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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
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COMMISSION FILE NUMBER 1-14256
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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 New York Stock Exchange
per share
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 15, 1999, was approximately $44.6
million (based on a value of $5.9375 per share, the closing price of the Common
Stock as quoted by the New York Stock Exchange on such date) 31,786,600 shares
of Common Stock, par value $.01 per share, were outstanding on March 15, 1999.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1999 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 BUSINESS.................................................... 2
1 --
Overview.................................................... 2
Recent Developments......................................... 2
Primary Operating Areas..................................... 3
Costs Incurred and Drilling Results......................... 8
Acreage..................................................... 9
Productive Well Summary..................................... 10
Marketing................................................... 10
Production Sales Contracts.................................. 11
Price Risk Management Transactions.......................... 11
Texas Severance Tax Abatement............................... 13
Section 29 Tax Credit....................................... 13
Other Tax Relief............................................ 13
Regulation.................................................. 13
Operating Hazards and Insurance............................. 14
Title to Properties......................................... 15
Employees................................................... 15
Office and Equipment........................................ 15
Forward-Looking Information and Risk Factors................ 16
Executive Officers of the Registrant........................ 22
Certain Definitions......................................... 24
ITEM PROPERTIES.................................................. 26
2 --
Oil and Gas Reserves........................................ 26
ITEM LEGAL PROCEEDINGS........................................... 26
3 --
ITEM SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 26
4 --
PART II
ITEM MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
5 -- STOCKHOLDER MATTERS......................................... 27
ITEM SELECTED FINANCIAL DATA..................................... 28
6 --
ITEM MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
7 -- AND RESULTS OF OPERATIONS................................... 29
Overview.................................................... 29
Results of Operations -- 1998 Compared to 1997.............. 30
Results of Operations -- 1997 Compared to 1996.............. 31
Liquidity and Capital Resources............................. 32
Other....................................................... 36
ITEM QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
7A -- RISK........................................................ 37
ITEM CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.... 38
8 --
ITEM CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
9 -- AND FINANCIAL DISCLOSURE.................................... 38
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PART III
ITEM DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 38
10 --
ITEM EXECUTIVE COMPENSATION...................................... 38
11 --
ITEM SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
12 -- MANAGEMENT.................................................. 39
ITEM CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 39
13 --
PART IV
ITEM EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM
14 -- 8-K......................................................... 39
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BELCO OIL & GAS CORP.
PART I
ITEM 1 -- BUSINESS
OVERVIEW
Belco Oil & Gas Corp. and its subsidiaries ("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 in the United
States 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 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 attempts to structure its participation in
natural gas and oil exploration and development activities to minimize initial
costs and risks, while permitting substantial follow-on investment.
The Company has achieved substantial growth in reserves, production,
revenues and EBITDA (Earnings Before Interest, Taxes, Depreciation, Depletion
and Amortization and other non-cash charges) since 1992. Belco's estimated
proved reserves have increased at a compound annual growth rate of 44%, from 67
Bcfe as of December 31, 1992 to 604 Bcfe as of December 31, 1998 with a reserve
life index of approximately 10 years based on 1998 production. Average daily
production has increased from 4 MMcfe per day in 1992 to approximately 171 MMcfe
per day in 1998. Similarly, the growth in the Company's EBITDA has been
substantial, increasing from $2.9 million for the year ended December 31, 1992,
to $104.7 million for the year ended December 31, 1998. The Company's low cost
structure is evidenced by its general and administrative expenses of $0.08 per
Mcfe and lease operating expenses of $0.66 per Mcfe in 1998.
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, 1998, the Company had estimated proved reserves of
604 Bcfe with a pre-tax PV10 value of $356.3 million (exclusive of a $4.3
million increase related to price risk management activities). The PV10 values
were derived using substantially lower oil and gas prices as required by SEC
rules when compared to the prices used at year-end 1997. As of December 31,
1998, Belco held or controlled approximately 1.9 million gross (822,000 net)
undeveloped acres and had an interest in approximately 2,755 gross (1,769 net)
oil and gas wells of which Belco operated 1,998.
The Company's Permian Basin and Mid-Continent activities concentrate 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. The Company has conducted or intends to conduct
significant secondary recovery/infill drilling programs on many of the
properties within these two core areas. Secondary recovery projects have been
the primary development focus in these areas over the past five 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. The
Company has considerable experience with and actively employs waterflood
techniques in many of its fields in order to stimulate production.
Certain terms relating to the oil and gas industry are defined in
"-- Certain Definitions" below.
RECENT DEVELOPMENTS
In November 1997, the Company completed the acquisition of Coda Energy,
Inc. ("Coda"), a Delaware corporation whose assets were concentrated in the
Permian Basin of west Texas and the Mid-Continent region
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of Oklahoma and north Texas. 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 "10 1/2% Notes") originally
issued by Coda. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity and Capital Resources." Immediately after
such merger, the Company contributed all of Coda's assets and liabilities,
except for the 10 1/2% Notes, into its wholly owned Nevada corporation Belco
Energy Corp. The Company also restructured its operations creating a Northern
Division, a Southern Division and a Western Division.
In February 1998, the Company acquired additional properties in its Permian
Basin core area for $37.3 million (the "Permian Acquisition"). The properties
consisted of approximately 65 Bcfe of estimated proved reserves at a cost of
approximately $0.59 per Mcfe.
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."
In June 1998, the Company purchased, through its wholly owned Canadian
subsidiary, approximately $10.5 million of 5% Convertible Preferred Shares of
Big Bear Exploration Ltd., a Canadian oil and gas company ("Big Bear"), at a
cost of approximately $0.85 per share with each such share convertible into one
common share of Big Bear. The Company was also issued approximately $120 million
of Special Acquisition Warrants at a price of approximately $0.72 per warrant.
In November 1998, the Company entered into an agreement to cancel the Special
Acquisition Warrants and to convert the 5% Convertible Preferred Shares into
21,428,571 shares of Big Bear common stock at an effective conversion price of
$0.50 per share. On January 22, 1999 the Company consummated this agreement. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."
Effective August 1, 1998, Diamond Energy Operating Company and Belco
Operating Corp., both wholly owned subsidiaries of Belco, were merged into Belco
Energy Corp., a wholly owned subsidiary of Belco.
Effective November 1, 1998, the Company acquired approximately 20 Bcfe (81%
natural gas) of long-lived reserves on producing properties in Oklahoma and
Kansas, as well as certain undeveloped acreage and 3-D seismic data for $14.8
million.
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, primarily in Texas. In addition to
these core areas, the Company conducts operations in the onshore Gulf Coast
region and in several other minor areas.
The following table sets forth information, as of December 31, 1998, with
respect to the Company's estimated net proved reserves by operating area.
Approximately 83% of the quantities of proved reserves aggregating 92% of the
pre-tax present value were estimated by the independent petroleum engineers
Miller and Lents, Ltd. ("Miller & Lents"). See "Forward Looking Information and
Risk Factors" below and "Properties."
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PROVED RESERVES
PERCENT
GAS OF
OIL GAS EQUIVALENT PROVED
(MBBLS) (MMCF)(1) (MMCFE) RESERVES
------- --------- ---------- --------
Rocky Mountains...................................... 652 114,130 118,044 20%
Permian Basin........................................ 32,906 32,363 229,796 38%
Mid-Continent........................................ 18,442 52,405 163,059 27%
Austin Chalk......................................... 1,043 81,053 87,314 14%
Other Areas.......................................... 11 5,582 5,647 1%
------ ------- ------- ---
Total...................................... 53,054 285,533 603,860 100%
====== ======= ======= ===
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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, 1998, the Company controlled approximately 894,916 gross
(283,623 net) undeveloped acres in these three basins.
Moxa Arch Trend. One of the Company's primary operating areas is the Moxa
Arch Trend located in the Green River Basin in southwestern Wyoming, principally
in Lincoln, Sweetwater and Uinta Counties. Approximately 19% of the Company's
estimated proved reserves at December 31, 1998 were located in this trend. 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 1998, the Company had participated in 221 gross (69 net) wells in
this field with 157 Frontier wells, 15 Dakota wells and 49 dual completions
(both Frontier and Dakota completed in the same well bore). Average net
production for the year ended December 31, 1998, was approximately 25.4 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." The Company drilled 13 wells (7 net) in 1998 and anticipates
drilling another 12 wells in 1999. 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 after spending 50% of the committed amount. At December 31, 1998, the
Company had spent approximately $10 million of its $20 million commitment with
operations conducted 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 has
acquired a 50% interest in approximately 87,321 net acres in the Wind River
Basin of Wyoming and 110,859 net acres in the Big Horn Basin of Wyoming. Under
such agreements, SOCO is the operator. The initial well on the Company's Wind
River
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acreage, the Tribal #46, was completed in August 1997 and was producing 1.1 MMcf
per day gross on December 31, 1998. Four offset wells were drilled to the Tribal
#46 in 1998 and two of the offsets were producing in the aggregate,
approximately 2.4 MMcf per day gross in December 1998. The initial well in the
Big Horn Basin, the Otto 16-4, was put on production in 1998 and was producing
at a rate of 400 Mcfe per day as of December 31, 1998. One successful offset
well to the Otto 16-4 has already been drilled in early 1999 and the Company
currently anticipates drilling 4 additional offset wells in 1999.
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. Based on interpretation of purchased 2-D
seismic, the Company currently plans to drill two wells in 1999.
The Company expects to participate in a series of exploratory wells in
these basins over the next 12 to 24 months with UPR, SOCO, Tom Brown and Yates
serving as operators for most wells. The 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.
Permian Basin
Approximately 38% of the Company's estimated proved reserves at December
31, 1998 were located in the Company's Permian Basin core area. These reserves
are concentrated in five properties: the Andrews Unit, the Roundtop Unit, the
Powell lease, the Shafter Lake San Andres Unit and the Nolley Wolfcamp 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. Most of the
properties that produce from these horizons are under secondary recovery, and,
based on analogous properties nearby, are potentially responsive to CO(2)
miscible flooding. Given the existence of nearby 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 produced
approximately 2,630 gross BOPD in Andrews County, and realized significant
advantages as a result of its large scale operation. The Company owns two
electrical distribution systems and three 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 in acquiring additional operated properties in Andrews
County.
The Company's largest (by value) Permian Basin units are the Andrews Unit,
the Roundtop Unit, the Powell lease and the Shafter Lake San Andres 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 some response occurring in
late 1998. The Company anticipates additional response in 1999. Gross production
in December 1998 was approximately 660 BOPD with injection of over 3,000 barrels
of water per day. During 1998, the Company drilled one infill well which
produced 102 BOPD in December 1998. The Company anticipates expanding its
waterflood operations during 1999 by converting five wells to injection. The
Company also believes that production from this waterflood unit can be enhanced
with the use of CO(2) or surfactants.
Roundtop Unit. The Company owns a 61.6% working interest in this 4,559 acre
unit in Fisher County, Texas. This Company operated secondary recovery unit
produces from the Palo Pinto formation at approximately 4,700 feet. The Company
became operator of this unit in March 1998. Gross oil production was
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approximately 490 BOPD in December 1998. The unit was originally waterflooded
with success on a peripheral injection pattern prior to changing to a five spot
pattern. The Company began the process of returning the unit to a peripheral
flood pattern in 1998. The Company plans to continue reconfiguring the injection
pattern during 1999.
Powell Lease. The Powell lease is a 1,360 acre tract in Crockett County,
Texas that produces from the Strawn and Ellenburger formations at 8,100 feet.
The Company became the operator of this lease in March 1998 and owns a 50%
working interest. Gross production in December 1998 was approximately 185 BOPD
and 1,420 Mcf/d. During 1998, the Company drilled one well which produced
approximately 80 BOPD and 500 Mcf/d in December 1998. The Company plans to drill
three wells during 1999.
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 averaged 950 BOPD in 1998.
The Company has drilled 42 infill 20 acre locations since becoming operator of
the unit in early 1993. In 1998, the Company drilled 10 infill wells and
anticipates continuing to develop this waterflood during 1999 by drilling an
additional 10 infill wells. In addition, the Company believes a large part of
this field has potential for 10 acre infill wells as well as CO(2) potential.
Recent Acquisition. In February 1998, the Company acquired additional
properties in its Permian Basin core area for $37.3 million. The properties
contained approximately 65 Bcfe of estimated proved reserves at a cost of
approximately $0.59 per Mcfe to Belco. See "-- Recent Developments."
Mid-Continent Region
The Company's Mid-Continent operations are currently focused in Oklahoma,
north Texas and Kansas, where approximately 27% of its total estimated proved
reserves at December 31, 1998 were located.
Oklahoma. Six waterfloods collectively represent a majority of the
Company's proved reserves in the region. These waterfloods are identified as the
Oakdale Unit, the Calumet Unit, the Witcher Unit, the Crooked Creek Unit, the
Cutter South Unit and the Rush Springs 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 1,250 BOPD in December 1998. The
Company drilled 4 wells during 1998. Plans for 1999 include drilling infill
production wells and fracture stimulating certain current producing wells.
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 1998 was approximately 2,100 BOPD. The Company has a 44.1% working
interest in this unit. 1999 plans include drilling several infill and
re-entry wells and converting two wells to water 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 1998 gross
production was approximately 530 BOPD.
North Texas. The north Texas region stretches from the Chadbourne Ranch
Field in Coke County in the west to several individual leases in Grayson County
in the east. The Katz, Electra and Burkburnett Fields represent the properties
of the most significant value in the north Texas region. The Company has drilled
289 wells in these fields. In addition to the Company's extensive inventory of
oil and gas opportunities in the north Texas region, the Company owns three
electrical distribution systems and has extensive field facilities.
Katz Field. The Katz Field consists of five secondary recovery leases
located in King and Knox Counties, Texas. The Company became the operator
in March 1998 and has a 100% working interest in
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these leases. Production is from two Strawn sands at approximately 4,800
feet and 5,100 feet. Gross oil production was approximately 370 BOPD in
December 1998. During 1998, the Company drilled three wells producing 50
BOPD total. In addition, the Company began reactivating the waterflood in
the zone at 4,800 feet with response occurring in late 1998. The Company
anticipates continuing reactivation of the waterflood by activating three
shut-in injectors and five shut-in producers during 1999.
Electra Area. The Electra area produces from shallow Cisco sand at a
depth of 150 to 2,100 feet. The Company operates 22 leases in this area
with 233 active oil producing wells and 121 active water 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 1998 was
approximately 1,400 BOPD. In 1998 the Company drilled 16 producing wells
and plans to drill an addition 7 wells in 1999.
Burkburnett Area. The Burkburnett area produces from the Gunsight Sand
formation at a depth of 1,750 feet. The Company operates 12 leases in this
area with 159 active oil producing wells and 116 active water injectors.
The Company's working interest is 100% in all leases. Gross production for
December 1998 was approximately 525 BOPD and the Company currently plans to
drill six wells in 1999.
Recent Acquisition. Effective November 1, 1998, the Company acquired
approximately 20 Bcfe (81% natural gas) of long-lived reserves on producing
properties in Oklahoma and Kansas, as well as certain undeveloped acreage and
3-D seismic data for $14.8 million. See "-- Recent Developments."
Austin Chalk Trend
Texas -- Giddings Field. Approximately 14% of the Company's estimated total
proved reserves at December 31, 1998 were located in the Giddings Field of east
central Texas, principally in Grimes, Washington and Fayette Counties. The
Giddings Field has been and still 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 formation, a fractured carbonate formation that has
been highly conducive to the application of horizontal drilling technology. The
Austin Chalk formation is encountered in this field at depths ranging between
approximately 7,000 and 17,000 feet.
The Company first acquired interests in the Giddings Field in September
1992. During the year ended December 31, 1998, average net production from this
field was approximately 60.2 MMcfe per day. Through December 31, 1998, the
Company had drilled 256 gross (84 net) wells in this field and continues to
control approximately 242,000 gross (85,000 net) 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 in
Washington County; and (iii) River Bend, primarily in Fayette County. The
Company expects to drill new wells, including infill wells, and re-enter older
wells to drill additional laterals in the Giddings Field. Currently, a majority
of the Company's interests in this field are held pursuant to agreements with
and are operated by Chesapeake Energy Corporation ("CHK") 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 formation or deep wells by the Texas Railroad Commission. Wells spud
between May 1989 and September 1996 are exempt from the 7.5% state severance tax
on high cost natural gas through August 2001. See "-- Texas Severance Tax
Abatement."
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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. At December 31, 1998, the Company owned or had the right to acquire
approximately 217,363 net acres in this trend but, as previously reported, low
oil prices prompted the postponement by the Company of substantially all oil
prone Gulf Coast drilling, including drilling in the Louisiana extension of the
Austin Chalk.
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
expected to jointly conduct a series of 3-D seismic programs 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 and Yegua
formations 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, 1998, Belco and Edge had acquired
seismic options on approximately 11,749 gross acres. As of December 31, 1998,
the Company had a 50% working interest in twenty-five (25) productive Frio and
Yegua wells (out of thirty-six (36) wells drilled). The Company participated in
17 Frio and 3 Yegua wells, respectively, in 1998. The Company anticipates
concluding its drilling program in this area in 1999 with an additional 6 wells.
HLM Project. The Company has obtained 3-D seismic on approximately 140
square miles located mainly in Montgomery and Liberty Counties. This seismic is
currently being interpreted with target objectives in the Frio, Yegua and Wilcox
formations. The Company anticipates drilling up to 10 wells in this prospect
area in 1999.
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 an interest in acreage in the Central Basin of Michigan with
the Company serving as operator. At December 31, 1998, the Company held or
controlled interests in a total of approximately 106,299 gross and 17,841 net
acres in this basin. As of year end 1998, the Company's drilling program in this
basin has had limited success and the remaining prospects are currently being
evaluated.
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. The table includes results
for Coda since November 26, 1997, the date Coda was acquired by the Company.
YEAR ENDED DECEMBER 31,
------------------------------------------
1998(1)(2) 1997 1996
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
Development:
Productive......................................... 69.0 47.1 54.0 23.1 64.0 23.0
Non-productive..................................... 1.0 1.0 4.0 2.2 2.0 0.8
---- ---- ---- ---- ---- ----
Total...................................... 70.0 48.1 58.0 25.3 66.0 23.8
==== ==== ==== ==== ==== ====
Exploratory:
Productive......................................... 23.0 9.4 20.0 13.7 10.0 7.9
Non-productive..................................... 7.0 4.0 18.0 6.4 3.0 2.4
---- ---- ---- ---- ---- ----
Total...................................... 30.0 13.4 38.0 20.1 13.0 10.3
==== ==== ==== ==== ==== ====
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- ---------------
(1) Includes 7 gross (4 net) wells in progress at December 31, 1998.
(2) Excludes 343 gross (175 net) productive wells acquired during 1998.
Volumes, revenue, prices and production costs
The following table sets forth certain information regarding the production
volumes, revenue, average prices received (prior to any commodity price risk
management activities) 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,
------------------------------
1998 1997 1996
-------- -------- --------
Net Production Data:
Oil (MBbl)................................................ 4,177 1,295 794
Gas (MMcf)................................................ 37,208 49,710 51,289
Gas equivalent (MMcfe).................................... 62,272 57,479 56,053
Oil and Gas Sales ($ in 000's)(1)........................... $124,199 $129,994 $119,710
Average Sales Price (Unhedged):
Oil ($ per Bbl)........................................... $ 13.17 $ 19.28 $ 21.30
Gas ($ per Mcf)........................................... $ 1.86 $ 2.11 $ 2.00
Costs ($ per Mcfe):
Oil and gas operating expenses............................ $ 0.66 $ 0.22 $ 0.14
General and administrative................................ $ 0.08 $ 0.07 $ 0.06
Depreciation, depletion and amortization of oil and gas
properties............................................. $ 0.90 $ 0.81 $ 0.73
- ---------------
(1) Oil and gas sales exclude results related to commodity price risk management
activities reported separately.
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, the date Coda was acquired by the Company.
YEAR ENDED DECEMBER 31,
--------------------------------
($'S IN THOUSANDS)
1998 1997 1996
-------- -------- --------
Property acquisitions costs --
Proved................................................... $ 56,695 $443,930(1) $ 9,871
Unproved................................................. 14,414 24,226 64,530
Exploration costs.......................................... 18,597 46,939 17,444
Development costs.......................................... 37,969 59,571 50,433
Capitalized interest....................................... 5,123 3,742 434
Property Sales............................................. (6,292) (13,949) --
-------- -------- --------
Total net costs incurred......................... $126,506 $564,459 $142,712
======== ======== ========
- ---------------
(1) Acquisition of proved properties includes $437.4 million (inclusive of
$101.6 million of deferred taxes related to the difference between the book
and tax basis of assets acquired) relative to the acquisition of Coda.
ACREAGE
The following table sets forth, as of December 31, 1998, 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
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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.................................. 5,123 480 455,654 113,856
Moxa Arch Trend.................................... 25,180 15,037 31,650 17,709
Wind River Basin................................... 1,280 321 309,403 107,747
Big Horn Basin..................................... 643 321 129,859 62,020
Denver-Julesburg Basin............................. 207,365 2,298 231,865 130,524
Permian Basin........................................ 97,871 49,497 20 20
Mid-Continent Region:
Oklahoma........................................... 118,250 39,132 30,525 10,902
North Texas........................................ 36,593 21,777 640 320
Kansas............................................. 37,489 31,488 8,563 8,000
Austin Chalk Trend:
Texas-Giddings Field............................... 99,672 38,608 241,989 84,552
Louisiana.......................................... 11,208 2,643 282,681 217,363
Other Operating Areas:
Michigan-Central Basin............................. 1,632 525 106,299 17,841
Gulf Coast......................................... 2,642 1,453 74,574 50,980
------- ------- --------- -------
Totals..................................... 644,948 203,580 1,903,722 821,834
======= ======= ========= =======
- ---------------
(1) Leases covering approximately half of the undeveloped acreage will expire
within the next three 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.
PRODUCTIVE WELL SUMMARY
The following table sets forth the Company's ownership in productive wells
at December 31, 1998. Gross oil and gas wells include multiple completions.
Wells with multiple completions are counted only once for purposes of the
following table. Production from various formations in wells without multiple
completions is commingled.
PRODUCTIVE WELLS
-----------------
GROSS NET
------- -------
Gas......................................................... 747 333
Oil......................................................... 2,008 1,436
----- -----
Total............................................. 2,755 1,769
===== =====
MARKETING
There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and gas, the
proximity and capacity of natural gas pipelines and other transportation
facilities, demand for oil and gas, the marketing of competitive fuels and the
effects of state and federal regulations on oil and gas production and sales.
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
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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 gas is the
Northwest Pipeline Rocky Mountain Index, plus $0.03 per MMBtu, less fuel charges
and gathering fees and adjustments for Btu content. The Amoco Gas Contract was
renewed effective January 1, 1999 for an additional three year period on the
same terms.
All of the Company's current Moxa Arch Wyoming oil and condensate
production is sold at market sensitive prices pursuant to an option held by
Amoco.
The Company's Moxa Arch wells are subject to various gathering agreements
with third parties. Wells drilled under the Amoco Farmout Agreement in the
Wilson Ranch, Seven Mile Gulch and Bruff areas are subject to the Gas Gathering
and Processing Agreement dated March 20, 1992 with Northwest Pipeline. Gathering
fees under this agreement are currently $0.0762 per MMBtu and fuel charges are
0.5%. Gathering fees and fuel charges in the Cow Hollow/Shute Creek areas are
$0.1386.
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 price per MMBtu the
Company receives for its gas at the wellhead is tied to indexes published in
Inside FERC or Gas Daily, and in most cases is subject to a discount to the
relevant index in lieu of a gathering fee.
All of 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 1998 were made to Aquila Southwest Pipeline (14%) and Amoco Gas Trading
Corp. (11%).
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 1997 and 1998 and with respect to a
substantial portion of its estimated production for 1999 through 2000 and with
respect to lesser portions thereafter. The Company continues to evaluate whether
to enter into additional such transactions for 1999 and future years. In
addition, the Company may determine from time to time to terminate its then
existing hedging and other risk management positions.
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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"). These financial counterparties all have at least an investment grade
credit rating. All of these transactions provide solely for financial
settlements relating to closing prices on the NYMEX.
The following is a summary of the types of price risk management
transactions in effect as of December 31, 1998.
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 will receive
a sufficiently high cash premium (or other consideration) for granting the
counterparty a call or put option, it may enter into such a transaction. If the
Company sold a $16.00 call on oil for $0.40 a barrel in a given month and prices
averaged $15.00 a barrel for such month, the Company would receive a net
realization per barrel of $15.40 ($15.00 plus the $0.40 premium). However, if
for that month the price of oil averaged $16.00 per barrel, the Company would
receive a net realization of $16.40 (the call price, $16.00, plus $0.40). The
Company regards this as a 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 and any sold options are required to be marked to market as to their
value on the last day of the accounting period.
Basis Swaps. Since a substantial portion of the Company's natural gas is
sold under spot contracts with reference to East Texas hub 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 gas
delivered at the Houston Ship Channel (the most liquid East Texas hub) 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 sells Wyoming natural gas at prices based on
the Northwest Pipeline Rocky Mountain Index ("NPRMI") and the Colorado
Interstate Gas Co. -- Rocky Mountain Index ("CIGCo. -- RMI") (indices of prices
for gas delivered at various delivery points on the Northwest Pipeline and the
CIGCo. pipeline in the Northern Rocky Mountain area). For natural gas sold
against these indices, 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 gas delivered to the Northwest
Pipeline in the Rocky
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Mountains as reflected in the NPRMI (the most liquid Rocky Mountain hub) 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 NPRMI gas by less than the
stated differential (or in the event that the NPRMI price exceeds the Henry Hub
price).
TEXAS SEVERANCE TAX ABATEMENT
Production from natural gas wells that have been certified as tight
formations or deep wells by the Texas Railroad Commission ("high cost gas
wells") and that were spudded or completed during the period from May 24, 1989
to September 1, 1996 qualify for an exemption from the 7.5% severance tax in
Texas on natural gas and natural gas liquids produced by such wells prior to
August 31, 2001. The natural gas production from wells drilled on certain of 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.
SECTION 29 TAX CREDIT
The natural gas production from wells drilled on certain of the Company's
properties in the Wyoming Moxa Arch Trend and Golden Trend Field in Oklahoma
qualifies for the Section 29 Tax Credit. The Section 29 Tax Credit is an income
tax credit against regular federal income tax liability with respect to sales of
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 ($0.59
per Mcf) of natural gas produced from tight sand reservoirs and approximately
$1.05 per MMbtu of natural gas produced from Devonian Shale, is computed by
reference to the price of crude oil and is phased out as the price of oil
exceeds $23.50 per Bbl in 1979 dollars (as adjusted for inflation) with complete
phaseout if such price exceeds $29.50 per Bbl in 1979 dollars (as adjusted for
inflation). Under this formula, the commencement of phaseout would be triggered
if the average price for crude oil rose above approximately $48 per Bbl in
current dollars. The Company generated approximately $0.7 and $0.9 million of
Section 29 Tax Credits in 1998 and 1997, respectively. The Section 29 Tax Credit
may not be credited against the alternative minimum tax, but under certain
circumstances may be carried over and applied against regular tax liability in
future years. Therefore, no assurances can be given that the Company's Section
29 Tax Credits will reduce its federal income tax liability in any particular
year.
OTHER TAX RELIEF
Currently, Louisiana, Texas and Oklahoma are considering tax relief
addressing persistent low oil and gas prices. Legislation related to the
proposed relief is not final and as a result the Company cannot evaluate the
potential impact.
REGULATION
General. The oil and gas industry is extensively regulated by federal,
state and local authorities. In particular, oil and gas production operations
and economics are affected by price controls, environmental protection statutes
and regulations, tax statutes and other laws relating to the petroleum industry,
as well as changes in such laws, changing administrative regulations and the
interpretations and application of such laws, rules and regulations. Oil and gas
industry legislation and agency regulation are under constant review for
amendment and expansion for a variety of political, economic and other reasons.
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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 may
be drilled and the unitization or pooling of oil and gas properties. In this
regard, some states (such as Oklahoma) allow the forced pooling or integration
of tracts to facilitate exploration while other states (such as Texas) rely on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units and, therefore, more difficult to develop a
project if the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. The effect of these regulations may
limit the amount of oil and gas 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. In addition to permits required from other agencies (such as the
Army Corps of Engineers and the Environmental Protection Agency (the "EPA")),
lessees must obtain a permit from the MMS prior to the commencement of drilling.
The MMS also has regulations restricting the flaring or venting of natural gas,
liquid hydrocarbons and oil without prior authorization. The MMS generally
requires that lessees post substantial bonds or other acceptable assurances that
such obligations will be met. The cost of such bonds or other surety can be
substantial and there is no assurance that bonds or other surety can be obtained
in all cases. Under certain circumstances, the MMS may require Company
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially and adversely affect the Company's financial
condition and operations.
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. Such
regulation has increased the cost of planning, designing, drilling, 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.
The risks of substantial costs and liabilities associated with such compliance
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 and more comprehensive environmental laws and regulations as well as
claims for damages to property or persons resulting from the Company's
operations could result in substantial costs and liabilities to the Company. The
Company believes that it is in substantial compliance with existing
environmental regulations, and that any noncompliance will not have a material
adverse effect on operations or earnings.
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
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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, certain 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.
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, as well as to liens for current taxes not
yet due and to other encumbrances. As is customary in the industry in the case
of undeveloped properties, little investigation of record title is made at the
time of acquisition of leasehold interests (other than a preliminary review of
local records). Investigations, including a title opinion of local counsel, are
generally made before commencement of drilling operations. To the extent title
opinions or other investigations reflect title defects, 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, 1998, the Company had 189 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 prorated 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. See
"Certain Relationships and Related Transactions." The Company owns a building in
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Dallas, Texas, containing approximately 65,000 square feet which serves as the
operations headquarters. 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, 2001. 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 of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements
other than statements of historical facts included in this document (including
the information incorporated by reference herein), including without limitation
statements regarding planned capital expenditures, the availability of capital
resources to fund capital expenditures, estimates of proved reserves, the number
of anticipated wells to be drilled in 1999 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, 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 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. Recent declines in oil and natural gas prices have
reduced the amount of the Company's oil and natural gas that can be produced
economically, and may adversely affect the Company's financial condition,
liquidity and results of operations. 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 pursuant to contracts based on
market indexes 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
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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 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 23% of the Company's total proved reserves at December 31,
1998 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 or
decreases in production, 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
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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."
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 proved 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 proved 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 will be
required to record a ceiling limitation writedown. See "-- Volatility of Oil and
Natural Gas Prices; Marketability of Production." For the year 1998 the Company
recorded approximately $229 million ($149 million after-tax) of non-cash ceiling
test provisions after applying substantially lower commodity prices to estimated
recoverable reserves. At year-end 1997, the Company recorded a non-cash
writedown of approximately $150 million ($97.5 million after tax), a significant
portion of which was attributable to the 1997 acquisition of Coda and lower year
end reserve values due to lower year end oil and gas 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 expects to continue to make, substantial
expenditures for the development, exploration, acquisition and production of oil
and natural gas reserves. The Company incurred capital expenditures of $141.0
million during 1997 and $133.0 million during 1998. The Company has budgeted $50
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to $55 million, exclusive of potential acquisitions, for capital expenditures
for producing properties and leasehold acquisitions and drilling operations in
1999. Management believes that the Company will have sufficient cash provided by
operating activities and borrowings under its credit facility to fund capital
expenditures in 1999. 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 current drilling plans, or it may be
forced to raise additional debt or equity proceeds to fund such expenditures in
the future. 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. There can be no assurance that additional debt or
equity financing or cash generated by operations will be available to meet all
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 consummated
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 the Company's 10 1/2% Senior Subordinated Notes due 2006
(the "10 1/2% 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 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 10 1/2% 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 $50 million 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 million 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
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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 10 1/2% Indenture permits the Company to pay cash dividends of up
to $5 million in the aggregate and would restrict additional dividends to 50% of
the Company's cumulative consolidated net income (as defined in the 10 1/2%
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 10 1/2% Indenture.
The Company believes that it will have capacity beyond the $5 million dividend
limit under the 10 1/2% Indenture. The 10 1/2% 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 10 1/2% 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 10 1/2% 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. 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, certain 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.
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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 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 Vice Chairman 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
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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 15% 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.
EXECUTIVE OFFICERS OF THE REGISTRANT
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 63, 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
ReCorporation. 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 32, is Vice-Chairman 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, was named President in April 1997 and Vice-Chairman in
March, 1999. He is a founder and Chairman of Harvest Management, Inc., a money
management firm. Mr. Belfer graduated from Harvard University (B.A. 1988) and
from Columbia Law School (J.D. 1992).
Grant W. Henderson, age 40, is President of the Company. He was named
President effective March 1, 1999 and prior to his promotion he served as Senior
Vice President-Corporate Development. Mr. Henderson was formerly President and
Chief Financial Officer of Coda 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.
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Dominick J. Golio, age 53, is Senior Vice President -- Finance, Chief
Financial Officer, Treasurer and Secretary 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 57, 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 46, is Senior Vice President -- Exploration and
Production of the Company. Mr. Mueller began his career in 1975 as a Geological
Engineer at Tenneco Oil, Lafayette. He advanced at Tenneco Oil to Division
Exploration Manager in 1987. In 1988, Mr. Mueller joined Fina Oil in Houston,
Texas as Exploration 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 23 years experience in exploring for and exploiting oil and gas
fields both onshore and offshore. He holds a BS in Geological Engineering from
the Colorado School of Mines (1975).
Gary Hampton, age 43, is Vice President -- Exploration 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 Vice
President -- Exploration in January 1996. He received a B.S. in Geology from the
University of Southern Mississippi in 1978.
George A. Sheffer, age 46, is Vice President -- Operations -- Western
Division 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. 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.
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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.
Infill well. A well drilled between known producing wells to better exploit
the reservoir.
Liquids. Crude oil, condensate and natural gas liquids.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
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.
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MMBOE. One million barrels of oil equivalent.
MMbtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells, as the case may be.
Oil. Crude oil and condensate.
Operating cash inflows per Mcfe. Net operating cash inflows as listed in
the Consolidated Statements of Cash Flows in the Consolidated Financial
Statements divided by net gas equivalent production for the applicable periods.
Present Value or PV10. When used with respect to oil and natural gas
reserves, the estimated future gross revenue to be generated from the production
of proved reserves, net of estimated production and future development costs,
using prices and costs in effect as of the date indicated, without giving effect
to non-property related expenses such as general and administrative expenses,
debt service and future income tax expenses or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed nonproducing reserves. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
Updip. A higher point in the reservoir.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and to a share
of production.
Workover. Operations on a producing well to restore or increase production.
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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, 1998. Information
in this 10-K as of December 31, 1998 relating to properties with 83% of the
Company's estimated net proved oil and gas reserves (92% of the PV10) and the
estimated future net revenues attributable thereto is based upon the Miller and
Lents, Ltd. Report, 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, 1998
--------------------------------
PROVED PROVED
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ------
Estimated Proved Reserves:
Gas (Bcf)................................................. 213.4 72.1 285.5
Oil (MMBbls).............................................. 41.5 11.6 53.1
Total Gas Equivalents (Bcfe)................................ 462.3 141.6 603.9
Estimated Future Net Revenue before Income Taxes (in
millions)(1).............................................. $604.8 $102.1 $706.9
Present Value of Estimated Future Net Revenues before Income
Taxes (discounted at 10% per annum) (in millions)(1)...... $317.9 $ 38.4 $356.3
- ---------------
(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
1998 prices, which were $2.20 per Mcf of gas and $10.85 per barrel of oil
without giving effect to commodities price risk management activities
accounted for as hedges. At December 31, 1998, the estimated future net
revenue before income taxes and the present value of such estimated future
net revenue before income taxes related to such price risk management
activities were $4.6 million and $4.3 million, respectively (based on oil
and gas prices in effect at December 31, 1998), 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 $609.4 million (Proved Developed)
and $711.5 million (Total) and present values of such estimated future net
revenues before income taxes would equal $322.5 million (Proved Developed)
and $360.6 million (Total).
See also "Business."
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, 1998, 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 15, 1999, the Company estimates there were approximately 142
record 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
15, 1999, the Company had 31,786,600 shares outstanding and its closing price on
the NYSE was $5.9375 per share. The high and low sales prices for the Company's
Common Stock during each quarter in the two years ended December 31, 1998 were
as follows:
COMMON STOCK
HIGH LOW
-------- -------
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
1998
First Quarter............................................. 19.00 16.75
Second Quarter............................................ 17.75 8.125
Third Quarter............................................. 11.25 6.625
Fourth Quarter............................................ 6.875 4.375
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 10 1/2% Indenture restrict the Company's ability to declare or pay cash
dividends on its Common Stock. See "Forward-Looking Information and Risk
Factors -- Restrictions Upon Ability to Pay Dividends". 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,
-------------------------------------------------------
1998 1997 1996 1995 1994
--------- --------- --------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales.................. $ 124,200 $ 129,994 $ 119,710 $ 68,767 $ 40,362
Commodity Price Risk Management
Activities...................... 24,800 (6,479) (5,967) 9,480 550
Interest........................... 1,730 3,245 2,653 353 195
--------- --------- --------- -------- --------
Total revenues....................... 150,730 126,760 116,396 78,600 41,107
--------- --------- --------- -------- --------
Costs and expenses:
Oil and gas operating expenses..... 40,847 12,758 7,847 5,824 5,510
Depreciation, depletion and
amortization.................... 56,102 46,684 40,904 27,590 14,072
Impairment of oil and gas
properties...................... 229,000 150,000
Impairment on equity securities.... 24,216 -- -- -- --
General and administrative......... 5,216 3,913 3,059 2,597 2,269
Interest Expense................... 21,013 1,668 -- -- --
--------- --------- --------- -------- --------
Total costs and expenses............. 376,394 215,023 51,810 36,011 21,851
--------- --------- --------- -------- --------
Income (loss) before income taxes.... (225,664) (88,263) 64,586 42,589 19,256
Provision (benefit) for income
taxes(1)........................... (78,107) (31,355) 21,953 13,852 5,030
--------- --------- --------- -------- --------
Net income (loss)(1)................. $(147,557) $ (56,908) $ 42,633 $ 28,737 $ 14,226
========= ========= ========= ======== ========
Net income available to common
stock.............................. $(152,963) $ (56,908) $ 42,633 $ 28,737 $ 14,226
========= ========= ========= ======== ========
Basic and diluted earnings (loss) per
common share(1).................... $ (4.85) $ (1.80) $ 1.42 $ 1.15 $ .57
========= ========= ========= ======== ========
Weighted average common shares
outstanding(2)..................... 31,529 31,538 29,986 25,000 25,000
STATEMENT OF CASH FLOWS DATA:
Income before income taxes,
depreciation, depletion and
amortization and other non-cash
items(3)........................... $ 72,135 $ 107,345 $ 108,716 $ 69,609 $ 33,605
Capital expenditures................. 126,506 564,459 142,712 71,387 52,230
Cash flow from operating
activities......................... 86,345 101,523 108,059 62,037 28,126
Cash flow from investing
activities......................... (138,526) (363,136) (143,826) (65,133) (52,670)
Cash flow from financing
activities......................... 42,356 230,400 77,684 (2,299) 30,376
BALANCE SHEET DATA:
Working capital...................... $ 14,823 $ 36,757 $ 48,667 $ 446 $ 14,357
Total assets......................... 505,536 697,109 303,918 145,550 101,625
Long-term debt....................... 294,990 352,090 -- 22,000 6,930
Equity............................... 138,292 184,648 233,203 105,015 89,890
- ---------------
(1) 1996 includes a one-time non-cash deferred tax charge of $30.1 million
recognized as a result of the Combination consummated on March 29, 1996 in
connection with the Company's Initial Public Offering.
(2) Earnings per share have 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,
impairments 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. It 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
Belco Oil & Gas Corp. (the "Company") is an independent energy company
engaged in the exploration for and the acquisition, exploitation, development
and production of natural gas and oil in the United States primarily in the
Rocky Mountains, the Permian Basin, the Mid-Continent region and the 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.
On November 26, 1997, the Company acquired all of the outstanding capital
stock of Coda Energy, Inc. ("Coda"), an independent energy company that was
principally engaged in the acquisition and exploitation of producing oil and
natural gas properties. Coda's properties were 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 index at that
time and established a more balanced reserve mix of approximately 51% oil and
49% natural gas. Based on 1998 production, the Company's reserve life index is
9.7 years.
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 of Wyoming, the Permian Basin in west Texas, the
Mid-Continent region in Oklahoma and north Texas, and the Austin Chalk Trend,
primarily in Texas. These areas accounted for approximately 99% of the Company's
proved reserves at December 31, 1998.
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. 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 small premium to the price posted for such
oil. Currently, approximately 60% of the Company's production volumes relate to
the sale of natural gas (based on six Mcf of gas being considered equivalent to
one barrel of oil).
The Company utilizes commodity swaps and options and other commodity price
risk management transactions related to 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, 1998, the Company has various
natural gas and oil price risk management contracts in place with respect to
substantial portions of its estimated production for calendar year 1999 and with
respect to lesser portions of its estimated production for 2000 and 2001. The
Company expects from time to time to either add 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,
------------------------------
1998 1997 1996
-------- -------- --------
Oil and Gas Sales (Unhedged) (in thousands)................. $124,200 $129,994 $119,710
Commodity Price Risk Management (in thousands).............. 24,800 (6,479) (5,967)
Weighted Average Sales Prices (Unhedged):
Oil (per Bbl)............................................. $ 13.17 $ 19.28 $ 21.30
Gas (per Mcf)............................................. $ 1.86 $ 2.11 $ 2.00
Net Production Data:
Oil (MBbls)............................................... 4,177 1,295 794
Gas (MMcf)................................................ 37,207 49,710 51,289
Gas equivalent (MMcfe).................................... 62,272 57,479 56,053
Gas equivalent (Mcfe-daily)............................... 170,609 157,477 153,570
Data per Mcfe:
Oil and gas sales revenues (unhedged)..................... $ 2.00 $ 2.26 $ 2.14
Commodity price risk management activities................ 0.40 (0.11) (0.11)
Oil and gas operating expenses............................ (0.66) (0.22) (.14)
General and administrative................................ (0.08) (0.07) (.06)
Depreciation, depletion and amortization.................. (0.90) (0.81) (0.73)
-------- -------- --------
Pre-tax operating profit(1)............................... $ 0.76 $ 1.05 $ 1.10
======== ======== ========
- ---------------
(1) Excluding non-cash ceiling test and securities impairment provisions,
interest income and interest expenses.
RESULTS OF OPERATIONS -- 1998 COMPARED TO 1997
Revenues
Oil and gas sales revenues for the year 1998 (unhedged) declined 5% to
$124.2 million when compared to the $130.0 million realized in 1997, due to
substantially lower commodity prices. The year 1997 included only one month of
Coda activities. In 1998 weighted average oil prices realized (unhedged) totaled
$13.17 per barrel, a 32% decline when compared to the $19.28 realized in 1997.
The natural gas weighted average prices realized (unhedged) declined 12% from
$2.11 in 1997 to $1.86 in 1998. Average daily production volume in 1998 on an
Mcfe basis increased 8% to 170,609 Mcfe.
Commodity price risk management activities resulted in a net pre-tax gain
of $24.8 million for 1998 which included (1) realized hedging gains of $2.0
million, (2) net realized gains related to non-hedging transactions totaling
$3.9 million, and (3) non-cash unrealized gains for mark-to-market accounting of
$18.9 million. The impact of such activities on an Mcfe basis amounted to net
gains of $0.40 ($0.10 cash and $0.30 non-cash). This compares to net losses of
$0.11 ($0.13 cash losses and a non-cash gain of $0.02) per Mcfe for 1997.
Costs and Expenses
Production and Operating Expenses. Production and operating expenses
increased to $40.8 million in 1998 when compared to the $12.8 million incurred
during 1997. The increase is identified with the growth in oil production
through secondary recovery techniques following the Coda acquisition and
reflects the higher costs normally associated with such production when compared
to natural gas. On a unit basis, operating costs were $0.66 per Mcfe for 1998
compared to $0.22 per Mcfe for 1997 which included only one month of Coda
activities.
Depreciation, Depletion and Amortization. Recurring depreciation, depletion
and amortization ("DD&A") costs for the year totalled $56.1 million when
compared to the $46.7 million recorded for the prior year. The DD&A rate per
Mcfe was $0.90 and $0.81 for 1998 and 1997, respectively. For the year 1998, the
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Company also recorded $229 million ($149 million after-tax) in non-cash ceiling
test provisions as required by full-cost accounting rules. The provisions were
the result of applying substantially lower commodity prices to estimated
recoverable reserves.
General and Administrative Expenses. General and administrative ("G&A")
costs increased by 33% during 1998 to $5.2 million when compared to the $3.9
million incurred in 1997. The increase is primarily due to the addition of
personnel associated with the Coda transaction. The rate per Mcfe for such costs
increased from $0.07 in 1997 to $0.08 in 1998. Exploration related G&A expenses
for 1998 in the amount of $6.2 million have been capitalized to oil and gas
property accounts. The increase of $0.4 million over the 1997 comparable
capitalized amount of $5.8 million principally reflects additional personnel
costs and seismic activities related to a number of exploration projects.
Interest expense is incurred on $150 million of the 8 7/8% Senior
Subordinated Notes due 2007 (the "8 7/8% Notes") issued in September 1997, $109
million of the 10 1/2% Notes assumed in the Coda acquisition in November 1997
and bank debt incurred under the Revolving Credit Facility. Net interest costs
incurred for the year 1998 totalled $26.1 million, with approximately $5.1
million of this total capitalized to property accounts.
As a result of the substantial decline in the market value of Chesapeake
Energy Corp. ("CHK") securities acquired when Hugoton Energy Corp. ("Hugoton")
was merged into CHK, the Company realized a loss of $14.4 million upon
disposition of these securities during the first nine months of 1998. In
addition, a $9.7 million non-cash impairment provision was recorded to recognize
a decline in the value of Big Bear securities currently owned by the Company.
See "Liquidity and Capital Resources" for additional details related to the Big
Bear investment.
Income (Loss) Before Income Taxes
The Company's reported loss before income tax benefits for the year 1998
was $225.7 million. This compares to a loss of $88.3 million reported in 1997.
The 1998 loss is primarily the result of the non-cash ceiling test impairment
provisions totalling $229 million ($149 million after-tax) mandated by full-cost
accounting rules. The 1997 loss was principally identified with purchase price
allocations related to the Coda acquisition which resulted in a required ceiling
test provision. Income before income taxes, excluding the effect of the non-cash
impairments and purchase accounting provisions, was $3.0 million and $61.7
million for 1998 and 1997, respectively.
Income Taxes
Income tax benefits were recorded for 1998 in the amount of $78.1 million
and $31.4 million for 1997 as a result of reported pre-tax losses.
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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34
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% 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 inactive for two or more years or
having 30 days or less of production during the past two years.
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 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. 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.
LIQUIDITY AND CAPITAL RESOURCES
General
On March 29, 1996, the Company successfully completed an initial public
offering of 6.5 million shares of common stock (the "Offering"). The 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
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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 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) in effect from time to time, which includes a
sub-facility from the Agent for letters of credit. The Borrowing Base at
December 31, 1998 was set at $150 million with $29.5 million advanced to the
Company at that date. The borrowing base is redetermined by the Agent and the
Banks semi-annually based upon their usual and customary oil and gas lending
criteria as such exist from time to time. In addition, 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 (as defined) for one, two, three or six months (or nine
or twelve months if available to the Banks) Eurodollar Loans (as defined), plus
the Applicable Margin. The ABR is the greater of (i) the Prime Rate (as
defined), (ii) the Base CD Rate (as defined) plus 1% or (iii) the Federal Funds
Effective Rate (as defined) plus 0.50%. The Applicable Margin for Eurodollar
Loans varies from 0.50% to 0.875% depending on the Borrowing Base usage.
Borrowing Base usage is determined by a ratio of (i) outstanding Loans (as
defined) and letters of credit to (ii) the then effective Borrowing Base.
Interest on ABR Loans is payable quarterly in arrears and interest on Eurodollar
Loans is payable on the last day of the interest period therefore and, if longer
than three months, at three month intervals.
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 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 to 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.
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 Coda acquisition)), assumption of
$110 million of Coda long-term debt outstanding and three year warrants to
purchase 1,666,667 shares of Common Stock of the Company at $27.50 per share
issued to the holders of the outstanding common stock, preferred stock and
options to
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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. At closing, 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 its Credit Facility.
On February 25, 1998, the Company merged Coda into Belco and immediately
thereafter transferred all of Coda's assets and liabilities, except for Coda's
obligations under the 10 1/2% Notes to Belco Energy Corp., a Nevada corporation
and a wholly owned subsidiary of the Company. As of December 31, 1998, the
Company also had $109 million principal amount outstanding under the 10 1/2%
Notes. Interest on the 10 1/2% Notes accrue 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 10 1/2% Notes are not redeemable at the
Company's option prior to April 1, 2001. Thereafter the 10 1/2% Notes will be
subject to redemption at specified prices, plus accrued and unpaid interest, if
any, thereon to the applicable redemption date.
The 10 1/2% Notes are general unsecured obligations of the Company and are
subordinated in right of payment to all existing and future Senior Debt (as
defined) of the Company, including any bank debt.
The Company entered into interest rate swap agreements converting two
long-term debt fixed rate obligations to floating rate obligations as follows:
TRANSACTION FIXED FLOATING FLOATING RATE
AGREEMENT AMOUNT DATE RATE RATE EXPIRATION DATE
---------------- ----------- ------- -------- -----------------
$100 million................... 12/97 8.875% 8.280% March 15, 2000(a)
$110 million................... 12/97 10.500% 10.120% April 1, 2000(a)
$50 million................... 1/98 8.875% 8.080% March 15, 1999(a)
- ---------------
(a) Floating rate is redetermined at each six month period following the
expiration through September 15, 2007.
The agreements obligate the Company to actually pay the indicated floating
rate rather than the original fixed rate. The floating rates are capped at
8 7/8% through September 15, 2001 and at 10% from March 15, 2002 through
September 15, 2007 on the 8 7/8% Notes and capped at 10 1/2% through October 1,
1999 and 11.625% from April 1, 2000 through April 1, 2003 on the 10 1/2% Notes.
The agreements reduced the Company's 1998 interest expense by approximately $1
million.
On March 10, 1998 the Company completed the sale of 4.37 million shares of
its 6 1/2% 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.
On June 12, 1998, the Company, through its wholly-owned Canadian
subsidiary, purchased approximately $10.5 million of 5% Convertible Preferred
Stock of Big Bear, a Canadian oil and gas company, at approximately $0.85 per
share with each share convertible into one common share of Big Bear. The Company
was also issued approximately $120 million of Special Acquisition Warrants at a
price of approximately $0.72 per warrant. In connection with the issuance of the
Special Acquisition Warrants, the Company deposited a $60 million letter of
credit and 3,436,000 shares of the Company's common stock into an escrow
account. On November 10, 1998, the Company executed a restructuring agreement
whereby (i) the Company agreed to convert the Big Bear 5% Convertible Preferred
Stock into 21,428,571 shares of Big Bear Common Stock at a conversion price of
approximately $0.50 per share (reduced from $0.85 per share), (ii) the Special
Acquisition Warrants were canceled, (iii) the Belco representatives resigned
from Big Bear's Board of Directors, (iv) the $60 million letter of credit was
canceled, and (v) the 3,436,000 shares of Company common stock held in the
escrow account were returned to the Company and designated as unissued. The
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restructuring agreement closed on January 22, 1999. Additionally, following the
acquisition of Blue Range Resource Corporation by Big Bear in December 1998
through the issuance of 381,689,000 shares of Big Bear common stock, directors
of Big Bear determined that an 11 to 1 reverse split of Big Bear Common Shares
would be in the corporation's best interests. The proposed Big Bear reverse
split received the required approvals and Belco, through its wholly-owned
Canadian subsidiary, now owns 1,948,052 common shares or approximately 4.6%
ownership in Big Bear.
In February 1998, the Company acquired properties consisting of
approximately 65 Bcfe of long-lived reserves in the Permian Basin of west Texas
from EnerVest Texoma Acquisition L.P. for $37.3 million in cash.
In November 1998, the Company acquired approximately 20 Bcfe of long-lived
reserves on producing properties in Oklahoma and Kansas, as well as certain
undeveloped acreage and 3-D seismic data, for approximately $14.8 million.
Cash Flow
Operating cash flow, a measure of performance for exploration and
production companies, is generally derived by adjusting net income to eliminate
the effects of the non-cash components included in the net income calculation
such as depreciation, depletion and amortization expense, provision for deferred
income taxes, ceiling test provisions, and the non-cash effects of investing and
commodity price risk management activities. Operating cash flow, before changes
in working capital, was approximately $72.1 and $107.3 million for the years
1998 and 1997, respectively. The Company had working capital of $14.8 million as
of December 31, 1998, a decrease of $22.0 million from the $36.8 million
available as of December 31, 1997.
Capital Expenditures
For 1998, the Company incurred capital expenditures in the amount of $133.1
million, including property acquisitions totalling $52.2 million.
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. The Company has a
preliminary 1999 capital expenditure budget of approximately $75 million, with
$25 million allocated to potential acquisitions. 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 that it will have
sufficient capital resources and liquidity to fund its capital expenditures and
meet all of its financial obligations as they come due.
On December 15, 1998, the Company's Board of Directors authorized the
purchase from time to time, in the open market or in privately negotiated
transactions, shares of its Common and 6 1/2% Convertible Preferred Stock, in an
aggregate amount not to exceed $10 million.
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 commodity 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
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38
with respect to a substantial portion of its estimated production for 1999 and
lesser portions of its estimated production thereafter. The Company continues to
evaluate whether to enter into additional price risk management transactions for
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.
Year 2000 Compliance
The year 2000 issue concerns the potential inability of information
technology and non-information technology systems and processes to properly
recognize and process date-sensitive information before, during, and after
December 31, 1999.
The Company has a variety of operating systems, computer software program
applications, computer hardware equipment and other equipment with embedded
electronic circuits, including applications used in the Company's financial
business systems, field operations, and administrative functions (collectively,
the "systems").
Members of the Company's management group and financial department
personnel have oversight of the information systems and personnel charged with
implementing the Company's year 2000 compliance program.
The Company has upgraded hardware and software over the past year and
believes that its internal financial and most of the operational systems are
currently year 2000 compliant. The Company does not separately track the costs
associated with the year 2000 compliance effort, as they have not been material
and, further, no projects with any significant impact to the Company's
operations have been deferred due to the year 2000 compliance effort. To date,
the Company estimates that it has incurred less than $100,000 in upgrading a
limited amount of hardware and does not expect to incur any significant
additional cost in becoming year 2000 compliant. The Company does not know
whether its significant vendors' and customers' systems are yet fully year 2000
compliant. If they are not, such failure could partially affect the Company's
ability to sell its oil and gas and receive related payments. In addition, there
could be disruptions in getting certain vendors to provide supplies and/or
services in support of the Company's operations. While this is the most likely
worst case scenario, the Company believes that its significant vendors and
customers will be year 2000 compliant before that critical date.
Additionally, the Company fully understands that there are risks associated
with year 2000 issues that it cannot directly control, primarily the readiness
of its key suppliers and customers. The Company has had contact with a
significant number of its customers and vendors and furnished information about
how it is addressing the year 2000 issue. The Company is presently investigating
contingency strategies primarily with existing internal resources in the event
of any third party or internal system failure. Contingency plans contemplated
include the use of alternative hardware and software vendors and customers as
appropriate in the event that a presently unforeseen failure of a key vendor or
customer is burdened with some non-controllable year 2000 compliance related
failure.
The Company presently expects that its financial and related information
systems, operations systems and other essential functions will be ready for the
year 2000 transition, and that year 2000 issues would not have a material effect
on the Company's business or financial condition.
36
39
New Accounting Standards
In June 1998, the Financial Accounting Standards Board issued Statement No.
133, Accounting for Derivative Instruments and Hedging Activities ("FAS 133").
FAS 133 is effective for fiscal years beginning after June 15, 1999. FAS 133
requires all derivatives to be recorded on the balance sheet at fair value and
established "special accounting" for the following three different types of
hedges: hedges of changes in the fair value of assets, liabilities, or firm
commitments (referred to as fair value hedges); hedges of the variable cash
flows of forecasted transactions (cash flow hedges); and hedges of foreign
currency exposures of net investments in foreign operations. Though the
accounting treatment and criteria for each of the three types of hedges is
unique, they all result in offsetting changes in fair values or cash flows of
both the hedge and the hedged item being recognized in earnings in the same
period with no net impact on reported earnings. Changes in fair value of
derivatives that do not meet the criteria of one of these three categories of
hedges are included in income and reported as either gain or loss for the
current period. Transition adjustments resulting from adoption must be
recognized in income and comprehensive income, as appropriate, as a cumulative
effect of an accounting change. Belco has not yet determined the effect of total
compliance, but it is not expected to materially impact the financial statements
of the Company.
ITEM 7A -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's market risk exposures relate primarily to commodity prices,
interest rates and marketable equity securities. The Company enters into various
transactions involving commodity price risk management activities involving a
variety of derivatives instruments to, in effect, hedge the impact of crude oil
and natural gas price fluctuations. In addition, the Company entered into
interest rate swap agreements to reduce current interest burdens related to its
fixed long-term debt. The derivatives instruments are generally put in place to
limit the risk of adverse oil and natural gas price movements, however, such
instruments can limit future gains resulting from upward favorable oil and
natural gas price movements. Recognition of both realized and unrealized gains
or losses are reported currently in the Company's financial statements as
required by existing generally accepted accounting principles. The cash flow
impact of all derivative related transactions is reflected as cash flows from
operating activities.
As a result of certain commodity price risk management transactions in
effect for crude oil and natural gas, the Company's average realized crude oil
and natural gas pricing has been impacted as follows:
YEAR ENDED DECEMBER 31,
----------------------------
1998 1997 1996
------ ------ ------
Percent of crude oil production........................ 80% 80% 80%
Price realized without hedging (per Bbl)............... $13.17 $19.28 $21.30
Increase (decrease) in price realized (per Bbl)........ $ 3.78 $ 1.44 $ 1.59
Percent of natural gas production...................... 80% 80% 80%
Price realized without hedging (per Mcf)............... $ 1.86 $ 2.11 $ 2.00
Increase (decrease) in price realized (per Mcf)........ $(0.22) $(0.39) $(0.37)
- ---------------
Note: All amounts approximate.
As of December 31, 1998, the Company had substantial derivative financial
instruments outstanding and related to its price risk management program. See
"Footnote 7" to the consolidated financial statements of the Company "Commodity
Price Risk Management Activities and Fair Value of Financial Instruments" for
complete details on the Company's oil and gas related transactions in effect as
of December 31, 1998. Transactions subsequent to year-end 1998 were not
significant.
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The table below provides information related to the Company's interest rate
swaps on long-term debt obligations. For interest rate swaps, the table presents
notional amounts and approximate weighted average interest rates by contractual
maturity dates. Notional amounts are used to calculate the contractual payments
to be exchanged under the agreements in place.
FAIR VALUE
EXPECTED MATURITY DATE AS OF
---------------------------------------------------- DECEMBER 31,
1999 2000 2001 2002 TOTAL 1998
-------- -------- -------- -------- -------- ------------
($ IN THOUSANDS)
Assets:
Marketable Equity
Securities.............. $ -- $ -- $ -- $ -- $ 643 $ 643
Liabilities:
Bank credit facility....... -- -- -- 29,500 29,500 $29,500
Variable rate.............. 6.0% 6.25% 6.25% 6.25%
Belco 8.875% Notes......... -- -- -- -- 150,000(1)
Belco 10.500% Notes........ -- -- -- -- 109,000(2)
Interest Rate Swaps:
Fixed to Variable.......... $260,000 $235,000 $235,000 $235,000 $ 196
Average pay rate........... 8.92% 8.92% 9.20% 9.20%
Average receive rate....... 9.56% 9.56% 9.56% 9.56%
- ---------------
(1) Notes mature 2007
(2) Notes mature 2006
ITEM 8 -- CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
See the Consolidated Financial Statements and supplementary data listed in
the accompanying Index to Financial Statements and Financial Statement Schedules
on page F-1 herein. Information required by other schedules required under
Regulation S-X is either not applicable or is included in the financial
statements or notes thereto.
ITEM 9 -- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10 -- DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information regarding Directors and Executive Officers required under
Item 10 will be contained in the definitive Proxy Statement of the Company for
its 1999 Annual Meeting of Shareholders (the "Proxy Statement") under the
headings "Election of Directors", "Executive Compensation and Other Information"
and "Section 16(a) Beneficial Ownership Compliance" and is incorporated herein
by reference. The Proxy Statement will be filed pursuant to Regulation 14A with
the Securities and Exchange Commission not later than 120 days after December
31, 1998. For information regarding Executive Officers not appearing in the
Proxy Statement, see "Business -- Executive Officers of the Registrant".
ITEM 11 -- EXECUTIVE COMPENSATION
The information required under Item 11 will be contained in the Proxy
Statement under the heading "Executive Compensation and Other Information" and
is incorporated herein by reference.
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ITEM 12 -- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required under Item 12 will be contained in the Proxy
Statement under the heading "Security Ownership of Management and Certain
Beneficial Owners" and is incorporated herein by reference.
ITEM 13 -- CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required under Item 13 will be contained in the Proxy
Statement under the headings "Transactions with Management and Certain
Shareholders" and "Executive Compensation and Other Information" and is
incorporated herein by reference.
PART IV
ITEM 14 -- EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements: See Index to Consolidated Financial
Statements and Schedules immediately following the signature page of this
report.
2. Financial Statement Schedules: See Index to Consolidated Financial
Statements and Schedules immediately following the signature page of this
report.
3. Exhibits: The following documents are filed as exhibits to this
report.
EXHIBIT
NO. DESCRIPTION OF EXHIBIT
------- ----------------------
3.1 -- Articles of Incorporation of Company (Incorporated by
reference from Exhibit 3.1 of the Registration Statement
on Form S-1, Registration No. 333-1034).
3.2 -- Amended and Restated Bylaws of Company dated February 5,
1996 (Incorporated by reference from Exhibit 3.2(ii) of
the Form 10-Q dated March 31, 1996).
4.1 -- Specimen Common Stock certificate (Incorporated by
reference from Exhibit 4.1 of the Registration Statement
on Form S-1, Registration No. 333-1034).
4.2 -- Indenture dated as of September 23, 1997 among the
Company, as issuer, and The Bank of New York, as trustee
(Incorporated by reference from Exhibit 4.1 of
Registration Statement on Form S-4, Registration No.
333-37125).
4.3 -- Supplemental Indenture dated as of February 25, 1998
between Coda Energy, Inc., Diamond Energy Operating
Company, Electra Resources, Inc., Belco Operating Corp.,
Belco Energy L.P., Gin Lane Company, Fortune Corp., BOG
Wyoming LLC and Belco Finance Co. (individually, the
Subsidiary Guarantors), a subsidiary of the Company, and
The Bank of New York, a New York banking corporation (as
Trustee) amending the Indenture filed as Exhibit 4.2
above(Incorporated by reference from Exhibit 4.3 of the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1997).
4.4 -- Exchange and Registration Rights Agreement dated
September 23, 1997 by and among 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).
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EXHIBIT
NO. DESCRIPTION OF EXHIBIT
------- ----------------------
4.6 -- First Supplemental Indenture dated as of April 25, 1996
amending the Indenture filed as Exhibit 4.5 above
(Incorporated by reference from Exhibit 4.12 of the Coda
Energy, Inc. Quarterly Report on Form 10-Q for the
quarterly period ended June 30, 1996, Commission File No.
0-10955).
4.7 -- Second Supplemental Indenture dated as of February 25,
1998 by and among 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. (Incorporated by reference from
Exhibit 4.7 of the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1997).
4.8 -- Third Supplemental Indenture dated as of February 25,
1998 by and between 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).
(Incorporated by reference from Exhibit 4.8 of the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1997).
4.9 -- Certificate of Designations of 6 1/2% Convertible
Preferred Stock dated March 5, 1997 (Incorporated by
reference from Exhibit 4.1 of current report on Form 8-K
dated March 11, 1998).
10.1 -- 1996 Non-Employee Directors' Stock Option Plan
(Incorporated by reference from Exhibit 10.1 of the
Registration Statement on Form S-1, Registration No.
333-1034).
10.2 -- 1996 Stock Incentive Plan (Incorporated by reference from
Exhibit 10.2 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.3 -- Exchange and Subscription Agreement and Plan of
Reorganization dated as of January 1, 1996 by and among
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).
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EXHIBIT
NO. DESCRIPTION OF EXHIBIT
------- ----------------------
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. (the 'Borrower'), and The
Chase Manhattan Bank, as administrative agent, and
certain financial institutions named therein as Lenders
(the 'Lenders') (Incorporated by reference to Exhibit
10.1 of 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 the Borrower, 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 the Borrower, the Lenders and The Chase
Manhattan Bank, as administrative agent. (Incorporated by
reference from Exhibit 10.16 of the Company's Annual
Report on Form 10-K for the fiscal year ended December
31, 1997).
*10.17 -- Third Amendment, dated as of May 29, 1998, to the Credit
Agreement, dated as of September 23, 1997, as amended by
the First Amendment and Waiver thereto, dated as of
November 25, 1997, and the Second Amendment and Consent
thereto, dated as of February 25, 1998, by and among the
Borrower, the Lenders and The Chase Manhattan Bank, as
administrative agent.
*10.18 -- Fourth Amendment, dated as of December 21, 1998, to the
Credit Agreement, dated as of September 23, 1997, as
amended by the First Amendment and Waiver thereto, dated
as of November 25, 1997, and the Second Amendment and
Consent thereto, dated as of February 25, 1998, and the
Third Amendment, dated as of May 29, 1998, by and among
the Borrower, the Lenders and The Chase Manhattan Bank,
as administrative agent.
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EXHIBIT
NO. DESCRIPTION OF EXHIBIT
------- ----------------------
10.19 -- Executive Employment Agreement with Grant W. Henderson
(Incorporated by reference from Exhibit 99.7 of the Coda
Energy, Inc. Current Report on Form 8-K dated October 30,
1995, Commission File No. 0-10955).
10.20 -- Executive Employment Agreement with Jarl P. Johnson
(Incorporated by reference from Exhibit 99.8 of the Coda
Energy, Inc. Current Report on Form 8-K dated October 30,
1995, Commission File No. 0-10955).
*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.
(b) Reports on Form 8-K.
Current Report on Form 8-K dated November 10, 1998.
Item 5. Other Events
Item 7. Financial Statements, Pro Forma Financial Information and
Exhibits
(a) Financial Statements of Business Acquired.
Not applicable.
(b) Pro Forma Financial Information
Not applicable.
(c) Exhibits.
99.1 Press release dated November 11, 1998.
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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
Vice-Chairman, Chief Operating
Officer and Director
Date: March 26, 1999
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 26, 1999
- ----------------------------------------------------- Chairman of the Board of
Robert A. Belfer Directors (Principal Executive
Officer)
/s/ LAURENCE D. BELFER Vice-Chairman, Chief Operating March 26, 1999
- ----------------------------------------------------- Officer and Director
Laurence D. Belfer
/s/ DOMINICK J. GOLIO Senior Vice March 26, 1999
- ----------------------------------------------------- President -- Finance, Chief
Dominick J. Golio Financial Officer, Treasurer
and Secretary (Principal
Financial Officer and
Principal Accounting Officer)
/s/ GRAHAM ALLISON Director March 26, 1999
- -----------------------------------------------------
Graham Allison
/s/ DANIEL C. ARNOLD Director March 26, 1999
- -----------------------------------------------------
Daniel C. Arnold
/s/ ALAN D. BERLIN Director March 26, 1999
- -----------------------------------------------------
Alan D. Berlin
/s/ JACK SALTZ Director March 26, 1999
- -----------------------------------------------------
Jack Saltz
/s/ GEORGIANA SHELDON-SHARP Director March 26, 1999
- -----------------------------------------------------
Georgiana Sheldon-Sharp
43
46
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, 1998 and
1997................................................... F-3
Consolidated Statements of Operations for the Years Ended
December 31, 1998, 1997 and 1996....................... F-4
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1998, 1997 and 1996........... F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996....................... 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
47
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, 1998 and
1997, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1998. 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, 1998 and 1997, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted accounting
principles.
ARTHUR ANDERSEN LLP
Dallas, Texas
March 4, 1999
F-2
48
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
DECEMBER 31,
---------------------
1998 1997
--------- ---------
(IN THOUSANDS)
CURRENT ASSETS:
Cash and cash equivalents................................. $ 2,435 $ 12,260
Accounts receivable....................................... 28,464 43,867
Assets from commodity price risk management activities.... 18,643 936
Marketable equity securities.............................. -- 28,884
Other current assets...................................... 1,005 1,056
--------- ---------
Total Current Assets.............................. 50,547 87,003
--------- ---------
PROPERTY AND EQUIPMENT:
Oil and gas properties at cost based on full-cost
accounting --
Proved oil and gas properties.......................... 931,218 793,475
Unproved oil and gas properties........................ 74,935 86,172
Less -- Accumulated depreciation, depletion and
amortization.......................................... (566,613) (282,750)
--------- ---------
Net oil and gas property.................................. 439,540 596,897
--------- ---------
Building and other equipment.............................. 8,633 7,667
--------- ---------
Less -- Accumulated depreciation....................... (1,281) (790)
--------- ---------
Net building and other equipment.......................... 7,352 6,877
--------- ---------
OTHER ASSETS................................................ 8,097 6,332
--------- ---------
Total Assets...................................... $ 505,536 $ 697,109
========= =========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable.......................................... $ 18,372 $ 25,879
Liabilities from commodity price risk management
activities............................................. 5,393 9,555
Accrued interest.......................................... 6,897 7,040
Other accrued liabilities................................. 5,064 7,772
--------- ---------
Total Current Liabilities......................... 35,726 50,246
LONG-TERM DEBT.............................................. 294,990 352,090
DEFERRED INCOME TAXES....................................... 31,833 110,047
LIABILITIES FROM COMMODITY PRICE RISK MANAGEMENT
ACTIVITIES................................................ 4,696 78
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares
authorized and 4,312,000 outstanding................... 43 --
Common Stock, $0.01 par value; 120,000,000 shares
authorized; 31,609,900 and 31,584,400 issued and
outstanding at December 31, 1998 and 1997,
respectively........................................... 316 316
Additional paid-in capital................................ 301,416 196,864
Retained earnings (deficit)............................... (161,627) (8,664)
Unearned compensation..................................... (1,082) (1,093)
Notes receivable for equity interest...................... (775) (775)
Unrealized loss on marketable equity securities........... -- (2,000)
--------- ---------
Total Stockholders' Equity........................ 138,291 184,648
--------- ---------
Total Liabilities and Stockholders' Equity........ $ 505,536 $ 697,109
========= =========
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-3
49
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------ ----------- -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
REVENUES:
Oil and gas sales....................................... $ 124,200 $129,994 $119,710
Commodity price risk management activities.............. 24,800 (6,479) (5,967)
Interest................................................ 1,730 3,245 2,653
--------- -------- --------
Total revenues.................................. 150,730 126,760 116,396
--------- -------- --------
COSTS AND EXPENSES:
Oil and gas operating expenses.......................... 40,847 12,758 7,847
Depreciation, depletion and amortization................ 56,102 46,684 40,904
Impairment of oil and gas properties.................... 229,000 150,000 --
Impairment of equity securities......................... 24,216 -- --
General and administrative.............................. 5,216 3,913 3,059
Interest expense........................................ 21,013 1,668 --
--------- -------- --------
Total costs and expenses........................ 376,394 215,023 51,810
--------- -------- --------
INCOME (LOSS) BEFORE INCOME TAXES......................... (225,664) (88,263) 64,586
PROVISION (BENEFIT) FOR INCOME TAXES...................... (78,107) (31,355) 21,953(a)
--------- -------- --------
NET INCOME (LOSS)......................................... (147,557) (56,908) 42,633
PREFERRED STOCK DIVIDENDS................................. (5,406) -- --
--------- -------- --------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK............... $(152,963) $(56,908) $ 42,633
========= ======== ========
EARNINGS (LOSS) PER SHARE OF COMMON STOCK, BASIC AND FULLY
DILUTED................................................. $ (4.85) $ (1.80) $ 1.42
========= ======== ========
AVERAGE NUMBER OF COMMON SHARES USED IN
COMPUTATION, BASIC AND FULLY DILUTED.................... 31,529 31,538 30,039
========= ======== ========
- ---------------
(a) Does not include 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. For
1996, the amounts present the Company as if it was a taxable corporation for
the year then ended and earnings per share are based on the average number
of shares outstanding assuming the shares issued in connection with the
Combination were outstanding for the entire year.
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-4
50
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
PREFERRED STOCK COMMON STOCK ADDITIONAL RETAINED COMBINED
--------------- ---------------- PAID-IN UNEARNED EARNINGS PREDECESSOR
SHARES AMOUNT SHARES AMOUNT CAPITAL COMPENSATION (DEFICIT) EQUITY
------ ------ ------- ------ ---------- ------------ --------- -----------
BALANCE, December 31, 1995..... -- $-- -- $ -- $ -- $ -- $ -- $105,849
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................... -- -- -- -- -- -- -- --
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 $ --
----- --- ------- ---- -------- ------- --------- --------
Comprehensive Income...........
Restricted stock issued........ -- -- 5 -- 123 192 -- --
Exercise of stock options...... -- -- 2 -- 38 -- -- --
Issuance of warrants........... -- -- -- -- 10,000 -- -- --
Unrealized loss on marketable
equity securities............ -- -- -- -- -- -- -- --
Net income (loss).............. -- -- -- -- -- -- (56,908) --
----- --- ------- ---- -------- ------- --------- --------
BALANCE, December 31, 1997..... -- -- 31,584 $316 $196,864 $(1,093) $ (8,664) $ --
----- --- ------- ---- -------- ------- --------- --------
Comprehensive Income...........
Issuance of Preferred Stock.... 4,370 $44 -- -- $105,025 -- -- --
Repurchase of Preferred
Stock........................ (58) (1) -- -- (806) -- -- --
Restricted Stock Issued
(Net)........................ -- -- 25 -- 333 11 -- --
Unrealized loss on marketable
equity securities............ -- -- -- -- -- -- -- --
Net income (loss).............. -- -- -- -- -- -- (147,557) --
Preferred Dividend paid........ -- -- -- -- -- -- (5,406) --
----- --- ------- ---- -------- ------- --------- --------
BALANCE, December 31, 1998..... 4,312 $43 31,609 $316 $301,416 $(1,082) $(161,627) $ --
===== === ======= ==== ======== ======= ========= ========
Comprehensive Income...........
UNREALIZED
NOTES LOSS ON
RECEIVABLE MARKETABLE
FOR EQUITY EQUITY COMPREHENSIVE
INTEREST SECURITIES TOTAL INCOME
---------- ---------- --------- -------------
BALANCE, December 31, 1995..... $(834) $ -- $ 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 -- 59 --
Distributions to predecessor
owners....................... -- -- (3,395) --
Net income(a).................. -- -- 18,182 18,182
----- ------- --------- ---------
BALANCE, December 31, 1996..... $(775) $ -- $ 233,203
----- ------- ---------
Comprehensive Income........... $ 18,182
=========
Restricted stock issued........ -- -- 315 --
Exercise of stock options...... -- -- 38 --
Issuance of warrants........... -- -- 10,000 --
Unrealized loss on marketable
equity securities............ -- (2,000) (2,000) (1,320)
Net income (loss).............. -- -- (56,908) (56,908)
----- ------- --------- ---------
BALANCE, December 31, 1997..... $(775) $(2,000) $ 184,648
----- ------- ---------
Comprehensive Income........... $ (58,228)
=========
Issuance of Preferred Stock.... -- -- $ 105,069 --
Repurchase of Preferred
Stock........................ -- -- (807) --
Restricted Stock Issued
(Net)........................ -- -- 344 --
Unrealized loss on marketable
equity securities............ -- 2,000 2,000 1,320(b)
Net income (loss).............. -- -- (147,557) (147,557)
Preferred Dividend paid........ -- -- (5,406) --
----- ------- --------- ---------
BALANCE, December 31, 1998..... $(775) -- $ 138,291
===== ======= =========
Comprehensive Income........... $(146,237)
=========
- ---------------
(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.
(b) Represents a reclassification adjustment for $2.0 million gross ($1.32
million net of tax) unrealized loss recognized in comprehensive income in
1997, but recognized in net income during 1998.
The accompanying notes to consolidated financial statements are an integral part
of these statements.
F-5
51
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(IN THOUSANDS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)(a).................................... $(147,557) $ (56,908) $ 18,182
Adjustments to reconcile net income (loss) to net
operating cash inflows --
Depreciation, depletion and amortization............. 56,102 46,684 40,904
Impairment of oil and gas properties................. 229,000 150,000 --
Impairment of equity securities...................... 9,773 -- --
Deferred tax (benefit) provision (a)................. (78,107) (31,536) 39,967
Commodity price risk management activities........... 2,942 (1,248) 9,436
Other................................................ (19) 353 227
Changes in operating assets and liabilities --
Commodity price risk management.................... (21,869) -- --
Accounts receivable................................ 15,208 1,850 (11,955)
Marketable equity securities....................... 30,884 -- --
Other current assets............................... 247 (65) (286)
Accounts payable and accrued liabilities........... (10,259) (7,607) 11,584
--------- --------- ---------
Net operating cash inflows...................... 86,345 101,523 108,059
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures................ (133,078) (140,975) (142,712)
Proceeds from sale of oil and gas properties............ 6,292 13,949 --
Changes in accounts payable and accrued liabilities for
oil and gas expenditures............................. -- 11,726 (730)
Change in advances to oil and gas operators............. -- (277) (24)
Purchase of Coda Energy, Inc............................ -- (214,896) --
Purchase of marketable equity securities................ (10,467) (30,884) --
Changes in other assets................................. (22) (1,779) (360)
Other property additions................................ (1,251) -- --
--------- --------- ---------
Net investing cash outflows..................... (138,526) (363,136) (143,826)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from initial public offering................... -- -- 113,115
Long-term borrowings.................................... 68,000 85,000 13,300
Net proceeds from issuance of subordinated notes........ -- 145,400 --
Long-term debt repayments............................... (124,500) -- (35,300)
Proceeds from issuance of Preferred Stock............... 105,069 -- --
Dividends on Preferred Stock............................ (5,406) -- --
Repurchase Preferred Stock.............................. (807) -- --
Equity distributions.................................... -- -- (13,490)
Employee loans, net..................................... -- -- 59
--------- --------- ---------
Net financing cash inflows...................... 42,356 230,400 77,684
--------- --------- ---------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.......... (9,825) (31,213) 41,917
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.......... 12,260 43,473 1,556
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD................ $ 2,435 $ 12,260 $ 43,473
========= ========= =========
- ---------------
(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
52
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 CURRENT 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 two years ended December 31,
1998 include the accounts of the Company and its wholly-owned subsidiaries
including one month of Coda operations for 1997. The Company's interests in the
Moxa Arch investment programs (the 1992 Moxa Arch Drilling Program, the 1993
Moxa Arch Drilling Program, the Moxa Arch 1992 Offset Drilling Program and the
Moxa Arch 1993 Offset Drilling Program) (collectively, the "Programs") are
accounted for using the proportionate consolidation method of accounting for
investments in oil and gas property interests, whereby the Company's share of
each program's assets, liabilities, revenues and expenses is included in the
appropriate accounts of the consolidated
F-7
53
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
financial statements. All material intercompany balances and transactions have
been eliminated. 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.
CASH EQUIVALENTS
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
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 $6,054,000, $5,769,000 and $3,065,000
of related internal costs during 1998, 1997 and 1996, 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 1998 estimated proved reserves, the Company
recorded in the fourth quarter ended December 31, 1998 a non-cash impairment of
oil and gas properties of approximately $75 million ($48.8 million after tax).
The impairment provision is in addition to similar provisions booked at the end
of the first and second quarters of 1998 due to low commodity prices. The 1997
provision included the effect of the non-cash $101 million Statement of
Financial Accounting Standards ("SFAS") No. 109 deferred tax "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 also 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 three 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 in 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.
F-8
54
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
After elimination of management fees received from affiliated entities,
including predecessor owners, the Company earned management fees totaling
$305,000, $297,000 and $583,000 during 1998, 1997 and 1996, respectively.
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, 1998, 1997 and 1996, totaled $5,123,000,
$3,742,000 and $434,000, 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 a gain or loss in the period of change.
In June 1998, the Financial Accounting Standards Board issued Statement No.
133, "Accounting for Derivative Instruments and Hedging Activities" ("FAS 133").
FAS 133 is effective for fiscal years beginning after June 15, 1999. FAS 133
requires all derivatives to be recorded on the balance sheet at fair value and
established "special accounting" for the following three different types of
hedges: hedges of changes in the fair value of assets, liabilities, or firm
commitments (referred to as fair value hedges); hedges of the variable cash
flows of forecasted transactions (cash flow hedges); and hedges of foreign
currency exposures of net investments in foreign operations. Though the
accounting treatment and criteria for each of the three types of hedges is
unique, they all result in offsetting changes in fair values or cash flows of
both the hedge and the hedged item being recognized in earnings in the same
period with no net impact on reported earnings. Changes in fair value of
derivatives that do not meet the criteria of one of these three categories of
hedges are included in income and reported as either gain or loss for the
current period. Transition adjustments resulting from adoption must be
recognized in income and comprehensive income, as appropriate, as a cumulative
effect of an accounting change. Belco has not yet determined the effect of total
compliance, but it is not expected to materially impact the financial statements
of the Company.
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
F-9
55
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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,
1998 and 1997 were not significant.
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 three months ended March 29, 1996 were not subject to
corporate income taxes as the Company through that date was a combination of
non-taxpaying entities, including Subchapter S, limited liability corporations,
partnership and joint venture entities and individual interests. Accordingly,
earnings were directly taxable to the individual owners. The pro forma provision
for income tax for 1996 is 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 period (See Note 6).
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, after the
payment of dividends to preferred stockholders, 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. ("Belco Sub"), a Delaware corporation
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
F-10
56
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. 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)
---------
Net cash paid, including capital contributed................ $ 214,896
=========
NOTE 4 -- LONG TERM DEBT
Long term debt consists of the following at December 31, 1998 and 1997 (in
thousands):
DECEMBER 31,
-------------------
1998 1997
-------- --------
Revolving credit facility due 2002.......................... $ 29,500 $ 85,000
8 7/8% Senior Subordinated Notes due 2007................... 150,000 150,000
10 1/2% Senior Subordinated Notes due 2006, including
premium totaling approximately $6.4 and $7.1 million for
1998 and 1997, respectively............................... 115,490 117,090
-------- --------
Total Debt........................................ 294,990 352,090
Less: Current maturities.................................... -- --
-------- --------
Long term debt.............................................. $294,990 $352,090
======== ========
In September, 1997 the Company entered into a five-year $150 million Credit
Agreement dated September 23, 1997 (as amended, 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, 1998 was set at $150 million with
$29.5 million advanced to the Company at that date. 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 Company may request two additional redeterminations and the Banks
may request one additional redetermination per year. During 1998, the weighted
average interest rate was approximately 6%.
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
F-11
57
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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
therefore 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 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, 1998, the Company had outstanding $109 million face
value of the 10 1/2% Notes. The debt was assumed in connection with the
acquisition of Coda in 1997 and was recorded at $117.1 million, including
premium, reflecting the fair value at the date of acquisition. The 10 1/2% Notes
bear interest at an annual rate of 10 1/2% payable semiannually in arrears on
April 1 and October 1 of each year. The Notes are general, unsecured obligations
of the Company, are subordinated in right of payment to all Senior Debt (as
defined in the Indenture governing the 10 1/2% Notes) of the Company, and are
senior in right of payment to all future subordinated debt of the Company. On
February 25, 1998, the Company merged Coda into Belco and Belco assumed the
obligations under the Coda Indenture. Effective with the merger, the 10 1/2%
Notes became pari passu in right of payment with the 8 7/8% Notes.
The 10 1/2% Notes were issued pursuant to an Indenture, which contains
certain covenants that, among other things, limit the ability of Coda and its
restricted subsidiaries (as defined in the Indenture) to incur additional
indebtedness and issue Disqualified Stock (as defined in the Indenture), pay
dividends, make distributions, make investments, make certain other restricted
payments, enter into certain transactions with affiliates, dispose of certain
assets, incur liens securing pari passu or subordinated indebtedness of the
Company and engage in mergers and consolidations.
F-12
58
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The 10 1/2% Notes are not redeemable by the Company prior to April 1, 2001.
After April 1, 2001, the 10 1/2% Notes will be subject to redemption at the
option of the Company, 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 10 1/2%
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.
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 7/8% 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 7/8% through September 15, 2001 and at 10% from March 15,
2002 through September 15, 2007. The second agreement covers $110 million of
10 1/2% long-term debt (comparable to the interest rate on the 10 1/2% 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 1/2% through October 1,
1999 and 11.625% from April 1, 2000 through April 1, 2003.
NOTE 5 -- RELATED-PARTY TRANSACTIONS
The Company's executive offices are leased from its Chairman and $250,000
was paid under such lease in 1998, 1997 and 1996. 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.
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 $894,000 and $775,000 as of December 31, 1998 and 1997,
respectively, and related to amounts loaned to employees in connection with
purchases of oil and gas interests from such employees. The notes receivable
have been recorded as a reduction of equity in the consolidated balance sheets,
as such interests were exchanged for Common Stock in the Combination (See Note
1).
NOTE 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 provision for income taxes reflected in the Consolidated
Statements of Operations for the year ended December 31, 1996 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
F-13
59
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
Total provision (benefit) for income taxes consists of the following:
YEARS ENDED DECEMBER 31,
-----------------------------
1998 1997 1996
-------- -------- -------
(IN THOUSANDS)
Current:
Federal............................................ $ 20 $ (192) $ --
State.............................................. 87 373 --
-------- -------- -------
107 181 --
Deferred:............................................ (78,214) (31,536) --
-------- -------- -------
Total provision (benefit) for income
taxes:................................... $(78,107) $(31,355) $21,953(1)
======== ======== =======
- ---------------
(1) Provision includes combination related adjustments and excludes a one time
non-cash deferred tax charge of $30.1 million.
The differences between the statutory federal income taxes and the
Company's effective taxes is summarized as follows (in thousands):
YEARS ENDED DECEMBER 31,
-----------------------------
1998 1997 1996
-------- -------- -------
Statutory federal income taxes........................ $(78,982) $(30,892) $22,605
State income tax, net of federal benefit.............. 57 242 80
Section 29 tax credits................................ -- (850) (947)
Capital loss valuation allowance...................... 875 -- --
Other................................................. (57) 145 215
-------- -------- -------
Provision (benefit) for income taxes.................. $(78,107) $(31,355) $21,953
======== ======== =======
The principal components of the Company's net deferred income tax liability
at December 31, 1998 are as follows:
YEARS ENDED DECEMBER 31,
------------------------
1998 1997
---------- -----------
(IN THOUSANDS)
Deferred income tax assets
Commodity price risk management activities................ $ 3,940 $ 822
Net operating loss........................................ 12,092 4,798
Capital loss.............................................. 5,055 --
Other..................................................... 5,983 5,235
-------- ---------
$ 27,070 $ 10,855
-------- ---------
Deferred income tax liabilities
Depreciation, depletion and amortization.................. $(55,369) $(116,257)
Other..................................................... (2,659) (4,645)
-------- ---------
(58,028) (120,902)
Valuation allowance......................................... (875) --
-------- ---------
Net deferred income tax liability................. $(31,833) $(110,047)
======== =========
F-14
60
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As a result of the acquisition of Coda, the Company succeeded to net
operating loss carryforwards ("NOLs") for income tax purposes that expire from
1999 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, 1998, the
Company estimates that approximately $12.0 million of the NOLs is available to
offset future income. In addition to the NOLs, at December 31, 1998, the Company
has approximately $14.4 million of capital loss carry forwards which may be used
to offset capital gains realized over the next five years. A valuation allowance
of $2.5 million was established against the capital loss carryforward since this
amount is not expected to meet the realization test. The Company also has $0.6
million of alternative minimum tax ("AMT") credit carryovers. AMT credits may be
carried forward indefinitely.
SECTION 29 TAX CREDIT
The natural gas production from wells drilled on certain of 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 $1.05 per
MMBtu of natural gas produced from Devonian Shale, is computed by reference to
the price of crude oil and is phased out as the price of oil exceeds $23.50 in
1979 dollars (as adjusted for inflation) with complete phaseout if such price
exceeds $29.50 in 1979 dollars (as adjusted for inflation). Under this formula,
the commencement of phaseout would be triggered if the average price for crude
oil rose above approximately $48 per Bbl in current dollars. The Company
estimates that it generated approximately $0.7 million of Section 29 Tax Credits
in 1998. 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 May 24, 1989 to
September 1, 1996 qualify for an exemption from the 7.5% severance tax in Texas
on natural gas and natural gas liquids produced by such wells prior to August
31, 2001. The natural gas production from wells drilled on certain of 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).
F-15
61
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1998, the Company had entered into hedging
transactions with respect to a significant portion of its estimated oil and gas
production for 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,
1998:
PRODUCTION PERIODS
-------------------------------------------
1999 2000 2001 2002 TOTAL
------- ------- ------ ---- -------
Gas --
Price swaps -- receive fixed price (thousand
MMBtu)(1)(5).................................. 10,340 5,490 -- -- 15,830
Average price, per MMBtu...................... $ 2.21 $ 2.24 $ -- $-- $ 2.22
Collars and options (thousand MMBtu)(2)(6)....... 9,125 14,330 3,650 -- 27,105
Average floor price, per MMBtu................ $ 1.74 $ 2.64 $ 1.25 $-- $ 2.15
Average ceiling price, per MMBtu.............. $ 1.95 $ 1.41 $ 2.75 $-- $ 1.77
Price swaps -- pay fixed price (thousand
MMBtu)(3)..................................... 1,060 -- -- -- 1,060
Average price, per MMBtu...................... $ 2.27 $ -- $ -- $-- $ 2.27
Basis swaps (thousand MMBtu)(4).................. 13,688 5,490 -- -- 19,178
Average basis differential, per MMBtu......... $ (.32) $ (.57) $ -- $-- $ (0.39)
Oil --
Price swaps -- receive fixed price
(MBbls)(1)(7)................................. 385 503 255 -- 1,143
Average price, per Bbl........................ $ 18.40 $ 18.17 $17.80 $-- $ 18.16
Collars and options (MBbls)(2)................... 843 81 -- -- 924
Average floor price, per Bbl.................. $ 17.69 $ 17.69 $ -- $-- $ 17.69
Average ceiling price, per Bbl................ $ 20.11 $ 20.15 $ -- $-- $ 19.33
- ---------------
(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.
F-16
62
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(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 3,665, 724, 6,410, and 4,555 thousand MMBtu of swaps in
1999 through 2002, respectively, that are extendable at the election of the
counterparty. Also, does not include 3,660 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.
(6) Does not include 1,825 thousand MMBtu of collars in 2000 that are extendable
at the election of the counterparty.
(7) 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. These financial counterparties all have 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 $1.9 million, $(13.1) million and $(0.1)
million for 1998, 1997 and 1996, respectively, was included in Commodity Price
Risk Management revenues. As of December 31, 1998, the Company had no accrued
liabilities settled derivative contracts and as of December 31, 1997, had
accrued liabilities of $0.6 million for settled derivative contracts. 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 1998
results of operations included an aggregate pre-tax gain of $22.8 million
related to these activities which included (1) net premiums received totaling
$3.9 million and (2) 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, 1998 of $18.9 million, all included in Commodity
Price Risk Management revenues. At December 31, 1998, the Company's consolidated
balance sheet reflects $21.1 million and $10.1 million of price risk management
assets and liabilities, respectively.
The 1997 results of operations included an aggregate pre-tax gain of $6.6
million related to these activities which included (1) net premiums received
totaling $11.5 million and (2) 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, 1997 of $4.9 million, all included in
Commodity Price Risk Management revenues. At December 31, 1997, the Company's
consolidated balance sheet reflects $1.7 million and $9.6 million of price risk
management assets and liabilities, respectively.
F-17
63
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1998, that do not qualify for hedge accounting:
PRODUCTION PERIODS
-----------------------------------
1999 2000 2001 TOTAL
------- ------ ------ -------
Gas --
Straddles (thousand MMBtu)(1)......................... 2,895 -- -- 2,895
Average price, per MMBtu........................... $ 2.36 $ -- $ -- $ 2.36
Calls bought (thousand MMBtu)(2)...................... 1,820 1,520 -- 3,340
Average price, per MMBtu........................... $ 2.93 $ 3.00 $ -- $ 2.96
Calls Sold (thousand MMBtu)(2)........................ 10,020 7,320 -- 17,340
Average price, per MMBtu........................... $ 2.58 $ 2.78 $ -- $ 2.66
Puts Sold (thousand MMBtu)(2)......................... 3,660 600 -- 4,260
Average price, per MMBtu........................... $ 2.06 $ 2.00 $ -- $ 2.05
Price Swaps -- pay fixed price (thousand MMBtu)....... -- -- -- --
Average price, per MMBtu........................... $ -- $ -- $ -- $ --
Price Swaps -- receive fixed price (thousand
MMBtu)(4).......................................... 17,345 7,320 -- 24,665
Average price, per MMBtu........................... $ 2.28 $ 2.30 $ -- $ 2.29
Oil --
Straddles (MBbls)(1).................................. 215 25 -- 240
Average price, per Bbl............................. $ 17.48 $17.48 $ -- $ 17.48
Price Swaps-- receive fixed price (MBbls) (3)(5)...... 2,304 1,051 139 3,494
Average price, per Bbl............................. $ 19.65 $19.27 $17.65 $ 19.46
Calls Bought (MBbls)(2)............................... -- -- -- --
Average price, per Bbl............................. $ -- $ -- $ -- $ --
Calls Sold (MBbls)(2)................................. 1,972 1,011 293 3,276
Average price, per Bbl............................. $ 21.46 $19.86 $19.10 $ 20.76
Puts Sold (MBbls)(2).................................. 491 56 -- 547
Average price, per Bbl............................. $ 15.68 $15.33 $ -- $ 15.64
Puts Bought (MBbls)(2)................................ 885 404 38 1,327
Average price, per Bbl............................. $ 19.99 $17.82 $18.12 $ 19.28
- ---------------
(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) 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.
F-18
64
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(4) On these trades, protection of 9,125, 3,650 and 1,825 thousand MMbtu per day
disappear in any month that the respective NYMEX Reference Price is below
$2.00, $1.80 and $1.70 in 1999.
(5) Does not include 600 and 360 MBbls of oil swaps for 1999 and 2000,
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.
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, 1998 and 1997. 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, 1998 DECEMBER 31, 1997
------------------- -------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- -------- -------- --------
(IN THOUSANDS)
Cash and cash equivalents................... $ 2,435 $ 2,435 $ 12,260 $ 12,260
Marketable equity securities................ -- -- 28,884 28,884
Long-term debt.............................. 294,990 277,180 352,090 358,100
Interest rate swaps......................... -- 196 -- (3,579)
Oil and gas commodity -- Hedges............. -- 4,584 (590) (1,942)
-- Non-hedges...... 11,028 14,368 (7,367) (7,367)
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, 1998 and
1997.
CASH AND CASH EQUIVALENTS
The carrying amounts approximate fair value because of the short maturity
of those instruments.
MARKETABLE EQUITY SECURITIES
In June 1997 the Company purchased 2,940,000 shares of common stock of
Hugoton Energy Corp. ("Hugoton") at $10.50 per share for a total investment of
$30.9 million. At December 31, 1997 a non-cash investment valuation provision in
the amount of $2 million was charged to stockholder's equity to reflect the
value of this investment at that date. In March 1998, Hugoton was acquired by
Chesapeake Energy Corporation ("CHK"). In the merger each share of Hugoton
common stock was converted into 1.3 shares of CHK common stock. During 1998 the
Company disposed of its holdings in CHK and realized a loss of $14.4 million.
On June 12, 1998, the Company, through its wholly-owned Canadian
subsidiary, purchased approximately $10.5 million of 5% Convertible Preferred
Stock of Big Bear Exploration, Ltd. ("Big Bear"), a Canadian oil and gas
company, at approximately $0.85 per share with each share convertible into one
common share of Big Bear. Through a subsequent restructuring agreement, Belco's
preferred stock holdings were converted to common stock and then subject to an
11:1 reverse stock split.
F-19
65
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As a result of the substantial decline in the market value of Big Bear
securities currently owned by the Company, a $9.7 million impairment provision
was recorded during the fourth quarter of 1998.
LONG-TERM DEBT
The fair value of the Company's revolving credit facility debt of $29.5
million is assumed to be the same as the carrying value because the interest
rate is variable and is reflective of market rates. The fair value of the
10 1/2% Notes is based upon the quoted market prices for that issue. The fair
value of the 8 7/8% Notes is based upon estimates provided to 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 usually required in interpreting market data, and the use of
different market assumptions or estimation methodologies could result in
different estimates of fair value.
NOTE 8 -- COMMITMENTS AND CONTINGENCIES
FUTURE CONTINGENCIES RELATED TO THE MOXA ARCH PROGRAMS
From 1992 to 1994, 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, 1998, the
Programs have invested approximately $130 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 through December 31, 1998.
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 14, Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves (SEC basis using
F-20
66
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1998.
LEASE COMMITMENTS
At December 31, 1998, the Company had operating leases covering office
space. Minimum rental commitments under such operating leases are as follows (in
thousands):
YEAR ENDING DECEMBER 31
-----------------------
1999........................................................ $316
2000........................................................ 44
----
Total............................................. $360
====
For the years ended December 31, 1998, 1997 and 1996, total rental expense was
approximately $512,000, $438,000 and $329,000, respectively.
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,
----------------------------
1998 1997 1996
-------- ------- -------
Cash paid (received) during the year for (in thousands):
Interest, including amounts capitalized................. $26,139 $ 307 $ --
Income and other taxes, net of (refunds)................ (788) $1,345 $4,000
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.
F-21
67
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
MAJOR CUSTOMERS
Oil and gas sales for 1998 include $28.9 million and $16.9 million in
revenues received from two customers. Also, 1998 revenues included net gains in
the amount of $24.8 million related to Commodity Price Risk Management
Activities. Oil and gas sales for 1997 include $40.6 million, $27.9 million,
$25.5 million in revenues received from three customers. Also, 1997 revenues
include Commodity Price Risk Management net losses totaling $6.5 million. Oil
and gas sales for 1996 include $44.6 million, $37.7 million and $11.7 million in
revenues received from three customers and Commodity Price Risk Management
losses of $5.9 million. No other customers individually accounted for 10 percent
or more of revenues.
NOTE 11 -- EMPLOYEE BENEFIT PLANS
RETIREMENT PLAN
The Company provides a 401(k) and savings plan for all its full-time
employees. The plan qualifies under Section 401(k) of the Internal Revenue Code
as a salary reduction plan. Under the plan, but subject to certain limitations
imposed under the Internal Revenue Code, eligible employees are permitted to (a)
defer receipt of up to 15 percent of their compensation on a pre-tax basis
(salary deferral contributions) or (b) contribute up to 10 percent of their
compensation to the plan on an after-tax basis. The plan provides for a Company
matching contribution in an amount equal to 50 percent (75% for employees with
more than three years of service) of a participant's salary deferral
contributions that are not in excess of 6 percent of such participant's
compensation. The plan also permits 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 1998 and 1997, the Company incurred contribution expenses of
$398,000 and $99,000, 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 did not grant
any units during 1998. The Company granted 320,000 and 250,000 performance units
during 1997 and 1996, respectively. As of December 31, 1998 the Company has made
no cash payments in connection with this plan.
NOTE 12 -- CAPITAL STOCK
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
F-22
68
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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, 1998, 1997 and 1996 is
presented in the table below (in thousands, except per share amounts):
YEARS ENDED DECEMBER 31,
------------------------------
1998 1997 1996
--------- -------- -------
Basic net income (loss) per Common Share:
Net income (loss).................................. $(152,963) $(56,908) $42,633
--------- -------- -------
Weighted average shares of common stock
outstanding(1)(4).................................. 31,529 31,538 29,986
--------- -------- -------
Basic net income (loss) per share:................... $ (4.85) $ (1.80) $ 1.42
========= ======== =======
Diluted net income (loss) per share.................. $(152,963) $(56,908) $42,633
========= ======== =======
Weighted average shares of common stock
outstanding(1)(4).................................. 31,529 31,538 29,986
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................................ 31,529 31,538 30,039
--------- -------- -------
Diluted net income (loss) per share.................. $ (4.85) $ (1.80) $ 1.42
========= ======== =======
- ---------------
(1) Includes shares issued and outstanding plus the restricted stock vested. A
total of 80,628 shares of restricted stock grants were not vested as of
December 31, 1998.
(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 1998 and 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-23
69
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, 1998 and 1997 and the changes during the year then ended is presented below:
1998 1997
----------------------------- -----------------------------
WEIGHTED WEIGHTED
SHARES UNDER AVERAGE SHARES UNDER AVERAGE
OPTION EXERCISE PRICE OPTION EXERCISE PRICE
------------ -------------- ------------ --------------
Outstanding, beginning of year............ 960,500 $20.31 409,000 $20.91
Granted................................. 433,000 9.82 561,000 19.87
Exercised............................... -- -- -- --
Forfeited............................... (239,500) 19.37 (9,500) (19.00)
---------- ------ ---------- ------
Outstanding, end of year.................. 1,154,000 $16.25 960,500 $20.31
========== ====== ========== ======
Exercisable, end of year.................. 201,500 $20.24 81,900 $21.12
========== ====== ========== ======
Available for grant, end of year.......... 1,254,000 1,365,100
========== ==========
Weighted average fair value of options
granted during the year................. $ 10.36 $ 9.82
========== ==========
The following table summarizes information about stock options outstanding
at December 31, 1998.
OPTIONS OUTSTANDING
--------------------------------------- OPTIONS EXERCISABLE
WEIGHTED -------------------------------
NUMBER AVERAGE WEIGHTED NUMBER WEIGHTED
OUTSTANDING AT REMAINING AVERAGE EXERCISABLE AT AVERAGE
DECEMBER 31, CONTRACTUAL EXERCISE DECEMBER 31, EXERCISE
RANGE OF PRICES 1998 LIFE PRICE 1998 PRICE
--------------- -------------- ----------- -------- -------------- --------------
$7.41 - $ 11.00................... 398,000 9.41 $ 9.32 -- --
$12.47 - $17.63................... 35,000 9.27 $15.42 -- --
$18.88 - $28.13................... 713,000 8.15 $20.02 198,300 $20.11
$28.81 - $29.00................... 8,000 7.43 $28.88 3,200 $28.88
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) for
calendar years 1998 and 1997 would have been reduced to the pro forma amounts
indicated below (in thousands, except for per share amounts):
1998 1997
--------- --------
Net Income (Loss)
As Reported............................................... $(152,963) $(56,908)
Pro Forma................................................. $(154,625) (57,784)
Basic and Diluted Net Income (Loss) Per Share
As Reported............................................... $ (4.85) $ (1.80)
Pro Forma................................................. $ (4.90) $ (1.80)
F-24
70
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 1998 and 1997, respectively: risk-free interest rate of 5.60
and 6.35 percent, expected volatility of 49.0 and 46.6 percent, expected lives
of 6.0 and 5.7 years and no dividend yield.
Under the Stock Incentive Plan, participants may be granted stock without
cost (restricted stock). During 1998 and 1997, the Company granted 34,700 and
5,100 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 $15.69
and $24.44 per share, respectively. At December 31, 1998, 80,828 shares remained
unvested, net of 11,700 shares forfeited. The weighted average fair value of
shares forfeited was $21.31. 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 1998 and 1997,
$344,100 and $192,000, respectively, was charged to costs and expenses relating
to the Plan.
NOTE 13 -- SUPPLEMENTAL QUARTERLY FINANCIAL DATA (IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS):
QUARTERS
----------------------------------------
FIRST SECOND THIRD FOURTH
-------- -------- ------- --------
(UNAUDITED)
1998
Revenues.......................................... $ 33,351 $ 37,503 $34,690 $ 45,186
======== ======== ======= ========
Costs and Expenses................................ $119,286 $108,879 $29,423 $118,805
======== ======== ======= ========
Net Income (Loss)................................. $(59,393) $(43,846) $ 3,439 $(47,756)
======== ======== ======= ========
Basic and Diluted Net Income (Loss) Per Common
Share.......................................... $ (1.90) $ (1.43) $ 0.05 $ (1.57)
======== ======== ======= ========
1997
Revenues.......................................... $ 31,659 $ 29,089 $23,645 $ 42,367
======== ======== ======= ========
Costs and Expenses................................ $ 13,433 $ 14,439 $13,450 $173,701
======== ======== ======= ========
Net Income (Loss)................................. $ 11,984 $ 9,632 $ 6,703 $(85,243)
======== ======== ======= ========
Basic and Diluted Net Income (Loss) Per Common
Share.......................................... $ 0.38 $ 0.31 $ 0.21 $ (2.70)
======== ======== ======= ========
F-25
71
BELCO OIL & GAS CORP. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The sum of the individual quarterly pro forma basic and diluted net income
(loss) per share amounts may not agree with year-to-date pro forma basic and
diluted net income per share as each period's computation is based on the
weighted average number of common shares outstanding during that period. In
addition, certain potentially dilutive securities were not included in certain
of the quarterly computations of diluted net income per common share because to
do so would have been antidilutive.
NOTE 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, 1998 and 1997 (in thousands):
1998 1997
---------- --------
Proved properties........................................... $ 931,218 $793,475
Unproved properties......................................... 74,935 86,172
---------- --------
Total capitalized costs..................................... 1,006,153 879,647
Less-- Accumulated depreciation, depletion and
amortization.............................................. (566,613) (282,750)
---------- --------
Net capitalized costs....................................... $ 439,540 $596,897
========== ========
COSTS NOT BEING AMORTIZED
The following table sets forth a summary of unproved oil and gas property
costs not being amortized at December 31, 1998, by the year in which such costs
were incurred (in thousands):
1998 1997 1996 1995 1994 TOTAL
------ ------- ---- ------ ---- -------
Leasehold and seismic.............. $7,880 $64,778 $846 $1,386 $45 $74,935
COSTS INCURRED
The following table sets forth the costs incurred in oil and gas
acquisition, exploration and development activities as of December 31, 1998,
1997 and 1996 (in thousands):
1998 1997 1996
-------- -------- --------
Property Acquisitions Costs --
Proved(1).......................................... $ 56,695 $443,930 $ 9,871
Unproved........................................... 14,414 24,226 64,530
Exploration costs.................................... 18,597 46,939 17,444
Development costs.................................... 37,969 59,571 50,433
Capitalized interest................................. 5,123 3,742 434
Property sales....................................... (6,292) (13,949) --
-------- -------- --------
Total costs incurred....................... $126,506 $564,459 $142,712
======== ======== ========
- ---------------
(1) Acquisition of proved properties in 1997 includes $437.4 million relative to
the acquisition of Coda of which $50 million was allocated to unproved
property costs.
F-26
72
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, 1998, 1997 and 1996 (in thousands):
1998 1997 1996
--------- -------- --------
Oil and gas revenues (including commodity price risk
management activities)............................ $ 149,000 $123,515 $113,743
Costs and expenses --
Lease operating expenses.......................... 36,969 9,365 7,024
Production taxes.................................. 3,878 3,393 823
Impairment of oil and gas properties.............. 229,000 150,000 --
Depreciation, depletion and amortization.......... 54,863 46,684 40,904
--------- -------- --------
Results of operations from producing activities
before income taxes............................... (175,710) (85,927) 64,992
Provision (benefit) for income taxes................ (61,498) (30,537) 22,095
--------- -------- --------
Results of operations from producing activities..... $(114,212) $(55,390) $ 42,897
========= ======== ========
Amortization rate per Mcf equivalent, recurring..... $ 0.88 $ 0.81 $ 0.73
========= ======== ========
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,
1998, 1997 and 1996 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-27
73
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.
F-28
74
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATING TO PROVED OIL AND GAS RESERVES
DECEMBER 31,
------------------------------------
1998 1997 1996
---------- ---------- ----------
(IN THOUSANDS)
Future cash inflows(2)................................... 1,215,691 $1,569,976 $1,071,550
Future production costs.................................. (405,171) (531,583) (253,159)
Future development costs................................. (99,342) (100,427) (71,061)
---------- ---------- ----------
Future net inflows before income taxes(2)................ 711,178 937,966 747,330
Discount at 10% annual rate.............................. (350,562) (427,562) (331,800)
---------- ---------- ----------
Discounted future net cash flows before income taxes..... 360,616 510,404 415,530
Pro forma discounted future income taxes(1).............. (7,457) (84,196) (134,957)
---------- ---------- ----------
Standardized measure of discounted future net cash
flows.................................................. $ 353,159 $ 426,208 $ 280,573
========== ========== ==========
- ---------------
(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 $32.6,
$146.4 and $245.9 million for the years 1998, 1997 and 1996, respectively.
(2) Oil and gas commodity hedges included in future cash inflows totaled $4.6
million, $5.9 million and ($60.8) million at December 31, 1998, 1997, and
1996, respectively, and such hedges included in discounted future net cash
flows before income taxes totaled $4.3 million, $5.5 million and ($55.2)
million at December 31, 1998, 1997 and 1996, respectively.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
1998 1997 1996
--------- -------- --------
(IN THOUSANDS)
Balance, beginning of year.................................. 426,208 $280,573 $148,509
Sales and transfers of oil and gas produced, net of
production costs.......................................... (83,353) (111,819) (111,780)
Net change in sales price and production costs.............. (142,014) (216,169) 145,133
Extensions and discoveries.................................. 29,730 65,741 153,920
Purchases of minerals in place.............................. 66,409 312,148 7,843
Sale of reserves in place................................... (1,401) -- --
Changes in estimated future development costs............... 21,382 32,222 24,618
Revisions in quantities..................................... (39,163) (9,099) 50,309
Accretion of discount....................................... 51,040 41,553 20,651
Other, principally revisions in estimates of timing of
production................................................ (53,923) (22,267) (81,673)
Change in income taxes...................................... 78,244 53,325 (76,957)
--------- -------- --------
Balance, End of year........................................ $ 353,159 $426,208 $280,573
========= ======== ========
F-29
75
RESERVE QUANTITY INFORMATION
PROVED RESERVES
OIL GAS
------- -------
(MBBLS) (MMCF)
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
------ -------
Purchases of minerals in place............................ 9,800 25,903
Extensions, discoveries and other additions............... 249 34,279
Revisions of previous estimates(1)........................ (3,775) (33,977)
Sales of minerals in place................................ (203) (649)
Production................................................ (4,177) (37,208)
------ -------
Balance at December 31, 1998................................ 53,054 285,533
====== =======
PROVED DEVELOPED RESERVES
December 31, 1995........................................... 1,838 140,725
December 31, 1996........................................... 2,070 184,904
December 31, 1997........................................... 41,255 226,071
December 31, 1998........................................... 41,475 213,449
- ---------------
(1) Revisions include the reduction of previously recoverable quantities,
primarily of oil and to a lesser extent natural gas resulting from the use
of lower oil and gas prices.
F-30
76
EXHIBIT INDEX
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(Incorporated by reference from Exhibit 4.3 of the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1997).
4.4 -- Exchange and Registration Rights Agreement dated
September 23, 1997 by and among 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. (Incorporated by reference from
Exhibit 4.7 of the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1997).
4.8 -- Third Supplemental Indenture dated as of February 25,
1998 by and between 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).
(Incorporated by reference from Exhibit 4.8 of the
Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 1997).
4.9 -- Certificate of Designations of 6 1/2% Convertible
Preferred Stock dated March 5, 1997 (Incorporated by
reference from Exhibit 4.1 of current report on Form 8-K
dated March 11, 1998).
77
DESCRIPTION OF EXHIBIT
----------------------
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).
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).
78
DESCRIPTION OF EXHIBIT
----------------------
10.14 -- Credit Agreement dated as of September 23, 1997 by and
among Belco Oil & Gas Corp. (the 'Borrower'), and The
Chase Manhattan Bank, as administrative agent, and
certain financial institutions named therein as Lenders
(the 'Lenders') (Incorporated by reference to Exhibit
10.1 of 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 the Borrower, 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 the Borrower, the Lenders and The Chase
Manhattan Bank, as administrative agent. (Incorporated by
reference from Exhibit 10.16 of the Company's Annual
Report on Form 10-K for the fiscal year ended December
31, 1997).
*10.17 -- Third Amendment, dated as of May 29, 1998, to the Credit
Agreement, dated as of September 23, 1997, as amended by
the First Amendment and Waiver thereto, dated as of
November 25, 1997, and the Second Amendment and Consent
thereto, dated as of February 25, 1998, by and among the
Borrower, the Lenders and The Chase Manhattan Bank, as
administrative agent.
*10.18 -- Fourth Amendment, dated as of December 21, 1998, to the
Credit Agreement, dated as of September 23, 1997, as
amended by the First Amendment and Waiver thereto, dated
as of November 25, 1997, and the Second Amendment and
Consent thereto, dated as of February 25, 1998, and the
Third Amendment, dated as of May 29, 1998, by and among
the Borrower, the Lenders and The Chase Manhattan Bank,
as administrative agent.
10.19 -- Executive Employment Agreement with Grant W. Henderson
(Incorporated by reference from Exhibit 99.7 of the Coda
Energy, Inc. Current Report on Form 8-K dated October 30,
1995, Commission File No. 0-10955).
10.20 -- Executive Employment Agreement with Jarl P. Johnson
(Incorporated by reference from Exhibit 99.8 of the Coda
Energy, Inc. Current Report on Form 8-K dated October 30,
1995, Commission File No. 0-10955).
*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