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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
or
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-14256
Belco Oil & Gas Corp.
(Exact name of Registrant as specified in its charter)
Nevada 13-3869719
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
767 Fifth Avenue, 46th Floor
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
------------------- ---------------------
Common Stock, par value $.01 per share New York Stock Exchange
6-1/2% Convertible Preferred Stock,
par value $.01 per share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
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Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
YES |X| NO |_|
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. |_|
The aggregate market value of the voting and non-voting common equity
held by non-affiliates of the Registrant at March 15, 2000, was approximately
$105.2 million (based on a value of $8.5625 per share, the closing price of the
Common Stock as quoted by the New York Stock Exchange on such date). 31,092,400
shares of Common Stock, par value $.01 per share, were outstanding on March 15,
2000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 2000
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
PAGE
----
ITEM 1 - BUSINESS..............................................................2
Overview..............................................................2
Primary Operating Areas...............................................3
Costs Incurred and Drilling Results...................................7
Acreage...............................................................8
Productive Well Summary...............................................9
Marketing.............................................................9
Production Sales Contracts...........................................10
Price Risk Management Transactions...................................10
Texas Severance Tax Abatement........................................12
Section 29 Tax Credit................................................12
Regulation...........................................................12
Operating Hazards and Insurance......................................13
Title to Properties..................................................14
Employees............................................................14
Office and Equipment.................................................14
Forward-Looking Information and Risk Factors.........................14
Executive Officers of the Registrant.................................21
Certain Definitions..................................................22
ITEM 2 - PROPERTIES...........................................................24
Oil and Gas Reserves.................................................24
ITEM 3 - LEGAL PROCEEDINGS....................................................25
ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..................25
PART II
ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS............................................................25
ITEM 6 - SELECTED FINANCIAL DATA..............................................26
ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS..............................................27
Overview.............................................................27
Results of Operations - 1999 Compared to 1998........................29
Results of Operations - 1998 Compared to 1997........................30
Liquidity and Capital Resources......................................31
Other................................................................34
ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..........35
ITEM 8 - CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.............37
ITEM 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE...............................................37
PART III
ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..................37
ITEM 11 - EXECUTIVE COMPENSATION..............................................37
ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT......37
ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS......................37
PART IV
ITEM 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K....37
i
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 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 32%, from 67
Bcfe as of December 31, 1992 to 641 Bcfe as of December 31, 1999 with a reserve
life index of approximately 10.6 years based on 1999 production. Average daily
production has increased from 4 MMcfe per day in 1992 to approximately 165 MMcfe
per day in 1999. Similarly, the growth in the Company's EBITDA has been
substantial, increasing from $2.9 million for the year ended December 31, 1992,
to $96.5 million for the year ended December 31, 1999. The Company's low cost
structure is evidenced by its general and administrative expenses of $0.08 per
Mcfe and lease operating expenses of $0.65 per Mcfe in 1999.
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 primarily in Texas. At
December 31, 1999, the Company had estimated proved reserves of 641 Bcfe with a
pre-tax PV10 value of $635 million. As of December 31, 1999, Belco held or
controlled approximately 1.9 million gross (750,000 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 proven properties 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.
2
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, 1999, with
respect to the Company's estimated net proved reserves by operating area.
Approximately 83% of the quantities of proved reserves on an Mcfe basis
aggregating 84% 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."
Proved Reserves
Percent
Gas of
Oil Gas Equivalent Proved
(MBbls) (MMcf)(1) (MMcfe) Reserves
------- --------- ----------- --------
Rocky Mountains.............. 1,497 139,525 148,507 23%
Permian Basin................ 34,372 41,150 247,379 39%
Mid-Continent................ 15,878 48,394 143,663 22%
Gulf Coast-Austin Chalk...... 1,329 93,079 101,055 16%
------ ------- ------- ----
Total...................... 53,076 322,148 640,604 100%
====== ======= ======= ====
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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, 1999, the Company controlled approximately 1,152,531 gross
(351,789 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 23% of the Company's
estimated proved reserves at December 31, 1999 were located in this region. 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 1999, the Company had participated in 229 gross (75 net) wells in
this field with 158 Frontier wells, 18 Dakota wells and 53 dual completions
(both Frontier and Dakota completed in the same well bore). Average net
production for the year ended December 31, 1999, was approximately 22 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 8 wells (5.6 net) in 1999 and anticipates drilling
approximately 12 wells in 2000. See "-- Regulation -- Environmental Regulation."
3
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, 1999, the
Company had spent approximately $15 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, now Santa Fe Snyder ("Santa Fe") 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, Santa Fe is the operator. A total of 6
wells have been drilled to date on this acreage. The aggregate total gross pro-
ducing rate was approximately 3.1 MMcfe per day gross in December 1999. Two
wells have been drilled in the Big Horn Basin and were producing at a com-
bined rate of 265 Mcfe per day as of December 31, 1999. At least one well is
planned in 2000.
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. The Company is in negotiations to set up
drilling units for exploration in 2000.
The Company expects to participate in a series of exploratory wells in
these basins over the next 12 to 24 months with UPR, Santa Fe, Tom Brown and
Yates serving as operators for most wells. The wells will target multiple forma-
tions, with the Mesa Verde and Frontier formation the most frequent targets. If
initial results are successful, these projects hold the potential for multi-well
developmental drilling programs for the Company over the next several years.
Belco expects to drill and operate one well in 2000.
Permian Basin
Approximately 39% of the Company's estimated proved reserves at December
31, 1999 were located in the Company's Permian Basin core area. These reserves
are concentrated in the Andrews Unit, the Roundtop Unit, 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 2,560 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 and the Shafter Lake San Andres Unit.
4
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 occuring in
late 1998. Gross production in December 1999 was approximately 765 BOPD with
injection of over 5,000 barrels of water per day. The Company anticipates
continued expansion of its waterflood operations during 2000 by drilling 6
wells and converting 2 wells to injection. The Company also believes that pro-
duction from this waterflood unit can be enhanced with the use of CO(2) or sur-
factants with flooding.
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
approximately 540 BOPD in December 1999. 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 2000.
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 790 BOPD in 1999.
The Company has drilled 42 infill 20 acre locations since becoming operator of
the unit in early 1993. In 2000, the Company plans to drill 24 infill wells to
continue the downspacing effort. In addition, the Company believes a large part
of this field has potential for 10 acre infill wells as well as CO(2) potential.
Mid-Continent Region
The Company's Mid-Continent operations are currently focused in Oklahoma,
north Texas and Kansas, where approximately 22% of its total estimated proved
reserves at December 31, 1999 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 790 BOPD in December 1999. The Company drilled 2
wells during 1999. Plans for 2000 include drilling 3 infill production wells and
the continued expansion of water injection to the south.
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 1999 was approximately 1,850 BOPD. The Company has a 44.1% working
interest in this unit. A total of 8 wells were drilled in 1999. 2000 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 1999 gross production was
approximately 350 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 Rhombochasm, Katz, Electra and Burkburnett Fields represent the
properties with the most significant value in the north Texas region. The Com-
pany has drilled 289 wells in these fields. In addition to the Company's exten-
sive inventory of oil and gas opportunities in the north Texas region, the Com-
pany owns three electrical distribution systems and has extensive field facili-
ties.
5
Rhombochasm Field. The Company acquired a 37.5% working interest in the
Rhombochasm Field from the operator, Burnett Oil Company, in early 1994. The
Rhombochasm Field encompasses approximately 3,200 acres in Cottle County, Texas.
Production is from the Bend Conglomerate formation at an average depth of 8,000
feet. Gross field production in December 1999 was approximately 90 BOPD and
10,320 Mcfpd. During 1999, the Company participated in the drilling of 3 wells.
The Company anticipates participating in the drilling of 3 wells during 2000.
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 these leases. Production is from
two Strawn sands at approximately 4,800 feet and 5,100 feet. Gross oil
production was approximately 320 BOPD in December 1999. In 1998, the Company
began reactivating the waterflood in the zone at 4,800 feet with response
occuring in late 1998. The Company anticipates continuing reactivation of the
waterflood by activating three shut-in injectors and drilling one producer in
2000.
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 1999 averaged approximately 1,064
BOPD. In 1999 the Company drilled 1 producing well.
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
1999 was approximately 425 BOPD.
Gulf Coast-Austin Chalk
Texas -- Giddings Field. Approximately 15% of the Company's estimated total
proved reserves at December 31, 1999 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, 1999, average net production from this
field was approximately 61 MMcfe per day. Through December 31, 1999, the Company
had drilled 260 gross (86 net) wells in this field and continues to control
approximately 217,000 gross (69,000 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. The Company serves as operator for portions of the River Bend
prospect area.
Four wells were drilled in the Independence area in 1999. Belco
participated in the first well in this prolific area in 1998. Five additional
wells are planned in 2000.
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
6
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."
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, 1999, the Company owned or had the right to acquire
approximately 154,783 net acres in this trend. Low oil prices prompted the
postponement of drilling activity during 1998 and most of 1999. In late 1999,
Belco added an additional lateral to the Turner #1 well. At year-end this 100%
working interest well was producing 700 BOPD. One additional reentry is planned
in 2000.
Other Operating Areas
HLM Project. The Company has obtained 3-D seismic on approximately 140
square miles located mainly in Montgomery and Liberty Counties. This seismic was
interpreted in 1999 and a total of 5 wells were drilled for shallow Yegua, Frio
and Wilcox target. At December 31, 1999 the wells were producing an aggregate
of 6 Mmcfe per day. The Company has a 79% working interest in the formations
shallower than Wilcox. The Company has identified several additional shallow
prospects that it will pursue in 2000.
Also in 1999, Belco made a trade with Newfield Exploration Company
("Newfield") for 33% of the Wilcox rights. Newfield will pay Belco's remaining
46% share of the costs to drill Wilcox wells until Belco receives a total of
$2.3 million. Belco is operator for all of the drilling activities. Two Wilcox
tests are planned in 2000.
Costs Incurred and Drilling Results
Drilling Activity
The following table sets forth the wells participated in by the Company
during the periods indicated. In the table, "gross" refers to the total wells in
which the Company has a working interest, and "net" refers to gross wells
multiplied by the Company's working interest therein.
Year Ended December 31,
----------------------------------------------------------
1999 (1) 1998 (1) (2) 1997 (3)
-------------------------------------------------------------
Gross Net Gross Net Gross Net
Development:
Productive...... 46.0 29.4 69.0 47.1 54.0 23.1
Non-productive.. 2.0 1.0 1.0 1.0 4.0 2.2
----- ----- ----- ----- ----- -----
Total... 48.0 30.4 70.0 48.1 58.0 25.3
==== ==== ==== ==== ==== ====
Exploratory:
Productive...... 11.0 8.2 23.0 9.4 20.0 13.7
Non-productive.. 3.0 2.5 7.0 4.0 18.0 6.4
----- --- ----- ---- ----- ----
Total... 14.0 10.7 30.0 13.4 38.0 20.1
==== ==== ==== ==== ==== ====
- ----------
(1) Includes 15 gross (11.2 net) and 7 gross (4 net) wells in progress at
December 31, 1999 and 1998, respectively.
(2) Excludes 343 gross (175 net) productive wells acquired during 1998.
(3) Includes results for Coda Energy, Inc. ("Coda") since November 26, 1997, the
date Coda was acquired by the Company.
7
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.
Year Ended December 31,
------------------------------------
1999 1998 1997 (1)
-------- -------- --------
Net Production Data:
Oil (MBbl)................................. 3,439 4,177 1,295
Gas (MMcf)................................. 39,737 37,208 49,710
Gas equivalent (MMcfe)..................... 60,370 62,272 57,479
Oil and Gas Sales ($ in 000's)(2)............ $139,242 $124,199 $129,994
Average Sales Price (Unhedged) (2):
Oil ($ per Bbl)............................ $17.49 $13.17 $19.28
Gas ($ per Mcf)............................ $1.99 $1.86 $2.11
Costs ($ per Mcfe):
Oil and gas operating expenses............. $0.65 $0.66 $0.22
General and administrative................. $0.08 $0.08 $0.07
Depreciation, depletion and amortization
of oil and gas properties................ $0.90 $0.90 $0.81
- ----------
(1) Includes results for Coda since November 26, 1997, the date Coda was
acquired by the Company.
(2) Oil and gas sales exclude results related to commodity price risk management
activities which are reported separately.
Development, Exploration and Acquisition Expenditures
The following table sets forth certain information regarding the costs
incurred by the Company in its development, exploration and acquisition
activities during the periods indicated.
Year Ended December 31,
------------------------------------
($'s in thousands)
1999 1998 1997 (1)
-------- -------- ----------
Property acquisitions costs--
Proved........................ $17,608 $56,695 $443,930 (2)
Unproved...................... 10,390 14,414 24,226
Exploration costs............... 10,943 18,597 46,939
Development costs............... 29,576 37,969 59,571
Capitalized interest............ 4,881 5,123 3,742
Property Sales.................. (215) (6,292) (13,949)
--------- -------- ---------
Total net costs incurred...... $73,183 $126,506 $564,459
======= ======== ========
- ----------
(1) Includes results for Coda since November 26, 1997, the date Coda was
acquired by the Company.
(2) Acquisition of proved properties includes $437.4 million (exclusive 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, 1999, the gross and net
acres that the Company owned, controlled or had the right to acquire interests
in both developed and undeveloped acreage. Developed acreage refers to acreage
within
8
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....... 5,123 480 525,140 138,337
Moxa Arch Trend......... 24,861 14,619 23,559 14,227
Wind River Basin........ 2,077 720 336,202 113,440
Big Horn Basin.......... 643 321 291,188 100,012
Denver-Julesburg Basin.. 207,365 2,298 177,939 91,279
Permian Basin............. 97,871 49,497 20 20
Mid-Continent Region:
Oklahoma................ 119,100 39,635 30,475 10,898
North Texas............. 36,593 21,777 640 320
Kansas.................. 37,489 31,488 8,563 8,000
North Dakota............ 0 0 4,000 1,858
Austin Chalk Trend:
Texas-Giddings Field.... 104,370 41,498 216,916 69,014
Louisiana............... 5,330 2,373 183,183 154,783
Other Operating Areas:
Arkansas................ 56 42 6,001 4,383
Michigan-Central Basin.. 1,664 702 71,055 12,554
Gulf Coast.............. 10,254 7,976 49,790 30,871
------- ------- --------- -------
Totals.......... 652,796 213,426 1,924,671 749,996
======= ======= ========= =======
- ----------
(1) Leases covering less than 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, 1999. 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.......... 878.0 344.8
Oil.......... 1,828.0 1,099.8
------- -------
Total.. 2,706.0 1,444.6
======= =======
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.
9
Although the Company seeks to moderate the impact of price volatility
through its commodity price risk management activities, the Company remains
subject to price fluctuations for natural gas sold in the spot market due
primarily to seasonality of demand and other factors beyond the Company's
control. Domestic oil prices generally follow worldwide oil prices, which are
subject to price fluctuations resulting from changes in world supply and demand.
Production Sales Contracts
In Wyoming, the Company sells all of its natural gas, natural gas liquids
and condensate from its Moxa Arch wells under a market sensitive long term sales
contract with Amoco Energy Trading Corporation (the "Amoco Gas Contract"). The
price payable to the Company under the Amoco Gas Contract for 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
currently $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 revenues in
1999 were made to Aquila Southwest Pipeline (25%), Amoco Energy Trading (15%),
GPM Gas Marketing (13%) and EOTT Energy Operating LP (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 estimated oil production and approximately 50%
of its estimated gas production for 2000 and lesser amounts of its estimated
production for 2001 and beyond. The Company continues
10
to evaluate whether to enter into additional such transactions for 2001 and
beyond. In addition, the Company may determine from time to time to terminate
its then existing hedging and other risk management positions.
All of the Company's price risk management transactions are carried out in
the over-the-counter market and not on the New York Mercantile Exchange
("NYMEX"). 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, 1999.
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 $20.00 call on oil for $0.40 a barrel in a given month and prices
averaged $19.00 a barrel for such month, the Company would receive a net
realization per barrel of $19.40 ($19.00 plus the $0.40 premium). However, if
for that month the price of oil averaged $20.00 or higher per barrel, the
Company would receive a net realization of $20.40 (the call price, $20.00, plus
$0.40).
A limited number of these transactions contain negotiated knockout,
extendable or leverage provisions. These provisions either limit price
protection beyond a specific level, contain tiered pricing provisions, allow the
option to be extended for a period of time, or provide for payment based upon a
multiple of the underlying notional volume. The transactions described in this
paragraph and any sold options are required to be marked to market as to their
value on the last day of the accounting period.
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
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).
11
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
$1.06 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 $0.6 and $0.7 million of
Section 29 Tax Credits in 1999 and 1998, 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.
Regulation
General. The oil and gas industry is extensively regulated by federal,
state and local authorities. In particular, oil and gas production operations
and economics are affected by price controls, environmental protection statutes
and regulations, tax statutes and other laws relating to the petroleum industry,
as well as changes in such laws, changing administrative regulations and the
interpretations and application of such laws, rules and regulations. Oil and gas
industry legislation and agency regulation are under constant review for
amendment and expansion for a variety of political, economic and other reasons.
Regulation of Natural Gas and Oil Exploration and Production. 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
12
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 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,
13
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, 1999, the Company had 181 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 approximately $250,000 per annum for office space
and services provided through such office. This fee is indexed to the consumer
price index. The fee is based on the actual cost of such office space pro-rated
to the amount utilized in Company operations. The Company believes the fee
compares favorably to the terms which might have been available from a
non-affiliated party. See "Certain Relationships and Related Transactions." The
Company owns a building in 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
14
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 2000 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. Low oil and natural gas prices reduce 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 moved over a very broad range
during the past two years. 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 and other derivative
type transactions with respect to a portion of its expected future production.
There can be no assurance, however, that such commodity price risk management
transactions will reduce risk or mitigate the effect of any substantial or
extended decline in oil or natural gas prices. Any substantial increase or
extended decline in the prices of oil or natural gas could 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
15
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 25% of the Company's total proved reserves at December 31,
1999 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
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.
16
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. Unpredictable 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." No ceiling limitation writedown was
required for the calendar year 1999. 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 $133.0
million during 1998 and $74.0 million during 1999. For the year 2000, the
Company has budgeted $60 million in capital expenditures for exploration and
development operations. Management believes that the Company will have
sufficient cash provided by operating activities to fund capital expenditures in
2000. 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."
17
Acquisition Risks
The Company continues to pursue the selective acquisition of oil and gas
properties and businesses. Although no definitive agreements, other than matters
disclosed elsewhere in this filing, have been reached regarding any such
acquisitions, if consummated such acquisitions may have a material impact on the
Company's business. Any acquisition by the Company must satisfy the applicable
covenants set forth in the indenture governing the Company's 8-7/8% Senior
Subordinated Notes due 2007 (the "8-7/8% Indenture"), the indenture governing
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 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 currently has
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
18
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.
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."
19
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 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 son Laurence D. Belfer, his brother-in-law Jack
Saltz, their spouses, and certain trusts for their respective children and
grandchildren own approximately 60% of the outstanding shares of the Common
Stock and approximately 16% 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.
20
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 64, 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 board of Enron.
Mr. Belfer received his undergraduate degree from Columbia College (A.B.
1955) and a law degree from the Harvard Law School (J.D. 1958).
Laurence D. Belfer, age 33, 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 41, 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 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.
Dominick J. Golio, age 54, 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 58, 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.
21
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 47, 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 24 years experience in exploring for and exploiting oil and gas
fields both onshore and offshore. He holds a BS in Geological Engineering from
the Colorado School of Mines (1975).
Certain Definitions
The definitions set forth below shall apply to the indicated terms as used
in this 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 tem-
perature 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.
22
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.
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.
23
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 produc-
tion.
See also the Consolidated Financial Statements beginning on page F-1.
ITEM 2 -- PROPERTIES
Oil and Gas Reserves
The following table sets forth information with respect to the Company's
estimated net proved oil and gas reserves as of December 31, 1999. Information
in this 10-K as of December 31, 1999 relating to properties with 83% of the
Company's estimated net proved oil and gas reserves (84% 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
24
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, 1999
-----------------------------------
Proved Proved
Developed Undeveloped Total
--------- ----------- -------
Estimated Proved Reserves:
Gas (Bcf)............................. 224.1 98.0 322.1
Oil (MMBbls).......................... 42.4 10.7 53.1
Total Gas Equivalents (Bcfe)............ 478.3 162.3 640.6
Estimated Future Net Revenue before
Income Taxes (in millions)(1)..........$1,014.9 $239.9 $1,254.8
Present Value of Estimated Future
Net Revenues before Income Taxes
(discounted at 10% per annum)
(in millions)(1)....................... $527.8 $106.9 $634.7
(1) Estimated future net revenue before income taxes represents estimated future
gross revenue to be generated from the production of proved reserves, net
of estimated production and future development costs, using average December
31, 1999 prices, which were $2.14 per Mcf of gas and $23.79 per barrel of
oil without giving effect to commodities price risk management activities
accounted for as hedges. At December 31, 1999, 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 ($8.6) million and ($8.2) million, respectively (based on
oil and gas prices in effect at December 31, 1999), which amounts have not
been subtracted from estimated future net revenue before income taxes and
its present value as shown above. If such amounts were subtracted, estimated
future net revenue before income taxes would equal $1,006.3 million (Proved
Developed) and $1,246.2 million (Total) and present values of such estimated
future net revenues before income taxes would equal $519.2 million (Proved
Developed) and $626.5 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, 1999, no matters were submitted by
the Company to a vote of its security holders.
PART II
ITEM 5-- MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
As of March 15, 2000, the Company estimates there were approximately 123
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, 2000, the Company had 31,092,400 shares outstanding and its closing price on
the NYSE was $8.5625 per share. The high and low sales prices for the Company's
Common Stock during each quarter in the two years ended December 31, 1999 were
as follows:
25
COMMON STOCK
---------------------
High Low
------ ------
1998
First Quarter............ $19.00 $16.75
Second Quarter........... 17.75 8.13
Third Quarter............ 11.25 6.63
Fourth Quarter........... 6.88 4.38
1999
First Quarter............ 6.38 4.75
Second Quarter........... 7.94 5.75
Third Quarter............ 7.56 6.38
Fourth Quarter........... 7.06 4.94
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.
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,
-----------------------------------------------------
1999 1998 1997 1996 1995
---------- ---------- ---------- ---------- -------
(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil and gas sales.......................................$139,242 $124,200 $129,994 $119,710 $68,767
Commodity Price Risk Management Activities
- Cash................................................ 248 5,888 (1,551) 3,417 9,480
- Non-cash............................................ (34,094) 18,912 (4,928) (9,384) --
Interest................................................ 1,134 1,730 3,245 2,653 353
--------- --------- --------- -------- --------
Total revenues............................................ 106,530 150,730 126,760 116,396 78,600
------- ------- ------- ------- ------
Costs and expenses:
Oil and gas operating expenses.......................... 39,168 40,847 12,758 7,847 5,824
Depreciation, depletion and amortization 54,182 56,102 46,684 40,904 27,590
Impairment of oil and gas properties.................... -- 229,000 150,000 -- --
Impairment of equity securities......................... 450 24,216 -- -- --
General and administrative.............................. 4,940 5,216 3,913 3,059 2,597
Interest Expense........................................ 21,021 21,013 1,668 -- --
-------- -------- ------- --------- ---------
Total costs and expenses.................................. 119,761 376,394 215,023 51,810 36,011
------- ------- ------- ------ ------
Income (loss) before income taxes......................... (13,231) (225,664) (88,263) 64,586 42,589
Provision (benefit) for income taxes (1) (4,631) (78,107) (31,355) 21,953 13,852
--------- ---------- ---------- ------- --------
Net income (loss) (1)..................................... $(8,600) $(147,557) $(56,908) $42,633 $28,737
======== ========= ========= ======= =======
Net income (loss) available to common stock $(15,484) $(152,963) $(56,908) $42,633 $28,737
========= ========== ========= ======= =======
Basic and diluted earnings (loss) per common share (1) $(0.49) $(4.85) $(1.80) $1.42 $1.15
======= ====== ======= ===== =====
Weighted average common shares outstanding (2) 31,642 31,529 31,538 29,986 25,000
26
Statement of Cash Flows Data:
Cash flow from operating activities....................... 78,044 86,345 101,523 108,059 62,037
Cash flow from investing activities....................... (74,542) (138,526) (363,136) (143,826) (65,133)
Cash flow from financing activities....................... (3,832) 42,356 230,400 77,684 (2,299)
Capital expenditures...................................... 73,183 126,506 564,459 142,712 71,387
Balance Sheet Data:
Working capital ..........................................$ (8,389)(3) $14,823 $36,757 $48,667 $446
Total assets.............................................. 510,973 505,536 697,109 303,918 145,550
Long-term debt............................................ 306,744 294,990 352,090 -- 22,000
Equity.................................................... 113,972 138,291 184,648 233,203 105,015
- ------------------
(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) Excluding the commodity price risk management mark-to-market balance
sheet items, working capital would have been positive $6.6 million at
December 31, 1999.
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. and its subsidiaries (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 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
27
approximately 51% oil and 49% natural gas. The Company's reserve base was
641 Bcfe with a reserve life index of 10.6 years, based on 1999 production.
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, 1999.
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 66% 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, 1999, 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 2000 and with
respect to lesser portions of its estimated production for 2001 and 2002. 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.
The following table sets forth certain operations data of the Company for
the periods presented:
Year Ended December 31,
-------------------------------------------
1999 1998 1997
------------ ------------ ------------
Oil and Gas Sales (Unhedged) (in thousands)................................. $139,242 $124,200 $129,994
Commodity Price Risk Management (in thousands)
Cash...................................................................... 248 5,888 (1,551)
Non-Cash.................................................................. (34,094) 18,912 (4,928)
Weighted Average Sales Prices (Unhedged):
Oil (per Bbl)............................................................. $17.49 $13.17 $19.28
Gas (per Mcf)............................................................. $1.99 $1.86 $2.11
Net Production Data:
Oil (MBbls)............................................................... 3,439 4,177 1,295
Gas (MMcf)................................................................ 39,738 37,207 49,710
Gas equivalent (MMcfe).................................................... 60,370 62,272 57,479
Gas equivalent (Mcfe-daily)............................................... 165,398 170,609 157,477
Operations Data per Mcfe:
Oil and gas sales revenues (unhedged)..................................... $2.31 $1.99 $2.26
Oil and gas operating expenses............................................ (0.65) (0.66) (0.22)
General and administrative................................................ (0.08) (0.08) (0.07)
Depreciation, depletion and amortization.................................. (0.90) (0.90) (0.81)
------ ------ ------
Pre-tax operating profit (1).............................................. $0.68 $0.35 $1.16
===== ===== =====
28
- ----------
(1) Excluding commodity price risk management activities charges, ceiling
test and securities impairment provisions, interest income and
interest expenses.
Results of Operations - 1999 Compared to 1998
Revenues
Oil and gas sales revenues for the year 1999, excluding the effects of
commodity price risk management activities, increased 12% to $139.2 million
compared to $124.2 million realized in 1998. The year over year increase is due
to higher commodity prices and higher natural gas production partially offset by
lower crude oil production. In 1999, weighted average oil prices realized
(unhedged) totaled $17.49 per barrel, a 33% increase when compared to the $13.17
realized in 1998. The natural gas weighted average prices realized (unhedged)
increased by 7% from $1.86 in 1998 to $1.99 in 1999. Average daily production
volume in 1999 on an Mcfe basis declined by 3% to 165,398 Mcfe.
Commodity price risk management activities resulted in a net pre-tax loss
of $33.8 million for 1999 which included (1) cash realized hedging losses of
$3.2 million, (2) cash realized gains related to non-hedging transactions
totaling $3.4 million, and (3) non-cash unrealized losses for mark-to-market
accounting of $34.1 million. The impact of such activities on an Mcfe basis
amounted to net losses of $0.56 ($0.00 cash gain and $0.56 non-cash loss). This
compares to net gains of $0.40 ($0.09 cash and $0.31 non-cash) per Mcfe for
1998.
Costs and Expenses
Production and Operating Expenses. Production and operating expenses
declined to $39.2 million or 4% in 1999 when compared to the $40.8 million
incurred during 1998. The decrease is identified with cost reduction efforts in
response to lower commodity prices realized in the first half of 1999 combined
with the implementation of other operating efficiencies on newly operated
properties located in Wyoming. On a unit basis, operating costs were $0.65 per
Mcfe for 1999 compared to $0.66 per Mcfe for 1998.
Depreciation, Depletion and Amortization. Recurring depreciation, depletion
and amortization ("DD&A") costs for the year totalled $54.2 million when
compared to the $56.1 million recorded for the prior year. The DD&A rate for the
year was unchanged at $0.90 per Mcfe. For the year 1998, the 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 declined by 5% during 1999 to $4.9 million when compared to the $5.2
million incurred in 1998. The decrease is primarily due to the cost controls
implemented in response to lower commodity prices. The rate per Mcfe for such
costs was unchanged at $0.08 for both years. Exploration related G&A expenses
for 1999 in the amount of $5.5 million have been capitalized to oil and gas
property accounts. The decrease of $0.7 million when compared to 1998 comparable
capitalized amount of $6.2 million principally reflects reduced exploration
activities.
Interest expense is incurred on $150 million of the 8-7/8% Senior
Subordinated Notes due 2007 (the "8-7/8% Notes") issued in September 1997, $109
million of the 10-1/2% Senior Subordinated Notes due 2006 (the "10-1/2% Notes")
and bank debt incurred under the Company's Revolving Credit Facility. Net
interest costs incurred for the year 1999 totalled $25.9 million, with
approximately $4.9 million of this total capitalized to property accounts. The
1999 net total interest cost declined modestly when compared to 1998 when net
total interest costs were $26.1 million, with $5.1 million capitalized.
29
As a result of the substantial decline in the market value of Big Bear
Exploration Ltd. ("Big Bear") securities acquired in June 1998, impairment
provisions were $450,000 and $9.7 million recorded by the Company in 1999 and
1998, respectively. 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 1999
was $13.2 million. This compares to a loss of $225.7 million reported in 1998.
The substantially lower loss reported for 1999 reflects improved commodity
prices and the absence of non-cash ceiling test and securities impairment
provisions of $229.0 million and $24.2 million, respectively, reported in 1998.
Income Taxes
Income tax benefits were recorded for 1999 in the amount of $4.6 million
and $78.1 million for 1998 as a result of reported pre-tax losses.
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
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
30
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.
Liquidity and Capital Resources
General
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, 1999 was set at $150 million with $42.0 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
31
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 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, 1999, 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.
32
The Company entered into interest rate swap agreements converting two
long-term debt fixed rate obligations to floating rate obligations as follows:
Agreement Transaction Fixed Floating Floating Rate
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% 8.195% March 15, 2000 (a)
- -----------------------
(a) Floating rate is redetermined at each six month period following the expira-
tion 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 1999 and 1998 interest expense by approximately
$1.1 and $1.0 million, respectively.
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. Through December 31, 1999, the Company purchased 384,700 shares of
its 6-1/2% preferred stock for a total cost of $5.9 million and 704,900 shares
of its common stock at a total cost of $4.3 million. All such purchases were
made pursuant to the Company's Board approved share re-acquisition program.
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., 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 restructuring agreement closed on January 22, 1999.
Subsequently, Big Bear effected an 11 to 1 reverse split of Big Bear common
shares and Belco, through its wholly-owned Canadian subsidiary, received
1,948,052 common shares or approximately 4.6% ownership at that time, in Big
Bear. In January 2000, shareholders of Big Bear approved its acquisition by Avid
Oil & Gas, Ltd. ("Avid"), a Canadian based energy company providing for Big Bear
shareholders to receive 1 share of Avid common stock for every 15 common shares
of Big Bear. As a result of the transaction described above, the Company
currently owns 129,870 shares of Avid with an approximate market value of
$190,000 (US) as of December 31, 1999.
In September 1999, the Company acquired 25.1 Bcfe of long lived reserves on
producing properties in the Permian Basin and South Texas for approximately
$16.2 million.
In February 2000, the Company closed a $40.5 million acquisition of oil and
gas properties expected to add approximately 2,400 BOE per day to the existing
production base. The transaction was financed through additional borrowings
under the Company's Revolving Credit Facility.
33
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 was
approximately $78.0 and $86.3 million for the years 1999 and 1998, respectively.
The Company had a working capital deficit of $8.4 million as of December 31,
1999, a decrease of $23.2 million from the $14.8 million available as of
December 31, 1998. The deficit is created by the recording of non-cash
mark-to-market losses related to derivatives activities and recorded under
current obligations in the balance sheet as required by current accounting
rules. Excluding the mark-to-market items, working capital would have been
positive $6.6 million at December 31, 1999, before recognizing the unused $108
million available under the Company's revolving credit facility.
Capital Expenditures
For 1999, the Company incurred capital expenditures in the amount of $73.2
million, including approximately $17 million in property acquisitions.
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 2000 capital expenditure budget for exploration and development of
approximately $60 million exclusive of producing property 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 Stock and 6-1/2% Convertible Preferred Stock,
in an aggregate amount not to exceed $10 million. The $10 million authorization
was exhausted in December 1999, and on December 27, 1999 the Board authorized
additional such purchases in an 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 with
respect to a substantial portion of its estimated oil production and
approximately 60% of its natural gas production for the year 2000 with lesser
portions of its production for periods 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.
34
At December 31, 1999 the Company had recorded a net current liability of
$14.9 million. This liability reflected the market value of the Company's
commodity price risk management contracts expiring during 2000. Due to the sus-
tained higher oil prices subsequent to year-end, the Company expects to incur
additional cash settlement costs and non-cash mark-to-market losses related to
its commodity price risk management activities unless prices at March 31, 2000
decline below levels at December 31, 1999.
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 dealt with 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. Given that this date threshold has passed without incidence,
all of the Company's 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") are deemed fully capable and currently operating effectively.
The Company did not separately track the costs associated with the year
2000 compliance effort, as they were not 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 additional costs in connection with this issue.
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, 2000. 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.
35
As of December 31, 1999, 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, 1999. Transactions subsequent to year-end 1999 were not
significant.
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.
Expected Maturity Date
------------------------------------- Fair Value
as of
2000 2001 2002 Total December 31, 1999
---- ---- ---- ----- -----------------
($ in thousands)
Liabilities:
Bank credit facility........... - - $42,000 $42,000 $42,000
Variable rate.................. 6.25% 6.25% 6.25%
Belco 8.875% Notes............. - - - $150,000 (1) $142,000
Belco 10.500% Notes............ - - - $109,000 (2) $112,000
Interest Rate Swaps:
Fixed to Variable.............$235,000 $235,000 $235,000 $ (6,549)
Average pay rate............... 8.92% 9.20% 9.20%
Average receive rate........... 9.56% 9.56% 9.56%
- ----------------
(1) Notes mature 2007
(2) Notes mature 2006
36
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 2000 Annual Meeting of Shareholders (the "Proxy Statement") under the
headings "Election of Directors", "Executive Compensation and Other Information"
and "Section 16(a) Beneficial Ownership Reporting Compliance" and is incorpora-
ted herein by reference. The Proxy Statement will be filed pursuant to Regulat-
ion 14A with the Securities and Exchange Commission not later than 120 days
after December 31, 1999. For information regarding Executive Officers not
appearing in the Proxy Statement, see "Business--Executive Officers of the Reg-
istrant".
ITEM 11 -- EXECUTIVE COMPENSATION
The information required under Item 11 will be contained in the Proxy
Statement under the heading "Executive Compensation and Other Information" and
is incorporated herein by reference.
ITEM 12-- SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required under Item 12 will be contained in the Proxy
Statement under the heading "Security Ownership of Management and Certain
Beneficial Owners" and is incorporated herein by reference.
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.
37
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).
4.6 First Supplemental Indenture dated as of April 25, 1996 amending the Inden-
ture 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 refer-
ence 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).
38
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 offi-
cers 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 Dec-
ember 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 Decem-
ber 30, 1994 (Incorporated by reference to Exhibit 10.7 of the Registra-
tion Statement on Form S-1, Registration No. 333-1034).
10.8 Sale Agreement (Independence) dated as of June 10, 1994 between Chesa-
peake 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. (Incor-
porated 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 Drill-
ing Program (Incorporated by reference to Exhibit 10.16 of the Regis-
tration 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 admin-
istrative agent, and certain financial institutions named therein as Lend-
ers (the "Lenders")(Incorporated by reference to Exhibit 10.1 of Registra-
tion 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 Administra-
tive Agent for the ratable benefit of Lenders. (Incorporated by refer-
ence 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 Bor-
rower, the Lenders and The Chase Manhattan Bank, as administrative agent.
(Incorporated by reference from Exhibit 10.17 of the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1998).
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,
39
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. (Incorporated by reference from Exhibit 10.18 of the Company's
Annual Report on Form 10-K for the fiscal year ended December 31, 1998).
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 First Amendment to Belco Oil & Gas Corp. 1996 Nonemployee Directors' Stock
Option Plan. (Incorporated by reference from Exhibit 10.1 of the Com-
pany's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999,
Commission File No. 1-14256).
*21.1 Subsidiaries of the Registrant.
*23.1 Consent of Arthur Andersen LLP.
*23.2 Consent of Miller and Lents, Ltd.
*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.
None.
40
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 30, 2000
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 30, 2000
- --------------------------- Chairman of the Board of
Robert A. Belfer Directors (Principal
Executive Officer)
/s/ Laurence D. Belfer Vice-Chairman, Chief Operating March 30, 2000
- --------------------------- Officer and Director
Laurence D. Belfer
/s/ Dominick J. Golio Senior Vice President--Finance, March 30, 2000
- --------------------------- Chief Financial Officer,
Dominick J. Golio Treasurer and Secretary
(Principal Financial Officer
and Principal Accounting
Officer)
/s/ Graham Allison Director March 30, 2000
- ---------------------------
Graham Allison
/s/ Daniel C. Arnold Director March 30, 2000
- ---------------------------
Daniel C. Arnold
/s/ Alan D. Berlin Director March 30, 2000
- ---------------------------
Alan D. Berlin
/s/ Grant W. Henderson President and Director March 30, 2000
- ---------------------------
Grant W. Henderson
/s/ Jack Saltz Director March 30, 2000
- ---------------------------
Jack Saltz
/s/ Georgiana Sheldon-Sharp Director March 30, 2000
- ---------------------------
Georgiana Sheldon-Sharp
41
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, 1999 and 1998............ F-3
Consolidated Statements of Operations for the Years Ended December 31,
1999, 1998 and 1997................................................... F-4
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1999, 1998 and 1997..................................... F-5
Consolidated Statements of Cash Flows for the Years Ended December 31,
1999, 1998 and 1997................................................... 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
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, 1999 and
1998, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1999. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the 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, 1999 and 1998, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States.
ARTHUR ANDERSEN LLP
Dallas, Texas
February 23, 2000
F-2
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS December 31,
-------------------
1999 1998
-------- ------
CURRENT ASSETS: (in thousands)
Cash and cash equivalents (including restricted cash
of $800,000 at December 31, 1999).................... $2,105 $2,435
Accounts receivable.................................... 24,870 28,464
Income taxes receivable................................ 6,661 --
Assets from commodity price risk management activities. 2,879 18,643
Other current assets................................... 3,496 1,005
----- -------
Total Current Assets.............................. 40,011 50,547
PROPERTY AND EQUIPMENT:
Oil and gas properties at cost based on full-cost
accounting--
Proved oil and gas properties....................... 1,008,261 931,218
Unproved oil and gas properties..................... 71,075 74,935
Less-- Accumulated depreciation, depletion and
amortization...................................... (619,446) (566,613)
--------- ---------
Net oil and gas property............................... 459,890 439,540
------- -------
Building and other equipment........................... 9,107 8,633
Less-- Accumulated depreciation..................... (2,634) (1,281)
------- -------
Net building and other equipment....................... 6,473 7,352
OTHER ASSETS............................................. 4,599 8,097
----- -----
Total Assets...................................... $510,973 $505,536
======== ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable....................................... $17,970 $18,372
Liabilities from commodity price risk management
activities........................................... 17,822 5,393
Accrued interest....................................... 7,098 6,897
Other accrued liabilities.............................. 5,510 5,064
------- -------
Total Current Liabilities......................... 48,400 35,726
LONG-TERM DEBT........................................... 306,744 294,990
DEFERRED INCOME TAXES.................................... 33,638 31,833
LIABILITIES FROM COMMODITY PRICE RISK MANAGEMENT ACTIVI-
TIES................................................... 8,219 4,696
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares
authorized and 3,985,000 and 4,312,000 outstanding
at December 31, 1999 and 1998, respectively.......... 40 43
Common Stock, $0.01 par value; 120,000,000 shares
authorized; 31,797,300 and 31,609,900 issued and
outstanding at December 31, 1999 and 1998,
respectively......................................... 318 316
Additional paid-in capital............................. 297,225 301,416
Retained earnings deficit.............................. (177,111) (161,627)
Treasury Stock, 704,900 shares......................... (4,317) --
Unearned compensation.................................. (1,430) (1,082)
Notes receivable for equity interest................... (753) (775)
--------- ---------
Total Stockholders' Equity........................ 113,972 138,291
------- ---------
Total Liabilities and Stockholders' Equity........ $510,973 $505,536
======== ========
The accompanying notes to consolidated financial statements are an
integral part of these statements.
F-3
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Year Ended December 31,
---------------------------------
1999 1998 1997
--------- --------- -------
(in thousands, except per
share amounts)
REVENUES:
Oil and gas sales............................ $139,242 $124,200 $129,994
Commodity price risk management activities
- Cash..................................... 248 5,888 (1,551)
- Non-cash................................. (34,094) 18,912 (4,928)
Interest..................................... 1,134 1,730 3,245
--------- --------- ---------
Total revenues............................ 106,530 150,730 126,760
------- ------- -------
COSTS AND EXPENSES:
Oil and gas operating expenses............... 39,168 40,847 12,758
Depreciation, depletion and amortization..... 54,182 56,102 46,684
Impairment of oil and gas properties......... -- 229,000 150,000
Impairment of equity securities.............. 450 24,216 --
General and administrative................... 4,940 5,216 3,913
Interest expense............................. 21,021 21,013 1,668
-------- -------- ---------
Total costs and expenses.................. 119,761 376,394 215,023
------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES.............. (13,231) (225,664) (88,263)
PROVISION (BENEFIT) FOR INCOME TAXES........... (4,631) (78,107) (31,355)
------- -------- --------
NET INCOME (LOSS).............................. (8,600) (147,557) (56,908)
PREFERRED STOCK DIVIDENDS...................... (6,884) (5,406) --
---------- ----------- ---------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK.... $(15,484) $(152,963) $(56,908)
========= ========== =========
EARNINGS (LOSS) PER SHARE OF COMMON STOCK,
BASIC AND FULLY DILUTED...................... $(0.49) $(4.85) $(1.80)
======= ======= =======
AVERAGE NUMBER OF COMMON SHARES USED IN
COMPUTATION, BASIC AND FULLY DILUTED......... 31,642 31,529 31,538
====== ====== ======
The accompanying notes to consolidated financial statements are an integral
part of these statements.
F-4
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands)
Preferred Stock Common Stock Additional
--------------- --------------- Paid-In
Shares Amount Shares Amount Capital
BALANCE, December 31, 1996 -- $ -- 31,577 $ 316 $186,703
------ ------ ------ ------ --------
Restricted stock issued....... -- -- 5 -- 123
Exercise of stock options -- -- 2 -- 38
Issuance of warrants.......... -- -- -- -- 10,000
Unrealized loss on marketable
equity securities............ -- -- -- -- --
Net income (loss)............. -- $ -- -- -- --
------ ------ ------ ------ --------
BALANCE, December 31, 1997 -- -- 31,584 $ 316 $196,864
------ ====== ====== ===== ========
Comprehensive Income..........
Issuance of Preferred Stock... 4,370 $ 44 -- -- $105,025
Repurchase of Preferred Stock. (58) (1) -- -- (806)
Restricted Stock Issued (Net). -- -- 25 -- 333
Unrealized loss on marketable
equity securities........... -- -- -- -- --
Net income (loss)............. -- -- -- -- --
Preferred Dividend paid....... -- -- -- -- --
----- ------ ------ ----- --------
BALANCE, December 31, 1998 4,312 $ 43 31,609 $ 316 $301,416
====== ======= ====== ===== ========
Comprehensive Income..........
Repurchase of Preferred Stock (327) $(3) -- -- $(5,049)
Restricted Stock Issued....... -- -- 200 2 1,018
Restricted Stock Forfeited.... -- -- (12) -- (160)
Restricted Stock Amortized.... -- -- -- -- --
Net Income (Loss)............. -- -- -- -- --
Preferred Dividend Paid....... -- -- -- -- --
Treasury Stock Acquisitions... -- -- -- -- --
Payment Received.............. -- -- -- -- --
----- ----- ----- ----- -------
BALANCE, December 31, 1999 3,985 $ 40 31,797 $ 318 $297,225
===== ===== ====== ===== ========
Comprehensive Income..........
Notes
Retained Receivable
Unearned Earnings for Equity
Compensation (Deficit) Interest
BALANCE, December 31, 1996
Restricted stock issued..... $(1,285) $48,244 $ (775)
------- -------- --------
Exercise of stock options... 192 -- --
Issuance of warrants........ -- -- --
Unrealized loss on marketa-
ble equity securities...... -- -- --
Net income (loss)........... -- -- --
-- (56,908) --
------- -------- -------
BALANCE, December 31, 1997 $(1,093) $(8,664) $ (775)
======= ======= ========
Comprehensive Income........
Issuance of Preferred Stock. -- -- --
Repurchase of Preferred Stock -- -- --
Restricted Stock Issued (Net) 11 -- --
Unrealized loss on marketable
equity securities......... -- -- --
Net income (loss)........... -- (147,557) --
Preferred Dividend paid..... -- (5,406) --
------- --------- -------
BALANCE, December 31, 1998 $(1,082) $(161,627) $ (775)
======== ========== ========
Comprehensive Income........
Repurchase of Preferred Stock -- -- --
Restricted Stock Issued..... (1,020) -- --
Restricted Stock Forfeited.. 160 -- --
Restricted Stock Amortized.. 512 -- --
Net Income (Loss)........... -- (8,600) --
Preferred Dividend Paid..... -- (6,884) --
Treasury Stock Acquisitions. -- -- --
Payment Received............ -- -- 22
------ ------ --------
BALANCE, December 31, 1999 $(1,430) $(177,111) $ (753)
======== ========== =========
Comprehensive Income........
Unrealized
Treasury Loss On
Common Stock Marketable Compre-
---------------- Equity hensive
Shares Amount Securities Total Income
-------------------------------------------------
BALANCE, December 31, 1996 -- $ -- $ -- $233,203
------ ------- -------- --------
Restricted stock issued..... -- -- -- 315 --
Exercise of stock options... -- -- -- 38 --
Issuance of warrants........ -- -- -- 10,000 --
Unrealized loss on marketa-
ble equity securities...... -- -- (2,000) (2,000) (1,320)
Net income (loss)........... -- -- -- (56,908) (56,908)
------ ------ -------- --------- --------
BALANCE, December 31, 1997 -- $ -- $(2,000) $184,648
====== ====== ======== ========
Comprehensive Income........ $(58,228)
=========
Issuance of Preferred Stock. -- -- -- $105,069 --
Repurchase of Preferred Stock -- -- -- (807) --
Restricted Stock Issued (Net) -- -- -- 344 --
Unrealized loss on marketable
equity securities.......... -- -- 2,000 2,000 1,320 (a)
Net income (loss)............ -- -- -- (147,557) (147,557)
Preferred Dividend paid...... -- -- $ -- (5,406) --
------ ----- ------- --------- --------
BALANCE, December 31, 1998 -- $ -- -- $138,291
====== ===== ======= ========
Comprehensive Income......... $(146,237)
==========
Repurchase of Preferred Stock -- -- -- $(5,052) --
Restricted Stock Issued...... -- -- -- --
Restricted Stock Forfeited... -- -- -- -- --
Restricted Stock Amortized... -- -- -- 512 --
Net Income (Loss)............ -- -- -- (8,600) (8,600)
Preferred Dividend Paid...... -- -- -- (6,884) --
Treasury Stock Acquisitions.. (705) (4,317) -- (4,317) --
Payment Received............. -- -- -- 22 --
------- ------- ------- -------- ---------
BALANCE, December 31, 1999 (705) $(4,317) $ -- $113,972
===== ======== ======= ========
Comprehensive Income......... $ (8,600)
=========
- --------------
(a) Represents a reclassification adjustment for $2.0 million gross ($1.32
million net of tax) unrealized loss recognized in comprehensive income in 1997,
but recognized in net income during 1998.
The accompanying notes to consolidated financial statements are
an integral part of these statements.
F-5
BELCO OIL & GAS CORP. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31,
----------------------------------------
1999 1998 1997
---------- ---------- --------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $(8,600) $(147,557) $(56,908)
Adjustments to reconcile net income (loss) to net
operating cash inflows--
Depreciation, depletion and amortization............... 54,182 56,102 46,684
Impairment of oil and gas properties................... -- 229,000 150,000
Impairment of equity securities........................ 450 9,773 --
Deferred tax benefit................................... (4,856) (78,107) (31,536)
Commodity price risk management activities............. 5,901 2,942 (1,248)
Other.................................................. 203 (19) 353
Changes in operating assets and liabilities--
Commodity price risk management...................... 28,193 (21,869) --
Accounts receivable.................................. 3,617 15,208 1,850
Marketable equity securities......................... -- 30,884 --
Other current assets................................. (1,292) 247 (65)
Accounts payable and accrued liabilities............. 246 (10,259) (7,607)
------ ------- -------
Net operating cash inflows........................ 78,044 86,345 101,523
------ ------ -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures.................. (73,932) (133,078) (140,975)
Proceeds from sale of oil and gas properties.............. 215 6,292 13,949
Changes in accounts payable and accrued liabilities for
oil and gas expenditures............................... -- -- 11,726
Change in advances to oil and gas operators............... -- -- (277)
Purchase of Coda Energy, Inc.............................. -- -- (214,896)
Purchase of marketable equity securities.................. -- (10,467) (30,884)
Changes in other assets................................... (351) (22) (1,779)
Other property additions.................................. (474) (1,251) --
-------- --------- ---------
Net investing cash outflows....................... (74,542) (138,526) (363,136)
-------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Long-term borrowings...................................... 53,500 68,000 85,000
Net proceeds from issuance of subordinated notes.......... -- -- 145,400
Long-term debt repayments................................. (41,100) (124,500) --
Proceeds from issuance of Preferred Stock................. -- 105,069 --
Dividends on Preferred Stock.............................. (6,884) (5,406) --
Repurchase of Common Stock................................ (4,317) -- --
Repurchase of Preferred Stock............................. (5,052) (807) --
Other..................................................... 21 -- --
-------- --------- --------
Net financing cash inflows (outflows)............. (3,832) 42,356 230,400
------- ------ -------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS............ (330) (9,825) (31,213)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............ 2,435 12,260 43,473
------- ------ --------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.................. $2,105 $2,435 $12,260
====== ====== =======
The accompanying notes to consolidated financial statements are an
integral part of these statements.
F-6
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 periods presented 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
F-7
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 financial statements. All material intercompany
balances and transactions have been eliminated.
Cash Equivalents
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents. At December 31, 1999
cash includes $800,000 of funds on deposit with a counterparty and related to
Commodity Price Risk Management Activities. The depository amount varies from
day to day and dependent on the movement of commodity prices. Subsequent to
calendar year-end 1999 the Company has deposited substantial amounts due to the
run-up in the price of oil during the first quarter of 2000 through mid-March.
Property and Equipment
The Company follows the full-cost method of accounting for oil and gas
properties. Accordingly, all costs associated with acquisition, exploration and
development of oil and gas reserves, including directly related internal costs,
are capitalized. The Company capitalized $5,492,000, $6,054,000 and $5,769,000
of related internal costs during 1999, 1998 and 1997, 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.
The PV10 value of the Company's year-end 1999 estimated proved reserves
were well in excess of the ceiling test limit. For the full year ended December
31, 1998 the Company recorded $229 million ($149 million after tax) in non-cash
ceiling test provisions as required by full cost accounting rules. The
provisions were the result of applying substantially lower commodity prices to
estimated recoverable reserves.
Sales and other dispositions of proved and unproved properties are
accounted for as adjustments of capitalized costs with no gain or loss
recognized, unless significant reserves are involved. Abandonments of properties
are accounted for as adjustments of capitalized costs with no loss recognized.
Buildings, equipment and gas processing facilities are depreciated on a
straight-line basis over the estimated useful lives of the assets, which range
from three to 20 years.
Management Fees
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.
After elimination of management fees received from affiliated entities,
including predecessor owners, the Company earned management fees totaling
$305,000 for both 1999 and 1998 and $297,000 during 1997.
F-8
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, 1999, 1998 and 1997, totaled $4,881,000,
$5,123,000 and $3,742,000, 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 have 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, 2000. 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 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, 1999 and 1998 were not significant.
F-9
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.
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 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.
F-10
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, 1999 and 1998 (in
thousands):
December 31,
1999 1998
------- -------
Revolving credit facility due 2002........................ $42,000 $29,500
8-7/8% Senior Subordinated Notes due 2007................. 150,000 150,000
10-1/2% Senior Subordinated Notes due 2006,
including premium totaling approximately $5.7 and $6.5
million for 1999 and 1998, respectively................. 114,744 115,490
------- -------
Total Debt...................................... 306,744 294,990
Less: Current maturities.................................. -- --
-------- -------
Long term debt............................................ $306,744 $294,990
======== ========
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, 1999 was set at $150 million with
$42.0 million advanced to the Company at that date. The borrowing base is
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 1999, the Credit
Facility weighted average interest rate was approximately 6.0%.
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
a minimum Interest Coverage Ratio, Current Ratio and Leverage Ratio (Indebted-
ness to EBITDA). The Company and its subsidiaries may not incur any indebtedness
other than indebtedness falling within the enumerated exceptions contained
in the Credit Facility. In addition, the Company's various debt instruments
contain certain restrictive covenants that, among other things, limit the
ability of the Company to pay dividends.
Indebtedness under the Credit Facility bears interest at a floating rate
based (at the Company's option) upon (i) the ABR (as defined below) with respect
to ABR Loans or (ii) the Eurodollar Rate for one, two, three or six months (or
nine or twelve months if available to the Banks) with respect to Eurodollar
Loans, plus the Applicable Margin. The ABR is the greater of (i) the Prime Rate,
(ii) the Base CD Rate plus 1% or (iii) the Federal Funds Effective Rate plus
0.50%. The Applicable Margin for Eurodollar Loans varies from 0.50% to 0.875%
depending on the Borrowing Base usage. Borrowing Base usage is determined by a
ratio of (i) outstanding Loans and letters of credit to (ii) the then effective
Borrowing Base. Interest on
F-11
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, 1999, 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.
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 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.
F-12
NOTE 5 -- RELATED-PARTY TRANSACTIONS
The Company's executive offices are leased from its Chairman and
approximately $250,000 was paid under such lease in 1999, 1998 and 1997.
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 $753,000 and $775,000 as of December 31, 1999 and 1998,
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
Total provision (benefit) for income taxes consists of the following:
Years Ended December 31,
1999 1998 1997
-------- -------- --------
(In thousands)
Current:
Federal (a)................................ $ (6,661) $ 20 $ (192)
State...................................... 225 87 373
------- ------- ----------
(6,436) 107 181
Deferred: (a)................................ (1,805) (78,214) (31,536)
------- -------- ---------
Total income tax provision (benefit)... $(4,631) $(78,107) $(31,355)
======== ========= =========
- --------------------
(a) The 1999 federal income tax amount reflects a tax benefit of $6.7 million
for which a refund claim was filed in late 1999. Accordingly, this amount was
recorded as an income tax refund receivable as of December 31, 1999. The refund
was received in January 2000.
The differences between the statutory federal income taxes and the
Company's effective taxes is summarized as follows (in thousands):
Years Ended December 31,
1999 1998 1997
-------- -------- --------
Statutory federal income taxes............... $(4,631) $(78,982) $(30,892)
State income tax, net of federal benefit..... 146 57 242
Section 29 tax credits....................... -- -- (850)
Capital loss valuation allowance............. (161) 875 --
Other........................................ 15 (57) 145
-------- --------- ---------
Provision (benefit) for income taxes......... $(4,631) $(78,107) $(31,355)
======== ========= =========
F-13
The principal components of the Company's net deferred income tax liability
are as follows:
Years Ended December 31,
------------------------
1999 1998
-------- ---------
(in thousands)
Deferred income tax assets
Commodity price risk management activities..... $ -- $3,940
Net operating loss............................. 21,416 12,092
Capital loss................................... 4,495 5,055
Other.......................................... 8,095 5,983
------- -------
$34,006 $27,070
------- -------
Deferred income tax liabilities
Depreciation, depletion and amortization....... $(60,834) $(55,369)
Commodity price risk management actitivities... (1,875) --
Other.......................................... (4,221) (2,659)
-------- ---------
(66,930) (58,028)
Valuation allowance.............................. (714) (875)
--------- ---------
Net deferred income tax liability...... $(33,638) $(31,833)
========= =========
As a result of the acquisition of Coda, the Company succeeded to net
operating loss carryforwards ("NOLs") for income tax purposes that expire from
2000 through 2004. Due to a change of ownership (as defined by the Tax Return
Act of 1986) which occurred prior to the acquisition by the Company, the
utilization of the Coda NOLs is severely restricted. At December 31, 1999, the
Company estimates that approximately $12.4 million of the Coda NOLs is available
to offset future income. For the year ended December 31, 1999, the Company
generated an NOL of approximately $48.8 million which can be carried forward
from 2000 to 2020. In addition to the NOLs, at December 31, 1999, the Company
has approximately $12.8 million of capital loss carry forwards which may be used
to offset capital gains realized over the next four years. A valuation allowance
of $2.0 million was established against the capital loss carryforward since this
amount is not expected to meet the realization test. 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 $1.06 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 $0.6 million of Section 29 Tax Credits
in 1999. 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 produced based tax credit will also decline.
F-14
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).
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, 1999, the Company had entered into hedging
transactions with respect to a significant portion of its estimated oil
production for 2000 and approximately 50% of its estimated natural gas
production. Similar transactions were entered into covering lower quantities of
its estimated production for the years 2001-2002. 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,
1999:
Production Periods
-----------------------
2000 2001 Total
------ ------ -----
Gas--
Price swaps-- receive fixed price (thousand MMBtu)(1)(5).. 4,890 - 4,890
Average price, per MMBtu............................... $2.29 - $2.29
Collars and options (thousand MMBtu)(2)................... 12,785 9,125 21,910
Average floor price, per MMBtu......................... $1.47 $1.91 $1.63
Average ceiling price, per MMBtu....................... $2.62 $2.85 $2.73
Price swaps-- pay fixed price (thousand MMBtu)(3)......... 310 - 310
Average price, per MMBtu............................... $2.81 - $2.81
Basis swaps (thousand MMBtu)(4)........................... 7,320 - 7,320
Average basis differential, per MMBtu.................. ($0.49) - ($0.49)
Oil--
Price swaps-- receive fixed price (MBbls)(1)(3)(7)........ 610 268 878
Average price, per Bbl................................. $18.81 $17.99 $18.56
Collars and options (MBbls)(2)(6)......................... 959 184 1,143
Average floor price, per Bbl........................... $16.95 $17.71 $17.06
Average ceiling price, per Bbl......................... $19.81 $20.90 $19.99
F-15
- ----------
(1) For any particular swap transaction, the counterparty is required to
make a payment to the Company in the event that the NYMEX Reference
Price for any settlement period is less than the swap price for such
hedge, and the Company is required to make a payment to the
counterparty in the event that the NYMEX Reference Price for any
settlement period is greater than the swap price for such hedge.
(2) For any particular collar transaction, the counterparty is required to
make a payment to the Company if the average NYMEX Reference Price for
the reference period is below the floor price for such transaction, and
the Company is required to make payment to the counterparty if the
average NYMEX Reference Price is above the ceiling price for such
transaction.
(3) In order to close certain commodity price hedge positions, the Company
entered into various swap positions where the Company is the
fixed-price payer on the swap. In these transactions, the counterparty
is required to make a payment to the Company in the event that the
NYMEX Reference Price for any settlement period is greater than the
swap price, and the Company is required to make a payment to the
counterparty in the event that the NYMEX Reference Price for any
settlement period is less than the swap price.
(4) The Company 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 ex-
ceeds 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 ex-
ceeds 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 920, 19,155 and 3,650 thousand MMBtu of swaps in 2000
through 2002, respectively, that are extendable at the election of the
counterparty.
(6) Does not include 108 and 13 MBbls collars in 2001 and 2002, respective-
ly, that are extendable at the election of the counterparty.
(7) Does not include 333, 840, 966, 590 and 31 thousand Bbls of swaps in
2000 through 2004, 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 $3.9 million, $1.9 million and $(13.1)
million for 1999, 1998 and 1997, respectively, was included in Commodity Price
Risk Management revenues. As of December 31, 1999 and 1998, the Company had no
accrued liabilities settled derivative contracts. These amounts are included in
Price Risk Management activities as assets or liabilities as appropriate.
F-16
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 1999
results of operations included an aggregate pre-tax loss of $33.8 million
related to these activities which included (1) net premiums received totaling
$248,000 and (2) the unrealized loss 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, 1999 of $34.1 million, all included in Commodity
Price Risk Management revenues. At December 31, 1999, the Company's consolidated
balance sheet reflects $3.0 million and $26.0 million of price risk management
assets and liabilities, respectively.
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, 1999, that do not qualify for hedge accounting:
Production Periods
-----------------------------------------------
2000 2001 2002 2003 Total
---------- ---------- ---------- ---------- -------
Gas--
Calls bought (thousand MMBtu)(2)............................ 2,120 - - - 2,120
Average price, per MMBtu................................. $2.98 - - - $2.98
Calls Sold (thousand MMBtu)(2).............................. 7,320 7,300 - - 14,620
Average price, per MMBtu................................. $2.78 $3.23 - - $3.00
Puts Sold (thousand MMBtu)(2)............................... 3,620 - - - 3,620
Average price, per MMBtu................................. $2.28 - - - $2.28
Price Swaps-- receive fixed price (thousand MBbls)(3)(4).... 7,320 3,650 - - 10,970
Average price, per MMBtu................................. $2.30 $2.51 - - $2.37
Oil--
Straddles (MBbls)(1)........................................ 25 - - - 25
Average price, per Bbl................................... $17.48 - - - $17.48
Price Swaps-- pay fixed price (thousand MMBtu).............. 45 - - - 45
Average price, per MMBtu................................. $22.65 - - - $22.65
Price Swaps-- receive fixed price (MBbls) (3)(5)............ 1,051 151 13 - 1,215
Average price, per Bbl................................... $19.27 $17.72 $17.25 - $19.06
Calls Bought (MBbls)(2)..................................... 150 - - - 150
Average price, per Bbl................................... $19.00 - - - $19.00
Calls Sold (MBbls)(2)....................................... 2,148 996 714 75 3,933
Average price, per Bbl................................... $20.06 $20.05 $21.86 $22.00 $20.42
Puts Sold (MBbls)(2)........................................ 986 199 19 - 1,204
Average price, per Bbl................................... $18.70 $15.81 $16.00 - $18.18
Puts Bought (MBbls)(2)...................................... 404 38 - - 442
Average price, per Bbl................................... $17.82 $17.17 - - $17.76
- ----------
(1) A straddle is a combination of a put sold and a call sold at the same
strike price. The Company is required to make a payment to the counter-
party 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
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 in return for the Company's payment of a
premium or 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.
F-17
(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.
(4) Does not include 3,660 thousand MMBtu of gas swap which have tiered pricing
at which the swap is canceled when the NYMEX Reference Price falls below
$1.80 per MMBtu.
(5) Does not include 341 and 38 MBbls of oil swaps for 2000 and 2001,
respectively, which have tiered pricing at which the swap is canceled when
the NYMEX Reference Price falls below $16.50 per Bbl as to 52% of the
volumes and $18.00 for the remaining 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, 1999 and 1998. 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, 1999 December 31, 1998
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- ------
(In thousands)
Cash and cash equivalents.............. $2,105 $2,105 $2,435 $2,435
Long-term debt......................... 306,744 296,323 294,990 277,180
Interest rate swaps.................... -- (6,549) -- 196
Oil and gas commodity-- Hedges......... -- (8,603) -- 4,584
-- Non-hedges..... (23,066) (23,066) 11,028 14,368
The carrying values of trade receivables and trade payables included in the
accompanying consolidated balance sheets approximated market value at December
31, 1999 and 1998.The following methods and assumptions were used to estimate
the fair value of the financial instruments summarized in the above table.
Cash and Cash Equivalents
The carrying amounts approximate fair value because of the short maturity
of those instruments.
Marketable Equity Securities
In June 1997 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.
F-18
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. As a result of the aforementioned transactions, Belco
became the owner of 1,948,052 common shares or approximately 4.6% ownership in
Big Bear. The substantial decline in the market value of Big Bear securities at
year-end 1999 and 1998 required the Company to record $0.45 and $9.7 million in
impairment provisions, respectively.
In January 2000, shareholders of Big Bear approved its acquisition by AVID
Oil & Gas, Ltd. ("AVID"), a Canadian based energy company providing for Big Bear
shareholders to receive 1 share of AVID common stock for every 15 common shares
of Big Bear. As a result of the transaction described above, the Company cur-
rently owns 129,870 shares of Avid with an approximate market value of $190,000
(US) as of December 31, 1999.
Long-Term Debt
The fair value of the Company's revolving credit facility debt of $42.0
million is assumed to be the same as the carrying value because the interest
rate is variable and is reflective of market rates. The fair value of the
10-1/2% Notes is based upon the quoted market prices for that issue. The fair
value of the 8-7/8% Notes is based upon estimates provided to 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. 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"). In November 1999, pursuant to the 80%
Price Participation Right provision the Company paid out $2.3 million to former
third party investors in the Moxa Program. 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, 80.5% of the Moxa Arch
1992 Offset Drilling Program, and 74% of the Moxa Arch 1993 Offset Drilling
Program. The transaction was accounted for using the purchase method of
accounting.
F-19
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, 1999.
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 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, 1999.
Lease Commitments
At December 31, 1999, the Company had operating leases covering office
space. Minimum rental commitments under operating leases are $44,000 for the
year 2000. For the years ended December 31, 1999, 1998 and 1997, total rental
expense was approximately $316,000, $512,000 and $438,000, 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,
---------------------------
1999 1998 1997
------ ------ ------
(in thousands)
Cash paid (received) during the year for:
Interest, including amounts capitalized........... $26,823 $26,139 $ 307
Income and other taxes, net of (refunds).......... 487 (788) 1,345
In November 1997, the company acquired Coda for cash, warrants and the
assumption of certain liabilities. See Note 3.
F-20
NOTE 10 -- CUSTOMER INFORMATION
Concentrations of Credit Risk
The Company's revenues are derived from uncollateralized sales to customers
in the oil and gas industry. The concentration of credit risk in a single
industry affects the Company's overall exposure. The Company has not experienced
significant credit losses on such sales.
Major Customers
Oil and gas sales for 1999 include $26.6 million, $16.1 million, $14.1
million and $11.9 million in revenues received from four customers. Also, 1999
revenues included net losses in the amount of $33.8 million related to Commodity
Price Risk Management Activities. Oil and gas sales for 1998 include $28.9
million and $16.9 million in revenues received from two customers. Also, 1998
revenues include Commodity Price Risk Management net gains totaling $24.8
million. Oil and gas sales for 1997 include $40.6 million, $27.9 million and
$25.5 million in revenues received from three customers and Commodity Price Risk
Management net losses of $6.5 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 1999, 1998 and 1997, the Company incurred contribution expenses of
$378,000, $398,000 and $99,000, respectively, 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 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.
In December 1998, the Company's Board of Directors (the "Board") authorized
the purchase from time to time, in the open market or in privately negotiated
transactions, shares of its Common Stock and 6-1/2% Convertible Preferred Stock
in an aggregate amount not to exceed $10 million. This authorization was
exhausted in December 1999. Subsequently, the Board authorized an additional
$10 million for the purchase of additional Common and Preferred Shares.
Net Income (Loss) Per Common Share
Potential common stock not included in the calculation of diluted earnings
per share because to do so would have been antidilutive amounted to 7,673,000,
7,690,000 and 7,562,000 for 1999, 1998 and 1997, respectively.
F-21
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.
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, 1999 and 1998 and the changes during the years then ended is presented be-
low:
1999 1998
-------------------------------------------------------
Shs. Under Wtd. Avg. Shs. Under Wtd. Avg.
Option Exer. Price Option Exer. Price
---------- ----------- ---------- -----------
Outstanding, beginning of year.......... 1,154,000 $16.25 960,500 $20.31
Granted............................... 414,500 5.19 433,000 9.82
Exercised............................. -- -- -- --
Forfeited............................. (62,000) 15.00 (239,500) 19.37
---------- ------- --------- ------
Outstanding, end of year................ 1,506,500 $13.68 1,154,000 $16.25
========= ====== ========= ======
Exercisable, end of year................ 432,300 $18.62 201,500 $20.24
======= ====== ========= ======
Available for grant, end of year........ 901,600 1,254,100
======= =========
Weighted average fair value of options
granted during the year............... $ 2.78 $ 10.36
========= =========
F-22
The following table summarizes information about stock options outstanding
at December 31, 1999.
Options Outstanding Options Exercisable
-------------------------------------- -----------------------
Weighted Number
Number Average Weighted Exercis- Weighted
Outstanding at Remaining Average able at Average
December 31, Contractual Exercise December 31, Exercise
Range of Prices 1999 Life Price 1999 Price
- --------------- ------------- ----------- -------- ------------ ---------
$4.88 - $6.50 369,500 9.19 $4.99 - -
$7.41 - $11.00 389,500 8.53 $9.80 71,200 $9.99
$12.47 - $17.63 35,000 8.34 $15.42 9,000 $14.26
$18.88 - $28.13 709,500 7.29 $19.00 350,300 $20.42
$28.81 - $29.00 3,000 6.58 $29.00 1,800 $29.00
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 1999 and 1998 would have been reduced to the pro forma amounts
indicated below (in thousands, except for per share amounts):
1999 1998
------------- -----------
Net Income (Loss) Available to Common Stock
As Reported.................................. $ (15,484) $(152,963)
Pro Forma.................................... $ (15,886) $(154,625)
Basic and Diluted Net Income (Loss) Per Share
As Reported.................................. $ (0.49) $ (4.85)
Pro Forma.................................... $ (0.50) $ (4.90)
The fair value of grants was estimated on the date of grant using the
Black-Scholes options pricing model with the following weighted average
assumptions used in 1999 and 1998, respectively: risk-free interest rate of 5.43
and 5.60 percent, expected volatility of 48.3 and 49.0 percent, expected lives
of 6.0 years and no dividend yield.
Under the Stock Incentive Plan, participants may be granted stock without
cost (restricted stock). During 1999 and 1998, the Company granted 200,000 and
34,700 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 $5.09
and $15.69 per share, respectively. At December 31, 1999, 223,120 shares
remained unvested, net of 17,800 shares forfeited. The weighted average fair
value of shares forfeited was $18.57. 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 1999 and
1998, $512,000 and $344,100, 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)
1999
Revenues................................................ $24,725 $19,572 $15,246 $49,986
Costs and Expenses...................................... $29,666 $29,751 $29,830 $30,514
Net Income (Loss)....................................... $(3,212) $(6,617) $(9,480) $10,709
Basic and Diluted Net Income (Loss) Per Common Share.... $ (0.16) $ (0.26) $ (0.35) $ 0.29
F-23
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)
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, 1999 and 1998 (in thousands):
1999 1998
----------- -----------
Proved properties...............................$1,008,261 $931,218
Unproved properties............................. 71,075 74,935
---------- ----------
Total capitalized costs......................... 1,079,336 1,006,153
Less-- Accumulated depreciation, depletion and
amortization................................. (619,446) (566,613)
----------- ---------
Net capitalized costs........................... $459,890 $439,540
======== ========
Costs Not Being Amortized
The following table sets forth a summary of unproved oil and gas property
costs not being amortized at December 31, 1999, by the year in which such costs
were incurred (in thousands):
1999 1998 1997 1996 1995 Total
---- ---- ---- ---- ---- -----
Leasehold and seismic.......$8,046 $6,128 $56,184 $177 $542 $71,077
Costs Incurred
The following table sets forth the costs incurred in oil and gas
acquisition, exploration and development activities as of December 31, 1999,
1998 and 1997 (in thousands):
1999 1998 1997
---------- ------------ -----------
Property Acquisitions Costs--
Proved(1)...................... $17,608 $56,695 $443,930
Unproved....................... 10,390 14,414 24,226
Exploration costs................ 10,943 18,597 46,939
Development costs................ 29,576 37,969 59,571
Capitalized interest............. 4,881 5,123 3,742
Property sales................... (215) (6,292) (13,949)
--------- --------- ----------
Total costs incurred........... $73,183 $126,506 $564,459
======= ======== ========
F-24
- ----------
(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.
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, 1999, 1998 and 1997 (in thousands):
1999 1998 1997
-------- -------- -------
Oil and gas revenues (including commodity price
risk management activities)...................$105,396 $149,000 $123,515
Costs and expenses--
Lease operating expenses...................... 33,683 36,969 9,365
Production taxes.............................. 5,485 3,878 3,393
Impairment of oil and gas properties.......... -- 229,000 150,000
Depreciation, depletion and amortization...... 52,833 54,863 46,684
-------- ------- --------
Results of operations from producing activities
before income taxes........................... 13,395 (175,710) (85,927)
Provision (benefit) for income taxes............ 4,688 (61,498) (30,537)
------- -------- --------
Results of operations from producing activities. $8,707 $(114,212) $(55,390)
====== ========== =========
Amortization rate per Mcf equivalent, recurring. $ 0.88 $ 0.88 $ 0.81
======= ========= =========
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,
1999, 1998 and 1997 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).
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.
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
F-25
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-26
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
(In thousands)
December 31,
------------------------------------
1999 1998 1997
---------- -------- ----------
Future cash inflows(1)......................1,945,175 $1,215,691 $1,569,976
Future production costs..................... (588,932) (405,171) (531,583)
Future development costs.................... (110,091) (99,342) (100,427)
---------- -------- ----------
Future net inflows before income taxes(1)...1,246,152 711,178 937,966
Discount at 10% annual rate................. (619,610) (350,562) (427,562)
---------- --------- ---------
Discounted future net cash flows before
income taxes.............................. 626,542 360,616 510,404
Pro forma discounted future income taxes(2). (161,213) (7,457) (84,196)
---------- --------- --------
Standardized measure of discounted future
net cash flows........................... $465,329 $353,159 $426,208
======== ======== ========
- ----------
(1) Oil and gas commodity hedges included in future cash inflows totaled $(8.6)
million, $4.6 million and $5.9 million at December 31, 1999, 1998, and
1997, respectively, and such hedges included in discounted future net cash
flows before income taxes totaled $(8.2) million, $4.3 million and $5.5
million at December 31, 1999, 1998 and 1997, respectively.
(2) The estimated undiscounted future income taxes related to future net
inflows were $354.5, $32.6 and $146.4 million for the years 1999, 1998
and 1997, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows
(In thousands)
1999 1998 1997
-------- -------- --------
Balance, beginning of year......................$353,159 $426,208 $280,573
Sales and transfers of oil and gas produced,
net of production costs.......................(100,075) (83,353) (111,819)
Net change in sales price and production costs.. 239,549 (142,014) (216,169)
Extensions and discoveries...................... 65,424 29,730 65,741
Purchases of minerals in place.................. 21,346 66,409 312,148
Sale of reserves in place....................... (112) (1,401) --
Changes in estimated future development costs... 33,925 21,382 32,222
Revisions in quantities......................... (8,841) (39,163) (9,099)
Accretion of discount........................... 36,062 51,040 41,553
Other, principally revisions in estimates of
timing of production......................... (21,352) (53,923) (22,267)
Change in income taxes..........................(153,756) 78,244 53,325
--------- -------- ---------
Balance, End of year............................$465,329 $353,159 $426,208
======== ======== ========
F-27
Reserve Quantity Information
Proved Reserves
Oil Gas
------- -------
(MBbls) (MMcf)
Balance at December 31, 1996........................... 3,327 284,992
------- -------
Purchases of minerals in place....................... 45,646 44,855
Extensions, discoveries and other additions.......... 2,004 39,248
Revisions of previous estimates...................... 1,478 (22,200)
Production........................................... (1,295) (49,710)
------- --------
Balance at December 31, 1997........................... 51,160 297,185
------ -------
Purchases of minerals in place....................... 9,800 25,903
Extensions, discoveries and other additions.......... 249 34,279
Revisions of previous estimates ..................... (3,775) (33,977)
Sales of minerals in place........................... (203) (649)
Production........................................... (4,177) (37,208)
------- --------
Balance at December 31, 1998........................... 53,054 285,533
------ -------
Purchases of minerals in place....................... 1,066 20,982
Extensions, discoveries and other additions.......... 3,342 57,881
Revisions of previous estimates...................... (947) (2,322)
Sales of minerals in place........................... - (189)
Production........................................... (3,439) (39,737)
------- --------
Balance at December 31, 1999........................... 53,076 322,148
====== =======
Proved Developed Reserves
December 31, 1996...................................... 2,070 184,904
December 31, 1997...................................... 41,255 226,071
December 31, 1998...................................... 41,475 213,449
December 31, 1999...................................... 42,352 224,143
F-28
NOTE 15 -- SUBSEQUENT EVENTS (Unaudited)
In February 2000, the Company closed a $40.5 million acquisition of oil and
gas properties expected to add approximately 2,400 BOE per day to the existing
production base. The transaction was financed through additional borrowings
with the Company's Revolving Credit Facility.
Due to the sustained higher oil prices subsequent to year-end, the Company
expects to incur additional cash settlements costs and non-cash mark-to-market
losses related to its commodity price risk management activities unless prices
at March 31, 2000 decline below levels at December 31, 1999.
EXHIBIT INDEX
Exhibit
No. Description of Exhibit
- ------- ----------------------
3.1 Articles of Incorporation of Company (Incorporated by reference from
Exhibit 3.1 of the Registration Statement on Form S-1, Registration No.
333-1034).
3.2 Amended and Restated Bylaws of Company dated February 5, 1996 (Incorporated
by reference from Exhibit 3.2(ii) of the Form 10-Q dated March 31, 1996).
4.1 Specimen Common Stock certificate (Incorporated by reference from Exhibit
4.1 of the Registration Statement on Form S-1, Registration No. 333-1034).
4.2 Indenture dated as of September 23, 1997 among the Company, as issuer,
and The Bank of New York, as trustee (Incorporated by reference from
Exhibit 4.1 of Registration Statement on Form S-4, Registration No.
333-37125).
4.3 Supplemental Indenture dated as of February 25, 1998 between Coda
Energy, Inc., Diamond Energy Operating Company, Electra Resources, Inc.,
Belco Operating Corp., Belco Energy L.P., Gin Lane Company, Fortune Corp.,
BOG Wyoming LLC and Belco Finance Co. (individually, the Subsidiary
Guarantors), a subsidiary of 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 Inden-
ture 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 refer-
ence 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).
38
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 offi-
cers 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 Dec-
ember 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 Decem-
ber 30, 1994 (Incorporated by reference to Exhibit 10.7 of the Registra-
tion Statement on Form S-1, Registration No. 333-1034).
10.8 Sale Agreement (Independence) dated as of June 10, 1994 between Chesa-
peake 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. (Incor-
porated 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 Drill-
ing Program (Incorporated by reference to Exhibit 10.16 of the Regis-
tration 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 admin-
istrative agent, and certain financial institutions named therein as Lend-
ers (the "Lenders")(Incorporated by reference to Exhibit 10.1 of Registra-
tion 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 Administra-
tive Agent for the ratable benefit of Lenders. (Incorporated by refer-
ence 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 Bor-
rower, the Lenders and The Chase Manhattan Bank, as administrative agent.
(Incorporated by reference from Exhibit 10.17 of the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1998).
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,
39
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. (Incorporated by reference from Exhibit 10.18 of the Company's
Annual Report on Form 10-K for the fiscal year ended December 31, 1998).
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 First Amendment to Belco Oil & Gas Corp. 1996 Nonemployee Directors' Stock
Option Plan. (Incorporated by reference from Exhibit 10.1 of the Com-
pany's Quarterly Report on Form 10-Q for the quarter ended June 30, 1999,
Commission File No. 1-14256).
*21.1 Subsidiaries of the Registrant.
*23.1 Consent of Arthur Andersen LLP.
*23.2 Consent of Miller and Lents, Ltd.
*27 Financial Data Schedule.
- ----------
* Filed herewith
40