, the
Cinnamon prospect, from the A-1 Well. Three additional wells are planned for
the first phase of development on this block in which BR owns a 17 percent
interest.
Although BR's Deep water program is not scheduled to be fully underway until
1999, the Company participated in the drilling of three wells in 1998, none of
which found commercial quantities of hydrocarbons. In preparation for its fully
operational Deep water drilling program, BR contracted for the construction of a
semisubmersible drilling rig capable of operating in water depths up to 7,500
feet. The rig will be delivered in the third quarter of 2000 and will be
exclusively available to BR for up to six years.
BR's Deep water drilling program is scheduled to accelerate in 1999, with seven
to ten wells planned. In light of the current industry environment, some of our
anticipated 1999 Deep water activity may be delayed due to a lack of partner
participation. In total, the 1999 program should expose the Company to
significant reserve potential. The first well to be drilled in the 1999 program
is the BR-operated Spoon prospect, located in Ewing Bank Block 913 in
approximately 800 feet of water. In addition, joint ventures have been forged
between BR and other companies to share risk and to gain exposure to other
exploration opportunities. One such venture will begin drilling in 1999. In the
fourth quarter of 1999, the joint venture will take delivery of a drillship
capable of drilling in up to 10,000 feet of water. The rig will be available to
the joint venture for up to five years.
BR will continue to pursue opportunities in the Deep water in 2000 and beyond.
The Company projects that its typical program in the future will consist of
drilling up to ten new wells per year. Based on its success from an aggressive
exploration program, BR plans to commit the capital to fund its drilling
program, as well as the capital necessary for future development.
[offshore drilling rig graphic]
13
18
[BURLINGTON RESOURCES INTERNATIONAL GRAPHIC]
BUSINESS AT A GLANCE
BR entered the international oil and gas business through two major events: its
merger with LL&E, which had an established international presence, and the
acquisition of approximately 700 BCF of undeveloped proved and probable gas
reserves in the East Irish Sea. In 1998, BR affirmed its commitment to a global
presence as a key element of its long-term growth strategy by forming Burlington
Resources International (BRI).
BRI's proved reserves at year-end 1998 totaled 801 BCFE, approximately 35
percent oil and 65 percent natural gas. The proved reserves are concentrated in
the Northwest European Shelf, in the Irish Sea and the United Kingdom and Dutch
sectors of the North Sea. BRI also has proven reserves in Algeria, Colombia and
Indonesia. Although it is a relatively small part of BR's total business today,
BRI is positioning itself to provide significant future growth to BR through
high potential exploration and development opportunities.
[GLOBE GRAPHIC]
14
19
INTERNATIONAL 1998 HIGHLIGHTS
Formed BR International Inc. as a separate operating unit.
Successful exploration discovery on North Sea Block 21/12. The well tested at
8,200 Bbls of oil per day. Participated with a 26 percent interest.
Reached transportation and processing agreements for the East Irish Sea Dalton
and Millom Fields.
Eventful year in Algeria with the discovery of the MLSE Field, commencement of
Qoubba field development and successful drilling of 3 wells in Block 405.
Entered into an agreement to earn a working interest in both exploration and
development opportunities in the Offshore North Sinai Concession in Egypt.
Completed environmental and pre-drilling engineering work at Delta Centro Block
in Venezuela in preparation for 1999 drilling program.
Participated in a 22-year agreement to provide up to 325 MMCF of gas per day to
Singapore from the Indonesian Kakap Block in the West Natuna Sea.
INTERNATIONAL
RESERVES
As of December 31, 1998
GAS OIL TOTAL
(BCF) (MMBbls) (BCFE)
- ------------------------------------
Proved
Developed
Reserves 258 14.5 345
- ------------------------------------
Proved
Undeveloped
Reserves 264 32.1 456
- ------------------------------------
Total
Proved
Reserves 522 46.6 801
- ------------------------------------
"BRI has adopted a strategy with three major elements: focus, balance and
discipline."
In building its portfolio, BRI adopted a strategy based on focus, balance and
discipline. Focus translates into a decision to concentrate in a limited number
of geographical areas. Each area must be capable of becoming material to BR and
offer potential for repeatable or continued investment opportunities to provide
sustainable growth. Balance refers to building a portfolio which includes
acquisition, exploitation and exploration opportunities, as well as creating a
mix of short, medium and longer term projects that can provide a sustainable and
growing production profile. Finally, although a sense of urgency is crucial to
grow the international business and contribute to corporate growth goals, BR
takes a disciplined approach when considering new projects and ventures. This
approach assures that opportunities create value and are beneficial to the
corporate portfolio.
An objective assessment was undertaken in 1998 of hydrocarbon basins around the
world based on geotechnical, commercial and geopolitical risks balanced with
BR's knowledge and competencies. As a result, five areas were selected for
business development activities: the Northwest European Shelf; North Africa;
Northern South America; the Far East; and West Africa. Strategies for the first
four are centered around expanding the Company's existing assets in these areas,
while an entry strategy has been developed for West Africa, where the Company
currently has no operations.
Oil and gas capital expenditures devoted to international activities totaled
$136 million in 1998: $102 million for exploration; $30 million for development
activities; and $4 million related to proved acquisition activities. Proved
reserves added during the year totaled 225 BCFE. International projects are
typically viewed on a multi-year investment cycle. As a start-up operation,
single year statistics are somewhat distorted. Nonetheless, BR's international
reserve replacement averaged 260 percent over the three-year period 1996 to
1998, and reserve replacement costs over the same period averaged $.82 per MCFE.
[Oil and gas equipment graphic]
15
20
INTERNATIONAL
1998 PROVED RESERVES
Total: 801 BCFE
[PIE CHART GRAPHIC]
Oil - 35%
Gas - 65%
INTERNATIONAL
1998 DAILY PRODUCTION
Total: 166 MMCFE
[PIE CHART GRAPHIC]
Oil - 60%
Gas - 40%
[NORTH SEA DRILLING PLATFORM GRAPHIC]
NORTHWEST EUROPEAN SHELF
BR's Northwest European Shelf focus area includes the U.K., Dutch and Danish
sectors of the North Sea, as well as the East Irish Sea. Current production
comes from the U.K. and Dutch sectors of the North Sea, where in 1998 the
Company's average net production was 66 MMCF of gas per day and 11 MBbls of oil
per day.
In the U.K. North Sea, production is from the T-Block Complex, where BR has an
11 percent working interest, and from the Brae Complex, where the Company has a
six percent working interest. Although base production is declining in both
fields, this is being mitigated by new exploration and development opportunities
within each area. In 1999, newly identified leads at Brae will be evaluated for
drilling. Also, one well is scheduled for drilling at the T-Block Thelma Field
to extend field limits.
The Company participates in natural gas exploration and production in the Dutch
and Danish sectors of the North Sea. Net production in this area averaged 30
MMCF of gas per day in 1998. In 1999, three wells are scheduled to be drilled in
the Dutch North Sea. In the Danish North Sea, BR participated in a new license
which was awarded for exploration on the Ribe and Viborg Blocks. During 1999,
seismic evaluation of leads on these blocks will be conducted, with exploratory
drilling expected in 2000. Work commitment under the license requires
acquisition of 170 square miles of seismic data and drilling of three wells. The
Company has assessed the reserve potential of this area to be significant.
In mid-1998, BR acquired a 20 percent working interest in central North Sea
Blocks 21/12 and 21/13 through two farmins. In August 1998, an exploratory
discovery was made when the 21/12-3 well encountered a 100-foot thick oil
producing Jurassic sandstone formation. BR has a 26 percent interest in this
well as a result of a farmin. The well, located 80 miles off the coast of
Scotland in 279 feet of water, tested at a stabilized rate of 8,200 Bbls of oil
per day. Development options are currently being evaluated.
BR's most exciting project on the Northwest European Shelf is in the East Irish
Sea. In late 1997, BR acquired ten licenses in the East Irish Sea, encompassing
267,000 acres at a cost of $143 million, including a 90 percent working interest
in seven operated, undeveloped gas fields with estimated gross recoverable
reserves in excess of 700 BCF.
The properties are located 25 miles offshore in approximately 100 feet of water
and are covered by high quality 3-D seismic surveys. BR originally included
construction of processing and transportation facilities into the project timing
and economic evaluation. Development plans were accelerated and economics were
enhanced when an agreement was reached with a nearby operator to transport and
process the gas from two sweet gas fields, Dalton and Millom. The Company also
received development and operatorship approval for Dalton Annex B from the U.K.
government.
The first development well for these fields was spud in February 1999, with a
total of three wells scheduled for the year. Subsea completion of these wells
will initiate first production in October 1999, with gross production reaching
95 MMCF of gas per day by year end. Additional drilling, completion and
facilities work is scheduled in 2000. Gross production from the project is
expected to reach 170 MMCF of gas per day. Development options for the five
remaining sour gas fields are being evaluated.
16
21
INTERNATIONAL
PRODUCTION & PRICES
YEAR ENDED DECEMBER 31,
1998 1997 1996
- ---------------------------------------------------------------
PRODUCTION
Gas 67 77 83
(MMCF per day)
Oil 16.5 18.9 18.9
(MBbls per day)
- ---------------------------------------------------------------
AVERAGE
SALES PRICES
Gas (per MCF) $ 2.56 $ 2.69 $ 2.56
Oil (per Bbl) $13.16 $18.95 $19.45
- ---------------------------------------------------------------
INTERNATIONAL
CAPITAL EXPENDITURES
YEAR ENDED DECEMBER 31,
($ MILLIONS)
1998 1997 1996
- --------------------------------------------------------
Oil and Gas
Activities $136 $228 $ 62
- --------------------------------------------------------
Plants and
Pipelines -- 10 9
- --------------------------------------------------------
Administration 3 8 4
- --------------------------------------------------------
Total $139 $246 $ 75
- --------------------------------------------------------
INTERNATIONAL UNIT COSTS
YEAR ENDED DECEMBER 31,
($ PER MCFE)
1998 1997 1996
- ----------------------------------------------------------------
Average
Production
Costs $ .71 $ .60 $ .71
- ----------------------------------------------------------------
DD&A Rates $ 1.06 $ 1.08 $ 1.13
- ----------------------------------------------------------------
NORTH AFRICA
The Company's operations on Algeria's Block 405, located in the Berkine Basin of
eastern Algeria, are the centerpiece of the Company's North African focus area.
Industry activity in this highly prospective area has discovered in excess of
three billion Bbls of recoverable oil reserves since the country opened to
foreign investment in 1989.
BR was a relatively early entrant into Algeria, having initiated a production
sharing agreement in 1993 that gave the Company a 65 percent working interest,
before participation by Sonatrach, the state-owned oil company, in two
exploration blocks in the Saharan Berkine Basin, Blocks 215 and 405.
As operator, BR has drilled 12 wells on Block 405 so far and all have
encountered hydrocarbons. Appraisal of these accumulations is ongoing. However,
the Company now believes it has discovered at least three commercial oil fields,
the MLN Field, the MLSE Field and the MLNE Field which is an extension of the
giant Qoubba Field, discovered on adjacent blocks. A fourth discovery well, the
MLC-1, is currently under evaluation. The Company is also appraising deeper
accumulations encountered in at least three wells. The nature and full extent of
this deeper reservoir is not yet known.
Proved reserves for Block 405 were booked in 1998 with the potential to increase
significantly with successful delineation of recent discoveries. In compliance
with its production sharing agreement, the Company relinquished a portion of
Block 405 in 1998 as it entered the second five-year exploration phase of the
contract. The area relinquished included a portion of the unexplored area of the
block, as well as the MLE gas discovery, which was the first well drilled on the
block. BR also relinquished Block 215 in 1998.
Capital and exploration expenditures in Algeria totaled $45 million in 1998. Of
this total, $33 million was devoted to exploratory, development and appraisal
drilling, $11 million was related to seismic evaluation and $1 million was
committed to production facility construction.
Two wells were drilled in the central portion of Block 405 in 1998. In August,
BR began drilling the MLW-1, a wildcat well 8.4 miles southwest of MLN-4, which
had encountered the presence of a deeper Devonian reservoir in addition to the
Triassic TAG. The MLW-1 encountered hydrocarbons at both intervals. While the
TAG Formation failed to produce fluids to the surface, the Devonian flowed 1,545
Bbls of oil per day and 3 MMCF of gas per day, confirming the presence of a
productive Devonian reservoir in the western portion of the block.
Following the completion of the MLW-1, the rig was moved to drill the MLN-5, 6.8
miles northeast of the MLW-1 and 1.6 miles southwest of the MLN-4. The well
tested at a rate of 6,820 Bbls per day of 44 degree API gravity oil and 7 MMCF
of gas per day from the Devonian Formation, but was not productive in the TAG
reservoir. Two other thin hydrocarbon zones identified were not tested and will
be evaluated in future drilling. The presence of the Devonian at MLN-4, MLN-5
and MLW-1 is highly encouraging and could indicate a very productive and
widespread accumulation on Block 405. Additional drilling in 1999 should provide
additional data in determining the extent and potential of the reservoir. At
year end, the Company was planning development for the MLN Field. The plan will
be submitted to the government in 1999 and, with timely approval by Sonatrach,
production at the field is anticipated in late 2001.
[PIPE GRAPHIC]
22
INTERNATIONAL
WELLS DRILLED
YEAR ENDED DECEMBER 31,
1998 1997 1996
- ---------------------------------------------------------------
Productive
Exploratory 3.5 2.4 2.0
Development 1.8 1.3 2.4
- ---------------------------------------------------------------
Dry
Exploratory 2.0 1.3 0.6
Development -- 0.1 --
- ---------------------------------------------------------------
Total Net Wells 7.3 5.1 5.0
- ---------------------------------------------------------------
INTERNATIONAL
PRODUCTIVE WELLS
DECEMBER 31, 1998
Gross Net
- ------------------------------------------------------
Oil 134 19
- ------------------------------------------------------
Gas 59 5
- ------------------------------------------------------
In June of 1998, BR announced the discovery of a new field, MLSE, with the
successful drilling of the MLSE-1. Located in the southeastern portion of the
block, the well encountered four hydrocarbon bearing intervals. The well flowed
at a combined rate of 14,638 Bbls of oil per day and 107 MMCF of gas per day. In
the fourth quarter, the MLSE-2 was drilled, establishing the limits of the two
main producing horizons and was suspended as a potential water injector. In late
1998, additional 3-D seismic survey work was initiated to cover the southeast
portion of the block. When this survey is completed in 1999, additional drilling
will more fully appraise the extent of the MLSE Field.
The MLNE Field, representing approximately six percent of the giant Qoubba
Field, which extends onto the block from the north, is currently under
development. Production is anticipated in 2002.
BR will drill six more wells on Block 405 in 1999. A total capital commitment of
$84 million has been earmarked for drilling, facilities development and
completion of seismic survey work.
BR's approach to exploration includes allocating a small part of its portfolio
to frontier exploration opportunities. These are high-risk opportunities in
relatively unexplored regions that provide tremendous upside potential if a
discovery is made. In 1998, BR took a 20 percent interest in a frontier
exploration project of this type in Eritrea. The concession covers nine million
gross acres and carries a commitment to drill at least three wells. The first
well was drilled in 1998 and although the well was unsuccessful, the fact that
free oil was encountered in sidewall cores was very encouraging. The second well
on the concession was also unsuccessful. The third well was spud in January
1999. Although a high-risk venture, any success in Eritrea could be significant
because of the huge acreage position covered by the concession.
In December 1998, BR announced an agreement to earn a working interest in both
exploration and development opportunities at the Offshore North Sinai Block,
located in the Nile River Delta area of the Mediterranean Sea. The agreement
provides the Company with a 50 percent working interest in an 870,000 gross acre
block that contains three proved undeveloped Pliocene gas fields, several
additional exploration prospects which are similar in nature to these Pliocene
accumulations and an exploration prospect in deeper Miocene stratigraphy. In
exchange, BR has agreed to fund a disproportionate share of future capital
commitment to develop these proved undeveloped gas reserves. Initial development
is projected to begin during 1999, with production to commence during 2001.
Additionally, if the high potential deeper Miocene prospect, referred to as Seti
East, is successful and deemed to be commercial, BR has agreed to fund a
disproportionate share of future development costs associated with the project,
as well. Total capital committed to this project in 1999 is $22 million.
NORTHERN SOUTH AMERICA
BR's efforts in Latin America are focused in northern South America. Presently,
the Company has a 14 percent interest in the Casanare Association Contract in
Colombia as well as exploration interests in Venezuela, Colombia and Peru.
The Latin American strategy provides the springboard to quickly transform the
business from a highly leveraged exploration portfolio to one of balance -
providing production, exploitation and exploration opportunities. BR intends to
aggregate substantive interest in key producing assets then work to enhance the
value through exploitation. Success of the strategy hinges on maintaining focus,
aggressive pursuit of key assets and value-based acquisitions.
18
23
INTERNATIONAL ACREAGE
DECEMBER 31, 1998
Gross Net
- --------------------------------------------------------------
Developed
Acres 165,401 12,745
- --------------------------------------------------------------
Undeveloped
Acres 16,112,345 5,125,131
- --------------------------------------------------------------
INTERNATIONAL
PLANS FOR 1999
Submit plan of development for the Algerian MLN Field in Block 405.
Drill 6 additional wells in Algeria on Block 405 and participate in 12
development wells in the Qoubba Field.
Begin development of the Dalton and Millom fields in the East Irish Sea, with
initial gross production of 95 MMCF of gas per day commencing in the fourth
quarter of 1999.
Commence exploratory drilling on the Delta Centro Block in Venezuela.
Pursue aggressively opportunities to establish a West African focus area and
expand the Far East focus area.
Of the exploration interests, the most significant is the Delta Centro Block in
eastern Venezuela. BR operates this block with a 35 percent working interest.
Located in the Orinoco River Basin near the prolific Oficina Trend the 525,000
gross acre block is covered by 230 square miles of 3-D seismic and 230 miles of
2-D seismic data. As part of its work commitment, the Company will drill three
exploratory wells before the end of 2001, with an option to extend the
exploratory period for an additional four years. The most promising prospect,
Wakajara, is scheduled for drilling in 1999. During 1998, extensive
environmental evaluation was performed in preparation for drilling.
In Colombia, BR has a 14 percent non-operated working interest in 12 fields in
the Casanare Association Contract Area. During 1998, three development wells
were drilled in this area, mitigating natural production declines in these
mature fields. The Company also holds a 25 percent working interest in a 288,000
gross acre association contract located in the San Jacinto Association Contract
Area. The contract is located in the upper Magdalena Valley Basin. During 1998,
93 miles of 2-D seismic data were acquired. A decision on the initial
exploratory well is expected by mid-year 1999.
Peru Block 32 is non-operated with BR holding a 35 percent interest. Results of
the 1998 acquisition and processing of approximately 450 kilometers of 2-D
seismic have resulted in the identification of the Guineayacu prospect. Site
preparation for drilling of this exploratory well should commence by year-end
1999, with drilling anticipated in early 2000.
FAR EAST
BR holds a 15 percent working interest in the Indonesian KAKAP block, located in
the West Natuna Sea. The partners in KAKAP recently negotiated a 22 year
agreement for the sale of up to 325 MMCF of gas per day to Singapore. This
long-term sales agreement enhances the value of KAKAP reserves and production,
which historically have had limited marketability.
BR has selected the Far East as a potential focus area for value-added growth.
The Far East growth strategy targets selected basins in Indonesia, Thailand,
Malaysia, Vietnam, China, Bangladesh and Australia, primarily by acquisition.
WEST AFRICA
The fifth focus area selected by BR is West Africa, unique in being the only
focus area that has not been established around an existing acreage position.
This region was selected on the basis of its world class reserves, tremendous
upside potential, relative stability, and very active deal flow. During 1998,
the West Africa team was established, conducted initial studies of the region,
and pursued several attractive exploration and production opportunities. BR is
committed to establishing a strategic foothold within the West Africa region
that will lead to a significant value-added position in this prolific
hydrocarbon province.
[SAND DUNES AND MEN ON AIR BOAT GRAPHICS]
19
24
BURLINGTON RESOURCES 1998
Financial Review
CONTENTS
Selected Financial Data ............................... 21
Management's Discussion & Analysis of
Financial Condition and Results of Operations ...... 22
Financial Statements .................................. 26
Report of Management .................................. 44
Report of Independent Accountants ..................... 45
Supplementary Financial Information ................... 46
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BURLINGTON RESOURCES INC.
SELECTED FINANCIAL DATA
The selected financial data for Burlington Resources Inc. ("the Company")
set forth below for the five years ended December 31, 1998 should be read in
conjunction with the consolidated financial statements.
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(In Millions, Except per Share Amounts) 1998 1997 1996 1995 1994
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Income Statement Data
Revenues $ 1,637 $ 2,000 $ 2,200 $ 1,734 $ 1,871
Operating Income (Loss) 218 503 580 (397) (159)
Net Income (Loss) 86 319 335 (261) (73)
Basic Earnings (Loss) per Common Share .48 1.80 1.89 (1.47) (.41)
Diluted Earnings (Loss) per Common Share $ .48 $ 1.79 $ 1.88 $ (1.47) $ (.41)
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Balance Sheet Data
Total Assets $ 5,917 $ 5,821 $ 5,683 $ 5,608 $ 6,285
Long-term Debt 1,938 1,748 1,853 2,042 2,049
Stockholders' Equity 3,018 3,016 2,808 2,591 2,920
Cash Dividends Declared per Common Share $ .55 $ .46 $ .44 $ .44 $ .58
Common Shares Outstanding 177 177 177 178 177
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND LIQUIDITY
The Company's long-term debt to capital ratio at December 31, 1998 and
1997 was 39 percent and 37 percent, respectively.
The Company's credit facilities are comprised of a $600 million revolving
credit agreement that expires in February 2003 and a $400 million revolving
credit agreement that expires in February 2000. The $400 million revolving
credit agreement is renewable annually by mutual consent. As of December 31,
1998, there were no borrowings outstanding under the credit facilities. At
December 31, 1998, the Company had outstanding commercial paper borrowings of
$190 million at an average interest rate of 6 percent. The Company also has the
capacity to issue $1 billion of securities under a shelf registration statement
filed with the Securities and Exchange Commission.
The Company has a total of $640 million of debt to be repaid in 1999. Of
this amount, $450 million represents fixed-rate debt which the Company intends
to refinance with other fixed-rate long-term debt in 1999. The remaining $190
million represents commercial paper.
In July 1998, the Company's Board of Directors approved the repurchase of
up to two million shares of its Common Stock. During 1998, the Company
repurchased 435,000 shares of its Common Stock for $15 million. Since December
1988, the Company has repurchased approximately 32 million shares. In
conjunction with the Company's stock repurchase program, the Company sold put
options ("options") during 1998. The options entitled the holders, upon exercise
on the expiration dates, to sell shares of BR Common Stock to the Company at
specified prices. Alternatively, the Company retained the ability to settle the
options in cash. During 1998, the Company sold 400,000 options with an average
strike price of $37.25 per share and received an average premium of $2.67 per
option. During 1998, 110,000 options were exercised, 25,000 expired and 265,000
remained outstanding at December 31, 1998 with expiration dates through March of
1999.
Net cash provided by operating activities for 1998 was $770 million
compared to $1,122 million and $995 million in 1997 and 1996, respectively. The
decrease in 1998 compared to 1997 was primarily due to lower operating income
and working capital changes. The increase in 1997 compared to 1996 was primarily
due to significantly higher operating income and working capital changes.
In June 1997, the Company completed its divestiture program of
non-strategic assets which was announced in July 1996. As planned, the Company
sold approximately 27,000 wells and related facilities. Before closing
adjustments, gross proceeds for 1997 from the sales of oil and gas properties
related to this divestiture program were approximately $450 million.
On July 31, 1996, the Company completed the sale of its crude oil
refinery and terminal, including crude oil and refined product inventories, for
approximately $70 million. The net book value of refinery property, plant and
equipment and inventory at that date was approximately $68 million.
The Company and its subsidiaries are named defendants in numerous
lawsuits and named parties in numerous governmental and other proceedings
arising in the ordinary course of business. While the outcome of lawsuits and
other proceedings cannot be predicted with certainty, management believes these
matters will not have a material adverse effect on the consolidated financial
position of the Company, although results of operations and cash flows could be
significantly impacted in the reporting periods in which such matters are
resolved.
The Company has certain other commitments and uncertainties related to
its normal operations. Management believes that there are no other commitments,
uncertainties or contingent liabilities that will have a material adverse effect
on the consolidated financial position, results of operations or cash flows of
the Company.
CAPITAL EXPENDITURES AND RESOURCES
Capital expenditures during 1998 totaled $1,165 million compared to
$1,245 million and $804 million in 1997 and 1996, respectively. The Company
invested $1,030 million on internal development and exploration during 1998
compared to $941 million and $646 million in 1997 and 1996, respectively. The
Company invested $27 million for proved property acquisitions in 1998 compared
to $214 million and $92 million in 1997 and 1996, respectively.
Capital expenditures for 1999, excluding proved property acquisitions,
are projected to be approximately $750 million. Capital expenditures are
expected to be primarily for internal development and exploration of oil and gas
properties and plant and pipeline expenditures. Capital expenditures will be
funded from internal cash flows, supplemented, if needed, by external financing.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
MARKETING
Domestic
In pursuit of its mission to build long-term shareholder value, the
Company's marketing strategy is to maximize the value of its production by
developing marketing flexibility from the wellhead to its ultimate sale. The
Company's gas production is gathered, processed, exchanged and transported
utilizing various firm and interruptible contracts and routes to access the
highest value market hubs. The Company's customers include local distribution
companies, electric utilities and a diverse portfolio of industrial users. The
Company maintains the capacity to ensure its production can be marketed either
at the wellhead or downstream at market sensitive prices.
All of the Company's crude oil production is sold to third parties at the
wellhead or transported to market hubs where it is sold or exchanged. NGLs are
typically transported to market hubs, primarily in the Houston area, and sold to
third parties.
International
The Company's international oil and gas is produced from non-operated
properties. These products are sold to third parties either directly by the
Company or by the operators of the properties.
Commodity Pricing and Demand
Substantially all of the Company's crude oil and natural gas production
is sold on the spot market or under short-term contracts at market sensitive
prices. Spot market prices for domestic crude oil and natural gas are subject to
volatile trading patterns in the commodity futures markets, including among
others, the New York Mercantile Exchange ("NYMEX"). Crude oil prices are also
affected by quality differentials, by worldwide political developments and by
the actions of the Organization of Petroleum Exporting Countries.
There is also a difference between the NYMEX futures contract price for a
particular month and the actual cash price received for that month in a U.S.
producing basin or at a U.S market hub, which is referred to as the "basis
differential."
In the ordinary course and conduct of its business, the Company utilizes
futures contracts traded on the NYMEX and the Kansas City Board of Trade, and
over-the-counter price and basis swaps and options with major crude oil and
natural gas merchants and financial institutions to hedge its price risk
exposure related to the Company's U.S. production. The gains and losses realized
as a result of these derivative transactions are substantially offset in the
cash market when the hedged commodity is delivered. In order to accommodate the
needs of its customers, the Company also uses price swaps to convert gas sold
under fixed price contracts to market prices.
The Company uses a sensitivity analysis technique to evaluate the
hypothetical effect that changes in the market value of crude oil and natural
gas may have on the fair value of the Company's derivative instruments. At
December 31, 1998, the potential decrease in fair value of commodity derivative
instruments assuming a 10 percent adverse movement in the underlying commodities
would result in an 89 percent decrease in the net deferred amount.
For purposes of calculating the hypothetical change in fair value, the
relevant variables are the type of commodity (crude oil or natural gas), the
commodity futures prices, the volatility of commodity prices and the basis and
quality differentials. The hypothetical change in fair value is calculated by
multiplying the difference between the hypothetical price (adjusted for any
basis or quality differentials) and the contractual price by the contractual
volumes.
DIVIDENDS
On January 13, 1999, the Board of Directors declared a common stock
quarterly cash dividend of $.1375 per share, payable April 1, 1999 to
shareholders of record on March 12, 1999. Dividend levels are determined by the
Board of Directors based on profitability, capital expenditures, financing and
other factors. The Company declared cash dividends on Common Stock totaling
approximately $98 million during 1998.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Year Ended December 31, 1998 Compared With Year Ended December 31, 1997
The Company reported net income of $86 million or $.48 basic earnings per
common share in 1998 compared to $319 million or $1.80 basic earnings per common
share in 1997. The 1997 results included a $.40 per share charge related to the
1997 merger with The Louisiana Land and Exploration Company ("LL&E") for
severance and related exit costs and transaction costs. The 1997 results also
included an $.18 per share gain related to the sales of oil and gas properties.
Revenues were $1,637 million in 1998 compared to $2,000 million in 1997.
Average oil prices decreased 31 percent to $13.28 per barrel in 1998 and average
gas prices decreased 10 percent to $1.97 per MCF which decreased revenues $180
million and $129 million, respectively. Oil sales volumes decreased 5 percent in
1998 to 82.7 MBbls per day and gas sales volumes decreased 1 percent to 1,647
MMCF per day which decreased revenues $31 million and $18 million, respectively.
Oil and gas sales volumes decreased primarily due to natural production declines
in certain areas, adverse weather conditions and third-party plant outages.
Costs and Expenses were $1,419 million in 1998 compared to $1,497 million
in 1997. Costs and expenses in 1997 included an $80 million charge related to
the 1997 merger with LL&E for severance and related exit costs and transaction
costs. Excluding the $80 million charge in 1997, costs and expenses in 1998
increased $2 million compared to 1997. The increase was primarily due to a $39
million increase in exploration costs and a $4 million increase in production
and processing expenses. These increases were partially offset by a $19 million
decrease in production taxes, a $15 million decrease in administrative expenses
and a $7 million decrease in depreciation, depletion and amortization expenses.
Administrative expenses decreased primarily due to a reduction in employees.
Interest Expense was $148 million in 1998 compared to $142 million in
1997. The increase was primarily due to higher outstanding commercial paper
balances during 1998.
Other Income-Net was $25 million in 1998 compared to $50 million in 1997.
The decrease in other income is primarily related to lower gains on sales of oil
and gas properties.
The effective income tax rate was an expense of 9 percent in 1998
compared to an expense of 23 percent in 1997. The decreased tax expense in 1998
versus 1997 was primarily a result of lower pretax income partially offset by
lower benefits from nonconventional fuel tax credits.
Year Ended December 31, 1997 Compared With Year Ended December 31, 1996
The Company reported net income of $319 million or $1.80 basic earnings
per common share in 1997 compared to net income of $335 million or $1.89 basic
earnings per common share in 1996. The 1997 results included a $.40 per share
charge related to the merger with LL&E for severance and related exit costs and
transaction costs. The 1997 results also included an $.18 per share gain related
to the sales of oil and gas properties. The 1996 results included an $.11 per
share charge related to the divestiture program and reorganization for severance
and other related exit costs.
Revenues were $2,000 million in 1997 compared to $2,200 million in 1996.
Revenues decreased $264 million as a result of the sale of the refinery on July
31, 1996. Average oil prices decreased 6 percent to $19.24 per barrel and oil
sales volumes decreased 4 percent to 87.2 MBbls per day which decreased revenues
$37 million and $31 million, respectively. These decreases were partially offset
by an average gas price increase of 6 percent to $2.18 per MCF and an increase
in gas sales volumes of 4 percent to 1,669 MMCF per day which increased revenues
$82 million and $46 million, respectively. Gas volumes increased due to
continued development of gas properties. Oil volumes were down primarily due to
the divestiture program.
Costs and Expenses were $1,497 million in 1997 compared to $1,620 million
in 1996. Costs and expenses in 1997 included an $80 million charge related to
the merger with LL&E for severance and related exit costs and transaction costs.
Costs and expenses in 1996 included $30 million related to the divestiture
program and reorganization. Excluding the $80 million charge in 1997 and the $30
million charge in 1996, costs and expenses in 1997 decreased $173 million from
1996. The decrease was primarily due to a $254 million decrease in refinery
costs resulting from the sale of the refinery and a $27 million decrease in
production and processing expenses. These decreases were partially offset by a
$100 million increase in exploration costs, a $5 million increase in
depreciation, depletion and amortization and a $4 million increase in production
taxes.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Interest Expense was $142 million in 1997 compared to $147 million in
1996. The decrease was primarily due to lower outstanding commercial paper
balances during 1997.
Other Income -- Net was $50 million in 1997 due to a gain related to the
sales of oil and gas properties associated with the Company's 1996 divestiture
program.
OTHER MATTERS
Year 2000 Compliance
The Company began a program during 1996 to assess computer software and
hardware (hereafter referred to as information technology) for year 2000
compliance. The Company determined that because significant portions of
information technology were scheduled for replacement before the year 2000 that
its exposure with respect to information technology was not material.
The Company's year 2000 project plan involves four phases; assessment,
remediation, testing, and implementation. The Company has completed its
assessment of all material systems that could be affected by the year 2000
issue. The assessment confirmed that information technology exposures were not
material, however, assets used in producing, gathering and transporting
hydrocarbons (hereafter referred to as operating equipment) are at risk.
For its operating equipment, the Company has completed 85 percent of the
remediation phase for all operationally significant equipment and expects to
complete testing and implementation in the second quarter of 1999.
The total cost of the year 2000 project is being funded through operating
cash flows and is estimated at $3 million of which $2 million has been incurred.
The Company has contacted all third-party vendors and suppliers of
products and services that it considers critical to its operations in order to
ascertain their level of year 2000 readiness. The Company has no means of
ensuring that all customers and suppliers will be year 2000 compliant. The
inability of these parties to complete their year 2000 resolution process could
materially impact the Company. As a result, the Company will consider new
business relationships with alternate providers of products and services as
necessary and to the extent alternatives are available.
The Company's plan to complete the year 2000 modifications is based on
management's best estimates, which were derived utilizing numerous assumptions
of future events including the continued availability of certain resources and
other factors. However, there can be no guarantee that these estimates will be
achieved and actual results could differ materially from those plans. Specific
factors that might cause such material differences include, but are not limited
to, the availability and cost of personnel trained in this area, the ability to
locate and correct all relevant computer codes and similar uncertainties.
The Company's goal is to ensure that all critical systems and processes
under its direct control remain operational. However, because certain systems
and processes may be linked with systems outside of the Company's control, there
can be no assurance that all implementations will be successful. As a result,
the Company is developing a contingency plan, which will be complete at the end
of the first quarter 1999, to respond to any failures that may occur. The cost
estimates associated with the contingency plan are currently being developed.
Management does not expect the costs of the Company's year 2000 project to have
a material adverse effect on the Company's financial position or results of
operations. Presently, based on information available, the Company cannot
conclude that any failure of the Company or third parties to achieve year 2000
compliance will not adversely effect the Company.
Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative
Instruments and Hedging Activities, which is effective for fiscal years
beginning after June 15, 1999.
SFAS No. 133 establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. It also requires that an entity
recognize all derivatives as either assets or liabilities in the balance sheet
and measure those items at fair value. If certain conditions are met, a
derivative may be specifically designated as (a) a hedge of the exposure to
changes in the fair value of a recognized asset or liability or an unrecognized
firm commitment, (b) a hedge of the exposure to variable cash flows of a
forecasted transaction or (c) a hedge of the foreign currency exposure of a net
investment in a foreign operation, an unrecognized firm commitment, an
available-for-sale security, or a foreign-currency-denominated forecasted
transaction. The Company plans to adopt SFAS No. 133 during the first quarter of
the year ended December 31, 2000 and is currently evaluating the effects of this
pronouncement.
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BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF INCOME
Year Ended December 31,
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(In Millions, Except per Share Amounts) 1998 1997 1996
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REVENUES $1,637 $2,000 $2,200
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COSTS AND EXPENSES
Production Taxes 95 114 110
Production and Processing 383 379 406
Refinery Costs -- -- 254
Depreciation, Depletion and Amortization 519 526 521
Exploration Costs 298 259 159
Reorganization Charge -- -- 30
Merger Costs -- 80 --
Administrative 124 139 140
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Total Costs and Expenses 1,419 1,497 1,620
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Operating Income 218 503 580
Interest Expense 148 142 147
Other Income -- Net 25 50 --
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Income Before Income Taxes 95 411 433
Income Tax Expense 9 92 98
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NET INCOME $ 86 $ 319 $ 335
==================================================================================
BASIC EARNINGS PER COMMON SHARE $ .48 $ 1.80 $ 1.89
==================================================================================
DILUTED EARNINGS PER COMMON SHARE $ .48 $ 1.79 $ 1.88
==================================================================================
See accompanying Notes to Consolidated Financial Statements.
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BURLINGTON RESOURCES INC.
CONSOLIDATED BALANCE SHEET
December 31,
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(In Millions, Except Share Data) 1998 1997
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ASSETS
Current Assets
Cash and Cash Equivalents $ -- $ 152
Short-term Investments -- 83
Accounts Receivable 402 376
Inventories 33 39
Other Current Assets 21 28
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456 678
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Oil and Gas Properties (Successful Efforts Method) 9,348 8,666
Other Properties 828 689
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10,176 9,355
Accumulated Depreciation, Depletion and Amortization 4,818 4,315
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Properties -- Net 5,358 5,040
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Other Assets 103 103
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Total Assets $ 5,917 $ 5,821
=====================================================================================================================
LIABILITIES
Current Liabilities
Accounts Payable $ 374 $ 396
Taxes Payable 53 71
Accrued Interest 26 28
Dividends Payable 24 24
Deferred Revenue 17 19
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494 538
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Long-term Debt 1,938 1,748
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Deferred Income Taxes 199 203
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Deferred Revenue 40 56
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Other Liabilities and Deferred Credits 217 260
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Put Options on Common Stock 11 --
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Commitments and Contingent Liabilities
STOCKHOLDERS' EQUITY
Preferred Stock, Par Value $.01 Per Share
(Authorized 75,000,000 Shares; No Shares Issued) -- --
Common Stock, Par Value $.01 Per Share
(Authorized 325,000,000 Shares; Issued 202,795,635 Shares) 2 2
Paid-in Capital 2,984 3,001
Retained Earnings 1,039 1,051
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4,025 4,054
Cost of Treasury Stock (25,420,562 and 26,087,134 Shares for 1998 and 1997, respectively) 1,007 1,038
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Stockholders' Equity 3,018 3,016
=====================================================================================================================
Total Liabilities and Stockholders' Equity $ 5,917 $ 5,821
=====================================================================================================================
See accompanying Notes to Consolidated Financial Statements.
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BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
Year Ended December 31,
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(In Millions) 1998 1997 1996
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CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 86 $ 319 $ 335
Adjustments to Reconcile Net Income to Net Cash
Provided By Operating Activities
Depreciation, Depletion and Amortization 534 538 534
Deferred Income Taxes (4) 36 32
Exploration Costs 298 259 159
Gain on Sales of Oil and Gas Properties (13) (50) --
Working Capital Changes
Accounts Receivable (26) 108 (135)
Inventories 6 (4) 39
Other Current Assets 7 -- 1
Accounts Payable (22) 47 (57)
Taxes Payable (18) (3) 11
Accrued Interest (2) -- 2
Other Current Liabilities (2) (22) 37
Other (74) (106) 37
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Net Cash Provided By Operating Activities 770 1,122 995
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CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Properties (1,165) (1,245) (804)
Short-term Investments 83 (83) --
Proceeds from Sales and Other 55 494 193
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Net Cash Used In Investing Activities (1,027) (834) (611)
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CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from Long-term Debt 190 -- 150
Reduction in Long-term Debt -- (105) (337)
Dividends Paid (97) (74) (77)
Common Stock Purchases (15) (58) (112)
Other 27 24 38
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Net Cash Provided By (Used In) Financing Activities 105 (213) (338)
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INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (152) 75 46
CASH AND CASH EQUIVALENTS
Beginning of Year 152 77 31
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End of Year $ -- $ 152 $ 77
======================================================================================================
See accompanying Notes to Consolidated Financial Statements.
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BURLINGTON RESOURCES INC.
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
Cost of
Common Paid-in Retained Treasury Stockholders'
(In Millions, Except per Share Data) Stock Capital Earnings Other Stock Equity
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1995 $ 2 $ 2,955 $ 555 $ (2) $ (919) $ 2,591
Net Income 335 335
Cash Dividends ($.44 per Share) (77) (77)
Stock Purchases (2,706,000 Shares) (112) (112)
Stock Option Activity and Other 27 2 42 71
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1996 2 2,982 813 -- (989) 2,808
Net Income 319 319
Cash Dividends ($.46 per Share) (82) (82)
Stock Purchases (1,312,500 Shares) (58) (58)
Stock Option Activity and Other 19 1 9 29
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1997 2 3,001 1,051 -- (1,038) 3,016
Net Income 86 86
Cash Dividends ($.55 per Share) (98) (98)
Stock Purchases (435,000 Shares) (15) (15)
Stock Option Activity and Other (17) 46 29
- ---------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1998 $ 2 $ 2,984 $ 1,039 $ -- $ (1,007) $ 3,018
===========================================================================================================================
See accompanying Notes to Consolidated Financial Statements.
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BURLINGTON RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION AND REPORTING
The consolidated financial statements include the accounts of
Burlington Resources Inc. ("BR") and its majority-owned subsidiaries (the
"Company"). All significant intercompany transactions have been eliminated in
consolidation. Due to the nature of financial reporting, management makes
estimates and assumptions in preparing the consolidated financial statements.
Actual results could differ from estimates. The consolidated financial
statements include certain reclassifications that were made to conform to
current presentation. Such reclassifications have no impact on net income or
stockholders' equity.
CASH AND CASH EQUIVALENTS
All short-term investments purchased with a maturity of three months or
less are considered cash equivalents. Cash equivalents are stated at cost, which
approximates market value.
SHORT-TERM INVESTMENTS
Short-term investments consist of highly-liquid debt securities with a
maturity of more than three months. The securities are available for sale and
are carried at fair value based on quoted market prices. As of December 31,
1997, the fair value of these investments approximated amortized cost.
Unrealized gains and losses, net of tax, are included as a component of
stockholders' equity until realized. Realized gains and losses are based on
specific identification of the securities sold.
INVENTORIES
Inventories of materials, supplies and products are valued at the lower
of average cost or market.
PROPERTIES
Oil and gas properties are accounted for using the successful efforts
method. Under this method, all development costs and acquisition costs of proved
properties are capitalized and amortized on a units-of-production basis over the
remaining life of proved developed reserves and proved reserves, respectively.
Costs of drilling exploratory wells are initially capitalized, but charged to
expense if and when a well is determined to be unsuccessful. In addition,
unamortized capital costs at a field level are reduced to fair value if the sum
of expected undiscounted future cash flows is less than net book value.
Costs of retired, sold or abandoned properties that constitute a part
of an amortization base are charged or credited, net of proceeds, to accumulated
depreciation, depletion and amortization. Gains or losses from the disposal of
other properties are recognized currently. Expenditures for maintenance, repairs
and minor renewals necessary to maintain properties in operating condition are
expensed as incurred. Major replacements and renewals are capitalized. Estimated
dismantlement and abandonment costs for oil and gas properties are accrued, net
of salvage value, based on a units-of-production method.
REVENUE RECOGNITION
Gas revenues are recorded on the entitlement method. Under the
entitlement method, revenue is recorded based on the Company's net interest.
FUNCTIONAL CURRENCY
International exploration and production operations are considered an
extension of the Company's operations. The assets, liabilities and operations of
international locations are therefore measured using the United States dollar as
the functional currency. Foreign currency transaction adjustments, which are not
material, are included in net income.
HEDGING AND RELATED ACTIVITIES
In order to mitigate the risk of market price fluctuations, the Company
utilizes options and swaps to hedge future crude oil and natural gas production.
Changes in the market value of these contracts are deferred until the gain or
loss is recognized on the hedged commodity. To qualify as a hedge, these
transactions must be designated as a hedge and changes in their fair value must
correlate with changes in the price of anticipated future production such that
the Company's exposure to the effects of commodity price changes is reduced. The
Company also enters into swap agreements to convert fixed price gas sales
contracts to market-sensitive contracts. Gains or losses resulting from these
transactions are included in revenue as the related physical production is
delivered.
These instruments are measured for effectiveness on an enterprise basis
both at the inception of the contract and on an ongoing basis. If these
instruments are terminated prior to maturity, resulting gains or losses continue
to be deferred until the hedged item is recognized in income.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Treasury lock agreements are used to hedge interest rate exposure on
specific anticipated debt issuances of the Company. Accordingly, the
differential paid or received by the Company on maturity of a treasury lock
agreement is recognized as an adjustment to interest expense over the term of
the underlying financing transaction.
CREDIT AND MARKET RISKS
The Company manages and controls market and counterparty credit risk
through established formal internal control procedures which are reviewed on an
ongoing basis. The Company attempts to minimize credit risk exposure to
counterparties through formal credit policies, monitoring procedures and through
establishment of valuation reserves related to counterparty credit risk. In the
normal course of business, collateral is not required for financial instruments
with credit risk.
INCOME TAXES
Income taxes are provided based on earnings reported for tax return
purposes in addition to a provision for deferred income taxes. Deferred income
taxes are provided to reflect the tax consequences in future years of
differences between the financial statement and tax basis of assets and
liabilities. Tax credits are accounted for under the flow-through method, which
reduces the provision for income taxes in the year the tax credits are earned. A
valuation allowance is established to reduce deferred tax assets if it is more
likely than not that the related tax benefits will not be realized.
STOCK-BASED COMPENSATION
The Company uses the intrinsic value based method of accounting for
stock-based compensation. Under this method, the Company records no compensation
expense for stock options granted when the exercise price for options granted is
equal to the fair market value of the Company's stock on the date of the grant.
EARNINGS PER COMMON SHARE
Basic earnings per common share ("EPS") is computed by dividing income
available to common stockholders by the weighted-average number of common shares
outstanding for the period. The weighted average number of common shares
outstanding for computing basic EPS was 177 million for the years ended December
31, 1998, 1997 and 1996. Diluted EPS reflects the potential dilution that could
occur if securities or other contracts to issue common stock were exercised or
converted into common stock. The weighted average number of common shares
outstanding for computing diluted EPS, including dilutive stock options, was 178
million for the years ended December 31, 1998, 1997 and 1996. For the years
ended December 31, 1998, 1997 and 1996, approximately 4 million, 600 thousand
and 3 million shares, respectively, attributable to the exercise of outstanding
options were excluded from the calculation of diluted EPS because the effect was
antidilutive. No adjustments were made to reported net income in the computation
of EPS.
2. MERGER
On July 17, 1997, BR and The Louisiana Land and Exploration Company
("LL&E")announced that they had entered into an Agreement and Plan of Merger
(the "Merger"). On October 22, 1997, the Merger was completed and LL&E became a
wholly-owned subsidiary of the Company. Pursuant to the Merger, BR issued
52,795,635 shares of its Common Stock based on an exchange ratio of 1.525 for
each outstanding share of LL&E stock. The Merger was accounted for as a pooling
of interests and qualified as a tax-free reorganization. The transaction was
valued at approximately $3 billion based on BR's closing stock price on October
22, 1997. During the fourth quarter of 1997, the Company recorded a pretax
charge of $80 million ($71 million after tax) for direct costs associated with
the Merger. These costs primarily consist of $44 million for severance and
related exit costs and $36 million for direct transaction costs. Approximately
$2 million of accrued unpaid costs remained on the consolidated balance sheet as
of December 31, 1998.
3. INCOME TAXES
The jurisdictional components of income before income taxes follow.
Year Ended December 31,
- -----------------------------------------------
(In Millions) 1998 1997 1996
- -----------------------------------------------
Domestic $139 $369 $400
Foreign (44) 42 33
- -----------------------------------------------
Total $ 95 $411 $433
===============================================
31
36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The provision for income taxes follows.
Year Ended December 31,
- ------------------------------------------------
(In Millions) 1998 1997 1996
- ------------------------------------------------
Current
Federal $ 10 $ 44 $ 53
State 5 2 11
Foreign (2) 10 2
- ------------------------------------------------
13 56 66
- ------------------------------------------------
Deferred
Federal 8 30 18
State 1 11 9
Foreign (13) (5) 5
- ------------------------------------------------
(4) 36 32
- ------------------------------------------------
Total $ 9 $ 92 $ 98
================================================
Reconciliation of the federal statutory income tax rate to the effective income
tax rate follows.
Year Ended December 31,
- ----------------------------------------------------------------------
1998 1997 1996
- ----------------------------------------------------------------------
Statutory rate 35.0% 35.0% 35.0%
State income taxes 4.1 2.1 3.0
Taxes on foreign income
in excess of statutory rate .6 2.1 .2
Tax credits (33.4) (18.5) (15.0)
Merger costs -- 4.6 --
Other 3.1 (2.8) (.7)
- ----------------------------------------------------------------------
Effective rate 9.4% 22.5% 22.5%
======================================================================
Deferred income tax liabilities (assets) follow.
December 31,
- ------------------------------------------------------------------------
(In Millions) 1998 1997
- ------------------------------------------------------------------------
Deferred income tax liabilities
Excess of book over tax basis of properties $ 514 $ 548
Deferred income tax assets
AMT credit carryforward (264) (255)
Deferred foreign tax credits (71) (66)
Net operating loss carryforward (3) (4)
Foreign tax credit carryforward (2) (2)
Financial accruals and other (10) (51)
- ------------------------------------------------------------------------
(350) $(378)
- ------------------------------------------------------------------------
Less valuation allowance 35 33
- ------------------------------------------------------------------------
Net deferred income tax liabilities $ 199 $ 203
========================================================================
32
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The above net deferred tax liabilities, as of December 31, 1998 and
1997, include deferred state income tax liabilities of approximately $39 million
for both years.
The Alternative Minimum Tax ("AMT") credit carryforward, related
primarily to nonconventional fuel tax credits, is available to offset future
federal income tax liabilities. The AMT credit carryforward has no expiration.
The benefit of these tax credits is recognized in net income for accounting
purposes and is reflected in the current tax provision to the extent the Company
is able to utilize the credits for tax return purposes.
The foreign tax credit carryforward is available through the year 2003
to offset future federal income taxes. The federal income tax net operating loss
carryforward is available through the year 2009 to offset future federal taxable
income, subject to the separate return limitation provisions of the federal
income tax regulations.
A valuation allowance is provided for uncertainties surrounding the
realization of certain foreign tax credit carryforwards and certain deferred
foreign tax credits.
4. COMMODITY HEDGING ACTIVITIES
Gas Swaps
The Company enters into gas swap agreements to fix the price of
anticipated future natural gas production. As of December 31, 1998, the Company
has the following volumes hedged.
Total Hedged Average
Production Volume Hedge/Strike Deferred Gain
Period (MMBTU) Price (In Millions)
- -----------------------------------------------------------
1999 168,650,000 $2.39 $ 68
2000 201,300,000 2.33 26
2001 77,565,000 $2.36 $ 7
Gas Basis Swaps
The Company enters into gas basis swap agreements to fix a component of
the sales price of anticipated future natural gas production. This component is
expressed as the differential between a location and Henry Hub. These
transactions are accounted for as hedges of the Company's underlying production.
As of December 31, 1998, the Company had 40 million MMBTU of 1999 natural gas
production hedged at a fixed differential of approximately $.28 per MMBTU. The
deferred loss on these transactions as of December 31, 1998 is approximately $2
million.
Options Contracts
The Company enters into put option agreements to set a floor price on
anticipated future natural gas production while allowing the Company to
participate in market price increases that exceed those floor prices. These
transactions are accounted for as hedges of the Company's underlying production.
As of December 31, 1998, the Company has 34 million MMBTU of 1999 natural gas
production hedged at a floor price of $1.80 per MMBTU. The deferred gain on
these transactions as of December 31, 1998 is approximately $1 million.
5. LONG-TERM DEBT
Long-term debt follows.
December 31,
- ---------------------------------------------------------
(In Millions) 1998 1997
- ---------------------------------------------------------
Commercial Paper $ 190 $ --
Notes, 7.15%, due 1999 300 300
Notes, 6 7/8%, due 1999 150 150
Notes, 9 5/8%, due 2000 150 150
Notes, 8 1/2%, due 2001 150 150
Notes, 8 1/4%, due 2002 100 100
Debentures, 9 7/8%, due 2010 150 150
Debentures, 7 5/8%, due 2013 100 100
Debentures, 9 1/8%, due 2021 150 150
Debentures, 7.65%, due 2023 200 200
Debentures, 8.20%, due 2025 150 150
Debentures, 6 7/8%, due 2026 150 150
Other, including discounts -- net (2) (2)
- ---------------------------------------------------------
Total $1,938 $1,748
=========================================================
33
38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Company had fixed-rate debt maturities of $450 million, $150
million, $150 million, $100 million, $0 and $1,090 million due in 1999, 2000,
2001, 2002, 2003 and thereafter, respectively. The Company's commercial paper
borrowings at December 31, 1998 had an average interest rate of 6 percent.
The Company's credit facilities are comprised of a $600 million
revolving credit agreement that expires in February 2003 and a $400 million
revolving credit agreement that expires in February 2000. The $400 million
revolving credit agreement is renewable annually by mutual consent. Annual fees
are .08 and .12 percent, respectively, of the $600 million and $400 million
commitments. At the Company's option, interest on borrowings is based on the
Prime rate or Eurodollar rates. The unused commitment under these agreements is
available to cover debt due within one year; therefore, commercial paper and
fixed-rate debt due within one year are classified as long-term debt. Under the
covenants of these agreements, debt cannot exceed 60 percent of capitalization
(as defined in the agreements). As of December 31, 1998, there were no
borrowings outstanding under these credit facilities. In addition, the Company
has the capacity to issue $1 billion of securities under shelf registration
statements filed with the Securities and Exchange Commission.
The Company utilizes a treasury lock agreement to hedge the effect of
interest rate movements on anticipated debt transactions. At December 31, 1998,
the aggregate notional amount of the lock agreement was $128 million. At
December 31, 1998, the fair value of the agreement was an obligation of $11
million. The treasury lock agreement matures in the first quarter 1999.
6. TRANSPORTATION ARRANGEMENTS WITH EL PASO NATURAL GAS COMPANY
In 1998, 1997 and 1996, approximately 37 percent, 41 percent and 43
percent, respectively, of the Company's gas production was transported to direct
sale customers through El Paso Natural Gas Company's ("EPNG") pipeline systems.
These transportation arrangements are pursuant to EPNG's approved Federal Energy
Regulatory Commission tariffs applicable to all shippers. The Company expects to
continue to transport a substantial portion of its future gas production through
EPNG's pipeline system. See Note 9 for demand charges paid to EPNG which provide
the Company with firm and interruptible transportation capacity rights on
interstate and intrastate pipeline systems.
34
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. CAPITAL STOCK
STOCK OPTIONS
The Company's 1993 Stock Incentive Plan (the "1993 Plan") succeeds its
1988 Stock Option Plan which expired by its terms in May 1993 but remains in
effect for options granted prior to May 1993. The 1993 Plan provides for the
grant of stock options, restricted stock, stock purchase rights and stock
appreciation rights or limited stock appreciation rights (together "SARs").
Under the 1993 Plan, options may be granted to officers and key
employees at fair market value on the date of grant, exercisable in whole or
part by the optionee after completion of at least one year of continuous
employment from the grant date and have a term of ten years. At December 31,
1998, 6,049,276 shares were available for grant under the 1993 Plan.
In 1997, the Company adopted the 1997 Employee Stock Incentive Plan
(the "1997 Plan") from which stock options and restricted stock ("Awards") may
be granted to employees who are not eligible to participate in the 1993 Plan.
The options are granted at fair market value on the grant date, become
exercisable in whole or part by the optionee after completion of at least one
year of continuous employment and have a term of ten years. The 1997 Plan limits
Awards, in aggregate, to a maximum of one million shares annually.
Activity in the Company's stock option plans follows.
Weighted Average
Options Exercise Price
- -----------------------------------------------------------------------------------------------
Balance, December 31, 1995 6,283,659 $29.07
Granted 2,896,483 47.35
Exercised (2,288,458) 26.91
Cancelled (105,615) 34.74
- -----------------------------------------------------------------------------------------------
Balance, December 31, 1996 6,786,069 37.51
Granted 2,253,627 40.99
Exercised (886,009) 27.09
Cancelled (210,613) 47.82
- -----------------------------------------------------------------------------------------------
Balance, December 31, 1997 7,943,074 39.39
Granted 276,200 43.43
Exercised (1,060,365) 26.11
Cancelled (758,460) 47.35
- -----------------------------------------------------------------------------------------------
Balance, December 31, 1998 6,400,449 $40.82
===============================================================================================
The following table summarizes information related to stock options outstanding
and exercisable at December 31, 1998.
Weighted Average
Options Range of Weighted Average Remaining Options Weighted Average
Outstanding Exercise Prices Exercise Price Contractual Life Exercisable Exercise Price
- ---------------------------------------------------------------------------------------------------------------------------------
2,267,554 $19.51 to $38.00 $30.36 5.1 years 2,090,366 $30.10
4,132,895 39.63 to 52.03 46.55 7.8 years 2,430,599 46.16
- ---------------------------------------------------------------------------------------------------------------------------------
6,400,449 $19.51 to $52.03 $40.82 6.9 years 4,520,965 $38.74
=================================================================================================================================
Exercisable stock options and weighted average exercise prices at December 31,
1997 and 1996 follow.
Weighted Average
Options Exercisable Exercise Price
- -------------------------------------------------------------
December 31, 1997 3,917,331 $33.93
=============================================================
December 31, 1996 3,593,423 $30.79
=============================================================
35
40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The weighted average fair values of options granted during the years
1998, 1997 and 1996 were $11.32, $10.45 and $12.45, respectively. The fair
values of employee stock options were calculated using a variation of the
Black-Scholes stock option valuation model with the following weighted average
assumptions for grants in 1998, 1997 and 1996: stock price volatility of 24.18
percent, 18.35 percent and 18.62 percent, respectively; risk free rate of return
ranging from 4.66 percent to 6.00 percent; dividend yield of 1.36 percent, 1.07
percent and 1 percent, respectively; and an expected term of 5 years. If the
fair value based method of accounting had been applied, the Company's net income
and EPS would have been reduced to the pro forma amounts indicated below. The
fair value of stock options included in the pro forma amounts is not necessarily
indicative of future effects on net income and EPS.
Year Ended December 31,
- -------------------------------------------------------------------
(In Millions, Except per share Amounts) 1998 1997 1996
- -------------------------------------------------------------------
Net income -- as reported $ 86 $ 319 $ 335
Net income -- pro forma 74 308 329
Basic EPS -- as reported .48 1.80 1.89
Basic EPS -- pro forma .42 1.74 1.86
Diluted EPS -- as reported .48 1.79 1.88
Diluted EPS -- pro forma $.42 $1.73 $1.85
STOCK APPRECIATION RIGHTS
The Company has granted SARs in connection with certain outstanding
options under the 1988 Stock Option Plan. SARs are subject to the same terms and
conditions as the related options. A SAR entitles an option holder, in lieu of
exercise of an option, to receive a cash payment equal to the difference between
the option price and the fair market value of the Company's Common Stock based
upon the plan provisions. To the extent the SAR is exercised, the related option
is cancelled and to the extent the option is exercised, the related SAR is
cancelled. The outstanding SARs are exercisable only under certain circumstances
related to significant changes in the ownership of the Company or its holdings,
or certain changes in the constitution of its Board of Directors. At December
31, 1998, there were 74,276 SARs outstanding related to stock options with a
weighted average exercise price of $34.21 per share.
PREFERRED STOCK AND PREFERRED STOCK PURCHASE RIGHTS
The Company is authorized to issue 75,000,000 shares of preferred
stock, par value $.01 per share, and as of December 31, 1998, there were no
shares issued. On December 9, 1998, the Company's Board of Directors designated
3,250,000 of the authorized preferred shares as Series A Junior Participating
Preferred Stock. Upon issuance, each one-hundredth of a share of Series A Junior
Participating Preferred Stock will have dividend and voting rights approximately
equal to those of one share of Common Stock of the Company. In addition, on
December 9, 1998, the Board of Directors declared a dividend distribution of one
Right for each outstanding share of Common Stock of the Company to shareholders
of record on December 16, 1998. The Rights become exercisable if, without the
Company's prior consent, a person or group acquires securities having 15 percent
or more of the voting power of all of the Company's voting securities (an
"Acquiring Person") or ten days following the announcement of a tender offer
which would result in such ownership. Each Right, when exercisable, entitles the
registered holder to purchase from the Company one-hundredth of a share of
Series A Junior Participating Preferred Stock at a price of $200 per one
hundredth of a share, subject to adjustment. If, after the Rights become
exercisable, the Company were to be involved in a merger or other business
combination in which its Common Stock was exchanged or changed or 50% or more of
the Company's assets or earning power were sold, each Right would permit the
holder to purchase, for the exercise price, stock of the acquiring company
having a value of twice the exercise price. In addition, except for certain
permitted offers, if any person or group becomes an Acquiring Person, each Right
would permit the purchase, for the exercise price, of Common Stock of the
Company having a value of twice the exercise price. Rights owned by an Acquiring
Person are void. The Rights may be redeemed by the Company under certain
circumstances until their expiration date for $.01 per Right.
36
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. RETIREMENT BENEFITS
The Company's pension plans are non-contributory defined benefit plans
covering substantially all employees. The benefits are based on years of
credited service and final average compensation. Contributions to the plans are
limited to amounts that are currently deductible for tax purposes. Contributions
are intended to provide not only for benefits attributed to service to date but
also for those expected to be earned in the future.
The Company has postretirement medical and dental care plans for a closed
group of retirees and their dependents and certain employees. The postretirement
benefit plans are unfunded and the Company funds claims on a cash basis. The
Company also maintains a Medicare Part B reimbursement plan and life insurance
coverage for a closed group of retirees.
The following tables set forth the amounts recognized in the Consolidated
Balance Sheet and Statement of Income.
Postretirement
Pension Benefits Benefits
- ---------------------------------------------------------------------------------
Year Ended December 31,
- ---------------------------------------------------------------------------------
(In Millions) 1998 1997 1998 1997
- ---------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $ 178 $ 161 $ 33 $ 31
Service cost 9 9 -- 1
Interest cost 12 12 2 3
Amendments 2 -- 1 --
Actuarial loss (gain) 8 17 (2) --
Benefits paid (27) (21) (2) (2)
- ---------------------------------------------------------------------------------
Benefit obligation at end of year 182 178 32 33
- ---------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets
at beginning of year 161 144 -- --
Actual return on plan assets 30 28 -- --
Employer contribution 8 10 2 2
Benefits paid (27) (21) (2) (2)
- ---------------------------------------------------------------------------------
Fair value of plan assets at
end of year 172 161 -- --
- ---------------------------------------------------------------------------------
Funded status (10) (17) (32) (33)
- ---------------------------------------------------------------------------------
Unrecognized net actuarial loss 16 26 1 3
Unrecognized net transition obligation 1 2 -- --
Unrecognized prior service cost 2 -- 2 --
- ---------------------------------------------------------------------------------
Net prepaid (accrued) benefit cost $ 9 $ 11 $ (29) $ (30)
=================================================================================
37
42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Postretirement
Pension Benefits Benefits
- ---------------------------------------------------------------------------------------------------------
(In Millions) Year Ended December 31,
- ---------------------------------------------------------------------------------------------------------
1998 1997 1996 1998 1997 1996
- ---------------------------------------------------------------------------------------------------------
Benefit cost for the plans includes the following
components
Service cost $ 9 $ 9 $ 9 $-- $ 1 $ 1
Interest cost 12 12 12 1 3 3
Expected return on plan assets (13) (12) (12) -- -- --
Amortization of transition obligation -- -- 2 -- -- --
Amortization of prior service cost -- 1 1 -- -- --
Recognized net actuarial loss 2 1 2 -- -- --
- ---------------------------------------------------------------------------------------------------------
Net benefit cost $ 10 $ 11 $ 14 $ 1 $ 4 $ 4
- ---------------------------------------------------------------------------------------------------------
Postretirement
Pension Benefits Benefits
- --------------------------------------------------------------------------------------------------------
December 31,
- --------------------------------------------------------------------------------------------------------
1998 1997 1998 1997
- --------------------------------------------------------------------------------------------------------
Weighted average assumptions
Discount rate 6.75% 7.25% 6.75% 7.25%
Expected return on plan assets 9.00% 9.00% -- --
Rate of compensation increase 5.00% 5.00% -- --
- --------------------------------------------------------------------------------------------------------
During 1998, the Company recognized a settlement expense of approximately
$800 thousand related to the employee reduction associated with the LL&E merger
in the fourth quarter of 1997.
A 5 percent annual rate of increase in the per capita cost of covered
health care benefits was assumed for 1998. The rate is assumed to decrease
gradually to 4 percent for 2003 and remain at that level thereafter.
Assumed health care cost trends have a significant effect on the amounts
reported for the postretirement medical and dental care plans. A one-percentage
point change in assumed health care cost trend rates would have the following
effects:
1-Percentage 1-Percentage
(In Thousands) Point Increase Point Decrease
- --------------------------------------------------------------------------------------------------------
Effect on total service and interest cost $ 152 $ (131)
Effect on postretirement benefit obligation $2,841 $(2,457)
38
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. COMMITMENTS AND CONTINGENT LIABILITIES
DEMAND CHARGES
The Company has entered into contracts which provide firm transportation
capacity rights on interstate and intrastate pipeline systems. The remaining
terms on these contracts range from 1 to 9 years and require the Company to pay
transportation demand charges regardless of the amount of pipeline capacity
utilized by the Company. The Company paid $60 million, $49 million and $61
million of demand charges of which $44 million, $34 million and $47 million was
paid to EPNG for the years ended December 31, 1998, 1997 and 1996, respectively.
Future transportation demand charge commitments at December 31, 1998
follow.
Year Ended December 31,
- ------------------------------------------------------------
(In Millions)
1999 $ 62
2000 47
2001 42
2002 41
2003 42
Thereafter 127
- ------------------------------------------------------------
Total $361
============================================================
LEASE OBLIGATIONS
The Company has operating leases for office space and other property and
equipment. The Company incurred lease rental expense of $17 million, $18 million
and $20 million for the years ended December 31, 1998, 1997 and 1996,
respectively.
Future minimum annual rental commitments at December 31, 1998 follow.
Year Ended December 31,
- ----------------------------------------------------------
(In Millions)
1999 $ 18
2000 16
2001 16
2002 16
2003 16
Thereafter 68
- ----------------------------------------------------------
Total $150
==========================================================
DRILLING RIG COMMITMENTS
During 1998, the Company entered into agreements to lease or participate in
the use of various drilling rigs. The exposure with respect to these commitments
ranges from $152 million to $280 million depending on partner participation.
These agreements extend through the year 2004.
LEGAL PROCEEDINGS
The Company is involved in several proceedings challenging the payment of
royalties for its crude oil and natural gas production.
On November 20, 1997, the Company and numerous other defendants entered
into a settlement agreement in a lawsuit styled as The McMahon Foundation, et
al. v. Amerada Hess Corporation, et al. This lawsuit is a proposed class action
consisting of both working interest owners and royalty owners against numerous
defendants, all of which are oil companies and/or purchasers of oil from oil
companies, including Burlington Resources Oil & Gas Company, formerly known as
Meridian Oil Inc. ("BROG") and LL&E. The plaintiffs allege that the defendants
conspired to fix, depress, stabilize and maintain at artificially low levels the
prices paid for oil by, among other things, setting their posted prices at
arbitrary levels below competitive market prices. Cases involving similar
allegations have been filed in federal courts in other states. On January 14,
1998, the United States Judicial Panel on Multidistrict Litigation issued an
order consolidating these cases and transferring the McMahon case to the United
States District Court for the Southern District of Texas in Corpus Christi. The
Company and other defendants have entered into a Settlement Agreement which
received preliminary approval by the Court on October 28, 1998. The Court has
set a hearing to finally determine the fairness, accuracy and reasonableness of
the Settlement Agreement beginning in April 1999.
The Company is also involved in several governmental proceedings relating
to the payment of royalties. Various administrative proceedings are pending
before the Minerals Management Service ("MMS") of the United States Department
of the Interior with respect to the proper valuation of oil and gas produced on
federal and Indian lands for purposes of paying royalties on production sold by
BROG to its affiliate, Burlington Resources Trading Inc. ("BRTI"), or gathered
by its affiliate, Burlington Resources Gathering Inc. In general, these
proceedings stem from regular MMS audits of the Company's royalty payments over
various periods of time and involve the interpretation of the relevant federal
regulations. Most of these administrative proceedings currently have been
suspended pending
39
44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
LEGAL PROCEEDINGS (CONTINUED)
negotiations between the Company and the MMS to resolve their disputes regarding
the appropriate valuation methodology or pending resolution of the federal False
Claims Act litigation as hereinafter described.
In late February 1998, the Company and numerous other oil and gas companies
received a complaint filed in the United States District Court for the Eastern
District of Texas in Lufkin in a lawsuit styled as United States of America ex
rel J. Benjamin Johnson, Jr., et al v. Shell Oil Company, et al. alleging
violations of the civil False Claims Act. The United States has intervened in
this lawsuit as to some of the defendants, including the Company, and has filed
a separate complaint. This suit alleges that the Company underpaid royalties for
crude oil produced on federal and Indian lands through the use of below-market
posted prices in the sale of oil from BROG to BRTI. The suit alleges that
royalties paid by BROG based on these posted prices were lower than the
royalties allegedly required to be paid under federal regulations, and that the
forms filed by BROG with the MMS reporting the royalties paid were false,
thereby violating the civil False Claims Act. The Company and others have also
received document subpoenas and other inquiries from the Department of Justice
relating to the payment of royalties to the federal government for natural gas
production. These requests and inquiries have been made in the context of one or
more other False Claims Act cases brought by individuals which remain under seal
and are now being investigated by the Civil Division of the Department of
Justice. The Company has responded and continues to respond to these requests
and inquiries, but the Company does not know what action, if any, the Department
of Justice will take with regard to these other cases. If the government chooses
not to intervene and pursue these cases, the individuals who initially brought
these cases are free to pursue them in return for a share, if any, of any final
settlement or judgment. In addition, the Company has been advised that it is a
target of a criminal investigation by the United States Attorney for the
District of Wyoming into the alleged underpayment of oil and gas royalties. The
Company has responded to numerous grand jury document subpoenas in connection
with an investigation and is otherwise cooperating with the investigation.
Management cannot predict when the investigation will be completed or its
ultimate outcome.
Based on the Company's present understanding of the various governmental
proceedings relating to royalty payments, described in the preceding two
paragraphs, the Company believes that it has substantial defenses to these
claims and intends to vigorously assert such defenses. However, in the event
that the Company is found to have violated the civil False Claims Act or is
indicted or convicted on criminal charges, the Company could be subjected to a
variety of sanctions, including treble damages, substantial monetary fines,
civil and/or criminal penalties and a temporary suspension from entering into
future federal mineral leases and other federal contracts for a defined period
of time. While the ultimate outcome and impact on the Company cannot be
predicted with certainty, management believes that the resolution of these
proceedings will not have a material adverse effect on the consolidated
financial position of the Company, although results of operations and cash flows
could be significantly impacted in the reporting periods in which such matters
are resolved.
In addition to the foregoing, the Company and its subsidiaries are named
defendants in numerous other lawsuits and named parties in numerous governmental
and other proceedings arising in the ordinary course of business. While the
outcome of these other lawsuits and proceedings cannot be predicted with
certainty, management believes these matters, other than the above-described
proceedings, will not have a material adverse effect on the consolidated
financial position, results of operations or cash flows of the Company.
10. DIVESTITURE PROGRAM AND REORGANIZATION
In June 1997, the Company completed its divestiture program of
non-strategic assets which was announced in July 1996. As planned, the Company
sold approximately 27,000 wells and related facilities. Before closing
adjustments, gross proceeds for 1997 from the sales of oil and gas properties
related to this divestiture program were approximately $450 million. During
1997, the Company recorded a pretax gain of approximately $50 million related to
the sales of oil and gas properties. This program allowed the Company to
reorganize and resulted in a reduction of 456 employees. As of December 31,
1997, this program was complete.
On July 31, 1996, the Company completed the sale of its crude oil refinery
and terminal, including crude oil and refined product inventories, for
approximately $70 million. The net book value of refinery property, plant and
equipment and inventory at that date was approximately $68 million.
40
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
11. DEFERRED REVENUE
In September 1996, the Company received cash proceeds of $108 million for a
transaction in which it is obligated to deliver gas through December 31, 2002.
The proceeds were recorded as deferred revenue and are being amortized into
revenues as the gas is delivered. Approximately $18 million, $20 million and $13
million of deferred revenue was recognized in 1998, 1997 and 1996, respectively.
12. RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative
Instruments and Hedging Activities, which is effective for fiscal years
beginning after June 15, 1999.
SFAS No. 133 establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It also requires that an entity recognize
all derivatives as either assets or liabilities on the balance sheet and measure
those items at fair value. If certain conditions are met, a derivative may be
specifically designated as (a) a hedge of the exposure to changes in the fair
value of a recognized asset or liability or an unrecognized firm commitment, (b)
a hedge of the exposure to variable cash flows of a forecasted transaction or
(c) a hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated forecasted transaction. The Company plans to adopt
SFAS No. 133 during the first quarter of the year ended December 31, 2000 and is
currently evaluating the effects of this pronouncement.
13. SUPPLEMENTAL CASH FLOW INFORMATION
The following is additional information concerning supplemental disclosures
of cash flow activities.
Year Ended December 31,
- --------------------------------------------------------------------
(In Millions) 1998 1997 1996
- --------------------------------------------------------------------
Interest paid $150 $149 $154
Income taxes paid-- net $ 21 $ 56 $ 60
14. SEGMENT AND GEOGRAPHIC INFORMATION
The Company's reportable segments are North America and International. Both
segments are engaged principally in the exploration, development, production and
marketing of oil and gas. The North America segment is responsible for the
Company's operations in the U.S. and Canada and the International segment is
responsible for all operations outside that geographical region. The accounting
policies for the segments are the same as those described in Note 1 to the
consolidated financial statements. There are no significant intersegment sales
or transfers.
41
46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following tables present information about reported segment operations.
Year Ended December 31, 1998
- ---------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- ---------------------------------------------------------------------------------------------------
Revenues $1,488 $149 $1,637
Depreciation, depletion and amortization 440 67 507
Operating income (loss) 391 (38) 353
Additions to oil and gas properties $ 981 $136 $1,117
Year Ended December 31, 1997
- ---------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- ---------------------------------------------------------------------------------------------------
Revenues $1,795 $205 $2,000
Depreciation, depletion and amortization 434 75 509
Operating income 686 53 739
Additions to oil and gas properties $ 977 $228 $1,205
Year Ended December 31, 1996
- ---------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- ---------------------------------------------------------------------------------------------------
Revenues $1,989 $211 $2,200
Depreciation, depletion and amortization 419 81 500
Operating income 717 54 771
Additions to oil and gas properties $ 730 $ 62 $ 792
42
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is a reconciliation of segment operating income to consolidated
income before income taxes.
Year Ended December 31,
- ---------------------------------------------------------------------------------------------------
(In Millions) 1998 1997 1996
- ---------------------------------------------------------------------------------------------------
Total operating income for reportable segments $ 353 $ 739 $771
Corporate expenses(a) 135 236 191
Interest expense 148 142 147
Other income-- net 25 50 --
- ---------------------------------------------------------------------------------------------------
Consolidated income before income taxes $ 95 $ 411 $433
===================================================================================================
(a) In 1997, corporate expenses included an $80 million charge related to the
Merger. In 1996, corporate expenses included a $30 million charge related to the
reorganization.
The following is a reconciliation of segment additions to oil and gas properties
to consolidated amounts.
Year Ended December 31,
- ----------------------------------------------------------------------------------------------------
(In Millions) 1998 1997 1996
- ----------------------------------------------------------------------------------------------------
Total additions to oil and gas properties
for reportable segments $1,117 $1,205 $792
Administrative expenditures 48 40 12
- ----------------------------------------------------------------------------------------------------
Consolidated additions to properties $1,165 $1,245 $804
====================================================================================================
43
48
REPORT OF MANAGEMENT
The management of Burlington Resources is responsible for the preparation
and integrity of all information contained in this Annual Report. The
accompanying financial statements have been prepared in conformity with
generally accepted accounting principles. The financial statements include
amounts that are management's best estimates and judgments.
BR maintains a system of internal control and a program of internal
auditing that provides management with reasonable assurance that BR's assets are
protected and that published financial statements are reliable and free of
material misstatement. Management is responsible for the effectiveness of
internal controls. This is accomplished through established codes of conduct,
accounting and other control systems, policies and procedures, employee
selection and training, appropriate delegation of authority and segregation of
responsibilities.
The Audit Committee of the Board of Directors, composed solely of directors
who are not officers or employees, meets regularly with the independent
certified public accountants, financial management, counsel and corporate audit.
To ensure complete independence, the certified public accountants and corporate
audit have full and free access to the Audit Committee to discuss the results of
their audits, the adequacy of internal controls and the quality of financial
reporting.
Our independent certified public accountants provide an objective
independent review by their audit of the Company's financial statements. Their
audit is conducted in accordance with generally accepted auditing standards and
includes a review of internal accounting controls to the extent deemed necessary
for the purposes of their audit.
/s/ John E. Hagale /s/ Philip W. Cook
------------------ ------------------
John E. Hagale Philip W. Cook
Executive Vice President and Vice President, Controller and
Chief Financial Officer Chief Accounting Officer
44
49
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders of Burlington Resources Inc.
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of income, cash flows and stockholders' equity present
fairly, in all material respects, the financial position of Burlington Resources
Inc. and its subsidiaries at December 31, 1998 and 1997, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted accounting
principles. 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 of these statements in
accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for the opinion expressed
above.
PriceWaterhouseCoopers LLP
Houston, Texas
January 20, 1999
45
50
BURLINGTON RESOURCES INC.
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTAL OIL AND GAS DISCLOSURES -- UNAUDITED
- --------------------------------------------------------------------------------
The supplemental data presented herein reflects information for all of the
Company's oil and gas producing activities. Capitalized costs for oil and gas
producing activities follow.
December 31,
- --------------------------------------------------------------------------------
(In Millions) 1998 1997
- --------------------------------------------------------------------------------
Proved properties $9,154 $8,516
Unproved properties 194 150
- --------------------------------------------------------------------------------
9,348 8,666
Accumulated depreciation, depletion and amortization 4,474 4,003
- --------------------------------------------------------------------------------
Net capitalized costs $4,874 $4,663
================================================================================
Costs incurred for oil and gas property acquisition, exploration and
development activities follow.
Year Ended December 31, 1998
- --------------------------------------------------------------------------------
(In Millions) North America International Total
- --------------------------------------------------------------------------------
Property acquisition
Unproved $ 92 $ 6 $ 98
Proved 23 4 27
Exploration 315 96 411
Development 491 30 521
- --------------------------------------------------------------------------------
Total costs incurred $921 $136 $1,057
================================================================================
Year Ended December 31, 1997
- --------------------------------------------------------------------------------
(In Millions) North America International Total
- --------------------------------------------------------------------------------
Property acquisition
Unproved $ 93 $ 5 $ 98
Proved 54 160 214
Exploration 241 48 289
Development 539 15 554
- --------------------------------------------------------------------------------
Total costs incurred $927 $228 $1,155
================================================================================
Year Ended December 31, 1996
- --------------------------------------------------------------------------------
(In Millions) North America International Total
- --------------------------------------------------------------------------------
Property acquisition
Unproved $ 48 $ 9 $ 57
Proved 92 -- 92
Exploration 134 29 163
Development 402 24 426
- --------------------------------------------------------------------------------
Total costs incurred $676 $62 $738
================================================================================
46
51
SUPPLEMENTARY FINANCIAL INFORMATION
Results of operations for oil and gas producing activities follow.
Year Ended December 31, 1998
- -------------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- -------------------------------------------------------------------------------------------------------
Revenues $1,448 $ 149 $1,597
- -------------------------------------------------------------------------------------------------------
Production costs 343 43 386
Exploration costs 239 59 298
Operating expenses 177 32 209
Depreciation, depletion and amortization 429 64 493
- -------------------------------------------------------------------------------------------------------
1,188 198 1,386
- -------------------------------------------------------------------------------------------------------
Operating income (loss) 260 (49) 211
Income tax provision (benefit) 64 (11) 53
- -------------------------------------------------------------------------------------------------------
Results of operations for oil and gas producing activities $ 196 $ (38) $ 158
=======================================================================================================
Year Ended December 31, 1997
- -------------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- -------------------------------------------------------------------------------------------------------
Revenues $1,747 $ 205 $1,952
- -------------------------------------------------------------------------------------------------------
Production costs 363 42 405
Exploration costs 234 25 259
Operating expenses 220 10 230
Depreciation, depletion and amortization 422 75 497
- -------------------------------------------------------------------------------------------------------
1,239 152 1,391
- -------------------------------------------------------------------------------------------------------
Operating income 508 53 561
Income tax provision 103 27 130
- -------------------------------------------------------------------------------------------------------
Results of operations for oil and gas producing activities $ 405 $ 26 $ 431
=======================================================================================================
Year Ended December 31, 1996
- -------------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- -------------------------------------------------------------------------------------------------------
Revenues $1,682 $ 211 $1,893
- -------------------------------------------------------------------------------------------------------
Production costs 372 51 423
Exploration costs 145 14 159
Operating expenses 224 11 235
Depreciation, depletion and amortization 408 81 489
- -------------------------------------------------------------------------------------------------------
1,149 157 1,306
- -------------------------------------------------------------------------------------------------------
Operating income 533 54 587
Income tax provision 131 20 151
- -------------------------------------------------------------------------------------------------------
Results of operations for oil and gas producing activities $ 402 $ 34 $ 436
=======================================================================================================
47
52
SUPPLEMENTARY FINANCIAL INFORMATION
The following table reflects estimated quantities of proved oil and gas
reserves. These reserves have been reduced for royalty interests owned by
others. These reserves have been estimated by the Company's petroleum engineers.
The Company considers such estimates to be reasonable, however, due to inherent
uncertainties, estimates of underground reserves are imprecise and subject to
change over time as additional information becomes available.
Oil (MMBbls) Gas (BCF)
- ----------------------------------------------------------------------------------------------------------------------------
North America International Total North America International Total
- ----------------------------------------------------------------------------------------------------------------------------
PROVED DEVELOPED AND UNDEVELOPED RESERVES
December 31, 1995 257.6 36.1 293.7 6,197 289 6,486
Revision of previous estimates 6.6 (.4) 6.2 (8) 28 20
Extensions, discoveries and
other additions 33.1 2.3 35.4 474 34 508
Production (26.1) (7.2) (33.3) (559) (28) (587)
Purchases of reserves in place 8.0 -- 8.0 78 -- 78
Sales of reserves in place (4.2) -- (4.2) (274) -- (274)
- ----------------------------------------------------------------------------------------------------------------------------
December 31, 1996 275.0 30.8 305.8 5,908 323 6,231
Revisions of previous estimates (15.6) (2.6) (18.2) 68 (4) 64
Extensions, discoveries and
other additions 44.9 .3 45.2 913 1 914
Production (24.6) (7.2) (31.8) (583) (26) (609)
Purchases of reserves in place 1.4 -- 1.4 116 240 356
Sales of reserves in place (48.7) -- (48.7) (538) -- (538)
- ----------------------------------------------------------------------------------------------------------------------------
December 31, 1997 232.4 21.3 253.7 5,884 534 6,418
Revision of previous estimates (8.4) 1.6 (6.8) (94) (6) (100)
Extensions, discoveries and
other additions 26.7 29.7 56.4 636 35 671
Production (24.2) (6.0) (30.2) (577) (24) (601)
Purchases of reserves in place .1 -- .1 81 8 89
Sales of reserves in place -- -- -- (72) (25) (97)
- ----------------------------------------------------------------------------------------------------------------------------
December 31, 1998 226.6 46.6 273.2 5,858 522 6,380
============================================================================================================================
PROVED DEVELOPED RESERVES
December 31, 1995 224.8 30.3 255.1 5,064 271 5,335
December 31, 1996 242.0 25.4 267.4 4,870 265 5,135
December 31, 1997 203.9 15.6 219.5 4,641 233 4,874
December 31, 1998 199.2 14.5 213.7 4,565 258 4,823
48
53
SUPPLEMENTARY FINANCIAL INFORMATION
A summary of the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves is shown below. Future net cash flows
are computed using year end sales prices, costs and statutory tax rates
(adjusted for tax credits and other items) that relate to the Company's existing
proved oil and gas reserves.
December 31, 1998
- --------------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- --------------------------------------------------------------------------------------------------------
Future cash inflows $13,840 $1,912 $15,752
Less related future
Production costs 3,761 773 4,534
Development costs 617 296 913
Income taxes 2,113 190 2,303
- --------------------------------------------------------------------------------------------------------
Future net cash flows 7,349 653 8,002
10% annual discount for estimated timing of cash flows 3,643 301 3,944
- --------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 3,706 $ 352 $ 4,058
========================================================================================================
December 31, 1997
- --------------------------------------------------------------------------------------------------------
(In Millions) North America International Total
- --------------------------------------------------------------------------------------------------------
Future cash inflows $15,934 $1,800 $17,734
Less related future
Production costs 4,076 702 4,778
Development costs 736 214 950
Income taxes 2,767 200 2,967
- --------------------------------------------------------------------------------------------------------
Future net cash flows 8,355 684 9,039
10% annual discount for estimated timing of cash flows 3,960 234 4,194
- --------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 4,395 $ 450 $ 4,845
========================================================================================================
A summary of the changes in the standardized measure of discounted future
net cash flows applicable to proved oil and gas reserves follows.
Year Ended December 31,
- ----------------------------------------------------------------------------------------------------
(In Millions) 1998 1997 1996
- ----------------------------------------------------------------------------------------------------
January 1 $ 4,845 $ 7,505 $ 4,393
- ----------------------------------------------------------------------------------------------------
Revisions of previous estimates
Changes in prices and costs (904) (4,167) 4,981
Changes in quantities (100) (23) 119
Changes in rate of production (262) (436) (77)
Additions to proved reserves resulting from extensions,
discoveries and improved recovery, less related costs 465 655 782
Purchases of reserves in place 56 246 148
Sales of reserves in place (77) (667) (177)
Accretion of discount 612 1,048 529
Sales of oil and gas, net of production costs (1,211) (1,547) (1,470)
Net change in income taxes 297 1,697 (1,652)
Other 337 534 (71)
- ----------------------------------------------------------------------------------------------------
Net change (787) (2,660) 3,112
- ----------------------------------------------------------------------------------------------------
December 31 $ 4,058 $ 4,845 $ 7,505
====================================================================================================
49
54
BURLINGTON RESOURCES INC.
QUARTERLY FINANCIAL DATA -- UNAUDITED
1998 1997
- ------------------------------------------------------------------------------------------------------------------------------
(In Millions, Except per Share Amounts) 4th 3rd 2nd 1st 4th 3rd 2nd 1st
- ------------------------------------------------------------------------------------------------------------------------------
Revenues $ 403 $ 390 $ 412 $ 432 $ 541 $ 464 $ 427 $ 568
Operating Income(a) 14 41 64 99 87 116 93 207
Net Income(a)(b) -- 15 23 48 37 65 86 131
Basic Earnings per Common Share -- .08 .13 .27 .20 .37 .49 .74
Diluted Earnings per Common Share -- .08 .13 .27 .20 .37 .49 .73
Cash Dividends Declared per Common Share $ .14 $ .13 $ .14 $ .14 $ .14 $ .10 $ .11 $ .11
- ------------------------------------------------------------------------------------------------------------------------------
Common Stock Price Range
High $43 1/8 $ 44 1/2 $ 49 5/8 $ 49 1/2 $53 5/8 $53 3/16 $48 5/8 $54 1/2
Low $ 32 $29 7/16 $38 3/16 $38 15/16 $42 1/2 $ 43 5/8 $39 3/4 $42 5/8
(a) During the fourth quarter of 1997, as a result of the Merger, the Company
recorded a pretax charge of $80 million ($71 million after tax).
(b) During the second quarter of 1997, as a result of the divestiture program,
the Company recorded a pretax gain of $50 million ($31 million after tax).
50
55
EXECUTIVE OFFICERS OF THE REGISTRANT
BOBBY S. SHACKOULS, 48
Chairman of the Board,
President and Chief Executive Officer
Burlington Resources Inc.
July 1997 to Present
President and Chief Executive Officer, Burlington Resources Inc., December 1995
to July 1997; President and Chief Executive Officer, Burlington Resources Oil &
Gas Company, October 1994 to Present; Executive Vice President and Chief
Operating Officer, Meridian Oil Inc., June 1993 to October 1994.
JOHN E. HAGALE, 42
Executive Vice President and Chief Financial Officer
Burlington Resources Inc.
December 1995 to Present
Executive Vice President and Chief Financial Officer, Burlington Resources Oil &
Gas Company, March 1993 to Present; Senior Vice President and Chief Financial
Officer, Burlington Resources Inc., April 1994 to December 1995.
RANDY L. LIMBACHER, 40
President and Chief Executive Officer
Burlington Resources North America
July 1998 to Present
Vice President, Gulf Coast Division, Burlington Resources Oil & Gas Company,
February 1997 to June 1998; Vice President, Farmington Region, Burlington
Resources Oil & Gas Company, June 1993 to January 1997.
H. LEIGHTON STEWARD, 64
Vice Chairman of the Board
Burlington Resources Inc.
October 1997 to Present
Chairman of the Board, President and Chief Executive Officer, The Louisiana Land
and Exploration Company, November 1996 to October 1997; Chairman of the Board
and Chief Executive Officer, The Louisiana Land and Exploration Company,
September 1995 to November 1996; and Chairman of the Board, President and Chief
Executive Officer, The Louisiana Land and Exploration Company, January 1989 to
September 1995.
L. DAVID HANOWER, 39
Senior Vice President
Law and Administration
Burlington Resources Inc.
July 1998 to Present
Senior Vice President, Law, Burlington Resources Inc., April 1996 to June 1998,
Vice President, Law, Burlington Resources Inc., April 1991 to April 1996; Senior
Vice President, Law, Burlington Resources Oil & Gas Company, July 1993 to June
1998.
JOHN A. WILLIAMS, 54
President and Chief Executive Officer
Burlington Resources International
July 1998 to Present
Senior Vice President, Exploration, Burlington Resources Inc., October 1997 to
June 1998; Senior Vice President, Exploration and Production, The Louisiana Land
and Exploration Company, September 1995 to October 1997; Vice President, The
Louisiana Land and Exploration Company, March 1988 to September 1995.
51
56
FORWARD-LOOKING STATEMENTS
The Company may, in discussions of its future plans, objectives and expected
performance in periodic reports filed by the Company with the Securities and
Exchange Commission (or documents incorporated by reference therein) and in
written and oral presentations made by the Company, include projections or other
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 or Section 21E of the Securities Exchange Act of 1934, as amended.
Such projections and forward-looking statements are based on assumptions which
the Company believes are reasonable, but are by their nature inherently
uncertain. In all cases, there can be no assurance that such assumptions will
prove correct or that projected events will occur, and actual results could
differ materially from those projected.
52
57
BOARD OF DIRECTORS
John V. Byrne (1)
President Emeritus
Oregon State University
S. Parker Gilbert (2)
Former Chairman
Morgan Stanley Group Inc.
Laird I. Grant (1)
Former President, Chief Executive Officer
and Chief Investment Officer
Rockefeller & Co., Inc.
John T. LaMacchia (2) (3)
President and Chief Executive Officer
Cincinnati Bell Inc.
James F. McDonald (1) (3)
President and Chief Executive Officer
Scientific-Atlanta, Inc.
Kenneth W. Orce (1)
Senior Partner
Cahill Gordon & Reindel
Donald M. Roberts (1)
Retired Vice Chairman and Treasurer
United States Trust Company of New York
and U.S. Trust Corporation
John F. Schwarz (2)
Chairman, President and Chief Executive Officer
Entech Enterprises, Inc.
Walter Scott, Jr. (2) (3)
Chairman
Level 3 Communications, Inc.
Bobby S. Shackouls (3)
Chairman of the Board, President
and Chief Executive Officer
Burlington Resources Inc.
H. Leighton Steward (3)
Vice Chairman of the Board
Burlington Resources Inc.
William E. Wall (2)
Of Counsel
Siderius Lonergan
(1) Audit Committee
(2) Compensation and Nominating Committee
(3) Executive Committee
EXECUTIVE OFFICERS
Bobby S. Shackouls
Chairman of the Board, President and
Chief Executive Officer
Burlington Resources Inc.
H. Leighton Steward
Vice Chairman of the Board
Burlington Resources Inc.
John E. Hagale
Executive Vice President and
Chief Financial Officer
Burlington Resources Inc.
L. David Hanower
Senior Vice President,
Law and Administration
Burlington Resources Inc.
Randy L. Limbacher
President and Chief Executive Officer
Burlington Resources North America
John A. Williams
President and Chief Executive Officer
Burlington Resources International
CORPORATE INFORMATION
Principal Corporate Office
Burlington Resources Inc.
5051 Westheimer, Suite 1400
Houston, Texas 77056
(713) 624-9500
http://www.br-inc.com
Annual Meeting
The Annual Meeting of Stockholders will be in Houston, Texas on April 7, 1999.
Formal notice of the meeting will be mailed in advance.
Stock Exchange Listing
New York Stock Exchange
Symbol: BR
Stock Transfer Agent and Registrar
BankBoston, N.A.
c/o EquiServe
P.O. Box 8040
Boston, Massachusetts 02266-8040
(800) 736-3001
http://www.equiserve.com
Additional copies of this Annual Report and the Company's Form 10-K filed with
the Securities and Exchange Commission are available, without charge, by writing
or calling:
Investor Relations
Burlington Resources Inc.
P.O. Box 4239
Houston, Texas 77210
(800) 262-3456
[GRAPHIC OF GAS PLANT]
58
[PHOTOS OF MAN, SUNSET, & SATELLITE]
BURLINGTON
RESOURCES
5051 WESTHEIMER, SUITE 1400
HOUSTON, TEXAS 77056