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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, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 1-12634
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
NEW YORK, NEW YORK 10153
(Address of principal executive office) (Zip Code)
Registrant's telephone number, including area code: (212) 644-2200
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Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, par value $.01 per share New York Stock Exchange
6 1/2% Convertible Preferred Stock, par value $.01 per share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
NONE
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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 20, 1998, was approximately
$131,863,185 (based on a value of $17.125 per share, the closing price of the
Common Stock as quoted by the New York Stock Exchange on such date). 31,584,400
shares of Common Stock, par value $.01 per share, were outstanding on March 20,
1998.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1998 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.
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BELCO OIL & GAS CORP.
FORM 10-K
TABLE OF CONTENTS
PART I
ITEM 1 -- BUSINESS.................................................... 3
Overview.................................................... 3
Recent Developments......................................... 3
Primary Operating Areas..................................... 4
Costs Incurred and Drilling Results......................... 9
Acreage..................................................... 11
Productive Well Summary..................................... 12
Marketing................................................... 12
Production Sales Contracts.................................. 12
Price Risk Management Transactions.......................... 13
Texas Severance Tax Abatement............................... 14
Louisiana Severance Tax Abatements.......................... 14
Section 29 Tax Credit....................................... 15
Regulation.................................................. 15
Operating Hazards and Insurance............................. 20
Title to Properties......................................... 20
Employees................................................... 21
Office and Equipment........................................ 21
Forward-Looking Information and Risk Factors................ 21
Certain Definitions......................................... 28
ITEM 2 -- PROPERTIES.................................................. 30
Oil and Gas Reserves........................................ 30
ITEM 3 -- LEGAL PROCEEDINGS........................................... 30
ITEM 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 30
PART II
ITEM 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS......................................... 31
ITEM 6 -- SELECTED FINANCIAL DATA..................................... 32
ITEM 7 -- MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS................................... 33
Overview.................................................... 33
Results of Operations --
Results of Operations --
Liquidity and Capital Resources............................. 38
Other....................................................... 40
ITEM 8 -- CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.... 41
ITEM 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE.................................... 41
PART III
ITEM 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 41
ITEM 11 -- EXECUTIVE COMPENSATION...................................... 43
ITEM 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.................................................. 43
ITEM 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 44
PART IV
ITEM 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM
8-K......................................................... 44
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BELCO OIL & GAS CORP.
PART I
ITEM 1 -- BUSINESS
OVERVIEW
Belco Oil & Gas Corp. ("Belco" or the "Company") is an independent energy
company engaged in the exploration for and the acquisition, exploitation,
development and production of natural gas and oil primarily in the Rocky
Mountains, the Permian Basin, the Mid-Continent region and the Austin Chalk
Trend. Since its inception in April 1992, the Company has grown its reserve base
largely through a balanced program of exploration and development drilling and
through acquisitions. The Company concentrates its activities primarily in four
core areas in which it has accumulated detailed geologic knowledge and has
developed significant management and technical expertise. Additionally, the
Company structures its participation in natural gas and oil exploration and
development activities to minimize initial costs and risks, while permitting
substantial follow-on investment. In November 1997, the Company completed a
significant acquisition (the "1997 Acquisition") by purchasing Coda Energy, Inc.
("Coda"). See "-- Recent Developments."(1)
The Company has achieved substantial growth in reserves, production,
revenues and EBITDA (Earnings Before Interest, Taxes, Depreciation, Depletion
and Amortization) since 1992. Belco's estimated proved reserves have increased
at a compound annual growth rate of 55%, from 67 Bcfe as of December 31, 1992 to
604 Bcfe as of December 31, 1997. Average daily production has increased from 4
MMcfe per day in 1992 to approximately 217 MMcfe per day in 1997 on a pro forma
basis. Similarly, the growth in the Company's EBITDA has been substantial,
increasing from $2.9 million for the year ended December 31, 1992, to $110.1
million for the year ended December 31, 1997. The Company's pro forma EBITDA for
the year ended December 31, 1997, was $143.0 million. The Company's low cost
structure is evidenced by its general and administrative expenses of $0.07 per
Mcfe and lease operating expenses of $0.22 per Mcfe in 1997.
The Company's 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, the Permian Basin in west Texas, the Mid-Continent region
in Oklahoma and north Texas, and the Austin Chalk Trend in both Texas and
Louisiana. At December 31, 1997, the Company had estimated proved reserves of
604 Bcfe with a pre-tax Present Value of $502 million (exclusive of a $5.5
million increase related to price risk management activities). As of December
31, 1997, Belco held or controlled approximately 2.1 million gross (976,000 net)
undeveloped acres and had an interest in approximately 2,866 gross (1,768 net)
wells of which Belco operated 1,777.
Certain terms relating to the oil and gas industry are defined in
"-- Certain Definitions" below.
RECENT DEVELOPMENTS
In November 1997, Belco completed the acquisition of Coda for consideration
of approximately $324 million plus three-year warrants to purchase 1.667 million
shares of Belco's common stock, par value $0.01 per share ("Common Stock"), at
$27.50 per share. The assets acquired in the 1997 Acquisition are concentrated
in the Permian Basin of west Texas and the Mid-Continent region of Oklahoma and
north Texas. The 1997 Acquisition materially added to the Company's reserve
base, extended the Company's reserve life from approximately 5.3 years to
approximately 8.1 years, and established a balanced reserve mix of 51% oil and
49% natural gas. With the 1997 Acquisition, the Company established its Dallas,
Texas division, which is focused on acquisition and exploitation activities,
including secondary recovery operations.
In February 1998, the Company acquired additional properties in its Permian
Basin core area for $37.5 million (the "Permian Acquisition"). The properties
consist of approximately 10.8 MMBOE of estimated proved reserves and add
approximately 11% to the Company's year end 1997 estimated proved
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1 The pro forma information included in this 10-K gives effect to the 1997
Acquisition.
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reserves at a cost of approximately $3.50 per BOE, bringing total Company
estimated proved reserves to approximately 669 Bcfe.
In February 1998, the Company merged Coda into Belco. As a result of the
merger, Belco assumed the obligations under the 10 1/2% Senior Subordinated
Notes due 2006 (the "Coda Notes") originally issued by Coda. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources."
On March 10, 1998 the Company completed the sale of 4.37 million shares of
its 6 1/2% Convertible Preferred Stock (the "Preferred Stock"). The Preferred
Stock has a liquidation preference of $25 per share and is convertible at the
option of the holder into shares of the Company'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. The
Company received net proceeds from the sale of the Preferred Stock of $105.1
million, which was used to pay down bank indebtedness. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."
PRIMARY OPERATING AREAS
The Company's operations are currently focused in four core operating
areas: (i) the Rocky Mountains, principally in Wyoming in the Green River
(inclusive of the Moxa Arch Trend), Wind River and Big Horn Basins; (ii) the
Permian Basin of west Texas; (iii) the Mid-Continent region in Oklahoma and
north Texas; and (iv) the Austin Chalk Trend, in both Texas and Louisiana. In
addition to these core areas, the Company conducts operations in the onshore
Gulf Coast region and in Michigan's Central Basin.
The following table sets forth information, as of December 31, 1997, with
respect to the Company's estimated net proved reserves by operating area, 94% of
which were estimated by the independent petroleum engineers Miller and Lents,
Ltd. ("Miller & Lents"), as well as the percent of total net present value
attributable to each geographic area. See "Forward Looking Information and Risk
Factors" below and "Properties."
PROVED RESERVES
PERCENT
GAS OF
OIL GAS EQUIVALENT PROVED
(MBBLS) (MMCF)(1) (MMCFE) RESERVES
------- --------- ---------- --------
Rocky Mountains.................................... 717 129,186 133,488 22.1%
Permian Basin...................................... 25,957 18,342 174,084 28.8%
Mid-Continent...................................... 21,741 44,555 175,001 29.0%
Austin Chalk....................................... 2,257 96,069 109,611 18.1%
Other Areas........................................ 488 9,033 11,961 2.0%
------ ------- ------- -----
Total.................................... 51,160 297,185 604,145 100%
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(1) Includes natural gas liquids.
Rocky Mountains
The Company maintains a significant acreage position in the Rocky Mountains
of Wyoming where it conducts an ongoing exploration and development program. In
June 1992, the Company commenced a development drilling program in the Moxa Arch
Trend pursuant to a farmout from Amoco. In 1996, the Company 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, 1997, the Company controlled approximately 825,000 gross
(260,000 net) undeveloped acres in these three basins.
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Moxa Arch Trend. One of the Company's primary operating areas is the Moxa
Arch Trend located in the Greater Green River Basin in southwestern Wyoming,
principally in Lincoln, Sweetwater and Uinta Counties. Approximately 22% of the
Company's estimated proved reserves at December 31, 1997 were located in this
field. The Company participates 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 1997, the Company had participated in 208 gross (62 net) wells in
this field with 142 Frontier wells, 15 Dakota wells and 48 dual completions
(both Frontier and Dakota completed). Average net production for the year ended
December 31, 1997, was approximately 23.2 MMcfe per day. Forty-seven of the
Company's 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."
Beginning in the middle of 1994, the Company substantially reduced the rate
at which it participated in new Moxa Arch Trend wells. This reduction was
primarily due to: (i) Rocky Mountain gas prices which, on both an absolute and
relative basis, experienced a substantial decline in 1994 through late 1996, but
which recovered in late 1996 and early 1997, and (ii) the Bureau of Land
Management ("BLM") which required all operators to perform an environmental
impact study ("EIS") along a portion of the Moxa Arch Trend. In March 1997, the
BLM issued its record of decision; in concluding its review of the EIS, the BLM
has authorized the drilling of approximately 700 natural gas wells in the Moxa
Arch Trend, subject to review of certain air quality components. In May 1997,
the Company re-commenced drilling operations in the Moxa Arch Trend and utilized
2-3 rigs to drill 30 locations in 1997 and plans to have an active drilling
program in 1998. See "-- Regulation -- Environmental Regulation."
Green River, Wind River and Big Horn Basins. Effective November 1, 1996,
the Company 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, the Company has committed to spend a minimum of
$20 million on seismic, leasing and exploratory activities through December 31,
2001 and will initially earn rights to a 50% interest in approximately 300,000
net acres. At December 31, 1997, the Company had participated in 1.95 net wells
with successful tests on 0.91 net wells. These wells were operated by either
Union Pacific Resources ("UPR") or Yates Petroleum Corporation ("Yates").
Effective December 31, 1996, the Company entered into two joint development
agreements with Snyder Oil Company ("SOCO") pursuant to which the Company
acquired or has the right to acquire a 50% interest in 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, SOCO will be the operator. The initial well on
the Company's Wind River acreage, the Tribal #46, was completed in August 1997
and was producing 2.4 MMcf per day on December 31, 1997. The initial well in the
Big Horn Basin, the Otto 16-4, tested at a rate of over 500 Mcfe per day and is
currently waiting on a pipeline connection.
In June 1997, the Company entered into a participation agreement with Tom
Brown, Inc. ("Tom Brown") 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. 2-D seismic covering portions of this acreage
has been purchased and is currently being interpreted. The first wells on this
acreage are planned for 1998.
The Company expects to participate in a series of exploratory wells in
these basins with UPR, SOCO, Tom Brown and Yates serving as operators. These
wells will target multiple formations, the most prevalent of which is the
Frontier formation. If initial results are successful, these projects hold the
potential for multi-well developmental drilling programs for the Company over
the next several years.
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Permian Basin
Approximately 29% of the Company's estimated proved reserves at December
31, 1997 were located in the Company's Permian Basin core area. These reserves
are concentrated in six waterflood units: the Andrews Unit, the Shafter Lake San
Andres Unit, the Boyd Mallet Unit, the Nolley Wolfcamp Unit, the SE Adair San
Andres Unit, and the SW Wellman San Andres Unit.
The Company'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. All 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 CO(2) pipelines, the Company believes
many of its 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 the Company's total estimated proved reserves in
the Permian Basin region lie in Andrews County, Texas. The Company believes that
in 1997 it was the largest independent producer of oil in Andrews County, with
approximately 2,600 gross BOPD, and realized significant advantages as a result
of its large scale operation. The Company owns two large electrical distribution
systems and two saltwater gathering and disposal systems. The Company has
several yards for both the storage of equipment and the staging of new
development projects. Two of the Company's larger production facilities connect
into a water supply system with excess capacity for expanding existing or
initiating new secondary and enhanced recovery projects. The Company believes
that these systems and facilities provide the Company with a competitive
advantage to acquire additional operated properties in Andrews County.
The Company's largest (by value) Permian Basin units are the Andrews Unit,
the Shafter Lake San Andres Unit and the Boyd Mallet Unit.
Andrews Unit. The Andrews Unit produces from the Wolfcamp/Penn formation at
approximately 8,600 feet. The Company has a 98.6% working interest in this 3,230
acre unit. Water injection began in late 1996 with expected response in late
1998. Gross production in December 1997 was approximately 510 BOPD with
injection of over 4,000 barrels of water per day. Plans for 1998 include
drilling several wells and expanding the waterflood operation. The Company
believes this waterflood is an excellent CO(2) or surfactant flooding candidate.
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. The Company has a 62.9% working interest
in this secondary recovery unit. Gross oil production was 910 BOPD in December
1997. The Company has drilled 32 infill 20 acre locations since becoming
operator of the unit in early 1993. Plans for 1998 include expansion of the
waterflood operation by drilling infill producers and converting certain wells
to injection. The Company believes a large part of this field has potential for
10 acre infill wells as well as CO(2) potential.
Boyd Mallet Unit. This Company operated secondary recovery unit is in the
Levelland-Slaughter field in Hockley County, Texas. The Company has an 87.3%
working interest in this unit which produced approximately 200 BOPD (gross) in
December 1997. The unitized interval is the Grayburg/San Andres formation at
5,000 feet. The Company plans to convert eight wells to water injection in 1998
and to drill several infill wells. Based on the performance of direct offset
CO(2) injection and the excellent waterflood history of this property, CO(2)
operations are scheduled to commence in early 1999.
Recent Acquisition. In February 1998, the Company acquired additional
properties in its Permian Basin core area for $37.5 million. The properties
consist of approximately 10.8 MMBOE of estimated proved reserves and add
approximately 11% to the Company's year end 1997 estimated proved reserves at a
cost of approximately $3.50 per BOE.
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Mid-Continent Region
The Company's Mid-Continent operations are currently focused in Oklahoma,
north Texas and Kansas, where approximately 29% of its estimated proved reserves
at December 31, 1997 were located.
Oklahoma. Six waterfloods collectively represent a majority of the
Company's proved reserves in the region. These waterfloods are identified as the
Calumet Unit, Crooked Creek Unit, Cutter South Unit, Oakdale Unit, Rush Springs
Unit and the Witcher Unit. All six waterfloods were initiated and unitized by
the Company.
Oakdale Red Fork Unit. The Company owns an 88.9% working interest in this
3,600 acre unit in northwestern Oklahoma. This Company operated secondary
recovery unit produces from the Redfork formation at 6,400 feet. Gross oil
production was approximately 1,825 BOPD in December 1997. Plans for 1998 include
drilling infill producers and fracture stimulating certain current producers.
Calumet Cottage Grove Unit. This Company 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
December 1997 was approximately 2,275 BOPD. The Company has a 44.1% working
interest in this unit. 1998 plans include drilling several infill and re-entry
wells and converting seven wells to injection.
Witcher Red Fork Unit. The 1,620 acre Company operated Witcher Red Fork
Unit is located in Central Oklahoma. The Company has a 70.7% working interest in
this 6,400 foot secondary recovery unit. December 1997 gross production was
approximately 735 BOPD.
North Texas. The north Texas region stretches from the Chadbourne Ranch
Field in Coke County in the west to the Hosey Driskell Unit in Cass County in
the east. The Electra and Burkburnett Fields represent the properties of the
most significant value in the north Texas region. The Company has drilled 250
wells in these two fields since 1991. In addition to the Company's extensive
inventory of oil and gas opportunities in the north Texas region, the Company
owns three large electrical distribution systems and has extensive field
facilities.
Electra Area. The Electra area produces from shallow Cisco sand lenses from
150 to 2,100 feet. The Company operates 22 leases in this area with 451 active
producers and 165 active injectors. The Company has a 100% working interest in
21 of these leases and a 75% working interest in the other lease. Gross
production for December 1997 was approximately 2,010 BOPD. The Company drilled
two 100% working interest wells in October 1997 that are each producing in
excess of 100 BOPD. 1998 plans include drilling 13 producer and injector wells.
Burkburnett Area. The Burkburnett area produces from the Gunsight Sand
formation from 1,750 feet. The Company operates 12 leases in this area with 390
active producers and 218 active injectors. The Company's working interest is
100% in all leases. Gross production for December 1997 was approximately 770
BOPD. Plans for 1998 include drilling approximately 13 producer and 4 injector
wells.
Austin Chalk Trend
Texas -- Giddings Field. Approximately 17% of the Company's estimated
proved reserves at December 31, 1997 were located in the Giddings Field of east
central Texas, principally in Grimes, Washington and Fayette Counties. The
Giddings Field is one of the most actively drilled oil and gas fields in the
United States. The primary producing zone in the Giddings Field is the Austin
Chalk, 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 believed by the Company to range between
approximately 7,000 and 17,000 feet.
The Company first acquired interests in the Giddings Field in September
1992. During the year ended December 31, 1997, average net production from this
field was approximately 95.1 MMcfe per day. Through December 31, 1997, the
Company had drilled 246 gross (80 net) wells in this field and continues to
control approximately 266,698 gross undeveloped acres in this area. The Company
currently divides the Giddings Field into three prospect areas: (i) Navasota
River, primarily in Grimes County; (ii) Independence, primarily
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in Washington County; and (iii) River Bend, primarily in Fayette County. The
Company expects to drill new wells, including infill wells, and re-entering
older wells to drill additional laterals, in the Giddings Field for the
foreseeable future. Currently, a majority of the Company's interests in this
field are held pursuant to agreements with and operated by Chesapeake Energy
Corporation ("Chesapeake") and, to a lesser extent, UPR and Swift Energy Co. The
Company serves as operator for portions of the River Bend prospect area.
The Company believes that its 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) the Company'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,
the Company's 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 the Company's acreage in the Giddings Field was classified
as a tight sands reservoir by the Texas Railroad Commission. Wells spudded
between June 1989 and September 1996 are exempt from the 7.5% state severance
tax on natural gas through August 2001 available for high cost wells. See
"-- Texas Severance Tax Abatement."
Louisiana. The Louisiana Austin Chalk Trend is an extension of the 200-mile
long Austin Chalk Trend of Texas and represents a continuation of the Company's
exploration and development activities using deep-well horizontal drilling
technology. In December 1994, OXY USA Inc. ("OXY") announced the completion of a
single lateral horizontal Austin Chalk discovery in the Masters Creek area of
central Louisiana, approximately 200 miles east of the Company's activities in
the Giddings Field. Since 1994, more than two and one-half million acres have
been leased in the Louisiana Austin Chalk Trend by industry participants
including the Company, UPR, Chesapeake, OXY and Sonat, Inc. Recent drilling
results for the Company include the Turner 22#1 well, a dual lateral horizontal
well, which was placed on production in late May and as of January 1, 1998 has
produced in excess of 423,000 BOE. In addition, in late November 1997 the
Company successfully completed its first horizontal lateral in the "B" zone of
the Austin Chalk formation, as opposed to the "A" zone which has been the target
of most Louisiana Austin Chalk wells to date. This well produced approximately
100,000 BOE in its first month and highlights additional potential for this
play. At December 31, 1997, the Company owned or had the right to acquire
approximately 304,000 net acres in this trend.
In order to further develop its large acreage position, in December 1996
the Company entered into two AMIs with UPR covering approximately 93,000
combined net acres in Avoyelles, Evangeline, Rapides and St. Landry Parishes,
and one AMI with OXY covering approximately 24,000 combined net acres in St.
Landry Parish. These AMIs, which provide for a sharing of costs and benefits as
well as operations in each such area, allow the Company to expedite the
exploration and development of its acreage position and gain the benefits of
shared expertise with two leading industry partners and experienced horizontal
players. In May 1997, the Company created an additional AMI with OXY by selling
additional fractional interests in approximately 29,500 net acres to OXY for
$12.1 million. The Company also retained a small royalty interest on such
acreage.
Other Operating Areas
Gulf Coast. In March 1996, the Company entered into an exploration
agreement with Edge Petroleum Corporation ("Edge") pursuant to which the parties
expect to jointly conduct a series of 3-D seismic programs covering potentially
up to 750 square miles onshore in the Gulf Coast region of Texas. Under the
program, Edge and the Company initiated the first 50+ square mile 3-D seismic
shoots targeting the shallower Frio formation and potentially larger reserves in
the deeper Yegua and Wilcox formations. Edge is the operator of any shallow zone
wells drilled under the program and under certain circumstances the Company will
operate prospects targeting deeper zones. At December 31, 1997, Belco and Edge
had acquired seismic options on approximately 15,017 gross acres. As of December
31, 1997, the Company had a 50% working
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interest in seven productive Frio wells (out of ten wells drilled), six
productive Yegua wells (out of six wells drilled) and one inconclusive Wilcox
well based on the evaluations of the initial 3-D seismic shoot. The Company
plans to participate in additional Frio wells and Yegua and Wilcox prospects
throughout 1998.
Michigan -- Central Basin. In June 1996, the Company entered into an
exploration program with two private oil and gas companies pursuant to which the
Company acquired a 35% interest in approximately 220,000 net acres in the
Central Basin of Michigan with the Company serving as operator. At December 31,
1997, the Company held or controlled interests, including the foregoing, in a
total of approximately 282,000 gross and 73,000 net acres in this basin. The
objectives of this play have been thin gas-bearing sands at depths ranging from
approximately 8,000 to 10,000 feet to be tested by vertical wells as well as
shallower oil zones penetrated by horizontal wells. At year end 1997, the
Company's drilling program was in the process of testing both the vertical and
horizontal prospects covering different portions of this large acreage position
in order to complete the initial evaluation of this play.
COSTS INCURRED AND DRILLING RESULTS
Drilling Activity
The following table sets forth the wells participated in by the Company
during the periods indicated. In the table, "gross" refers to the total wells in
which the Company has a working interest, and "net" refers to gross wells
multiplied by the Company's working interest therein.
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1997(1) 1996 1995
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
Development:
Productive.................................... 54.0 23.1 64.0(2) 23.0 84.0 24.0
Non-productive................................ 4.0 2.2 2.0 0.8 6.0 1.2
---- ---- ---- ---- ---- ----
Total................................. 58.0 25.3 66.0 23.8 90.0 25.2
==== ==== ==== ==== ==== ====
Exploratory:
Productive.................................... 20.0 13.7 10.0 7.9 5.0 1.9
Non-productive................................ 18.0 6.4 3.0 2.4 2.0 0.3
---- ---- ---- ---- ---- ----
Total................................. 38.0 20.1 13.0 10.3 7.0 2.2
==== ==== ==== ==== ==== ====
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(1) Does not include 41 gross (17.0 net) wells in progress at December 31, 1997.
(2) Includes three gross oil and gas wells with multiple completions. Wells with
multiple completions are counted only once for purposes of the above table.
The foregoing drilling activity table does not include drilling activity
for Coda. Coda concentrates on exploiting proved producing properties, including
those with development potential, through secondary recovery operations, the
drilling of development wells or infill wells, workovers, recompletions in other
productive zones and other exploitation techniques. Coda has conducted or
intends to conduct significant secondary recovery/infill drilling programs on
many of its properties.
Secondary recovery projects have represented Coda's primary development
focus over the past four years. Generally, "secondary recovery" refers to
methods of oil extraction in which fluid or gas (usually water, natural gas or
CO(2)) is injected into a formation through input (injector) wells, and oil is
removed from surrounding wells. "Waterflooding" is one proven method of
secondary recovery in which water is injected into an oil reservoir for the
purpose of forcing the oil out of the reservoir rock and into the bore of a
producing well. Waterflood projects are engineered to suit the type of
reservoir, depth and condition of the field. Coda has considerable experience
with and actively employs waterflood techniques in many of its fields in order
to stimulate production.
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The following table sets forth the wells participated in by Coda during the
periods indicated. In the table, "gross" refers to the total wells in which Coda
has a working interest, and "net" refers to gross wells multiplied by Coda's
working interest therein.
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1997(1) 1996 1995
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
Development:
Productive................................... 31.0 21.5 21.0 17.0 109.0 98.9
Non-productive............................... 0.0 0.0 0.0 0.0 0.0 0.0
---- ---- ---- ---- ----- ----
Total................................ 31.0 21.5 21.0 17.0 109.0 98.9
==== ==== ==== ==== ===== ====
Exploratory:
Productive................................... 0.0 0.0 0.0 0.0 2.0 0.8
Non-productive............................... 0.0 0.0 0.0 0.0 0.0 0.0
---- ---- ---- ---- ----- ----
Total................................ 0.0 0.0 0.0 0.0 2.0 0.8
==== ==== ==== ==== ===== ====
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 the Company's sale of oil and natural gas for the periods
indicated. The table includes results for Coda since November 26, 1997.
YEAR ENDED DECEMBER 31,
-------------------------------
1997 1996 1995
-------- -------- -------
Net Production Data:
Oil (MBbl)................................................ 1,295 794 961
Gas (MMcf)................................................ 49,710 51,289 37,047
Gas equivalent (MMcfe).................................... 57,479 56,053 42,813
Oil and Gas Sales ($ in 000's)(1)........................... $129,994 $119,710 $68,767
Average Sales Price (Unhedged):
Oil ($ per Bbl)........................................... $ 19.28 $ 21.30 $ 17.35
Gas ($ per Mcf)........................................... $ 2.11 $ 2.00 $ 1.42
Costs ($ per Mcfe):
Oil and gas operating expenses............................ $ 0.22 $ 0.14 $ 0.14
General and administrative................................ $ 0.07 $ 0.06 $ 0.06
Depreciation, depletion and amortization of oil and gas
properties............................................. $ 0.81 $ 0.73 $ 0.64
- ---------------
(1) Oil and gas sales exclude results related to commodity price risk management
activities reported separately.
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Development, Exploration and Acquisition Expenditures
The following table sets forth certain information regarding the costs
incurred by the Company in its development, exploration and acquisition
activities during the periods indicated. The table includes information for Coda
since November 26, 1997.
YEAR ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
--------- -------- -------
Property acquisitions costs --
Proved(1)................................................ $ 443,930 $ 9,871 $ --
Unproved................................................. 24,226 64,530 13,643
Exploration costs.......................................... 46,939 17,444 2,382
Development costs.......................................... 59,571 50,433 54,451
Capitalized interest....................................... 3,742 434 911
Property Sales............................................. (13,949) -- --
--------- -------- -------
Total costs incurred..................................... $ 564,459 $142,712 $71,387
========= ======== =======
- ---------------
(1) Acquisition of proved properties includes $437.4 million relative to the
acquisition of Coda of which $50 million was allocated to unproved property
costs.
ACREAGE
The following table sets forth, as of December 31, 1997, the gross and net
acres that the Company 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 producing units. "Gross" acres refers to the total number of
acres in which the Company owns a working interest. "Net" acres refers to gross
acres multiplied by the Company's fractional working interest.
DEVELOPED UNDEVELOPED(1)
----------------- -------------------
GROSS NET GROSS NET
------- ------- --------- -------
Rocky Mountains:
Green River Basin.......................... 1,920 373 425,995 108,877
Moxa Arch Trend............................ 50,221 27,307 24,850 15,858
Wind River Basin........................... 320 120 182,689 69,525
Big Horn Basin............................. 160 80 218,874 80,950
Denver-Julesburg Basin..................... 1,560 1,170 285,718 127,692
Permian Basin................................ 79,468 36,289 20 20
Mid-Continent Region:
Oklahoma................................... 115,050 37,987 2,500 750
North Texas................................ 24,658 19,632 -- --
Kansas..................................... 17,879 15,536 -- --
Austin Chalk Trend:
Texas-Giddings Field....................... 145,753 49,801 266,698 127,024
Louisiana.................................. 7,576 1,773 356,132 304,303
Other Operating Areas:
Michigan-Central Basin..................... 3,280 2,000 296,922 90,236
Gulf Coast................................. 4,051 2,026 69,380 50,283
------- ------- --------- -------
Totals............................. 451,896 194,094 2,129,778 975,518
======= ======= ========= =======
- ---------------
(1) Leases covering approximately half of the undeveloped acreage will expire
within the next four years. However, the Company expects to evaluate this
acreage prior to its expiration. The Company's 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.
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PRODUCTIVE WELL SUMMARY
The following table sets forth the Company's ownership in productive wells
at December 31, 1997. Gross oil and gas wells include three with 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......................................................... 667 275
Oil......................................................... 2,123 1,470
----- -----
Total............................................. 2,790 1,745
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 of oil and gas production and sales.
The Company has not experienced any difficulties in marketing its 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.
Although the Company seeks to moderate the impact of price volatility
through its commodity price risk management activities, the Company remains
subject to price fluctuations for natural gas sold in the spot market due
primarily to seasonality of demand and other factors beyond the Company's
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, the Company 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 the Company under the Amoco Gas Contract for the gas is the
Northwest Pipeline Rocky Mountain Index, plus $0.03 per MMBtu, less fuel charges
and gathering fees and adjusted for Btu content. The Amoco Gas Contract expires
on January 1, 1999. The Amoco Gas Contract can be extended by the Company for an
additional three year term.
All of the Company's current Moxa Arch Wyoming oil and condensate
production is sold at market related prices pursuant to an option held by Amoco.
The Company's Moxa Arch wells are subject to various gathering agreements
with third parties including, as to wells drilled under the Amoco Farmout
Agreement in the Wilson Ranch, Seven Mile Gulch and Bruff areas, a Gas Gathering
and Processing Agreement dated March 20, 1992 with Northwest Pipeline. Gathering
fees under this agreement are currently $0.065 per MMBtu, subject to indexed
escalation, and fuel charges of 0.5%. Gathering fees and fuel charges in the Cow
Hollow/ Shute Creek areas are similar to those under the Amoco Gas Contract.
In Texas, Louisiana and Oklahoma, the Company sells its gas to purchasers
under percentage of proceeds or index-based contracts. Under the percentage of
proceeds contract, the Company receives 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 the Company's gas. The Company receives
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 the Company's
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 the Company from the sale of natural gas liquids is included
in natural gas sales. Under indexed-based contracts, the Company
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receives for its gas at the wellhead a price per MMBtu tied to indexes published
in Inside FERC or Gas Daily, subject in most cases to a discount to the relevant
index in lieu of a gathering fee.
All of the Company'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 oil and gas
sales in 1997 were made to Aquila Southwest Pipeline (31%), GPM Gas Corporation
(21%) and Amoco Gas Trading Corp. (20%).
Management believes that the loss of any one of the above customers would
not have a material adverse effect on the Company's results of operations or its
financial position.
PRICE RISK MANAGEMENT TRANSACTIONS
Commodity Price Risk Management
With the objective of achieving more predictable revenues and cash flows
and reducing the exposure to fluctuations in gas and oil prices, the Company has
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. The
Company had entered into price risk management transactions with respect to a
substantial portion of its production for 1996 and 1997 and with respect to a
substantial portion of its estimated production for 1998 through 2000 and with
respect to lesser portions thereafter. The Company continues to evaluate whether
to enter into additional such transactions for 1998 and future years. In
addition, the Company may determine from time to time to terminate its then
existing hedging and other risk management positions.
All of the Company's price risk management transactions are carried out in
the over-the-counter market and not on the New York Mercantile Exchange
("NYMEX"), with financial counterparties having 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, 1997.
Swaps. Since all of the Company's natural gas and oil is sold on "floating"
or market related prices, the Company has 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 the Company in the event that the NYMEX Reference Price for any
settlement period is less than the swap price for such hedge, and the Company 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.
Reverse Swaps. When the Company 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 the role of the Company 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 the Company if the average NYMEX Reference Price
for the reference period is below the floor price for such transaction, and the
Company is 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 the Company believes that it receives 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 the
Company sold a $23.00 call on oil for $0.40 a barrel in a given month and prices
averaged $22.00 a barrel for such month, the Company would receive a net
realization per barrel of $22.40 ($22.00 plus the $0.40 premium). However, if
for that month the price of oil averaged $25.00 per barrel, the Company would
receive a net realization of $23.40 (the call price, $23.00, plus $0.40). The
Company regards this as a
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prudent transaction under certain circumstances provided that the Company always
has more physical production for the periods involved than its related aggregate
risk management transactions. 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 are required to be marked to market as
to the value of these transactions on the last day of the accounting period to
which such statement relates.
Basis Swaps. Since a substantial portion of the Company's natural gas is
sold under spot contracts with reference to Houston Ship Channel prices and the
Company's price risk management transactions are based on the NYMEX Reference
Price relating to gas delivered to Henry Hub, Louisiana, the Company has entered
into basis swaps that require the counterparty to make a payment to the Company
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
MMBtu for gas delivered at the Houston Ship Channel for such reference period by
more than a stated differential, and requires the Company to make a payment to
the counterparty in the event that the NYMEX Reference Price for Henry Hub
exceeds the price for Houston Ship Channel gas by less than the stated
differential (or in the event that the Houston Ship Channel price exceeds the
Henry Hub price). The Company also sells Wyoming gas at prices based on the
Northwest Pipeline Rocky Mountain Index (an index of prices for gas delivered at
various delivery points on the Northwest Pipeline in the Northern Rocky Mountain
area) and has entered into basis swaps that requires the counterparty to make a
payment to the Company in the event that the average NYMEX Reference Price per
MMBtu for gas delivered at Henry Hub, Louisiana for a reference period exceeds
the stated differential or to have the Company pay to the counterparty if it is
less than the stated differential (or if the Northwest Pipeline Rocky Mountain
index price is greater than the NYMEX reference price).
Certain of the Company's price risk management transactions were previously
covered by guarantees of, and certain other collateral from Robert A. Belfer,
Chairman of the Board and Chief Executive Officer. Subsequent to the Company's
initial public offering, all such guarantees have been terminated and all such
collateral has been returned.
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 June 16, 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 the
Company's 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, 2002 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.
LOUISIANA SEVERANCE TAX ABATEMENTS
A five-year exemption from severance tax applies to production from oil and
gas wells that are returned to service after having been inactive for two or
more years or having 30 days or less of production during the past two years. An
application must be made to the Louisiana Department of Natural Resources before
commencement of production during the period beginning July 31, 1994, and ending
June 30, 1998. Upon certification, the five-year exemption period begins from
the date of the application.
All severance tax is suspended for 24 months or until payout of the well
cost is achieved, whichever occurs first, on any horizontally drilled well or
recompletion well from which production commences after
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July 31, 1994. The term "horizontal drilling" means high angle drilling of bore
holes with 50 to 3,000 plus feet of lateral penetration through productive
reservoirs, and "horizontal recompletion" means horizontal drilling in an
existing well bore.
Production of natural gas, gas condensate and oil from any well drilled to
a true vertical depth of more than 15,000 feet and where production starts after
July 31, 1994, is exempt from severance tax for 24 months or until payout of the
well cost, whichever occurs first. The exemption applies to production from any
depth in the wellbore.
Currently, the Louisiana severance tax rate on oil is 12.5% of gross value
and the severance tax on gas is 10.1 cents per Mcf. Only one of the severance
tax exemptions discussed above may be taken on a particular well. The Company
anticipates that a substantial portion of its current and future Louisiana wells
will qualify for one of the two exemptions discussed above.
SECTION 29 TAX CREDIT
The natural gas production from wells drilled on certain of the Company'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 credit against
regular federal income tax liability with respect to sales of the Company'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 $1.03 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 $45 per Bbl in current dollars. The
Company generated approximately $0.9 million of Section 29 Tax Credits in 1996.
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 the Company's Section 29 Tax Credits will reduce its federal income tax
liability in any particular year.
REGULATION
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. In October
1992, comprehensive national energy legislation was enacted which focuses on
electric power, renewable energy sources and conservation. This legislation,
among other things, guarantees equal treatment of domestic and imported natural
gas supplies, mandates expanded use of natural gas and other alternative fuel
vehicles, funds natural gas research and development, permits continued offshore
drilling and use of natural gas for electric generation and adopts various
conservation measures designed to reduce consumption of imported oil. The
legislation may be viewed as generally intended to encourage the development and
use of natural gas. 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. The Company'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. The Company'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
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may be drilled in 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 the Company can produce from its
wells and may limit the number of wells or the locations at which the Company
can drill. The regulatory burden on the oil and gas industry increases the
Company's costs of doing business and, consequently, affects its profitability.
Inasmuch as such laws and regulations are frequently expanded, amended or
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such regulations.
The Company 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 and orders pursuant to the Outer Continental Shelf Lands Act
("OCSLA") (which are subject to change by the MMS). For offshore operations,
lessees must obtain MMS approval for exploration plans and development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies (such as the Coast Guard, 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 has
promulgated regulations requiring offshore production facilities located on the
Outer Continental Shelf (the "OCS") to meet stringent engineering and
construction specifications. The MMS proposed additional safety-related
regulations concerning the design and operating procedures for OCS production
platforms and pipelines. These proposed regulations were withdrawn pending
further discussions among interested federal agencies. The MMS also has
regulations restricting the flaring or venting of natural gas, liquid
hydrocarbons and oil without prior authorization. Similarly, the MMS has
promulgated other regulations governing the plugging and abandonment of wells
located offshore and the removal of all production facilities. To cover the
various obligations of lessees on the OCS, 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 the Company's financial
condition and operations.
The MMS issued a notice of proposed rulemaking in which it proposed to
amend its regulations governing the calculation of royalties and the valuation
of crude oil produced from federal leases. The proposed rule would modify the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on posted prices and assign a value to crude
oil that better reflects market value, establish a new MMS form for collecting
value differential data and amend the valuation procedure for the sale of
federal royalty oil. The Company cannot predict at this stage of the rulemaking
proceeding how it might be affected by this amendment to the MMS regulations.
In April 1997, after two years of study, the MMS withdrew proposed changes
to the way it values natural gas for royalty payments. These proposed changes
would have established an alternative market-based method to calculate royalties
on certain natural gas sold to affiliates or pursuant to non-arm's length sales
contracts.
Recently, the MMS has issued a final rule to clarify the types of costs
that are deductible transportation costs for purposes of royalty valuation of
production sold off the lease. In particular, under the rule, the MMS will not
allow deduction of costs associated with marketer fees, cash out and other
pipeline imbalance penalties, or long-term storage fees. The Company cannot
predict what, if any, effect the new rule will have on its operations.
Natural Gas and Oil Marketing and Transportation. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy
Act of 1978 (the "NGPA") and the regulations promulgated thereunder by the
Federal Energy
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Regulatory Commission (the "FERC"). In the past, the federal government has
regulated the prices at which oil and gas could be sold. Deregulation of
wellhead sales in the natural gas industry began with the enactment of the NGPA.
In 1989, the Natural Gas Wellhead Decontrol Act was enacted. This act amended
the NGPA to remove both price and non-price controls from natural gas sold in
"first sales" as of January 1, 1993. While sales by producers of natural gas and
all sales of crude oil, condensate and natural gas liquids can currently be made
at uncontrolled market prices, Congress could reenact price controls in the
future.
Several major regulatory changes have been implemented by the FERC from
1985 to the present that affect the economics of natural gas production,
transportation and sales. In addition, the FERC continues to promulgate
revisions to various aspects of the rules and regulations affecting those
segments of the natural gas industry, most notably interstate natural gas
transmission companies, which remain subject to the FERC's jurisdiction. These
initiatives may also affect the intrastate transportation of gas under certain
circumstances. The stated purposes of many of these regulatory changes is to
promote competition among the various sectors of the gas industry. The ultimate
impact of these complex and overlapping rules and regulations, many of which are
repeatedly subjected to judicial challenge and interpretation, cannot be
predicted.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and
636-C (collectively, "Order No. 636"), which, among other things, require
interstate pipelines to "restructure" to provide transportation separate, or
"unbundled," from the pipelines' sales of gas. Also, Order No. 636 requires
pipelines to provide open-access transportation on a basis that is equal for all
gas supplies. Order No. 636 has been implemented as a result of FERC orders in
individual pipeline service restructuring proceedings. In many instances, the
result of the Order No. 636 and related initiatives have been to substantially
reduce or bring to an end the interstate pipelines' traditional roles as
wholesalers of natural gas in favor of providing only storage and transportation
services. The FERC has issued final orders in virtually all pipeline
restructuring proceedings, and has completed a series of one year reviews to
determine whether refinements are required regarding individual pipeline
implementations of Order No. 636.
Although Order No. 636 does not directly regulate natural gas producers
such as the Company, the FERC has stated that Order No. 636 is intended to
foster increased competition within all phases of the natural gas industry. It
is unclear what impact, if any, increased competition within the natural gas
industry under Order No. 636 will have on the Company and its natural gas
marketing efforts. The United States Court of Appeals for the District of
Columbia Circuit (the "Court") recently issued its decision in the appeals of
Order No. 636. The Court largely upheld the basic tenets of Order No. 636,
including the requirements that interstate pipelines "unbundle" their sales of
gas from transportation and that pipelines provide open-access transportation on
a basis that is equal for all gas suppliers. The Court remanded several
relatively narrow issues for further explanation by the FERC. In doing so, the
Court made it clear that the FERC's existing rules on the remanded issues would
remain in effect pending further consideration. The Company believes that the
issues remanded for further action do not appear to materially affect it. The
United States Supreme Court has decided not to review the Court's decision
regarding Order No. 636. In February 1997, the FERC issued Order No. 636-C, its
order on remand from the Court. Order 636-C is currently pending on rehearing
before the FERC. Although Order No. 636 could provide the Company with
additional market access and more fairly applied transportation service rates,
terms and conditions, it could also subject the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violations of those
tolerances. The Company does not believe, however, that it will be affected by
any action taken with respect to Order No. 636 materially differently than other
natural gas producers and marketers with which it competes.
The FERC has issued a statement of policy and a request for comments
concerning alternatives to its traditional cost-of-service rate making
methodology. This policy statement articulates the criteria that the FERC will
use to evaluate proposals to charge market-based rates for the transportation of
natural gas. The policy statement also provides that the FERC will consider
proposals for negotiated rates for individual shippers of natural gas, so long
as a cost-of-service-based rate is available as a recourse rate. A number of
pipelines have obtained FERC authorization to charge negotiated rates. The FERC
also has requested comments on whether it should allow gas pipelines the
flexibility to negotiate the terms and conditions of transportation service with
prospective shippers. The Company cannot predict what further action the FERC
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will take on these matters, however, the Company does not believe that it will
be affected by any action taken materially differently than other natural gas
producers and marketers with which it competes.
The FERC has announced its intention to reexamine certain of its
transportation-related policies, including the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in the secondary market, and the price shippers can charge for
released capacity. In February 1997, the FERC announced a broad inquiry into
issues facing the natural gas industry, to assist the FERC in establishing
regulatory goals and priorities. In November 1997, the FERC issued a proposed
rulemaking to further standardize pipeline transportation tariffs that, if
implemented as proposed, could adversely affect the reliability of scheduled
interruptible transportation service. In December 1997, the FERC requested
comments on the financial outlook of the natural gas pipeline industry,
including among other matters, whether the FERC's current rate making policies
are suitable in the current industry environment. While any resulting FERC
action would affect the Company only indirectly, the FERC's current rules and
policies may have the effect of enhancing competition in natural gas markets by,
among other things, encouraging non-producer natural gas marketers to engage in
certain purchase and sale transactions. The Company cannot predict what action
the FERC will take on these matters, nor can it accurately predict whether the
FERC's actions will achieve the goal of increasing competition in markets in
which the Company's natural gas is sold. However, the Company does not believe
that it will be affected by any action taken materially differently than other
natural gas producers and marketers with which it competes.
The FERC has issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. While the FERC's
policy statement on new construction cost recovery affects the Company only
indirectly, in its present form, the new policy should enhance competition in
natural gas markets and facilitate construction of gas supply laterals. The FERC
has denied requests for rehearing of this policy statement. The FERC has issued
numerous orders approving the spin-down or spin-off by interstate pipelines of
their gathering facilities. A "spin-off" is a FERC-approved sale of gathering
facilities to a non-affiliate. A "spin-down" is a transfer of gathering
facilities to an affiliate. These approvals were given despite the strong
protests of a number of producers concerned that any diminution in FERC's
oversight of interstate pipeline-related gathering services might result in a
denial of open access or otherwise enhance the pipeline's monopoly power. The
FERC's lead decision in this area has been largely affirmed by an appellate
court. While the FERC has stated that it will retain limited jurisdiction over
such gathering facilities and will hear complaints concerning any denial of
access, it is unclear what effect the FERC's gathering policy will have on
producers such as the Company and the Company cannot predict what further action
the FERC will take on these matters. One possible result of the FERC's actions
may be increased state regulatory oversight of gathering.
Commencing in October 1993, the FERC issued a series of rules (Order Nos.
561 and 561-A) establishing an indexing system under which oil pipelines will be
able to change their transportation rates, subject to prescribed ceiling levels.
The indexing system, which allows or may require pipelines to make rate changes
to track changes in the Producer Price Index for Finished Goods, minus one
percent, became effective January 1, 1995. The FERC's decision in this matter
was recently affirmed by the Court. The Company is not able at this time to
predict the effects of Order Nos. 561 and 561-A, if any, on the transportation
costs associated with oil production from the Company's oil producing
operations.
Additional proposals and proceedings that might affect the oil and gas
industry are pending before the FERC and the courts. The Company cannot predict
when or whether any such proposals may become effective. In the past, the
natural gas industry has been heavily regulated. There is no assurance that the
regulatory approach currently pursued by the FERC will continue indefinitely.
Notwithstanding the foregoing, the Company 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 the Company.
Environmental Regulation. Activities of the Company with respect to the
exploration, development and production of oil and natural gas are subject to
stringent environmental regulation by state and federal authorities including
the EPA. Such regulation has increased the cost of planning, designing,
drilling,
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operating and in some instances, abandoning wells. In most instances, the
regulatory requirements relate to the handling and disposal of drilling and
production waste products and waste created by water and air pollution control
procedures. Although the Company believes that compliance with existing
environmental regulations will not have a material adverse effect on operations
or earnings, the risks of substantial costs and liabilities are inherent in oil
and gas operations, and there can be no assurance that significant costs and
liabilities, including civil and criminal penalties, will not be incurred.
Moreover, it is possible that other developments, such as stricter environmental
laws and regulations, and claims for damages to property or persons resulting
from the Company's operations could result in substantial costs and liabilities
to the Company.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
with respect to 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 released at such site. Persons who are or were
responsible for releases of hazardous substances under CERCLA may be subject to
joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment and for damages to
natural resources, and it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment.
The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes. Furthermore,
it is possible that certain wastes generated by the Company's oil and natural
gas operations that are currently exempt from treatment as "hazardous wastes"
may in the future be designated as "hazardous wastes" under RCRA or other
applicable statutes and therefore be subject to more rigorous and costly
operating and disposal requirements.
The Company currently owns or leases, and has in the past owned or leased,
numerous properties that for many years have been used for the exploration and
production of oil and gas. Although the Company has 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 the Company or on or under other locations where such wastes
have been taken for disposal. In addition, many of these properties have been
owned or operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under the Company's control. These
properties and the wastes disposed thereon may be subject to CERCLA, RCRA and
analogous state laws. Under such laws, the Company could be required to remove
or remediate previously disposed wastes (including wastes 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 operations to prevent future contamination.
The Oil Pollution Act of 1990 (the "OPA") amends certain provisions of the
Federal Water Pollution Control Act of 1972, commonly referred to as the Clean
Water Act ("CWA") and other statutes as they pertain to the prevention of and
response to oil spills into navigable waters. The OPA subjects owners and
operators of facilities to strict joint and several liability for all
containment and cleanup costs and certain other public and private damages
arising from a spill, including, but not limited to, the costs of responding to
a release of oil to surface waters. OPA establishes a liability limit for
onshore facilities of $350 million and for offshore facilities, all removal
costs plus $75 million, however, a party cannot take advantage of liability
limits 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,
liability limits likewise do not apply. The CWA provides penalties for any
discharges of petroleum product in reportable quantities and imposes substantial
liability for the costs of removing a spill. State laws for the control of water
pollution also provide varying civil and criminal penalties and liabilities in
the case of releases of petroleum or its derivatives into surface waters or into
the ground. Federal regulations under the CWA and OPA require certain owners or
operators of facilities that store or otherwise handle oil, such as the Company,
to prepare and implement spill prevention, control and countermeasure plans and
facility response plans relating to the
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possible discharge of oil into surface waters. In addition, the CWA and
analogous state laws require permits to be obtained to authorize discharges into
surface waters or to construct facilities in wetland areas. With respect to
certain of its operations, the Company is required to maintain such permits or
meet general permit requirements. In 1992, the EPA adopted regulations
concerning discharges of storm water runoff. This program requires covered
facilities to obtain individual permits, participate in a group permit or seek
coverage under an EPA general permit. The Company believes that it is in
substantial compliance with the requirements of the CWA and OPA and that any
non-compliance would not have a material adverse effect on the Company.
In April of 1994, the BLM directed that an EIS be performed along a portion
of the Moxa Arch area of Wyoming. The final EIS was completed in June of 1996.
In March of 1997, the BLM issued its record of decision relating to this EIS.
During the pendency of the EIS and record of decision, regulatory approval to
drill wells in the affected area was difficult to obtain. The BLM's record of
decision authorized the drilling of approximately 700 natural gas wells in the
Moxa Arch, subject to review of certain air quality components. The Company
believes that drilling activity will now resume, albeit subject to the record of
decision.
OPERATING HAZARDS AND INSURANCE
Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond the Company's 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 conditions, compliance with governmental
requirements, mechanical difficulties or shortages or delays in the delivery of
equipment and that the availability or capacity of gathering systems, pipelines
or processing facilities may limit the Company's ability to market its
production. There can be no assurance that new wells drilled by the Company will
be productive or that the Company will recover all or any portion of its
investment. Drilling for oil and natural gas may involve unprofitable efforts,
not only from dry wells, but from wells that are productive but do not produce
sufficient net revenues to return a profit after drilling, operating and other
costs.
In addition, the Company's 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 which
could result in substantial losses to the Company 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, the
Company's 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.
The MMS requires lessees of OCS properties to post performance bonds in
connection with the plugging and abandonment of wells located offshore and the
removal of all production facilities. The Company has posted an area wide bond
meeting MMS requirements and has obtained additional supplemental bonding on its
offshore leases as required by the MMS.
The Company maintains customary oil and gas related third party liability
coverage, which it must renew annually, that insures the Company 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 the Company will be able to
renew its coverage annually. The Company and its subsidiaries carry workers'
compensation insurance in all states in which they operate. While the Company
believes 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, to liens for current taxes not yet
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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, the Company, rather than
the seller of the undeveloped property, is typically responsible to cure any
such title defects at its expense. If the Company 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, the Company could suffer a loss of its entire
investment in the property. From time to time the Company's title to oil and gas
properties is challenged through legal proceedings. Under the terms of certain
of the Company's joint development, participation and farmout agreements, the
Company's interest (other than interests acquired through holding of leasehold
interests prior to spudding of the well) in each well is conveyed to the Company
upon the successful completion of the well or satisfaction of other conditions.
EMPLOYEES
As of December 31, 1997, the Company had 208 full time employees, none of
whom is represented by organized labor unions. The Company considers its
employee relations to be good.
OFFICE AND EQUIPMENT
The Company maintains its executive offices at 767 Fifth Avenue, New York,
New York. The Company pays Robert A. Belfer, Chairman of the Board and Chief
Executive Officer, a fee of $250,000 per annum 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 Company operations. The Company believes the fee compares favorably
to the terms which might have been available from a non-affiliated party. The
Company currently has 11 months remaining on a lease covering 18,004 square feet
of office space in Houston, Texas. The lease contains two two-year renewal
options. The Company owns a building in Dallas, Texas, containing approximately
65,000 square feet which serves as the headquarters of its Dallas division. The
Company leases 5,796 square feet of office space in Tulsa, Oklahoma pursuant to
a lease that terminates on August 31, 2000. The Company also leases 1,748 square
feet of office space in Midland, Texas pursuant to a lease that terminates on
February 28, 1999. Additionally, the Company owns a property in Granger, Wyoming
consisting of a metal building and associated four acres, used by Belco as a
production office and yard. The Company also maintains 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 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 therein), 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 1998 and thereafter, the Company's financial
position, business strategy and other plans and objectives for future
operations, are forward-looking statements. Although the Company believes that
the expectations reflected in such forward-looking statements are reasonable, it
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 the control of the
Company. 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,
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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 the Company's expectations are
described elsewhere herein. All subsequent written and oral forward-looking
statements attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by such factors.
Volatility of Oil and Gas Prices; Marketability of Production
The Company's revenue, profitability and future rate of growth are
substantially dependent upon the prevailing prices of, and demand for, oil and
natural gas. The Company's ability to maintain or increase its borrowing
capacity and to obtain additional capital on attractive terms is also
substantially dependent upon oil and gas prices. 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 the Company. 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 oil and gas imports and overall economic conditions.
From time to time, oil and gas prices have been depressed by excess domestic and
imported supplies. There can be no assurance that current price levels will be
sustained. It is impossible to predict future oil and natural gas price
movements with any certainty. Declines in oil and natural gas prices may
adversely affect the Company's financial condition, liquidity and results of
operations and may reduce the amount of the Company's oil and natural gas that
can be produced economically. Market prices for oil and gas have generally
declined since December 1997. Additionally, substantially all of the Company's
sales of oil and natural gas are made in the spot market or pursuant to
contracts based on spot market prices and not pursuant to long-term fixed price
contracts. With the objective of reducing price risk, the Company enters into
hedging transactions with respect to a portion of its expected future
production. There can be no assurance, however, that such hedging transactions
will reduce risk or mitigate the effect of any substantial or extended decline
in oil or natural gas prices. Any substantial or extended decline in the prices
of oil or natural gas would have a material adverse effect on the Company's
financial condition and results of operations.
In addition, the marketability of the Company's production depends upon the
availability and capacity of gas gathering systems, pipelines and processing
facilities. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand all
could adversely affect the Company's ability to produce and market its oil and
natural gas. If market factors were to change dramatically, the financial impact
on the Company could be substantial. The availability of markets and the
volatility of product prices are beyond the control of the Company and represent
a significant risk. See "-- Marketing and Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Overview."
Volatile oil and gas prices make it difficult to estimate the value of
producing properties for acquisition and often cause disruption in the market
for oil and gas producing properties, as buyers and sellers have difficulty
agreeing on such value. Price volatility also makes it difficult to budget for
and project the return on acquisitions and development and exploration projects.
Uncertainty of Estimates of Oil and Gas Reserves
This 10-K contains estimates of the Company's proved oil and gas reserves
and the estimated future net revenues therefrom based upon the Company's
estimates and the reserve report prepared by Miller and Lents (the "Miller and
Lents Report") that rely upon various assumptions, including assumptions
required by the Securities and Exchange Commission (the "Commission") as 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, requiring significant decisions and assumptions in the evaluation of
available geological, geophysical, engineering and economic data for each
reservoir. As a result, such 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 may vary
substantially from those estimated in the Company's
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estimates and the Miller and Lents Report. Any significant variance in these
assumptions could materially affect the estimated quantity and value of reserves
set forth in this 10-K. In addition, the Company's proved reserves may be
subject to downward or upward revision based upon production history, results of
future exploration and development, prevailing oil and gas prices and other
factors, many of which are beyond the Company's control. Actual production,
revenues, taxes, development expenditures and operating expenses with respect to
the Company's reserves will likely vary from the estimates used, and such
variances may be material.
Approximately 22% of the Company's total proved reserves at December 31,
1997 were undeveloped, which are by their nature less certain. Recovery of such
reserves will require significant capital expenditures and successful drilling
operations. The reserve data set forth in the Company's estimates and the Miller
and Lents Report assumes that substantial capital expenditures by the Company
will be required to develop such reserves. Although cost and reserve estimates
attributable to the Company's oil and gas reserves have been prepared in
accordance with industry standards, no assurance can be given that the estimated
costs are accurate, that development will occur as scheduled or that the results
will be as estimated. See "Properties -- Oil and Gas Reserves."
The present value of future net revenues referred to in this 10-K should
not be construed as the current market value of the estimated oil and gas
reserves attributable to the Company's properties. In accordance with applicable
requirements of the Commission, the estimated discounted future net cash flows
from proved reserves are generally based on prices and costs as of the date of
the estimate, whereas actual future prices and costs may be materially higher or
lower. Actual future net cash flows also will be affected by increases in
consumption by gas purchasers and changes in governmental regulations or
taxation. The timing of actual future net cash flows from proved reserves, and
thus their actual present value, will be affected by the timing of both the
production and the incurrence of expenses in connection with development and
production of oil and gas properties. In addition, the 10% discount factor,
which is required by the Commission to be used in calculating discounted future
net cash flows for reporting purposes, is not necessarily the most appropriate
discount factor based on interest rates in effect from time to time and risks
associated with the Company or the oil and gas industry in general.
Reserve Replacement
As is customary in the oil and gas exploration and production industry, the
Company's future success depends upon its ability to find, develop or acquire
additional oil and gas reserves that are economically recoverable. Unless the
Company replaces its estimated proved reserves (through development, exploration
or acquisition), the Company's proved reserves will generally decline as they
are produced.
Exploratory drilling and, to a lesser extent, development drilling involve
a high degree of risk that no commercial production will be obtained or that the
production will be insufficient to recover drilling and completion costs. The
costs of drilling, completing and operating wells are uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, including title problems, weather conditions, compliance with
governmental requirements and shortages or delays in the delivery of equipment.
Furthermore, completion of a well does not assure a profit on the investment or
a recovery of drilling, completion and operating costs. See " -- Costs Incurred
and Drilling Results."
The Company's current strategy includes increasing its reserve base through
acquisitions of leaseholds with drilling potential and by continuing to exploit
its existing properties. There can be no assurance, however, that the Company's
exploration and development projects will result in significant additional
reserves or that the Company will have continuing success drilling productive
wells at economically viable costs. Furthermore, while the Company's revenues
may increase if prevailing oil and gas prices increase significantly, the
Company's finding costs for additional reserves could also increase. For a
discussion of the Company's reserves, see "Properties -- Oil and Gas Reserves."
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Ceiling Limitation Writedowns
The Company reports its operations using the full cost method of accounting
for oil and gas properties. Under the full cost accounting rules, the net
capitalized costs of oil and gas properties may not exceed a "ceiling limit",
calculated at the end of each quarter, 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 value of unproved properties, net of related
tax effects. If net capitalized costs of oil and gas properties exceed the
ceiling limit, the Company is subject to a ceiling limitation writedown to the
extent of such excess. A ceiling limitation writedown is a charge to earnings
which does not impact cash flows. However, such writedowns impact the amount of
the Company's stockholders' equity. The risk that the Company will be required
to write down the carrying value of its oil and gas properties increases when
oil and gas prices are depressed or volatile. Application of these rules during
periods of relatively low oil or gas prices, even if temporary, may result in a
ceiling writedown. In addition, writedowns may occur if the Company makes
additional acquisitions or has substantial downward revisions in its estimated
proved reserves. The recent significant declines in oil and gas prices increase
the risk that the Company is required to record a ceiling limitation writedown.
See "--Volatility of Oil and Natural Gas Prices; Marketability of Production."
The Company recorded in its fourth quarter ended December 31, 1997, a non-cash
writedown of approximately $150 million ($97.5 million after tax), a significant
portion of which is attributable to the 1997 Acquisition and lower year end
reserve values due to lower year end prices. No assurance can be given that the
Company will not experience additional ceiling limitation writedowns in the
future. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations."
Substantial Capital Requirements
The Company makes, and will continue to make, substantial expenditures for
the development, exploration, acquisition and production of oil and natural gas
reserves. The Company incurred capital expenditures of $142.7 million during
1996 and $141.0 million, including $0.8 million representing Coda since date of
acquisition (before property sales of approximately $14 million to third parties
and excluding the acquisition of Coda) during 1997. The Company has budgeted
$170 million for capital expenditures for producing properties and leasehold
acquisitions and drilling operations in 1998. Management believes that the
Company will have sufficient cash provided by operating activities, borrowings
under its credit facility and any remaining proceeds from the sale of Preferred
Stock to fund planned capital expenditures in 1998. However, if revenues or cash
flows from operations decrease as a result of lower oil and natural gas prices
or operating difficulties, the Company may be limited in its ability to expend
the capital necessary to undertake or complete its planned drilling program, or
it may be forced to raise additional debt or equity proceeds to fund such
expenditures. The Company's credit facility currently limits the amounts the
Company may borrow to $150 million, subject to increase or decrease based upon
borrowing base adjustments. After giving effect to the application of the
estimated net proceeds from the sale of Preferred Stock, the Company had $16
million of outstanding borrowings under its bank credit facility. There can be
no assurance that additional debt or equity financing or cash generated by
operations will be available to meet these requirements. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."
Acquisition Risks
The Company continues to pursue the acquisition of oil and gas properties
and businesses. Although no definitive agreements have been reached regarding
any such acquisitions, if consummated such acquisitions may have a material
impact on the Company's business. Any acquisition by the Company must satisfy
the applicable covenants set forth in the indenture governing the Company's
8 7/8% Senior Subordinated Notes due 2007 (the "8 7/8% Indenture"), the
indenture governing Coda's 10 1/2% Senior Subordinated Notes due 2006 (the "Coda
Indenture") and the credit agreement (the "Credit Agreement") relating to the
Company's Credit Facility (as defined herein).
The successful acquisition of producing properties generally requires
accurate assessments of: (i) recoverable reserves; (ii) future oil and gas
prices and operating costs; (iii) potential environmental and
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other liabilities; and, (iv) other factors. Such assessments are necessarily
inexact and their accuracy inherently uncertain. It generally is not feasible to
review in detail every individual property involved in an acquisition.
Ordinarily, review efforts are focused on the higher-valued properties.
Nevertheless, even a detailed review of all properties and records may not
reveal existing or potential problems nor will it permit the Company to become
sufficiently familiar with the properties to assess fully their deficiencies and
capabilities. Inspections are not always performed on every well, and
environmental problems, such as groundwater contamination, are not necessarily
observable even when an inspection is undertaken.
Holding Company Structure
The Company conducts all of its operations through subsidiaries.
Accordingly, the Company relies on dividends and cash advances from its
subsidiaries to provide funds necessary to meet its obligations, and the Company
will rely upon such sources of funds to pay interest on indebtedness and
dividends on the Preferred Stock. The ability of any such subsidiary to pay
dividends or make cash advances is subject to applicable laws and contractual
restrictions as well as the financial condition and operating requirements of
such subsidiary.
Restrictions Upon Ability to Pay Dividends
The ability of the Company to make dividend payments on the Preferred Stock
will be dependent on the Company's future performance and liquidity. In
addition, the Credit Agreement, the 8 7/8% Indenture and the Coda Indenture
contain restrictions on the ability of the Company to pay cash dividends on its
capital stock, including the Preferred Stock. The Credit Agreement permits the
Company to pay cash dividends of up to $25,000,000 in the aggregate and
restricts additional dividends to 50% of the Company's cumulative consolidated
net income (as defined in the Credit Agreement) (or if such consolidated net
income is a deficit, 100% of such deficit) from October 1, 1997, subject to
increases and decreases to such cumulative amount based on other adjustments
specified in the Credit Agreement. The Credit Agreement also prohibits the
Company from paying cash dividends if there is a default or event of default
under the Credit Agreement. The 8 7/8% Indenture permits the Company to pay cash
dividends of up to $25,000,000 in the aggregate and restricts additional
dividends to 50% of the Company's cumulative consolidated net income (as defined
in the 8 7/8% Indenture) (or if such consolidated net income is a deficit, 100%
of such deficit) from October 1, 1997, subject to increases and decreases to
such cumulative amount based on other adjustments specified in the 8 7/8%
Indenture. The 8 7/8% Indenture also prohibits the payment of cash dividends in
the event that (i) the Company would not be permitted to incur $1.00 of
additional indebtedness under the 8 7/8% Indenture at the time of a proposed
dividend payment based on its inability to satisfy a fixed charge coverage ratio
or (ii) there is a default or event of default under the 8 7/8% Indenture. The
Coda Indenture permits the Company to pay cash dividends of up to $5,000,000 in
the aggregate and would restrict additional dividends to 50% of the Company's
cumulative consolidated net income (as defined in the Coda Indenture) (or if
such consolidated net income is a deficit, 100% of such deficit) from April 1,
1996, subject to increases and decreases to such cumulative amount based on
other adjustments specified in the Coda Indenture. The Company believes that it
will have capacity in addition to the $5,000,000 under the Coda Indenture. The
Coda Indenture would also prohibit the payment of cash dividends in the event
that (i) the Company would not be permitted to incur $1.00 of additional
indebtedness under the Coda Indenture at the time of a proposed dividend payment
based on its inability to satisfy a fixed charge coverage ratio or (ii) there is
a default or event of default under the Coda Indenture.
Operating Hazards and Uninsured Risks; Production Curtailments
Oil and gas drilling and production activities are subject to numerous
risks, many of which are beyond the Company's 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 and that
title problems, weather conditions, compliance with governmental requirements,
mechanical difficulties or shortages or delays in the delivery of drilling rigs,
work boats and other equipment may limit the Company's ability to market its
production. There can be no assurance that new wells drilled by the Company will
be productive or that the Company will recover all or any portion of its
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
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sufficient net revenues to return a profit after drilling, operating and other
costs. In addition, the Company's 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 which could result in substantial losses to the Company 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, many of the Company's 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. In accordance with customary industry practice, the Company
maintains insurance against some, but not all, of the risks described above.
There can be no assurance that any insurance will be adequate to cover losses or
liabilities. The Company cannot predict the continued availability of insurance
at premium levels that justify its purchase. Losses and liabilities arising from
uninsured or under-insured events could have a material adverse effect on the
financial condition and results of operations of the Company.
From time to time, due primarily to contract terms, pipeline interruptions
or weather conditions, the producing wells in which the Company owns an interest
may be subject to production curtailments. The curtailments may vary from a few
days to several months. In most cases the Company will be provided only limited
notice as to when production will be curtailed and the duration of such
curtailments. The Company is currently not curtailed on any of its production.
Competition
The Company operates in a highly competitive environment. The Company
competes with major and independent oil and gas companies for the acquisition of
desirable oil and gas properties, as well as for the equipment and labor
required to develop and operate such properties. Many of these competitors have
financial and other resources substantially greater than those of the Company.
Risks of Price Risk Management Transactions
In order to manage its exposure to price risks in the marketing of its oil
and natural gas, the Company has in the past and expects to continue to enter
into oil and natural gas price risk management arrangements with respect to a
portion of its expected production. These arrangements may include futures
contracts on the NYMEX fixed price delivery contracts and financial swaps. While
intended to reduce the effects of volatility of the price of oil and natural
gas, such transactions may limit potential gains by the Company if oil and
natural gas prices were to rise or fall substantially over the price established
by the arrangement. In addition, such transactions may expose the Company to the
risk of financial loss in certain circumstances, including instances in which:
(i) production is less than expected; (ii) if there is a widening of price
differentials between delivery points for the Company's production and the
delivery point assumed in the arrangement; (iii) the counterparties to the
Company's future contracts fail to perform under the contract; or (iv) a sudden,
unexpected event materially impacts oil or natural gas prices. See "-- Price
Risk Management Transactions" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
Governmental Regulation
Oil and gas operations are subject to various United States federal, state
and local governmental regulations that change from time to time in response to
economic or political conditions. Matters subject to regulation 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, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow of
oil and gas wells below actual production capacity in order to conserve supplies
of oil and gas. In
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addition, the production, handling, storage, transportation and disposal of oil
and gas, by-products thereof and other substances and materials produced or used
in connection with oil and gas operations are subject to regulation under
federal, state and local laws and regulations primarily relating to protection
of human health and the environment. The Company may also be subject to
substantial clean-up costs for any toxic or hazardous substance that may exist
under any of its current properties or properties that it has operated in the
past. To date, expenditures related to complying with these laws and for
remediation of existing environmental contamination have not been significant in
relation to the results of operations of the Company.
Although the Company believes it is in substantial compliance with all
applicable laws and regulations, the requirements imposed by such laws and
regulations are frequently changed and subject to interpretation. In addition,
the recent trend toward stricter standards in environmental legislation and
regulation is likely to continue. For instance, legislation has been proposed in
Congress from time to time that would reclassify certain crude oil and natural
gas exploration and production wastes as "hazardous wastes" which would make the
reclassified wastes subject to much more stringent handling, disposal and
clean-up requirements. If such legislation were to be enacted, it could have a
significant impact on the operating costs of the Company, as well as the oil and
gas industry in general. The Company could incur substantial costs to comply
with environmental laws and regulations, and the Company is unable to predict
the ultimate cost of compliance with these requirements or their effect on its
production. See "-- Regulation."
Reliance on Key Personnel
The Company depends, and will continue to depend in the foreseeable future,
on the services of its 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. The ability of the Company to retain its
officers and key employees is important to the continued success and growth of
the Company.
The Company is dependent upon Robert A. Belfer, the Company's Chairman and
Chief Executive Officer, and Laurence D. Belfer, the Company's President and
Chief Operating Officer, in addition to certain of its other executive officers.
The unexpected loss of the services of one or more of these individuals could
have a detrimental effect on the Company. The Company does not maintain key man
life insurance on any of its officers or key employees. See "Directors and
Executive Officers of the Registrant."
Control by Certain Stockholders
Robert A. Belfer, his spouse, his children, his sisters, their spouses,
their children and trusts for their children and grandchildren own approximately
77% of the outstanding shares of the Common Stock and approximately 14% of the
outstanding shares of the Preferred Stock. 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 the Company and may adversely affect the voting and other rights of
other stockholders.
Certain Potential Conflicts of Interests
Robert A. Belfer is a director of Enron Corp. ("Enron"). Enron, primarily
through its majority owned subsidiary, Enron Oil & Gas Company ("EOG"), is
involved in the exploration, development and production of oil and gas. Mr.
Belfer is not a director of EOG. While the Company's activities have not
historically overlapped with the activities of Enron or EOG, the Company may in
the future compete for certain opportunities with Enron or EOG. To the extent
any conflict from such future competition may arise, Mr. Belfer intends to
excuse himself from participating in any decisions of the Board of Directors of
Enron related to such opportunities.
Coda was acquired from Joint Energy Investment Development Investments
Limited Partnership ("JEDI") and certain members of Coda management. The general
partner of JEDI is an affiliate of Enron. The consideration paid and issued by
the Company for Coda was determined in an arms' length negotiations among the
Company, Coda and the stockholders of Coda (including JEDI).
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CERTAIN DEFINITIONS
The definitions set forth below shall apply to the indicated terms as used
in this 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.
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.
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.
MMbtu. One million Btus.
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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.
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 a share of
production.
Workover. Operations on a producing well to restore or increase production.
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ITEM 2 -- PROPERTIES
OIL AND GAS RESERVES
The following table sets forth information with respect to the Company's
estimated net proved oil and gas reserves as of December 31, 1997. Information
in this 10-K as of December 31, 1997 relating to properties with 94% of the
Company's estimated net proved oil and gas reserves and the estimated future net
revenues attributable thereto is based upon the Miller and Lents Report prepared
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 Commission 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 -- Uncertainty of Estimates of Oil
and Gas Reserves."
AS OF DECEMBER 31, 1997
--------------------------------
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ------
Estimated Proved Reserves:
Gas (Bcf)................................................. 226.1 71.1 297.2
Oil (MMBbls).............................................. 41.3 9.9 51.2
------ ------ ------
Total Gas Equivalents (Bcfe)................................ 473.6 130.5 604.1
Estimated Future Net Revenue before Income Taxes (in
millions)(1).............................................. $792.1 $139.9 $932.0
Present Value of Estimated Future Net Revenues before Income
Taxes (discounted at 10% per annum) (in millions)(1)...... $442.0 $ 62.9 $504.9
- ---------------
(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
1997 prices, which were $2.30 per Mcf of gas and $17.28 per barrel of oil
without giving effect to commodities price risk management activities
accounted for as hedges. At December 31, 1997, the estimated future net
revenue before income taxes and the present value of such estimated future
net revenue before income taxes related to such activities were $5.9 million
and $5.5 million, respectively (based on oil and gas prices in effect at
December 31, 1997), which amounts have not been added to estimated future
net revenue before income taxes and its present value as shown above. If
such amounts were added, estimated future net revenue before income taxes
would equal $798 million (Proved Developed) and $938 million (Total) and
present values of such estimated future net revenues before income taxes
would equal $447.5 million (Proved Developed) and $510.4 million (Total).
ITEM 3 -- LEGAL PROCEEDINGS
The Company is a named defendant in routine litigation incidental to its
business. While the ultimate results of these proceedings cannot be predicted
with certainty, the Company does not believe that the outcome of these matters
will have a material adverse effect on the Company.
ITEM 4 -- SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the quarter ended December 31, 1997, no matters were submitted by
the Company to a vote of its security holders.
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PART II
ITEM 5 -- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
As of March 20, 1998, the Company estimates there were approximately 3,429
beneficial holders of its Common Stock. The Company's Common Stock is listed on
the New York Stock Exchange ("NYSE") and traded under the symbol "BOG." As of
March 20, 1998, the Company had 31,584,400 shares outstanding and its closing
price on the NYSE was $17.125 per share. The high and low sales prices for the
Company's Common Stock during each quarter in the two years ended December 31,
1997 were as follows:
COMMON STOCK
HIGH LOW
-------- -------
1996
First Quarter (commencing March 25, 1996)................... $ 22.875 $21.625
Second Quarter.............................................. 35.50 22.25
Third Quarter............................................... 37.25 18.25
Fourth Quarter.............................................. 29.125 23.00
1997
First Quarter............................................... $ 28.50 $18.125
Second Quarter.............................................. 24.00 18.25
Third Quarter............................................... 22.1875 18.125
Fourth Quarter.............................................. 22.4375 18.25
The Company has never paid a dividend, cash or otherwise on its Common
Stock. Certain provisions of the Company's Credit Agreement, 8 7/8% Indenture
and the Coda Indenture restrict the Company's ability to declare or pay cash
dividends on its Common Stock. Other than payments of Preferred Stock dividends,
the Company currently intends to maintain a policy of retaining cash for the
continued expansion of its business.
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ITEM 6 -- SELECTED FINANCIAL DATA
The following table sets forth selected financial data regarding the
Company 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 the Company's financial statements and
notes thereto, which follow.
YEAR ENDED DECEMBER 31,
------------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales.................. $ 129,994 $ 119,710 $ 68,767 $ 40,362 $ 19,255
Commodity Price Risk Management
Activities...................... (6,479) (5,967) 9,480 550 --
Interest........................... 3,245 2,653 353 195 57
--------- --------- -------- -------- --------
Total revenues....................... 126,760 116,396 78,600 41,107 19,312
--------- --------- -------- -------- --------
Costs and expenses:
Oil and gas operating expenses..... 12,758 7,847 5,824 5,510 2,495
Depreciation, depletion and
amortization.................... 46,684 40,904 27,590 14,072 4,098
Impairment of oil and gas
properties...................... 150,000
General and administrative......... 3,913 3,059 2,597 2,269 856
Interest Expense................... 1,668 -- -- -- --
--------- --------- -------- -------- --------
Total costs and expenses............. 215,023 51,810 36,011 21,851 7,449
--------- --------- -------- -------- --------
Income (loss) before income taxes.... (88,263) 64,586 42,589 19,256 11,863
Pro forma provision (benefit) in lieu
of income tax(1)................... (31,355) 21,953 13,852 5,030 1,504
--------- --------- -------- -------- --------
Pro forma net income (loss)(1)....... $ (56,908) $ 42,633 $ 28,737 $ 14,226 $ 10,359
========= ========= ======== ======== ========
Pro forma basic and diluted earnings
(loss) per share(1)................ $ (1.80) $ 1.42 $ 1.15 $ .57 $ .41
========= ========= ======== ======== ========
Weighted average common shares
outstanding(2)..................... 31,538 29,986 25,000 25,000 25,000
STATEMENT OF CASH FLOWS DATA:
Income before income taxes,
depreciation, depletion and
amortization and other non-cash
items(3)........................... $ 107,345 $ 108,716 $ 69,609 $ 33,605 $ 15,961
Capital expenditures................. 564,459 142,712 71,387 52,230 32,647
Cash flow from operating
activities......................... 101,523 108,059 62,037 28,126 14,351
Cash flow from investing
activities......................... (363,136) (143,826) (65,133) (52,670) (33,698)
Cash flow from financing
activities......................... 230,400 77,684 (2,299) 30,376 18,708
BALANCE SHEET DATA:
Working capital...................... $ 36,757 $ 48,667 $ 446 $ 14,357 $ 3,108
Total assets......................... 697,109 303,918 145,550 101,625 50,248
Long-term debt....................... 352,090 -- 22,000 6,930 --
Equity............................... 184,648 233,203 105,015 89,890 47,188
- ---------------
(1) Gives pro forma effect to the application of federal and state income taxes
to the Company as if it were a taxable corporation for the periods
presented. 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 the Company's Initial Public Offering.
(2) Pro forma earnings per share has been computed as if the 25,000,000 shares
of Common Stock that were issued in connection with Combination had been
outstanding for all years prior to 1996.
(3) Income before income taxes, depreciation, depletion and amortization,
impairment of oil and gas properties and other non-cash mark-to-market
accounting provisions is presented as a measure of the Company's ability to
service its debt and to fund capital expenditures, not as a measure of
operating results, and is not presented in the financial statements.
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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 the
Company's historical financial position and results of operations for the
periods indicated. The following discussion is based on the Company's historical
financial statements and related notes thereto which follow and contain detailed
information that should be referred to in conjunction with Management's
Discussion and Analysis.
OVERVIEW
Since its inception in April 1992, the Company has grown rapidly, with
substantially all of its growth coming "through the drill bit" and the 1997
Acquisition of Coda. The Company's participation in exploration and development
activities in the Moxa Arch Trend of Wyoming and in the Austin Chalk Trend in
the Giddings Field of Texas are principally responsible for the drill bit
portion of its substantial expansion of production, revenues and reserves.
The Company was organized as a Nevada corporation in January 1996 in
connection with the Combination (the "Combination") of ownership interests (the
"Combined Assets") in certain entities (the "Predecessors") and direct interests
in oil and gas properties and certain hedge transactions (the "Direct
Interests") owned by members of the Robert A. Belfer family and by employees of
the Predecessors and entities related thereto. The Company 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 the Company 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 initial public 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.
Pursuant to the Exchange Agreement, the owners of the Combined Assets
received all revenues attributable to production and are responsible for all
incurred expenses related to the Combined Assets for all periods prior to
January 1, 1996. Effective with the Combination (which was contemporaneous with
the closing of the initial public offering), the Company is entitled to receive
all revenues and is responsible for all expenses related to the Combined Assets
on and after January 1, 1996.
From inception through the date of the Combination, March 29, 1996, the
Predecessors were not required to pay federal income taxes due to their status
as either a partnership, individual owner, Subchapter S corporation, limited
liability corporation or joint venture, which are "pass-through" entities that
are not subject to federal income taxation; instead, taxes relating to the
Combined Assets for such periods were required to be paid by the owners of the
Predecessors and the Direct Interests.
Although the effective date of the Exchange Agreement is January 1, 1996,
each owner of the Combined Assets was required to include in its taxable income,
for all periods ending on the date of or prior to the completion of the
Combination, such owner's allocable portion of the taxable income attributable
to the Combined Assets and was entitled to all tax benefits attributable to the
Combined Assets through completion of the Combination.
On November 26, 1997, the Company acquired all of the outstanding capital
stock of Coda, an independent energy company that is principally engaged in the
acquisition and exploitation of producing oil and natural gas properties. Coda's
properties are principally located in the Permian Basin of west Texas and the
Mid-Continent region of Oklahoma and north Texas. The acquisition approximately
doubled the Company's reserve base to 604 Bcfe at December 31, 1997, extended
the Company's reserve life from approximately 5.3 years to approximately 8.1
years, and established a balanced reserve mix of approximately 51% oil and 49%
natural gas.
The Company has accounted for the acquisition of Coda using the purchase
method of accounting for business combinations. In accordance with the Statement
of Financial Accounting Standards Board No. 109 ("SFAS 109"), the Company
recorded, in the fourth quarter ended December 31, 1997, a one-time non-cash
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"gross up" of deferred taxes of approximately $101 million to the full cost pool
related to the acquisition of Coda.
Based on the Company's year end 1997 estimated proved reserves, the Company
recorded in the fourth quarter ending December 31, 1997, a non-cash ceiling test
provision of approximately $150 million ($97.5 million after tax). The ceiling
test provision included the effect of the non-cash deferred tax liability of
$101 million (SFAS 109 "gross up") attributable to the 1997 Acquisition on the
Company's full cost pool at December 31, 1997 reflecting the difference between
the tax basis of Coda's assets and liabilities and the amounts recorded for
financial reporting purposes and the PV10 value of year end 1997 reserves, which
were significantly impacted by lower product prices when compared to year end
1996 prices.
The Company's revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for natural gas, oil and
condensate. These prices are dependent upon numerous factors beyond the
Company's control, such as economic, political and regulatory developments and
competition from other sources of energy. The energy markets have historically
been very volatile, and there can be 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 the Company's financial position, results of operations and access to
capital, as well as the quantities of natural gas and oil reserves that the
Company may economically produce. Natural gas produced is sold under contracts
that primarily reflect spot market conditions for their particular area. The
Company markets its oil with other working interest owners on spot price
contracts and typically receives a modest premium to the area price posted for
such oil.
The Company utilizes commodity swaps and options and other commodity price
risk management transactions for a portion of its oil and natural gas production
to achieve a more predictable cash flow and to reduce its exposure to price
fluctuations. The Company accounts for these transactions as hedging activities
or uses mark-to-market accounting for those contracts that do not qualify for
hedge accounting. As of December 31, 1997, the Company had various natural gas
and oil price risk management contracts in place with respect to substantial
portions of its estimated production for 1998 and 1999 and with respect to
lesser portions of its estimated production for thereafter. The Company expects
from time to time to either add to or reduce the amount of price risk management
contracts that it has in place in keeping with its price risk management
strategy.
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The following table sets forth certain operations data of the Company for
the periods presented:
YEAR ENDED DECEMBER 31,
-------------------------------
1997 1996 1995
-------- -------- -------
Oil and Gas Sales (in thousands)(1)................. $129,994 $119,710 $68,767
Weighted Average Sales Prices (Unhedged):
Oil (per Bbl)..................................... $ 19.28 $ 21.30 $ 17.35
Gas (per Mcf)..................................... $ 2.11 $ 2.00 $ 1.42
Net Production Data:
Oil (MBbls)....................................... 1,295 794 961
Gas (MMcf)........................................ 49,710 51,289 37,047
-------- -------- -------
Gas equivalent (MMcfe)............................ 57,479 56,053 42,813
Data per Mcfe:
Oil and gas sales revenues (unhedged)............. $ 2.26 $ 2.14 $ 1.61
Commodity price risk management activities
-- Cash........................................ (.13) .06 .22
-- Non-Cash.................................... .02 (.17) --
Oil and gas operating expenses.................... (0.22) (.14) (.14)
General and administrative........................ (0.07) (.06) (.06)
Depreciation, depletion and amortization.......... (0.81) (.73) (.64)
-------- -------- -------
Pre-tax operating profit(2)....................... $ 1.05 $ 1.10 $ 0.99
======== ======== =======
Number of wells drilled or drilling(3):
Gross............................................. 135 80 118
Net............................................... 62 34 34
- ---------------
(1) Oil and gas sales exclude results related to commodity price risk management
activities reported separately.
(2) Excludes $150 million non-cash ceiling test provision and interest
income/expense net.
(3) Excludes Coda prior to date of acquisition.
The Company does not currently have any information concerning the Year
2000 compliance of its suppliers and customers. In the event that any of the
Company's significant suppliers or customers do not successfully and timely
achieve Year 2000 compliance, the Company does not believe its business or
operations would be adversely affected.
RESULTS OF OPERATIONS -- 1997 COMPARED TO 1996
Revenues
Oil and gas sales revenues for the year 1997 (unhedged) increased 9% to
$130.0 million when compared to the $119.7 million realized in 1996. The
increase is principally identified with a 63% increase in oil production over
the prior year, partially offset by lower prices. In 1997, weighted average oil
prices realized (unhedged) totaled $19.28 per barrel, a 9% decline when compared
to the $21.30 realized in 1996. The natural gas weighted average prices realized
(unhedged) increased 6% from $2.00 in 1996 to $2.11 in 1997. Production volume
in 1997 on an Mcfe basis increased 3% to 57,479 MMcfe.
Commodity price risk management activities resulted in a net pre-tax loss
of $6.5 million for 1997 which included (1) realized hedging losses of $5.4
million, (2) net realized gains related to non-hedging transactions totaling
$8.1 million, (3) net premiums received totaling $5.0 million and (4) a non-cash
unrealized gain for mark-to-market accounting of $2.0 million. The impact of
such activities on an Mcfe basis amounted to net losses of $0.11 ($0.13 cash
losses and a non-cash gain of $0.02) and $0.11 ($0.06 cash gain and a non-cash
loss of $0.17) per Mcfe for 1997 and 1996, respectively.
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Interest income realized during 1997 was $3.3 million compared to $2.7
million for 1996 due to higher average cash balances principally attributable to
the proceeds realized by the Company from the offering of its 8 7/8% Senior
Subordinated Notes completed in September 1997.
Costs and Expenses
Production and Operating Expenses. Production and operating expenses,
including associated taxes, totaled $12.8 million in 1997, an increase of 63%
over the $7.9 million incurred in the prior year. Operating costs on a Mcfe
basis increased 59% to $0.22 per Mcfe compared to $0.14 per Mcfe in 1996. The
higher costs are directly associated with new oil wells placed into production
during the year, which typically are more costly than gas wells to operate, and
one month of Coda's production activity which is primarily secondary oil
recovery. A substantial portion of the Company's natural gas production from
wells drilled prior to September 1996 in the downdip Giddings Field qualifies
for exemption from Texas state production taxes. This exemption will continue
for production through August 31, 2001. The state of Louisiana offers a full
year exemption from severance taxes for production from oil and gas wells that
are returned to service after having been active for two or more years or having
30 days or less of production during the past two years.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization ("DD&A") costs related to oil and gas properties, excluding the
non-cash ceiling test provision described below, totaled $46.7 million for 1997,
a 14% increase over the $40.9 million incurred in the 1996 comparable period.
The Company average DD&A rate per Mcfe for 1997 was $0.81 compared to a rate of
$0.73 per Mcfe in 1996. The higher rate reflects increased levels of development
and exploration drilling activities and higher costs paid for related third
party services.
At year end 1997, the Company recorded a non-cash ceiling test provision of
$150 million ($97.5 million after tax) based on year end 1997 estimated proved
reserves. The ceiling test provision included the effect of the non-cash $101
million SFAS 109 "gross-up" attributable to the Coda acquisition on the
Company's full cost pool at December 31, 1997 and the SEC PV10 value of year end
1997 reserves, which were significantly impacted by lower product prices when
compared to year end 1996 prices.
General and Administrative Expenses. General and administrative expenses
("G&A") totaled $3.9 million for 1997, net of capitalized G&A costs directly
related to the Company's oil and natural gas exploration and development
efforts, a 28% increase over the prior year. The increase reflects the
acquisition of Coda and one month of Coda's operations and related expenses. On
an Mcfe basis, G&A costs were $0.07 for 1997 and $0.06 for 1996. Exploration
related G&A expenses for 1997 in the amount of $5.8 million have been
capitalized to oil and gas property accounts. The increase of $2.6 million over
the 1996 comparable amount of $3.1 million principally reflects the addition of
new personnel recruited to handle the Company's rapidly expanding exploration
activities.
Income Before Income Taxes
The Company's pre-tax loss for 1997 was $88.3 million compared to $64.6
million of pre-tax income reported in 1996. The loss is principally the result
of the $150 million non-cash ceiling test provision associated with SFAS 109
"gross-up" attributable to the acquisition of Coda and its impact on the full
cost pool coupled with lower product prices at December 31, 1997 when compared
to the prior year.
Income Taxes
Income tax benefits were recorded for 1997 totaling $31.4 million as a
result of the reported pre-tax loss. The provision for taxes in 1996 included a
one-time, non-cash charge in the amount of $30.1 million that was required as a
result of the Combination which changed the tax status of the Company.
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RESULTS OF OPERATIONS -- 1996 COMPARED TO 1995
Revenues
Oil and natural gas sales revenues for the year 1996 (unhedged) increased
74% to $119.7 million when compared to the $68.8 million realized in 1995. The
substantial increase is principally identified with the addition of new Giddings
Field wells, in both the Navasota and Independence areas of the Company's
operations, and higher average prices realized for both oil and natural gas.
Weighted average oil and natural gas prices (unhedged) increased 23% and 41%,
respectively, when compared to 1995 price realizations. Production volume in
1996 on an Mcfe basis increased 31% over the prior year to 56,053 MMcfe.
Commodity price risk management activities resulted in a pre-tax loss of
$6.0 million for 1996 which included (1) a realized hedging loss of $83,000, (2)
net realized losses on settlements of non-hedging transactions totaling $3.9
million, (3) net premiums received totaling $7.4 million and (4) a non-cash
unrealized loss for mark-to-market accounting of $9.4 million. As a result of
the substantial oil and natural gas price increases which occurred in the fourth
quarter of 1996 (which had a positive impact on oil and gas sales revenues), the
Company recorded a fourth quarter pre-tax loss of $8.4 million from commodity
price risk management activities which included a $4.2 million non-cash charge
for unrealized losses related to required mark-to-market accounting. The 1995
results of operations included pre-tax income of $9.5 million related to
realized hedging gains. The impact of such activities on an Mcfe basis amounted
to a loss of $0.11 ($0.06 cash gain and a non-cash loss of $0.17) and a gain of
$0.22 (all cash) per Mcfe for 1996 and 1995, respectively.
Interest income realized during 1996 was $2.7 million compared to $0.4
million for 1995 due to higher average cash balances principally attributable to
the proceeds of the Company's initial public offering.
Costs and Expenses
Production and Operating Expenses. Production and operating expenses
including associated taxes in 1996 amounted to $7.9 million, an increase of 35%
over the $5.8 million incurred in the prior year. Operating costs on an Mcfe
basis were flat at $0.14 per Mcfe for both 1996 and 1995. A substantial portion
of the Company's natural gas production from wells drilled prior to September
1996 in the downdip Giddings Field qualifies for exemption from Texas state
production taxes. This exemption will continue for production through August 31,
2001.
Depreciation, Depletion and Amortization. DD&A costs related to oil and gas
properties totaled $40.9 million for 1996, a 48% increase over the $27.6 million
incurred in the 1995 comparable period. The Company's average DD&A rate per Mcfe
for 1996 was $0.73 compared to a rate of $0.64 per Mcfe in 1995. The increased
rate primarily reflects the higher average cost of drilling deeper wells and
costs associated with the unsuccessful east Texas Cotton Valley Reef Trend
exploration activities.
General and Administrative Expenses. G&A totaled $3.1 million for 1996, net
of capitalized G&A costs directly related to the Company's oil and natural gas
exploration and development efforts; an 18% increase over the prior year. The
increase reflects the addition of new employees hired to assist with the
Company's expanding activities and additional costs incurred in connection with
becoming a publicly traded entity. On an Mcfe basis, G&A costs were flat at
$0.06 for both 1996 and 1995. Operations G&A expenses for 1996 in the amount of
$3.1 million have been capitalized to oil and gas property accounts. The
increase of $1.8 million over the 1995 comparable amount reflects the Company's
rapidly expanding exploration and development efforts.
Income Before Income Taxes
The Company's income before income taxes for 1996 was $64.6 million, a 52%
increase over the $42.6 million realized in the prior year comparable period.
The increase is directly related to increased production from new well additions
in the Giddings Field and substantially higher average prices realized for both
oil and natural gas.
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Income Taxes
Income tax expenses for 1996 totaled $46.4 million. The provision for taxes
includes a one-time, non-cash charge in the amount of $30.1 million that was
required as a result of the Combination and the Exchange Agreement which changed
the tax status of the Company.
LIQUIDITY AND CAPITAL RESOURCES
General
On March 29, 1996, the Company successfully completed an initial public
offering of 6,500,000 shares of Common Stock. The initial public offering
provided the Company with approximately $113 million net of offering expenses.
Proceeds from the offering were used to repay approximately $35 million of
indebtedness under the Company's previous credit facility, fund capital
expenditures and for other general corporate purposes. The remaining proceeds
from the offering, together with cash flows from operations, were used to fund
planned capital expenditures, including lease acquisitions, commitments, other
working capital requirements and general corporate purposes.
In September 1997, the Company entered into a new five-year $150 million
Credit Agreement dated September 23, 1997 (the "Credit Facility") with The Chase
Manhattan Bank, N.A., as administrative agent (the "Agent") and other lending
institutions (the "Banks"). The Credit Facility provides for an aggregate
principal amount of revolving loans of up to the lesser of $150 million or the
Borrowing Base (as defined) as in effect from time to time, which includes a
subfacility from the Agent for letters of credit of up to $25 million. The
Borrowing Base at December 31, 1997 was set at $105 million with $85 million
advanced to the Company at that date and was increased to $150 million on
February 27, 1998 concurrent with the consummation of the Permian Acquisition.
The borrowing base will be 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, the Company may request two additional
redeterminations and the Banks may request one additional redetermination per
year.
Indebtedness of the Company under the Credit Facility is secured by a
pledge of the capital stock of each of the Company's material subsidiaries.
Indebtedness under the Credit Facility bears interest at a floating rate
based (at the Company's option) upon (i) the ABR with respect to ABR Loans or
(ii) the Eurodollar Rate for one, two, three or six months (or nine or twelve
months if available to the Banks) Eurodollar Loans, plus the Applicable Margin.
The ABR is the greater of (i) the Prime Rate, (ii) the Base CD Rate plus 1% or
(iii) the Federal Funds Effective Rate plus 0.50%. The Applicable Margin for
Eurodollar Loans varies from 0.50% to 0.875% depending on the Borrowing Base
usage. Borrowing Base usage is determined by a ratio of (i) outstanding Loans
and letters of credit to (ii) the then effective Borrowing Base. Interest on ABR
Loans will be payable quarterly in arrears and interest on Eurodollar Loans is
payable on the last day of the interest period therefor and, if longer than
three months, at three month intervals.
The Company is 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 0.20% to 0.30% depending on the Borrowing Base usage.
In September 1997, the Company issued $150 million of 8 7/8% Senior
Subordinated Notes due 2007 (the "8 7/8% Notes"). Interest on the 8 7/8% Notes
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, commencing on March 15, 1998. 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 the
Company's option prior to September 15, 2002. Thereafter, the 8 7/8% Notes will
be subject to redemption at the option of the Company, 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
Company 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.
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The 8 7/8% Notes are general unsecured obligations of the Company and are
subordinated in right of payment to all existing and future Senior Debt (as
defined in the 8 7/8% Indenture) of the Company, 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 the Company,
including the Coda Notes and rank senior in right of payment to all other
subordinated indebtedness of the Company.
As of December 31, 1997, Coda had $110,000,000 principal amount outstanding
of the Coda Notes. Interest on the Coda Notes accrues at the rate of 10 1/2% per
annum and is payable semi-annually in arrears on April 1 and October 1 of each
year. Except under limited circumstances, the Coda Notes are not redeemable at
the Company's option prior to April 1, 2001. Thereafter the Coda Notes will be
subject to redemption at specified prices, plus accrued and unpaid interest, if
any, thereon to the applicable redemption date. The acquisition by the Company
of Coda required Coda to make an offer to purchase the Coda Notes at a purchase
price of 101% of principal amount which expired on January 9, 1998. $1 million
principal amount of Coda Notes were tendered and accepted for purchase under
this offer.
The Coda Notes are general unsecured obligations of Coda and are
subordinated in right of payment to all existing and future Senior Debt (as
defined) of Coda, including any bank debt.
On February 25, 1998, the Company merged Coda into Belco and Belco assumed
the obligations under the Coda Notes.
In December 1997, the Company entered into two interest rate swap
agreements converting two fixed rate obligations to floating rate obligations.
The first agreement covers $100 million of 8.875% long-term debt (comparable to
the interest rate on the 8 7/8% Notes) and obligates the Company 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 8.875% through September 15, 2001 and at 10% from March 15,
2002 through September 15, 2007. The second agreement covers $110 million of
10.5% long-term debt (comparable to the interest rate on the Coda Notes) and
obligates the Company 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 10.5% through October 1, 1999 and
11.625% from April 1, 2000 through April 1, 2003. The two agreements will reduce
the Company's interest expense by approximately $1 million through October 1,
1998.
On March 10, 1998 the Company completed the sale of 4.37 million shares of
its Preferred Stock. The Preferred Stock has a liquidation preference of $25 per
share and is convertible at the option of the holder into shares of the
Company'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. The Company received net proceeds from the
sale of the Preferred Stock of $105.1 million, which was used to pay down bank
indebtedness.
Cash Flow
Net operating cash flow (pre-tax), a measure of performance for exploration
and production companies, is generally derived by adjusting net income (loss) to
eliminate the effects of the non-cash depreciation, depletion and amortization
expense, impairment of oil and gas properties provision for deferred income
taxes and non-cash effects of commodity price risk management activities. Net
operating cash flow before changes in working capital was approximately $107.3
million and $108.7 million for 1997 and 1996, respectively. The Company had
working capital amounting to $36.8 million as of year end 1997, compared to
$48.7 million available as of December 31, 1996.
Capital Expenditures
For 1997, the Company, including one month of Coda activities, incurred
capital expenditures in the amount of $141 million, before property sales of
approximately $14 million to third parties, and excluding the acquisition of
Coda.
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The Company intends to fund its future capital expenditures, commitments
and working capital requirements through cash flows from operations, borrowings
under the Credit Facility or other potential financings. If there are changes in
oil and natural gas prices, however, that correspondingly affect cash flows and
the Borrowing Base under the Credit Facility, the Company has the discretion and
ability to adjust its capital budget. The Company believes it will have
sufficient capital resources and liquidity to fund its capital expenditures and
meet its financial obligations as they come due.
In November 1997, the Company completed the acquisition of Coda. The
Company paid an aggregate of $324 million including approximately $192 million
in cash ($150 million plus a $42 million adjustment for proceeds from the
disposition of Taurus Energy Corp. ("Taurus"), a subsidiary of Coda (which
occurred on the day prior to closing of the 1997 Acquisition), assumption of
$110 million of long-term debt outstanding of Coda and issued three year
warrants to purchase 1,666,667 shares of Common Stock of the Company at $27.50
per share to the holders of the outstanding common stock, preferred stock and
options to purchase common stock of Coda. Concurrently with the closing of the
acquisition of Coda, the Company contributed $23 million to Coda that Coda
utilized, together with the funds from the disposition of Taurus, to repay all
of the debt outstanding under Coda's revolving credit facility (approximately
$65 million in principal amount), plus accrued interest thereon, and such credit
facility was thereafter terminated. The Company funded the cash portion of the
consideration and the cash contribution to Coda through cash on hand and
borrowings of $84 million under the Credit Facility.
Commodity Price Risk Management Transactions
Certain of the Company's commodity price risk management arrangements
require the Company to deliver cash collateral or other assurances of
performance to the counterparties in the event that the Company's payment
obligations with respect to its commodity price risk management transactions
exceed certain levels.
With the primary objective of achieving more predictable revenues and cash
flows and reducing the exposure to fluctuations in oil and natural gas prices,
the Company has entered into price risk management 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. The
Company engages in transactions such as selling covered calls or straddles 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. The
Company has entered into price risk management transactions with respect to a
substantial portion of its estimated production for the remainder of 1998
through 2000 and lesser portions of its estimated production thereafter. The
Company continues to evaluate whether to enter into additional price risk
management transactions for 1998 and future years. In addition, the Company may
determine from time to time to unwind its then existing price risk management
positions as part of its price risk management strategy.
OTHER
Environmental Matters
The Company'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. The Company believes its current operations are
in material compliance with current environmental laws and regulations. There
are no environmental claims pending or, to the Company's knowledge, threatened
against the Company. 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 the Company's properties.
Recent Accounting Pronouncements
In June, 1997, Statement of Financial Accounting Standards ("SFAS") No.
130 -- "Comprehensive Income" was issued effective for interim and annual
periods after June 30, 1997. This Statement will require
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the presentation of comprehensive income which is traditional net income (loss)
adjusted for certain items that previously were only reflected in direct charges
or credits to equity. The new pronouncement will have an effect on Belco due to
its current investments held for sale.
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 Officers required under Item 10
will be contained in the definitive Proxy Statement of the Company for its 1998
Annual Meeting of Shareholders (the "Proxy Statement") under the headings
"Election of Directors" and "Executive Compensation and Other Information" 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, 1997. The information regarding Officers not appearing
in the Proxy Statement is identified below:
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 the Company and their
ages, positions with the Company and business experience are presented below:
Robert A. Belfer, age 62, is Chairman of the Board and Chief Executive
Officer of the Company. Mr. Belfer began his career at 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 the Company. In addition
to his position at the Company, Mr. Belfer serves on the boards of Enron and NAC
Re Corporation. 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 31, is Director, President and Chief Operating
Officer of the Company. Mr. Belfer joined the Company as Vice President in
September 1992. He was promoted to Executive Vice President in May 1995 and
Chief Operating Officer in December 1995 and was named President in April 1997.
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).
Philip A. Epstein, age 41, is Senior Financial and Legal Advisor and
General Counsel of the Company. Mr. Epstein began his career as a corporate
lawyer with the New York City law firms of Kaye, Scholer, Fierman, Hays &
Handler (1984-1987) and Fried, Frank, Harris, Shriver & Jacobson (1988-1991),
specializing in mergers and acquisitions and corporate finance. Mr. Epstein
joined the Belfer family in 1991 as Investment Counsel and assumed the founding
positions of Executive Vice President, General Counsel and Secretary of the
Company in April 1992. Mr. Epstein resigned from these positions in December
1992 but
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continues to serve as Senior Financial and Legal Advisor and General Counsel to
the Company. Mr. Epstein received an undergraduate degree from the University of
Chicago (B.A. 1978), a graduate degree in Politics and Economics from Oxford
University (M.A. Oxon 1981) and his law degree from Northwestern University of
Law (J.D. 1984).
Dominick J. Golio, age 52, is Vice President -- Finance, Chief Financial
Officer and Treasurer of the Company. 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 the
Company. 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 56, is Senior Vice President -- Engineering of the
Company. 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 the Company 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 44, is Senior Vice President -- Exploration of the
Company. Mr. Mueller began his career in 1975 as a Geological Engineer at
Tenneco Oil, Lafayette. He advanced at Tenneco Oil, Lafayette to Senior
Geological Engineer in 1979, Project Geological Engineer in 1980 and Division
Geological Engineer in the later part of 1980. Mr. Mueller relocated to San
Antonio, Texas in 1985 where he maintained the title of Division Geological
Engineer at Tenneco Oil but had the responsibility of reorganizing and then
supervising an 18 member geological engineering group. Mr. Mueller was then
promoted to Division Exploration Manager in 1987. In 1988, Mr. Mueller joined
Fina Oil in Houston, Texas as Exploration 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
the Company. Mr. Mueller has over 22 years experience in exploring for and
exploiting oil and gas fields both onshore and offshore and an expertise in 3-D
seismic, mapping, log analysis and risk management. He holds a BS in Geological
Engineering from the Colorado School of Mines (1975).
Mel Fife, age 47, is Vice President -- Business Development of the Company.
Mr. Fife began his career in 1979 as an Independent Landman working for various
companies. Mr. Fife joined Union Pacific Resources Company in 1988 and served as
a Landman until 1994. He joined the Company in November 1995 as Land Manager and
was promoted to Vice President -- Land in January 1997. Mr. Fife has 18 years of
extensive experience in all phases of land in the oil and gas industry. Mr. Fife
is a graduate of Dallas Christian College (1979) from which he received a
Bachelor of Science Degree and attended Emory University's Divinity Program
(1978-1979).
Gary Hampton, age 41, is Vice President -- Exploration -- Eastern Region of
the Company. Mr. Hampton began his career in 1978 as a Reservoir Geologist for
Texas Eastern (now PanEnergy). Mr. Hampton joined Champlin (currently UPR) in
1980 as a geologist and remained there until 1984. Mr. Hampton spent the next
two years with Clayton Williams Energy generating prospects and developing
acreage plays. In 1986, he became an independent consultant geologist providing
geological assessments to the energy and environmental industry. Mr. Hampton
rejoined Clayton Williams Energy in 1989 as the geologist responsible for, among
other programs, geological planning associated with the company's Austin Chalk
development program resulting in over 100 horizontal wells drilled in the Austin
Chalk, Buda and Georgetown formations. Mr. Hampton was named Exploration Manager
at Clayton Williams where he remained until February 1995, at which time he
joined the Company as Manager -- Geology. Mr. Hampton was promoted to
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Vice President -- Exploration in January 1996 and renamed Vice
President -- Exploration -- Eastern Division in October 1996. He received a B.S.
in Geology from the University of Southern Mississippi in 1978.
M. Bradford Moody, age 39, is Vice President -- Legal and Land. Mr. Moody
began his career in 1983 as an Associate with Akin, Gump, Strauss, Hauer & Feld
in Washington D.C., specializing in energy law. In 1988, he joined Pennzoil
Company as an Attorney, and later Senior Attorney, specializing in oil and gas
law. He remained at Pennzoil Company until 1996, at which time he joined the
Company as Senior Attorney. In August 1997, Mr. Moody was named Vice
President -- Legal and Land of the Company. Mr. Moody received his undergraduate
degree from Rice University (B.A. Economics 1980) and also attended Richmond
College in London, England (1978-79). He received his law degree from the
University of Texas School of Law (J.D. 1983).
George A. Sheffer, age 45, is Vice President -- Operations of the Company.
Mr. Sheffer began his career in 1974 at Chevron USA where he served in the
capacities of Reservoir Engineer, Drilling Representative and Production
Engineer. Mr. Sheffer went on to serve in various engineering management
positions with Meridian Oil and its predecessor Southland Royalty Company from
1979 to 1992. He joined the Company as Senior Petroleum Engineer in May 1994
after spending two years at Mearsk Energy, Inc. as Drilling Manager. He was
promoted to Vice President -- Operations at the Company in November 1994. Mr.
Sheffer has more than 20 years of diverse experience in all phases of petroleum
engineering and operations management in the domestic oil and gas industry. Mr.
Sheffer has specialized in horizontal drilling since 1987 in Oklahoma and Texas.
He has extensive experience in the entire Austin Chalk Trend from South Texas to
the Louisiana Border. Mr. Sheffer is a graduate of Pennsylvania State University
(1974) from which he received a degree in Petroleum and Natural Gas Engineering.
Jarl P. Johnson, age 67, is Vice Chairman and Chief Operating Officer of
Coda and has been active in the oil and natural gas industry since 1953. Mr.
Johnson worked for Phillips Petroleum from 1953 to 1955, and for Kewanee Oil Co.
from 1955 to 1978 where he served as Manager of Engineering for 14 years. He
worked for Hamilton Brothers Oil Company from 1978 to 1980 as Vice President of
Engineering. From 1980 to 1986 he was Vice President of Operations for Ensource
Inc. Mr. Johnson formed his own company, PetroJarl, Inc. in 1986 to own
non-operated oil and gas interests. He became President and a director of
Diamond Energy Operating Company ("Diamond") in October 1989. Mr. Johnson joined
Coda as Vice Chairman in 1994 in connection with Coda's acquisition of Diamond
and became Chief Operating Officer of Coda upon consummation of the merger with
JEDI in February 1996. Mr. Johnson obtained a degree in Petroleum Engineering
from the University of Tulsa in 1953.
Grant W. Henderson, age 39, is President and Chief Financial Officer of
Coda and 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 upon consummation of the merger with JEDI in February 1996.
Mr. Henderson was previously employed by NationsBank, 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.
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.
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.
43
44
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 the Company, and
The Bank of New York, a New York banking corporation (as
Trustee) amending the Indenture filed as Exhibit 4.2
above.
4.4 -- Exchange and Registration Rights Agreement dated
September 23, 1997 by and among the Company 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).
44
45
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
------- ----------------------
*4.7 -- Second Supplemental Indenture dated as of February 25,
1998 by and among the Company 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.
*4.8 -- Third Supplemental Indenture dated as of February 25,
1998 by and between the Company, 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).
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
the Company, 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 the Company, Belco Oil & Gas Corp., a Delaware
corporation, Robert A. Belfer and certain officers of the
Company (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).
45
46
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
------- ----------------------
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 -- Credit Agreement dated as of September 23, 1997 by and
among Belco Oil & Gas Corp., and The Chase Manhattan
Bank, as administrative agent, and certain financial
institutions named therein as Lenders (Incorporated by
reference to Exhibit 10.1 of Registration Statement on
Form S-4, Registration No. 333-37125)
10.15 -- First Amendment and Waiver, dated as of November 25, 1997
to (i) Credit Agreement dated as of September 23, 1997
among Belco Oil & Gas Corp. (the "Borrower"), the several
banks, financial institutions and other entities from
time to time parties to the Credit Agreement (the
"Lenders") and The Chase Manhattan Bank, as
administrative agent and (ii) the Pledge Agreement, dated
as of September 23, 1997 made by the Borrower and other
Pledgers (as defined in the Credit Agreement) in favor of
the Administrative Agent for the ratable benefit of
Lenders. (Incorporated by reference from Exhibit 99.4 to
the Company's Current Report on Form 8-K filed with the
Commission on November 26, 1997.)
*10.16 -- Second Amendment and Consent, dated as of February 25,
1998, to the Credit Agreement, dated as of September 23,
1997, among Belco Oil & Gas Corp. (the "Borrower"), the
several banks, financial institutions and other entities
from time to time parties to the Credit Agreement (the
"Lenders") and The Chase Manhattan Bank, as
administrative agent.
*21.1 -- Subsidiaries of the Registrant
*23.1 -- Consent of Arthur Andersen LLP
*23.2 -- Consent of Miller and Lents, Ltd.
*27 -- Financial Data Schedule.
- ---------------
* 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.
46
47
ITEM 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K -- (CONTINUED)
(b) Reports on Form 8-K.
Current Report on Form 8-K dated November 3, 1997
Item 5. Other Events
-- Announcement of Plan of Merger with Coda Energy, Inc.
Current Report on Form 8-K dated November 26, 1997
Item 2. Acquisition of Coda Energy, Inc.
Item 7. Financial Statements, Pro Forma Financial Information and Exhibits
(a) Financial Statements of Business Acquired.
Financial Statements to be filed by Amendment on Form 8K-A.*
(b) Pro Forma Financial Information
Financial Statements to be filed by Amendment on Form 8K-A.*
* Above Financial Statements filed on Form 8K-A dated January 28, 1998.
47
48
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: /s/ LAURENCE D. BELFER
-------------------------------------------------
Laurence D. Belfer
Date: March 20, 1998 President, Chief Operating Officer and Director
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
--------- ----- ----
/s/ ROBERT A. BELFER Chief Executive Officer and March 20, 1998
- ----------------------------------------------------- Chairman of the Board of
Robert A. Belfer Directors (Principal
Executive Officer)
/s/ LAURENCE D. BELFER President, Chief Operating March 20, 1998
- ----------------------------------------------------- Officer and Director
Laurence D. Belfer
/s/ DOMINICK J. GOLIO Vice President -- Finance, March 20, 1998
- ----------------------------------------------------- Chief Financial Officer and
Dominick J. Golio Treasurer (Principal
Financial Officer and
Principal Accounting Officer)
/s/ GRAHAM ALLISON Director March 20, 1998
- -----------------------------------------------------
Graham Allison
/s/ DANIEL C. ARNOLD Director March 20, 1998
- -----------------------------------------------------
Daniel C. Arnold
/s/ ALAN D. BERLIN Director March 20, 1998
- -----------------------------------------------------
Alan D. Berlin
/s/ JACK SALTZ Director March 20, 1998
- -----------------------------------------------------
Jack Saltz
/s/ GEORGIANA SHELDON-SHARP Director March 20, 1998
- -----------------------------------------------------
Georgiana Sheldon-Sharp
48
49
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, 1997 and
1996................................................... F-3
Consolidated Statements of Operations for the Years Ended
December 31, 1997,
1996 and 1995.......................................... F-4
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1997,
1996 and 1995.......................................... F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1997,
1996 and 1995.......................................... 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 the
Company's financial statements and related notes.
F-1
50
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, 1997 and
1996, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1997. 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 generally accepted auditing
standards. 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, 1997 and 1996, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1997, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 27, 1998
F-2
51
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
DECEMBER 31,
---------------------
1997 1996
--------- --------
(IN THOUSANDS)
CURRENT ASSETS:
Cash and cash equivalents................................. $ 12,260 $ 43,473
Accounts receivable (net)................................. 43,867 28,934
Assets from commodity price risk management activities.... 936 2,249
Advances to oil and gas operators......................... 346 69
Marketable equity securities.............................. 28,884 0
Other current assets...................................... 710 456
--------- --------
Total Current Assets.............................. 87,003 75,181
--------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties at cost based on full-cost
accounting --
Proved oil and gas properties............................. 793,475 237,150
Unproved oil and gas properties........................... 86,172 77,570
Less -- Accumulated depreciation, depletion and
amortization........................................... (282,750) (86,490)
--------- --------
Net oil and gas property.......................... 596,897 228,230
--------- --------
Building and other equipment, net......................... 6,877 47
--------- --------
OTHER ASSETS................................................ 6,332 460
--------- --------
Total Assets...................................... $ 697,109 $303,918
========= ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities.................. $ 33,651 $ 16,886
Liabilities from commodity price risk management
activities............................................. 9,555 7,220
Income taxes payable...................................... -- 2,408
Accrued interest.......................................... 7,040 --
--------- --------
Total Current Liabilities......................... 50,246 26,514
LONG-TERM DEBT.............................................. 352,090 --
DEFERRED INCOME TAXES....................................... 110,047 39,967
LIABILITIES FROM COMMODITY PRICE RISK MANAGEMENT
ACTIVITIES................................................ 78 4,234
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares
authorized; none issued or outstanding................. -- --
Common Stock, $0.01 par value; 120,000,000 shares
authorized; 31,584,400 and 31,577,300 issued and
outstanding at December 31, 1997 and 1996,
respectively........................................... 316 316
Additional paid-in capital................................ 196,864 186,703
Retained earnings (deficit)............................... (8,664) 48,244
Unearned compensation..................................... (1,093) (1,285)
Notes receivable for equity interest...................... (775) (775)
Unrealized loss on marketable equity securities........... (2,000) --
--------- --------
Total Stockholders' Equity........................ 184,648 233,203
--------- --------
Total Liabilities and Stockholders' Equity........ $ 697,109 $303,918
========= ========
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-3
52
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31,
----------------------------------------
1997 1996 1995
----------- ----------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
REVENUES:
Oil and gas sales......................................... $129,994 $119,710 $68,767
Commodity price risk management activities................ (6,479) (5,967) 9,480
Interest.................................................. 3,245 2,653 353
-------- -------- -------
Total revenues.................................... 126,760 116,396 78,600
-------- -------- -------
COSTS AND EXPENSES:
Oil and gas operating expenses............................ 12,758 7,847 5,824
Depreciation, depletion and amortization.................. 46,684 40,904 27,590
Impairment of oil and gas properties...................... 150,000 -- --
General and administrative................................ 3,913 3,059 2,597
Interest expense.......................................... 1,668 -- --
-------- -------- -------
Total costs and expenses.......................... 215,023 51,810 36,011
-------- -------- -------
INCOME (LOSS) BEFORE INCOME TAXES........................... (88,263) 64,586 42,589
-------- -------- -------
PROVISION (BENEFIT) FOR INCOME TAXES........................ (31,355) 46,404(a) --
-------- -------- -------
NET INCOME (LOSS)........................................... $(56,908) $ 18,182 $42,589
======== ======== =======
PRO FORMA NET INCOME (LOSS):
Income (loss) before income taxes......................... $(88,263) $ 64,586 $42,589
Pro forma provision (benefit) for income taxes............ (31,355) 21,953 13,852
-------- -------- -------
Pro forma net income (loss)....................... $(56,908) $ 42,633 $28,737
======== ======== =======
PRO FORMA NET INCOME (LOSS) PER COMMON SHARE
Basic..................................................... $ (1.80) $ 1.42 $ 1.15
======== ======== =======
Diluted................................................... $ (1.80) $ 1.42 $ 1.15
======== ======== =======
- ---------------
(a) 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.
See Note 1. Historical basic and diluted net income per share, including
the deferred tax charge, was $0.61 for the year ended December 31, 1996.
The pro forma amounts present the Company as if a taxable corporation for
all periods and are based on the average number of shares outstanding
during the period assuming the shares issued in connection with the
Combination were outstanding for all periods.
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-4
53
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
UNREALIZED
NOTES LOSS ON
COMMON STOCK ADDITIONAL RETAINED COMBINED RECEIVABLE MARKETABLE
--------------- PAID-IN UNEARNED EARNINGS PREDECESSOR FOR EQUITY EQUITY
SHARES AMOUNT CAPITAL COMPENSATION (DEFICIT) EQUITY INTEREST SECURITIES
------ ------ ---------- ------------ --------- ----------- ---------- ----------
BALANCE, DECEMBER 31,
1994...................... -- $ -- $ -- $ -- $ -- $ 90,016 $(126) $ --
------ ---- -------- ------- -------- -------- ----- -------
Contributions............... -- -- -- -- -- 4,512 -- --
Distributions............... -- -- -- -- -- (31,268) -- --
Issuance of employee notes
receivable................ -- -- -- -- -- -- (868) --
Repayment of employee notes
receivable................ -- -- -- -- -- -- 160 --
Income before income
taxes..................... -- -- -- -- -- 42,589 -- --
------ ---- -------- ------- -------- -------- ----- -------
BALANCE, DECEMBER 31,
1995...................... -- $ -- $ -- $ -- $ -- $105,849 $(834) $ --
------ ---- -------- ------- -------- -------- ----- -------
Exchange combination........ 25,000 250 72,142 -- -- (72,392) -- --
Public stock offering, net
of costs of $10.4
million................... 6,500 65 113,050 -- -- -- -- --
Restricted stock issued..... 77 1 1,511 (1,285) -- -- -- --
Repayment of employee notes
receivable................ -- -- -- -- -- -- 59 --
Distributions to predecessor
owners.................... -- -- -- -- -- (3,395) -- --
Net income(a)............... -- -- -- -- 48,244 (30,062) -- --
------ ---- -------- ------- -------- -------- ----- -------
BALANCE, DECEMBER 31,
1996...................... 31,577 $316 $186,703 $(1,285) $ 48,244 $ -- $(775) $ --
------ ---- -------- ------- -------- -------- ----- -------
Restricted stock issued..... 5 -- 123 192 -- -- -- --
Exercise of stock options... 2 -- 38 -- -- -- -- --
Issuance of warrants........ -- -- 10,000 -- -- -- -- --
Unrealized loss on
marketable equity
securities................ -- -- -- -- -- -- -- (2,000)
Net income (loss)........... -- -- -- -- (56,908) -- -- --
------ ---- -------- ------- -------- -------- ----- -------
BALANCE, DECEMBER 31,
1997...................... 31,584 $316 $196,864 $(1,093) $ (8,664) $ -- $(775) $(2,000)
------ ---- -------- ------- -------- -------- ----- -------
TOTAL
--------
BALANCE, DECEMBER 31,
1994...................... $ 89,890
--------
Contributions............... 4,512
Distributions............... (31,268)
Issuance of employee notes
receivable................ (868)
Repayment of employee notes
receivable................ 160
Income before income
taxes..................... 42,589
--------
BALANCE, DECEMBER 31,
1995...................... $105,015
--------
Exchange combination........ --
Public stock offering, net
of costs of $10.4
million................... 113,115
Restricted stock issued..... 227
Repayment of employee notes
receivable................ 59
Distributions to predecessor
owners.................... (3,395)
Net income(a)............... 18,182
--------
BALANCE, DECEMBER 31,
1996...................... $233,203
--------
Restricted stock issued..... 315
Exercise of stock options... 38
Issuance of warrants........ 10,000
Unrealized loss on
marketable equity
securities................ (2,000)
Net income (loss)........... (56,908)
--------
BALANCE, DECEMBER 31,
1997...................... $184,648
--------
- ---------------
(a) 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. See Note 1.
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-5
54
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
1997 1996 1995
-------- --------- --------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)(a).................................... $(56,908) $ 18,182 $ 42,589
Adjustments to reconcile net income (loss) to net
operating cash inflows --
Depreciation, depletion and amortization............. 46,684 40,904 27,590
Impairment of oil and gas properties................. 150,000 -- --
Deferred tax provision(a)............................ (31,536) 39,967 --
Amortization of restricted stock compensation........ 353 227 --
Commodity price risk management activities........... (1,248) 9,436 (570)
Changes in operating assets and liabilities --
Accounts receivable................................ 1,850 (11,955) (6,445)
Other current assets............................... (65) (286) --
Accounts payable and accrued liabilities........... (7,607) 11,584 (1,127)
-------- --------- --------
Net operating cash inflows...................... 101,523 108,059 62,037
-------- --------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures................ (140,975) (142,712) (71,387)
Proceeds from sale of oil and gas properties............ 13,949 -- --
Changes in accounts payable and accrued liabilities for
oil and gas expenditures............................. 11,726 (730) 5,243
Change in advances to oil and gas operators............. (277) (24) 1,566
Purchase of Coda Energy, Inc............................ (214,896) -- --
Purchase of marketable equity securities................ (30,884) -- --
Changes in other assets................................. (1,779) (360) (555)
-------- --------- --------
Net investing cash outflows..................... (363,136) (143,826) (65,133)
-------- --------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from initial public offering................... -- 113,115 --
Long-term borrowings.................................... 85,000 13,300 17,170
Net proceeds from issuance of subordinated notes........ 145,400 -- --
Long-term debt repayments............................... -- (35,300) (2,100)
Equity contributions.................................... -- -- 4,512
Equity distributions.................................... -- (13,490) (21,173)
Employee loans, net..................................... -- 59 (708)
-------- --------- --------
Net financing cash inflows (outflows)........... 230,400 77,684 (2,299)
-------- --------- --------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.......... (31,213) 41,917 (5,395)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.......... 43,473 1,556 6,951
-------- --------- --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD................ $ 12,260 $ 43,473 $ 1,556
======== ========= ========
- ---------------
(a) Prior to March 29, 1996, the earnings of the Company were not subject to
corporate income taxes as the Company, prior to the Combination, was a group
of non-taxpaying entities. See Note 1.
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-6
55
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- ORGANIZATION AND NATURE OF OPERATIONS
ORGANIZATION
Belco Oil & Gas Corp. 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 the Company 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 the stockholders of Belco Oil &
Gas Corp. 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 Oil & Gas Corp. and its subsidiaries and prior to March 29, 1996, the
combined predecessor entities, are referred to herein as "Belco" or the
"Company".
NATURE OF OPERATIONS
The Company is an independent energy company engaged in the exploration,
development and production of natural gas and oil. The Company operates in this
single industry segment, and all operations are presently conducted in the
United States. The Company'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 the Austin Chalk (Texas and
Louisiana).
Substantially all of the Company's production is sold under
market-sensitive contracts. The Company'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 the Company. 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, the Company has entered into hedging and
related price risk management transactions with respect to a significant amount
of its expected future production (See Note 7).
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements for the year ended December 31, 1997
include the accounts of the Company and its wholly-owned subsidiaries including
one month of Coda operations. The Company's interests in the Moxa Arch
investment programs (the 1992 Moxa Arch Drilling Program, the 1993 Moxa Arch
Drilling Program and the Moxa Arch 1992 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 the
Company's share of each program's assets, liabilities, revenues and expenses is
F-7
56
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
included in the appropriate accounts of the consolidated financial statements.
All material intercompany balances and transactions have been eliminated.
For 1995 and through March 1996, the combined accounts were prepared using
the historical costs and results of operations of the combined predecessor
entities as if such entities had always been combined.
PROPERTY AND EQUIPMENT
The Company 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. The Company capitalized $5,769,000, $3,065,000 and $1,181,000
of related internal costs during 1997, 1996 and 1995, 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 capitalization 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, discounted at a 10 percent interest rate, of
future net cash flows from proved reserves, based on current economic and
operating conditions (PV10). If capitalized costs exceed this limit, the excess
is charged to depreciation, depletion and amortization.
Based on the Company's year end 1997 estimated proved reserves, the Company
recorded in the fourth quarter ended December 31, 1997 a non-cash impairment of
oil and gas properties of approximately $150 million ($97.5 million after tax).
The impairment provision includes the effect of the non-cash $101 million
Statement of Financial Accounting Standards ("SFAS") No. 109 tax basis "gross
up" attributable to the acquisition of Coda on the Company's full cost pool at
December 31, 1997 and PV10 value of year end 1997 reserves, which were
significantly impacted by lower product prices when compared to year end 1996
prices.
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 two to 20 years.
MANAGEMENT FEES
The Company manages three investment programs, which were formed during
1992-1994 to acquire and develop interests in certain drilling prospects located
in the Moxa Arch trend Wyoming. The Company 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,
the Company earns an annual management fee of one percent of committed capital.
After elimination of management fees received from affiliated entities,
including predecessor owners, the Company earned management fees totaling
$297,000, $583,000 and $602,000 during 1997, 1996 and 1995, respectively. Such
management fees have been credited to oil and gas property costs.
F-8
57
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1997, 1996 and 1995, totaled $3,742,000,
$434,000 and $911,000, respectively.
ACCOUNTING FOR COMMODITY PRICE RISK MANAGEMENT ACTIVITIES
The Company periodically 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 the Company 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 the Company. Gains and losses related to qualifying hedges of
the Company'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 has not offset changes in actual oil and
gas prices.
Estimates of future cash flows applicable to oil and gas commodity hedges
are reflected in future cash flows from proved reserves in the supplemental oil
and gas disclosures, with such estimates based on prices in effect as of the
date of the reserve report (See Note 14).
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 gain or loss in the period of change.
GAS BALANCING/REVENUE RECOGNITION
The Company uses the sales method to account for natural gas imbalances.
Under the sales method, the Company recognizes revenues based on the amount of
gas sold to purchasers, which may differ from the amounts to which the Company
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 the Company exceeds its entitled share of remaining natural gas reserves. Gas
balancing obligations as of December 31, 1997 and 1996 were not significant.
Additionally, gas imbalances are generally reflected as adjustments to reported
gas reserves and future cash flows in the supplemental oil and gas disclosures.
INCOME TAXES
The Company 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.
The earnings for the year ended December 31, 1995 and the three months
ended March 29, 1996 were not subject to corporate income taxes as the Company
was a combination of nontaxpaying entities, including Subchapter S, limited
liability corporations, partnership and joint venture entities and individual
interest. Accordingly, earnings were directly taxable to the individual owners.
The pro forma provision for income tax is
F-9
58
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
an estimate of the Company's income taxes that would have been provided in
accordance with SFAS No. 109, if the Company were a taxable entity during the
periods presented (See Note 6).
STOCK-BASED COMPENSATION
The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board (APB) Opinion
No. 25, "Accounting for Stock Issued to Employees." Accordingly, the adoption of
SFAS No. 123, "Accounting for Stock-Based Compensation" in 1996 had no effect on
the Company's results of operations.
CASH EQUIVALENTS
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
PRO FORMA 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 the Company adopted at
year end 1997. Net income per share amounts for prior periods have been restated
to conform with the provisions of the new standard. Basic net income per common
share is computed by dividing income available to common shareholders by the
weighted average number of common shares outstanding for the periods. 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 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 7 and 14).
NOTE 3 -- ACQUISITION OF CODA ENERGY, INC.
On November 26, 1997, Belco completed the Merger (the "Merger") of its
subsidiary Belco Acquisition Sub, Inc., a Delaware corporation ("Belco Sub")
with and into Coda Energy, Inc., a Delaware corporation. The Merger was effected
pursuant to the terms of an Agreement and Plan of Merger, dated as of October
31, 1997, by and among Belco, Belco Sub and Coda. In connection with the Merger,
Belco paid $324 million, including $214 million in cash, assumption of $110
million in debt (face value), and the issuance of warrants to purchase 1,666,667
shares of common stock, par value $0.01 per share, of Belco (the "Belco Common
Stock") to the holders of the outstanding common stock, preferred stock and
options to purchase common stock of Coda. The warrants are exercisable for a
period of three years commencing on November 26, 1998 at an exercise price of
$27.50 per share. The warrant exercise price and the number of shares of Belco
Common Stock that may be issued pursuant to the exercise of the warrants will be
adjusted to prevent dilution in the event of stock splits, stock dividends and
certain other events affecting the capital structure of Belco.
The acquisition of Coda has been accounted for using the purchase method of
accounting and has been included in the financial statements of the Company
since the date of acquisition.
F-10
59
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The purchase price has been allocated to the assets purchased and the
liabilities assumed based upon the fair values on the date of acquisition as
follows (in thousands):
Value of proved and unproved oil and gas properties
acquired.................................................. $ 437,431
Value of building and other assets acquired................. 6,470
Working capital acquired, net............................... 5,534
Assumed deferred tax liability.............................. (101,616)
Long-term debt assumed...................................... (117,090)
Transaction costs and other................................. (5,833)
Issuance of warrants........................................ (10,000)
---------
Cash paid, net of cash acquired................... $ 214,896
=========
The following unaudited pro forma financial information shows the effect on
the Company's consolidated results of operations as if the acquisition of Coda
occurred on January 1, 1996. The pro forma data is based on numerous assumptions
and is not necessarily indicative of future results of operations.
FOR THE YEAR FOR THE YEAR
ENDED DECEMBER 31, 1997 ENDED DECEMBER 31, 1996
----------------------- -----------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA
----------- --------- ----------- ---------
(IN THOUSANDS, EXCEPT PER COMMON SHARE DATA)
(UNAUDITED)
Revenues................................. $126,760 $194,610 $116,396 $195,472
Pro forma net income (loss).............. (56,908) (70,612) 42,633 31,896
Net income (loss) per common share:
Basic.................................. (1.80) (2.23) 1.42 1.06
Diluted................................ (1.80) (2.23) 1.42 1.06
NOTE 4 -- LONG TERM DEBT
Long term debt consists of the following at December 31, 1997 and 1996 (in
thousands):
DECEMBER 31,
--------------------
1997 1996
-------- --------
Revolving credit facility due 2002.......................... $ 85,000 $ --
8 7/8% Senior Subordinated Notes due 2007................... 150,000 --
Coda 10 1/2% Senior Subordinated Notes due 2006, including
premium totaling approximately $7.1 million............... 117,090 --
-------- --------
Total Debt........................................ 352,090 --
Less: Current maturities.................................... -- --
-------- --------
Long term debt.............................................. $352,090 $ --
======== ========
In September, 1997 the Company entered into a new five-year $150 million
Credit Agreement dated September 23, 1997 (the "Credit Facility") with The Chase
Manhattan Bank, N.A., as administrative agent (the "Agent") and other lending
institutions (the "Banks"). The Credit Facility provides for an aggregate
principal amount of revolving loans of up to the lesser of $150 million or the
Borrowing Base (as defined) as in effect from time to time, which includes a
subfacility from the Agent for letters of credit of up to $25 million. The
Borrowing Base at December 31, 1997 was set at $105 million with $85 million
advanced to the Company at that date and was increased to $150 million on
February 27, 1998 concurrent with the consummation of the Permian Acquisition.
The borrowing base will be redetermined by the Agent and the Banks
semi-annually, determined solely at their discretion, predicated on the
Company's oil and gas reserve value. In addition, the
F-11
60
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company may request two additional redeterminations and the Banks may request
one additional redetermination per year.
Indebtedness of the Company under the Credit Facility is secured by a
pledge of the capital stock of each of the Company's material subsidiaries.
Covenants contained in the Credit Facility require the Company to maintain
minimum Interest Coverage Ratio (3:1), Current Ratio (1:1) and Leverage Ratio
(Indebtedness to EBITDA) not to exceed (3.5:1). The Company and its subsidiaries
may not incur any indebtedness other than indebtedness falling within the
enumerated exceptions contained in the Credit Facility. In addition, the
Company's various debt instruments contain certain restrictive covenants that,
among other things, limit the ability of the Company to pay dividends.
Indebtedness under the Credit Facility bears interest at a floating rate
based (at the Company's option) upon (i) the ABR (as defined below) with respect
to ABR Loans or (ii) the Eurodollar Rate for one, two, three or six months (or
nine or twelve months if available to the Banks) with respect to Eurodollar
Loans, plus the Applicable Margin. The ABR is the greater of (i) the Prime Rate,
(ii) the Base CD Rate plus 1% or (iii) the Federal Funds Effective Rate plus
0.50%. The Applicable Margin for Eurodollar Loans varies from 0.50% to 0.875%
depending on the Borrowing Base usage. Borrowing Base usage is determined by a
ratio of (i) outstanding Loans and letters of credit to (ii) the then effective
Borrowing Base. Interest on ABR Loans will be payable quarterly in arrears and
interest on Eurodollar Loans is payable on the last day of the interest period
therefor and, if longer than three months, at three month intervals.
The Company is 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 0.20% to 0.30% depending on the Borrowing Base usage.
In September 1997, the Company issued $150 million of 8 7/8% Senior
Subordinated Notes due 2007 (the "8 7/8% Notes"). 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, commencing on March 15, 1998. 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 the Company's option prior
to September 15, 2002. Thereafter, the 8 7/8% Notes will be subject to
redemption at the option of the Company, 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")) the Company 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 the Company and are
subordinated in right of payment to all existing and future senior debt (as
defined in the 8 7/8% Indenture) of the Company, 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 the Company
and rank senior in right of payment to all other subordinated indebtedness of
the Company.
As of December 31, 1997, Coda had outstanding $110 million of 10 1/2%
Senior Subordinated Notes due 2006. The debt assumed in the acquisition of Coda
was recorded at $117.1 million, including premium, reflecting the fair value at
the date of acquisition. The Coda 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 Coda, are subordinated in right
of payment to all Senior Debt (as defined in the Indenture governing the Coda
Notes) of Coda, and are senior in right of payment to all future subordinated
debt of Coda. The claims of the holders of the Coda Notes are subordinated to
Senior Debt.
The Coda 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
F-12
61
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 Coda and engage in
mergers and consolidations.
The Coda Notes are not redeemable by Coda prior to April 1, 2001. After
April 1, 2001, the Coda Notes will be subject to redemption at the option of
Coda, 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. In
addition, until March 12, 1999, up to $27.5 million in aggregate principal
amount of Notes are redeemable, at the option of the Company on any one or more
occasions from the net proceeds of an offering of common equity, at a price of
110.5% of the aggregate principal amount of the Coda Notes, together with
accrued and unpaid interest thereon to the date of the redemption; provided,
however, that at least $82.5 million in aggregate principal amount of Notes must
remain outstanding immediately after the occurrence of such redemption;
provided, further, that any such redemption shall occur within 75 days of the
date of the closing of such offering of common equity.
On February 25, 1998, the Company merged Coda into Belco and Belco assumed
the obligations under the Coda Indenture. Effective with the merger, the Coda
Notes became pari passu in right of payment with the 8 7/8% Notes.
In December 1997, the Company entered into two interest rate swap
agreements converting two fixed rate obligations to floating rate obligations.
The first agreement covers $100 million of 8.875% long-term debt (comparable to
the interest rate on the 8 7/8% Notes) and obligates the Company 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 8.875% through September 15, 2001 and at 10% from March 15,
2002 through September 15, 2007. The second agreement covers $110 million of
10.5% long-term debt (comparable to the interest rate on the Coda Notes) and
obligates the Company 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 10.5% through October 1, 1999 and
11.625% from April 1, 2000 through April 1, 2003.
NOTE 5 -- RELATED-PARTY TRANSACTIONS
The Company enters into a substantial portion of its Commodity Price Risk
Management Activities with Enron Capital & Trade Resources, a subsidiary of
Enron Corp. The Company's Chairman serves on the board of directors of Enron
Corp. These agreements were entered into in the ordinary course of business of
the Company and are on terms that the Company believes are no less favorable
than the terms of similar arrangements with third parties. Pursuant to the terms
of these agreements, (i) Belco has paid to ECT a net amount of $8,571,000 during
1997 and (ii) ECT has paid to the Company a net amount of approximately
$5,243,000 with respect to 1996 and (iii) ECT has paid to the Company a net
amount of approximately $5,370,000 with respect to 1995.
The Company's executive offices are leased from its Chairman and $250,000
was paid under such lease in 1997 and 1996. Lease expense for the Company's
executive offices for the period from inception through 1995 was paid by the
Chairman, with no reimbursement. The Company has recorded an office space and
service expense and a corresponding capital contribution of approximately
$250,000 for the year ended December 31, 1995, based on an estimated allocation
of space occupied. The Company's remaining commitment related to the office
space and service charge is $250,000 per year (adjusted for annual changes in
the CPI) through 1999. Management believes the fee compares favorably to the
terms which might have been available from a non-affiliated party.
Additionally, from inception through March 31, 1996, the Company's Chairman
did not draw any compensation from the Company. The Company has recorded salary
and benefits expense and a correspond-
F-13
62
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ing capital contribution of $150,000 for the period ended December 31, 1995
based on estimates of time devoted to the Company and using expected 1996
compensation. In 1996, the Chairman commenced receiving compensation.
Certain employees of the Company had an ownership interest in certain oil
and gas properties held by the Company as of December 31, 1995. The Company had
receivables of $775,000 as of December 31, 1997 and 1996, respectively, related
to amounts loaned to employees in connection with employee purchases of oil and
gas interests. Such receivables 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).
In 1995, the Company engaged Midway Partners LLC (Midway) to serve as
advisor in connection with certain financial matters of the Company, including
the Combination and the initial public offering of the Company's Common Stock.
The Company's Senior Financial and Legal Advisor and General Counsel was one of
two managing partners and principals of Midway. In connection with such
engagement, the Company has paid Midway an advisory fee of $50,000. In 1996,
upon consummation of the offering, the Company paid Midway an additional
$200,000.
Coda was acquired in November 1997 from Joint Energy Investment Development
Investments Limited Partnership ("JEDI") and certain members of Coda management.
The general partner of JEDI is an affiliate of Enron. In management's opinion,
the consideration paid and issued by the Company for Coda was determined in
arms' length negotiations among the Company, Coda and the stockholders of Coda
(including JEDI).
NOTE 6 -- INCOME TAXES
Prior to March 29, 1996, the earnings of the Company were not subject to
corporate income taxes as the Company, prior to the Combination, was a
combination of non-taxpaying entities, including Subchapter S, limited liability
corporations, partnership and joint venture entities and individual interests.
Accordingly, taxable earnings were directly taxable to the individual owners
through the date of the Combination. As a result of the Combination consummated
on March 29, 1996, the Company became a taxpaying entity and recorded, in the
first quarter of 1996, a $30.1 million one-time, non-cash charge to earnings to
establish a deferred tax liability (discussed further below). The historical
provision for income taxes for the year ended December 31, 1996 includes the
one-time charge. The pro forma provision for income taxes reflected in the
Consolidated Statements of Operations for the years ended December 31, 1996 and
1995 has been presented to reflect the Company's income taxes under the
assumption that the Company was a taxpaying entity since its inception.
Although the effective date of the Exchange Agreement is January 1, 1996,
each owner of the Combined Assets was required under existing federal income tax
rules and regulations to include in its taxable income, for all periods ended on
the date of or prior to the completion of the Combination (March 29, 1996), its
allocable portion of the taxable income attributable to the Combined Assets and
was entitled to all tax benefits related to the Combined Assets through the
completion of the Combination on March 29, 1996.
F-14
63
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Total provision (benefit) for income taxes consists of the following:
YEARS ENDED
DECEMBER 31
-------------------
1997 1996
-------- -------
(IN THOUSANDS)
Payable currently:
Federal................................................... $ (192) $ 6,345
State..................................................... 373 92
-------- -------
181 6,437
-------- -------
Deferred:................................................... (31,536) 39,967
-------- -------
Total provision (benefit) for income taxes:....... $(31,355) $46,404
======== =======
The differences between the statutory federal income taxes and the
Company's pro forma effective taxes is summarized as follows (in thousands):
YEARS ENDED DECEMBER 31,
------------------------------
1997 1996 1995
-------- ------- -------
Statutory federal income taxes....................... $(30,892) $22,605 $14,906
State income tax, net of federal benefit............. 242 80 115
Section 29 tax credits............................... (850) (947) (909)
Other................................................ 145 215 (260)
-------- ------- -------
Pro forma provision (benefit) for income taxes....... $(31,355) $21,953 $13,852
======== ======= =======
The principal components of the Company's net deferred income tax liability
are as follows (in thousands):
YEARS ENDED
DECEMBER 31,
-------------------
1997 1996
-------- -------
Deferred income tax assets
Commodity price risk management activities................ $ (822) $(1,494)
Net operating loss........................................ (4,798) --
Other..................................................... (5,235) (245)
-------- -------
$(10,855) $(1,739)
-------- -------
Deferred income tax liabilities
Depreciation, depletion and amortization.................. $116,257 $41,159
Other..................................................... 4,645 547
-------- -------
120,902 41,706
-------- -------
Net deferred income tax liability................. $110,047 $39,967
======== =======
As a result of the acquisition of Coda, the Company succeeded to net
operating loss carryforwards ("NOLs") for income tax purposes that expire from
1998 through 2004. Due to a change of ownership (as defined by the Tax Reform
Act of 1986) which occurred prior to the acquisition by the Company, the
utilization of the Coda NOLs is severely restricted. At December 31, 1997, the
Company estimates that approximately $13.7 million of the NOLs is available to
offset future income. In addition to the NOLs, the Company has approximately
$0.6 million of alternative minimum tax ("AMT") credit carryovers at December
31, 1997. AMT credits may be carried forward indefinitely.
F-15
64
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SECTION 29 TAX CREDIT
The natural gas production from wells drilled on certain of the Company'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 credit against
regular federal income tax liability with respect to sales of the Company'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 $1.03 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 $45 per Bbl in current dollars. The Company
estimates that it generated approximately $0.9 million of Section 29 Tax Credits
in 1997. 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 the Company's Section 29 Tax Credits will reduce its federal income
tax liability in any particular year. As production from qualified wells
decline, the production 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 June 16, 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 the
Company'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, 2002 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).
LOUISIANA SEVERANCE TAX ABATEMENT
A five-year exemption from severance tax applies to production from oil and
gas wells that are returned to service after having been inactive for two or
more years or having 30 days or less of production during the past two years. An
application must be made to the Louisiana Department of Natural Resources before
commencement of production during the period beginning July 31, 1994, and ending
June 30, 1998. Upon certification, the five-year exemption period begins from
the date of the application.
All severance tax is suspended for 24 months or until payout of the well
cost is achieved, whichever occurs first, on any horizontally drilled well or
recompletion well from which production commences after July 31, 1994. The term
"horizontal drilling" means high angle drilling of bore holes with 50 to 3,000
plus feet of lateral penetration through productive reservoirs, and "horizontal
recompletion" means horizontal drilling in an existing well bore.
F-16
65
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Production of natural gas, gas condensate, and oil from any well drilled to
a true vertical depth of more than 15,000 feet and where production starts after
July 31, 1994, is exempt from severance tax for 24 months or until payout of the
well cost, whichever occurs first. The exemption applies to production from any
depth in the wellbore.
Currently, the Louisiana severance tax rate on oil is 12.5% of gross value
and the severance tax on gas is 10.1 cents per MCF. Only one of the severance
tax exemptions discussed above may be taken on a particular well. The Company
anticipates that each of its current and future Louisiana wells will qualify for
one of the exemptions discussed above.
NOTE 7 -- COMMODITY PRICE RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF FINANCIAL
INSTRUMENTS
OIL AND GAS HEDGING TRANSACTIONS
With the objective of achieving more predictable revenues and cash flows
and reducing the exposure to fluctuations in gas and oil prices, the Company has
entered into hedging transactions of various kinds with respect to both gas and
oil. While the use of these hedging arrangements limits the downside risk of
adverse price movements, it may also limit future revenues from favorable price
movements. As of December 31, 1997, the Company had entered into hedging
transactions with respect to a significant portion of its estimated oil and gas
production for 1998, 1999 and 2000 and to a lesser extent its estimated
production for the year 2001. The Company continues to evaluate whether to enter
into additional hedging transactions for future years. In addition, the Company
may determine from time to time to terminate its then existing hedging positions
if market conditions warrant.
The following table and notes thereto cover the Company's pricing and
notional volumes on open natural gas and oil commodity hedges as of December 31,
1997:
PRODUCTION PERIODS
------------------------------------------
1998 1999 2000 2001 TOTAL
------ ------ ------ ------ ------
Gas --
Price swaps -- receive fixed price
(thousand MMBtu)(1)(6)............... 14,245 10,045 4,570 -- 28,860
Average price, per MMBtu............. $ 2.20 $ 2.20 $ 2.22 $ -- $ 2.20
Collars and options (thousand
MMBtu)(2)(7)......................... 22,920 13,980 10,670 3,650 51,220
Average floor price, per MMBtu....... $ 1.76 $ 1.80 $ 1.34 $ 1.25 $ 1.65
Average ceiling price, per MMBtu..... $ 2.27 $ 2.58 $ 2.60 $ 2.75 $ 2.46
Price swaps -- pay fixed price (thousand
MMBtu)(3)............................ 20,845 905 -- -- 21,750
Average price, per MMBtu............. $ 2.29 $ 2.24 $ -- $ -- $ 2.29
Basis swaps (thousand MMBtu)(4)(5)...... 24,055 6,395 5,490 -- 35,940
Average basis differential, per
MMBtu.............................. $ (.17) $ (.50) $ (.56) $ -- $ (.29)
Oil --
Price swaps -- receive fixed price
(MBbls)(1)(8)........................ 1,024 794 224 18 2,060
Average price, per Bbl............... $20.35 $20.44 $19.14 $18.54 $20.24
Collars and options (MBbls)(2).......... 1,274 1,058 106 -- 2,438
Average floor price, per Bbl......... $19.07 $19.22 $19.24 $ -- $19.14
Average ceiling price, per Bbl....... $21.45 $22.13 $22.24 $ -- $21.78
Secondary Floor MBbls................ 322 199 19 -- 540
Secondary Floor, per BBL............. $17.38 $16.87 $16.75 $ -- $17.17
F-17
66
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- ---------------
(1) For any particular swap transaction, the counterparty is required to make a
payment to the Company in the event that the NYMEX Reference Price for any
settlement period is less than the swap price for such hedge, and the
Company 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.
(2) For any particular collar transaction, the counterparty is required to make
a payment to the Company if the average NYMEX Reference Price for the
reference period is below the floor price for such transaction, and the
Company is required to make payment to the counterparty if the average NYMEX
Reference Price is above the ceiling price for such transaction.
(3) In order to close certain commodity price hedge positions, the Company
entered into various swap positions where the Company is the fixed-price
payer on the swap. In these transactions, the counterparty is required to
make a payment to the Company in the event that the NYMEX Reference Price
for any settlement period is greater than the swap price, and the Company is
required 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.
(4) Since most of the Company's gas is sold under spot contracts with reference
to Houston Ship Channel prices and substantially all of the Company's hedge
transactions are based on the NYMEX Reference Price, the Company has entered
into basis swaps that require the counterparty to make a payment to the
Company in the event that the average NYMEX Reference Price per MMBtu for a
reference period exceeds the average price per MMBtu for gas delivered at
the Houston Ship Channel for such reference period by a stated differential,
and requires the Company to make a payment to the counterparty in the event
that the NYMEX Reference Price exceeds the Houston Ship Channel price by
less than a stated differential (or in the event that the Houston Ship
Channel price exceeds the NYMEX Reference Price). The Company also sells 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 the Company 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 the Company to make a
payment to the counterparty in the event that the NYMEX Reference Price
exceeds the Northwest 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).
(5) Does not include 3,650 thousand MMBtu of basis swaps in 1999 that are
extendable at the election of the counterparty.
(6) Does not include 3,665, 724, 6,410, and 4,555 thousand MMBtu of swaps in
1998 through 2001, respectively, that are extendable at the election of the
counterparty, and does not include 7,320 and 10,950 thousand MMBtu of swaps
in 2000 and 2001, which price will be fixed upon the close of the NYMEX
Reference Price on a specified date less an average of $0.25.
(7) Does not include 1,825 thousand MMBtu of collars in 2000 that are extendable
at the election of the counterparty.
(8) Does not include 429, 1,291 and 1,085 thousand Bbls of swaps in 1999 through
2001, respectively that are extendable at the option of the counterparty.
All of the above transactions were carried out in the over-the-counter
market, and not on the NYMEX, with financial counterparties having at least an
investment grade credit rating. All of these transactions provide solely for
financial settlements related to closing prices on the NYMEX.
A realized hedging gain (loss) of $(5.4) million, $(0.1) million and $9.5
million for 1997, 1996 and 1995, respectively, was included in Commodity Price
Risk Management revenues. As of December 31, 1997, the Company had accrued
liabilities of $0.6 million for settled derivative contracts and as of December
31, 1996,
F-18
67
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
had accrued liabilities of $0.3 million for settled derivative contracts and net
deferred premium costs of $0.5 million, all relative to future periods. These
amounts are included in Price Risk Management activities as assets or
liabilities as appropriate.
NON-HEDGING TRANSACTIONS
As described in Note 2, the Company uses the mark-to-market method of
accounting for instruments that do not qualify for hedge accounting. The 1997
results of operations included an aggregate pre-tax loss of $1.1 million related
to these activities which included (1) net realized losses on settlements
totaling $8.1 million, (2) net premiums received totaling $5.0 million and (3)
the unrealized gain resulting from net change in the value of the Company's
market-to-market portfolio of price risk management activities for the year
ended December 31, 1997 of $2.0 million, all included in Commodity Price Risk
Management revenues. At December 31, 1997, the Company's consolidated balance
sheet reflects $1.9 million and $9.3 million of price risk management assets and
liabilities, respectively, which includes primarily the mark-to-market reserve.
The 1996 results of operations included an aggregate pre-tax loss of $5.9
million related to these activities which included (1) net realized losses on
settlements totaling $3.9 million, (2) net premiums received totaling $7.4
million and (3) the unrealized loss resulting from net change in the value of
the company's mark-to-market portfolio of price risk management activities for
the year ended December 31, 1996 of $9.4 million, all included in Commodity
Price Risk Management revenues. At December 31, 1996, the Company's consolidated
balance sheet reflects $1.8 million and $11.2 million of price risk management
assets and liabilities, respectively, which includes primarily the
mark-to-market reserve. The Company had not entered into any financial
instruments that did not qualify for hedge accounting prior to 1996.
The following table and notes thereto cover the Company's pricing and
notional volumes on open natural gas and oil financial instruments at December
31, 1997, that do not qualify for hedge accounting:
PRODUCTION PERIODS
------------------------------------
1998 1999 2000 TOTAL
------ ------ ------ ------
Gas --
Straddles (thousand MMBtu)(1)................. 5,025 -- -- 5,025
Average price, per MMBtu................... $ 2.26 $ -- $ -- $ 2.26
Calls bought (thousand MMBtu)(2).............. -- 1,510 5,480 6,990
Average price, per MMBtu................... $ -- $ 3.00 $ 2.75 $ 2.80
Calls Sold (thousand MMBtu)(2)................ 13,595 3,650 7,320 24,565
Average price, per MMBtu................... $ 2.51 $ 2.90 $ 2.78 $ 2.65
Puts Sold (thousand MMBtu)(2)................. 11,767 303 607 12,677
Average price, per MMBtu................... $ 2.15 $ 2.00 $ 2.00 $ 2.14
Price Swaps -- pay fixed price (thousand
MMBtu)(3).................................. 4,485 -- -- 4,485
Average price, per MMBtu................... $ 2.84 $ -- $ -- $ 2.84
Price Swaps -- receive fixed price (thousand
MMBtu)(5).................................. 450 9,125 -- 9,575
Average price, per MMBtu................... $ 2.55 $ 2.28 $ -- $ 2.29
F-19
68
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
PRODUCTION PERIODS
------------------------------------
1998 1999 2000 TOTAL
------ ------ ------ ------
Oil --
Straddles (MBbls)(1).......................... 100 -- -- 100
Average price, per Bbl..................... $20.00 $ -- $ -- $20.00
Price Swaps -- receive fixed price
(MBbls)(4)(6).............................. 269 31 -- 300
Average price, per Bbl..................... $20.40 $20.40 $ -- $20.40
Calls Bought (MBbls)(2)....................... 12 -- -- 12
Average price, per Bbl..................... $24.00 $ -- $ -- $24.00
Calls Sold (MBbls)(2)......................... 501 402 44 947
Average price, per Bbl..................... $22.28 $22.72 $23.90 $22.54
Puts Sold (MBbls)(2).......................... 221 180 19 420
Average price, per Bbl..................... $18.47 $18.00 $18.00 $18.25
Puts Bought (MBbls)(2)........................ 645 559 56 1,260
Average price, per Bbl..................... $18.50 $18.64 $18.67 $18.57
- ---------------
(1) A straddle is a combination of a put sold and a call sold. The Company 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 ceiling price
or less than the floor price. The Company receives a significant premium
upon entering into such contract.
(2) Calls sold or puts sold under written option contracts, in return for a
significant premium received by the Company upon initiation of the contract.
The Company 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 require the counterparty to make a payment to the
company in the event that the NYMEX Reference Price on any settlement period
is greater than the call price or less than the put price.
(3) Does not include 2,250 and 1,825 thousand MMbtu of accumulator reverse swaps
for 1998. The volumes associated with these reverse swaps double when the
reference price goes above the swap price, which is set at $2.44 and $2.23
per MMbtu, respectively. 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.
(4) For any particular swap transaction, the counterparty is required to make a
payment to the Company in the event that the NYMEX Reference Price for any
settlement period is less than the swap price for such instrument and the
Company 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. All of these swaps listed will double the volumes
swapped when the NYMEX Reference Price is above the swap price for such
instrument.
(5) On these trades, protection disappears in any month that the respective
NYMEX Reference Price is below $1.75 in 1998 or below $1.70 in 1999. Does
not include 3,650, and 3,650 thousand Mmbtu of swaps for 1999 and 2000,
respectively, which have tiered pricing at which the swap is canceled when
the NYMEX Reference Price falls below $1.80 per MMbtu and the swap volumes
double when the NYMEX Reference Price rises above $2.90 per MMbtu.
(6) Does not include 322, 360, 360 and 38 MBbls of oil swaps for 1998 through
2001, respectively, which have tiered pricing at which the swap is canceled
when the NYMEX Reference Price falls below $16.50 per Bbl as to 50% of the
volumes and $18.00 for the remaining volume and the volumes double when the
NYMEX Reference Price rises above $23.05 per Bbl as to 50% of the volumes
and above $22.85 for the remaining volume. 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.
F-20
69
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FAIR VALUE OF FINANCIAL INSTRUMENTS
The following table presents the carrying amounts and estimated fair values
of the Company's financial instruments at December 31, 1997 and 1996. 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, 1997 DECEMBER 31, 1996
------------------- ------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- -------- -------- -------
(IN THOUSANDS)
Cash and cash equivalents.................... $ 28,884 $ 28,884 $43,473 $43,473
Marketable equity securities................. 28,900 28,900 -- --
Long-term debt............................... 352,090 358,100 -- --
Interest rate swaps.......................... -- (3,579) -- --
Oil and gas commodity -- Hedges.............. (590) (1,942) 158 (8,555)
-- Non-hedges.......... (7,367) (7,367) (9,363) (9,363)
The following methods and assumptions were used to estimate the fair value
of the financial instruments summarized in the above table. The carrying values
of trade receivables and trade payables included in the accompanying
consolidated balance sheets approximated market value at December 31, 1997 and
1996.
CASH AND CASH EQUIVALENTS
The carrying amounts approximate fair value because of the short maturity
of those instruments.
MARKETABLE SECURITIES
In June 1997 the Company purchased 2,940,000 shares of common stock of
Hugoton Energy Corporation ("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. In the merger each share
of Hugoton common stock was converted into 1.3 shares of Chesapeake common
stock. As of March 24, 1998, the value of this investment was approximately
$25.1 million.
LONG-TERM DEBT
The fair value of the Company's revolving credit facility debt of $85
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 Coda
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 the Company 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 necessarily required in interpreting market data, and the use of
different market assumptions or estimation methodologies could result in
different estimates of fair value.
F-21
70
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 8 -- COMMITMENTS AND CONTINGENCIES
FUTURE CONTINGENCIES RELATED TO THE MOXA ARCH PROGRAMS
From 1992 to 1994, the Company 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. The Company offered
certain qualified investors (the Investors) the opportunity to invest in the
prospects through participation in the Programs. As of December 31, 1997, the
Programs have invested $122.0 million in connection with the development of the
Moxa Arch Trend of Southwest Wyoming. Through October 30, 1996, the Company
owned approximately 55.20 percent of the 1992 Moxa Arch Drilling Program, 32.45
percent of the 1993 Moxa Arch Drilling Program, and 58.21 percent of the Moxa
Arch 1992 Offset Drilling Program. On October 31, 1996 the Company 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 the
Company's natural gas wells in the Moxa Arch trend located in Lincoln,
Sweetwater and Uinta Counties, Wyoming. The Company 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"). After
the purchase, the Company'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, and 80.5% of the Moxa Arch 1992 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 in 1996 or 1997. The Company
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, the Company's interest). The Company'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 13, 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 the Company as of December 31, 1997.
LEASE COMMITMENTS
At December 31, 1997, the Company had operating leases covering office
space. Minimum rental commitments under such operating leases are as follows (in
thousands):
YEAR ENDING DECEMBER 31
- -----------------------
1998........................................................ $365
1999........................................................ 250
----
Total.................................................. $615
====
For the years ended December 31, 1997, 1996 and 1995, total rental expense
was approximately $438,000, $329,000 and $317,000, respectively.
F-22
71
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
LEGAL PROCEEDINGS
The Company is a named defendant in routine litigation incidental to its
business. While the ultimate results of these proceedings cannot be predicted
with certainty, the Company does not believe that the outcome of these matters
will have a material adverse effect on the Company.
ENVIRONMENTAL MATTERS
The Company'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. The Company believes its current operations are
in material compliance with current environmental laws and regulations. There
are no environmental claims pending or, to the Company's knowledge, threatened
against the Company. 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 the Company's properties.
NOTE 9 -- CASH FLOW INFORMATION
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
FOR YEAR ENDED DECEMBER 31,
-------------------------------
1997 1996 1995
------- ------ ------
Cash paid (received) during the year for (in
thousands):
Interest, net of amounts capitalized.............. $(3,447)(1) $ -- $ --
Income and other taxes, net of refunds............ $ 1,345 $4,000 $ --
- ---------------
(1) Includes capitalized interest in the amount of $(3.7) million and $307,000
in actual cash payments.
In November 1997, the company acquired Coda for cash, warrants and the
assumption of certain liabilities. See Note 3.
NOTE 10 -- CUSTOMER INFORMATION
CONCENTRATIONS OF CREDIT RISK
The Company'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 the Company's overall exposure. The Company has not experienced
significant credit losses on such sales.
MAJOR CUSTOMERS
Oil and gas sales for 1997 include $40.6 million, $27.9 million and $25.5
million in revenues received from three customers. Also, 1997 revenues included
net losses in the amount of $6.5 million related to Commodity Price Risk
Management Activities. Oil and gas sales for 1996 include $44.6 million, $37.7
million, $11.7 million in revenues received from three customers. Also, 1996
revenues include Commodity Price Risk Management net losses totaling $5.9
million. Oil and gas sales for 1995 include $7.9 million, $21.1 million, $17.2
million and $14.0 million in revenues received from four customers and Commodity
Price Risk Management gains of $9.5 million. No other customers individually
accounted for 10 percent or more of revenues.
F-23
72
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 11 -- EMPLOYEE BENEFIT PLANS
RETIREMENT PLAN
The Company adopted a 401(k) and savings plan for its employees on January
1, 1995. 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 of a participant's salary
deferral contributions that are not in excess of 6 percent of such participant's
compensation. The plan also permits the Company, 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 1997 and 1996, the Company incurred $99,000 and $62,000,
respectively, in connection with this plan.
PERFORMANCE UNIT PLAN
In 1996, Belco adopted a performance unit plan which is a long-term
incentive compensation plan to be administered by the Stock Option Committee of
the Board of Directors. All employees of the Company are eligible to receive an
award of performance units under the plan. A performance unit has a performance
period that is four consecutive calendar years beginning with and including the
calendar year in which the performance unit is granted. The value of a
performance unit will be determined based on the ranking of the Company's return
on Common Stock during an applicable performance period compared to the return
on the shares of Common Stock of certain companies with which the Company
competes; however, the maximum value is $2.00 per unit. While payments with
respect to performance units will normally be made at the end of the four-year
performance period, pro-rated payments may also be made at an earlier time in
the event a participant's employment with the Company is involuntarily
terminated without cause or is terminated by reason of retirement, death or
disability. Payments with respect to performance units will be made in a single
sum and may be made in cash, Common Stock or a combination thereof as the Stock
Option Committee in its sole discretion may determine. The Company granted
320,000 and 250,000 performance units during 1997 and 1996, respectively. As of
December 31,1997 the Company has made no cash payments in connection with this
plan.
F-24
73
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 12 -- CAPITAL STOCK
NET INCOME (LOSS) PER COMMON SHARE
A reconciliation of the components of basic and diluted net income (loss)
per common share for the years ended December 31, 1997, 1996 and 1995 is
presented in the table below (in thousands, except per share amounts):
YEARS ENDED DECEMBER 31,
------------------------------
1997 1996 1995
-------- ------- -------
Basic net income (loss) per share:
Pro forma net income (loss)........................ $(56,908) $42,633 $28,737
-------- ------- -------
Weighted average shares of common stock
outstanding(1)(4).................................. 31,538 29,986 25,000
-------- ------- -------
Basic net income (loss) per share:................... $ (1.80) $ 1.42 $ 1.15
======== ======= =======
Diluted net income (loss) per share:
Pro forma net income (loss)........................ $(56,908) $42,633 $28,737
-------- ------- -------
Weighted average shares of common stock
outstanding(1)(4).................................. 31,538 29,986 25,000
Effect of dilutive securities:
Restricted stock(2)(3)............................. -- 9 --
Warrants and stock options(2)(3)................... -- 44 --
-------- ------- -------
Average shares of common stock outstanding including
dilutive securities................................ 31,538 30,039 25,000
-------- ------- -------
Diluted net income (loss) per share.................. $ (1.80) $ 1.42 $ 1.15
======== ======= =======
- ---------------
(1) Includes shares issued and outstanding plus the restricted stock vested.
(2) Calculated using the treasury stock method, including unearned compensation
of restricted stock as proceeds.
(3) Amounts are not included in the computation of diluted net income (loss) per
share in 1997 because to do so would have been antidilutive.
(4) The computation assumes that the Company was incorporated during the periods
presented and presents the 25 million shares issued in connection with the
Combination as outstanding for all periods.
EXCHANGE AGREEMENT AND PUBLIC EQUITY OFFERING
On March 29, 1996, the Exchange Agreement was consummated resulting in the
issuance of 25,000,000 shares to the Predecessor Owners (See Note 1). In
addition, on March 29, 1996, the Company completed its initial public offering
issuing 6,500,000 shares at $19 per share. Net proceeds totaled $113.1 million
after offering costs of $10.4 million.
STOCK INCENTIVE PLANS
On March 25, 1996, the Company 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 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 of the stock at the date of grant. Options vest 20% per year
until fully vested five years from the date of grant.
F-25
74
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 the Company's plans (the Plans) as of December
31, 1997 and 1996 and the changes during the year then ended is presented below:
1997 1996
-------------------------- -------------------------
SHS. UNDER WTD. AVG. SHS. UNDER WTD. AVG.
OPTION EXER. PRICE OPTION EXER. PRICE
----------- ------------ ----------- -----------
Outstanding, beginning of year.......... 409,000 $ 20.91 -- $ --
Granted............................... 561,000 19.87 417,000 20.91
Exercised............................. -- -- -- --
Forfeited............................. (9,500) (19.00) (8,000) 20.09
--------- -------- --------- ------
Outstanding, end of year................ 960,500 $ 20.31 409,000 $20.91
========= ======== ========= ======
Exercisable, end of year................ 81,900 $ 21.12 -- $ --
========= ======== ========= ======
Available for grant, end of year........ 1,365,100 1,921,700
========= =========
Weighted average fair value of options
granted during the year............... $ 9.82 $ 12.73
========= =========
The following table summarizes information about stock options outstanding
at December 31, 1997.
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
-------------------------------------------------- -------------------------------
NUMBER WEIGHTED NUMBER
OUTSTANDING AT AVERAGE WEIGHTED EXERCISABLE AT WEIGHTED
DECEMBER 31, REMAINING AVERAGE DECEMBER 31, AVERAGE
RANGE OF PRICES 1997 CONTRACTUAL LIFE EXERCISE PRICE 1997 EXERCISE PRICE
- --------------- -------------- ---------------- -------------- -------------- --------------
$18.88-19.90 600,000 8.89 $18.95 61,500 $19.00
$20.13-23.97 269,500 9.65 20.93 -- --
$24.06-32.68 91,000 8.31 27.40 20,400 27.49
------- ------ ------ ------
960,500 20.31 81,900 $21.12
======= ====== ====== ======
As permitted by SFAS No. 123, the Company 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, the Company's pro forma net income (loss) and pro
forma earnings (loss) per share for calendar years 1997 and 1996 would have been
reduced to the pro forma amounts indicated below (in thousands, except for per
share amounts):
1997 1996
-------- -------
Pro Forma Net Income (Loss)
As Reported............................................... $(56,908) $42,633
Pro Forma................................................. (57,784) 42,117
Pro Forma Basic and Diluted Net Income (Loss) Per Share
As Reported............................................... $ (1.80) $ 1.42
Pro Forma................................................. $ (1.80) $ 1.40
F-26
75
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 1997 and 1996, respectively: risk-free interest rate of 6.35
and 6.74 percent, expected volatility of 46.63 and 31.0 percent, expected lives
of 5.7 and 7.5 years and no dividend yield.
Under the Stock Incentive Plan, participants may be granted stock without
cost (restricted stock). During 1997 and 1996, the Company granted 5,100 and
77,300 shares, respectively, of restricted stock with a weighted average fair
value based on the price of the Company's stock on the date of grant of $24.44
and $19.56 per share, respectively. At December 31, 1997, 66,740 shares remained
unvested, net of forfeitures. 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 1997 and 1996,
$192,000 and $227,000, respectively, was charged to expense relating to the
Plan.
NOTE 13 -- SUPPLEMENTAL QUARTERLY FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS):
QUARTERS
--------------------------------------
FIRST SECOND THIRD FOURTH
------- ------- ------- --------
(UNAUDITED)
1997
Revenues...................................... $31,659 $29,089 $23,645 $ 42,367
======= ======= ======= ========
Costs and Expenses............................ $13,433 $14,439 $13,450 $173,701
======= ======= ======= ========
Pro Forma Net Income (Loss)................... $11,984 $ 9,632 $ 6,703 $(85,243)
======= ======= ======= ========
Pro Forma Basic and Diluted Net Income (Loss)
Per Share................................... $ 0.38 $ 0.31 $ 0.21 $ (2.70)
======= ======= ======= ========
1996
Revenues...................................... $28,610 $31,555 $28,027 $ 28,204
======= ======= ======= ========
Costs and Expenses............................ $12,118 $12,837 $13,206 $ 13,649
======= ======= ======= ========
Pro Forma Net Income.......................... $11,066 $12,354 $ 9,782 $ 9,431
======= ======= ======= ========
Pro Forma Basic and Diluted Net Income Per
Share....................................... $ 0.44 $ 0.39 $ 0.31 $ 0.30
======= ======= ======= ========
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.
F-27
76
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 14 -- 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 the Company's
oil and gas production, exploration and development activities as of December
31, 1997 and 1996 (in thousands):
1997 1996
--------- --------
Proved properties........................................... $ 793,475 $237,150
Unproved properties......................................... 86,172 77,570
--------- --------
Total capitalized costs..................................... 879,647 314,720
Less -- Accumulated depreciation, depletion and
amortization.............................................. (282,750) (86,490)
--------- --------
Net capitalized costs....................................... $ 596,897 $228,230
========= ========
COSTS NOT BEING AMORTIZED
The following table sets forth a summary of unproved oil and gas property
costs not being amortized at December 31, 1997, by the year in which such costs
were incurred (in thousands):
1997 1996 1995 1994 1993 TOTAL
------- ------- ------ ------ ------ -------
Leasehold and seismic..... $52,734 $24,081 $2,866 $5,065 $1,426 $86,172
COSTS INCURRED
The following table sets forth the costs incurred in oil and gas
acquisition, exploration and development activities as of December 31, 1997,
1996 and 1995 (in thousands):
1997 1996 1995
--------- -------- -------
Property Acquisitions Costs --
Proved(1)........................................ $ 443,930 $ 9,871 $ --
Unproved......................................... 24,226 64,530 13,643
Exploration costs.................................. 46,939 17,444 2,382
Development costs.................................. 59,571 50,433 54,451
Capitalized interest............................... 3,742 434 911
Property sales..................................... (13,949) -- --
--------- -------- -------
Total costs incurred............................. $ 564,459 $142,712 $71,387
========= ======== =======
- ---------------
(1) Acquisition of proved properties includes $437.4 million relative to the
acquisition of Coda of which $50 million was allocated to unproved property
costs.
F-28
77
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth revenue and direct cost information relating
to the Company's oil and gas exploration and production activities as of
December 31, 1997, 1996 and 1995 (in thousands):
1997 1996 1995
-------- -------- -------
Oil and gas revenues (including commodity price risk
management activities)............................ $123,515 $113,743 $78,247
Costs and expenses --
Lease operating expenses.......................... 9,365 7,024 4,136
Production taxes.................................. 3,393 823 1,688
Impairment of oil and gas properties.............. 150,000 -- --
Depreciation, depletion and amortization.......... 46,684 40,904 27,590
-------- -------- -------
Results of operations from producing activities
before income taxes............................... (85,927) 64,992 44,833
Pro forma provision (benefit) for income taxes...... (30,537) 22,095 14,638
-------- -------- -------
Pro forma results of operations from producing
activities........................................ $(55,390) $ 42,897 $30,195
======== ======== =======
Amortization rate per Mcf equivalent, recurring..... $ .81 $ .73 $ .64
======== ======== =======
OIL AND GAS RESERVE INFORMATION
The following summarizes the policies used by the Company 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.
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 (without giving effect to hedging activities) as of December 31,
1997, 1996 and 1995 are based on estimates prepared by Miller & Lents,
independent petroleum engineers. Such estimates have been prepared in accordance
with guidelines established by the Securities and Exchange Commission (SEC).
Reserve estimates for periods prior to December 31, 1995 were not prepared by an
independent petroleum engineer. While reserve reports for years ended prior to
December 31, 1995 were not prepared contemporaneously, they have been prepared
by an in-house engineer on a basis generally consistent with the Miller & Lents
report. The Company used the December 31, 1995 Miller & Lents estimates as an
initial basis and adjusted such data for actual production and extensions,
discoveries and other additions in 1994 to determine the relevant data for each
of these periods. The Company also calculated the reserve economics at the end
of 1994 using oil and gas prices in effect as of the end of the year.
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 the
Company. 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.
F-29
78
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 the Company 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 the
Company'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.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES
(IN THOUSANDS)
DECEMBER 31,
------------------------------------
1997 1996 1995
---------- ---------- --------
Future cash inflows(2).................................. $1,569,976 $1,071,550 $427,213
Future production costs................................. (531,583) (253,159) (96,643)
Future development costs................................ (100,427) (71,061) (36,003)
---------- ---------- --------
Future net inflows before income taxes(2)............... 937,966 747,330 294,567
Discount at 10% annual rate............................. (427,562) (331,800) (88,058)
---------- ---------- --------
Discounted future net cash flows before income
taxes.............................................. 510,404 415,530 206,509
Pro forma discounted future income taxes(1)............. (84,196) (134,957) (58,000)
---------- ---------- --------
Standardized measure of discounted future net cash
flows................................................. $ 426,208 $ 280,573 $148,509
========== ========== ========
- ---------------
(1) The earnings of the Company were not subject to corporate income taxes prior
to March 29, 1996 as the Company was a combination of nontaxpaying entities.
Concurrent with the March 1996 Exchange Agreement (see Note 1), the Company
became a taxable corporation. The estimated pro forma income taxes as of
December 31, 1995, discounted at 10%, have been presented assuming the
Company was a taxable entity for all periods. In addition, the estimated
undiscounted future income taxes related to future net inflows were $146.4,
$245.9 and $83.0 million for the years 1997, 1996 and 1995, respectively.
(2) Oil and gas commodity hedges included in future cash inflows totaled $5.9
million, ($60.8) million and $7.6 million at December 31, 1997, 1996, and
1995, respectively, and such hedges included in discounted future net cash
flows before income taxes totaled $5.5 million, $(55.2) million and $7.2
million at December 31, 1997, 1996 and 1995, respectively.
F-30
79
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
(IN THOUSANDS)
1997 1996 1995
--------- --------- --------
BALANCE, BEGINNING OF YEAR............................... $ 280,573 $ 148,509 $ 80,785
Sales and transfers of oil and gas produced, net of
production costs....................................... (111,819) (111,780) (72,423)
Net change in sales price and production costs........... (216,169) 145,133 11,390
Extensions and discoveries............................... 65,741 153,920 104,549
Purchases of minerals in place........................... 312,148 7,843 --
Changes in estimated future development costs............ 32,222 24,618 8,655
Revisions in quantities.................................. (9,099) 50,309 --
Accretion of discount.................................... 41,553 20,651 10,979
Other, principally revisions in estimates of timing of
production............................................. (22,267) (81,673) 33,574
Change in income taxes................................... 53,325 (76,957) (29,000)
--------- --------- --------
BALANCE, END OF YEAR..................................... $ 426,208 $ 280,573 $148,509
========= ========= ========
RESERVE QUANTITY INFORMATION
PROVED RESERVES
OIL GAS
------- -------
(MBBLS) (MMCF)
Balance at December 31, 1994................................ 1,929 114,655
Purchases of minerals in place............................ -- --
Extensions, discoveries and other additions............... 1,484 126,562
Revisions of previous estimates........................... -- --
Sales of minerals in place................................ -- --
Production................................................ (961) (37,047)
------ -------
Balance at December 31, 1995................................ 2,452 204,170
Purchases of minerals in place............................ 162 21,993
Extensions, discoveries and other additions............... 1,411 87,319
Revisions of previous estimates........................... 96 22,799
Sales of minerals in place................................ -- --
Production................................................ (794) (51,289)
------ -------
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)
Sales of minerals in place................................ -- --
Production................................................ (1,295) (49,710)
------ -------
Balance at December 31, 1997................................ 51,160 297,185
====== =======
PROVED DEVELOPED RESERVES
December 31, 1994........................................... 1,793 100,113
December 31, 1995........................................... 1,838 140,725
December 31, 1996........................................... 2,070 184,904
December 31, 1997........................................... 41,255 226,071
F-31
80
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 15 -- EVENTS (UNAUDITED) SUBSEQUENT TO DATE OF AUDITORS' REPORT
On February 27, 1998, Belco acquired properties in the Permian Basin of
west Texas from EnerVest Texoma Acquisition L.P. for $37.5 million in cash. The
acquisition was funded with advances under the Company's Credit Facility.
On March 10, 1998 the Company completed the closing and sale of 4,370,000
shares at $25 per share ($109.3 million) of 6 1/2% Convertible Preferred Stock
in an underwritten public offering. Each share of Convertible Preferred Stock
can be converted into Belco Common Stock at an initial conversion rate of 1.1292
shares of Common Stock for each share of Convertible Preferred Stock, equivalent
to a conversion price of $22.14 per share of Common Stock. The net proceeds of
the offering in the amount of $105.1 million were used to reduce bank
indebtedness.
F-32
81
INDEX TO EXHIBITS
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 the Company, and
The Bank of New York, a New York banking corporation (as
Trustee) amending the Indenture filed as Exhibit 4.2
above.
4.4 -- Exchange and Registration Rights Agreement dated
September 23, 1997 by and among the Company 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 the Company 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.
*4.8 -- Third Supplemental Indenture dated as of February 25,
1998 by and between the Company, 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).
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).
82
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
the Company, 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 the Company, Belco Oil & Gas Corp., a Delaware
corporation, Robert A. Belfer and certain officers of the
Company (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 -- Credit Agreement dated as of September 23, 1997 by and
among Belco Oil & Gas Corp., and The Chase Manhattan
Bank, as administrative agent, and certain financial
institutions named therein as Lenders (Incorporated by
reference to Exhibit 10.1 of Registration Statement on
Form S-4, Registration No. 333-37125)
83
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
------- ----------------------
10.15 -- First Amendment and Waiver, dated as of November 25, 1997
to (i) Credit Agreement dated as of September 23, 1997
among Belco Oil & Gas Corp. (the "Borrower"), the several
banks, financial institutions and other entities from
time to time parties to the Credit Agreement (the
"Lenders") and The Chase Manhattan Bank, as
administrative agent and (ii) the Pledge Agreement, dated
as of September 23, 1997 made by the Borrower and other
Pledgers (as defined in the Credit Agreement) in favor of
the Administrative Agent for the ratable benefit of
Lenders. (Incorporated by reference from Exhibit 99.4 to
the Company's Current Report on Form 8-K filed with the
Commission on November 26, 1997.)
*10.16 -- Second Amendment and Consent, dated as of February 25,
1998, to the Credit Agreement, dated as of September 23,
1997, among Belco Oil & Gas Corp. (the "Borrower"), the
several banks, financial institutions and other entities
from time to time parties to the Credit Agreement (the
"Lenders") and The Chase Manhattan Bank, as
administrative agent.
*21.1 -- Subsidiaries of the Registrant
*23.1 -- Consent of Arthur Andersen LLP
*23.2 -- Consent of Miller and Lents, Ltd.
*27 -- Financial Data Schedule.
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* 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.