Back to GetFilings.com
1
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-14256
BELCO OIL & GAS CORP.
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
NEVADA 13-3869719
(STATE OR OTHER JURISDICTION OF (IRS EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
767 FIFTH AVENUE, 46TH FLOOR 10153
NEW YORK, NEW YORK (ZIP CODE)
(ADDRESS OF PRINCIPAL EXECUTIVE
OFFICE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (212) 644-2200
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
ON WHICH REGISTERED
-----------------------
COMMON STOCK, PAR VALUE $.01 PER SHARE NEW YORK STOCK EXCHANGE
6 1/2% CONVERTIBLE PREFERRED STOCK, PAR VALUE $.01 PER NEW YORK STOCK EXCHANGE
SHARE
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES [X] NO [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the Registrant at March 19, 2001, was approximately $133.4
million (based on a value of $9.35 per share, the closing price of the Common
Stock as quoted by the New York Stock Exchange on such date). 32,761,890 shares
of Common Stock, par value $.01 per share, were outstanding on March 19, 2001.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 2001 Annual
Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
2
BELCO OIL & GAS CORP.
FORM 10-K
TABLE OF CONTENTS
PAGE
----
PART I
ITEM 1 -- BUSINESS.................................................... 1
Overview.................................................... 1
Primary Operating Areas..................................... 1
Costs Incurred and Drilling Results......................... 6
Acreage..................................................... 7
Productive Well Summary..................................... 8
Marketing................................................... 8
Production Sales Contracts.................................. 9
Price Risk Management Transactions.......................... 9
Texas Severance Tax Abatement............................... 10
Section 29 Tax Credit....................................... 11
Regulation.................................................. 11
Operating Hazards and Insurance............................. 13
Title to Properties......................................... 13
Employees................................................... 13
Office and Equipment........................................ 13
Forward-Looking Information and Risk Factors................ 15
Executive Officers.......................................... 22
Certain Definitions......................................... 23
ITEM 2 -- PROPERTIES.................................................. 25
Oil and Gas Reserves........................................ 25
ITEM 3 -- LEGAL PROCEEDINGS........................................... 25
ITEM 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 25
PART II
ITEM 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS......................................... 26
ITEM 6 -- SELECTED FINANCIAL DATA..................................... 27
ITEM 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS................................... 28
Overview.................................................... 28
Results of Operations -- 2000 Compared to 1999.............. 29
Results of Operations -- 1999 Compared to 1998.............. 30
Liquidity and Capital Resources............................. 31
Other....................................................... 35
ITEM 7A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK........................................................ 35
ITEM 8 -- CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.... 36
ITEM 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.................................... 36
PART III
ITEM 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 36
ITEM 11 -- EXECUTIVE COMPENSATION...................................... 36
ITEM 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.................................................. 37
ITEM 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 37
PART IV
ITEM 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM
8-K......................................................... 37
i
3
BELCO OIL & GAS CORP.
PART I
ITEM 1 -- BUSINESS
OVERVIEW
Belco Oil & Gas Corp. is an independent energy company engaged in the
exploration for and the acquisition, exploitation, development and production of
natural gas and oil in the United States primarily in the Rocky Mountains, the
Gulf Coast, the Permian Basin and the Mid-Continent region. Since inception in
April 1992, we have grown our reserve base through a program of acquisitions,
exploration, exploitation and development drilling. Focusing in core areas
allows us to accumulate detailed geologic and geophysical knowledge, significant
operational efficiencies and technical expertise.
We have achieved substantial growth in reserves, production, revenues and
EBITDA (Earnings Before Interest, Taxes, Depreciation, Depletion and
Amortization and other non-cash charges) since 1992. Our estimated proved
reserves have increased at a compound annual growth rate of 35%, from 67 Bcfe as
of December 31, 1992 to 726 Bcfe as of December 31, 2000, with a reserve life
index of approximately 11.3 years based on 2000 production. Average daily
production has increased from 4 MMcfe per day in 1992 to approximately 176 MMcfe
per day in 2000. Similarly, the growth in Belco's EBITDA has been substantial,
increasing from $2.9 million for the year ended December 31, 1992, to $112.1
million for the year ended December 31, 2000. Our low cost structure is
evidenced by our general and administrative expenses of $0.10 per Mcfe and lease
operating expenses and production taxes of $0.74 per Mcfe in 2000.
At December 31, 2000, Belco had estimated proved reserves of 726 Bcfe with
a pre-tax PV10 value of $2,256 million utilizing mandated SEC price guidelines.
As of December 31, 2000, we held or controlled approximately 1.8 million gross
(703,000 net) undeveloped acres and had an interest in approximately 2,460 gross
(1,068 net) oil and gas wells of which we operated 1,167.
Belco's Rocky Mountain gas operations are currently focused in the Green
River, Wind River and Big Horn Basins. Oil is targeted in North Dakota in the
Mission Canyon and Lodgepole horizons.
The Gulf Coast region includes drilling horizontal wells to develop the
Austin Chalk and the Georgetown formations and the exploitation of tight Cotton
Valley sands in northern Louisiana.
Belco's Permian Basin and Mid-Continent activities concentrate on
exploiting proven properties through secondary recovery operations, the drilling
of development wells or infill wells, workovers, recompletions in other
productive zones and other exploitation techniques. We have ongoing secondary
recovery/infill drilling programs on many of the properties within these two
core areas.
PRIMARY OPERATING AREAS
Belco's operations are currently focused in four core operating areas: (i)
the Rocky Mountains, in Wyoming and North Dakota; (ii) the Gulf Coast, primarily
in Texas and Louisiana, (iii) the Permian Basin of west Texas; and (iv) the
Mid-Continent region in Oklahoma and Kansas.
The following table sets forth information, as of December 31, 2000, with
respect to our estimated net proved reserves by operating area. Miller and
Lents, Ltd. ("Miller & Lents"), our independent petroleum
1
4
engineers, made independent estimates covering approximately 84% of Belco's net
equivalent Mcf reserves and confirmed Belco's estimates are in accordance with
Security and Exchange Commission's guidelines.
ESTIMATED PROVED RESERVES AT DECEMBER 31, 2000
PERCENT
GAS OF
OIL GAS EQUIVALENT PROVED
(MBBLS) (MMCF)(1) (MMCFE) RESERVES
------- --------- ---------- --------
Rocky Mountains................................... 6,668 108,382 148,390 20%
Gulf Coast........................................ 1,786 184,451 195,167 27%
Permian Basin..................................... 37,646 50,698 276,574 38%
Mid-Continent..................................... 11,391 37,792 106,138 15%
------ ------- ------- ---
Total................................... 57,491 381,323 726,269 100%
====== ======= ======= ===
- ---------------
(1) Includes natural gas liquids.
ROCKY MOUNTAINS
Approximately 20% of our estimated proved reserves at December 31, 2000
were located in our Rocky Mountains core area.
WYOMING. We maintain a significant acreage position where we conduct an
ongoing exploration and development program. In June 1992, Belco commenced a
development drilling program in the Moxa Arch Trend (Green River Basin) pursuant
to a farmout from Amoco. In 1996, Belco significantly expanded its acreage and
exploration activities by acquiring the rights to approximately 750,000 gross
(250,000 net) acres in the Green River, Wind River and Big Horn Basins in
Wyoming, which lie north and east of the Moxa Arch Trend. At December 31, 2000,
Belco controlled approximately 1,165,000 million gross (363,269 net) undeveloped
acres in these three basins.
Moxa Arch Trend. One of our primary operating areas is the Moxa Arch Trend
located in the Green River Basin in southwestern Wyoming, principally in
Lincoln, Sweetwater and Uinta Counties. Approximately 13% of our estimated
proved reserves at December 31, 2000 were located in this trend. We participate
in vertical gas wells in this area which target the Frontier and/or Dakota
formations at depths that range from approximately 10,000 to 12,500 feet. The
Frontier formation is a relatively blanket "tight gas sand" formation, while the
Dakota formation, beneath the Frontier, tends to be a more prolific, but less
predictable, channel sand. Production from Moxa Arch wells, particularly from
the Frontier formation, tends to be long-lived, with 25 to 30 year reserve lives
not uncommon.
Through 2000, we had participated in 256 gross (91 net) wells in this field
with 183 Frontier wells, 18 Dakota wells and 55 dual completions (both Frontier
and Dakota completed in the same well bore). Average net production for the year
ended December 31, 2000, was approximately 22.4 MMcfe per day. Forty-seven of
our gross wells drilled in 1992 qualified for the Section 29 Tax Credit of
approximately $0.59 per Mcf, which is attributable to all qualified production
from these wells through 2002. See "-- Section 29 Tax Credit." Belco drilled 27
gross wells (15.8 net) in 2000 and anticipates drilling approximately 18 gross
wells in 2001. See "-- Regulation -- Environmental Regulation."
Green River, Wind River and Big Horn Basins. Effective November 1, 1996,
Belco entered into an agreement with Andex Partners and Andover Partners to
conduct exploratory operations in the Green River and Wind River Basins of
Wyoming. Under the agreement, Belco committed to spend a minimum of $20 million,
which commitment was satisfied as of October 1, 2000, on seismic, leasing and
exploratory activities through December 31, 2001 and has earned rights to a 50%
interest in approximately 300,000 net acres. Anadarko and Yates Petroleum
Corporation operate most of the acreage.
During 2000, we participated in 4 development wells in the Tipton project
in Sweetwater County, Wyoming. These wells target Mesa Verde sands at depths
from 9,000 to 10,500 feet. Yates, the operator of
2
5
these wells, plans 20 additional wells in 2001. Belco has approximately a 19%
average working interest in this development.
Effective December 31, 1996, we entered into two joint development
agreements with Snyder Oil Company, now Devon Energy Corp. pursuant to which
Belco has acquired a 50% interest in approximately 87,321 net acres in the Wind
River Basin of Wyoming and 110,859 net acres in the Big Horn Basin of Wyoming.
Under such agreements, Devon is the operator. A total of 8 wells have been
drilled to date on this acreage. At least two wells are planned in 2001.
In June 1997, Belco entered into a participation agreement with Tom Brown,
Inc. and Andover Partners covering an approximate one million acre AMI in the
Big Horn Basin and acquired an interest in an initial 100,000 gross (25,000 net)
acres. We plan to continue acquiring additional leases in the Big Horn Basin.
Belco expects to participate in a series of exploratory wells in these
basins over the next 12 to 24 months with Anadarko, Devon, Tom Brown and Yates
serving as operators for most wells. The wells will target multiple formations,
with the Mesa Verde and Frontier formation the most frequent targets. If initial
results are successful, these projects hold the potential for multi-well
developmental drilling programs for Belco over the next several years.
NORTH DAKOTA. Effective March 1, 2000, Belco acquired interests in the
Stadium, Livestock, Subdivision and Eland units producing from the Lodgepole
formation in Stark County, North Dakota. Belco operates the five well Stadium
unit and both of the neighboring one well units, Subdivision and Livestock. In
1999, we began leasing acreage on a series of Mission Canyon prospects within 30
miles of these Stark County units. The first wells were drilled in 2000 and
development will continue in 2001 on the four discoveries made to date.
Stadium Unit. Belco has a 51% working interest in the Stadium unit. The
prior owner drilled the first well in 1996 and encountered a total of 150 feet
of oil pay in a 300-foot thick carbonate reef. A total of five wells were
drilled prior to the acquisition. The deepest well was converted to a water
injector in 1998 to maintain pressures, and the unit has averaged over 4,000
gross BOPD from 4 wells since mid-1999.
Mission Canyon. Belco has acquired more than 75,000 net acres in four
separate prospects targeting thin oil productive zones in the Mission Canyon
interval. Other operators recognized these zones in the past in several vertical
wells, but often could not complete them economically because nearby wet zones
would also produce along with the oil. We believed the use of horizontal wells
would decrease the tendency for water production from the underlying intervals.
The first horizontal well was drilled in December 1999, and through December
2000, a total of 16 wells had been drilled with a success ratio of 75%. The
typical well is drilled to approximately 9,600 feet vertical depth and has a
5,000-foot lateral within a 640-acre unit. Crooked Canyon, the most drilled
prospect, has ten wells drilled within a 15 square mile area. The Rocky Hill
discovery has three wells, the North Treetop discovery has two wells, and the
Manning discovery has one well. Belco has a 100% interest in all but the Manning
well where its interest is 50%. We expect to drill at least 10 wells in 2001.
GULF COAST
Approximately 27% of Belco's estimated proved reserves at December 31, 2000
were located in our Gulf Coast core area.
Giddings Field. Approximately 17% of Belco's estimated total proved
reserves at December 31, 2000 were located in the Giddings Field of east central
Texas, principally in Grimes, Washington and Fayette Counties. To date, the
primary producing zone in the Giddings Field has been the Austin Chalk
formation, a fractured carbonate formation that has been highly conducive to the
application of horizontal drilling technology. The Austin Chalk formation is
encountered in this field at depths ranging between approximately 7,000 and
17,000 feet. The Georgetown formation, approximately 300 to 500 feet below the
base of the Austin Chalk, has been a secondary objective in the field. Recent
success targeting the Georgetown indicates it may be the main objective for
future development in the field.
3
6
Belco first acquired interests in the Giddings Field in September 1992.
During the year ended December 31, 2000, average net production from this field
was approximately 55.5 MMcfe per day. Through December 31, 2000, we had drilled
265 gross (88 net) wells in this field and we continue to control approximately
203,000 gross (60,500 net) undeveloped acres in this area. Belco currently
divides the Giddings Field into two prospect areas: (i) Navasota River,
primarily in Grimes County; (ii) Independence, primarily in Washington County.
We expect to drill new wells, including infill wells, and re-enter older wells
to drill additional laterals in the Giddings Field. Currently, a majority of
Belco's interests in this field are held pursuant to agreements with and are
operated by Chesapeake Energy Corporation and, to a lesser extent, Anadarko.
Five wells were drilled in the Independence area in 2000. Four of the wells
continued the Austin Chalk development of the Brenham dome area that began in
1998. The fifth well was a re-entry of the Ricks 1-H. It targeted the lower
Georgetown formation and produced at an initial rate of 40,000 Mcfd of gas. The
Georgetown will be the target for most of the 9 wells planned in 2001 for
Independence.
While not expected to have the high initial rates indicated by the Ricks
1-H, the Navasota area also has potential for additional Georgetown wells. We
plan approximately 8 wells for this area in 2001.
We believe that our success in the Giddings Field is attributable to three
principal factors: (i) continued technological advances in horizontal drilling
have significantly lowered finding and development costs in the field; (ii) the
geological setting of the deeper downdip areas of the field has created more
extensive fracturing than in other areas of the Texas Austin Chalk Trend; and
(iii) Belco's acquisition program in cooperation with other operators has
permitted the creation of larger spacing units, thus reducing possible
competition for reserves from offsetting wells. As a result of these factors,
our deeper downdip wells have, on average, produced greater reserves per well
than average wells in other areas of the Texas Austin Chalk Trend.
The majority of Belco's acreage in the Giddings Field was classified as a
tight formation or deep wells by the Texas Railroad Commission. Wells spud
between May 1989 and September 1996 are exempt from the 7.5% state severance tax
on high cost natural gas through August 2001. See "-- Texas Severance Tax
Abatement."
Elm Grove. Effective January 1, 2000, Belco acquired an approximate 37%
working interest in 20 wells in the Elm Grove field in Caddo and Bossier
Parishes in Northern Louisiana. The operator, J.W. Operating, drilled the 20
wells in 17 sections to extend the Cotton Valley production downdip from the
mature Caspiana field. In addition to the Cotton Valley at 9,500 feet, shallower
secondary zones include the Hosston and Rodessa intervals.
Through December 2000, Belco has participated in drilling 33 gross wells
(12 net wells). Our net production has increased from 5.3 MMcfd at the time of
the acquisition to approximately 10.0 MMcfd of gas as of December 2000. A three
to four rig drilling program is planned in 2001, with the drilling of
approximately 42 wells. We plan to drill most of these wells on 160 acre spacing
with the remainder on 80 acre spacing. Other fields in the area have been
successfully downspaced to 80 acre patterns, and the potential exists for
similar spacing throughout our Elm Grove acreage.
In addition, the quality of the Hosston sands increases significantly in
parts of the field to merit dual completions or separate wells. Five of the
wells drilled in 2000 were drilled with Hosston objectives.
PERMIAN BASIN
Approximately 38% of Belco's estimated proved reserves at December 31, 2000
were located in our Permian Basin core area. These reserves are concentrated in
the Andrews Unit, the Shafter Lake San Andres Unit, the Roundtop Unit and the
Nolley Wolfcamp Unit.
Belco's Permian Basin properties produce primarily from either the
Grayburg/San Andres formation, at an average depth of 4,500 feet, or the
Wolfcamp/Penn formation at an average depth of 9,000 feet. Most of the
properties that produce from these horizons are under secondary recovery, and,
based on analogous properties nearby, are potentially responsive to CO(2)
miscible flooding. Given the existence of nearby
4
7
CO(2) pipelines, we believe many of our properties in the Permian Basin region
contain significant upside potential based on application of enhanced recovery
methods and deeper drilling which could add to existing reserves.
A significant portion of Belco's total estimated proved reserves in the
Permian Basin region lie in Andrews County, Texas. We produced approximately
3,000 gross BOPD in Andrews County, and realized significant advantages as a
result of our large-scale operation. Belco owns two electrical distribution
systems and three saltwater gathering and disposal systems. We have several
yards for both the storage of equipment and the staging of new development
projects. Two of Belco's larger production facilities connect into a water
supply system with excess capacity for expanding existing or initiating new
secondary and enhanced recovery projects. We believe that these systems and
facilities provide Belco with a competitive advantage in acquiring additional
operated properties in Andrews County.
Our largest (by value) Permian Basin units are the Andrews Unit, the
Roundtop Unit and the Shafter Lake San Andres Unit.
Andrews Unit. The Andrews Unit produces from the Wolfcamp/Penn formation
at approximately 8,600 feet. Belco has a 98.6% working interest in this 3,230
acre unit. Water injection began in late 1996 with the first response occurring
in late 1998. Gross production in 2000 averaged 860 BOPD with injection of over
5,300 barrels of water per day. During 2000 we continued expansion of the
waterflood by drilling 1 producer and 2 injectors, converting 3 additional wells
to injection, re-entering a plugged well for injection and performing 13
workovers. The conversion and workover activity will continue in 2001 with the
planned drilling of three wells. We also believe that production from this
waterflood unit can be enhanced with the use of CO(2) or surfactants with
flooding.
Roundtop Unit. Belco owns a 61.6% working interest in this 4,559-acre unit
in Fisher County, Texas. We operate the secondary recovery unit that produces
from the Palo Pinto formation at approximately 4,700 feet. We became operator of
this unit in March 1998. Gross oil production in 2000 averaged approximately 520
BOPD. The unit was originally waterflooded with success on a peripheral
injection pattern prior to changing to a five spot pattern. We began the process
of returning the unit to a peripheral flood pattern in 1998 and continued
reconfiguring the injection pattern during 2000. In 2001, we will continue to
optimize the flood pattern and isolate individual zones within the overall
section to gain higher flood efficiencies.
Shafter Lake San Andres Unit. The Shafter Lake San Andres Unit is a 12,880
acre unit in Andrews County, Texas that produces from the Grayburg/San Andres
formation at approximately 4,500 feet. Belco has an 81.4% working interest in
this secondary recovery unit. Gross oil production averaged 745 BOPD in 2000. We
have drilled 51 infill 20 acre locations since becoming operator of the unit in
early 1993. In 2000, we drilled nine wells on 20 acre spacing along with six
wells on ten acre spacing. Operators of nearby San Andres fields have
successfully drilled to ten acre spacing before CO(2) injection. The wells we
drilled are designed to test the viability of ten acre locations within the
center of the Shafter Lake unit. The preliminary indications are promising with
the two producers each averaging initial production of over 50 BOPD gross. We
plan to drill approximately 10 wells in 2001 to continue to expand both the 20
acre and 10 acre spacing. Potential exists for CO(2) flooding as the field
matures.
MID-CONTINENT REGION
Belco's Mid-Continent operations are currently focused in Oklahoma and
Kansas and represent approximately 15% of its total estimated proved reserves at
December 31, 2000. The oil is concentrated in Belco operated waterfloods in
Oklahoma while the gas production is in Belco operated wells in Kansas and
mainly outside operated wells in Oklahoma.
OKLAHOMA. Three waterfloods represent a majority of our estimated proved
oil reserves in the region. These waterfloods are identified as the Oakdale
Unit, the Calumet Unit and the Rush Springs Unit.
Oakdale Red Fork Unit. Belco owns a 97.3% working interest in this 3,600
acre unit in northwestern Oklahoma. We operate the secondary recovery unit that
produces from the Redfork formation at 6,400 feet. Gross oil production was
approximately 815 BOPD in 2000. We drilled 2 wells and re-entered one well
during
5
8
2000. Plans for 2001 include the drilling of at least 2 wells and the continued
expansion of water injection to the south.
Calumet Cottage Grove Unit. The Belco operated secondary recovery unit
consists of 11,400 acres in central Oklahoma. Production is from the
Pennsylvanian Cottage Grove formation at 8,100 feet. Gross production in 2000
averaged approximately 1,815 BOPD. We have a 44.1% working interest in this
unit. Five wells were drilled in 2000 and 6 wells are planned in 2001.
KANSAS. Belco has 31,649 developed net acres and approximately 7,692
undeveloped net acres in Kansas. We initially acquired interests in Kansas in
1993 from Mobil and made 2 additional acquisitions from Huber in 1997 and 1998.
Gas is produced from the Chase formation and both gas and oil are produced from
the Lansing, Morrow and Chester formations. Most of the 169 producing wells are
in Stanton, Morton, Stevens and Haskell counties. We drilled 3 wells in 2000
targeting the Chase gas sands.
COSTS INCURRED AND DRILLING RESULTS
Drilling Activity
The following table sets forth the wells participated in by Belco during
the periods indicated. In the table, "gross" refers to the total wells in which
we have a working interest, and "net" refers to gross wells multiplied by our
working interest therein.
YEAR ENDED DECEMBER 31, (1)
-----------------------------------------------
2000 1999 1998
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
DEVELOPMENT:
Productive................................... 106.0 57.2 46.0 29.4 69.0 47.1
Non-productive............................... 7.0 5.1 2.0 1.0 1.0 1.0
----- ---- ---- ---- ---- ----
Total................................ 113.0 62.3 48.0 30.4 70.0 48.1
===== ==== ==== ==== ==== ====
EXPLORATORY:
Productive................................... 17.0 10.8 11.0 8.2 23.0 9.4
Non-productive............................... 5.0 3.7 3.0 2.5 7.0 4.0
----- ---- ---- ---- ---- ----
Total................................ 22.0 14.5 14.0 10.7 30.0 13.4
===== ==== ==== ==== ==== ====
- ---------------
(1) Includes wells in progress at December 31 of each year presented.
Volumes, revenue, prices and production costs
The following table sets forth certain information regarding the production
volumes, revenue, average prices received and average production costs
associated with our sale of oil and natural gas for the periods indicated.
6
9
YEAR ENDED DECEMBER 31,
--------------------------------
2000 1999 1998
-------- -------- --------
Net Production Data:
Oil (MBbl)............................................... 3,922 3,439 4,177
Gas (MMcf)............................................... 40,847 39,737 37,208
Gas equivalent (MMcfe)................................... 64,379 60,370 62,272
Oil and Gas Sales, net of cash hedging activities ($ in
000's)(1)................................................ $199,387 $141,932 $129,916
Average Sales Price(1):
Oil (per Bbl)
-- Unhedged........................................... $ 29.23 $ 17.49 $ 13.17
-- Hedge settlements.................................. (4.62) 1.76 2.92
-------- -------- --------
Net realized.......................................... $ 24.61 $ 19.25 $ 16.09
======== ======== ========
Gas (per Mcf)
-- Unhedged........................................... $ 3.50 $ 1.99 $ 1.86
-- Hedge settlements.................................. (0.98) (0.08) (0.17)
-------- -------- --------
Net realized.......................................... $ 2.52 $ 1.91 $ 1.69
======== ======== ========
Costs (per Mcfe):
Oil and gas operating expenses........................ $ 0.52 $ 0.49 $ 0.50
Production taxes...................................... 0.22 0.16 0.16
General and administrative............................ 0.10 0.08 0.08
Depreciation, depletion and amortization of oil and
gas properties...................................... 0.88 0.90 0.90
- ---------------
(1) Excludes non-hedge commodity price risk management cash settlements.
Development, Exploration and Acquisition Expenditures
The following table sets forth certain information regarding the costs
incurred by Belco in our development, exploration and acquisition activities
during the periods indicated.
YEAR ENDED DECEMBER 31,
-------------------------------
2000 1999 1998
-------- ------- --------
(IN THOUSANDS)
Property acquisitions costs --
Proved.................................................... $ 79,532 $17,608 $ 56,695
Unproved.................................................. 11,991 10,390 14,414
Exploration costs........................................... 21,442 10,943 18,597
Development costs........................................... 66,310 29,576 37,969
Capitalized interest........................................ 7,570 4,881 5,123
Property Sales.............................................. (11,517) (215) (6,292)
-------- ------- --------
Total Net Costs Incurred.......................... $175,328 $73,183 $126,506
======== ======= ========
ACREAGE
The following table sets forth, as of December 31, 2000, the gross and net
acres that we owned, controlled or had the right to acquire interests in both
developed and undeveloped acreage. Developed acreage refers to acreage within
producing units and undeveloped acreage refers to acreage that has not been
placed in
7
10
producing units. "Gross" acres refers to the total number of acres in which we
own a working interest. "Net" acres refers to gross acres multiplied by our
fractional working interest.
DEVELOPED UNDEVELOPED(1)
------------------ --------------------
GROSS NET GROSS NET
------- ------- --------- -------
ROCKY MOUNTAINS:
Green River Basin............................... 5,443 533 539,762 141,793
Moxa Arch Trend................................. 33,413 19,632 27,414 16,426
Wind River Basin................................ 1,917 718 275,016 103,007
Big Horn Basin.................................. 643 321 322,625 102,043
Denver-Julesburg Basin.......................... 207,365 2,298 110,074 57,927
PERMIAN BASIN:.................................... 100,191 51,817 20 20
MID-CONTINENT REGION:
Oklahoma..................................... 119,957 39,687 37,895 12,012
North Texas.................................. 23,093 10,302 640 320
Kansas....................................... 37,649 31,628 8,256 7,693
North Dakota................................. 10,973 4,391 37,571 25,343
Michigan..................................... 2,411 734 13,263 2,382
GULF COAST/OTHER:
Texas-Giddings Field............................ 106,626 41,831 203,171 60,515
Louisiana....................................... 18,133 8,172 183,339 147,248
Arkansas........................................ 345 345 4,264 2,952
Gulf Coast...................................... 11,999 9,030 41,027 23,762
New Mexico...................................... 320 160 -- --
------- ------- --------- -------
Totals.................................. 680,478 221,599 1,804,337 703,443
======= ======= ========= =======
- ---------------
(1) Leases covering less than half of the undeveloped acreage will expire within
the next three years. However, we expect to evaluate this acreage prior to
its expiration. Our leases generally provide that the leases will continue
past their primary terms if oil or gas in commercial quantities is being
produced from a well on such leases.
PRODUCTIVE WELL SUMMARY
The following table sets forth Belco's ownership in productive wells at
December 31, 2000. Gross oil and gas wells include multiple completions. Wells
with multiple completions are counted only once for purposes of the following
table. Production from various formations in wells without multiple completions
is commingled.
PRODUCTIVE WELLS
------------------
GROSS NET
------- -------
Gas......................................................... 842.0 368.9
Oil......................................................... 1,618.0 699.5
------- -------
Total............................................. 2,460.0 1,068.4
======= =======
MARKETING
There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and gas, the
proximity and capacity of natural gas pipelines and other transportation
facilities, demand for oil and gas, the marketing of competitive fuels and the
effects of state and federal regulations on oil and gas production and sales.
Historically we have not experienced any difficulties in marketing our oil or
gas. The oil and gas industry also competes with other industries in supplying
the energy and fuel requirements of industrial, commercial and individual
customers.
8
11
Although Belco seeks to moderate the impact of price volatility through its
commodity price risk management activities, we remain subject to price
fluctuations for natural gas sold in the spot market due primarily to
seasonality of demand and other factors beyond our control. Domestic oil prices
generally follow worldwide oil prices, which are subject to price fluctuations
resulting from changes in world supply and demand.
PRODUCTION SALES CONTRACTS
In Wyoming, Belco sells all of its natural gas, natural gas liquids and
condensate from its Moxa Arch wells under a market sensitive long term sales
contract with Amoco Energy Trading Corporation (the "Amoco Gas Contract"). The
price payable to Belco under the Amoco Gas Contract for gas is the Northwest
Pipeline Rocky Mountain Index, plus $0.03 per MMBtu, less fuel charges and
gathering fees and adjustments for Btu content. The Amoco Gas Contract was
renewed effective January 1, 1999 for an additional three year period on the
same terms.
All of Belco's current Moxa Arch Wyoming oil and condensate production is
sold at market sensitive prices pursuant to an option held by Amoco.
Our Moxa Arch wells are subject to various gathering agreements with third
parties. Wells drilled under the Amoco Farmout Agreement in the Cow Hollow,
Wilson Ranch, Seven Mile Gulch and Bruff areas are subject to the Gas Gathering
and Processing Agreement dated March 20, 1992 with Northwest Pipeline.
In Texas, Louisiana and Oklahoma, Belco sells its gas to purchasers under
percentage of proceeds or index-based contracts. Under the percentage of
proceeds contract, we receive a fixed percentage of the resale price received by
the purchaser for sales of residue gas and natural gas liquids recovered after
gathering and processing our gas. We receive between 85% and 92% of the proceeds
from residue gas sales and from 85% to 90% of the proceeds from natural gas
liquids sales received by our purchasers when the products are resold. The
residue gas and natural gas liquids sold by these purchasers are sold primarily
based on spot market prices. The revenue received by Belco from the sale of
natural gas liquids is included in natural gas sales. Under indexed-based
contracts, the price per MMBtu we receive for our gas at the wellhead is tied to
indexes published in Inside FERC or Gas Daily, and in most cases is subject to a
discount to the relevant index in lieu of a gathering fee.
All of Belco's oil production is sold under market sensitive or spot price
contracts to various purchasers.
Sales to individual customers constituting 10% or more of total revenues in
2000 were made to Aquila Southwest Pipeline (26%), Amoco Energy Trading (17%),
EOTT Energy Operating LP (14%), Duke Energy Field Services (11%), Enron Reserve
Acquisition Corp. (11%) and Eighty-Eight Oil, LLC (10%).
We believe that the loss of any one of the above customers would not have a
material adverse effect on our results of operations or our financial condition.
PRICE RISK MANAGEMENT TRANSACTIONS
Commodity Price Risk Management ("CPRM")
With the objective of achieving more predictable revenues and cash flows
and reducing the exposure to fluctuations in gas and oil prices, we have entered
into price risk management transactions of various types with respect to both
natural gas and oil, as described below. While the use of these arrangements
limits the downside risk of adverse price movements to a certain extent, it may
also limit future revenues from favorable price movements. We entered into price
risk management transactions with respect to a substantial portion of our
estimated oil production and approximately 60% of our estimated gas production
for 2000 and lesser amounts of our estimated production for 2001 and beyond. We
continue to evaluate whether to enter into additional such transactions for 2001
and beyond. We expect to reduce the current amount of price risk management
contracts to largely phase out such transactions that we have in place over the
next 12 to 18 months in an effort to limit our future exposure to the
mark-to-market accounting rules requiring the immediate recognition of non-cash
unrealized gains and losses that cause large unpredictable swings in
9
12
reported results of operations, related earnings per share and shareholder
equity. In addition, we may determine from time to time to terminate our then
existing hedging and other risk management positions.
All of our price risk management transactions are carried out in the
over-the-counter market and not on the New York Mercantile Exchange ("NYMEX").
These financial counterparties all have at least an investment grade credit
rating. All of these transactions provide solely for financial settlements
relating to closing prices on the NYMEX.
The following is a summary of the types of price risk management
transactions in effect as of December 31, 2000.
Swaps. Since all of Belco's natural gas and oil is sold on "floating" or
market related prices, we have entered into financial swap transactions which
convert a floating price into a fixed price for a future month. For any
particular swap transaction, the counterparty is required to make a payment to
Belco in the event that the NYMEX Reference Price for any settlement period is
less than the swap price for such hedge, and we are required to make a payment
to the counterparty in the event that the NYMEX Reference Price for any
settlement period is greater than the swap price for such hedge.
Reverse Swaps. When Belco determines it desires to reduce the amount of
swaps because of an assumed favorable outlook for prices, it enters into a
reverse swap. Under such a transaction, our role and the role of the
counterparty are reversed.
Collars. A collar provides for an average floor price and an average
ceiling price. For any particular collar transaction, the counterparty is
required to make a payment to Belco if the average NYMEX Reference Price for the
reference period is below the floor price for such transaction, and we are
required to make payment to the counterparty if the average NYMEX Reference
Price is above the ceiling price for such transaction.
Options, Puts and Straddles. When Belco believes that it will receive a
sufficiently high cash premium (or other consideration) for granting the
counterparty a call or put option, it may enter into such a transaction. If we
sold a $20.00 call on oil for $0.40 a barrel in a given month and prices
averaged $19.00 a barrel for such month, we would receive a net realization per
barrel of $19.40 ($19.00 plus the $0.40 premium). However, if for that month the
price of oil averaged $20.00 or higher per barrel, we would receive a net
realization of $20.40 (the call price, $20.00, plus $0.40).
A limited number of these transactions contain negotiated knockout,
extendable or leverage provisions. These provisions either limit price
protection beyond a specific level, contain tiered pricing provisions, allow the
option to be extended for a period of time, or provide for payment based upon a
multiple of the underlying notional volume. The transactions described in this
paragraph and any sold options are non-hedge instruments and required to be
marked to market as to their value on the last day of the accounting period.
We sell Wyoming natural gas at prices based on the Northwest Pipeline Rocky
Mountain Index ("NPRMI") and the Colorado Interstate Gas Co.-Rocky Mountain
Index ("CIGCo.-RMI") (indices of prices for gas delivered at various delivery
points on the Northwest Pipeline and the CIGCo. pipeline in the Northern Rocky
Mountain area). For a portion of the natural gas sold against these indices, we
have entered into basis swaps that require the counterparty to make a payment to
Belco in the event that the average NYMEX Reference Price per MMBtu for gas
delivered to Henry Hub, Louisiana for a reference period exceeds the average
price for gas delivered to the Northwest Pipeline in the Rocky Mountains as
reflected in the NPRMI (the most liquid Rocky Mountain hub) for such reference
period by more than a stated differential, and requires Belco to make a payment
to the counterparty in the event that the NYMEX Reference Price for Henry Hub
exceeds the price for NPRMI gas by less than the stated differential (or in the
event that the NPRMI price exceeds the Henry Hub price).
TEXAS SEVERANCE TAX ABATEMENT
Production from natural gas wells that have been certified as tight
formations or deep wells by the Texas Railroad Commission ("high cost gas
wells") and that were spudded or completed during the period from
10
13
May 24, 1989 to September 1, 1996 qualify for an exemption from the 7.5%
severance tax in Texas on natural gas and natural gas liquids produced by such
wells prior to August 31, 2001. The natural gas production from wells drilled on
certain of our properties in the Austin Chalk area qualify for this tax
exemption. In addition, high cost gas wells that are spudded or completed during
the period from September 1, 1996 to August 31, 2010 are entitled to receive a
severance tax reduction upon obtaining a high cost gas certification from the
Texas Railroad Commission within 180 days after first production. The tax
reduction is based on a formula composed of the statewide "median" (as
determined by the State of Texas from producer reports) and the producer's
actual drilling and completion costs. More expensive wells will receive a
greater amount of tax credit. This tax rate reduction remains in effect for 10
years or until the aggregate tax credits received equal 50% of the total
drilling and completion costs.
SECTION 29 TAX CREDIT
The natural gas production from wells drilled on certain of our properties
in the Wyoming Moxa Arch Trend and Golden Trend Field in Oklahoma qualifies for
the Section 29 Tax Credit. The Section 29 Tax Credit is an income tax credit
against regular federal income tax liability with respect to sales of our
production of natural gas produced from tight gas sand formations, subject to a
number of limitations. Fuels qualifying for the Section 29 Tax Credit must be
produced from a well drilled or a facility placed in service after November 5,
1990 and before January 1, 1993, and be sold before January 1, 2003.
The basic credit, which is currently approximately $0.52 per MMBtu ($0.59
per Mcf) of natural gas produced from tight sand reservoirs and approximately
$1.05 per MMBtu of natural gas produced from Devonian Shale, is computed by
reference to the price of crude oil and is phased out as the price of oil
exceeds $23.50 per Bbl in 1979 dollars (as adjusted for inflation) with complete
phaseout if such price exceeds $29.50 per Bbl in 1979 dollars (as adjusted for
inflation). Under this formula, the commencement of phaseout would be triggered
if the average price for crude oil rose above approximately $47 per Bbl in
current dollars. We generated approximately $0.5 and $0.6 million of Section 29
Tax Credits in 2000 and 1999, respectively. The Section 29 Tax Credit may not be
credited against the alternative minimum tax, but under certain circumstances
may be carried over and applied against regular tax liability in future years.
Therefore, no assurances can be given that our Section 29 Tax Credits will
reduce our federal income tax liability in any particular year.
REGULATION
General. The oil and gas industry is extensively regulated by federal,
state and local authorities. In particular, oil and gas production operations
and economics are affected by price controls, environmental protection statutes
and regulations, tax statutes and other laws relating to the petroleum industry,
as well as changes in such laws, changing administrative regulations and the
interpretations and application of such laws, rules and regulations. Oil and gas
industry legislation and agency regulation are under constant review for
amendment and expansion for a variety of political, economic and other reasons.
Regulation of Natural Gas and Oil Exploration and Production. Belco's
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. Belco's operations are also subject to various conservation
laws and regulations. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells which may be drilled
and the unitization or pooling of oil and gas properties. In this regard, some
states (such as Oklahoma) allow the forced pooling or integration of tracts to
facilitate exploration while other states (such as Texas) rely on voluntary
pooling of lands and leases. In areas where pooling is voluntary, it may be more
difficult to form units and, therefore, more difficult to develop a project if
the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. The effect of these regulations may
limit the amount of oil and gas we can produce from our wells and may
11
14
limit the number of wells or the locations at which we can drill. The regulatory
burden on the oil and gas industry increases our costs of doing business and,
consequently, affects our profitability. Inasmuch as such laws and regulations
are frequently expanded, amended or reinterpreted, we are unable to predict the
future cost or impact of complying with such regulations.
Belco has operations located on federal oil and gas leases, which are
administered by the MMS. Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed MMS
regulations. In addition to permits required from other agencies (such as the
Army Corps of Engineers and the Environmental Protection Agency (the "EPA")),
lessees must obtain a permit from the MMS prior to the commencement of drilling.
The MMS also has regulations restricting the flaring or venting of natural gas,
liquid hydrocarbons and oil without prior authorization. The MMS generally
requires that lessees post substantial bonds or other acceptable assurances that
such obligations will be met. The cost of such bonds or other surety can be
substantial and there is no assurance that bonds or other surety can be obtained
in all cases. Under certain circumstances, the MMS may require Company
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially and adversely affect our financial condition and
operations.
Belco does not anticipate that compliance with existing federal, state and
local laws, rules and regulations will have a material or significantly adverse
effect upon the capital expenditures, earnings or competitive position of Belco.
Regulation of Natural Gas and Oil Sales and Transportation. Sales prices
of crude oil, condensate, gas liquids and natural gas are not currently
regulated. State and federal laws regulations governing transportation of these
commodities by intrastate and interstate pipelines, although they do not
directly apply to Belco, nonetheless have an indirect effect upon the
exploration and production business due to legal and regulatory impact upon the
cost and availability of pipeline capacity. Belco does not believe that its
business will be affected by any laws and regulations governing pipeline
transportation differently than any other similarly situated company with which
Belco competes.
Environmental Matters. Our operations are subject to stringent federal,
state and local laws and regulations governing the discharge of materials into
the environment or otherwise relating to environmental protection. Numerous
governmental agencies, such as the U.S. Environmental Protection Agency ("EPA"),
issue regulations to implement and enforce such laws, which often require
difficult and costly compliance measures that carry substantial administrative,
civil and criminal penalties or may result in injunctive relief for failure to
comply. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentrations of
various substances that can be released into the environment in connection with
drilling and production activities, limit or prohibit construction or drilling
activities on certain lands lying within wilderness, wetlands, ecologically
sensitive and other protected areas, require remedial action to prevent
pollution from former operations, and impose substantial liabilities for
pollution resulting from our operations. This regulatory burden on the oil and
gas industry increases the cost of doing business and consequently affects its
profitability. Changes in environmental laws and regulations occur frequently,
and any changes that result in more stringent and costly waste handling,
storage, transport, disposal or cleanup requirements could materially adversely
affect our operations and financial position, as well as those of the oil and
gas industry in general. While we believe that our current operations are in
substantial compliance with current applicable environmental laws and
regulations, there is no assurance that this trend will continue in the future.
The Comprehensive Environmental Response, Compensation and Liability Act,
as amended ("CERCLA"), also known as "Superfund," and comparable state laws
impose liability without regard to fault or the legality of the original
conduct, on certain classes of persons who are considered to be responsible for
the release of a "hazardous substance" into the environment. These persons
include the owner and operator of the disposal site or sites where the release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at the site. Under CERCLA, such persons may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment, for damages
to natural resources and for the costs of certain health studies, and it is not
uncommon for
12
15
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the release of hazardous
substances or other pollutants into the environment. Although we handle
hazardous substances in the ordinary course of business, we are not aware of any
hazardous substance contamination which has a material adverse effect on us.
The Resource Conservation and Recovery Act, as amended ("RCRA") and
comparable state laws generally does not regulate most wastes generated by the
exploration and production of oil and gas. Specifically, RCRA excludes from the
definition of hazardous waste "drilling fluids, produced waters, and other
wastes associated with the exploration, development, or production of crude oil,
natural gas or geothermal energy." However, these wastes may still be regulated
by EPA or state agencies as solid waste. Moreover, ordinary industrial wastes,
such as paint wastes, waste solvents, laboratory wastes, and waste compressor
oils, may be regulated as hazardous waste. Although the costs of managing solid
and hazardous waste may be significant, we do not expect to experience more
burdensome costs than similarly situated companies involved in oil and gas
exploration and production.
We own or lease properties that have been used in the past for the
exploration and production of oil and gas. Although we have utilized operating
and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by us or on or under other locations where such
wastes have been taken for disposal. In addition, many of these properties have
been operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under our control. These properties and the
wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state
laws. Under such laws, we could be required to remove or remediate previously
disposed wastes (including waste disposed of or released by prior owners or
operators) or property contamination (including groundwater contamination by
prior owners or operators), or to perform remedial plugging or pit closure
operations to prevent future contamination.
The Federal Water Pollution Control Act of 1972, as amended ("FWPCA"), also
known as the Clean Water Act and analogous state laws impose restrictions and
strict controls regarding the discharge of pollutants including produced waters
and other oil and gas wastes, into state waters or waters of the United States.
The discharge of pollutants into regulated waters is prohibited, except in
accord with the terms of a permit issued by EPA or the state. These
proscriptions also prohibit certain activity in wetlands unless authorized by a
permit issued by the U.S. Army Corps of Engineers. Sanctions for unauthorized
discharges include administrative, civil and criminal penalties, as well as
injunctive relief.
The Oil Pollution Act of 1990, as amended ("OPA"), pertains to the
prevention of and response to spills or discharges of hazardous substances or
oil into navigable water of the United States. Under OPA, a person owning or
operating a facility or equipment from which there is a discharge or threat of a
discharge of oil into or upon navigable waters or adjoining shorelines is
liable, regardless of fault, as a "responsible party" for removal costs and
damages. Federal law imposes strict, joint and several liability on facility
owners for containment and clean-up costs and certain other damages, including
natural resource damages arising from a spill. The OPA establishes a liability
limit for onshore facilities of $350 million; however, a party cannot take
advantage of this liability limit if the spill is caused by gross negligence or
willful misconduct or resulted from a violation of a federal safety,
construction, or operating regulation. If a party fails to report a spill or
cooperate in the cleanup, the liability limits likewise do not apply. Federal
regulations under the OPA and the FWPCA also require certain owners and
operators of facilities that store or otherwise handle oil, such as us, to
prepare and implement spill prevention, control and countermeasure plans and
spill response plans relating to possible discharge of oil into surface waters.
We believe that our operations are in substantial compliance with the
requirements of the OPA and FWPCA and that any non-compliance would not have a
material adverse effect on us.
OPERATING HAZARDS AND INSURANCE
Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond our control. These risks include the risk that
no commercially productive oil or natural gas reservoirs will be encountered,
that operations may be curtailed, delayed or canceled as a result of title
problems, weather
13
16
conditions, compliance with governmental requirements, mechanical difficulties
or shortages or delays in the delivery of equipment. Our ability to market our
production may be limited depending upon the availability or capacity of
gathering systems, pipelines or processing facilities. There can be no assurance
that new wells drilled by us will be productive or that we will recover all or
any portion of our investment. Drilling for oil and natural gas may involve
unprofitable efforts, not only from dry wells, but also from wells that are
productive but do not produce sufficient net revenues to return a profit after
drilling, operating and other costs. In addition, our properties may be
susceptible to hydrocarbon drainage from production by other operators on
adjacent properties.
Industry operating risks include the risk of fire, explosions, blow-outs,
pipe failure, abnormally pressured formations and environmental hazards such as
oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of
any of these events could result in substantial losses to Belco due to injury or
loss of life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations.
Additionally, certain of our oil and gas operations are located in an area that
is subject to tropical weather disturbances, some of which can be severe enough
to cause substantial damage to facilities and possibly interrupt production.
Belco maintains customary oil and gas related third party liability
coverage, which it must renew annually, that insures us against certain sudden
and accidental risks associated with drilling, completing and operating its
wells. There can be no assurance that this insurance will be adequate to cover
any losses or exposure to liability or that we will be able to renew our
coverage annually. Belco and its subsidiaries carry workers' compensation
insurance in all states in which they operate. While we believe this coverage is
customary in the industry, it does not provide complete coverage against all
operating risks.
TITLE TO PROPERTIES
Title to properties is subject to royalty, overriding royalty, carried, net
profits, working and other similar interests and contractual arrangements
customary in the oil and gas industry, as well as to liens for current taxes not
yet due and to other encumbrances. As is customary in the industry in the case
of undeveloped properties, little investigation of record title is made at the
time of acquisition of leasehold interests (other than a preliminary review of
local records). Investigations, including a title opinion of local counsel, are
generally made before commencement of drilling operations. To the extent title
opinions or other investigations reflect title defects, Belco, rather than the
seller of the undeveloped property, is typically responsible to cure any such
title defects at its expense. If we were unable to remedy or cure title defect
of a nature such that it would not be prudent to commence drilling operations on
the property, we could suffer a loss of our entire investment in the property.
From time to time our title to oil and gas properties is challenged through
legal proceedings. Under the terms of certain of our joint development,
participation and farmout agreements, our interest (other than interests
acquired through holding of leasehold interests prior to spudding of the well)
in each well is conveyed to us upon the successful completion of the well or
satisfaction of other conditions.
EMPLOYEES
As of December 31, 2000, Belco had 167 full time employees, none of whom
are represented by organized labor unions. We consider our employee relations to
be good.
OFFICE AND EQUIPMENT
Belco maintains its executive offices at 767 Fifth Avenue, New York, New
York. We pay Robert A. Belfer, Chairman of the Board and Chief Executive
Officer, a fee of approximately $250,000 per annum as of 1996 for office space
and services provided through such office. This fee is indexed to the consumer
price index. The fee is based on the actual cost of such office space pro-rated
to the amount utilized in our operations. We believe the fee compares favorably
to the terms that might have been available from a non-affiliated party. See
"Certain Relationships and Related Transactions." Belco owns a building in
Dallas, Texas, containing approximately 65,000 square feet, which serves as the
operations headquarters. We lease
14
17
5,796 square feet of office space in Tulsa, Oklahoma pursuant to a lease that
terminates on August 31, 2003. We also lease 1,748 square feet of office space
in Midland, Texas pursuant to a lease that terminates on February 28, 2002.
Additionally, we own a property in Granger, Wyoming consisting of a metal
building and associated four acres, used by Belco as a production office and
yard. We also maintain an inventory of field equipment and materials including
tubular goods, compressors, pumping units and field vehicles.
FORWARD-LOOKING INFORMATION AND RISK FACTORS
This document includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements
other than statements of historical facts included in this document (including
the information incorporated by reference herein), including without limitation
statements regarding planned capital expenditures, the availability of capital
resources to fund capital expenditures, estimates of proved reserves, the number
of anticipated wells to be drilled in 2001 and thereafter, Belco's financial
position, business strategy and other plans and objectives for future
operations, are forward-looking statements. Although we believe that the
expectations reflected in such forward-looking statements are reasonable, we can
give no assurance that such expectations will prove to have been correct. There
are numerous uncertainties inherent in estimating quantities of proved oil and
natural gas reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond our control. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in an exact way, and the accuracy of
any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, estimates
made by different engineers often vary from one another. In addition, results of
drilling, testing and production subsequent to the date of an estimate may
justify revisions of such estimate and such revisions, if significant, would
change the schedule of any further production and development drilling.
Accordingly, reserve estimates are generally different from the quantities of
oil and natural gas that are ultimately recovered. Additional important factors
that could cause actual results to differ materially from our expectations are
described elsewhere herein. All written and oral forward-looking statements
attributable to Belco or persons acting on its behalf are expressly qualified in
their entirety by such factors.
OIL AND GAS PRICES ARE VOLATILE, AND AN EXTENDED DECLINE IN PRICES COULD
ADVERSELY AFFECT BELCO'S REVENUES, CASH FLOWS AND PROFITABILITY.
Our revenues, operating results, profitability, future rate of growth and
the carrying value of our oil and gas properties depend substantially upon the
prevailing prices of oil and gas. We expect the markets for oil and gas to
continue to be volatile. Prices also affect the amount of cash flow available
for capital expenditures and our ability to borrow money or raise additional
capital. The amount we can borrow from banks is subject to redetermination based
on current prices. In addition, we may have ceiling test writedowns when prices
decline. Lower prices may also reduce the amount of oil and gas that we can
produce economically.
We cannot predict future oil and gas prices. Factors that can cause oil and
gas prices to fluctuate include:
- relatively minor changes in the supply of and demand for oil and gas;
- market uncertainty;
- the level of consumer and industrial product demand;
- weather conditions;
- domestic and foreign governmental regulations;
- the price and availability of alternative fuels;
- political conditions in the Middle East;
- the foreign supply of oil and gas;
15
18
- the price of oil and gas imports; and
- overall economic conditions.
OUR RECENT COMMODITY PRICE RISK MANAGEMENT ACTIVITIES HAVE RESULTED IN LOSSES.
OUR COMMODITY PRICE RISK MANAGEMENT TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS.
In 1999 and 2000, we recorded non-hedge commodity price risk management
losses of $36.5 million and $137.6 million, respectively. These losses consisted
of $2.4 million and $34.0 million in cash settlements and $34.1 million and
$103.6 million in unrealized non-cash mark-to-market losses due to substantial
increases in commodity prices for 1999 and 2000, respectively. We expect to
incur additional hedge and non-hedge related cash settlement costs through
calendar year 2001 assuming commodity prices remain at current levels. We
believe that our losses from commodity price risk management transactions will
decline due to price decreases since December 31, 2000. We can give you no
assurance as to the ultimate size of these losses.
For the year 2001, Belco currently has approximately 6,920 BOPD and 67,000
MMBtu of gas per day committed at average prices of $19.15 per Bbl of oil and
$2.08 per MMBtu of gas. The committed volumes assume the NYMEX forward curve
reference prices as of February 14, 2001. No estimate of settlements or
mark-to-market gains or losses are determinable as such amounts are contingent
upon commodity prices at the time of production. We cannot assure you that we
will not experience additional losses from these activities.
Certain of Belco's commodity price risk management arrangements require
Belco to deliver cash collateral or other assurances of performance to the
counterparties in the event that Belco's payment obligations with respect to its
commodity price risk management transactions exceed certain levels. Two of the
inherent risks of a price risk management program are margin requirement and
collateralization. Certain transactions may be subject to margin calls under
certain conditions including change of ownership control, rating agency activity
or default. Belco's collateral requirement at December 31, 2000 was $36.5
million in letters of credit and $15.0 million in letters of credit as of March
19, 2001.
In order to manage our exposure to price volatility in marketing our oil
and gas, we enter into oil and gas price risk management arrangements for a
portion of our expected production. These transactions are limited in life.
While intended to reduce the effects of volatile oil and gas prices, commodity
price risk management transactions may limit our potential gains if oil and gas
prices were to rise substantially over the price established by the
arrangements. In addition, our commodity price risk management transactions may
expose us to the risk of financial loss in certain circumstances, including
instances in which:
- our production is less than expected;
- there is a widening of price differentials between delivery points for
our production and time delivery point assumed in the hedge arrangement;
or
- the counterparties to our contracts fail to perform the contracts.
OUR CREDIT AGREEMENT AND INDENTURES RESTRICT OUR ABILITY TO PAY DIVIDENDS;
DIVIDENDS ON OUR PREFERRED STOCK MAY NOT BE PERMITTED AFTER THE FIRST QUARTER OF
2001.
Our ability to pay dividends on our capital stock will be dependent on our
future performance and liquidity. In addition, our credit agreement and the
indentures governing our subordinated debt contain restrictions on our ability
to pay cash dividends on our capital stock, including our outstanding preferred
stock. As a result of reporting substantial unrealized non-cash mark-to-market
losses required by existing accounting rules, dividends on our preferred stock
may be limited or prohibited by the restrictions contained in our 10- 1/2% bond
indenture. Payment of the March 2001 dividend on our preferred stock will be
permitted. Subsequent dividends will be contingent upon the sale of equity
interests or sufficient net income to restore dividend payment capacity under
the indenture. At the present time, we do not estimate that first quarter 2001
net income, as defined in the indenture, will be sufficient to restore this
dividend payment capacity.
16
19
WE MAY NOT BE ABLE TO GENERATE OR OBTAIN SUFFICIENT CAPITAL TO EXECUTE OUR
OPERATING STRATEGY.
We have experienced, and expect to continue to experience, substantial
capital needs as a result of our exploration, development and acquisitions
strategies. We have historically addressed our capital needs by using our bank
credit facility, using cash provided by operating activities and issuing debt
and equity securities.
We continue to examine the following alternative sources of capital:
- bank borrowings or the issuance of debt securities;
- the sale of common stock or preferred stock;
- sales of non-strategic properties;
- sales of prospect and technical information; and
- joint venture financing.
The availability of these sources of capital will depend upon a number of
factors, some of which are beyond our control. These factors include general
economic and financial market conditions, oil and gas prices and the value and
performance of Belco. We will be unable to fully execute our operating strategy
if we cannot generate or obtain sufficient capital from these or other sources.
ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE.
This Form 10-K contains estimates of our proved reserves and the estimated
future net revenues from our proved reserves. These estimates are based upon
various assumptions, including assumptions required by the SEC relating to oil
and gas prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. The process of estimating oil and gas reserves is
complex. The process involves significant decisions and assumptions in the
evaluation of available geological, geophysical, engineering and economic data
for each reservoir. Therefore, these estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from these estimates. Such variations may be
material. In addition, we may adjust estimates of proved reserves to reflect
production history, results of exploration and development drilling, prevailing
oil and gas prices and other factors, many of which are beyond our control. In
certain situations, hydrocarbon reservoirs underlying our properties may extend
beyond the boundaries of our own acreage into acreage owned by others. In this
case, our properties may also be susceptible to hydrocarbon drainage from
production by the operators on those adjacent properties. Any significant
variance could materially affect the estimated quantities and present value of
our proved reserves.
At December 31, 2000, approximately 35% of our estimated proved reserves
were undeveloped. Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling operations. The estimates of our future
reserves include the assumption that we will make significant capital
expenditures to develop our reserves, including approximately $60.0 million in
2001. Although we have prepared estimates of our oil and gas reserves and the
costs associated with these reserves in accordance with industry standards, we
cannot assure you that the estimated costs are accurate, that development will
occur as scheduled or that the results will be as estimated.
You should not assume that the present value referred to in this Form 10-K
is the current market value of our estimated oil and gas reserves. In accordance
with SEC requirements, the estimate of present value is generally based on
prices and costs as of the date of the estimate. Actual future prices and costs
may be materially higher or lower than the prices and costs as of the date of
the estimate. Any changes in consumption by oil and gas purchasers or in
governmental regulations or taxation will also affect actual future net cash
flows.
We have included in this Form 10-K certain reserve information and present
values that were calculated using oil and gas prices at December 31, 2000. We
have calculated this reserve information using estimates of
17
20
oil and gas reserves at December 31, 2000. As described above, the present
values may not represent actual values of our proved reserves.
The timing of both the production and the expenses from the development and
production of oil and gas properties will affect both the timing of actual
future net cash flows from proved reserves and their present value. In addition,
the 10% discount factor, which is required by the SEC to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the
most accurate discount factor. The effective interest rate at various times and
the risks associated with our business or the oil and gas industry in general
will affect the accuracy of the 10% discount factor.
LEVERAGE MAY ADVERSELY AFFECT OUR FINANCIAL CONDITION, OUR ABILITY TO FINANCE
OUR OPERATIONS AND THE CONDUCT OF OUR BUSINESS.
As of December 31, 2000, our long-term debt was $402.0 million, including
$141.0 million outstanding under our bank credit facility. Our long-term debt
represented approximately 87% of our total capitalization at December 31, 2000.
Our debt affects our operations in several important ways, including the
following:
- a significant portion of our cash flow from operations is used to pay
interest on our borrowings;
- the covenants contained in the agreements governing our debt limit our
ability to borrow additional funds or to dispose of assets;
- the covenants contained in the agreements governing our debt may affect
our flexibility in planning for, and reacting to, changes in business
conditions;
- a high level of debt may impair our ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes; and
- the terms of the agreements governing our debt permit our creditors to
accelerate payments upon an event of default or a change of control.
In addition, we may incur additional debt in order to make future
acquisitions or develop our properties. A higher level of debt increases the
risk that we may default on our debt obligations. Our ability to meet our debt
obligations and to reduce our level of debt depends on our future performance.
General economic conditions and financial, business and other factors affect our
operations and our future performance. Many of these factors are beyond our
control.
If we are unable to repay our debt at maturity out of cash on hand, we
could attempt to refinance such debt, sell assets or repay such debt with the
proceeds of an equity offering. We cannot assure you that we will be able to
generate sufficient cash flow to pay the interest on our debt or that future
working capital, borrowings or equity financing will be available to pay or
refinance such debt. Factors that will affect our ability to raise cash through
an offering of our capital stock or a refinancing of our debt include financial
market conditions and our value and performance at the time of such offering or
other financing. We cannot assure you that any such offering or refinancing can
be successfully completed.
In addition, our bank borrowing base is subject to semi-annual
redeterminations. We could be forced to repay a portion of our bank borrowings
due to redeterminations of our borrowing base. We cannot assure you that we will
have sufficient funds to make such repayments. If we are not able to negotiate
renewals of our borrowings or arrange new financing, we may have to sell
significant assets. Any such sale could have a material adverse effect on our
business and financial results.
LOWER OIL AND GAS PRICES INCREASE THE RISK OF CEILING LIMITATION WRITEDOWNS.
We use the full cost method to account for our oil and gas operations. As a
result, we capitalize the cost to acquire, explore for and develop oil and gas
properties. Under full cost accounting rules, the net capitalized costs of oil
and gas properties may not exceed a "ceiling limit," which is based upon the
present value of estimated future net cash flows from proved reserves,
discounted at 10%, plus the lower of cost or fair market
18
21
value of unproved properties. If net capitalized costs of oil and gas properties
exceed the ceiling limit, we must charge the amount of the excess to earnings.
This is called a "ceiling limitation writedown." This charge does not reduce the
cash flow from operating activities, but does reduce the book value of our net
tangible assets and our stockholders' equity. The risk that we will be required
to write down the carrying value of oil and gas properties increases when the
oil and gas prices are low or volatile. In addition, writedowns may occur if we
experience substantial downward adjustments to our estimated proved reserves,
increases in estimates of development costs or deterioration in exploration and
exploitation results. In 1998 and 1997, we recorded $229.0 million ($148.9
million after-tax) and $150.0 million ($97.5 million after-tax), respectively,
in non-cash ceiling limitation writedowns after applying substantially lower
commodity prices to estimated recoverable reserves. We may experience ceiling
limitation writedowns in the future.
OUR ABILITY TO REPLACE PRODUCTION WITH NEW RESERVES IS HIGHLY DEPENDENT ON
ACQUISITIONS OR SUCCESSFUL DEVELOPMENT AND EXPLORATION ACTIVITIES.
In general, the volume of production from oil and gas properties declines
as reserves are depleted. Our reserves will decline as they are produced, unless
we acquire properties with proved reserves or conduct successful exploration and
development activities. Our future oil and gas production is highly dependent
upon our level of success in finding or acquiring additional reserves. The
business of exploring for, developing or acquiring reserves is capital intensive
and uncertain. We may be unable to make the necessary capital investments to
maintain or expand our oil and gas reserves if cash flow from operations is
reduced and external sources of capital become limited or unavailable. We cannot
assure you that our future exploration and development activities will result in
additional proved reserves or that we will be able to drill productive wells at
acceptable costs. In addition, we may not be able to acquire new properties with
proved reserves at acceptable costs.
OUR EXPLORATION ACTIVITIES INVOLVE A HIGH DEGREE OF RISK AND MAY NOT BE
COMMERCIALLY SUCCESSFUL.
Oil and gas exploration involves a high degree of risk that hydrocarbons
will not be found, that they will not be found in commercial quantities, or that
their production will be insufficient to recover drilling, completion and
operating costs. The 3-D seismic data and other technologies we may use do not
allow us to know conclusively prior to drilling a well that oil or gas is
present or economically producible. The cost of drilling, completing, and
operating a well is often uncertain, and cost factors can adversely affect the
economics of a project. Furthermore, completion of a well does not guarantee
that it will be profitable or even that it will result in recovery of drilling,
completion and operating costs. Therefore, we may not earn revenues with respect
to, or recover costs spent on, our exploration activities.
OUR SECONDARY RECOVERY PROJECTS REQUIRE SIGNIFICANT EXPENDITURES AND MAY NOT BE
COMMERCIALLY SUCCESSFUL.
Secondary recovery operations, such as waterflooding projects, may require
us to spend a significant amount of capital without any increase in production.
Although waterflooding requires significant capital expenditures, the total
amount of reserves that can be recovered through waterflooding is uncertain. In
addition, there is generally a delay between the initiation of water injection
into a formation containing hydrocarbons and any increase in production that may
result from the injection. The degree of success, if any, of any secondary
recovery program depends on a large number of factors. These factors include the
porosity, permeability and heterogeneity of the formation, the technique used
and the location of injection wells.
OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND GAS DRILLING AND
PRODUCTION ACTIVITIES.
Oil and gas drilling and production activities are subject to numerous
risks, including the risk that no commercially productive oil or gas reservoirs
will be found. The cost of drilling and completing wells is often uncertain. Oil
and gas drilling and production activities may be shortened, delayed or canceled
as a result of a variety of factors, many of which are beyond our control. These
factors include:
- unexpected drilling conditions;
- pressure irregularities in formations;
19
22
- equipment failures or accidents;
- weather conditions; and
- shortages in experienced labor or shortages or delays in the delivery of
equipment.
We cannot assure you that the new wells we drill or participate in will be
productive or that we will recover all or any of our investment. Drilling for
oil and gas may be unprofitable. Drilling activities can result in dry holes and
wells that are productive but do not produce sufficient net revenues after
operating and other costs. In addition, our properties may be susceptible to
hydrocarbon draining from production by third party operations on adjacent
properties.
HIGHER OIL AND GAS PRICES ADVERSELY AFFECT THE COST AND AVAILABILITY OF DRILLING
AND PRODUCTION SERVICES.
Higher oil and gas prices, such as those we are currently experiencing,
generally stimulate increased demand and result in increased prices for drilling
rigs, crews and associated supplies, equipment and services. In the past, we
have had difficulty securing drilling equipment or crews in certain of our core
areas. We have recently experienced higher costs for drilling rigs and other
related services.
OUR INDUSTRY EXPERIENCES MANY OPERATING RISKS THAT COULD CAUSE US SUBSTANTIAL
LOSSES.
Our operating risks include the risk of fire, explosions, blow-outs, pipe
failure, abnormally pressured formations and environmental hazards.
Environmental hazards include oil spills, gas leaks, ruptures or discharges of
toxic gases. If any of these industry operating risks occur, we could have
substantial losses. Substantial losses may be caused by:
- injury or loss of life;
- severe damage to or destruction of property, natural resources and
equipment;
- pollution or other environmental damage;
- clean-up responsibilities;
- regulatory investigations and penalties; and
- suspension of operations.
In accordance with industry practice, we maintain insurance against some,
but not all, of the risks described above. We cannot assure you that our
insurance will be adequate to cover losses or liabilities. Also, we cannot
predict the continued availability of insurance at premium levels that justify
its purchase.
WE OPERATE IN A HIGHLY COMPETITIVE INDUSTRY, WHICH MAY ADVERSELY AFFECT OUR
OPERATIONS.
We operate in a highly competitive environment. We compete with other oil
and gas companies for the acquisition of desirable oil and gas properties and
the equipment labor required to develop and operate such properties. We also
compete with other oil and gas companies in the marketing and sale of oil and
gas. Many of our competitors have financial and other resources substantially
greater than ours.
OUR ACQUISITIONS ARE SUBJECT TO THE RISKS OF THE UNCERTAINTIES OF RECOVERABLE
RESERVES AND POTENTIAL LIABILITIES.
Our recent growth is due in part to acquisitions of producing properties.
The successful acquisition of producing properties requires an assessment of a
number of factors beyond our control. These factors include recoverable
reserves, future oil and gas prices, operating costs and potential environmental
and other liabilities. Such assessments are inexact and their accuracy is
inherently uncertain. In connection with our assessments, we perform a review of
the subject properties, which we believe is generally consistent with industry
practices. However, such a review will not reveal all existing or potential
problems. In addition, our review may not permit us to become sufficiently
familiar with the properties to fully assess their deficiencies and
capabilities. We do not inspect every well. Even when we inspect a well, we do
not always discover structural, subsurface and environmental problems that may
exist or arise.
20
23
We are generally not entitled to contractual indemnification for preclosing
liabilities, including environmental liabilities. Normally, we acquire interests
in properties on an "as is" basis with limited remedies for breaches of
representations and warranties. In addition, competition for producing oil and
gas properties is intense and many of our competitors have financial and other
resources which are substantially greater than those available to us. Therefore,
we cannot assure you that we will be able to acquire oil and gas properties that
contain economically recoverable reserves or that we will complete such
acquisitions on acceptable terms.
OUR OIL AND GAS OPERATIONS ARE SUBJECT TO VARIOUS FEDERAL, STATE AND LOCAL LAWS
AND REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS.
Our oil and gas operations are subject to various federal, state and local
regulations. These regulations may be changed in response to economic or
political conditions. Matters regulated include discharge permits for drilling
operations, drilling and abandonment bonds, reports concerning operations, the
spacing of wells and unitization and pooling of properties and taxation. From
time to time, federal, state and local governments allege that we have not
complied with their regulations and seek to impose fines on us. We cannot assure
you that we will not be liable for substantial fines in the future for failing
to comply with federal, state or local laws or regulations.
At various times, regulatory agencies have imposed price controls and
limitations on production. In order to conserve supplies of oil and gas, these
agencies have restricted the rates of flow of oil and gas wells below actual
production capacity. Under federal and state environmental statutes, owners and
operators of certain defined facilities are strictly liable for spills, subject
to certain limitations. A substantial spill from one of our facilities could
have a material adverse effect on our results of operations, competitive
position or financial condition.
Federal, state and local laws regulate production, handling, storage,
transportation and disposal of oil and gas, by-products from oil and gas and
other substances, materials and wastes produced, used or generated in connection
with oil and gas operations. To date, we have not been required to spend
significant amounts to comply with these laws or to remediate existing
environmental contamination. We believe that we are in substantial compliance
with all applicable laws and regulations. Nevertheless, the requirements of such
laws and regulations change frequently and we cannot predict the ultimate cost
of compliance with existing or future requirements or their effect on our
operations.
THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT OUR ABILITY TO OPERATE.
We depend, and will continue to depend in the foreseeable future, on the
services of our officers and key employees with extensive experience and
expertise in evaluating and analyzing producing oil and gas properties and
drilling prospects, maximizing production from oil and gas properties and
marketing oil and gas production. Our ability to retain our officers and key
employees is important to our continued success and growth. The unexpected loss
of the services of one or more of these individuals could have a detrimental
effect on our business. We do not maintain key man life insurance on any of our
officers or key employees.
THE SIGNIFICANT OWNERSHIP POSITION OF THE BELFER FAMILY COULD LIMIT OUR ABILITY
TO ENTER INTO CERTAIN TRANSACTIONS.
Robert A. Belfer, his son Laurence D. Belfer, his brother-in-law Jack
Saltz, their spouses, and certain trusts for their respective children and
grandchildren own approximately 56% of the outstanding shares of our common
stock at December 31, 2000 and approximately 20% of the currently outstanding
shares of our preferred stock at December 31, 2000. As a result, such
stockholders will be able to effectively control the outcome of certain matters
requiring a stockholder vote, including the election of directors. Such
ownership of common stock may have the effect of delaying, deferring or
preventing a change of control of Belco and may adversely affect the voting and
other rights of other stockholders.
21
24
EXECUTIVE OFFICERS
Officers are elected each year by the Board of Directors following the
Annual Meeting for a term of one year and until the election and qualification
of their successors. The current executive officers of Belco and their ages,
positions with Belco and business experience are presented below:
Robert A. Belfer, age 65, is Chairman of the Board and Chief Executive
Officer of Belco. Mr. Belfer began his career at Belco Petroleum Corporation
("BPC") in 1958 and became Executive Vice President in 1964, President in 1965
and Chairman of the Board in 1984. BPC was an independent oil and gas producer
in the United States and abroad, which went public in 1959. It was one of the
larger independent oil and gas companies in the United States and was included
in Fortune's listing of the 500 largest industrial companies in the United
States prior to merging with InterNorth, Inc. (now Enron Corp.) in 1983.
Following the merger, Mr. Belfer became Chief Operating Officer of BelNorth
Petroleum Corp., a combination of oil and gas producing operations of BPC and
InterNorth. He resigned from his position with InterNorth in 1986 and pursued
personal investments in oil and gas and other industries. In April 1992, Mr.
Belfer founded Belco. In addition to his position at Belco, Mr. Belfer serves on
the board of Enron. Mr. Belfer received his undergraduate degree from Columbia
College (A.B. 1955) and a law degree from the Harvard Law School (J.D. 1958).
Laurence D. Belfer, age 34, is Vice-Chairman of Belco. Mr. Belfer joined
Belco as Vice President in September 1992. He was promoted to Executive Vice
President in May 1995 and Chief Operating Officer in December 1995 was named
President in April 1997 and Vice-Chairman in March 1999. He is a founder and
Chairman of Harvest Management, Inc., a money management firm. Mr. Belfer
graduated from Harvard University (B.A. 1988) and from Columbia Law School (J.D.
1992).
Grant W. Henderson, age 42, is President and Chief Operating Officer of
Belco. He was named Chief Operating Officer in March of 2000 and named President
on March 1, 1999 and prior to his promotion he served as Senior Vice President
- -- Corporate Development. Mr. Henderson was formerly President and Chief
Financial Officer of Coda having joined Coda in October 1993 as Executive Vice
President and Chief Financial Officer. He was elected a director of Coda in 1995
and became President of Coda in February 1996. Mr. Henderson was previously
employed by NationsBank (now Bank of America N.A.), beginning 1981, last serving
as Senior Vice President in its Energy Banking Group. Mr. Henderson is a
graduate of Texas Tech University where he received a B.B.A. degree with a major
in finance.
Dominick J. Golio, age 55, is Senior Vice President -- Finance, Chief
Financial Officer, Treasurer and Secretary of Belco. Mr. Golio began his career
at the New York City office of Arthur Andersen & Co. in 1972. In 1975, he joined
Case, Pomeroy & Company and Felmont Oil Corporation, its publicly traded
affiliate, where he rose to the position of Vice President Finance. Mr. Golio
left Felmont in 1987 following a merger between Felmont and Homestake Mining
Company. He served as Vice President Finance and Administration at both AEG
Corporation, the U.S. electronics subsidiary of Daimler-Benz North America,
until 1991 and at Millmaster Onyx Group, Inc. until September 1993 at which time
he joined Belco. Mr. Golio is a Certified Public Accountant (NY). He holds
undergraduate and graduate degrees from Pace University (B.B.A. Accounting,
1972, M.B.A. -- Taxation, 1978).
Shiv K. Sharma, age 59, is Senior Vice President -- Engineering of Belco.
Mr. Sharma began his career in 1967 as a Reservoir Engineer with Shell Oil
Company. In 1970, he joined BPC as a reservoir engineer and was subsequently
elected to Vice President and Senior Vice President of Engineering, a position
he held until his departure from that company in 1988. From 1988 to 1992, Mr.
Sharma worked as a petroleum consultant for several New York companies. He
served as a director and consultant to Belco commencing April 1992 and was
elected to his present position in April 1994. Mr. Sharma received his degrees
in petroleum technology from the Indian School of Mines (B.S. 1963) and
petroleum engineering from Stanford University (M.S. 1966).
Steven L. Mueller, age 48, is Senior Vice President -- Exploration and
Production of Belco. Mr. Mueller began his career in 1975 as a Geological
Engineer at Tenneco Oil, Lafayette. He advanced at Tenneco Oil to Division
Exploration Manager in 1987. In 1988, Mr. Mueller joined Fina Oil in Houston,
Texas as Exploration
22
25
Manager of South Louisiana, and in 1992 he joined American Exploration in
Houston, Texas as Exploitation Vice President. He was with American Exploration
until October of 1996 when he joined Belco. Mr. Mueller has over 24 years
experience in exploring for and exploiting oil and gas fields both onshore and
offshore. He holds a BS in Geological Engineering from the Colorado School of
Mines (1975).
CERTAIN DEFINITIONS
The definitions set forth below shall apply to the indicated terms as used
in this Form 10-K. All volumes of natural gas referred to herein are stated at
the legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
AMI. Area of mutual interest.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
BOE. Barrel of oil equivalent (converting six Mcf of natural gas to one
Bbl of oil).
BOPD. Barrels of oil per day.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production of
oil or natural gas, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
Developed acreage. The number of acres that are allocated or assignable to
producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or
natural gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons
in sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Finding costs. Total costs incurred in oil and gas acquisition,
exploration and development activities and capitalized interest divided by total
reserve additions, including purchases of minerals in place, extensions,
discoveries, revisions and other additions.
Gross acres or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.
Infill well. A well drilled between known producing wells to better
exploit the reservoir.
Liquids. Crude oil, condensate and natural gas liquids.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
23
26
Mcfe. One thousand cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
MMS. Mineral Management Service of the United States Department of the
Interior.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio of
six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas
liquids.
Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells, as the case may be.
Oil. Crude oil and condensate.
Operating cash inflows per Mcfe. Net operating cash inflows as listed in
the Consolidated Statements of Cash Flows in the Consolidated Financial
Statements divided by net gas equivalent production for the applicable periods.
Present Value or PV10. When used with respect to oil and natural gas
reserves, the estimated future gross revenue to be generated from the production
of proved reserves, net of estimated production and future development costs,
using prices and costs in effect as of the date indicated, without giving effect
to non-property related expenses such as general and administrative expenses,
debt service and future income tax expenses or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed nonproducing reserves. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
24
27
Updip. A higher point in the reservoir.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and to a share
of production.
Workover. Operations on a producing well to restore or increase
production.
See also the Consolidated Financial Statements beginning on page F-1.
ITEM 2 -- PROPERTIES
OIL AND GAS RESERVES
The following table sets forth information with respect to Belco's
estimated net proved oil and gas reserves as of December 31, 2000. Information
in this 10-K as of December 31, 2000 relating to Belco's estimated net proved
oil and gas reserves and the estimated future net revenues attributable thereto
is based upon estimates prepared by in-house engineers and the audit review
thereof performed by Miller and Lents, Ltd., independent petroleum engineers.
All calculations of estimated net proved reserves have been made in accordance
with the rules and regulations of the SEC and, except as otherwise indicated,
give no effect to federal or state income taxes otherwise attributable to
estimated future net revenues from the sale of oil and gas. The present value of
estimated future net revenues has been calculated using a discount factor of
10%. See "Business -- Forward-Looking Statements and Risk Factors -- Estimates
of oil and gas reserves are uncertain and inherently imprecise."
AS OF DECEMBER 31, 2000
------------------------------------
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- --------
Estimated Proved Reserves:
Gas (MMcf).............................................. 231,380 149,943 381,323
Oil (MBbls)............................................. 40,642 16,849 57,491
Total Gas Equivalents (MMcfe)................... 475,232 251,037 726,269
Estimated Future Net Revenue before Income
Taxes (in millions)(1).................................. $ 2,545 $ 1,433 $ 3,978
======== ======== ========
Present Value of Estimated Future Net Revenues before
Income Taxes (discounted at 10% per annum) (in
millions)(1)............................................ $ 1,480 $ 776 $ 2,256
======== ======== ========
- ---------------
(1) Estimated future net revenue before income taxes represents estimated future
gross revenue to be generated from the production of proved reserves, net of
estimated production and future development costs, using average December
31, 2000 prices, which were $9.53 per Mcf of gas and $25.50 per barrel of
oil without giving effect to commodities price risk management activities
accounted for as hedges.
See also "Business."
ITEM 3 -- LEGAL PROCEEDINGS
Belco is a party to routine litigation incidental to its business. While
the ultimate results of these proceedings cannot be predicted with certainty,
Belco does not believe that the outcome of these matters will be material to
Belco.
ITEM 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the quarter ended December 31, 2000, no matters were submitted by
Belco to a vote of its security holders.
25
28
PART II
ITEM 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
As of March 19, 2001, Belco estimates there were approximately 122 record
holders of its Common Stock. Belco's Common Stock is listed on the New York
Stock Exchange ("NYSE") and traded under the symbol "BOG." As of March 19, 2001,
Belco had 32,789,590 shares outstanding and its closing price on the NYSE was
$9.35 per share. The high and low sales prices for Belco's Common Stock during
each quarter in the two years ended December 31, 2000 were as follows:
COMMON STOCK
HIGH LOW
------ -----
2000
First Quarter............................................... $11.25 $5.25
Second Quarter.............................................. 10.50 7.38
Third Quarter............................................... 9.63 8.00
Fourth Quarter.............................................. 12.44 8.50
1999
First Quarter............................................... $ 6.38 $4.75
Second Quarter.............................................. 7.94 5.75
Third Quarter............................................... 7.56 6.38
Fourth Quarter.............................................. 7.06 4.94
Belco has never paid a dividend, cash or otherwise, on its Common Stock.
Belco's credit agreement and the indentures governing its subordinated debt
contain restrictions on its ability to pay cash dividends on its capital stock,
including its outstanding preferred stock. As a result of reporting substantial
unrealized non-cash mark-to-market losses required by existing accounting rules,
dividends on Belco's preferred stock may be limited or prohibited by the
restrictions contained in its 10- 1/2% bond indenture. Payment of the March 2001
dividend on its preferred stock will be permitted. Subsequent dividends will be
contingent upon the sale of equity interests or sufficient net income to restore
dividend payment capacity under the indenture. At the present time, we do not
estimate that first quarter 2001 net income, as defined in the indenture, will
be sufficient to restore this dividend payment capacity. See "Business --
Forward-Looking Statements and Risk Factors -- Our credit agreement and
indentures restrict our ability to pay dividends; dividends on our preferred
stock may not be permitted after the first quarter of 2001."
Other than permitted payments of Preferred Stock dividends, Belco currently
intends to maintain a policy of retaining cash for the continued expansion of
its business.
PREFERRED STOCK
HIGH LOW
------ ------
2000
First Quarter.............................................. $15.88 $14.00
Second Quarter............................................. 15.75 13.00
Third Quarter.............................................. 15.75 14.44
Fourth Quarter............................................. 8.25 14.88
1999
First Quarter.............................................. $16.88 $15.13
Second Quarter............................................. 18.25 15.56
Third Quarter.............................................. 18.13 16.25
Fourth Quarter............................................. 17.00 14.50
26
29
In 2000, we issued a total of 1,241,675 shares of our common stock in
exchange for a total of 691,000 shares of our preferred stock. The common stock
issued in these transactions was not registered under the Securities Act of 1933
in reliance upon the exemption under Section 3(a)(9) of the Securities Act of
1933.
ITEM 6 -- SELECTED FINANCIAL DATA
The following table sets forth selected financial data regarding Belco as
of and for each of the periods indicated. The following data should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and Belco's financial statements and notes thereto,
which follow.
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
2000 1999 1998 1997 1996
--------- -------- --------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales, net of hedging
activities........................... $ 199,387 $141,932 $ 129,916 $129,994 $119,710
Commodity Price Risk Management
Activities -- Non-hedge cash
settlements.......................... (33,953) (2,442) 172 (1,551) 3,417
Interest............................... 951 1,134 1,730 3,245 2,653
--------- -------- --------- -------- --------
Total revenues.................. 166,385 140,624 131,818 131,688 125,780
--------- -------- --------- -------- --------
Costs and expenses:
Oil and gas operating expenses......... 33,290 29,854 33,615 7,358 6,296
Production taxes....................... 14,464 9,314 7,232 5,400 1,551
Depreciation, depletion and
amortization......................... 56,721 54,182 56,102 46,684 40,904
Impairment of oil and gas properties... -- -- 229,000 150,000 --
Impairment of equity securities........ -- 450 24,216 -- --
General and administrative............. 6,538 4,940 5,216 3,913 3,059
Interest expense....................... 25,253 21,021 21,013 1,668 --
Non-cash change in fair value of
derivatives.......................... 103,610 34,094 (18,912) 4,928 9,384
--------- -------- --------- -------- --------
Total costs and Expenses........ 239,876 153,855 357,482 219,951 61,194
--------- -------- --------- -------- --------
Income (loss) before income taxes........ (73,491) (13,231) (225,664) (88,263) 64,586
Provision (benefit) for income
taxes(1)............................... (25,722) (4,631) (78,107) (31,355) 21,953
--------- -------- --------- -------- --------
Net income (loss)(1)................... (47,769) $ (8,600) $(147,557) $(56,908) $ 42,633
========= ======== ========= ======== ========
Net income (loss) available to common
stock................................ $ (53,791) $(15,484) $(152,963) $(56,908) $ 42,633
========= ======== ========= ======== ========
Basic and diluted earnings (loss) per
common share(1)........................ (1.71) $ (0.49) $ (4.85) $ (1.80) $ 1.42
========= ======== ========= ======== ========
Weighted average common shares
outstanding............................ 31,469 31,642 31,529 31,538 29,986
STATEMENT OF CASH FLOWS DATA:
Cash flow from operating activities...... 86,698 78,044 86,345 101,523 108,059
Cash flow from investing activities...... (175,282) (74,542) (138,526) (363,136) (143,826)
Cash flow from financing activities...... 89,145 (3,832) 42,356 230,400 77,684
Capital expenditures (net)............... 175,328 73,183 126,506 564,459 142,712
BALANCE SHEET DATA:
Working capital.......................... (101,729)(2) $ (8,389)(2) $ 14,823 $ 36,757 $ 48,667
Total assets.................... 657,374 510,973 505,536 697,109 303,918
Long-term debt........................... 402,033 306,744 294,990 352,090 --
Equity................................... 60,400 113,972 138,291 184,648 233,203
- ---------------
(1) 1996 includes a one-time non-cash deferred tax charge of $30.1 million
recognized as a result of the Combination consummated on March 29, 1996 in
connection with Belco's Initial Public Offering.
(2) Excluding the commodity price risk management non-cash mark-to-market
balance sheet items, working capital would have been positive $7.5 and $6.6
million at December 31, 2000 and 1999, respectively.
27
30
ITEM 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion is intended to assist in the understanding of our
historical financial position and results of operations for the periods
indicated. It is based on our historical financial statements and related notes
thereto which follow and which contain detailed information that should be
referred to in conjunction with Management's Discussion and Analysis.
OVERVIEW
Belco Oil & Gas Corp. is an independent energy company engaged in the
exploration for and the acquisition, exploitation, development and production of
natural gas and oil in the United States primarily in the Rocky Mountains, the
Permian Basin, the Mid-Continent region and the Gulf Coast/Austin Chalk Trend in
Texas and Louisiana. Since our inception in April 1992, we have grown our
reserve base through a balanced program of exploration and development drilling
and through acquisitions. We concentrate our activities primarily in four core
areas in which we have accumulated detailed geologic knowledge and have
developed significant management and technical expertise. Additionally, we
structure our participation in natural gas and oil exploration and development
activities to minimize initial costs and risks, while permitting substantial
follow-on investment.
Our operations are currently focused in the Rocky Mountains, primarily in
the Green River (which includes the Moxa Arch Trend), Wind River and Big Horn
Basins of Wyoming, the Permian Basin in west Texas, the Mid-Continent region in
Oklahoma and north Texas, and the Gulf Coast, primarily in Texas. These areas
accounted for approximately 99% of our proved reserves at December 31, 2000. Our
reserve base was 726 Bcfe at December 31, 2000 with a reserve life index of 11.3
years, based on 2000 production. During the calendar year 2000, we acquired
approximately 104 Bcfe of proved reserves for approximately $79.5 million.
Our revenue, profitability and future rate of growth are substantially
dependent upon prevailing prices for natural gas, oil and condensate. Commodity
prices are subject to numerous factors beyond our control, such as economic,
political and regulatory developments and competition from other sources of
energy. Energy markets have historically been very volatile, and we can offer no
assurance that oil and natural gas prices will not be subject to wide
fluctuations in the future. A substantial or extended decline in oil and natural
gas prices could have a material adverse effect on our financial position,
results of operations and access to capital, as well as the quantities of
natural gas and oil reserves that we may economically produce. Natural gas
produced is sold under contracts that primarily reflect spot market conditions
for their particular area. We market our oil with other working interest owners
on spot price contracts and typically receive a small premium to the price
posted for such oil. Currently, approximately 64% of our production volumes
relate to the sale of natural gas (based on six Mcf of gas being considered
equivalent to one barrel of oil).
We utilize commodity swaps and options and other commodity price risk
management transactions related to a portion of our oil and natural gas
production to achieve a more predictable cash flow, and to reduce our exposure
to price fluctuations. We account for these transactions in compliance with
current generally accepted accounting principles as hedging activities or use
mark-to-market accounting for those contracts that do not qualify for hedge
accounting. As of December 31, 2000, we had various natural gas and oil price
risk management contracts in place with respect to portions of our estimated
production for years 2001, 2002 and 2003. We expect to reduce the current amount
of price risk management contracts to largely phase out such transactions that
we have in place over the next 12 to 24 months in an effort to limit our future
exposure to the mark-to-market accounting rules requiring the immediate
recognition of non-cash unrealized gains and losses that cause large
unpredictable swings in reported results of operations, related earnings per
share and shareholder equity.
28
31
The following table sets forth certain operations data of Belco for the
periods presented:
YEAR ENDED DECEMBER 31,
--------------------------------
2000 1999 1998
-------- -------- --------
Oil and Gas Sales, Net of Hedging Activities (in
thousands)....................................... $199,387 $141,932 $129,916
Average Sales Prices(1):
Oil (per Bbl)
-- Unhedged................................... $ 29.23 $ 17.49 $ 13.17
-- Hedge settlements.......................... (4.62) 1.76 2.92
Net realized.................................. $ 24.61 $ 19.25 $ 16.09
Gas (per Mcf)
-- Unhedged................................... $ 3.50 $ 1.99 $ 1.86
-- Hedge settlements.......................... (0.98) (0.08) (0.17)
Net realized.................................. $ 2.52 $ 1.91 $ 1.69
Net Production Data:
Oil (MBbl).................................... 3,922 3,439 4,177
Gas (MMcf).................................... 40,847 39,738 37,207
Gas equivalent (MMcfe)........................ 64,379 60,370 62,272
Daily production (MMcfe)...................... 176 165 171
Operations Data per Mcfe:
Oil and gas sales revenues (unhedged)......... $ 4.00 $ 2.31 $ 1.99
Hedged and non-hedge cash settlements......... (1.43) -- 0.09
Oil and gas operating expenses................ (0.52) (0.49) (0.54)
Production taxes.............................. (0.22) (0.16) (0.12)
General and administrative.................... (0.10) (0.08) (0.08)
Depreciation, depletion and amortization...... (0.88) (0.90) (0.90)
-------- -------- --------
Pre-tax operating profit(2)................... $ 0.85 $ 0.68 $ 0.44
-------- -------- --------
Operating cash flow(2)........................ $ 1.73 $ 1.58 $ 1.34
-------- -------- --------
- ---------------
(1) Excludes non-hedge commodity price risk management cash settlements reported
separately.
(2) Excluding non-cash commodity price risk management activities, non-cash
ceiling test and securities impairment provisions, interest income and
interest expenses.
RESULTS OF OPERATIONS -- 2000 COMPARED TO 1999
Revenues
Oil and gas sales revenues for the year 2000, net of hedging activities,
increased $57.5 million, or 41% to $199.4 million when compared to the prior
year primarily the result of both higher production and higher commodity prices.
Natural gas production increased 3% over the prior year. Average Mcfe price
realizations, net of hedging activities, increased by 32% when compared to last
year's price realizations. Natural gas production represented approximately 63%
of total production on an Mcfe basis compared to the 66% reported for 1999. Oil
production increased by 14% over the prior year due to property acquisitions and
newly drilled well additions during the year less oil producing properties sold.
CPRM activities, including hedged and non-hedged transactions, for the year
2000 resulted in reported revenue reductions of $92.2 million in actual cash
settlements paid compared to incremental revenues of $0.2 million received in
the prior year. In addition, $103.6 million in non-cash mark-to-market
unrealized future losses related to CPRM activities were recorded under costs
and expenses in compliance with current accounting rules. In the prior year,
$34.1 million in non-cash mark-to-market unrealized losses were reported.
29
32
Costs and Expenses
Production and operating expenses for the year 2000 increased by 11% to
$33.3 million compared to $29.9 million reported in the prior year. The increase
was related to the addition of wells, both acquired and drilled, in the current
year. On an equivalent unit basis, lifting costs were $0.52 per Mcfe for the
year 2000 compared to $0.49 per Mcfe in 1999. Production taxes were $0.22 and
$0.16 per Mcfe for the years 2000 and 1999, respectively, with the increase
related to higher commodity prices.
Depreciation, Depletion and Amortization ("DD&A") for the year 2000
increased $2.5 million to $56.7 million when compared to the $54.2 million
recorded in the prior year due to higher production volumes. The annual DD&A
rate per Mcfe was $0.88, a 2% decline as compared to the prior year when $0.90
per Mcfe was recorded.
General and Administrative Costs ("G&A") costs increased by 32% in 2000 to
$6.5 million when compared to the $4.9 million incurred in 1999. The increase
was principally due to reduced amounts charged to the full cost pool. The G&A
costs per Mcfe increased from $0.08 to $0.10.
Interest expense is incurred on $147 million of 8 7/8% Senior Subordinated
Notes due 2007 issued in September 1997, $109 million of 10- 1/2% Notes assumed
in the Coda acquisition in November 1997 and bank debt incurred to fund various
activities. Interest expense for the year 2000 increased by $4.2 million to
$25.3 million, a 20% increase over the $21.0 million incurred in the prior year.
The increase is due to higher interest rates charged and additional borrowings
outstanding under Belco's credit facility related to property acquisitions. The
higher interest costs were partially offset by additional amounts capitalized
during the current year.
Income (Loss) Before Income Taxes
Our reported loss before income tax benefits for the year 2000 was $73.5
million. This compares to a pre-tax loss of $13.2 million reported for the year
1999. The 2000 and 1999 reported losses are the result of recognizing the
required non-cash mark-to-market unrealized CPRM losses as required by current
accounting rules. Excluding the effect of the non-cash mark-to-market unrealized
CPRM losses, Belco had income before income taxes of $30.1 million and $20.9
million for the years 2000 and 1999, respectively.
Income Taxes
Income tax benefits were recorded for the year 2000 in the amount of $25.7
million as a result of the reported pre-tax loss. The benefit for income taxes
for 1999 was $4.6 million.
RESULTS OF OPERATIONS -- 1999 COMPARED TO 1998
Revenues
Oil and gas sales revenues for the year 1999, net of hedging activities,
increased 9% to $141.9 million compared to $129.9 million realized in 1998. The
year over year increase is due to higher commodity prices and higher natural gas
production partially offset by lower crude oil production. In 1999, weighted
average oil prices realized, net of hedging, totaled $19.25 per barrel, a 20%
increase when compared to the $16.09 realized in 1998. The natural gas weighted
average prices realized, net of hedging, increased by 13% from $1.69 in 1998 to
$1.91 in 1999. Average daily production volume in 1999 on an Mcfe basis declined
by 3% to 165 MMcfe.
Commodity price risk management activities, including hedged and non-hedged
transactions, increased revenues by $0.2 million in the year 1999 and $5.9
million in 1998. In addition, a $34.1 million charge and a ($18.9) million
reduction was recorded in 1999 and 1998, respectively, under costs and expenses
representing non-cash mark-to-market unrealized future losses or (gains) related
to CPRM activities in compliance with current accounting rules.
30
33
Costs and Expenses
Production and Operating Expenses. Production and operating expenses
declined to $39.2 million or 4% in 1999 when compared to the $40.8 million
incurred during 1998. The decrease is identified with cost reduction efforts in
response to lower commodity prices realized in the first half of 1999 combined
with the implementation of other operating efficiencies on newly operated
properties located in Wyoming. On a unit basis, operating costs were $0.65 per
Mcfe for 1999 compared to $0.66 per Mcfe for 1998, including production taxes.
DD&A costs for the year totaled $54.2 million when compared to the $56.1
million recorded for the prior year. The DD&A rate for the year was unchanged at
$0.90 per Mcfe. For the year 1998, Belco also recorded $229 million ($149
million after-tax) in non-cash ceiling test provisions as required by full-cost
accounting rules. The provisions were the result of applying substantially lower
commodity prices to estimated recoverable reserves.
G&A costs declined by 5% during 1999 to $4.9 million when compared to the
$5.2 million incurred in 1998. The decrease is primarily due to the cost
controls implemented in response to lower commodity prices. The rate per Mcfe
for such costs was unchanged at $0.08 for both years. Exploration related G&A
expenses for 1999 in the amount of $5.5 million have been capitalized to oil and
gas property accounts. The decrease of $0.7 million when compared to 1998
comparable capitalized amount of $6.2 million principally reflects reduced
exploration activities.
Interest expense is incurred on $150 million of the 8 7/8% Senior
Subordinated Notes due 2007 issued in September 1997, $109 million of the
10 1/2% Senior Subordinated Notes due 2006 and bank debt incurred under Belco's
Revolving Credit Facility. Net interest costs incurred for the year 1999 totaled
$25.9 million, with approximately $4.9 million of this total capitalized to
property accounts. The 1999 net total interest cost declined modestly when
compared to 1998 when net total interest costs were $26.1 million, with $5.1
million capitalized.
As a result of the substantial decline in the market value of Big Bear
Exploration Ltd. ("Big Bear") securities acquired in June 1998, impairment
provisions were $450,000 and $9.7 million recorded by Belco in 1999 and 1998,
respectively. See "Liquidity and Capital Resources" for additional details
related to the Big Bear investment.
Income (Loss) Before Income Taxes
Belco's reported loss before income tax benefits for the year 1999 was
$13.2 million. This compares to a loss of $225.7 million reported in 1998. The
substantially lower loss reported for 1999 reflects improved commodity prices
and the absence of non-cash ceiling test and securities impairment provisions of
$229.0 million and $24.2 million, respectively, reported in 1998.
Income Taxes
Income tax benefits were recorded for 1999 in the amount of $4.6 million
and $78.1 million for 1998 as a result of reported pre-tax losses.
LIQUIDITY AND CAPITAL RESOURCES
General
In September 1997, we entered into a five-year $150 million Credit
Agreement dated September 23, 1997 with The Chase Manhattan Bank, N.A., as
administrative agent and other lending institutions. In June 2000, the credit
facility was amended and restated and now provides for an aggregate principal
amount of revolving loans of up to the lesser of $250 million or a defined
borrowing base in effect from time to time, includes a sub-facility for letters
of credit and expires in January 2004. The borrowing base at December 31, 2000
was $200 million with $141.0 million advanced at that date. Additionally, there
were letters of credit outstanding in the amount of $36.5 million in connection
with CPRM activities. The borrowing base is redetermined by the agent
31
34
and the participating banks semi-annually based upon their usual and customary
oil and gas lending criteria as such exist from time to time. In addition, we
may request two additional redeterminations and the banks may request one
additional redetermination per year. Our indebtedness under the credit facility
is secured by a pledge of the capital stock of each of our material
subsidiaries.
Indebtedness under the credit facility bears interest at a floating rate
based (at our option) upon (i) the ABR with respect to ABR Loans or (ii) the
Eurodollar Rate (as defined) for one, two, three or six months (or nine or
twelve months if available to the banks) Eurodollar Loans (as defined), plus the
Applicable Margin. The ABR is the greater of (i) the Prime Rate (as defined),
(ii) the Base CD Rate (as defined) plus 1% or (iii) the Federal Funds Effective
Rate (as defined) plus 0.50%. The Applicable Margin for Eurodollar Loans varies
from 1.125% to 1.625% depending on the borrowing base usage. Borrowing base
usage is determined by a ratio of (i) outstanding Loans (as defined) and letters
of credit to (ii) the then effective borrowing base. Interest on ABR Loans is
payable quarterly in arrears and interest on Eurodollar Loans is payable on the
last day of the interest period therefore and, if longer than three months, at
three month intervals.
We are required to pay to the banks a commitment fee based on the lesser of
the unused available aggregate commitments or the unused available then
effective borrowing base during a quarterly period equal to a percent that
varies from 0.25% to 0.50% depending on the borrowing base usage.
We entered into interest rate swap agreements converting two long-term debt
fixed rate obligations to floating rate obligations as follows:
AGREEMENT TRANSACTION FIXED FLOATING RATE
AMOUNT DATE RATE RATE RE-SET DATE
- --------- ----------- ------ -------- --------------
$100 million......................... 12/97 8.875% 8.875% March 15, 2001(a)
$85 million.......................... 12/97 10.500% 11.625% April 1, 2001(a)
$50 million.......................... 1/98 8.875% 8.875% March 15, 2001(a)
- ---------------
(a) Floating rate is redetermined at each six month period following the
expiration through September 15, 2007 and is currently capped at rates
indicated.
The agreements obligate Belco to actually pay the indicated floating rate rather
than the original fixed rate. The floating rates are capped at 8 7/8% through
September 15, 2001 and at 10% from March 15, 2002 through September 15, 2007 on
the 8 7/8% Notes and capped at 11.625% from April 1, 2000 through April 2003 on
the 10 1/2% Notes.
Belco's board of directors has authorized the purchase from time to time,
in the open market or in privately negotiated transactions, shares of its common
stock and 6 1/2% convertible preferred stock, in an aggregate amount not to
exceed $10 million. The current $10 million authorization is in addition to the
$10 million that was exhausted in December 1999. During the year 2000, Belco
purchased 20,700 shares of its preferred stock for a total cost of $0.3 million
pursuant to the existing authorization.
Additionally, during the year 2000, Belco exchanged 691,000 shares of its
6 1/2% convertible preferred stock for 1,241,675 shares of its common stock. The
liquidation preference of the preferred stock that was exchanged was $17.3
million.
In December 2000, Belco closed a $9.8 million acquisition of oil and gas
properties adding approximately 18.6 Bcfe of proved reserves to its reserve
base. The transaction was financed through additional borrowings under the
credit facility.
In August 2000, Belco sold its interest in certain North Texas oil
properties, including 436 producing wells for $10.1 million in cash and retained
a volumetric production payment which Belco values at approximately $5.0
million.
In April 2000, Belco closed a $24.1 million acquisition of oil and gas
properties adding approximately 51 Bcfe of proved reserves to its reserve base.
The transaction was financed through additional borrowings under the credit
facility.
32
35
In February 2000, Belco closed a $41.6 million acquisition of oil and gas
properties expected to add approximately 2,400 BOE per day to the existing
production base. The transaction was financed through additional borrowings
under Belco's Revolving Credit Facility.
In January 2000, Belco purchased $3 million face value of its 8 7/8% Senior
Subordinated Notes due 2007 at a discount in the open market resulting in a
modest gain.
Cash Flow
Our principal sources of cash are operating cash flow and bank borrowings.
Cash flow from operating activities for the year 2000 was $86.7 million, an 11%
increase over the prior year when $78.0 million was realized. The increase is
the result of higher production volumes and higher commodity prices.
Net cash used in investing activities for the years 2000 and 1999 were
$175.3 and $74.5 million, respectively. Investing activities for these periods
include oil and gas property acquisitions in the amount of $79.5 million and
$18.1 million for 2000 and 1999, respectively. In addition, investing activities
generally include exploration and development activities and proceeds from the
sale of properties or other assets.
Net cash provided (used) by financing activities for the years 2000 and
1999 were $89.1 million and ($3.8) million, respectively. Net debt increased by
$95.3 million primarily related to property acquisitions. Cash flow from
operations and the disposition of assets funded drilling and other operating
activities during the current year, including preferred dividends paid. Belco's
credit facility and the indentures governing its subordinated debt restrict the
payments of dividends. As a result of reporting substantial unrealized non-cash
mark-to-market losses required by existing accounting rules, dividends on
Belco's preferred stock may be limited or prohibited by the restrictions
contained in Belco's 10 1/2% bond indenture. Payment of the March 2001 dividend
on Belco's preferred stock will be permitted. Subsequent dividends will be
contingent upon the sale of equity interests or sufficient net income to restore
dividend payment capacity under the indenture. At the present time, Belco
management does not estimate that first quarter 2001 net income, as defined in
the indenture, will be sufficient to restore this dividend payment capacity.
Capital Expenditures
Net capital expended by Belco during the year 2000 totaled $175.3 million,
including $79.5 million identified with the acquisition of properties and
property dispositions of $11.5 million.
We intend to fund our future capital expenditures, commitments and working
capital requirements through cash flows from operations, borrowings under the
credit facility or other potential financings, including the sale of equity or
debt securities. If there are changes in oil and natural gas prices that
correspondingly affect cash flows and the borrowing base under the credit
facility, we have the discretion and ability to adjust our capital budget. We
believe that we will have sufficient capital resources and liquidity to fund our
capital expenditures and meet all of our financial obligations through the end
of 2001.
Belco's capital expenditure budget for 2001 is $90 million exclusive of
potential acquisitions. Approximately 70% of the budget will be dedicated
towards development projects and approximately 30% towards exploratory projects.
Belco's budget is highly discretionary and capital may be reallocated as
necessary in order to pursue attractive opportunities. The budget may also be
increased during 2001 if commodity prices remain strong throughout the year.
Belco does not specifically budget for acquisition activities due to the
uncertainty of potential opportunities.
Commodity Price Risk Management Transactions
Certain of the Belco's commodity price risk management arrangements require
Belco to deliver cash collateral or other assurances of performance to the
counterparties in the event that Belco's payment obligations with respect to its
CPRM transactions exceed certain levels. Two of the inherent risks of a price
risk management program are margin requirements and collateralization. Certain
transactions may be subject to margin calls under certain conditions including
change of ownership control, rating agency activity or default. As of March 15,
2001 Belco's current collateral requirement is $15.0 million in letters of
credit.
33
36
Belco's borrowing capacity under its credit facility will allow Belco to be
responsive to any additional collateral calls.
With the primary objective of achieving more predictable revenues and cash
flows, Belco has entered into CPRM transactions of various kinds with respect to
both oil and natural gas. While the use of certain of these price risk
management arrangements limits the downside risk of adverse price movements, it
may also limit future revenues from favorable price movements. Belco engages in
transactions such as selling options, which are marked-to-market at the end of
the relevant accounting period. Since the futures market historically has been
highly volatile, these fluctuations may cause significant impact on the results
of any given accounting period. Belco has entered into price risk management
transactions with respect to approximately 60% of its gas equivalent estimated
production for the year 2001 and substantially lesser portions of its estimated
equivalent production thereafter. Belco continues to evaluate whether to enter
into additional price risk management transactions for future years. We expect
to reduce the current amount of price risk management contracts to largely phase
out such transactions that we have in place over the next 12 to 18 months in an
effort to limit our future exposure to the mark-to-market accounting rules
requiring the immediate recognition of non-cash unrealized gains and losses that
cause large unpredictable swings in reported results of operations, related
earnings per share and shareholder equity. In addition, Belco may determine from
time to time to unwind its then existing price risk management positions as part
of its price risk management strategy.
A summary of our approximate current committed volumes and prices by year,
assuming the NYMEX forward curve reference prices for oil and gas as of February
14, 2001 is as follows:
VOLUME AVERAGE
YEAR PER DAY REALIZED PRICE
---- ------- --------------
Oil -- Barrels per day................................ 2001 6,920 $19.15
2002 5,990 $21.40
2003 2,410 $20.40
Gas -- MMBtu per day.................................. 2001 67,400 $ 2.08
2002 37,800 $ 2.85
2003 12,500 $ 3.40
We expect to incur additional hedge and non-hedge related cash settlement
costs through calendar year 2001 assuming commodity prices remain at current
levels. This cash settlement amount is estimated at approximately $135 million
utilizing the December 31, 2000 forward price curve applied to volumes of oil
and gas expected to be produced during the twelve month period ending December
31, 2001. This estimated amount can increase or decrease if commodity prices
rise or decline from the current levels used in developing this estimate. As
cash settlements are made on volumes produced, no additional losses are expected
to be recorded, unless actual prices increase above estimated future prices used
in the December 31, 2000 mark-to-market calculation. Subsequent to December 31,
2000 natural gas futures prices have declined and if such conditions persist,
Belco will be required to record mark-to-market unrealized gains representing a
reversal of previously reported mark-to-market unrealized losses. No estimate of
future mark-to-market unrealized gains or losses are determinable as such
amounts are contingent upon commodity prices at the end of each calendar
quarter.
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities" which was amended by Financial Accounting
Standard No. 138 ("SFAS 138") in June 1999. SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. It
also requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows derivatives gains and losses to offset
related results on the hedged item in the income statement, and requires that a
company must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. We adopted SFAS 133 on January 1,
2001, the effective date as amended by SFAS 138. SFAS 133 is expected to
increase volatility of stockholder's equity, reported earnings (losses) and
other
34
37
comprehensive income. Assuming that SFAS 133 had been adopted on December 31,
2000, Belco would have recorded an additional $17.5 million in current assets,
$2.0 million in non-current assets, $52.2 million in current liabilities and
$12.7 million in non-current liabilities related to Belco's existing oil and gas
hedges based on the forward price curve in effect at December 31, 2000. These
contracts should also qualify for hedge accounting treatment under SFAS 133. The
total potential net liability of $45.4 million related to qualifying hedge
instruments would be charged to Other Comprehensive Income and appear in the
equity section of the balance sheet. This amount combined with amounts
previously recorded on the balance sheet representing the non-cash
mark-to-market unrealized losses in the net amount of $162.8 million represent
the full potential exposure of Belco's CPRM related activities that may or may
not be realized as they are dependent on future commodity prices. After
adoption, Belco will be required to recognize any hedge ineffectiveness in the
income statement each period. In addition, Belco has three interest rate swaps
that will be affected by SFAS 133. We currently believe these swaps will not
qualify for hedge accounting and as a result, Belco will be required to record
an additional $6.6 million in non-current liabilities with the offsetting charge
to the income statement.
OTHER
Environmental Matters
Our operations are subject to various federal, state and local laws and
regulations relating to the protection of the environment, which have become
increasingly stringent. We believe that our current operations are compliant in
all material respects with current environmental laws and regulations. There are
no environmental claims pending or, to our knowledge, threatened against Belco.
We can give no assurance, however, that current regulatory requirements will not
change, currently unforeseen environmental incidents will not occur or past
noncompliance with environmental laws will not be discovered on Belco's
properties.
Information Regarding Forward Looking Statements
The information contained in this Form 10-K includes certain
forward-looking statements. When used in this document, such words as "expect",
"intend", "plan", "believes", "potential", "will", "may" and similar expressions
are intended to identify forward-looking statements. Although we believe that
our expectations are based on reasonable assumptions, it is important to note
that actual results could differ materially from those projected by such
forward-looking statement. Important factors that could cause actual results to
differ materially from those in the forward-looking statements include, but are
not limited to, the timing and extent of changes in commodity prices for oil and
gas, the need to develop and replace reserves, environmental risk, the
substantial capital expenditures required to funds its operations, drilling and
operating risks, risks related to exploration and development, uncertainties
about the estimates of reserves, competition, government regulation and our
ability to implement our business strategy.
ITEM 7A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Belco's market risk exposures relate primarily to commodity prices and
interest rates. Belco enters into various transactions involving commodity price
risk management activities involving a variety of derivatives instruments to
hedge the impact of crude oil and natural gas price fluctuations. In addition,
Belco entered into interest rate swap agreements to reduce current interest
burdens related to its fixed long-term debt. Belco does not enter into
derivative instruments for trading purposes.
The derivatives commodity price instruments are generally put in place to
limit the risk of adverse oil and natural gas price movements, however, such
instruments can limit future gains resulting from upward favorable oil and
natural gas price movements. Recognition of both realized and unrealized gains
or losses are reported currently in Belco's financial statements as required by
existing generally accepted accounting principles. The cash flow impact of all
derivative related transactions is reflected as cash flows from operating
activities.
As of December 31, 2000, Belco had substantial derivative financial
instruments outstanding and related to its price risk management program. See
"Footnotes 6 and 7" to the consolidated financial statements of Belco "Commodity
Price Risk Management Activities and Fair Value of Financial Instruments" for
complete
35
38
details on Belco's oil and gas related transactions in effect as of December 31,
2000. Transactions subsequent to year-end 2000 were not significant. For a
further discussion of our CPRM transactions, see "Business-Price Risk Management
Transaction," "-- Forward-Looking Information and Risk Factors," and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
The table below provides information related to Belco's interest rate swaps
on long-term debt obligations. For interest rate swaps, the table presents
notional amounts and approximate weighted average interest rates by contractual
maturity dates. Notional amounts are used to calculate the contractual payments
to be exchanged under the agreements in place. For more information on our
interest rate swaps, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations-Liquidity and Capital Resources."
FAIR VALUE
EXPECTED MATURITY DATE AS OF
------------------------------------------------------ DECEMBER 31,
2001 2002 2003 2004 THEREAFTER TOTAL 2000
-------- -------- -------- -------- ---------- -------- ------------
Liabilities:
Bank credit facility...... -- -- -- $141,000 -- $141,000 $141,000
Belco 8.875% Notes........ -- -- -- -- $147,000 $147,000(1) $139,283
Belco 10.500% Notes....... -- -- -- -- $109,000 $109,000(2) $110,450
Interest Rate Swaps:
Fixed to Variable......... $235,000 $235,000 $235,000 $150,000 $ (6,652)
- ---------------
(1) Notes mature 2007
(2) Notes mature 2006
ITEM 8 -- CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See the Consolidated Financial Statements and supplementary data listed in
the accompanying Index to Financial Statements and Financial Statement Schedules
on page F-1 herein. Information required by other schedules required under
Regulation S-X is either not applicable or is included in the financial
statements or notes thereto.
ITEM 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information regarding Directors and Executive Officers required under
Item 10 will be contained in the definitive Proxy Statement of Belco for its
2001 Annual Meeting of Shareholders (the "Proxy Statement") under the headings
"Election of Directors", "Executive Compensation and Other Information" and
"Section 16(a) Beneficial Ownership Reporting Compliance" and is incorporated
herein by reference. The Proxy Statement will be filed pursuant to Regulation
14A with the Securities and Exchange Commission not later than 120 days after
December 31, 2000. For information regarding Executive Officers not appearing in
the Proxy Statement, see "Business -- Executive Officers of the Registrant".
ITEM 11 -- EXECUTIVE COMPENSATION
The information required under Item 11 will be contained in the Proxy
Statement under the heading "Executive Compensation and Other Information" and
is incorporated herein by reference.
36
39
ITEM 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required under Item 12 will be contained in the Proxy
Statement under the heading "Security Ownership of Management and Certain
Beneficial Owners" and is incorporated herein by reference.
ITEM 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required under Item 13 will be contained in the Proxy
Statement under the headings "Transactions with Management and Certain
Shareholders" and "Executive Compensation and Other Information" and is
incorporated herein by reference.
PART IV
ITEM 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements: See Index to Consolidated Financial
Statements and Schedules immediately following the signature page of this
report.
2. Financial Statement Schedules: See Index to Consolidated Financial
Statements and Schedules immediately following the signature page of this
report.
3. Exhibits: The following documents are filed as exhibits to this
report.
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
- ------- ----------------------
3.1 -- Articles of Incorporation of Company (Incorporated by
reference from Exhibit 3.1 of the Registration Statement on
Form S-1, Registration No. 333-1034).
3.2 -- Amended and Restated Bylaws of Company dated February 5,
1996 (Incorporated by reference from Exhibit 3.2(ii) of the
Form 10-Q dated March 31, 1996).
4.1 -- Specimen Common Stock Certificate (Incorporated by reference
from Exhibit 4.1 of the Registration Statement on Form S-1,
Registration No. 333-1034).
4.2 -- Indenture dated as of September 23, 1997 among the Company,
as issuer, and The Bank of New York, as trustee
(Incorporated by reference from Exhibit 4.1 of Registration
Statement on Form S-4, Registration No. 333-37125).
4.3 -- Supplemental Indenture dated as of February 25, 1998 between
Coda Energy, Inc., Diamond Energy Operating Company, Electra
Resources, Inc., Belco Operating Corp., Belco Energy L.P.,
Gin Lane Company, Fortune Corp., BOG Wyoming LLC and Belco
Finance Co. (individually, the Subsidiary Guarantors), a
subsidiary of Belco, and The Bank of New York, a New York
banking corporation (as Trustee) amending the Indenture
filed as Exhibit 4.2 above. (Incorporated by reference from
Exhibit 4.3 of the Company's Annual Report on Form 10-K for
the fiscal year ended December 31, 1997).
4.4 -- Exchange and Registration Rights Agreement dated September
23, 1997 by and among Belco and Chase Securities Inc.,
Goldman, Sachs & Co. and Smith Barney Inc. (Incorporated by
reference from Exhibit 4.2 of Registration Statement on Form
S-4, Registration No. 333-37125).
4.5 -- Indenture dated as of March 18, 1996 by and among Coda
Energy, Inc., as issuer, and Taurus Energy Corp., Diamond
Energy Operating Company and Electra Resources, Inc. (as
guarantors), and Chase Bank of Texas, N.A., (formerly known
as Texas Commerce Bank National Association, as trustee
(Incorporated by reference from Exhibit 4.1 of the Coda
Energy, Inc. Registration Statement on Form S-4 filed April
9, 1996, Registration No. 333-2375).
37
40
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
- ------- ----------------------
4.6 -- First Supplemental Indenture dated as of April 25, 1996
amending the Indenture filed as Exhibit 4.5 above
(Incorporated by reference from Exhibit 4.12 of the Coda
Energy, Inc. Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 1996, Commission File No. 0-10955).
4.7 -- Second Supplemental Indenture dated as of February 25, 1998
by and among Belco and Chase Bank of Texas, N.A. (formerly
known as Texas Commerce Bank National Association), as
trustee, amending the Indenture filed as Exhibit 4.5 above.
(Incorporated by reference from Exhibit 4.7 of Belco's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1997).
4.8 -- Third Supplemental Indenture dated as of February 25, 1998
by and between Belco, the Belco subsidiaries who are making
a Subsidiary Guarantee (the Guarantors) and Chase Bank of
Texas, N.A., formerly known as Texas Commerce Bank National
Association (the Trustee). (Incorporated by reference from
Exhibit 4.8 of the Company's Annual Report on Form 10-K for
the fiscal year ended December 31, 1997).
4.9 -- Certificate of Designations of 6 1/2% Convertible Preferred
Stock dated March 5, 1997 (Incorporated by reference from
Exhibit 4.1 of current report on Form 8-K dated March 11,
1998).
10.1 -- 1996 Non-Employee Directors' Stock Option Plan (Incorporated
by reference from Exhibit 10.1 of the Registration Statement
on Form S-1, Registration No. 333-1034).
10.2 -- 1996 Stock Incentive Plan (Incorporated by reference from
Exhibit 10.2 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.3 -- Exchange and Subscription Agreement and Plan of
Reorganization dated as of January 1, 1996 by and among
Belco, its Predecessors and certain individuals and trusts
(Incorporated by reference to Exhibit 10.3 of the
Registration Statement on Form S-1, Registration No.
333-1034).
10.4 -- Form of Registration Rights Agreement entered into by
parties to Exchange Agreement (Incorporated by reference to
Exhibit 10.4 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.5 -- Supplemental Agreement dated as of January 1, 1996 by and
between Belco, Belco Oil & Gas Corp., a Delaware
corporation, Robert A. Belfer and certain officers of Belco
(Incorporated by reference to Exhibit 10.5 of the
Registration Statement on Form S-1, Registration No.
333-1034).
10.6 -- Form of Indemnification Agreement by and between the Company
and its officers and directors (Incorporated by reference to
Exhibit 10.6 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.7 -- Amended and Restated Well Participation Letter Agreement
dated as of December 31, 1992 between Chesapeake Operating,
Inc. and Belco Oil & Gas Corp., as amended by (i) Letter
Agreement dated April 14, 1983, (ii) Amendment dated
December 31, 1993, and (iii) Third Amendment dated December
30, 1994 (Incorporated by reference to Exhibit 10.7 of the
Registration Statement on Form S-1, Registration No.
333-1034).
10.8 -- Sale Agreement (Independence) dated as of June 10, 1994
between Chesapeake Operating, Inc. and Belco Oil & Gas Corp.
(Incorporated by reference to Exhibit 10.10 of the
Registration Statement on Form S-1, Registration No.
333-1034).
10.9 -- Sale and Area of Mutual Interest Agreement (Greater
Giddings) dated as of December 30, 1994 between Chesapeake
Operating, Inc. and Belco Oil & Gas Corp. (Incorporated by
reference to Exhibit 10.12 of the Registration Statement on
Form S-1, Registration No. 333-1034).
38
41
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
- ------- ----------------------
10.10 -- Golden Trend Area of Mutual Interest Agreement dated as of
December 17, 1992 between Chesapeake Operating, Inc. and
Belco Oil & Gas Corp. (Incorporated by reference to Exhibit
10.13 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.11 -- Form of Participation Agreement for Belco Oil & Gas Corp.
1992 Moxa Arch Drilling Program (Incorporated by reference
to Exhibit 10.15 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.12 -- Form of Offset Participation Agreement to the Moxa Arch 1992
Offset Drilling Program (Incorporated by reference to
Exhibit 10.16 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.13 -- Form of Participation Agreement for Belco Oil & Gas Corp.
1993 Moxa Arch Drilling Program (Incorporated by reference
to Exhibit 10.17 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.14 -- Amended and Restated Credit Agreement dated as of June 30,
2000 by and among Belco Oil & Gas Corp. (the "Borrower"),
and The Chase Manhattan Bank, as administrative agent, and
certain financial institutions named therein as Lenders (the
"Lenders") (Incorporated by reference to Exhibit 10.1 of
Belco's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2000, Commission File No. 1-14256).
10.15 -- First Amendment to Belco Oil & Gas Corp. 1996 Stock
Incentive Plan (Incorporated by reference from Exhibit 10.2
of Belco's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000, Commission File No. 1-14256).
10.16 -- Executive Employment Agreement with Grant W. Henderson
(Incorporated by reference from Exhibit 99.7 of the Coda
Energy, Inc. Current Report on Form 8-K dated October 30,
1995, Commission File No. 0-10955).
10.17 -- First Amendment to Belco Oil & Gas Corp. 1996 Nonemployee
Directors' Stock Option Plan. (Incorporated by reference
from Exhibit 10.1 of Belco's Quarterly Report on Form 10-Q
for the quarter ended June 30, 1999, Commission File No.
1-14256).
*21.1 -- Subsidiaries of the Registrant.
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Miller and Lents, Ltd.
- ---------------
* Filed herewith
Certain of the exhibits to this filing contain schedules, which have been
omitted in accordance with applicable regulations. The Registrant undertakes to
furnish supplementally a copy of any omitted schedule to the Securities and
Exchange Commission upon request.
(b) Reports on Form 8-K.
None.
39
42
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
BELCO OIL & GAS CORP.
By:
------------------------------------
Laurence D. Belfer
Vice-Chairman
Date: March 30, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
Chief Executive Officer and Chairman of the March 30, 2001
- --------------------------------------- Board of Directors (Principal Executive
Robert A. Belfer Officer)
Vice-Chairman and Director March 30, 2001
- ---------------------------------------
Laurence D. Belfer
Senior Vice President-Finance, Chief March 30, 2001
- --------------------------------------- Financial Officer, Treasurer and
Dominick J. Golio Secretary (Principal Financial Officer
and Principal Accounting Officer)
Director March 30, 2001
- ---------------------------------------
Graham Allison
Director March 30, 2001
- ---------------------------------------
Daniel C. Arnold
Director March 30, 2001
- ---------------------------------------
Alan D. Berlin
President, Chief Operating Officer and March 30, 2001
- --------------------------------------- Director
Grant W. Henderson
Director March 30, 2001
- ---------------------------------------
Jack Saltz
40
43
BELCO OIL & GAS CORP. AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND
FINANCIAL STATEMENT SCHEDULES
PAGE
----
CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants.................. F-2
Consolidated Balance Sheets as of December 31, 2000 and
1999................................................... F-3
Consolidated Statements of Operations for the Years Ended
December 31, 2000, 1999 and 1998....................... F-4
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2000, 1999 and 1998........... F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 1999 and 1998....................... F-6
Notes to Consolidated Financial Statements................ F-7
CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
None
Financial Statement schedules pursuant to regulations of the Securities and
Exchange Commission have been omitted because they are either not required, not
applicable or the information required to be presented is included in Belco's
financial statements and related notes.
F-1
44
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Belco Oil & Gas Corp.:
We have audited the accompanying consolidated balance sheets of Belco Oil &
Gas Corp. (a Nevada Corporation) and subsidiaries as of December 31, 2000 and
1999, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 2000. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Belco Oil &
Gas Corp. and subsidiaries as of December 31, 2000 and 1999, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2000, in conformity with accounting principles generally
accepted in the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas
February 23, 2001
F-2
45
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
------------------------
2000 1999
---------- ----------
(IN THOUSANDS)
ASSETS
Current Assets:
Cash and cash equivalents (including restricted cash of
$800,000 at December 31, 1999)......................... $ 2,666 $ 2,105
Accounts receivable....................................... 43,192 24,870
Income taxes receivable................................... -- 6,661
Assets from commodity price risk management activities.... 15,721 2,879
Prepaid expenses.......................................... 4,372 1,230
Other current assets...................................... 1,911 2,266
---------- ----------
Total Current Assets.............................. 67,862 40,011
Property and Equipment:
Oil and gas properties at cost based on full-cost
accounting --
Proved oil and gas properties.......................... 1,185,686 1,008,261
Unproved oil and gas properties........................ 68,979 71,075
Less -- Accumulated depreciation, depletion and
amortization.......................................... (674,735) (619,446)
---------- ----------
Net oil and gas property.................................. 579,930 459,890
---------- ----------
Building and other equipment.............................. 9,159 9,107
Less -- Accumulated depreciation....................... (3,914) (2,634)
---------- ----------
Net building and other equipment.......................... 5,245 6,473
Other Assets.............................................. 4,337 4,599
---------- ----------
Total Assets...................................... $ 657,374 $ 510,973
========== ==========
LIABILITIES AND EQUITY
Current Liabilities:
Accounts payable.......................................... $ 25,443 $ 17,970
Liabilities from commodity price risk management
activities............................................. 124,981 17,822
Accrued interest.......................................... 7,695 7,098
Accrued expenses.......................................... 8,926 3,743
Other liabilities......................................... 2,546 1,767
---------- ----------
Total Current Liabilities......................... 169,591 48,400
Long-Term Debt.............................................. 402,033 306,744
Deferred Income Taxes....................................... 7,933 33,638
Liabilities from commodity price risk management
activities................................................ 17,417 8,219
Stockholders' Equity:
Preferred stock, $0.01 par value; 10,000,000 shares
authorized and 3,273,600 and 3,985,000 outstanding at
December 31, 2000 and 1999, respectively............... 33 40
Common Stock, $0.01 par value; 120,000,000 shares
authorized; 32,342,315 and 31,797,300 issued and
outstanding at December 31, 2000 and 1999,
respectively........................................... 323 318
Additional paid-in capital................................ 292,635 297,225
Retained earnings deficit................................. (230,902) (177,111)
Treasury Stock, 704,900 shares at December 31, 1999....... -- (4,317)
Unearned compensation..................................... (936) (1,430)
Notes receivable for equity interest...................... (753) (753)
---------- ----------
Total Stockholders' Equity........................ 60,400 113,972
---------- ----------
Total Liabilities and Stockholders' Equity........ $ 657,374 $ 510,973
========== ==========
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-3
46
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------
2000 1999 1998
----------- ----------- ------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
Revenues:
Oil and gas sales, net of hedging activities............ $199,387 $141,932 $ 129,916
Commodity Price Risk Management Activities
-- Non-hedge cash settlements........................ (33,953) (2,442) 172
Interest................................................ 951 1,134 1,730
-------- -------- ---------
Total revenues.................................. 166,385 140,624 131,818
-------- -------- ---------
Costs and expenses:
Oil and gas operating expenses.......................... 33,290 29,854 33,615
Production taxes........................................ 14,464 9,314 7,232
Depreciation, depletion and amortization................ 56,721 54,182 56,102
Impairment of oil and gas properties.................... -- -- 229,000
Impairment of equity securities......................... -- 450 24,216
General and administrative.............................. 6,538 4,940 5,216
Interest expense........................................ 25,253 21,021 21,013
Non-cash change in fair value of derivatives............ 103,610 34,094 (18,912)
-------- -------- ---------
Total costs and expenses........................ 239,876 153,855 357,482
-------- -------- ---------
Income (loss) before income taxes......................... (73,491) (13,231) (225,664)
Provision (benefit) for income taxes...................... (25,722) (4,631) (78,107)
-------- -------- ---------
Net income (loss)....................................... (47,769) $ (8,600) $(147,557)
======== ======== =========
Net income (loss) available to common stock............. $(53,791) $(15,484) $(152,963)
======== ======== =========
Basic and diluted earnings (loss) per common share........ $ (1.71) $ (0.49) $ (4.85)
======== ======== =========
Weighted average common shares outstanding................ 31,469 31,642 31,529
======== ======== =========
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-4
47
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
NOTES
PREFERRED STOCK COMMON STOCK ADDITIONAL RETAINED RECEIVABLE
--------------- --------------- PAID-IN UNEARNED EARNINGS FOR EQUITY
SHARES AMOUNT SHARES AMOUNT CAPITAL COMPENSATION (DEFICIT) INTEREST
------ ------ ------ ------ ---------- ------------ --------- ----------
(IN THOUSANDS)
BALANCE, DECEMBER 31, 1997......... -- -- 31,584 $316 $196,864 $(1,093) $ (8,664) $(775)
===== === ====== ==== ======== ======= ========= =====
Comprehensive Income...............
Issuance of Preferred Stock........ 4,370 $44 -- -- $105,025 -- -- --
Repurchase of Preferred Stock...... (58) (1) -- -- (806) -- -- --
Restricted Stock Issued (Net)...... -- -- 25 -- 333 11 -- --
Unrealized loss on marketable
equity securities................ -- -- -- -- -- -- -- --
Net income (loss).................. -- -- -- -- -- -- (147,557) --
Preferred Dividend paid............ -- -- -- -- -- -- (5,406) --
----- --- ------ ---- -------- ------- --------- -----
BALANCE, DECEMBER 31, 1998......... 4,312 $43 31,609 $316 $301,416 $(1,082) $(161,627) $(775)
===== === ====== ==== ======== ======= ========= =====
Comprehensive Income...............
Repurchase of Preferred Stock...... (327) $(3) -- -- $ (5,049) -- -- --
Restricted Stock Issued............ -- -- 200 2 1,018 (1,020) -- --
Restricted Stock Forfeited......... -- -- (12) -- (160) 160 -- --
Restricted Stock Amortized......... -- -- -- -- -- 512 -- --
Net Income (Loss).................. -- -- -- -- -- -- (8,600) --
Preferred Dividend Paid............ -- -- -- -- -- -- (6,884) --
Treasury Stock Acquisitions........ -- -- -- -- -- -- -- --
Payment Received................... -- -- -- -- -- -- -- 22
----- --- ------ ---- -------- ------- --------- -----
BALANCE, DECEMBER 31, 1999......... 3,985 $40 31,797 $318 $297,225 $(1,430) $(177,111) $(753)
===== === ====== ==== ======== ======= ========= =====
Comprehensive Income...............
Exchanges of Preferred Stock to
Common Stock..................... (691) (7) 536 5 (4,315) -- -- --
Exercise of stock options.......... -- -- 2 -- 10 -- -- --
Repurchase of Preferred Stock...... (20) -- -- -- (303) -- -- --
Restricted Stock Issued............ -- -- 10 -- 49 (49) -- --
Restricted Stock Forfeited......... -- -- (3) -- (31) 31 -- --
Restricted Stock Amortized......... -- -- -- -- -- 512 -- --
Net Income (Loss).................. -- -- -- -- -- -- (47,769) --
Preferred Dividend Paid............ -- -- -- -- -- -- (6,022) --
----- --- ------ ---- -------- ------- --------- -----
BALANCE, DECEMBER 31, 2000......... 3,274 $33 32,342 $323 $292,635 $ (936) $(230,902) $(753)
===== === ====== ==== ======== ======= ========= =====
Comprehensive Income...............
UNREALIZED
TREASURY LOSS ON
COMMON STOCK MARKETABLE
---------------- EQUITY COMPREHENSIVE
SHARES AMOUNT SECURITIES TOTAL INCOME
------ ------- ---------- --------- -------------
(IN THOUSANDS)
BALANCE, DECEMBER 31, 1997......... -- $ -- $(2,000) $ 184,648
==== ======= ======= =========
Comprehensive Income............... $ (58,228)
=========
Issuance of Preferred Stock........ -- -- -- $ 105,069 --
Repurchase of Preferred Stock...... -- -- -- (807) --
Restricted Stock Issued (Net)...... -- -- -- 344 --
Unrealized loss on marketable
equity securities................ -- -- 2,000 2,000 1,320(a)
Net income (loss).................. -- -- -- (147,557) (147,557)
Preferred Dividend paid............ -- -- -- (5,406) --
---- ------- ------- --------- ---------
BALANCE, DECEMBER 31, 1998......... -- $ -- $ -- $ 138,291
==== ======= ======= =========
Comprehensive Income............... $(146,237)
=========
Repurchase of Preferred Stock...... -- -- -- $ (5,052) --
Restricted Stock Issued............ -- -- -- --
Restricted Stock Forfeited......... -- -- -- -- --
Restricted Stock Amortized......... -- -- -- 512 --
Net Income (Loss).................. -- -- -- (8,600) (8,600)
Preferred Dividend Paid............ -- -- -- (6,884) --
Treasury Stock Acquisitions........ (705) (4,317) -- (4,317) --
Payment Received................... -- -- -- 22 --
---- ------- ------- --------- ---------
BALANCE, DECEMBER 31, 1999......... (705) $(4,317) $ -- $ 113,972
==== ======= ======= =========
Comprehensive Income............... $ (8,600)
=========
Exchanges of Preferred Stock to
Common Stock..................... 705 4,317 -- -- --
Exercise of stock options.......... -- -- -- 10 --
Repurchase of Preferred Stock...... -- -- -- (303) --
Restricted Stock Issued............ -- -- -- -- --
Restricted Stock Forfeited......... -- -- -- -- --
Restricted Stock Amortized......... -- -- -- 512 --
Net Income (Loss).................. -- -- -- (47,769) (47,769)
Preferred Dividend Paid............ -- -- -- (6,022) --
---- ------- ------- --------- ---------
BALANCE, DECEMBER 31, 2000......... -- $ -- $ -- $ 60,400
==== ======= ======= =========
Comprehensive Income............... $ (47,769)
=========
- ---------------
(a) Represents a reclassification adjustment for $2.0 million gross ($1.32
million net of tax) unrealized loss recognized in comprehensive income in
1997, but recognized in net income during 1998.
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-5
48
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------
2000 1999 1998
--------- -------- ---------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)...................................... $ (47,769) $ (8,600) $(147,557)
Adjustments to reconcile net income (loss) to net
operating cash inflows --
Depreciation, depletion and amortization............ 56,721 54,182 56,102
Impairment of oil and gas properties................ -- -- 229,000
Impairment of equity securities..................... -- 450 9,773
Deferred tax benefit................................ (25,722) (4,856) (78,107)
Commodity price risk management activities.......... 9,293 5,901 2,942
Other............................................... 202 203 (19)
Changes in operating assets and liabilities --
Commodity price risk management................... 94,317 28,193 (21,869)
Accounts receivable............................... (11,781) 3,617 15,208
Marketable equity securities...................... -- -- 30,884
Other current assets.............................. (2,594) (1,292) 247
Accounts payable and accrued liabilities.......... 14,031 246 (10,259)
--------- -------- ---------
Net operating cash inflows..................... 86,698 78,044 86,345
--------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures............... (186,845) (73,932) (133,078)
Proceeds from sale of oil and gas properties........... 11,517 215 6,292
Purchase of marketable equity securities............... -- -- (10,467)
Changes in other assets................................ 569 (351) (22)
Other property additions............................... (523) (474) (1,251)
--------- -------- ---------
Net investing cash outflows.................... (175,282) (74,542) (138,526)
--------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings................................... 324,500 53,500 68,000
Long-term debt repayments.............................. (225,500) (41,100) (124,500)
Proceeds from issuance of Preferred Stock.............. -- -- 105,069
Dividends on Preferred Stock........................... (6,022) (6,884) (5,406)
Repurchase of Common Stock............................. -- (4,317) --
Repurchase of Preferred Stock.......................... (303) (5,052) (807)
Repurchase of Bonds.................................... (2,850) -- --
Credit Agreement fee................................... (691) -- --
Other.................................................. 11 21 --
--------- -------- ---------
Net financing cash inflows (outflows).......... 89,145 (3,832) 42,356
--------- -------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS......... 561 (330) (9,825)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD......... 2,105 2,435 12,260
--------- -------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD............... $ 2,666 $ 2,105 $ 2,435
========= ======== =========
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-6
49
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- ORGANIZATION AND NATURE OF OPERATIONS
Organization
Belco Oil & Gas Corp. ("Belco") was organized as a Nevada corporation in
January 1996 in connection with the combination of assets (the "Combination")
consisting of ownership interests (the "Combined Assets") in certain entities
and direct interests in oil and gas properties and certain hedge transactions
owned by the predecessors and entities related thereto. On March 29, 1996, Belco
Oil & Gas Corp. completed its initial public offering (the "Offering") issuing
6,500,000 shares of Common Stock at $19 per share. Belco Oil & Gas Corp. and the
owners of the Combined Assets entered into an Exchange and Subscription
Agreement and Plan of Reorganization dated as of January 1, 1996 (the "Exchange
Agreement") that provided for the issuance by Belco of an aggregate of
25,000,000 shares of Common Stock to such owners in exchange for the Combined
Assets on March 29, 1996, the date the Offering closed. The owners of the
Combined Assets received shares of Common Stock proportionate to the value of
the Combined Assets underlying their ownership interests in the predecessors and
the direct interests.
The Combination was accounted for as a reorganization of entities under
common control because of the common control of our stockholders and by virtue
of their direct ownership of the entities and interests exchanged. Accordingly,
the net assets acquired in the Combination have been recorded at the historical
cost basis of the affiliated predecessor owners. Belco currently conducts the
majority of our business through our wholly owned subsidiaries, Belco Energy
Corp. and Belco Energy I L.P.
Nature of Current Operations
Belco is an independent energy company engaged in the exploration,
development and production of natural gas and oil. Belco operates in this single
industry segment, and all operations are presently conducted in the United
States. Belco's operations are focused in four core areas including the Permian
Basin (west Texas), the Mid-Continent (Oklahoma, north Texas and Kansas), the
Rocky Mountains (Wyoming and North Dakota), and the Gulf Coast/Austin Chalk
(Texas, Arkansas and Louisiana).
Substantially all of Belco's production is sold under market-sensitive
contracts. Belco's revenue, profitability and future rate of growth are
substantially dependent upon the price of, and demand for, oil, natural gas and
natural gas liquids. Prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond the control of Belco. These factors include the level of
consumer product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, the foreign supply of oil and natural gas, the
price of foreign imports and overall economic conditions. With the objective of
reducing price risk, Belco has entered into hedging and related price risk
management transactions with respect to a significant amount of its expected
future production (See Note 6).
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements for the periods presented include the
accounts of Belco and its wholly-owned subsidiaries. Belco's interests in the
Moxa Arch investment programs (the 1992 Moxa Arch Drilling Program, the 1993
Moxa Arch Drilling Program, the Moxa Arch 1992 Offset Drilling Program and the
Moxa Arch 1993 Offset Drilling Program) (collectively, the "Programs") are
accounted for using the proportionate consolidation method of accounting for
investments in oil and gas property interests, whereby Belco's share of each
program's assets, liabilities, revenues and expenses is included in the
appropriate accounts of the consolidated financial statements. All material
intercompany balances and transactions have
F-7
50
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
been eliminated. Certain reclassifications have been made to prior period
amounts to conform to current year presentations.
Cash Equivalents
Belco considers all highly liquid investments with an original maturity of
three months or less to be cash equivalents. At December 31, 1999 cash includes
$800,000 of funds related to Commodity Price Risk Management activities on
deposit with a counterparty. The depository amount varies from day to day and is
dependent on the movement of commodity prices.
Prepaid Expenses
Prepaid expenses consist primarily of settlements paid on certain CPRM
contracts applicable to future production months and prepaid insurance. All
prepaid expenses are amortized over the contract life, which typically is one
year or less.
Property and Equipment
Belco follows the full-cost method of accounting for oil and gas
properties. Accordingly, all costs associated with acquisition, exploration and
development of oil and gas reserves, including directly related internal costs,
are capitalized. Belco capitalized $3,684,000, $5,492,000 and $6,054,000 of
related internal costs during 2000, 1999 and 1998, respectively.
Oil and gas properties are amortized on the unit-of-production method using
estimates of proved reserve quantities. Investments in unproved properties are
not amortized until proved reserves associated with the projects can be
determined or until impairment occurs. The amortizable base includes estimated
future development costs and, where significant, dismantlement, restoration and
abandonment costs, net of estimated salvage values.
In addition, the capitalized costs of proved oil and gas properties are
subject to a "ceiling test," which limits such costs to the estimated present
value net of related tax effects of future net cash flows from proved reserves.
The estimated present value is based on current economic and operating
conditions and discounted at a 10 percent interest rate (PV10). If capitalized
costs exceed this limit, the excess is charged to depreciation, depletion and
amortization.
The PV10 value of Belco's year-end 2000 and 1999 estimated proved reserves
were well in excess of the ceiling test limit. For the full year ended December
31, 1998 Belco recorded $229 million ($149 million after tax) in non-cash
ceiling test provisions as required by full cost accounting rules. The
provisions were the result of applying substantially lower commodity prices to
estimated recoverable reserves.
Sales and other dispositions of proved and unproved properties are
accounted for as adjustments of capitalized costs with no gain or loss
recognized, unless significant reserves are involved. Abandonments of properties
are accounted for as adjustments of capitalized costs with no loss recognized.
Buildings, equipment and gas processing facilities are depreciated on a
straight-line basis over the estimated useful lives of the assets, which range
from three to 20 years.
Management Fees
Belco manages several investment programs, which were formed during
1992-1994 to acquire and develop interests in certain drilling prospects located
in the Moxa Arch trend in Wyoming. Belco offered, to certain qualified
investors, the opportunity to invest in the prospects through participation in
the Programs. In return for its management activities on behalf of the Programs,
Belco earns an annual management fee of one percent of committed capital. After
elimination of management fees received from affiliated entities, including
F-8
51
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
predecessor owners, Belco earned management fees totaling $375,000 for the year
2000 and $305,000 for both 1999 and 1998.
Capitalization of Interest
Interest costs related to the acquisition and development of unproved
properties are capitalized to oil and gas properties. Interest costs capitalized
for the years ended December 31, 2000, 1999 and 1998, totaled $7,570,000,
$4,881,000 and $5,123,000, respectively.
Accounting for Commodity Price Risk Management Activities
Belco engages in price risk management activities in order to manage its
exposure to oil and gas price volatility. Commodity derivatives contracts, which
are usually placed with major financial institutions that Belco believes are
minimal credit risks, may take the form of futures contracts, swaps or options.
The oil and gas reference prices upon which these commodity derivatives
contracts are based reflect various market indices that have a high degree of
historical correlation with actual prices received by Belco. Gains and losses
related to qualifying hedges of Belco's oil and gas production are deferred and
are recognized as revenues as the associated production occurs. In the event of
a loss of correlation between changes in oil and gas reference prices under a
commodity derivatives contract and actual oil and gas prices, a gain or loss is
recognized currently to the extent the commodity derivatives have not offset
changes in actual oil and gas prices.
Transactions that do not qualify for hedge accounting are accounted for
using the mark-to-market method. Under such method, the financial instruments
are reflected at market value at the end of the period with resulting unrealized
gains and losses recorded as assets and liabilities in the consolidated
financial statements. Changes in the market value of outstanding financial
instruments are recognized as a gain or loss in the period of change (See Note
6).
Gas Balancing/Revenue Recognition
Belco uses the sales method to account for natural gas imbalances. Under
the sales method, Belco recognizes revenues based on the amount of gas sold to
purchasers, which may differ from the amounts to which Belco is entitled based
on its interests in the properties. However, revenue is deferred and a liability
is recorded for those properties where production sold by Belco exceeds its
entitled share of remaining natural gas reserves. Gas balancing obligations as
of December 31, 2000 and 1999 were not significant.
Income Taxes
Belco accounts for income taxes under the provisions of SFAS No.
109 -- "Accounting for Income Taxes," which provides for an asset and liability
approach for accounting for income taxes. Under this approach, deferred tax
assets and liabilities are recognized based on anticipated future tax
consequences, using currently enacted tax laws, attributable to differences
between financial statement carrying amounts of assets and liabilities and their
respective tax bases. Deferred tax assets are reduced by a valuation allowance
when, based upon management's estimate, it is more likely than not that a
portion of the deferred tax assets will not be realized in a future period.
Net Income (Loss) Per Common Share
Basic and diluted net income (loss) per common share have been computed in
accordance with SFAS No. 128, "Earnings Per Share," which Belco adopted at year
end 1997. Net income per share amounts for prior periods have been restated to
conform with the provisions of the standard. Basic net income per common share
is computed by dividing income available to common shareholders, after the
payment of dividends to preferred stockholders, by the weighted average number
of common shares outstanding for the periods.
F-9
52
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Diluted net income per common share reflects the potential dilution that could
occur if securities or other contracts to issue common stock were exercised or
converted into common stock. Calculations of basic and diluted net income (loss)
per common share are illustrated in Note 12.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Significant estimates with regard to these financial statements include the
estimated fair value of oil and gas commodity price risk management contracts
and the estimate of proved oil and gas reserve volumes and the related
discounted future net cash flows therefrom (See Notes 6 and 15).
NOTE 3 -- LONG TERM DEBT
Long term debt consists of the following at December 31, 2000 and 1999 (in
thousands):
DECEMBER 31,
--------------------
2000 1999
-------- --------
Revolving credit facility due 2004..................... $141,000 $ 42,000
8 7/8% Senior Subordinated Notes due 2007.............. 147,000 150,000
10 1/2% Senior Subordinated Notes due 2006, including
premium totaling approximately $5.0 and $5.7 million
for 2000 and 1999, respectively...................... 114,033 114,744
-------- --------
Total Debt................................... 402,033 306,744
Less: Current maturities............................... -- --
-------- --------
Long term debt......................................... $402,033 $306,744
======== ========
In September 1997, we entered into a five-year $150 million Credit
Agreement dated September 23, 1997 with The Chase Manhattan Bank, N.A., as
administrative agent and other lending institutions. In June 2000, the credit
facility was amended and restated and now provides for an aggregate principal
amount of revolving loans of up to the lesser of $250 million or a defined
borrowing base in effect from time to time, includes a sub-facility for letters
of credit and expires in January 2004. The borrowing base at December 31, 2000
was $200 million with $141.0 million advanced at that date. Additionally, there
were letters of credit outstanding in the amount of $36.5 million in connection
with CPRM activities. The borrowing base is redetermined by the agent and the
banks semi-annually based upon their usual and customary oil and gas lending
criteria as such exist from time to time. In addition, we may request two
additional redeterminations and the banks may request one additional
redetermination per year. During 2000 the credit facility weighted average
interest rate was approximately 7.6%.
Indebtedness under the credit facility is secured by a pledge of the
capital stock of each of Belco's material subsidiaries. Covenants contained in
the credit facility require us to maintain a minimum interest coverage ratio and
current ratio, as defined in the agreement. Belco and its subsidiaries may not
incur any indebtedness other than indebtedness falling within the enumerated
exceptions contained in the credit facility. In addition, Belco's various debt
instruments contain certain restrictive covenants that, among other things,
limit our ability to pay dividends.
Indebtedness under the credit facility bears interest at a floating rate
based (at our option) upon (i) the ABR with respect to ABR Loans or (ii) the
Eurodollar Rate (as defined) for one, two, three or six months (or nine or
twelve months if available to the banks) Eurodollar Loans (as defined), plus the
Applicable Margin.
F-10
53
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The ABR is the greater of (i) the Prime Rate (as defined), (ii) the Base CD Rate
(as defined) plus 1% or (iii) the Federal Funds Effective Rate (as defined) plus
0.50%. The Applicable Margin for Eurodollar Loans varies from 1.125% to 1.625%
depending on the borrowing base usage. Borrowing base usage is determined by a
ratio of (i) outstanding Loans (as defined) and letters of credit to (ii) the
then effective borrowing base. Interest on ABR Loans is payable quarterly in
arrears and interest on Eurodollar Loans is payable on the last day of the
interest period therefore and, if longer than three months, at three month
intervals.
We are required to pay to the banks a commitment fee based on the committed
undrawn amount of the lesser of the aggregate commitments or the then effective
borrowing base during a quarterly period equal to a percent that varies from
0.25% to 0.50% depending on the borrowing base usage.
In September 1997, Belco issued $150 million of the 8 7/8% Notes. In
January 2000, we purchased $3 million face value of the notes in the open
market. Interest accrues at the rate of 8 7/8% per annum and is payable
semi-annually in arrears on March 15 and September 15 of each year. The 8 7/8%
Notes mature on September 15, 2007 unless previously redeemed. Except under
limited circumstances, the 8 7/8% Notes are not redeemable at Belco's option
prior to September 15, 2002. Thereafter, the 8 7/8% Notes will be subject to
redemption at the option of Belco, in whole or in part, at specified redemption
prices, plus accrued and unpaid interest, if any, thereon to the applicable
redemption date. In addition, upon a change of control (as defined in the
indenture pursuant to which the 8 7/8% Notes were issued (the "8 7/8%
Indenture")) Belco is required to offer and redeem the 8 7/8% Notes for cash at
101% of the principal amount, plus accrued and unpaid interest, if any, thereon
to the applicable date of repurchase.
The 8 7/8% Notes are general unsecured obligations of Belco and are
subordinated in right of payment to all existing and future senior debt (as
defined in the 8 7/8% Indenture) of Belco, which includes borrowings under the
Credit Facility described above. The 8 7/8% Notes rank pari passu in right of
payment with any existing or future senior subordinated debt of Belco and rank
senior in right of payment to all other subordinated indebtedness of Belco.
As of December 31, 2000, Belco had outstanding $109 million face value of
the 10 1/2% Notes. The debt was assumed in connection with the acquisition of
Coda in 1997 and was recorded at $117.1 million, including premium, reflecting
the fair value at the date of acquisition. The 10 1/2% Notes bear interest at an
annual rate of 10 1/2% payable semiannually in arrears on April 1 and October 1
of each year. The Notes are general, unsecured obligations of Belco, are
subordinated in right of payment to all Senior Debt (as defined in the Indenture
governing the 10 1/2% Notes) of Belco, and are senior in right of payment to all
future subordinated debt of Belco. On February 25, 1998, Belco merged Coda into
Belco and Belco assumed the obligations under the Coda Indenture. Effective with
the merger, the 10 1/2% Notes became pari passu in right of payment with the
8 7/8% Notes.
The 10 1/2% Notes were issued pursuant to an Indenture, which contains
certain covenants that, among other things, limit the ability of Coda and its
restricted subsidiaries (as defined in the Indenture) to incur additional
indebtedness and issue Disqualified Stock (as defined in the Indenture), pay
dividends, make distributions, make investments, make certain other restricted
payments, enter into certain transactions with affiliates, dispose of certain
assets, incur liens securing pari passu or subordinated indebtedness of Belco
and engage in mergers and consolidations.
The 10 1/2% Notes mature April 1, 2006 and are not redeemable by Belco
prior to April 1, 2001. After April 1, 2001, the 10 1/2% Notes will be subject
to redemption at the option of Belco, in whole or in part, at the redemption
prices set forth in the Indenture, plus accrued and unpaid interest thereon to
the applicable redemption date.
As of December 31, 2000, Belco was in compliance with all debt covenants.
F-11
54
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Belco has entered into interest rate swap agreements converting two fixed
rate obligations to floating rate obligations. The agreements cover $150 million
of 8 7/8% long-term debt (comparable to the interest rate on the 8 7/8% Notes)
and obligates Belco to pay an initial rate of 8.175% through September 15, 1998.
Thereafter, the rate is redetermined at each six month period through September
15, 2007. The floating rates are capped at 8 7/8% through September 15, 2001 and
at 10% from March 15, 2002 through September 15, 2007. The remaining agreement
currently covers $85 million of 10 1/2% long-term debt (comparable to the
interest rate on the 10 1/2% Notes) and obligates Belco to pay an initial rate
of 9.8881% through April 1, 1998. Thereafter, the rate is redetermined at each
six month period through 2003. Floating rates on this agreement are capped at
10 1/2% through October 1, 1999 and 11.625% from April 1, 2000 through April 1,
2003.
NOTE 4 -- RELATED-PARTY TRANSACTIONS
Belco's executive offices are leased from its Chairman and approximately
$250,000 was paid under such lease in 2000, 1999 and 1998. Management believes
the fee compares favorably to the terms which might have been available from a
non-affiliated party.
Certain employees of Belco had an ownership interest in certain oil and gas
properties held by Belco as of December 31, 1995. Belco had receivables of
$753,000 as of December 31, 2000 and 1999 related to amounts loaned to employees
in connection with purchases of oil and gas interests from such employees. The
notes receivable have been recorded as a reduction of equity in the consolidated
balance sheets, as such interests were exchanged for Common Stock in the
Combination (See Note 1).
NOTE 5 -- INCOME TAXES
Total provision (benefit) for income taxes consists of the following:
YEARS ENDED DECEMBER 31,
-------------------------------
2000 1999 1998
-------- ------- --------
(IN THOUSANDS)
CURRENT:
Federal(a)........................................ $ (17) $(6,661) $ 20
State............................................. -- 225 87
-------- ------- --------
(17) (6,436) 107
DEFERRED:........................................... (25,705) 1,805 (78,214)
-------- ------- --------
Total income tax provision (benefit)...... $(25,722) $(4,631) $(78,107)
======== ======= ========
- ---------------
(a) The 1999 federal income tax amount reflects a tax benefit of $6.7 million
for which a refund claim was filed in late 1999. Accordingly, this amount
was recorded as an income tax refund receivable as of December 31, 1999. The
refund was received in January 2000.
F-12
55
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The differences between the statutory federal income taxes and Belco's
effective taxes is summarized as follows (in thousands):
YEARS ENDED DECEMBER 31,
-------------------------------
2000 1999 1998
-------- ------- --------
Statutory federal income taxes...................... $(25,722) $(4,631) $(78,982)
State income tax, net of federal benefit............ -- 146 57
Section 29 tax credits.............................. -- -- --
Capital loss valuation allowance.................... -- (161) 875
Other............................................... -- 15 (57)
-------- ------- --------
Provision (benefit) for income taxes................ $(25,722) $(4,631) $(78,107)
======== ======= ========
The principal components of Belco's net deferred income tax liability are
as follows:
YEARS ENDED
DECEMBER 31,
--------------------
2000 1999
-------- --------
(IN THOUSANDS)
DEFERRED INCOME TAX ASSETS:
Net operating loss................................... $ 63,443 $ 21,416
Capital loss......................................... 4,495 4,495
Other................................................ 7,395 8,095
-------- --------
Sub-total......................................... $ 75,333 $ 34,006
-------- --------
DEFERRED INCOME TAX LIABILITIES:
Depreciation, depletion and Amortization............. $(65,353) $(60,834)
Commodity price risk management activities........... (15,710) (1,875)
Other................................................ (1,489) (4,221)
-------- --------
Sub-total......................................... (82,552) (66,930)
Valuation allowance.................................... (714) (714)
-------- --------
Total Net deferred income tax liability........... $ (7,933) $(33,638)
======== ========
As a result of the acquisition of Coda, Belco succeeded to net operating
loss carryforwards ("NOLs") for income tax purposes that expire from 2000
through 2004. Due to a change of ownership (as defined by the Tax Return Act of
1986) which occurred prior to the acquisition by Belco, the utilization of the
Coda NOLs is severely restricted. At December 31, 2000, Belco estimates that
approximately $13.3 million of the Coda NOLs is available to offset future
income. Belco generated approximately $122.3 million of NOL for the year ended
December 31, 2000 that can be carried forward through the year 2021. For the
year ended December 31, 1999, Belco generated an NOL of $45.7 million which can
be carried forward from 2000 to 2020. In addition to the NOLs, at December 31,
2000, Belco has approximately $12.8 million of capital loss carry forwards which
may be used to offset capital gains realized over the next three years. A
valuation allowance of $2.0 million was established against the capital loss
carryforward since this amount is not expected to meet the realization test.
Belco also has $0.6 million of alternative minimum tax ("AMT") credit
carryovers. AMT credits may be carried forward indefinitely.
Section 29 Tax Credit
The natural gas production from wells drilled on certain of Belco's
properties in the Moxa Arch Trend and Golden Trend Field qualifies for the
Section 29 Tax Credit. The Section 29 Tax Credit is an income tax
F-13
56
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
credit against regular federal income tax liability with respect to sales of
Belco's production of natural gas produced from tight gas sand formations,
subject to a number of limitations. Fuels qualifying for the Section 29 Tax
Credit must be produced from a well drilled or a facility placed in service
after November 5, 1990 and before January 1, 1993, and be sold before January 1,
2003.
The basic credit, which is currently approximately $0.52 per MMBtu of
natural gas produced from tight sand reservoirs and approximately $1.05 per
MMBtu of natural gas produced from Devonian Shale, is computed by reference to
the price of crude oil and is phased out as the price of oil exceeds $23.50 in
1979 dollars (as adjusted for inflation) with complete phaseout if such price
exceeds $29.50 in 1979 dollars (as adjusted for inflation). Under this formula,
the commencement of phaseout would be triggered if the average price for crude
oil rose above approximately $47 per Bbl in current dollars. Belco estimates
that it generated approximately $0.5 million of Section 29 Tax Credits in 2000.
The Section 29 Tax Credit may not be credited against the alternative minimum
tax, but under certain circumstances may be carried over and applied against
regular tax liability in future years. Therefore, no assurances can be given
that Belco's Section 29 Tax Credits will reduce its federal income tax liability
in any particular year. As production from qualified wells decline, the produced
based tax credit will also decline.
Texas Severance Tax Abatement
Production from natural gas wells that have been certified as tight
formations or deep wells by the Texas Railroad Commission ("high cost gas
wells") and that are spudded or completed during the period from May 24, 1989 to
September 1, 1996 qualify for an exemption from the 7.5% severance tax in Texas
on natural gas and natural gas liquids produced by such wells prior to August
31, 2001. The natural gas production from wells drilled on certain of Belco's
properties in the Austin Chalk area qualify for this tax reduction. In addition,
high cost gas wells that are spudded or completed during the period from
September 1, 1996 to August 31, 2010 are entitled to receive a severance tax
reduction upon obtaining a high cost gas certification from the Texas Railroad
Commission within 180 days after first production. The tax reduction is based on
a formula composed of the statewide "median" (as determined by the State of
Texas from producer reports) and the producer's actual drilling and completion
costs. More expensive wells will receive a greater amount of tax credit. This
tax rate reduction remains in effect for 10 years or until the aggregate tax
credits received equal 50% of the total drilling and completion costs. The
reduction in severance taxes for such wells is reflected as a reduction in oil
and gas operating expenses and an increase in the standardized measure of
discounted future net cash flows relating to proved oil and gas reserves (See
Note 14).
NOTE 6 -- COMMODITY PRICE RISK MANAGEMENT ACTIVITIES (OR CPRM):
We periodically enter into CPRM transactions such as swaps and options in
order to manage our exposure to oil and gas price volatility. Gains and losses
related to hedges of our oil and gas production that qualify for hedge
accounting treatment are deferred and recognized as revenues as the associated
production occurs.
We use the mark-to-market method of accounting for instruments that do not
qualify for hedge accounting treatment. Under mark-to-market accounting, those
contracts that do not qualify for hedge accounting treatment are reflected at
market value at the end of the period with resulting unrealized gains and losses
recorded as assets and liabilities in the consolidated balance sheet. Under such
method, changes in the market value of outstanding financial instruments are
recognized as unrealized gain or loss in the period of change.
The tables and related notes set forth in this footnote provide details
about the volumes and prices of all open Belco CPRM commitments, hedge and
non-hedge, as of December 31, 2000. Since most of the contracts covering a
substantial portion of the committed volumes were entered into in 1997 and early
1998 when commodity prices were substantially below current commodity price
levels, it is not possible to estimate
F-14
57
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
future average prices to be realized given the broad ranges covering both
volumes and prices committed at different points in time.
For the year ended December 31, 2000, we recorded as required by existing
accounting rules non-hedge commodity price risk management losses of $137.6
million, consisting of $34.0 million in cash settlements and $103.6 million in
unrealized non-cash mark-to-market losses. This compares to a $36.5 million net
loss consisting of $2.4 million in cash settlements paid and $34.1 million in
unrealized non-cash mark-to-market losses reported for 1999. Certain of Belco's
CPRM arrangements require Belco to deliver cash collateral or other assurances
of performance to the counterparties in the event that Belco's payment
obligations with respect to its CPRM transactions exceed certain levels. Two of
the inherent risks of a price risk management program are margin requirements
and collateralization. Certain transactions may be subject to margin calls under
certain conditions. Letters of credit in the amount of $36.5 million in favor of
counterparties were outstanding at December 31, 2000 and related to unrealized
non-cash mark-to-market and potential hedge losses at that date.
The following table and notes thereto cover Belco's pricing and notional
volumes on open natural gas and oil commodity hedges as of December 31, 2000:
PRODUCTION PERIODS
---------------------------
2001 2002 2003
------- ------ ------
GAS(1) --
Price swaps sold -- receive fixed price (thousand
MMBtu)(2).......................................... 905 -- 913
Average price, per MMBtu........................... $ 2.30 -- $ 3.35
Price swaps bought -- pay fixed price (thousand
MMBtu)(2).......................................... (6,710) -- --
Average price, per MMBtu........................... $ 4.33 -- --
Sub-total -- net swap volume (thousand MMBtu).... (5,805) -- --
Collars (thousand MMBtu)(4)........................... 9,125 5,475 3,650
Average floor price, per MMBtu..................... $ 1.91 $ 2.50 $ 2.85
Average ceiling price, per MMBtu................... $ 2.85 $ 3.49 $ 4.91
Puts bought (thousand MMBtu)(3)....................... 228 3,650 --
Average price per MMBtu............................ 4.50 3.13 --
Calls bought (thousand MMBtu)(3)...................... (1,513) -- --
Average price per MMBtu............................ 7.07 -- --
OIL --
Price swaps sold -- receive fixed price (MBbls)(2).... 1,170 660 240
Average price, per Bbl............................. $ 19.54 $19.51 $19.60
Price swaps bought -- pay fixed price (MBbls)(2)...... (165) -- --
Average price, per Bbl............................. $ 28.53 -- --
Sub-total -- net swap volumes.................... 1,005 660 240
Collars sold (MBbls)(4)............................... 300 120 90
Average floor price, per Bbl....................... $ 18.30 $19.00 $21.00
Average ceiling price per Bbl...................... $ 22.12 $22.63 $24.63
- ---------------
(1) Belco sells the majority of its Wyoming gas at prices based on the Northwest
Pipeline Rocky Mountain Index and has entered into basis swaps that require
the Counterparty to make a payment to Belco in the event that the NYMEX
Reference Price per MMBtu for a reference period exceeds the Northwest
Pipeline Rocky Mountain Index Price by more than a stated differential and
requires Belco to make a payment to the Counterparty in the event that the
NYMEX Reference Price exceeds the Northwest
F-15
58
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pipeline Rocky Mountain Index Price by less than a stated differential (or
in the event that the Northwest Pipeline Rocky Mountain Index Price is
greater than the NYMEX Reference Price). Natural gas volumes covered by
basis transactions include 10,000 MMBtu/d at $0.27 for the year 2001.
Belco sells the majority of its East Texas gas at prices based on the Katy
and Houston Ship Channel Indices and has entered into basis swaps that
require the Counterparty to make a payment to Belco in the event that the
NYMEX Reference Price per MMBtu for a reference period exceeds the Katy and
Houston Ship Channel Indices Prices by more than a stated differential and
requires Belco to make a payment to the Counterparty in the event that the
NYMEX Reference Price exceeds the Katy and Houston Ship Channel Indices
Prices by less than a stated differential (or in the event that the Katy and
Houston Ship Channel Indices Prices are greater than the NYMEX Reference
Price). Natural gas volumes covered by basis transactions include 25,000
MMBtu/d at $0.02 for Katy and 5,000 MMBtu/d at $0.005 (over the NYMEX
Reference Price) for Houston Ship Channel for the year 2001.
(2) For any particular swap sold transaction, the Counterparty is required to
make a payment to Belco in the event that the NYMEX Reference Price for any
settlement period is less than the swap price for such hedge, and Belco is
required to make a payment to the Counterparty in the event that the NYMEX
Reference Price for any settlement period is greater than the swap price for
such hedge. Conversely, swaps bought require Belco to make a payment to the
Counterparty in the event that the NYMEX Reference Price for any settlement
period is less than the swap price for such hedge, and the Counterparty is
required to make a payment to Belco in the event that the NYMEX Reference
Price for any settlement period is greater than the swap price for such
hedge.
(3) Calls sold or puts sold under written option contracts, in return for a
premium received by Belco upon initiation of the contract. Belco is required
to make a payment to the Counterparty in the event that the NYMEX Reference
Price for any settlement period is greater than the price of the call sold,
or less than the price of the put sold. Conversely, calls or puts bought in
return for Belco's payment of a premium require the Counterparty to make a
payment to Belco in the event that the NYMEX Reference Price on any
settlement period is greater than the call price or less than the put price.
(4) For any particular collar transaction, the Counterparty is required to make
a payment to Belco if the average NYMEX Reference Price for the reference
period is below the floor price for such transaction, and Belco is required
to make payment to the Counterparty if the average NYMEX Reference Price is
above the ceiling price for such transaction.
Non-Hedging Transactions
We use the mark-to-market method of accounting for instruments that do not
qualify for hedge accounting treatment. The year 2000 results of operations
included an aggregate non-cash pre-tax loss of $103.6 million related to these
activities resulting from net change in the value of Belco's market-to-market
portfolio of price risk management activities. At December 31, 2000, Belco's
consolidated balance sheet reflects $15.7 million and $142.4 million of price
risk management assets and liabilities, respectively.
F-16
59
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table and notes thereto cover Belco's pricing and notional
volumes on open natural gas and oil financial instruments at December 31, 2000,
that do not qualify for hedge accounting:
PRODUCTION PERIODS
---------------------------
2001 2002 2003
------- ------ ------
GAS --
Calls sold (thousand MMBtu)(1).......................... 3,788 4,380 --
Average price, per MMBtu.............................. $ 3.27 $ 2.95 --
Price Swaps Sold -- receive fixed price (thousand
MMBtu)(2)............................................. 21,900 --
Average price, per MMBtu.............................. $ 2.55 -- --
Price Swaps Bought -- pay fixed price (thousand
MMBtu)(2)............................................. (1,365) -- --
Average price, per MMBtu.............................. $ 3.29 -- --
Sub-total net swap volume (thousand MMBtu)......... 20,535 -- --
------- ------ ------
Puts Sold (thousand MMBtu)(1)........................... (2,981) -- --
Average price, per MMBtu.............................. $ 4.58 -- --
Extension Swaps Sold -- receive fixed price (thousand
MMBtu)(2)............................................. -- 3,650 --
Average price, per MMBtu.............................. -- $ 2.65 --
OIL --
Price Swaps Sold -- receive fixed price (MBbls) (2)..... 120 -- --
Average price, per Bbl................................ $ 17.25 -- --
Calls Sold (MBbls)(1)................................... 840 720 --
Average price, per Bbl................................ $ 20.21 $22.00 --
Puts Sold (MBbls)(1).................................... (345) -- --
Average price, per Bbl................................ $ 21.99 -- --
Extension Swaps Sold, receive fixed price (MBbls)(2).... -- 300 300
Average price, per Bbl................................ -- $18.86 $18.86
Extension Collars Sold(3)............................... 120 -- --
Average ceiling price................................. $ 20.35 -- --
Average floor price................................... $ 17.50 -- --
- ---------------
(1) Calls sold or puts sold under written option contracts, in return for a
premium received by Belco upon initiation of the contract. Belco is required
to make a payment to the Counterparty in the event that the NYMEX Reference
Price for any settlement period is greater than the price of the call sold,
or less than the price of the put sold. Conversely, calls or puts bought in
return for Belco's payment of a premium require the Counterparty to make a
payment to Belco in the event that the NYMEX Reference Price on any
settlement period is greater than the call price or less than the put price.
(2) For any particular swap sold transaction, the Counterparty is required to
make a payment to Belco in the event that the NYMEX Reference Price for any
settlement period is less than the swap price for such instrument and Belco
is required to make a payment to the Counterparty in the event that the
NYMEX Reference Price for any settlement period is greater than the swap
price for such instrument. Conversely, swaps bought require Belco to make a
payment to the counterparty in the event that the NYMEX Reference Price for
any settlement period is less than the swap price for such hedge, and the
counterparty is required to make a payment to Belco in the event that the
NYMEX Reference Price for any settlement period is greater than the swap
price for such hedge.
(3) For any particular collar transaction, the Counterparty is required to make
a payment to Belco if the average NYMEX Reference Price for the reference
period is below the floor price for such transaction,
F-17
60
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
and Belco is required to make payment to the Counterparty if the average
NYMEX Reference Price is above the ceiling price for such transaction.
NOTE 7 -- FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair values
of Belco's financial instruments at December 31, 2000 and 1999. SFAS No. 107
defines the fair value of a financial instrument as the amount at which the
instrument could be exchanged in a current transaction between willing parties.
DECEMBER 31, 2000 DECEMBER 31, 1999
---------------------- ---------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
--------- --------- --------- --------
(IN THOUSANDS)
Cash and cash equivalents.................... $ 2,666 $ 2,666 $ 2,105 $ 2,105
Long-term debt............................... 402,033 390,733 306,744 296,323
Interest rate swaps.......................... -- (6,652) -- (6,549)
Oil and gas commodity -- Hedges.............. (36,172) -- (8,603)
-- Non-hedges....... (126,677) (126,677) (23,066) (23,066)
The carrying values of trade receivables and trade payables included in the
accompanying consolidated balance sheets approximated market value at December
31, 2000 and 1999. The following methods and assumptions were used to estimate
the fair value of the financial instruments summarized in the above table.
Cash and Cash Equivalents
The carrying amounts approximate fair value because of the short maturity
of those instruments.
Marketable Equity Securities
In June 1997, Belco purchased 2,940,000 shares of common stock of Hugoton
Energy Corp. ("Hugoton") at $10.50 per share for a total investment of $30.9
million. At December 31, 1997 a non-cash investment valuation provision in the
amount of $2 million was charged to stockholder's equity to reflect the value of
this investment at that date. In March 1998, Hugoton was acquired by Chesapeake
Energy Corporation ("CHK"). In the merger each share of Hugoton common stock was
converted into 1.3 shares of CHK common stock. During 1998, Belco disposed of
its holdings in CHK and realized a loss of $14.4 million.
On June 12, 1998, Belco, through its wholly-owned Canadian subsidiary,
purchased approximately $10.5 million of 5% Convertible Preferred Stock of Big
Bear Exploration, Ltd. ("Big Bear"), a Canadian oil and gas company, at
approximately $0.85 per share with each share convertible into one common share
of Big Bear. Through a subsequent restructuring agreement, Belco's preferred
stock holdings were converted to common stock and then subject to an 11:1
reverse stock split. As a result of the aforementioned transactions, Belco
became the owner of 1,948,052 common shares or approximately 4.6% ownership in
Big Bear. The substantial decline in the market value of Big Bear securities at
year-end 1999 and 1998 required Belco to record $0.45 and $9.7 million in
impairment provisions, respectively.
In January 2000, shareholders of Big Bear approved its acquisition by AVID
Oil & Gas, Ltd. ("AVID"), a Canadian based energy company providing for Big Bear
shareholders to receive 1 share of AVID common stock for every 15 common shares
of Big Bear. As a result of the transaction described above, Belco currently
owns 129,870 shares of Avid with an approximate market value of $190,000 (US) as
of December 31, 2000.
F-18
61
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Long-Term Debt
The fair value of Belco's revolving credit facility debt of $141.0 million
is assumed to be the same as the carrying value because the interest rate is
variable and is reflective of market rates. The fair value of the 10 1/2% Notes
is based upon the quoted market prices for that issue. The fair value of the
8 7/8% Notes is based upon estimates provided to Belco by independent banking
firms.
Interest Rate Swaps and Oil and Gas Commodity Financial Instruments
The estimated fair values of interest rate swaps and oil and gas commodity
financial instruments have been provided by responsible third parties and
determined by using available market data and applying certain valuation
methodologies. In some cases, quotes of termination values were available.
Judgment is usually required in interpreting market data, and the use of
different market assumptions or estimation methodologies could result in
different estimates of fair value.
NOTE 8 -- COMMITMENTS AND CONTINGENCIES
Future Contingencies Related to the Moxa Arch Programs
From 1992 to 1994, Belco established three Moxa Arch investment programs:
the 1992 Moxa Arch Drilling Program, the 1993 Moxa Arch Drilling Program, and
the Moxa Arch 1992 Offset Drilling Program. The Programs were established to
develop certain drilling prospects acquired as a result of a farmout agreement
with Amoco Production Company and others. Belco offered certain qualified
investors (the Investors) the opportunity to invest in the prospects through
participation in the Programs. Through October 30, 1996, Belco owned
approximately 55.20 percent of the 1992 Moxa Arch Drilling Program, 35.09
percent of the 1993 Moxa Arch Drilling Program, and 58.21 percent of the Moxa
Arch 1992 Offset Drilling Program. On October 31, 1996 Belco purchased from
certain third-party investors interests (the "Acquired Interests") in the Belco
Oil & Gas Corp. 1992, 1993 and 1992 Offset Moxa Arch Drilling Programs. The
effective date of the purchase was October 31, 1996 for financial reporting
purposes. The Acquired Interests represent incremental working interests in
Belco's natural gas wells in the Moxa Arch trend located in Lincoln, Sweetwater
and Uinta Counties, Wyoming. Belco paid aggregate cash consideration of $9.9
million plus an 80% participation in potential natural gas price increases (net
of incremental production costs) associated with production from the wells
through July 31, 1999 (the "Price Participation Right"). In November 1999,
pursuant to the 80% Price Participation Right provision Belco paid out $2.3
million to former third party investors in the Moxa Program. After the purchase,
Belco's interest in these programs was increased to 81.5% of the 1992 Moxa Arch
Drilling Program, 74.0% of the 1993 Moxa Arch Drilling Program, 80.5% of the
Moxa Arch 1992 Offset Drilling Program, and 74% of the Moxa Arch 1993 Offset
Drilling Program. The transaction was accounted for using the purchase method of
accounting.
The remaining third-party investors in the Programs may "put" their
interest to Belco annually through 2003, based upon a valuation by a nationally
recognized independent petroleum engineering firm of the discounted net present
value of the future net revenues from production of proved reserves attributable
to the interests. The put amount is to be calculated based upon certain
specified parameters including prices, discount factors and reserve life. No
investor under the Programs exercised the put right through December 31, 2000.
Belco is not obligated to repurchase in any one calendar year more than 30% of
the interests originally acquired by the program investors (including, for
purposes of this calculation, Belco's interest). Belco's purchase price under
the put right has not been calculated given that no investors have exercised
such right. However, using reserve values presented in Note 15, Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserves (SEC basis using year end prices and a 10% discount rate), the maximum
purchase price if all remaining investors exercised the put option would not be
material to Belco as of December 31, 2000.
F-19
62
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Lease Commitments
At December 31, 2000, Belco had operating leases covering office space.
Minimum rental commitments under operating leases are $108,000, $99,000 and
$65,000 for the years 2001, 2002 and 2003, respectively. For the years ended
December 31, 2000, 1999 and 1998, total rental expense was approximately
$328,000, $316,000 and $512,000, respectively.
Legal Proceedings
Belco is a named defendant in routine litigation incidental to its
business. While the ultimate results of these proceedings cannot be predicted
with certainty, Belco does not believe that the outcome of these matters will
have a material adverse effect on Belco.
Environmental Matters
Belco's operations are subject to various federal, state and local laws and
regulations relating to the protection of the environment, which have become
increasingly stringent. Belco believes its current operations are in material
compliance with current environmental laws and regulations. There are no
material environmental claims pending or, to Belco's knowledge, threatened
against Belco. There can be no assurance, however, that current regulatory
requirements will not change, currently unforeseen environmental incidents will
not occur or past noncompliance with environmental laws will not be discovered
on Belco's properties.
NOTE 9 -- CASH FLOW INFORMATION
Supplemental Disclosure of Cash Flow Information
FOR YEAR ENDED DECEMBER 31,
-----------------------------
2000 1999 1998
------- ------- -------
(IN THOUSANDS)
Cash paid (received) during the year for:
Interest, including amounts capitalized................... $32,105 $26,823 $26,139
Income and other taxes, net of (refunds).................. (6,679) 487 (788)
NOTE 10 -- CUSTOMER INFORMATION
Concentrations of Credit Risk
Belco's revenues are derived from uncollateralized sales to customers in
the oil and gas industry. The concentration of credit risk in a single industry
affects Belco's overall exposure. Belco has not experienced significant credit
losses on such sales.
All of Belco's price risk management transactions are carried out in the
over-the-counter market and not on the New York Mercantile Exchange ("NYMEX").
Belco currently utilizes approximately five financial counterparties that all
have at least an investment grade credit rating. All of these transactions
provide solely for financial settlements relating to closing prices on the
NYMEX.
Major Customers
Oil and gas sales for 2000 include $42.6 million, $27.6 million $23.8
million, $18.9 million, $17.6 million and $16.6 million in revenues received
from six customers. Oil and gas sales for 1999 include $26.6 million, $16.1
million, $14.1 million and $11.9 million in revenues received from four
customers. No other customers individually accounted for 10 percent or more of
revenues.
F-20
63
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 11 -- EMPLOYEE BENEFIT PLANS
Retirement Plan
Belco provides a 401(k) and savings plan for all its full-time employees.
The plan qualifies under Section 401(k) of the Internal Revenue Code as a salary
reduction plan. Under the plan, but subject to certain limitations imposed under
the Internal Revenue Code, eligible employees are permitted to (a) defer receipt
of up to 15 percent of their compensation on a pre-tax basis (salary deferral
contributions) or (b) contribute up to 10 percent of their compensation to the
plan on an after-tax basis. The plan provides for a Company matching
contribution in an amount equal to 50 percent (75% for employees with more than
three years of service) of a participant's salary deferral contributions that
are not in excess of 6 percent of such participant's compensation. The plan also
permits Belco, in its sole discretion, to make a contribution that is allocated
on the last day of each calendar year to certain eligible participants. Company
matching and discretionary contributions are vested over a period of five years
at the rate of 20 percent per year.
During 2000, 1999 and 1998, Belco incurred contribution expenses of
$409,000, $378,000 and $398,000, respectively, in connection with this plan.
NOTE 12 -- CAPITAL STOCK
In December 1998, Belco's Board of Directors (the "Board") authorized the
purchase from time to time, in the open market or in privately negotiated
transactions, shares of its Common Stock and 6 1/2% Convertible Preferred Stock
in an aggregate amount not to exceed $10 million. This authorization was
exhausted in December 1999. Subsequently, the Board authorized an additional $10
million for the purchase of additional Common and Preferred Shares.
F-21
64
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Net Income (Loss) Per Common Share
A reconciliation of the components of basic and diluted net income (loss)
per common share for the three years ended December 31, 2000 is presented in the
table below (in thousands, except per share amounts):
YEAR ENDED DECEMBER 31,
--------------------------------
2000 1999 1998
-------- ------- ---------
Basic net income (loss) per share:
Net loss......................................... $(47,769) $(8,600) $(147,557)
Less: Preferred Stock dividends.................. (6,022) (6,884) (5,406)
-------- ------- ---------
Loss attributable to common shareholders........... $(53,791) $15,484 $(152,963)
======== ======= =========
Weighted average shares of common stock
outstanding...................................... 31,469 31,642 31,529
======== ======= =========
Basic net income (loss) per share.................. (1.71) (0.49) (4.85)
======== ======= =========
Diluted net income (loss) per share:
Weighted average shares of common stock
outstanding................................... 31,469 31,642 31,529
Effect of dilutive securities:
Preferred stock, warrants and stock options(1)... -- -- --
-------- ------- ---------
Average shares of common stock outstanding
including dilutive securities.................... 31,469 31,642 31,529
======== ======= =========
Dilutive net loss per share........................ $ (1.71) $ (0.49) $ (4.85)
======== ======= =========
- ---------------
(1) Amounts are not included in the computation of diluted net loss per share
because to do so would have been antidilutive.
Potential common stock not included in the calculation of diluted earnings
per share because to do so would have been antidilutive amounted to 5,463,000,
7,673,000 and 7,690,000 for 2000, 1999 and 1998, respectively.
Preferred Stock
Belco's 6 1/2% convertible preferred stock has a liquidation preference of
$25 per share and is convertible at the option of the holder into shares of
Belco's common stock at an initial conversion rate of 1.1292 shares of common
stock for each share of preferred stock, equivalent to a conversion price of
$22.14 per share of common stock.
Belco's credit facility and the indentures governing its subordinated debt
restrict the payments of dividends. As a result of reporting substantial
unrealized non-cash mark-to-market losses required by existing accounting rules,
dividends on Belco's preferred stock may be limited or prohibited by the
restrictions contained in Belco's 10 1/2% bond indenture. Payment of the March
2001 dividend on Belco's preferred stock will be permitted. Subsequent dividends
will be contingent upon the sale of equity interests or sufficient net income to
restore dividend payment capacity under the indenture. At the present time,
Belco management does not estimate that first quarter 2001 net income, as
defined in the indenture, will be sufficient to restore this dividend payment
capacity.
Stock Incentive Plans
On March 25, 1996, Belco adopted a Stock Incentive Plan (the Plan) under
which options for shares of Belco's Common Stock may be granted to officers and
employees for up to 2,250,000 shares of Common
F-22
65
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Stock. Under the Plan, options granted may either be incentive stock options or
non-qualified stock options with a maximum term of 10 years and are granted at
no less than the fair market value of the stock at the date of grant. Options
vest 20% per year until fully vested five years from the date of grant.
A separate plan has been established under which options for shares of
Belco's Common Stock may be granted to non-employee directors for up to
approximately 158,000 shares of Common Stock. The plan provides that each
non-employee director be granted stock options for 3,000 shares annually as of
the date of the Annual Meeting. The option price of shares issued is equal to
the fair market value of the stock on the date of grant. All options vest
33 1/3% per year, beginning one year from date of grant, until fully vested and
expire ten years after the date of grant.
A summary of the status of Belco's plans (the Plans) as of December 31,
2000 and 1999 and the changes during the years then ended is presented below:
2000 1999 1998
------------------------ ------------------------ ------------------------
SHS. UNDER WTD. AVG. SHS. UNDER WTD. AVG. SHS. UNDER WTD. AVG.
OPTION EXER. PRICE OPTION EXER. PRICE OPTION EXER. PRICE
---------- ----------- ---------- ----------- ---------- -----------
Outstanding, beginning of
year........................ 1,506,500 $13.68 1,154,000 $16.25 960,500 $20.31
Granted..................... 376,750 7.72 414,500 5.19 433,000 9.82
Exercised................... (2,100) 4.98 -- -- -- --
Forfeited................... (115,000) 14.92 (62,000) 15.00 (239,500) 19.37
---------- ------ ---------- ------ ---------- ------
Outstanding, end of year...... 1,766,150 $12.36 1,506,500 $13.68 1,154,000 $16.25
========== ====== ========== ====== ========== ======
Exercisable, end of year...... 679,592 $16.36 432,300 $18.62 201,500 $20.24
========== ====== ========== ====== ========== ======
Available for grant, end of
year........................ 639,750 901,500 1,254,000
========== ========== ==========
Weighted average fair value of
options granted during the
year........................ $ 7.69 $ 2.78 $ 10.36
========== ========== ==========
The following table summarizes information about stock options outstanding
at December 31, 2000.
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------------- --------------------------------
WEIGHTED AVERAGE NUMBER NUMBER
OUTSTANDING AT REMAINING WEIGHTED EXERCISABLE AT WEIGHTED
DECEMBER 31, CONTRACTUAL AVERAGE DECEMBER 31, AVERAGE
RANGE OF PRICES 2000 LIFE EXERCISE PRICE 2000 EXERCISE PRICE
- --------------- -------------- ----------- -------------- -------------- --------------
$4.88-$6.50............... 347,900 8.18 $ 5.00 71,499 $ 4.99
$7.41-$8.81............... 387,750 9.11 $ 7.69 9,299 $ 7.57
$9.19-$17.63.............. 386,000 7.45 $10.47 154,596 $10.52
$18.88-$22.94............. 582,000 6.19 $19.56 391,799 $19.54
$24.06-$29.00............. 62,500 5.57 $26.85 52,399 $26.85
As permitted by SFAS No. 123, Belco applies APB Opinion No. 25 and related
Interpretations in accounting for its stock option plans. Accordingly, no
compensation expense has been recognized for the Plans. Had compensation costs
been determined based on the fair value at the grant dates consistent with the
method of SFAS No. 123, Belco's pro forma net income (loss) for the three years
ended December 31, 2000
F-23
66
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
would have been reduced to the pro forma amounts indicated below (in thousands,
except for per share amounts):
2000 1999 1998
-------- -------- ---------
Net Income (Loss) Available to Common Stock As
Reported........................................ $(53,791) $(15,484) $(152,963)
Pro Forma....................................... $(54,386) $(15,886) $(154,625)
Basic and Diluted Net Income (Loss) Per Share As
Reported........................................ $ (1.71) $ (0.49) $ (4.85)
Pro Forma....................................... $ (1.73) $ (0.50) $ (4.90)
The fair value of grants was estimated on the date of grant using the
Black-Scholes options pricing model with the following weighted average
assumptions used in 2000, 1999 and 1998, respectively: risk-free interest rate
of 6.67, 5.43 and 5.60 percent, expected volatility of 47.4, 48.3 and 49.0
percent, expected lives of 6.0 years and no dividend yield.
Under the Stock Incentive Plan, participants may be granted stock without
cost (restricted stock). During 2000, 1999 and 1998, Belco granted 10,000,
200,000 and 34,700 shares, respectively, of restricted stock with a weighted
average fair value based on the price of Belco's stock on the date of grant of
$4.94, $5.09 and $15.69 per share, respectively. At December 31, 2000, 182,600
shares remained unvested, net of shares forfeited. The restrictions on
disposition lapse 20% each year and non-vested shares must be forfeited in the
event employment ceases. Unearned compensation was charged for the market value
of the restricted shares at the date the shares were issued. The unearned
compensation is shown as a reduction of stockholders' equity in the accompanying
consolidated balance sheet and is being amortized ratably as the restrictions
lapse. During 2000, 1999 and 1998, $512,000, $512,000 and 344,100, respectively,
was charged to costs and expenses relating to the Plan.
NOTE 13 -- NEW ACCOUNTING PRONOUNCEMENT
In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative
Instruments and Hedging Activities" which was amended by Financial Accounting
Standards No. 138 ("SFAS 138") in June 1999. SFAS 133 establishes accounting and
reporting standards requiring that every derivative instrument (including
certain derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair value. It
also requires that changes in the derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows derivatives gains and losses to offset
related results on the hedged item in the income statement, and requires that a
company must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. We will fully adopt SFAS 133 on
January 1, 2001, the effective date as amended by SFAS 138. SFAS 133 is expected
to increase volatility of stockholder's equity, reporting earnings (losses) and
other comprehensive income. The current preliminary impact of full compliance
with SFAS 133 on financial statements as if the implementation were to have
occurred December 31, 2000, Belco would record an additional $17.5 million in
current assets, $2.0 million in non-current assets, $52.2 million in current
liabilities and $12.7 million in non-current liabilities related to Belco's
existing oil and gas hedges based on the forward price curve in effect at
December 31, 2000. These contracts should also qualify for hedge accounting
treatment under SFAS 133. The total potential net liability of $45.4 million
related to qualifying hedge instruments would be charged to Other Comprehensive
Income and appear in the equity section of the balance sheet. This amount
combined with amounts previously recorded on the balance sheet representing the
non-cash mark-to-market unrealized losses in the net amount of $162.8 million as
of December 31, 2000 represents the full potential exposure of Belco's CPRM
related activities that may or may not be realized as they are dependent on
future commodity prices. After adoption, Belco will be required to recognize any
hedge
F-24
67
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ineffectiveness in the income statement each period. In addition, Belco has
three interest rate swaps that will be effected by SFAS 133. We currently
believe these swaps will not qualify for hedge accounting and as a result, Belco
will be required to record an additional $6.6 million in non-current liabilities
with the offsetting charge to the income statement.
NOTE 14 -- SUPPLEMENTAL QUARTERLY FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS):
QUARTERS
------------------------------------------
FIRST SECOND THIRD FOURTH
------- -------- ------- --------
(UNAUDITED)
2000
Revenues.......................................... $40,159 $ 45,188 $41,470 $ 39,568
Costs and Expenses................................ $54,155 $ 79,444 $51,001 $ 55,276
Net Income (Loss)................................. $(9,097) $(22,267) $(6,195) $(10,210)
Basic and Diluted Net Income (Loss) Per Common
Share........................................... $ (0.34) $ (0.76) $ (0.25) $ (0.36)
1999
Revenues.......................................... $32,220 $ 35,093 $37,456 $ 35,855
Costs and Expenses................................ $37,159 $ 45,272 $52,040 $ 19,384
Net Income (Loss)................................. $(3,212) $ (6,617) $(9,480) $ 10,709
Basic and Diluted Net Income (Loss) Per Common
Share........................................... $ (0.16) $ (0.26) $ (0.35) $ 0.29
The sum of the individual quarterly pro forma basic and diluted net income
(loss) per share amounts may not agree with year-to-date pro forma basic and
diluted net income per share as each period's computation is based on the
weighted average number of common shares outstanding during that period. In
addition, certain potentially dilutive securities were not included in certain
of the quarterly computations of diluted net income per common share because to
do so would have been antidilutive.
NOTE 15 -- SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCING
ACTIVITIES (UNAUDITED):
Capitalized Costs
The following table sets forth the capitalized costs and related
accumulated depreciation, depletion and amortization relating to Belco's oil and
gas production, exploration and development activities as of December 31, 2000
and 1999 (in thousands):
2000 1999
---------- ----------
Proved properties................................... $1,185,686 $1,008,261
Unproved properties................................. 68,979 71,075
---------- ----------
Total capitalized costs................... 1,254,665 1,079,336
Less -- Accumulated depreciation, depletion and
amortization...................................... (674,735) (619,446)
---------- ----------
Net capitalized costs............................... $ 579,930 $ 459,890
========== ==========
F-25
68
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Costs Not Being Amortized
The following table sets forth a summary of unproved oil and gas property
costs not being amortized at December 31, 2000, by the year in which such costs
were incurred (in thousands):
2000 1999 1998 1997 1996 1995 TOTAL
------- ------ ------ ------- ---- ---- -------
Leasehold and seismic............ $10,480 $5,292 $2,957 $49,831 $168 $251 $68,979
Costs Incurred
The following table sets forth the costs incurred in oil and gas
acquisition, exploration and development activities as of December 31, 2000,
1999 and 1998 (in thousands):
2000 1999 1998
-------- ------- --------
Property Acquisitions Costs --
Proved............................................ $ 79,532 $17,608 $ 56,695
Unproved.......................................... 11,991 10,390 14,414
Exploration costs................................... 21,442 10,943 18,597
Development costs................................... 66,310 29,576 37,969
Capitalized interest................................ 7,570 4,881 5,123
Property sales...................................... (11,517) (215) (6,292)
-------- ------- --------
Total costs incurred...................... $175,328 $73,183 $126,506
======== ======= ========
Results of Operations for Oil and Gas Producing Activities
The following table sets forth revenue and direct cost information relating
to Belco's oil and gas exploration and production activities as of December 31,
2000, 1999 and 1998 (in thousands):
2000 1999 1998
--------- -------- ---------
Oil and gas revenues (including commodity price
risk management activities).................... $ 165,434 $139,490 $ 130,088
Costs and expenses --
Lease operating expenses....................... 33,290 29,854 33,615
Production taxes............................... 14,464 9,314 7,232
Impairment of oil and gas properties........... -- -- 229,000
Depreciation, depletion and amortization....... 55,289 52,833 54,863
Non-cash change in fair value of derivatives... 103,610 34,094 (18,912)
--------- -------- ---------
Results of operations from producing activities
before income taxes............................ (41,219) 13,395 (175,710)
Provision (benefit) for income taxes............. (14,427) 4,688 (61,498)
--------- -------- ---------
Results of operations from producing
activities..................................... $ (26,792) $ 8,707 $(114,212)
========= ======== =========
Amortization rate per Mcf equivalent,
recurring...................................... $ 0.86 $ 0.88 $ 0.88
========= ======== =========
Oil and Gas Reserve Information
The following summarizes the policies used by Belco in preparing the
accompanying oil and gas reserves and the standardized measure of discounted
future net cash flows relating to proved oil and gas reserves and the changes in
such standardized measure from period to period.
F-26
69
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Proved reserves are estimated quantities of crude oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.
Proved oil and gas reserve quantities and the related discounted future net
cash flows as of December 31, 2000 are based on internal estimates and audited
by Miller & Lents, independent petroleum engineers. Estimated reserve quantities
for 1999 and 1998 were based upon independent reports prepared by Miller &
Lents. Such estimates have been prepared in accordance with guidelines
established by the Securities and Exchange Commission (SEC).
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of Belco.
The reserve data set forth herein represent only estimates. Reserve engineering
is a subjective process of estimating underground accumulations of oil and gas
that cannot be measured in an exact way, and the accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. As a result, estimates made by different
engineers often vary. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of such estimates,
and such revisions may be material. Accordingly, reserve estimates are often
different from the quantities of oil and gas that are ultimately recovered.
The standardized measure of discounted future net cash flows from
production of proved reserves was developed by first estimating the quantities
of proved reserves and the future periods during which they are expected to be
produced based on year end economic conditions. The estimated future cash flows
from proved reserves were then determined based on year end prices, except in
those instances where fixed contracts provide for a higher or lower amount.
Estimates of future cash flows applicable to oil and gas commodity hedges have
been prepared by Belco and are reflected in future cash flows from proved
reserves with such estimates based on prices in effect as of the date of the
reserve report. Additionally, future cash flows were reduced by estimated
production costs, costs to develop and produce the proved reserves, and when
significant, certain abandonment costs, all based on year end economic
conditions. Future net cash flows have been discounted by 10 percent in
accordance with SEC guidelines.
The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of Belco's oil
and gas reserves. An estimate of fair value would also take into account, among
other things, the recovery of reserves not presently classified as proved,
anticipated future changes in prices and costs and a discount factor more
representative of the time value of money and the risks inherent in reserve
estimates.
Under SEC rules, companies that follow full-cost accounting methods are
required to make quarterly "ceiling test" calculations. Under this test, proved
oil and gas property costs may not exceed the present value of estimated future
net revenues from proved reserves, discounted at 10 percent, as adjusted for
related tax effects and deferred tax reserves. Application of these rules during
periods of relatively low oil and gas prices, even if of short-term duration,
may result in write-downs.
F-27
70
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES
DECEMBER 31,
---------------------------------------
2000 1999 1998
----------- ---------- ----------
(IN THOUSANDS)
Future cash inflows................................... $ 5,139,439 $1,945,175 $1,215,691
Future production costs............................... (977,369) (588,932) (405,171)
Future development costs.............................. (184,305) (110,091) (99,342)
----------- ---------- ----------
Future net inflows before income taxes................ 3,977,765 1,246,152 711,178
Discount at 10% annual rate........................... (1,721,378) (619,610) (350,562)
----------- ---------- ----------
Discounted future net cash flows before income
taxes............................................... 2,256,387 626,542 360,616
Pro forma discounted future income taxes(1)........... (590,383) (161,213) (7,457)
----------- ---------- ----------
Standardized measure of discounted future net cash
flows............................................... $ 1,666,004 $ 465,329 $ 353,159
=========== ========== ==========
- ---------------
(1) The estimated undiscounted future income taxes related to future net inflows
were $1,309.2, $354.5 and $32.6 million for the years 2000, 1999 and 1998,
respectively.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
2000 1999 1998
---------- --------- ---------
(IN THOUSANDS)
BALANCE, BEGINNING OF YEAR.............................. $ 465,329 $ 353,159 $ 426,208
Sales and transfers of oil and gas produced, net of
production costs...................................... (209,916) (100,075) (83,353)
Net change in sales price and production costs.......... 1,430,220 239,549 (142,014)
Extensions and discoveries.............................. 101,596 65,424 29,730
Purchases of minerals in place.......................... 118,390 21,346 66,409
Sale of reserves in place............................... (13,633) (112) (1,401)
Changes in estimated future development costs........... 24,303 33,925 21,382
Revisions in quantities................................. (147,218) (8,841) (39,163)
Accretion of discount................................... 62,654 36,062 51,040
Other, principally revisions in estimates of timing of
production............................................ 263,449 (21,352) (53,923)
Change in income taxes.................................. (429,170) (153,756) 78,244
---------- --------- ---------
BALANCE, END OF YEAR.................................... $1,666,004 $ 465,329 $ 353,159
========== ========= =========
F-28
71
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RESERVE QUANTITY INFORMATION
PROVED RESERVES
OIL GAS
------- -------
(MBBLS) (MMCF)
Balance at December 31, 1996................................ 3,327 284,992
------ -------
Purchases of minerals in place............................ 45,646 44,855
Extensions, discoveries and other additions............... 2,004 39,248
Revisions of previous estimates........................... 1,478 (22,200)
Production................................................ (1,295) (49,710)
------ -------
Balance at December 31, 1997................................ 51,160 297,185
------ -------
Purchases of minerals in place............................ 9,800 25,903
Extensions, discoveries and other additions............... 249 34,279
Revisions of previous estimates........................... (3,775) (33,977)
Sales of minerals in place................................ (203) (649)
Production................................................ (4,177) (37,208)
------ -------
Balance at December 31, 1998................................ 53,054 285,533
------ -------
Purchases of minerals in place............................ 1,066 20,982
Extensions, discoveries and other additions............... 3,342 57,881
Revisions of previous estimates........................... (947) (2,322)
Sales of minerals in place................................ -- (189)
Production................................................ (3,439) (39,737)
------ -------
Balance at December 31, 1999................................ 53,076 322,148
====== =======
Purchases of minerals in place............................ 8,346 57,726
Extensions, discoveries and other additions............... 4,289 76,433
Revisions of previous estimates........................... (1,316) (33,128)
Sales of minerals in place................................ (2,982) (1,009)
Production................................................ (3,922) (40,847)
------ -------
Balance at December 31, 2000................................ 57,491 381,323
====== =======
PROVED DEVELOPED RESERVES
December 31, 1996........................................... 2,070 184,904
December 31, 1997........................................... 41,255 226,071
December 31, 1998........................................... 41,475 213,449
December 31, 1999........................................... 42,352 224,143
December 31, 2000........................................... 40,642 231,380
F-29
72
EXHIBIT INDEX
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
- ------- ----------------------
3.1 -- Articles of Incorporation of Company (Incorporated by
reference from Exhibit 3.1 of the Registration Statement on
Form S-1, Registration No. 333-1034).
3.2 -- Amended and Restated Bylaws of Company dated February 5,
1996 (Incorporated by reference from Exhibit 3.2(ii) of the
Form 10-Q dated March 31, 1996).
4.1 -- Specimen Common Stock Certificate (Incorporated by reference
from Exhibit 4.1 of the Registration Statement on Form S-1,
Registration No. 333-1034).
4.2 -- Indenture dated as of September 23, 1997 among the Company,
as issuer, and The Bank of New York, as trustee
(Incorporated by reference from Exhibit 4.1 of Registration
Statement on Form S-4, Registration No. 333-37125).
4.3 -- Supplemental Indenture dated as of February 25, 1998 between
Coda Energy, Inc., Diamond Energy Operating Company, Electra
Resources, Inc., Belco Operating Corp., Belco Energy L.P.,
Gin Lane Company, Fortune Corp., BOG Wyoming LLC and Belco
Finance Co. (individually, the Subsidiary Guarantors), a
subsidiary of Belco, and The Bank of New York, a New York
banking corporation (as Trustee) amending the Indenture
filed as Exhibit 4.2 above. (Incorporated by reference from
Exhibit 4.3 of the Company's Annual Report on Form 10-K for
the fiscal year ended December 31, 1997).
4.4 -- Exchange and Registration Rights Agreement dated September
23, 1997 by and among Belco and Chase Securities Inc.,
Goldman, Sachs & Co. and Smith Barney Inc. (Incorporated by
reference from Exhibit 4.2 of Registration Statement on Form
S-4, Registration No. 333-37125).
4.5 -- Indenture dated as of March 18, 1996 by and among Coda
Energy, Inc., as issuer, and Taurus Energy Corp., Diamond
Energy Operating Company and Electra Resources, Inc. (as
guarantors), and Chase Bank of Texas, N.A., (formerly known
as Texas Commerce Bank National Association, as trustee
(Incorporated by reference from Exhibit 4.1 of the Coda
Energy, Inc. Registration Statement on Form S-4 filed April
9, 1996, Registration No. 333-2375).
4.6 -- First Supplemental Indenture dated as of April 25, 1996
amending the Indenture filed as Exhibit 4.5 above
(Incorporated by reference from Exhibit 4.12 of the Coda
Energy, Inc. Quarterly Report on Form 10-Q for the quarterly
period ended June 30, 1996, Commission File No. 0-10955).
4.7 -- Second Supplemental Indenture dated as of February 25, 1998
by and among Belco and Chase Bank of Texas, N.A. (formerly
known as Texas Commerce Bank National Association), as
trustee, amending the Indenture filed as Exhibit 4.5 above.
(Incorporated by reference from Exhibit 4.7 of Belco's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1997).
4.8 -- Third Supplemental Indenture dated as of February 25, 1998
by and between Belco, the Belco subsidiaries who are making
a Subsidiary Guarantee (the Guarantors) and Chase Bank of
Texas, N.A., formerly known as Texas Commerce Bank National
Association (the Trustee). (Incorporated by reference from
Exhibit 4.8 of the Company's Annual Report on Form 10-K for
the fiscal year ended December 31, 1997).
4.9 -- Certificate of Designations of 6 1/2% Convertible Preferred
Stock dated March 5, 1997 (Incorporated by reference from
Exhibit 4.1 of current report on Form 8-K dated March 11,
1998).
10.1 -- 1996 Non-Employee Directors' Stock Option Plan (Incorporated
by reference from Exhibit 10.1 of the Registration Statement
on Form S-1, Registration No. 333-1034).
73
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
- ------- ----------------------
10.2 -- 1996 Stock Incentive Plan (Incorporated by reference from
Exhibit 10.2 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.3 -- Exchange and Subscription Agreement and Plan of
Reorganization dated as of January 1, 1996 by and among
Belco, its Predecessors and certain individuals and trusts
(Incorporated by reference to Exhibit 10.3 of the
Registration Statement on Form S-1, Registration No.
333-1034).
10.4 -- Form of Registration Rights Agreement entered into by
parties to Exchange Agreement (Incorporated by reference to
Exhibit 10.4 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.5 -- Supplemental Agreement dated as of January 1, 1996 by and
between Belco, Belco Oil & Gas Corp., a Delaware
corporation, Robert A. Belfer and certain officers of Belco
(Incorporated by reference to Exhibit 10.5 of the
Registration Statement on Form S-1, Registration No.
333-1034).
10.6 -- Form of Indemnification Agreement by and between the Company
and its officers and directors (Incorporated by reference to
Exhibit 10.6 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.7 -- Amended and Restated Well Participation Letter Agreement
dated as of December 31, 1992 between Chesapeake Operating,
Inc. and Belco Oil & Gas Corp., as amended by (i) Letter
Agreement dated April 14, 1983, (ii) Amendment dated
December 31, 1993, and (iii) Third Amendment dated December
30, 1994 (Incorporated by reference to Exhibit 10.7 of the
Registration Statement on Form S-1, Registration No.
333-1034).
10.8 -- Sale Agreement (Independence) dated as of June 10, 1994
between Chesapeake Operating, Inc. and Belco Oil & Gas Corp.
(Incorporated by reference to Exhibit 10.10 of the
Registration Statement on Form S-1, Registration No.
333-1034).
10.9 -- Sale and Area of Mutual Interest Agreement (Greater
Giddings) dated as of December 30, 1994 between Chesapeake
Operating, Inc. and Belco Oil & Gas Corp. (Incorporated by
reference to Exhibit 10.12 of the Registration Statement on
Form S-1, Registration No. 333-1034).
10.10 -- Golden Trend Area of Mutual Interest Agreement dated as of
December 17, 1992 between Chesapeake Operating, Inc. and
Belco Oil & Gas Corp. (Incorporated by reference to Exhibit
10.13 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.11 -- Form of Participation Agreement for Belco Oil & Gas Corp.
1992 Moxa Arch Drilling Program (Incorporated by reference
to Exhibit 10.15 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.12 -- Form of Offset Participation Agreement to the Moxa Arch 1992
Offset Drilling Program (Incorporated by reference to
Exhibit 10.16 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.13 -- Form of Participation Agreement for Belco Oil & Gas Corp.
1993 Moxa Arch Drilling Program (Incorporated by reference
to Exhibit 10.17 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.14 -- Amended and Restated Credit Agreement dated as of June 30,
2000 by and among Belco Oil & Gas Corp. (the "Borrower"),
and The Chase Manhattan Bank, as administrative agent, and
certain financial institutions named therein as Lenders (the
"Lenders") (Incorporated by reference to Exhibit 10.1 of
Belco's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2000, Commission File No. 1-14256).
74
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
- ------- ----------------------
10.15 -- First Amendment to Belco Oil & Gas Corp. 1996 Stock
Incentive Plan (Incorporated by reference from Exhibit 10.2
of Belco's Quarterly Report on Form 10-Q for the quarter
ended June 30, 2000, Commission File No. 1-14256).
10.16 -- Executive Employment Agreement with Grant W. Henderson
(Incorporated by reference from Exhibit 99.7 of the Coda
Energy, Inc. Current Report on Form 8-K dated October 30,
1995, Commission File No. 0-10955).
10.17 -- First Amendment to Belco Oil & Gas Corp. 1996 Nonemployee
Directors' Stock Option Plan. (Incorporated by reference
from Exhibit 10.1 of Belco's Quarterly Report on Form 10-Q
for the quarter ended June 30, 1999, Commission File No.
1-14256).
*21.1 -- Subsidiaries of the Registrant.
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Miller and Lents, Ltd.
- ---------------
* Filed herewith