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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, 1996.
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.
COMMISSION FILE NUMBER 1-12634
BELCO OIL & GAS CORP.
(Exact name of Registrant as specified in its charter)
NEVADA 13-3869719
(State of 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
_______________________________
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
Securities registered pursuant to Section 12(g) of the Act:
None
__________________________
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. YES X NO ___.
Indicate by check mark if disclosure of delinquent files 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 stock held by non-affiliates of
the Registrant at March 24, 1997, was approximately $155,883,285 (based on a
value of $20.25 per share, the closing price of the Common Stock as quoted by
the New York Stock Exchange on such date). 31,582,300 shares of Common Stock,
par value $.01 per share, were outstanding on March 24, 1997.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Registrant's 1997 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.
BELCO OIL & GAS CORP.
PART I
Item 1 -- BUSINESS
OVERVIEW
Belco Oil & Gas Corp. ("Belco" or the "Company") is an independent energy
company engaged in theexploration, development and production of natural gas
and oil. The Company ranks among the most profitable andfastest growing
independent energy producers in the United States. Belco conducts its
operations primarily in Texas, Louisiana, Wyoming, Michigan and Oklahoma where
it currently controls interests in excess of 2.2 million gross acres.
Since its inception in April 1992, Belco has grown rapidly through
acreage acquisitions and the drilling of exploratory and development wells.
Belco utilizes state-of-the-art technology in drilling both horizontal and
vertical wells, including 3-D seismic. The Company's average daily production
increased from 4.4 MMcfe in 1992 to 153.1 MMcfe in 1996. While experiencing
this rapid growth, the Company has maintained a low cost structure and has
been profitable in each of the five years since its inception. From inception
through December 31, 1996, the Company's pre-tax operating cash flow per Mcfe
averaged $1.78 (revenues of $2.01 per Mcfe less operating expenses of $0.16
per Mcfe and general and administrative expenses of $0.07 per Mcfe).
At December 31, 1996, the Company's estimated proved reserves consisted
of 285 Bcf of natural gas and 3.327 MMBbls of oil, for a total of 305 Bcfe.
During 1996, the Company's proved reserves increased from 219 Bcfe to 305
Bcfe, an increase of 86 Bcfe representing a 254% replacement ratio of the 56
Bcfe of production in 1996. At December 31, 1996, Belco's estimated proved
reserves (including hedges) before income taxes and discounted to present
value at 10% per annum was $416 million, based on average prices at 1996
year-end of $25.13 per Bbl of oil and $3.68 per Mcf of natural gas.
The Company was organized in connection with the combination
("Combination") of ownership interests in certain entities and direct
interests in oil and gas properties and certain hedge transactions owned by
members of the Robert A. Belfer family and by employees of such entities and
entities related thereto. The Combination was effected in connection with the
Company's initial public offering of 6,500,000 shares of Common Stock, which
was completed on March 29, 1996, resulting in net proceeds of $113 million
after expenses ("Initial Public Offering").
Certain terms relating to the oil and gas industry are defined in
"Certain Definitions" below.
RECENT DEVELOPMENTS
From May 1992 through 1996, the Company has focused its operations
primarily in the Moxa Arch Trend (southwest Wyoming), the Giddings Field (east
central Texas) and to a lesser extent the Golden Trend Field (southern
Oklahoma), where it has profitably built reserves and increased production
through the drill bit. In 1996, the Company has significantly expanded the
scope of its operations through the extension of existing core areas and the
development of new ones.
1996 Drilling Program
The Company's drilling program for 1996 resulted in the drilling of 80
(gross) and 34 (net) wells. Of these, 69 (gross) and 28 (net) were
horizontal wells primarily in the deep Austin Chalk Trend of Texas and
Louisiana. See "Costs Incurred and Drilling Results," below.
2
Louisiana Austin Chalk
As an extension of its Austin Chalk drilling program in the Giddings
Field of east central Texas, the Company significantly expanded its acreage
acquisition activities into the Austin Chalk Trend of Louisiana (the
"Louisiana Austin Chalk"). At December 31, 1996, the Company owned or had the
right to acquire approximately 350,000 net acres in Louisiana and had entered
into joint development programs and areas of mutual interest ("AMIs") with
Union Pacific Resources Company ("UPR") and OXY USA, Inc. ("OXY USA") with
respect to approximately 93,000 combined net acres and 24,000 combined net
acres, respectively.
In the fourth quarter of 1996 the Company completed two productive
horizontal wells in the Louisiana Austin Chalk: the Martin #1 re-entry well
in Avoyelles Parish and the Turner #21 well in St. Landry Parish; and
commenced the drilling of a third well, the Turner #22, also in St. Landry
Parish. The Company believes that the Turner #21 was the world's deepest
horizontal well at the time drilled. Belco's large acreage position, together
with alliances with experienced industry partners, will permit the Company to
remain an important player in Louisiana Austin Chalk exploration and
development activities.
Rocky Mountains -- Wyoming
In 1996 the Company assumed operations of 73 of its 176 producing wells
in the Moxa Arch Trend of southwest Wyoming and acquired additional working
interests totaling 23.0 Bcfe in its Moxa Arch wells from its third party
investors.
Building on its substantial position in southwest Wyoming, the Company
consummated a series of transactions designed to significantly expand its
Wyoming exploration and development activities into the Big Horn, Green River
and Wind River Basins. In December 1996, Belco entered into acreage
acquisition and joint development projects with Snyder Oil Corporation
("SOCO"), Andex Partners, Andover Partners and Yates Petroleum Corporation
("Yates") covering up to a total of approximately 750,000 gross (250,000 net)
acres.
Central Michigan Basin
In June 1996, the Company entered into an exploration program with two
private oil and gas companies pursuant to which the Company acquired a 35%
interest in 220,000 net acres in the Central Basin of Michigan and obtained
the option to acquire an additional undivided 15% of such acreage following
the completion of a multi-well test program. By year-end 1996, Belco had
accumulated interests in a total of approximately 395,000 gross and 145,000
net acres in this Basin.
In the fourth quarter of 1996, the Company began operations on its
initial seven-well test program covering different portions of this large
acreage position, including six re-entries and one grass root well.
Gulf Coast 3-D Seismic Program
In March 1996, the Company entered into an exploration agreement with
Edge Petroleum Corporation ("Edge") pursuant to which the parties expect to
jointly conduct a series of 3-D seismic programs potentially covering up to
750 square miles onshore in the Gulf Coast region of Texas. Under the
program, the Company has initiated the first 50+ square mile 3-D seismic
shoot targeting the shallower Frio formation and potentially larger reserves
in the deeper Wilcox formation. The Company expects the seismic
interpretation of the initial shoot to be complete in mid-1997 and the
drilling of any identified Frio formation targets to commence soon thereafter.
The Company utilized 3-D seismic technology to identify a series of
exploratory drilling opportunities in the Vicksburg and Queen City formations
in South Texas. As an example, the Company drilled the La Brisa #1 in Starr
County, Texas in the fourth quarter of 1996 which had initial rates of
production in excess of 10 MMcfe per day. The Company holds a 50% working
interest in this exploratory well and its offset which was spud in February
1997.
3
PRIMARY OPERATING AREAS
The Company's operations are currently focused in four primary operating
areas: (i) the Giddings Field in east central Texas including the Navasota,
Independence, River Bend and Wedge prospect areas, (ii) the Louisiana Austin
Chalk Trend, (iii) the Rocky Mountains - Wyoming, including the Green River
(inclusive of the Moxa Arch Trend), the Big Horn and the Wind River Basins and
(iv) the Central Basin of Michigan.
The following table sets forth, as of December 31, 1996, estimates of the
Company's proved reserves by operating area based upon a report prepared by
Miller and Lents, Ltd. ("Miller & Lents") as well as the percent of total net
present value attributable to each geographic area. See "Forward Looking
Information and Risk Factors" below and "Item 2 -- Properties."
Proved Reserves
-------------------------------------
Percent
Gas of
Oil Gas Equivalent Proved
(Mbbls) (Mmcf)(1) (Mmcfe) Reserves
Texas - Giddings Field 1,964 126,705 138,489 45.4%
Texas - Other Areas 23 2,564 2,702 0.9%
Wyoming - Moxa Arch Trend (2) 808 141,905 146,753 48.1%
Oklahoma - Golden Trend Field 306 8,139 9,975 3.3%
Louisiana - Austin Chalk 150 415 1,315 0.4%
Michigan - Central Basin 76 5,264 5,720 1.9%
----- -------- ------- -----
Total 3,327 284,992 304,954 100.0%
===== ======== ======= ======
__________________
(1) Includes natural gas liquids.
(2) Includes approximately 11,000 MMcfe of proved undeveloped reserves which
are subject to the right of third party investor's in the Company's Moxa Arch
Drilling Programs to participate.
Giddings Field
Approximately 45% of the Company's estimated proved reserves at December
31, 1996 were located in the Giddings Field of east central Texas, principally
in Grimes, Washington and Fayette Counties. The Giddings Field is one of the
most actively drilled oil and gas fields in the United States. The primary
producing zone in the Giddings Field is the Austin Chalk, a fractured
carbonate formation that has been highly conducive to the application of
horizontal drilling technology. The Austin Chalk formation is encountered in
this field at depths believed by the Company to range between approximately
7,000 and 17,000 feet.
The Company first acquired interests in the Giddings Field in September
1992. During 1996, average net production from this field was approximately
126 MMcfe of natural gas per day. Through December 31, 1996, the Company had
drilled 214 gross (70.8 net) wells in this field and continues to control
approximately 313,500 gross undeveloped acres in this area. The Company
divides the Giddings Field into four prospect areas: (i) Navasota River,
primarily in Grimes County, (ii) Independence, primarily in Washington County,
(iii) River Bend, primarily in Fayette County and (iv) the Wedge, primarily in
Walker County. The Company expects to be drilling new wells in the Giddings
Field for the foreseeable future in addition to re-entering older wells to
drill additional laterals. Currently, a majority of the Company's interests
in this field are held pursuant to agreements with and operated by Chesapeake
Energy Corp. ("Chesapeake") and to a lesser extent UPR. The Company serves as
operator in the River Bend and Wedge prospect areas.
4
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 Texas
Austin Chalk Trend; and (iii) the Company's acquisition program in cooperation
with other operators has permitted the creation of larger spacing units, thus
reducing possible competition for reserves from offsetting wells. As a result
of these factors, the Company's deeper downdip wells have, on average,
produced greater reserves per well than average wells in other areas of the
Texas Austin Chalk Trend.
The majority of the Company's acreage in the Giddings Field was
classified as a tight sands reservoir by the Texas Railroad Commission. Wells
spud between June 1989 and September 1996 are exempt from the 7.5% state
severance tax on natural gas through August 2001. See "Item 1 - Texas
Severance Tax Abatement."
Rocky Mountains -- Wyoming
The Company maintains a significant acreage position in the Rocky
Mountains of Wyoming on which 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
Production Company ("Amoco"). In 1996 the Company significantly expanded its
acreage and exploration activities by acquiring the rights to up to
approximately 750,000 gross (250,000 net) acres in the Green River, Big Horn
and Wind River Basins in Wyoming which lie north and east of the Moxa Arch
Trend.
Moxa Arch Trend. Currently, Belco's second primary operating area is the
Moxa Arch Trend located in the Greater Green River Basin in southwestern
Wyoming, principally in Lincoln, Sweetwater and Uinta Counties. Approximately
48% of the Company's estimated proved reserves at December 31, 1996 were
located in this field. The Company participates in vertical gas wells in this
area which target the Frontier and/or Dakota formations at depths that range
from approximately 10,000 to 12,500 feet. The Frontier formation is a
relatively blanket "tight gas sand" formation, while the Dakota formation,
beneath the Frontier, tends to be a more prolific, but less predictable
channel sand. In contrast to production from the Giddings Field, 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 1996, the Company had participated in 178 gross (49 net) wells in
this field with 118 Frontier wells, 14 Dakota wells and 44 dual completions
(both Frontier and Dakota completed). Average net production for 1996 was
approximately 21.7 MMcfe per day. Forty-seven of the Company's wells drilled
in 1992 qualified for the Section 29 Tax Credit of approximately $.59 per Mcf,
which is attributable to all qualified production from these wells through
2002.
Since the middle of 1994, the Company has substantially reduced the rate
at which it has participated in new Moxa Arch wells. This reduction is
primarily due to: (i) Rocky Mountain gas prices which, on both an absolute and
relative basis, experienced a substantial decline in 1994 through late 1996,
but which recovered somewhat in late 1996 and early 1997, and (ii) the Bureau
of Land Management ("BLM") which has required all operators to perform an
environmental impact study ("EIS") along a portion of the Moxa Arch. In March
1997, the BLM issued its record of decision. In concluding its review of the
EIS, the BLM has authorized the drilling of approximately 700 natural gas
wells in the Moxa Arch, subject to review of certain air quality components.
The Company expects to re-commence drilling operations in the Moxa Arch Trend
in the middle of 1997. See "Item 1 -- Regulation -- Environmental
Regulation."
Green River, Big Horn and Wind River Basins. Effective November 1, 1996,
the Company entered into a joint development 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 will spend a
minimum of $20 million on seismic, leasing and exploratory activities through
December 31, 2001 and will initially earn rights to a 50% interest in
approximately 300,000 net acres. At December 31, 1996, one exploratory well
operated by UPR on the acreage was drilling.
Effective December 31, 1996, the Company entered into two joint
development agreements with SOCO pursuant to which Belco acquired or has the
right to acquire a 50% interest in 87,321 net acres in the Wind River Basin of
Wyoming and 110,859 net acres in the Big Horn Basin of Wyoming. Under such
agreements, SOCO will be operator with the two initial wells expected to be
spud on or before May 1, 1997.
5
The Company expects to participate in a series of exploratory vertical
wells in these Basins with UPR, SOCO and Yates serving as primary operators.
These wells will target multiple formations, the most prevalent of which is
the Frontier formation. If initial results are successful, these projects
hold the potential for multi-well developmental drilling programs for the
Company over the next several years.
Louisiana Austin Chalk Trend
The Louisiana Austin Chalk Trend is an extension of the 200-mile long
Austin Chalk Trend of Texas and represents a continuation of the Company's
exploration and development activities using deep-well horizontal drilling
technology. In December 1994, OXY USA announced the completion of a single
lateral horizontal Austin Chalk discovery in the Masters Creek area of central
Louisiana, approximately 200 miles east of the Company's activities in the
Giddings Field.
Since 1994, more than 2 million acres have been leased in the Louisiana
Austin Chalk Trend by industry participants including Belco, UPR, Chesapeake,
OXY USA and Sonat. At December 31, 1996, 23 rigs were drilling in the
Louisiana Austin Chalk Trend, including two rigs operated by Belco. At year
end 1996, Belco owned or had the right to acquire approximately 350,000 net
acres in this trend. This large acreage position provides the Company with
the opportunity to drill potentially in excess of 150 net horizontal Austin
Chalk wells, assuming spacing units of approximately 1,920 acres and assuming
continued drilling success by Belco and others in the Louisiana Austin Chalk
Trend.
In order to further development of its large acreage position, in
December 1996 Belco entered into two AMIs with UPR covering approximately
93,000 combined net acres in Avoyelles, Evangeline, Rapides and St. Landry
Parishes, and one AMI with OXY USA covering approximately 24,000 combined net
acres in St. Landry Parish. These AMIs, which provide for a sharing of costs
and benefits as well as operations in each such area, will allow Belco to
expedite the exploration and development of its acreage position and gain the
benefits of shared expertise with two leading industry partners and
experienced horizontal players.
Central Michigan Basin.
In June 1996, the Company entered into an exploration program with two
private oil and gas companies pursuant to which the Company acquired a 35%
interest in 220,000 net acres in the Central Basin of Michigan and obtained
the option to acquire an additional undivided 15% of such acreage following
the completion of a multi-well test program. By year-end 1996, Belco had
accumulated interests, including the foregoing, in a total of approximately
395,000 gross and 145,000 net acres in this Basin.
The initial objectives of this play are thin gas-bearing sands at depths
ranging from approximately 8,000 to 10,000 feet. In addition, shallower oil
zones are expected to be tested in the Company's 1997 drilling program.
In the fourth quarter of 1996, the Company began operations on an initial
seven-well test program covering different portions of this large acreage
position, including six re-entries and one grass root wells. Each of these
vertical wells will target one or more formations with long-lived reserves
anticipated. As of March 1, 1997, two wells were completed, two wells were
temporarily abandoned and three wells were in various stages of drilling or
completion. While per well recoveries are expected to modest, lower well
costs and higher natural gas prices in the area create the potential for
overall attractive economics. The price of natural gas sold in this area has
historically commanded a premium over NYMEX prices.
6
Gulf Coast
In March 1996, the Company entered into an exploration agreement with
Edge Petroleum Corporation pursuant to which the parties expect to jointly
conduct a series of 3-D seismic programs covering potentially up to 750
square miles onshore in the Gulf Coast region of Texas. Under the program,
Edge and the Company potentially initiated the first 50+ square mile 3-D
seismic shoots targeting the shallower Frio formation and potentially larger
reserves in the deeper Wilcox formation. Edge will be operator of any shallow
zone wells drilled under the program and the Company will operate prospects
targeting deeper zones. As of year end 1996, Belco and Edge had acquired
seismic options on approximately 36,000 gross acres. Belco expects the
seismic interpretation of the initial shoot to be complete in mid-1997 and the
drilling of any identified Frio formation targets to commence soon thereafter.
The Company utilized 3-D seismic technology to identify a series of
exploratory drilling opportunities in the Vicksburg and Queen City formations
in South Texas. As an example, the Company drilled the La Brisa #1 in Starr
County, Texas in the fourth quarter of 1996 which had initial rates of
production in excess of 10 MMcfe per day. The Company holds a 50% working
interest in this exploratory well and its offset which was spudded in February
1997. Belco drilled a second 42.5% owned exploratory well targeting the
Vicksburg formation which was a dry hole. Belco plans to commence drilling a
Queen City exploratory well by the middle of 1997.
East Texas Cotton Valley Reef Play
In December 1995 the Company acquired an interest in the East Texas
Cotton Valley Reef Play. During 1996, the Company drilled one dry hole,
conducted a 3-D seismic survey over a portion of the acreage and subsequently
relinquished its interest in the prospect. The Company expended approximately
$7.9 million on the East Texas Cotton Valley Reef Play.
COSTS INCURRED AND DRILLING RESULTS
Drilling Activity
The following table sets forth the wells participated in by the Company
during the periods indicated. In the table, "gross" refers to the total wells
in which the Company has a working interest, and "net" refers to gross wells
multiplied by the Company's working interest therein.
Year Ended December 31
--------------------------------------------
1996(1) 1995 1994
--------------- -------------- ----------
Gross Net Gross Net Gross Net
Development:
Productive 64.0(2) 23.0 84.0 24.0 82.0 21.0
Non-productive 2.0 0.8 6.0 1.2 0.0 0.0
---- ---- ----- ---- ---- ----
Total 66.0 23.8 90.0 25.2 82.0 21.0
==== ===== ===== ==== ==== ====
Exploratory:
Productive 10.0 7.9 5.0 1.9 5.0 1.2
Non-productive 3.0 2.4 2.0 0.3 0.0 0.0
---- ----- ---- ---- ---- ----
Total 13.0 10 .3 7.0 2.2 5.0 1.2
==== ===== ==== ==== ==== ===
______________________
(1) Does not include 16.0 gross (8.9 net) wells being drilled at December 31,
1996. On February 28, 1997, the CompanY was participating in the drilling of 28
gross (14.8 net) wells.
(2) Includes three gross oil and gas wells with multiple completions.
Multiple completions are counted only once for purposes of the above table.
7
Volumes, revenue, prices and production costs
The following table sets forth certain information regarding the production
volumes, revenue, average prices received and average production costs
associated with the Company's sale of oil and natural gas for the periods
indicated:
Year Ended December 31,
-------------------------
1996 1995 1994
------ ------ ------
Net production:
Oil (MBbl) . . . . . . . . . . . . 794 961 691
Gas (MMcf) . . . . . . . . . . . 51,289 37,047 17,482
Gas equivalent (MMcfe) . . . . . 56,053 42,813 21,628
Oil and gas sales ($ in 000's): $113,743 $78,247 $40,912
Average sales price (Unhedged):
Oil ($ per Bbl). . . . . . . . . . $21.30 $17.35 $16.48
Gas ($ per Mcf). . . . . . . . . . $2.00 $1.42 $1.67
Costs ($ per Mcfe):
Oil and gas operating expenses . . $0.14 $0.14 $0.25
General and administrative . . . . $0.06 $0.06 $0.10
Depreciation, depletion and amortization of oil
and gas properties . . . . . . . $0.73 $0.64 $0.65
____________________________
(1) Oil and gas sales for the fiscal years ended December 31, 1996, 1995 and
1994 includes ($5,967,000), $9,480,000 and $550,000, respectively, related to
commodity price risk management activities.
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,
---------------------------
1996 1995 1994
------ ------ ------
(in thousands)
Development costs $50,433 $54,451 $39,587
Exploration costs 17,444 2,382 1,727
Acquisition costs:
Unproved properties 64,530 13,643 10,916
Proved properties 9,871 ---- ----
Capitalized Interest 434 911 ----
-------- ------- -------
Total $142,712 $71,387 $52,230
======== ======= =======
8
ACREAGE
The following table sets forth, as of December 31, 1996, the gross and
net acres that the Company owns, controls or has the right to acquire
interests in both developed and undeveloped acreage. Developed acreage refers
to acreage within producing units and undeveloped acreage refers to acreage
that has not been placed in producing units.
"Gross" acres refers to the total number of acres in which the Company
owns a working interest. "Net" acres refers to gross acres multiplied by the
Company's fractional working interest.
Developed Undeveloped(1)
----------------- ------------------
Gross Net Gross Net
-------- ------- -------- -------
Texas:
Giddings Field 129,422 40,812 313,500 152,538
Other 428 214 35,17 217,720
Oklahoma:
Golden Trend 11,680 1,686 3,278 983
Wyoming:
Green River Basin - 0 - - 0 - 553,001 150,435
Moxa Arch Trend 25,737 14,290 33,822 19,755
Wind River Basin - 0 - - 0 - 57,923 28,459
Big Horn Basin - 0 - - 0 - 119,034 55,431
Louisiana:
Austin Chalk Trend 960 960 459,427 364,605
Michigan:
Central Basin - 0 - - 0 - 395,023 144,847
Denver-Julesburg Basin - 0 - - 0 - 217,811 131,032
------- ------ --------- ---------
Totals 168,227 57,962 2,187,991 1,065,805
======= ====== ========= =========
_________________________
(1) Leases covering approximately half of the undeveloped acreage will
expire within the next five 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.
PRODCUTIVE WELL SUMMARY
The following table sets forth the Company's ownership in productive
wells at December 31, 1996. Gross oil and gas wells include three with
multiple completions. Wells with multiple completions are counted only
once for purposes of the following table. Production from various formations
in wells without multiple completions is commingled.
Productive Wells
-----------------------
Gross Net
---------- ----------
Gas. . . . . . . . . . . . . . . . . . . . . 386.0 105.9
Oil. . . . . . . . . . . . . . . . . . . . . 31.0 14.0
----- -----
Total . . . . . . . . . . . . . . . . . . . . 417.0 119.9
===== =====
9
MARKETING
There are a variety of factors which affect the market for oil and
natural gas, including the extent of domestic production and imports of oil
and gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and gas, the marketing of
competitive fuels and the effects of state and federal regulations of oil and
gas production and sales. The Company has not experienced any difficulties in
marketing its oil or gas. The oil and gas industry also competes with other
industries in supplying the energy and fuel requirements of industrial,
commercial and individual customers.
Despite the measures taken by the Company to attempt to control price
risk, 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 Texas, Louisiana and Oklahoma, the Company sells its gas to purchasers
under percentage of proceeds or index-based contracts. Under the percentage
of proceeds contract, the Company receives a fixed percentage of the resale
price received by the purchaser for sales of residue gas and natural gas
liquids recovered after gathering and processing the Company's gas. The
Company receives between 85% and 92% of the proceeds from residue gas sales
and from 85% to 90% of the proceeds from natural gas liquids sales received by
the Company's purchasers when the products are resold. The residue gas and
natural gas liquids sold by these purchasers are sold primarily based on spot
market prices. The revenue received by the Company from the sale of natural
gas liquids is included in natural gas sales. Under indexed-based contracts,
the Company receives for its gas at the wellhead a price per MMBtu tied to
indexes published in Inside FERC or Gas Daily, subject in most cases to a
discount to the relevant index in lieu of a gathering fee.
In Wyoming, the Company sells all of its natural gas, natural gas liquids
and condensate from its Moxa Arch Wells under a market sensitive long term
sales contract with Amoco Energy Trading Corporation (the "Amoco Gas
Contract"). The price payable to the Company under the Amoco Gas Contract for
the gas is the Northwest Pipeline Rocky Mountain Index, plus $0.03 per MMBtu,
less fuel charges and gathering fees and adjusted for Btu content. The Amoco
Gas Contract expires on January 1, 1999. The Amoco Gas Contract can be
extended by the Company for an additional three year term.
All of the Company's current Wyoming oil and condensate production is
sold at market related prices pursuant to an option held by Amoco.
The Company's Moxa Arch wells are subject to various gathering agreements
with third parties including, as to wells drilled under the Amoco Farmout
Agreement in the Wilson Ranch, Seven Mile Gulch and Bruff areas, a Gas
Gathering and Processing Agreement dated March 20, 1992 with Northwest
Pipeline. Gathering fees under this agreement are presently $0.065 per MMBtu,
subject to indexed escalation, and fuel charges of 0.5%. Gathering fees and
fuel charges in the Cow Hollow/Shute Creek areas are similar to those under
the Amoco Gas Contract.
All of the Company's Texas, Louisiana and Oklahoma oil production is sold
under market sensitive or spot price contracts to various purchasers.
Sales to individual customers constituting 10% or more of total oil and
gas sales in 1996 were made to Aquila Southwest Pipeline (37%), GPM Gas
Corporation (31%) and Amoco Gas Trading Corp. (10%).
Management believes that the loss of any of the above customers would not
have a material adverse effect on the Company's results of operations or its
financial position.
10
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, it may
also limit future revenues from favorable price movements. The Company had
entered into price risk management transactions with respect to a substantial
portion of its production for 1996 and with respect to lesser portions of its
estimated production for 1997 and 1998 and significantly less for 1999. The
Company continues to evaluate whether to enter into additional such
transactions for 1997 and future years. In addition, the Company may
determine from time to time to terminate its then existing hedging and other
risk management positions.
All of the Company's price risk management transactions are carried out
in the over-the-counter market and not on the NYMEX, with financial
counterparties having at least an investment grade credit rating. All of
these transactions provide solely for financial settlements relating to
closing prices on the NYMEX.
The following is a summary of the types of price risk management
transactions in effect as of December 31, 1996.
Swaps. Since all of the Company's natural gas and oil is sold on
"floating" or market related prices, the Company has entered into financial
swap transactions which convert a floating price into a fixed price for a
future month. For any particular swap transaction, the counterparty is
required to make a payment to the Company in the event that the NYMEX
Reference Price for any settlement period is less than the swap price for such
hedge, and the Company is required to make a payment to the counterparty in
the event that the NYMEX Reference Price for any settlement period is greater
than the swap price for such hedge.
Reverse Swaps. When the Company determines it desires to reduce the
amount of swaps because of an assumed favorable outlook for prices it enters
into a reverse swap. Under such a transaction the role of the Company and the
role of the counterparty are reversed.
Collars. A collar provides for an average floor price and an average
ceiling price. For any particular collar transaction, the counterparty is
required to make a payment to the Company if the average NYMEX Reference Price
for the reference period is below the floor price for such transaction, and
the Company is required to make payment to the counterparty if the average
NYMEX Reference Price is above the ceiling price for such transaction.
Options, Puts and Straddles. When the Company believes that it receives
a sufficiently high cash premium (or other consideration) for granting the
counterparty a call or put option, it will enter into such a transaction. If
the Company's estimate of future price movement is correct then it will retain
the cash premium (or other benefit). If markets move against the Company, the
cost can be a multiple of the benefit received, e.g., if the Company sold a
$23 call on oil for $.40 a barrel for a given month and the price for that
month averaged $25 a barrel, it would lose $1.60 a barrel ($2.00 minus $.40 =
$1.60). But if oil averaged $22 a barrel, it would keep the $.40. Since the
Company believes it can be highly profitable at $23.40 a barrel, it regards
this as a prudent transaction under certain circumstances provided that the
Company always has more physical production for the periods involved than its
related aggregate risk management transactions. The transactions described in
this paragraph are required to be marked to market as to the value of these
transactions on the last day of the accounting period to which such statement
relates.
Basis Swaps. Since a substantial portion of the Company's natural gas is
sold under spot contracts with reference to Houston Ship Channel prices and
the Company's price risk management transactions are based on the NYMEX
Reference Price relating to gas delivered to Henry Hub, Louisiana, the Company
has entered into basis swaps that require the counterparty to make a payment
to the Company in the event that the average NYMEX Reference Price per MMBtu
for gas delivered to Henry Hub, Louisiana for a reference period exceeds the
average price for MMBtu for gas delivered at the Houston Ship Channel for such
reference period by more than a stated differential, and requires the Company
to make a payment to the counterparty in the event that the NYMEX Reference
11
Price for Henry Hub exceeds the price for Houston Ship Channel gas by less
than the stated differential (or in the event that the Houston Ship Channel
price exceeds the Henry Hub price). The Company also sells Wyoming gas at
prices based on the Northwest Pipeline Rocky Mountain Index (an index of
prices for gas delivered at various delivery points on the Northwest Pipeline
in the Northern Rocky Mountain area) and has entered into basis swaps that
requires the counterparty to make a payment to the Company in the event that
the average NYMEX Reference Price per MMBtu for gas delivered at Henry Hub,
Louisiana for a reference period exceeds the stated differential or to have
the Company pay to the counterparty if it is less than the stated
differential.
The result of all of these transactions with respect to 1996 and the open
positions for both natural gas and oil with respect to future years (primarily
1997 and 1998) are set forth in detail in Footnote 6 to the Consolidated
Financial Statements.
Certain of the Company's price risk management transactions were
previously covered by guarantees of, and certain other collateral from Robert
A. Belfer. Subsequent to the Initial Public Offering, all such guarantees
have been terminated and all such collateral has been returned.
TEXAS SEVERANCE TAX ABATEMENT
Production from natural gas wells that have been certified as tight
formations or deep wells by the Texas Railroad Commission ("high cost gas
wells") and that were spudded or completed during the period from June 16,
1989 to September 1, 1996 qualify for an exemption from the 7.5% severance tax
in Texas on natural gas and natural gas liquids produced by such wells prior
to August 31, 2001. The natural gas production from wells drilled on certain
of the Company's properties in the Austin Chalk area qualify for this tax
exemption. In addition, high cost gas wells that are spudded or completed
during the period from September 1, 1996 to August 31, 2002 are entitled to
receive a severance tax reduction upon obtaining a high cost gas certification
from the Texas Railroad Commission within 180 days after first production.
The tax reduction is based on a formula composed of the statewide "median" (as
determined by the State of Texas from producer reports) and the producer's
actual drilling and completion costs. More expensive wells will receive a
greater amount of tax credit. This tax rate reduction remains in effect for
10 years or until the aggregate tax credits received equal 50% of the total
drilling and completion costs.
LOUISIANA SEVERANCE TAX ABATEMENT
A five-year exemption from severance tax applies to production from oil
and gas wells that are returned to service after having been inactive for two
or more years or having 30 days or less of production during the past two
years. An application must be made to the Louisiana Department of Natural
Resources before commencement of production during the period beginning July
31, 1994, and ending June 30, 1998. Upon certification, the five-year
exemption period begins from the date of the application.
All severance tax is suspended for 24 months or until payout of the well
cost is achieved, whichever occurs first, on any horizontally drilled well or
recompletion well from which production commences after July 31, 1994. The
term "horizontal drilling" means high angle drilling of bore holes with 50 to
3,000 plus feet of lateral penetration through productive reservoirs, and
"horizontal recompletion" means horizontal drilling in an existing well bore.
Production of natural gas, gas condensate, and oil from any well drilled
to a true vertical depth of more than 15,000 feet and where production starts
after July 31, 1994, is exempt from severance tax for 24 months or until
payout of the well cost, whichever occurs first. The exemption applies to
production from any depth in the wellbore.
Currently, the Louisiana severance tax rate on oil is 12.5% of gross
value and the severance tax on gas is 7.7 cents per Mcf. Only one of the
severance tax exemptions discussed above may be taken on a particular well.
The Company anticipates that a substantial portion of its current and future
Louisiana wells will qualify for one of the two exemptions discussed above.
12
SECTION 29 TAX CREDIT
The natural gas production from wells drilled on certain of the Company's
properties in the Moxa Arch Trend and Golden Trend Field qualifies for the
Section 29 Tax Credit. The Section 29 Tax Credit is an income tax credit
against regular federal income tax liability with respect to sales of the
Company's production of natural gas produced from tight gas sand formations,
subject to a number of limitations. Fuels qualifying for the Section 29 Tax
Credit must be produced from a well drilled or a facility placed in service
after November 5, 1990 and before January 1, 1993, and be sold before January
1, 2003.
The basic credit, which is currently approximately $0.52 per MMBtu of
natural gas produced from tight sand reservoirs and approximately $1.03 per
MMBtu of natural gas produced from Devonian Shale, is computed by reference to
the price of crude oil and is phased out as the price of oil exceeds $23.50 in
1979 dollars (as adjusted for inflation) with complete phaseout if such price
exceeds $29.50 in 1979 dollars (as adjusted for inflation). Under this
formula, the commencement of phaseout would be triggered if the average price
for crude oil rose above approximately $45 per Bbl in current dollars. The
Company generated approximately $0.9 million of Section 29 Tax Credits in
1996. The Section 29 Tax Credit may not be credited against the alternative
minimum tax, but under certain circumstances may be carried over and applied
against regular tax liability in future years. Therefore, no assurances can
be given that the Company's Section 29 Tax Credits will reduce its federal
income tax liability in any particular year.
REGULATION
The oil and gas industry is extensively regulated by federal, state and
local authorities. In particular, oil and gas production operations and
economics are affected by price controls, environmental protection statutes
and regulations, tax statutes and other laws relating to the petroleum
industry, as well as changes in such laws, changing administrative regulations
and the interpretations and application of such laws, rules and regulations.
In October 1992, comprehensive national energy legislation was enacted which
focuses on electric power, renewable energy sources and conservation. The
legislation, among other things, guarantees equal treatment of domestic and
imported natural gas supplies, mandates expanded use of natural gas and other
alternative fuel vehicles, funds natural gas research and development, permits
continued offshore drilling and use of natural gas for electric generation and
adopts various conservation measures designed to reduce consumption of
imported oil. The legislation may be viewed as generally intended to
encourage the development and use of natural gas which is the Company's
principal product. 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 in, the plugging and abandoning of wells and the disposal of
fluids used in connection with operations. The Company's operations are also
subject to various conservation laws and regulations. These include the
regulation of the size of drilling and spacing units or proration units and
the density of wells which may be drilled in and the unitization or pooling of
oil and gas properties. In this regard, some states (such as Oklahoma) allow
the forced pooling or integration of tracts to facilitate exploration while
other states (such as Texas) rely on voluntary pooling of lands and leases.
In areas where pooling is voluntary, it may be more difficult to form units
and, therefore, more difficult to develop a project if the operator owns less
than 100% of the leasehold. In addition, state conservation laws establish
maximum rates of production from oil and gas wells, generally prohibit the
venting or flaring of gas and impose certain requirements regarding the
ratability of production. The effect of these regulations may limit the
amount of oil and gas the Company can produce from its wells and may limit the
number of wells or the locations at which the Company can drill. The
regulatory burden on the oil and gas industry increases the Company's costs of
doing business and, consequently, affects its profitability. Inasmuch as such
laws and regulations are frequently expanded, amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
regulations.
13
Natural Gas and Oil Marketing and Transportation. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy
Act of 1978 (the "NGPA"), and the regulations promulgated thereunder by the
Federal Energy Regulatory Commission (the "FERC"). In the past, the federal
government has regulated the wellhead price of natural gas. While sales by
producers of natural gas, and all sales of crude oil, condensate and natural
gas liquids, can currently be made at uncontrolled market prices, Congress
could reenact price controls in the future. Deregulation of wellhead sales in
the natural gas industry began with the enactment of the NGPA. In 1989, the
Natural Gas Wellhead Decontrol Act was enacted. This act amended the NGPA to
remove wellhead price controls on all domestic natural gas as of January 1,
1993.
Several major regulatory changes have been implemented by the FERC from
1985 to the present that affect the economics of natural gas production,
transportation and sales. In addition, the FERC continues to promulgate
revisions to various aspects of the rules and regulations affecting those
segments of the natural gas industry, most notably interstate natural gas
transmission companies, which remain subject to the FERC's jurisdiction.
These initiatives may also affect the intrastate transportation of gas under
certain circumstances. The stated purposes of many of these regulatory
changes is to promote competition among the various sectors of the gas
industry. The ultimate impact of these complex and overlapping rules and
regulations, many of which are repeatedly subjected to judicial challenge and
interpretation, cannot be predicted.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B
and 636-C (collectively, "Order No. 636"), which, among other things, require
interstate pipelines to "restructure" to provide transportation separate or
"unbundled" from the pipelines' sales of gas. Also, Order No. 636 requires
pipelines to provide open-access transportation on a basis that is equal for
all gas supplies. Order No. 636 has been implemented through negotiated
settlements in individual pipeline service restructuring proceedings. In many
instances, the result of the Order No. 636 and related initiatives have been
to substantially reduce or bring to an end the interstate pipelines'
traditional roles as wholesalers of natural gas in favor of providing only
storage and transportation services.
Although Order No. 636 does not directly regulate natural gas producers
such as the Company, the FERC has stated that Order No. 636 is intended to
foster increased competition within all phases of the natural gas industry.
It is unclear what impact, if any, increased competition within the natural
gas industry under Order No. 636 will have on the Company and its natural gas
marketing efforts. In addition, Order 636 and subsequent FERC orders issued
in individual pipeline restructuring proceedings have been the subject of
appeals, the results of which have generally supported the FERC's open-access
policy. Last year, the United States Court of Appeals for the District of
Columbia Circuit largely upheld Order No. 636. Because further review of
certain of these orders is still possible and other appeals remain pending, it
is difficult to predict the ultimate impact of the orders on the Company and
its production efforts. Although Order No. 636, assuming it is upheld in its
entirety in its current form, could provide the Company with additional market
access and more fairly applied transportation service rates, terms and
conditions, it could also subject the Company to more restrictive pipeline
imbalance tolerances and greater penalties for violations of those tolerances.
The Company does not believe, however, that it will be affected by any action
taken with respect to Order No. 636 materially differently than other natural
gas producers and marketers with which it competes.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in
which interstate pipelines release capacity under Order No. 636 and, more
recently, the price which shippers can charge for their released capacity. In
addition, in 1995, FERC issued a policy statement on how interstate natural
gas pipelines can recover the costs of new pipeline facilities. In January
1996, the FERC issued a policy statement and a request for comments concerning
alternatives to its traditional cost-of-service ratemaking methodology. A
number of pipelines have obtained FERC authorization to charge negotiated
rates as one such alternative. While any additional FERC action on these
matters would affect the Company only indirectly, these policy statements and
proposed rule changes are intended to further enhance competition in natural
gas markets. The Company cannot predict what action the FERC will take on
these matters, nor can it predict whether the FERC's actions will achieve its
stated goal of increasing competition in natural gas markets. However, the
Company does not believe that it will be treated materially differently than
other natural gas producers and marketers with which it competes.
14
Commencing in October 1993, the FERC issued a series of rules (Order Nos.
561 and 561-A) establishing an indexing system under which oil pipelines will
be able to change their transportation rates, subject to prescribed ceiling
levels. The indexing system, which allows or may require pipelines to make
rate changes to track changes in the Producer Price Index for Finished Goods,
minus one percent, became effective January 1, 1995. The Company is not able
at this time to predict the effects of Order Nos. 561 and 561-A, if any, on
the transportation costs associated with oil production from the Company's oil
producing operations.
Certain operations the Company conducts are on federal oil and gas
leases, which the Minerals Management Services ("MMS") administers. The MMS
issues such leases through competitive bidding. These leases contain
relatively standardized terms and require compliance with detailed MMS
regulations and orders. In addition to permits required from other agencies
(such as the Environmental Protection Agency), lessees must obtain a permit
from the MMS prior to the commencement of drilling. The MMS has promulgated
regulations implementing restrictions on various production-related
activities, including restricting the flaring or venting of natural gas. In
addition, the MMS recently amended its regulations to prohibit the flaring of
liquid hydrocarbons (including oil) without prior authorization. Finally, the
MMS is conducting an inquiry into certain contract agreements from which
producers on MMS leases have received settlement proceeds that are royalty
bearing and the extent to which producers have paid the appropriate royalties
on those proceeds. The Company believes that this inquiry will not have a
material impact on its financial condition, liquidity or results of
operations.
Under certain circumstances, the MMS may require any Company operations
on federal leases to be suspended or terminated. Any such suspension or
termination could materially and adversely affect the Company's financial
condition and operations.
The MMS has issued a notice of proposed rulemaking in which it proposes
to amend its regulations governing the calculation of royalties and the
valuation of natural gas produced form federal leases. The principle feature
in the amendments, as proposed, would establish an alternative market-index
based method to calculate royalties on certain natural gas production sold to
affiliates or pursuant to non-arm's length sales contracts. The MMS has
proposed this rulemaking to facilitate royalty valuation in light of changes
in the gas marketing environment. The Company cannot predict what action the
MMS will take on this matter, nor can it predict at this stage of the
rulemaking proceeding how the Company might be affected by this amendment to
the MMS' regulations.
The MMS has also issued a notice of proposed rulemaking in which it
proposes to amend its regulations governing the calculation of royalties and
the valuation of crude oil produced from federal leases. This proposed rule
would modify the valuation procedures for both arm's length and non-arm's
length crude oil transactions to decrease reliance on oil posted prices and
assign a value to crude oil that better reflects market value, establish a new
MMS form for collecting value differential data, and amend the valuation
procedure for the sale of federal royalty oil. The Company cannot predict
what action the MMS will take on this matter, nor can it predict at this stage
of the rulemaking proceeding how the company might be affected by this
amendment to the MMS' regulations.
Additional proposals and proceedings that might affect the oil and gas
industry are pending before the FERC and the courts. The Company cannot
predict when or whether any such proposals may become effective. In the past,
the natural gas industry has been heavily regulated. There is no assurance
that the regulatory approach currently pursued by the FERC will continue
indefinitely. Notwithstanding the foregoing, the Company does not anticipate
that compliance with existing federal, state, and local laws, rules, and
regulations will have a material or significantly adverse effect upon the
capital expenditures, earnings, or competitive position of the Company.
Environmental Regulation. Activities of the Company with respect to the
exploration, development and production of oil and natural gas are subject to
stringent environmental regulation by local, state and federal authorities
including the Environmental Protection Agency ("EPA"). Such regulation has
increased the cost of planning, designing, drilling, operating and, in many
instances, abandoning wells. In most instances, the regulatory requirements
relate to the handling and disposal of drilling and production waste products
and waste created by water and air pollution control procedures. Although the
Company believes that compliance with environmental regulations will not have
a material adverse effect on operations or earnings, risks of substantial
costs and liabilities are inherent in oil and gas operations, and there can be
15
no assurance that significant costs and liabilities, including criminal
penalties, will not be incurred. Moreover, it is possible that other
developments, such as stricter environmental laws and regulations or claims
for damages to property or persons resulting from the Company's operations,
could result in substantial costs and liabilities.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons with respect to the release of a "hazardous
substance" into the environment. These persons include current and former
owners and operators of the facility or site where the release occurred and
the companies that disposed or arranged for the disposal of the hazardous
substances released at the site. Persons who are or were responsible for
releases of hazardous substances under CERCLA or similar state laws may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment.
The Company generates wastes, including hazardous wastes, that are
subject to regulation under the federal Resource Conservation and Recovery Act
("RCRA") and comparable state statutes. Under RCRA, the EPA and various state
agencies have established extensive regulations pertaining to the generation,
transportation, storage, treatment and disposal of hazardous and nonhazardous
wastes. Furthermore, certain wastes generated by the Company's oil and
natural gas operations that are currently exempt from treatment as "hazardous
wastes" may in the future be designated as "hazardous wastes," and therefore
be subject to more rigorous and costly operating and disposal requirements.
The Company currently owns or leases, and has in the past owned or
leased, numerous properties that for many years have been used for the
exploration and production of oil and gas. Although the Company has utilized
operating and disposal practices that were standard in the industry at the
time, hydrocarbons or other wastes may have been disposed of or released on or
under the properties owned or leased by the Company or on or under other
locations where such wastes have been taken for disposal. In addition, many
of these properties have been operated by third parties whose treatment and
disposal or release of hydrocarbons or other wastes was not under the
Company's control. These properties and the wastes disposed thereon may be
subject to CERCLA, RCRA and analogous state laws. Under such laws, the
Company could be required to remove or remediate previously disposed wastes
(including wastes disposed of or released by prior owners or operators) or
property contamination (including groundwater contamination) or to perform
remedial plugging operations to prevent future contamination.
The Company's operations are subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted
in 1990 and contain provisions that may result in the gradual imposition of
certain pollution control requirements with respect to air emissions from the
operations of the Company. The EPA and states have been developing
regulations to implement these requirements. The Company may be required to
incur certain capital expenditures in the next several years for air pollution
control equipment in connection with maintaining or obtaining operating
permits and approvals addressing other air emission-related issues. However,
the Company does not believe its operations will be materially adversely
affected by any such requirements.
The Oil Pollution Act of 1990 ("OPA") amends certain provisions of the
federal Water Pollution Control Act of 1972, commonly referred to as the Clean
Water Act ("CWA") and other statutes as they pertain to the prevention of and
response to oil spills into navigable waters. The OPA subjects owners and
operators of facilities to strict joint and several liability for all
containment and cleanup costs and certain other public and private damages
arising from a spill, including, but not limited to, the costs of responding
to a release of oil to surface waters. OPA establishes a liability limit for
onshore facilities of $350 million and, for offshore facilities, all removal
costs plus $75 million, however a party cannot take advantage of liability
limits if the spill is caused by gross negligence or willful misconduct or
resulted from a violation of a federal safety, construction or operating
regulation. If a party fails to report a spill or cooperate in the cleanup,
liability limits likewise do not apply. The Company may, under recent
amendments to OPA, also be required to demonstrate financial responsibility
for up to $10 million in environmental cleanup and restoration costs. The
Company expects that financial responsibility could be established through
16
insurance, guaranty, indemnity, surety bond, letter of credit, qualification
as a self-insurer or a combination thereof. Although the Company cannot
predict the final form of the financial responsibility rule that may be
adopted under the recent OPA amendments, the impact of the rule is not
expected to be any more burdensome to the Company than it will be to other
similarly situated companies involved in oil and gas exploration and
production activities. The CWA provides penalties for any discharges of
petroleum product in reportable quantities and imposes substantial liability
for the costs of removing a spill. State laws for the control of water
pollution also provide varying civil and criminal penalties and liabilities in
the case of releases of petroleum or its derivatives into surface waters or
into the ground. Federal regulations under the CWA and OPA require certain
owners or operators of facilities that store or otherwise handle oil, such as
the Company, to prepare and implement spill prevention, control and
countermeasure plans and facility response plans relating to the possible
discharge of oil into surface waters. In addition, the CWA and analogous
state laws require permits to be obtained to authorize discharges into surface
waters or to construct facilities in wetland areas. With respect to certain
of its operations, the Company is required to maintain such permits or meet
general permit requirements. In 1992, the EPA adopted regulations concerning
discharges of storm water runoff. This program requires covered facilities to
obtain individual permits, participate in a group permit or seek coverage
under an EPA general permit. The Company believes that it is in substantial
compliance with the requirements of the CWA and OPA and that any
non-compliance would not have a material effect on the Company.
In April of 1994, the Bureau of Land Management directed that an
environmental impact study ("EIS") be performed along a portion of the Moxa
Arch area of Wyoming. The final EIS was completed in June of 1996. In March
of 1997, the BLM issued its record of decision relating to this EIS. During
the pendency of the EIS and record of decision, regulatory approval to drill
wells in the affected area was difficult to obtain. The BLM's record of
decision authorized the drilling of approximately 700 natural gas wells in the
Moxa Arch, subject to review of certain air quality components. The Company
believes that drilling activity will now resume, albeit subject to the record
of decision.
TITLE TO PROPERTIES
Title to properties is subject to royalty, overriding royalty, carried,
net profits, working and other similar interests and contractual arrangements
customary in the oil and gas industry, to liens for current taxes not yet 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 (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 March 3, 1997, the Company had 67 full time employees, none of whom
is represented by organized labor unions. The Company considers its employee
relations to be good.
17
OFFICE AND EQUIPMENT
The Company maintains its executive offices at 767 Fifth Avenue, New
York, New York. The Company pays Robert A. Belfer a fee of $250,000 per annum
for office space and services provided through such office. This fee is
indexed to the consumer price index. The fee is based on the actual cost of
such office space pro-rated to the amount utilized in Company operations. The
Company believes the fee compares favorably to the terms which might have been
available from a non-affiliated party. The Company currently has 21 months
remaining on a lease covering 14,500 square feet of office space in Houston,
Texas. The lease contains two two-year renewal options. The Company also
owns a property in Granger, Wyoming consisting of a metal building and
associated four acres, used by Belco as a production office and yard. The
Company also maintains an inventory of field equipment and materials including
tubular goods, compressors, pumping units and field vehicles.
FORWARD-LOOKING INFORMATION AND RISK FACTORS
Certain of the statements set forth under "Item 1 - Business", "Item 2 -
Properties" and "Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations" and elsewhere in this Form 10-K, such as
the statements regarding planned capital expenditures, the availability of
capital resources to fund capital expenditures, estimates of proved reserves
and the number of anticipated wells to be drilled in 1997 and thereafter, are
forward-looking and are based upon the Company's current belief and
assumptions as to the outcome and timing of such future events. There are
numerous risks and uncertainties that can affect the outcome and timing of
such events, including many factors beyond the control of the Company. These
factors include, but are not limited to, the matters described below. Should
one or more of these risks, uncertainties or other factors materialize, or
should underlying beliefs and assumptions prove incorrect, the Company's
actual results and plans for 1997 and beyond could differ materially from
those expressed in the forward-looking statements.
Volatility of Oil and Gas Prices. The Company's future revenue,
profitability and rate of growth are substantially dependent upon the
prevailing prices of, and the demand for, oil and natural gas. Prices for oil
and natural gas are subject to wide fluctuation due to changes in the supply
of and demand for such commodities, market uncertainty, and a variety of
additional factors that are beyond the control of the Company, such as various
economic, political and regulatory developments, and competition from other
sources of energy.
Uncertainty of Estimates of Oil and Gas Reserves. Estimating quantities
of reserves and future net cash flows is not an exact science. There are
numerous uncertainties inherent in estimating quantities of proved oil and gas
reserves, including many factors beyond the control of the Company. This Form
10-K contains estimates of the proved oil and gas reserves of the Company and
the estimated future net cash flows therefrom. Such estimates rely upon
various assumptions, including those prescribed by the Securities and Exchange
Commission, such as future oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. The present
value of future net cash flows referred to in this Form 10-K should not be
construed as the current market value of the estimated oil and gas reserves
attributable to the Company's properties. The process of estimating oil and
gas reserves is complex, requiring significant decisions and assumptions in
the evaluation of available geological, engineering and economic data for each
reservoir. As a result, any such estimate is inherently an imprecise
estimation of reserve quantities and estimated future net revenue therefrom.
Actual future production, revenue, taxes, development expenditures, operating
expenses and quantities of recoverable oil and gas reserves will vary from
those assumed in the estimate.
Any significant variance from the assumptions could materially affect the
quantity and value of the Company's reserves as compared to the estimates set
forth in this Form 10-K. The Company's production operations may be curtailed
or suspended as a result of governmental requirements or price controls,
mechanical difficulties or other circumstances beyond the control of the
Company. The Company's properties may also be susceptible to hydrocarbon
drainage from production by other operators on adjacent properties. In
addition, these 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.
Need for Development and Acquisition of Additional Reserves. The
Company's future success, as is generally the case in the industry, depends
upon its ability to find, develop or acquire additional oil and gas reserves
18
that are economically recoverable. Unless the Company conducts successful
exploration, development and exploitation activities on properties it
currently owns or acquires in the future or acquires additional properties
containing proved reserves, the Company's proved reserves will naturally
decline. The successful acquisition of producing properties requires an
assessment of recoverable reserves, future oil and gas prices and operating
costs, potential environmental and other liabilities, title issues and other
factors. Such assessments are necessarily inexact and their accuracy is
inherently uncertain.
There can be no assurance that the Company's exploration and development
projects will result in significant additional reserves being found or that
the Company will have success drilling productive wells at economically viable
costs. Furthermore, while the Company's revenues may increase if prevailing
oil and gas prices increase, the Company's finding costs for additional
reserves could also increase.
The Company intends to make substantial capital expenditures for the
acquisition, exploration, development and production of its oil and natural
gas reserves. While the Company believes that cash flow from operations and
borrowings under the Company's existing bank credit facility should provide
the Company with sufficient funds for its planned activities through the end
of 1997, additional debt or equity financing may be desirable or required
prior to such time or thereafter to fund further exploration, exploitation and
development activities or future property acquisitions. No assurances can be
given as to the availability or terms of any such additional financing that
may be required or that financing will continue to be available to the
Company. If such financing is not available, the Company's exploration,
exploitation and development activities and future property acquisitions may
be curtailed.
Risks of Hedging 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 hedging
arrangements with respect to a portion of its expected production. These
arrangements may include futures contracts on the New York Mercantile Exchange
("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 substantially over the price established by the hedge. In
addition, the Company engages in certain price risk management transactions
which are required to be marked-to-market in connection with the Company's
financial reporting. Such hedging and price risk management 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 hedging
arrangement, (iii) the counterparties to the Company's future contracts fail
to perform the contract, or (iv) a sudden, unexpected event materially impacts
oil or natural gas prices.
Reliance on Key Personnel. The Company is dependent upon Robert A.
Belfer, the Company's Chairman, President and Chief Executive Officer, and
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.
Control by Certain Stockholders. Robert A. Belfer, his spouse, his
children, his sisters, their spouses, their children and trusts for their
children and grandchildren own approximately 76.4% of the outstanding shares
of Common Stock. As a result, such stockholders will be able to effectively
control the outcome of certain matters requiring a stockholder vote, including
the election of directors. Such ownership of Common Stock may have the effect
of delaying, deferring or preventing a change of control of the Company and
may adversely affect the voting and other rights of other stockholders.
Certain Potential Conflicts of Interests. Robert A. Belfer is a director
of Enron Corp. ("Enron"). Enron, primarily through its majority owned
subsidiary, Enron Oil & Gas Company ("EOG"), is involved in the exploration,
development and production of oil and gas. Mr. Belfer is not a director of
EOG. While the Company's activities have not historically overlapped with the
activities of Enron or EOG, the Company may in the future compete for certain
opportunities with Enron or EOG. To the extent any conflict from such future
competition may arise, Mr. Belfer intends to excuse himself from participating
in any decisions of the Board of Directors of Enron related to such
opportunities.
19
Marketability of Production. The marketability of the Company's
production depends upon the availability and capacity of gas gathering
systems, pipelines and processing facilities, and the unavailability or lack
of capacity thereof could result in the shut-in of producing wells or the
delay or discontinuance of development plans for properties. In addition,
Federal and state regulation of oil and gas production and transportation,
general economic conditions and changes in supply and demand could adversely
affect the Company's ability to produce and market its oil and natural gas on
a profitable basis.
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 the equipment and
labor required to develop and operate such properties. The Company also
competes with major and independent oil and gas companies in the marketing and
sale of oil and natural gas to marketers and end-users. Many of these
competitors have financial and other resources substantially greater than
those of the Company.
Drilling Risks. Drilling involves numerous risks, including the risk
that no commercially productive oil or gas reservoirs will be encountered.
The cost of drilling and completing wells is often uncertain, and drilling
operations may be curtailed, delayed or canceled as a result of a variety of
factors, including unexpected drilling conditions, pressure or irregularities
in formations, equipment failures or accidents, weather conditions, and
shortages or delays in the delivery of equipment. There can be no assurance
as to the success of the Company's future drilling activities. The Company,
and the industry in general, has experienced higher demand for drilling rigs
and related products and services since early 1996. As a result, the Company
has experienced delays in obtaining drilling rigs and higher drilling costs in
general. The Company does not believe that this increased demand or higher
costs will have a significant impact on the Company's profitability or its
planned drilling activities.
Operating Hazards. The oil and gas business involves a variety of
operating risks, including 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. 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 obtained by the Company will be
adequate to cover any losses or liabilities. The Company cannot predict the
continued availability of insurance or the availability of insurance at
premium levels that justify its purchase.
Compliance with Governmental Regulations. Oil and gas operations are
subject to various federal, state and local governmental regulations which may
be changed 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 or other financial responsibility
requirements, reports concerning operations, the spacing of wells, 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. These laws and regulations have
continually imposed increasingly strict requirements for water and air
pollution control and solid waste management.
No Dividends. The Company has never paid cash dividends on its Common
Stock and does not intend to paycash dividends on its Common Stock in the
foreseeable future. The Company currently intends to retain its cash for the
continued development of its business, including development, exploration and
acquisition activities. In addition, the Company's bank credit facility
currently restricts the ability of the Company to pay dividends.
20
CERTAIN DEFINITIONS
The terms defined in this section are used throughout this Form 10-K.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used
herein in reference to crude oil or other liquid hydrocarbons.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet of gas equivalent.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Developed Acreage. The number of acres which are allocated or assignable
to producing wells or wells capable of production.
Development Well. A well participated in within the proved area of an
oil or gas reservoir to the depth of a stratigraphic horizon known to be
productive.
Dry Hole; Dry Well. A well found to be incapable of producing either oil
or gas in sufficient quantities to justify completion as an oil or gas well.
Exploratory Well. A well participated in to find and produce oil or gas
in an unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir or to extend a known reservoir.
Farmout. An assignment of an interest in a drilling location and related
acreage conditional upon the drilling of a well on that location.
Formation. A succession of sedimentary beds that were deposited under
the same general geologic conditions.
Gross Acres or Gross Wells. The total acres or wells, as the case may
be, in which a working interest is owned.
Horizontal Wells. Wells which are participated in at angles greater than
70 from vertical.
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet of gas equivalent, using the ratio of one
barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural
gas.
MMBbl. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet of gas equivalent.
Net Acres or Net Wells. The sum of the fractional working interests
owned in gross acres or gross wells.
21
Present Value. When used with respect to oil and gas reserves, present
value means 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 at the determination date,
without giving effect to non-property related expenses such as general and
administrative expenses, debt service and future income tax expense or to
depreciation, depletion and amortization, discounted using an annual discount
rate of 10%.
Productive Well. A well that is producing oil or gas or that is capable
of production.
Proved Developed Reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved Reserves. The estimated quantities of crude oil, natural gas
liquids 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 Undeveloped Reserves. 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.
Undeveloped Acreage. Lease acreage on which wells have not been
participated in or completed to a point that would permit the production of
commercial quantities of oil and gas regardless of whether such acreage
contains proved reserves.
Item 2 - PROPERTIES
OIL AND GAS RESERVES
The Company engaged Miller & Lents to estimate the Company's net proved
reserves, projected future production, estimated future net revenue
attributable to its proved reserves, and the present value of such estimated
future net revenue as of December 31, 1996. Miller & Lents' estimates were
based upon a review of production histories and other geologic, economic,
ownership and engineering data provided by the Company. In estimating the
reserve quantities that are economically recoverable, Miller & Lents used
selling prices and estimated development and production costs that were in
effect during December 1996 without giving effect to hedging activities. In
accordance with requirements of the Commission, no price or cost escalation or
de-escalation was considered by Miller & Lents.
Horizontal completions are relatively new and, therefore, reserve
estimates for such wells are inherently less certain than estimates of
reserves from wells completed utilizing traditional methods having longer
production histories. This lack of operating history also prevents reservoir
engineers from estimating reserves based on production and pressure
performance methods. Reserves assigned to these properties were necessarily
based on analogy with older wells producing from the same horizons. Reserve
estimates based on analogy are less precise than estimates based on volumetric
calculations or analysis of production and pressure performance. See, "Item 1
- - Business - Forward Looking Information and Risk Factors."
22
The table below sets forth information as of December 31, 1996, with
respect to the Company's estimated net proved reserves, the present value of
estimated future net revenue at such date, as estimated by Miller & Lents.
The present value of estimated future net revenue shown is not intended to
represent the current market value of the estimated oil and gas reserves owned
by the Company. For further information concerning the present value of
future net revenue from these proved reserves, see Note 13 of Notes to
Combined Financial Statements.
Proved Proved
Developed(1) Undeveloped(2)(3) Total(3)
------------ ----------------- --------
(Dollars in thousands)
Estimated Proved Reserves:
Oil and Condensate (MMBbls) 2.1 1.2 3.3
Gas (Bcf) (4) 184.9 100.1 285.0
Gas Equivalents (Bcfe) 197.3 107.7 305.0
Estimated future net revenue before
income taxes (5) $559,131 $248,958 $808,089
Present value of estimated future net
revenue before income taxes
(discounted at 10% per
annum) (5) $336,247 $134,332 $470,579
__________________________________
(1) Proved developed reserves are proved reserves which are expected to be
recovered from existing wells with existing equipment and operating methods.
(2) Proved undeveloped reserves are proved reserves which are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of such reserves can be estimated with
reasonable certainty or from existing wells where a relatively major
expenditure is required to establish production.
(3) Includes approximately 11 Bcfe of proved undeveloped reserves subject to
a participation right owned by third party investors in the Company's Moxa
Arch Drilling Programs.
(4) Includes natural gas liquids.
(5) Estimated future net revenue represents estimated future gross revenue to
be generated from the production of proved reserves, net of estimated
production and future development costs, using prices at year-end 1996, which
were $3.68 per Mcf of gas and $25.13 per barrel of oil without giving effect
to hedging activities. AT December 31, 1996, the estimated future net revenue
before income taxes and the present value of such estimated future net revenue
before income taxes related to hedges were ($60,760) and ($55,151),
respectivelY (based on oil and gas prices in effect at December 31, 1996),
which amounts have not been deducted froM estimated future net revenue before
income taxes and its present value as shown above. If such amounts were
deducted, estimated future net revenue before income taxes would equal
$498,372 (Proved Developed) and $747,330 (Total) and present values of such
estimated future net revenues before income taxes would equal $281,198 (Proved
Developed) and $415,530 (Total). The amounts shown do not give effect to
non-property related expenses, such as general and administrative expenses,
debt service and future income tax expense or to depreciation, depletion and
amortization. See Note 13 to Notes to Combined Financial Statements.
No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Commission.
The prices used in calculating the estimated future net revenue
attributable to proved reserves do not necessarily reflect market prices for
oil and gas production subsequent to December 31, 1996. For example, the
market price for natural gas on the date of this Form 10-K was dramatically
lower than the gas price assumed for purposes of such estimates. There can be
23
no assurance that all of the proved reserves will be produced and sold within
the periods indicated, that the assumed prices will actually be realized for
such production or that existing contracts will be honored or judicially
enforced.
With respect to the interests described in Note (3) above, the Company's
actual interests may differ from such assumed interests as a result of Moxa
Arch Program investor's determination to participate in offset wells under
applicable participation agreements.
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. Furthermore, the estimated future net
revenue from proved reserves and the present value thereof are based upon
certain assumptions, including prices, future production levels and costs,
that may not prove correct over time. Predictions about prices and future
production levels are subject to great uncertainty, and this is particularly
true as to proved undeveloped reserves, which are inherently less certain than
proved developed reserves and which comprise a significant portion of the
Company's proved reserves. See "Item 1 - Business - Forward Looking
Information and Risks Factors."
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, 1996, no matters were submitted by
the Company to a vote of its security holders.
24
PART II
Item 5 - MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
As of March 24, 1997, the Company estimates there were approximately 2,515
beneficial holders of its Common Stock. The Company's Common Stock is listed
on the New York Stock Exchange ("NYSE") and traded under the symbol "BOG". As
of March 24, 1997, the Company had 31,582,300 shares outstanding and its
closing price on the NYSE was $20.25 per share. The high and low sales prices
for the Company's Common Stock during each quarter in the year ended December
31, 1996 were as follows:
COMMON STOCK
High Low
Quarter:
First . . . . . . . . . . . $22.875 $21.625
Second. . . . . . . . . . . $35.50 $22.25
Third . . . . . . . . . . . $37.25 $21.25
Fourth. . . . . . . . . . . $29.125 $23.00
The Company has never paid a dividend, cash or otherwise. Certain
provisions of the Company's bank credit facility restrict the Company's
ability to declare or pay cash dividends unless certain financial ratios are
maintained. The Company currently intends to maintain a policy of retaining
cash for the continued expansion of its business.
In connection with the Company's formation, Robert A. Belfer acquired
1,000 shares of Common Stock on January 12, 1996. The Company issued such
1,000 shares to Mr. Belfer upon his payment of $1,000 in a transaction exempt
under Section 4(2) of the Securities Act of 1933, as amended (the "Securities
Act"). Such shares were redeemed for $1,000 upon consummation of the
Combination.
Pursuant to Section 4(2) of the Securities Act, on March 29, 1996 the
Company completed the Combination effective January 1, 1996, of certain oil
and gas interests held by Mr. Belfer, members of his family, trusts and
certain employees of the Company.
25
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.
Period From Inception
Year Ended December 31, (April 30,1992) to
------------------------
December31,
1996 1995 1994 1993 1992
------ ------ ------ ----- -----
(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Oil and gas sales $119,710 $68,767 $40,362 $19,255 $3,536
Commodity Price Risk Management
Activities (5,967) 9,480 550 -- --
Interest 2,653 353 195 57 80
-------- ------- ------- ------- ------
Total revenues 116,396 78,600 41,107 19,312 3,616
-------- ------- ------- ------- -------
Costs and expenses:
Oil and gas operating expenses 7,847 5,824 5,510 2,495 289
Depreciation, depletion and amortization 40,904 27,590 14,072 4,098 401
General and administrative 3,059 2,597 2,269 856 424
-------- ------- ------- ------- ------
Total costs and expenses 51,810 36,011 21,851 7,449 1,114
-------- ------- ------- ------- ------
Income before income taxes 64,586 42,589 19,256 11,863 2,502
Pro forma provision in lieu of income tax (1) 21,953 13,852 5,030 1,504 637
-------- ------- ------- ------- -------
Pro forma net income (1) $42,633 $28,737 $14,226 $10,359 $ 1,865
======== ======= ======= ======= =======
Pro forma earnings per share (1) $ 1.42 $ 1.15 $ .57 $ .41 $ .07
======== ======= ======= ======= =======
Weighted average common shares outstanding (2) 29,986 25,000 25,000 25,000 25,000
Statement of Cash Flows Data:
Income before income taxes, depreciation,
depletion and amortization and other
non-cash items (3) $108,716 $69,609 $33,605 $15,961 $ 2,903
Capital expenditures 142,712 71,387 52,230 32,647 15,744
Cash flow from operating activities 108,059 62,037 28,126 14,351 729
Cash flow from investing activities (143,826) (65,133) (52,670) (33,698) (13,086)
Cash flow from financing activities 77,684 (2,299) 30,376 18,708 14,115
Balance Sheet Data:
Working capital $ 48,667 $ 446 $14,357 $ 3,108 $ 1,184
Total assets 303,918 145,550 101,625 50,248 19,671
Long-term debt -- 22,000 6,930 -- --
Equity 233,203 105,015 89,890 47,188 16,617
____________________
(1) Gives pro forma effect to the application of federal and state income
taxes to the Company as if it were a taxable corporation for the periods
presented. 1996 includes a one-time non-cash deferred tax charge of $30.1
million recognized as a result of the Combination consummated on March 29,
1996 in connection with the Company's Initial Public Offering.
(2) Pro forma earnings per share has been computed as if the 25,000,000
shares of Common Stock that were issued in connection with Combination had
been outstanding for all years prior to 1996.
(3) Income before income taxes, depreciation, depletion and amortization and
other non-cash mark-to-market accounting provisions (1996 only) is presented
as a measure of the Company's ability to service its debt and to fund capital
expenditures, not as a measure of operating results, and is not presented in
the financial statements.
26
Item 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following is a review of the Company's financial position and results of
operations for the periods indicated. The Company's financial statements and
the related notes thereto which follow contain detailed information that
should be referred to in conjunction with Management's Discussion and
Analysis.
OVERVIEW
Since its inception in April 1992, the Company has grown rapidly, with
substantially all of its growth coming "through the drill bit".
The Company's participation in exploration and development activities in
the Moxa Arch Area of Wyoming and in the Austin Chalk Trend in the Giddings
Field of Texas are principally responsible for the substantial expansion of
production, revenues and reserves since the Company's inception.
The Company was organized as a Nevada corporation in January 1996 in
connection with the Combination (the "Combination") of ownership interests
(the "Combined Assets") in certain entities (the "Predecessors") and direct
interests in oil and gas properties and certain hedge transactions (the
"Direct Interests") owned by members of the Robert A. Belfer family and by
employees of the Predecessors and entities related thereto. The Company and
the owners of the Combined Assets entered into an Exchange and Subscription
Agreement and Plan of Reorganization, dated as of January 1, 1996 (the
"Exchange Agreement"), that provided for the issuance by the Company of an
aggregate of 25,000,000 shares of Common Stock to such owners in exchange for
the Combined Assets on March 29, 1996, the date the Offering closed. The
owners of the Combined Assets received shares of Common Stock proportionate to
the value of the Combined Assets underlying their ownership interests in the
Predecessors and the Direct Interests.
Pursuant to the Exchange Agreement, the owners of the Combined Assets
received all revenues attributable to production and are responsible for all
incurred expenses related to the Combined Assets for all periods prior to
January 1, 1996. Effective with the Combination (which was contemporaneous
with the closing of the Offering), the Company is entitled to receive all
revenues and is responsible for all expenses related to the Combined Assets on
and after January 1, 1996.
From inception through the date of the Exchange, March 29, 1996, the
Predecessors were not required to pay federal income taxes due to their status
as either a partnership, individual owner, Subchapter S corporation, limited
liability corporation or joint venture, which are "pass-through" entities that
are not subject to federal income taxation; instead, taxes relating to the
Combined Assets for such periods were required to be paid by the owners of the
Predecessors and the Direct Interests.
Although the effective date of the Exchange Agreement is January 1, 1996,
each owner of the Combined Assets was required to include in its taxable
income, for all periods ending on the date of or prior to the completion of
the Combination, such owner's allocable portion of the taxable income
attributable to the Combined Assets and was entitled to all tax benefits
attributable to the Combined Assets through completion of the Combination.
The Company's revenue, profitability and future rate of growth are
substantially dependent upon prevailing prices for natural gas, oil and
condensate. These prices are dependent upon numerous factors beyond the
Company's control, such as economic, political and regulatory developments and
competition from other sources of energy. The energy markets have
historically been very volatile, and there can be no assurance that oil and
natural gas prices will not be subject to wide fluctuations in the future. A
substantial or extended decline in oil and natural gas prices could have a
material adverse effect on the Company's financial position, results of
operations and access to capital, as well as the quantities of natural gas and
oil reserves that the Company may economically produce. Natural gas produced
is sold under contracts that primarily reflect spot market conditions for
their particular area. The Company markets its oil with other working
interest owners on spot price contracts and typically receives a premium
27
compared to the price posted for such oil. Approximately 92% of the Company's
production volumes relate to the sale of natural gas.
The Company utilizes commodity swaps and options and other commodity
price risk management transactions for a portion of its oil and natural gas
production to achieve a more predictable cash flow, and to reduce its exposure
to price fluctuations. The Company accounts for these transactions as hedging
activities or uses mark-to-market accounting for those contracts that do not
qualify for hedge accounting. As of December 31, 1996, the Company has
various natural gas and oil price risk management contracts in place with
respect to portions of its estimated production for 1997 and with respect to
lesser portions of its estimated production for 1998 and 1999. 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 hedging
strategy.
The following table sets forth certain operations data of the Company for
the periods presented:
Year Ended December 31,
1996 1995 1994
------ ------ ------
Oil and Gas Sales (1) (in thousands) . . . . $113,743 $78,247 $40,912
Weighted Average Sales Prices (Unhedged):
Oil (per Bbl) . . . . . . . . . . . . . . . $ 21.30 $ 17.35 $ 16.48
Gas (per Mcf) . . . . . . . . . . . . . . . 2.00 1.42 1.67
Net Production Data:
Oil (MBbl). . . . . . . . . . . . . . . . . 794 961 691
Gas (MMcf). . . . . . . . . . . . . . . . . 51,289 37,047 17,482
Gas equivalent (MMcfe). . . . . . . . . . . 56,053 42,813 21,628
Data per Mcfe:
Oil and gas sales revenues (Unhedged) . . . $ 2.14 $ 1.61 $ 1.86
Commodity Price Risk Management Activities - Cash .06 .22 .03
- Non-Cash (.17) -- --
Oil and gas operating expenses. . . . . . . (.14) (.14) (.25)
General and administrative. . . . . . . . . (.06) (.06) (.10)
Depreciation, depletion and amortization. . (.73) (.64) (.65)
Interest income . . . . . . . . . . . . . . .05 -- --
-------- -------- --------
Pre-tax operating profit. . . . . . . . . . $ 1.15 $ 0.99 $ 0.89
-------- -------- --------
Number of wells drilled or drilling:
Gross . . . . . . . . . . . . . . . . . . . 80 118 87
Net . . . . . . . . . . . . . . . . . . . . 34 34 22
_____________________
(1) Oil and gas sales for the fiscal years ended December 31, 1996, 1995 and
1994 includes ($5,967,000), $9,480,000 and $550,000, respectively, related to
commodity price risk management activities.
RESULTS OF OPERATIONS - 1996 COMPARED TO 1995
Revenues
Oil and natural gas sales revenues for the year 1996 (unhedged)
increased 74% to $119.7 million when compared to the $68.8 million realized in
1995. The substantial increase is principally identified with the addition of
new Giddings Field wells in both the Navasota and Independence areas of the
Company's operations and higher average prices realized for both oil and
natural gas. Weighted average oil and natural gas prices (unhedged) increased
23% and 41%, respectively, when compared to 1995 price realizations.
Production volume in 1996 on an Mcfe basis (using 6 Mcf of gas for 1 barrel of
oil) increased to 56,053 MMcfe, an increase of 31% over the prior year. Daily
production increased to 153,150 Mcfe for 1996 compared to 117,300 Mcfe for
1995.
28
Commodity price risk management activities resulted in a pre-tax loss of
$6.0 million for 1996 which included (1) a realized hedging loss of $83,000,
(2) net realized losses on settlements of non-hedging transactions totaling
$3.9 million, (3) net premiums received totaling $7.4 million and (4) a
non-cash unrealized loss for mark-to-market accounting of $9.4 million. As a
result of the substantial oil and natural gas price increases which occurred
in the fourth quarter of 1996 (which had a positive impact on oil and gas
sales revenue), the Company recorded a fourth quarter pre-tax loss of $8.4
million from commodity price risk management activities which included a $4.2
million non-cash charge for unrealized losses related to required
mark-to-market accounting. The 1995 results of operations included pre-tax
income of $9.5 million related to realized hedging gains. The impact of such
activities on an Mcfe basis amounted to a loss of $0.11 ($0.06 cash gain and a
non-cash loss of $0.17) and a gain of $0.22 (all cash) per Mcfe for 1996 and
1995, respectively.
Interest income realized during 1996 was $2.7 million compared to $0.4
million for 1995 due to higher average cash balances principally attributable
to the proceeds of the Company's initial public offering.
Costs and Expenses
Production and Operating Expenses. Production and operating expenses
including associated taxes in 1996 amounted to $7.9 million, an increase of
35% over the $5.8 million incurred in the prior year. Operating costs on a
Mcfe basis were flat at $0.14 per Mcfe for both 1996 and 1995. A substantial
portion of the Company's natural gas production from wells drilled prior to
September 1996 in the downdip Giddings Field qualifies for exemption from
Texas state production taxes. This exemption will continue for production
through August 31, 2001.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization ("DD&A") costs related to oil and gas properties totaled $40.9
million for 1996, a 48% increase over the $27.6 million incurred in the 1995
comparable period. The Company average DD&A rate per Mcfe for 1996 was $0.73
compared to a rate of $0.64 per Mcfe in 1995. The increased rate primarily
reflects the higher average cost of drilling deeper wells and costs associated
with the unsuccessful East Texas Cotton Valley Reef Trend exploration
activities.
General and Administrative Expenses. General and administrative expenses
("G&A") totaled $3.1 million for 1996, net of capitalized G&A costs directly
related to the Company's oil and natural gas exploration and development
efforts, an 18% increase over the prior year. The increase reflects the
addition of new employees hired to assist with the Company's expanding
activities and additional costs incurred in connection with becoming a
publicly traded entity. On an Mcfe basis, G&A costs were flat at $0.06 for
both 1996 and 1995. Operations G&A expenses for 1996 in the amount of $3.1
million have been capitalized to oil and gas property accounts. The increase
of $1.8 million over the 1995 comparable amount reflects the Company's rapidly
expanding exploration and development efforts.
Income Before Income Taxes
The Company's income before income taxes for 1996 was $64.6 million, a
52% increase over the $42.6 million realized in the prior year comparable
period. The increase is directly related to increased production from new
well additions in the Giddings Field and substantially higher average prices
realized for both oil and natural gas.
Income Taxes
Income tax expenses for 1996 amounted to $46.4 million. The provision
for taxes includes a one-time, non-cash charge in the amount of $30.1 million
that was required as a result of the Combination and the Exchange Agreement
which changed the tax status of the Company.
29
RESULTS OF OPERATIONS - 1995 COMPARED TO 1994
Revenues
During 1995, oil and natural gas sales revenues (unhedged) increased
$28.4 million, or 70%, to $68.8 million as compared to 1994. The revenue
increase is principally the result of new Giddings Field well additions in the
Navasota River and Independence areas of the Company's operations. Production
volume on an Mcfe basis increased to 42.8 MMcfe representing an increase of
98% over the prior year comparable period. Natural gas production represented
approximately 87% of total Company production on an Mcf equivalent basis.
This significant improvement in revenues was achieved despite a decline in the
Company average wellhead natural gas prices in 1995. Weighted average
wellhead natural gas prices (unhedged) were down approximately 15% from 1994
prices and weighted average wellhead oil prices were up approximately 5% from
1994 prices.
Commencing in late 1993, marketing activities associated with sales of
natural gas and crude oil also included natural gas, crude oil price swap and
option transactions, along with other commodity price hedging of natural gas
and crude oil and condensate prices. These transactions added approximately
$9.5 million to net operating revenues for 1995. The average Mcfe price
realized for these transactions amounted to $0.22 per Mcfe for 1995. During
1995, revenues per Mcfe, including revenue from hedges, per Mcfe totaled
$1.83.
Costs and Expenses
Production and Operating Expenses. Production and operating expenses
increased 6% from $5.5 million in 1994 to $5.8 million in 1995. On an Mcfe
basis, operating costs decreased 44% to $0.14 for 1995, compared to $0.25 for
1994. The decrease is due mainly to an increase in the number of highly
productive wells in the Giddings Field.
Depreciation, Depletion and Amortization. DD&A for 1995 increased 96%,
from $14.1 million to $27.6 million, due to increased production. Lower well
costs due to efficiencies achieved related to the Company's experience in its
existing operating areas coupled with the Company's ability to achieve a
higher level of reserve additions for its 1995 wells resulted in a DD&A rate
of $0.64 per Mcfe for 1995, compared to $0.65 per Mcfe in 1994, a 2%
reduction.
General and Administrative Expenses. G&A for 1995 increased 14%, from
$2.3 million for 1994 to $2.6 million for 1995. The higher G&A expenses for
1995 primarily relate to increases in the number of employees due to a higher
level of overall activity for the Company as well as increases in employee
salaries and benefits. G&A expense totaling $1.2 million and $0.1 million
have been capitalized to oil and gas property accounts for 1995 and 1994,
respectively.
Income Before Income Taxes. The Company's income before income taxes for
1995 increased by approximately $23.3 million, or 121% to $42.6 million from
$19.3 million in the prior year period. Increases in revenues were generated
primarily by increases in production from new well additions in the Giddings
Field and were partially offset by increases in operating costs and expenses
related to the new additions and lower natural gas and oil prices.
Additionally, the Company realized approximately $9.5 million related to its
commodity price risk management activities for 1995.
Liquidity and Capital Resources
On March 29, 1996, the Company successfully completed an initial public
offering of 6,500,000 shares of Common Stock. The offering provided the
Company with approximately $113 million net of offering expenses. Revolving
credit agreement indebtedness, in the amount of $35.3 million was repaid with
proceeds from the offering. The remaining proceeds from the offering,
together with cash flows from operations, are currently being used to fund
planned capital expenditures, including lease acquisitions, commitments, other
working capital requirements and general corporate purposes.
30
Net operating cash flow (pre-tax), a measure of performance for
exploration and production companies, is generally derived by adjusting income
before income taxes to eliminate the effects of the non-cash items including
depreciation, depletion and amortization expense and the provision for
deferred income taxes. Net operating cash flow before changes in working
capital was approximately $108.7 million for the year 1996 and $69.6 million
for the year 1995, an increase of 56%. The cash flow increase is the result
of increased production from new well additions, reflecting expanding
operations and of substantially higher prices realized for production. The
Company had working capital amounting to $48.7 million as of December 31,
1996, a substantial increase over the $0.4 million in working capital
available as of December 31, 1995.
For 1997, the Company has budgeted approximately $150 million for capital
expenditures, a 5% increase over 1996 capital expenditures, which amount may
be increased or decreased depending on oil and natural gas prices, drilling
results and other investment opportunities. The Company is allocating
approximately 77 of its budget to development and exploration projects and
approximately 23% to leasehold and seismic acquisition activities compared to
the 45% for development and exploration and 55% for leasehold and seismic in
1996.
In December of 1994, the Company entered into a three-year $25 million
Credit Agreement with The Chase Manhattan Bank, N.A. (the "Credit Facility").
Principal outstanding, if any, is due and payable upon maturity in December
1997 with interest due quarterly. In order to finance future capital
requirements during the first quarter of 1996, the Company increased the
Credit Facility and the Borrowing Base thereunder to $40 million. The
Borrowing Base represents the maximum available amount that may be borrowed
under the Credit Facility at any given time. Since all indebtedness under
this Credit Facility was repaid with proceeds from the Offering, the Company
elected to reduce its Credit Facility to $30 million and the Borrowing Base
under the Credit Facility to $15 million on May 1, 1996. The reduction in the
Borrowing Base permits the Company to pay a lower commitment fee, which is
currently calculated at an annual rate of 0.25 of 1% of the unused portion of
the available Borrowing Base. The Company may seek to adjust the terms and
availability of the Credit Facility in the future in accordance with its
anticipated capital requirements. As of December 31, 1996, there were no
borrowings under the Credit Facility.
During 1996, the Company acquired additional interests in the Moxa
Programs from certain third party investors. The amount paid for the
interests acquired totaled $9.9 million. The remaining third party investors
in the Moxa Programs have the contractual right on an annual basis through
2003 to require the Company to purchase their interests in such programs. No
investors under the Moxa Programs exercised such right in 1996. Based upon
December 31, 1996 present values, the maximum purchase price if all remaining
investors exercised the put option would not be material to the Company as of
December 31, 1996.
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.
The Company intends to fund its planned capital expenditures, commitments
and working capital requirements through cash flows from operations, remaining
proceeds of the Offering and to the extent necessary, borrowings under the
Credit Facility or other potential financings. If there are changes in oil
and natural gas prices, however, that correspondingly affect cash flows and
the Borrowing Base under the Credit Facility, the Company has the discretion
and ability to adjust its capital budget. The Company believes it will have
sufficient capital resources and liquidity to fund its capital expenditures
and meet its financial obligations as they come due.
31
COMMODITY RISK MANAGEMENT TRANSACTIONS
With the primary objective of achieving more predictable revenues and
cash flows and reducing the exposure to fluctuations in oil and natural gas
prices, the Company has entered into price risk management transactions of
various kinds with respect to both oil and natural gas. While the use of
certain of these price risk management arrangements limits the downside risk
of adverse price movements, it may also limit future revenues from favorable
price movements. The Company engages in transactions such as selling covered
calls or straddles which are marked to market at the end of the relevant
accounting period. Since the futures market historically has been highly
volatile, these fluctuations may cause significant impact on the results of
any given accounting period. The Company has entered into price risk
management transactions with respect to a substantial portion of its estimated
production for 1997 and with respect to lesser portions of its estimated
production for 1998 and 1999. The Company continues to evaluate whether to
enter into additional price risk management transactions for 1997 and future
years. In addition, the Company may determine from time to time to unwind its
then existing price risk management positions as part of its hedging strategy.
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.
INFORMATION REGARDING FORWARD LOOKING STATEMENTS
The information contained in this Form 10-K includes certain forward-looking
statements. When used in this document, such words as "expect", "believes",
"potential", and similar expressions are intended to identify forward-looking
statements. Although Belco believes that its expectations are based on
reasonable assumptions, it is important to note that actual results could
differ materially from those projected by such forward-looking statements.
Important factors that could cause actual results to differ materially from
those in the forward-looking statements include, but are not limited to, the
timing and extent of changes in commodity prices for oil and gas, the need to
develop and replace reserves, environmental risk, the substantial capital
expenditures required to fund its operations, drilling and operating risks,
risks related to exploration and development, uncertainties about the
estimates of reserves, competition, government regulation and the ability of
the Company to implement its business strategy. See "Item 1 - Business -
Forward Looking Information and Risk Factors."
32
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 Supplemental Data and
Financial Statement Schedules on page A-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.
Item 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information regarding Directors and Officers required under Item 10
will be contained in the definitive Proxy Statement of the Company for its
1997 Annual Meeting of Shareholders (the "Proxy Statement") under the headings
"Election of Directors" and "Executive Compensation and Other Information" and
is incorporated herein be reference. The Proxy Statement will be filed
pursuant to Regulation 14A with the Securities and Exchange Commission not
later than 120 days after December 31, 1996. The information regarding
Officers not appearing in the Proxy Statement is identified below:
Officers are elected each year by the Board of Directors following the
Annual Meeting for a term of one year and until the election and qualification
of their successors. The current executive officers of the Company and their
ages, positions with the Company and business experience are presented below:
Robert A. Belfer, age 61, is Chairman of the Board, President (through
April 1, 1997) and Chief Executive Officer of the Company. Mr. Belfer began
his career at Belco Petroleum Corporation ("BPC") in 1958 and became Executive
Vice President in 1964, President in 1965 and Chairman of the Board in 1984.
BPC was an independent oil and gas producer in the Unites States and abroad,
which went public in 1959. It was one of the largest 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) in 1983. Following the merger, Mr. Belfer became
Chief Operating Officer of BelNorth Petroleum Corp., a combination of oil and
gas producing operations of BPC and InterNorth. He resigned from his position
with InterNorth in 1986 and pursued personal investments in oil and gas and
other industries. In April 1992, Mr. Belfer founded the Company. In addition
to his position at the Company, Mr. Belfer serves on the boards of Enron, EOTT
Energy corp., and NAC Re Corporation. Mr. Belfer received his undergraduate
degree from Columbia college (A.B. 1955) and a law degree from the Harvard Law
School (J.D. 1958).
Laurence D. Belfer, age 30, is Director, President (effective April 1,
1997), Chief Operating Officer and Secretary 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. He is a founder and Chairman of Harvest Management, Inc., a money
management firm. Mr. Belfer graduated from Harvard University (B.A. 1988) and
from Columbia Law School (J.D. 1992).
Philip A. Epstein, age 40, is Senior Financial and Legal Advisor and
General Counsel of the Company. Mr. Epstein began his career as a corporate
associate with the New York City law firms of Kaye, Scholer, Fierman, Hays &
Handler (1984-1987) and Fried, Frank, Harris, Shriver & Jacobson (1988-1991),
specializing in mergers and acquisitions and corporate finance. Mr. Epstein
joined the Belfer family in 1991 as Investment Counsel, assuming the founding
positions of Executive Vice President, General Counsel and Secretary of the
Company in April 1992. Mr. Epstein resigned from these positions in December
1992 but continues to serve as Senior Financial and Legal Advisor and General
Counsel to the Company and to the Belfer family. Mr. Epstein received an
undergraduate degree from the University of Chicago (B.A. 1978), graduate
degree in Politics and Economics from Oxford University (M.S. Oxon 1981) and
his law degree from Northwestern University of Law (J.D. 1984).
33
Dominick J. Golio, age 51, is Vice President -- Finance, Chief Financial
Officer and Treasurer of the Company. Mr. Golio began his career at the New
York City office of Arthur Andersen & Co. in 1972. In 1975, he joined Case,
Pomeroy & Company and Felmont Oil Corporation, its publicly traded affiliate,
where he rose to the position of Vice President Finance. Mr. Golio left
Felmont in 1987 following a merger between Felmont and Homestake Mining
Company. He served as Vice President Finance and Administration at both AEG
Corporation, the U.S. electronics subsidiary of Daimler-Benz North America
until 1991 and at Millmaster Onyx Group, Inc. until September 1993 at which
time he joined the Company. Mr. Golio is a Certified Public Accountant (NY).
He holds undergraduate and graduate degrees from Pace University (B.B.A.
Accounting, 1972, M.B.A. - Taxation, 1978).
Shiv K. Sharma, age 55, is Senior Vice President -- Engineering of the
Company. Mr. Sharma began his career in 1967 as a Reservoir Engineer with
Shell Oil Company. In 1970, he joined BPC as a reservoir engineer and was
subsequently elected to Vice President and Senior Vice President of
Engineering, a position he held until his departure from that company in 1988.
From 1988 to 1992, Mr. Sharma worked as a petroleum consultant for several New
York companies. He served as a director and consultant to the Company
commencing April 1992 and was elected to his present position in April 1994.
Mr. Sharma received his degrees in petroleum technology from the Indian School
of Mines (B.S. 1963) and petroleum engineering from Stanford University (M.S.
1966).
Mel Fife, age 46, is Vice President - Land of the Company. Mr. Fife
began his career in 1979 as an Independent Landman working for various
companies. Mr. Fife joined Union Pacific Resources Company in 1988 and served
as a Landman until 1994. He joined the Company in November 1995 as Land
Manager and was promoted to Vice President - Land in January 1997. Mr. Fife
has 18 years of extensive experience in all phases of land in the oil and gas
industry. Mr. Fife is a graduate of Dallas Christian College (1979) from
which he received a Bachelor of Science Degree and attended Emory University's
Divinity Program (1978-1979).
Gary Hampton, age 40, is Vice President -- Exploration - Eastern Region
of the Company. Mr. Hampton began his career in 1978 as a Reservoir Geologist
for Texas Eastern (now PanEnergy). Mr. Hampton joined Champlin (currently
UPR) in 1980 as a geologist and remained there until 1984. Mr. Hampton spent
the next two years with Clayton Williams Energy generating prospects and
developing acreage plays. In 1986, he became an independent consultant
geologist providing geological assessments to the energy and environmental
industry. Mr. Hampton rejoined Clayton Williams Energy in 1989 as the
geologist responsible for, among other programs, geological planning
associated with the company's Austin Chalk development program resulting in
over 100 horizontal wells drilled in the Austin Chalk, Buda and Georgetown
formations. Mr. Hampton was named Exploration Manager at Clayton Williams
where he remained until February 1995, at which time he joined the Company as
Manager -- Geology. Mr. Hampton was promoted to Vice President -- Exploration
in January 1996 and renamed Vice President -- Exploration - Eastern Division
in October 1996. He received a B.S. in Geology from the University of
Southern Mississippi in 1978.
Steven L. Mueller, age 43, is Vice President -- Exploration - Western
Region of the Company. Mr. Mueller began his career in 1975 as a Geological
Engineer at Tenneco Oil, Lafayette. He advanced at Tenneco Oil, Lafayette to
Senior Geological Engineer in 1979, Project Geological Engineer in 1980 and
Division Geological Engineer in the later part of 1980. Mr. Mueller relocated
to San Antonio, Texas in 1985 where he maintained the title of Division
Geological Engineer at Tenneco Oil but had the responsibility of reorganizing
and then supervising an 18 member geological engineering group. Mr. Mueller
was then promoted to Division Exploration Manager in 1987. In 1988 Mr.
Mueller joined Fina Oil in Houston, Texas as Exploration Manager of South
Louisiana and in 1992 he joined American Exploration in Houston, Texas as
Exploitation Vice President. He was with American Exploration until October
of 1996 when he joined the Company. Mr. Mueller has over 21 years experience
in exploring for and exploiting oil and gas fields both onshore and offshore
and an expertise in 3-D Seismic, mapping, log analysis and risk management.
He holds a BS in Geological Engineering from the Colorado School of Mines
(1975) and serves on the Board of Directors of Concordia Lutheran High School.
George A. Sheffer, age 44, is Vice President - Operations of the Company.
Mr. Sheffer began his career in 1974 at Chevron USA where he served in the
capacities of Reservoir Engineer, Drilling Representative and Production
Engineer. Mr. Sheffer went on to serve in various engineering management
positions with Meridian Oil and its predecessor Southland Royalty Company from
1979 to 1992. He joined the Company as Senior Petroleum Engineer in May 1994
34
after spending two years at Mearsk Energy, Inc. as Drilling Manager. He was
promoted to Vice President -- Operations at the Company in November 1994. Mr.
Sheffer has had more than 20 years of diverse experience in all phases of
petroleum engineering and operations management in the domestic oil and gas
industry. Mr. Sheffer has specialized in horizontal drilling since 1987 in
Oklahoma and Texas. He has extensive experience in the entire Austin Chalk
Trend from South Texas to the Louisiana Border. Mr. Sheffer is a graduate of
Pennsylvania State University (1974) from which he received a degree in
Petroleum and Natural Gas Engineering.
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 be 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.
35
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 immediately following the signature page of this report.
2. Financial Statement Schedule: See Index to Consolidated Financial
Statements and Schedule immediately following the signature page of this
report.
3. Exhibits: The following documents are filed as exhibits to this
report.
Exhibit
No. Description of Exhibit
- ------- -----------------------------------------------------------------
3.1 Articles of Incorporation of Company (Incorporated by reference to
Exhibit 3.1 of the Registration Statement on Form S-1, Registration No.
333-1034).
3.2 Amended and Restated Bylaws of Belco Oil & Gas Corp. dated February 5,
1996 (Incorporated by reference to Exhibit 3.2(ii) of the Form 10-Q dated
March 31, 1996)
4.1 Specimen Common Stock certificate (Incorporated by reference to
Exhibit 4.1 of the Registration Statement on Form S-1, Registration No.
333-1034).
*10.1 1996 Non-Employee Directors' Stock Option Plan (Incorporated by
reference to Exhibit 10.1 of the Registration Statement on Form S-1,
Registration No. 333-1034).
*10.2 1996 Stock Incentive Plan (Incorporated by reference to Exhibit 10.2
of the Registration Statement on Form S-1, Registration No. 333-1034).
*10.3 Exchange and Subscription Agreement and Plan of Reorganization dated
as of January 1, 1996 by and among the Company, its Predecessors and certain
individuals and trusts (Incorporated by reference to Exhibit 10.3 of the
Registration Statement on Form S-1, Registration No. 333-1034).
10.4 Form of Registration Rights Agreement entered into by parties to
Exchange Agreement (Incorporated by reference to Exhibit 10.4 of the
Registration Statement on Form S-1, Registration No. 333-1034).
10.5 Supplemental Agreement dated as of January 1, 1996 by and between the
Company, Belco Oil & Gas Corp., a Delaware corporation, Robert A. Belfer and
certain officers of the Company (Incorporated by reference to Exhibit 10.5 of
the Registration Statement on Form S-1, Registration No. 333-1034).
10.6 Form of Indemnification Agreement by and between the Company and its
officers and directors (Incorporated by reference to Exhibit 10.6 of the
Registration Statement on Form S-1, Registration No. 333-1034).
10.7 Amended and Restated Well Participation Letter Agreement dated as of
December 31, 1992 between Chesapeake Operating, Inc. and Belco Oil & Gas
Corp., as amended by (i) Letter Agreement dated April 14, 1983, (ii) Amendment
dated December 31, 1993, and (iii) Third Amendment dated December 30, 1994
(Incorporated by reference to Exhibit 10.7 of the Registration Statement on
Form S-1, Registration No. 333-1034).
10.8 Sale Agreement (Navasota River) dated as of June 16, 1993 between
Chesapeake Operating, Inc. and Belco Oil & Gas Corp (Incorporated by reference
to Exhibit 10.8 of the Registration Statement on Form S-1, Registration No.
333-1034).
- ------------------------
* Constitutes a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this report.
36
10.9 Sale Agreement (Fayetteville) dated as of September 22, 1993 between
Chesapeake Operating, Inc. and Belco Oil & Gas Corp (Incorporated by reference
to Exhibit 10.9 of the Registration Statement on Form S-1, Registration No.
333-1034).
10.10 Sale Agreement (Independence) dated as of June 10, 1994 between
Chesapeake Operating, Inc. and Belco Oil & Gas Corp. (Incorporated by
reference to Exhibit 10.10 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.11 Sale Agreement (South Navasota) dated as of September 9, 1994 between
Chesapeake Operating, Inc. and Belco Oil & Gas Corp (Incorporated by reference
to Exhibit 10.11 of the Registration Statement on Form S-1, Registration No.
333-1034).
10.12 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 byreference to Exhibit 10.12 of the Registration Statement
on Form S-1, Registration No. 333-1034).
10.13 Golden Trend Area of Mutual Interest Agreement dated as of December
17, 1992 between Chesapeake Operating, Inc. and Belco Oil & Gas Corp.
(Incorporated by reference to Exhibit 10.13 of the Registration Statement on
Form S-1, Registration No. 333-1034).
10.14 Settlement Agreement dated as of December 31, 1993 between
Chesapeake Operating, Inc. and Belco Oil & Gas Corp. (Incorporated by
reference to Exhibit 10.14 of the Registration Statement on Form S-1,
Registration No. 333-1034).
10.15 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).
10.16 Form of Offset Participation Agreement to the Moxa Arch 1992 Offset
Drilling Program (Incorporated by reference to Exhibit 10.16 of the
Registration Statement on Form S-1, Registration No. 333-1034).
10.17 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).
10.18 Credit Agreement dated as of December 1, 1994 between Belco Energy
L.P. and The Chase Manhattan Bank, N.A. (Incorporated by reference to Exhibit
10.18 of the Registration Statement on Form S-1, Registration No. 333-1034).
10.19 Amendment No. 1 to the Credit Agreement dated as of January 25, 1996
between Belco Energy L.P., a Delaware limited partnership and The Chase
Manhattan Bank, N.A. (Incorporated by reference to Exhibit 10.19 of the
Quarterly Report filed on Form 10-Q dated March 31, 1996.)
10.20 Amendment No. 2 to the Credit Agreement dated as of March 1, 1996
between Belco Energy L.P., a Delaware limited partnership and The Chase
Manhattan Bank, N.A. (Incorporated by reference to Exhibit 10.20 of the
Quarterly Report filed on Form 10-Q dated March 31, 1996.)
10.21 Amendment No. 3 to the Credit Agreement dated as of March 29, 1996
between Belco Energy L.P., a Delaware limited partnership and The Chase
Manhattan Bank, N.A. (Incorporated by reference to Exhibit 10.21 of the
Quarterly Report filed on Form 10-Q dated March 31, 1996.)
**11.1 Computation of Earnings Per Share
**21.1 Subsidiaries of the Registrant
**23.1 Consent of Arthur Andersen LLP
**23.2 Consent of Miller and Lents, Ltd.
** Filed herewith
Certain of the exhibits to this filing contain schedules which have
beenomitted 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. The Company filed no report on Form 8-K during the
quarter ended December 31, 1996.
37
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.
Date: March 25, 1997 By: /s/ Laurence D. Belfer
--------------------------------------
Laurence D. Belfer
Executive Vice President, Chief
Operating Officer, Director and
Secretary
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.
Signatures Title Date
- ----------------------------- --------------------------- --------------
/s/ Robert A. Belfer President, Chief Executive March 25, 1997
- ----------------------------- Officer and Chairman of the
Robert A. Belfer Board of Directors
(Principal Executive Officer)
/s/ Laurence D. Belfer Executive Vice President, March 25, 1997
- ----------------------------- Chief Operating Officer,
Laurence D. Belfer Director and Secretary
/s/ Dominick J. Golio Vice President - Finance, March 25, 1997
- ----------------------------- Chief Financial Officer
Dominick J. Golio And Treasurer
(Principal Financial Officer
and Principal Accounting
Officer)
/s/ Graham Allison Director March 25, 1997
- -----------------------------
Graham Allison
/s/ Daniel C. Arnold Director March 25, 1997
- -----------------------------
Daniel C. Arnold
/s/ Alan D. Berlin Director March 25, 1997
- -----------------------------
Alan D. Berlin
/s/ Jack Saltz Director March 25, 1997
- -----------------------------
Jack Saltz
/s/ Georgiana Sheldon-Sharp Director March 25, 1997
- -----------------------------
Georgiana Sheldon-Sharp
38
BELCO OIL & GAS CORP. AND SUBSIDIARIES
Index to Consolidated Financial Statements and Financial Statement Schedule
Page
CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Public Accountants. . . . . . . . . . . . F-2
Consolidated Balance Sheets as of December 31, 1996 and 1995. . F-3
Consolidated Statements of Operations for the Years Ended
December 31, 1996, 1995 and 1994. . . . . . . . . . . . . . . F-4
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1996, 1995 and 1994. . . . . . . . . . . . . . . F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1996, 1995 and 1994. . . . . . . . . . . . . . . F-6
Notes to Consolidated Financial Statements. . . . . . . . . . . F-7
CONSOLIDATED FINANCIAL STATEMENT SCHEDULE
None
All other schedules for which provision is made in the applicable
accounting regulations of the Securities and Exchange commission are not
required under the related instructions or are inapplicable and therefore have
been omitted.
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, 1996 and
1995, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1996. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Belco Oil
& Gas Corp. and subsidiaries as of December 31, 1996 and 1995, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 28, 1997
F-2
BELCO OIL & GAS CORP. AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
1996 1995
---- ----
ASSETS (in thousands)
CURRENT ASSETS:
Cash and cash equivalents. . . . . . . . . . . . . . . . . . . . $43,473 $1,556
Accounts receivable, oil and gas . . . . . . . . . . . . . . . . 28,934 16,979
Assets from commodity price risk management activities . . . . . 2,249 --
Advances to oil and gas operators. . . . . . . . . . . . . . . . 69 45
Other current assets . . . . . . . . . . . . . . . . . . . . . . 456 401
-------- ------
Total Current Assets . . .. . . . . . . . . . . . . . . 75,181 18,981
------- --------
PROPERTY AND EQUIPMENT:
Oil and gas properties at cost based on full-cost accounting --
Proved oil and gas properties. . . . . . . . . . . . . . . . . 237,150 152,081
Unproved oil and gas properties. . . . . . . . . . . . . . . . 77,570 19,927
Less - Accumulated depreciation, depletion and amortization (86,490) (45,771)
------- -------
Net property and equipment. . . . . . . . . . . . . . . 228,230 126,237
------- -------
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . . . . . 507 332
------- -------
Total Assets. . . . . . . . . . . . . . . . . . . . . . $303,918 $145,550
======== ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities . . . . . . . . . . . . $ 16,886 $ 8,440
Distribution payable . . . . . . . . . . . . . . . . . . . . . . -- 10,095
Liabilities from commodity price risk management activities. . . 7,220 --
Income taxes payable . . . . . . . . . . . . . . . . . . . . . . 2,408 --
-------- --------
Total Current Liabilities. . . . . . . . . . . . . . . . . . 26,514 18,535
LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . . . . . . . -- 22,000
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . 39,967 --
LIABILITIES FROM COMMODITY PRICE RISK MANAGEMENT ACTIVITIES. . . . 4,234 --
STOCKHOLDERS' EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized;
none issued or outstanding. . . . . . . . . . . . . . . . . . -- --
Common Stock, $0.01 par value; 120,000,000 shares authorized;
31,577,300 shares issued and outstanding at December 31, 1996 316 --
Additional paid-in capital. . . . . . . . . . . . . . . . . . . 186,703 --
Retained earnings . . . . . . . . . . . . . . . . . . . . . . . 48,244 --
Combined equity of predecessor entities . . . . . . . . . . . . -- 105,849
Unearned compensation . . . . . . . . . . . . . . . . . . . . . (1,285) --
Notes receivable for equity interest. . . . . . . . . . . . . . (775) (834)
------- -------
Total Stockholders' Equity . . . . . . . . . . . . . . . . 233,203 105,015
------- -------
Total Liabilities and Stockholders' Equity . . . . . . . . $303,918 $145,550
======== ========
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,
1996 1995 1994
---- ---- ----
REVENUES: (in thousands, except per share amounts)
Oil and gas sales. . . . . . . . . . . . . . . . . . . . $119,710 $68,767 $40,362
Commodity price risk management activities . . . . . . . (5,967) 9,480 550
Interest . . . . . . . . . . . . . . . . . . . . . . . . 2,653 353 195
-------- ------- -------
Total revenues . . . . . . . . . . . . . . . . . . . 116,396 78,600 41,107
-------- ------- -------
COSTS AND EXPENSES:
Oil and gas operating expenses . . . . . . . . . . . . . 7,847 5,824 5,510
Depreciation, depletion and amortization . . . . . . . . 40,904 27,590 14,072
General and administrative . . . . . . . . . . . . . . . 3,059 2,597 2,269
------ ------ ------
Total costs and expenses . . . . . . . . . . . . . . 51,810 36,011 21,851
------ ------ ------
INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . . 64,586 42,589 19,256
------ ------ ------
PROVISION FOR INCOME TAXES . . . . . . . . . . . . . . . . (a) 46,404 -- --
---------- ------ ------
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . $ 18,182 $ 42,589 $ 19,256
PRO FORMA NET INCOME:
Income before income taxes . . . . . . . . . . . . . . . $ 64,586 $ 42,589 $ 19,256
Pro forma provision for income taxes . . . . . . . . . . 21,953 13,852 5,030
------ --------- ---------
Pro forma net income . . . . . . . . . . . . . . . . $ 42,633 $ 28,737 $ 14,226
======== ========= =========
PRO FORMA NET INCOME PER COMMON SHARE. . . . . . . . . . . $ 1.42 $ 1.15 $ 0.57
======== ========= =========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING . . . . . . . . 29,986 25,000 25,000
_____________________________
(a) Includes a one-time non-cash deferred tax charge of $30.1 million
recognized as a result of the Combination consummated on March 29,
1996. See Note 1. Historical net income per share, including the
deferred tax charge, was $0.61 for the year ended December 31, 1996.
The pro forma amounts present the Company as if a taxable
corporation for all periods and are based on the average number of
shares outstanding during the period assuming the shares issued in
connection with the Combination were outstanding for all periods.
The accompanying notes to consolidated financial statements are an integral
part of these statements.
F-4
BELCO OIL & GAS CORP. AND SUBSIDIARIES
Consolidated Statements of Stockholders' Equity
(in thousands)
Common Stock Notes
Additional Combined Receivable
Paid-in Unearned Retained Predecessor for Equity
Shares Amount Capital Compensation Earnings Equity Interest Total
-----------------------------------------------------------------------------------------------
BALANCE, December 31, 1993 -- $ -- $ -- $ -- $ -- $ 47,188 $ -- $ 47,188
- ----------------------------------------------------------------------------------------------------------------------------------
Contributions -- -- -- -- -- 50,040 -- 50,040
Distributions -- -- -- -- -- (26,468) -- (26,468)
Issuance of employee notes
receivable -- -- -- -- -- -- (126) (126)
Income before income taxes -- -- -- -- -- 19,256 -- 19,256
- ----------------------------------------------------------------------------------------------------------------------------------
BALANCE, December 31, 1994 -- $ -- $ -- $ -- $ -- $ 90,016 $ (126) $ 89,890
- ----------------------------------------------------------------------------------------------------------------------------------
Contributions -- -- -- -- -- 4,512 -- 4,512
Distributions -- -- -- -- -- (31,268) -- (31,268)
Issuance of employee notes
receivable -- -- -- -- -- -- (868) (868)
Repayment of employee notes
receivable -- -- -- -- -- -- 160 160
Income before income taxes -- -- -- -- -- 42,589 -- 42,589
- ----------------------------------------------------------------------------------------------------------------------------------
BALANCE, December 31, 1995 -- $ -- $ -- $ -- $ -- $ 105,849 $ (834) $ 105,015
- ----------------------------------------------------------------------------------------------------------------------------------
Exchange combination 25,000 250 72,142 -- -- (72,392) -- --
Public stock offering,
net of costs of $10.4 million 6,500 65 113,050 -- -- -- -- 113,115
Restricted stock issued 77 1 1,511 (1,285) -- -- -- 227
Repayment of employee notes
receivable -- -- -- -- -- -- 59 59
Distributions to predecessor
owners -- -- -- -- -- (3,395) -- (3,395)
Net Income (a) -- -- -- -- 48,244 (30,062) -- 18,182
- ----------------------------------------------------------------------------------------------------------------------------------
BALANCE, December 31, 1996 31,577 $ 316 $186,703 $ (1,285) $48,244 $ -- $ (775) $ 233,203
- ----------------------------------------------------------------------------------------------------------------------------------
(a) Includes a one-time non-cash deferred tax charge of $30.1 million
recognized as a result of the Combination consummated on March
29, 1996. See Note 1.
The accompanying notes to consolidated financial statements are an integral
part of these statements.
F-5
BELCO OIL & GAS CORP. AND SUBSIDIARIES
Consolidated Statements Of Cash Flows
For the Year Ended December 31,
1996 1995 1994
CASH FLOWS FROM OPERATING ACTIVITIES: (in thousands)
Net income (a) . . . . . . . . . . . . . . . . . . . . . . . . $18,182 $42,589 $19,256
Adjustments to reconcile net income to net operating
cash inflows
Depreciation, depletion and amortization . . . . . . . . . . 40,904 27,590 14,072
Deferred tax provision (a) . . . . . . . . . . . . . . . . . 39,967 -- --
Amortization of restricted stock compensation. . . . . . . . 227 -- --
Commodity price risk management activities . . . . . . . . . 9,436 (570) 277
Changes in operating assets and liabilities --
Accounts receivable, oil and gas . . . . . . . . . . . . . (11,955) (6,445) (6,084)
Other current assets . . . . . . . . . . . . . . . . . . . (286) -- --
Accounts payable and accrued liabilities . . . . . . . . . 11,584 (1,127) 605
------- ------ ------
Net operating cash inflows . . . . . . . . . . . . . . . 108,059 62,037 28,126
------- ------ ------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures . . . . . . . . . . . (142,712) (71,387) (52,230)
Changes in accounts payable and accrued liabilities
for oil and gas expenditures . . . . . . . . . . . . . . . . (730) 5,243 721
Change in advances to oil and gas operators. . . . . . . . . . (24) 1,566 (1,012)
Changes in other assets. . . . . . . . . . . . . . . . . . . . (360) (555) (149)
-------- ------- -------
Net investing cash outflows. . . . . . . . . . . . . . . (143,826) (65,133) (52,670)
-------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from initial public offering. . . . . . . . . . . . . 113,115 -- --
Long-term borrowings . . . . . . . . . . . . . . . . . . . . . 13,300 17,170 6,930
Long-term debt repayments. . . . . . . . . . . . . . . . . . . (35,300) (2,100) --
Equity contributions . . . . . . . . . . . . . . . . . . . . . -- 4,512 50,040
Equity distributions . . . . . . . . . . . . . . . . . . . . . (13,490) (21,173) (26,468)
Employee loans, net. . . . . . . . . . . . . . . . . . . . . . 59 (708) (126)
------- ------- -------
Net financing cash inflows (outflows). . . . . . . . . . 77,684 (2,299) 30,376
------- ------- -------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS . . . . . . . . 41,917 (5,395) 5,832
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD . . . . . . . . 1,556 6,951 1,119
------ ------- -------
CASH AND CASH EQUIVALENTS AT END OF PERIOD . . . . . . . . . . . $ 43,473 $ 1,556 $ 6,951
_________________________
(a) Prior to March 29, 1996, the earnings of the Company were not
subject to corporate income taxes as the Company, prior to the
Combination, was a group of non-taxpaying entities. See Note 1.
The accompanying notes to consolidated financial statements are an integral
part of these statements.
F-6
BELCO OIL & GAS CORP. AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Note 1 - ORGANIZATION AND NATURE OF OPERATIONS
Organization
Belco Oil & Gas Corp. was organized as a Nevada corporation in January
1996 in connection with the combination of assets (the "Combination")
consisting of ownership interests (the "Combined Assets") in certain entities
and direct interests in oil and gas properties and certain hedge transactions
owned by the predecessors and entities related thereto. On March 29, 1996,
Belco Oil & Gas Corp. completed its initial public offering (the "Offering")
issuing 6,500,000 shares of Common Stock at $19 per share. Belco Oil & Gas
Corp. and the owners of the Combined Assets entered into an Exchange and
Subscription Agreement and Plan of Reorganization dated as of January 1, 1996
(the "Exchange Agreement") that provided for the issuance by the Company of an
aggregate of 25,000,000 shares of Common Stock to such owners in exchange for
the Combined Assets on March 29, 1996, the date the Offering closed. The
owners of the Combined Assets received shares of Common Stock proportionate to
the value of the Combined Assets underlying their ownership interests in the
predecessors and the direct interests.
The Combination was accounted for as a reorganization of entities under
common control because of the common control of the stockholders of Belco Oil
& Gas Corp. and by virtue of their direct ownership of the entities and
interests exchanged. Accordingly, the net assets acquired in the Combination
have been recorded at the historical cost basis of the affiliated predecessor
owners.
Belco Oil & Gas Corp. and its subsidiaries and prior to March 29, 1996,
the combined predecessor entities, are referred to herein as "Belco" or the
"Company".
Nature of Operations
The Company is an independent energy company engaged in the exploration,
development and production of natural gas and oil. The Company operates in
this single industry segment, and all operations are conducted in the United
States. The Company's operations are presently focused in the Giddings Field
(east central Texas), the Moxa Arch Trend (southwest Wyoming) and to a lesser
extent the Golden Trend Field (southern Oklahoma) 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. The Company is affected more by fluctuations in natural gas
prices than oil prices, because a majority of its production (92 percent
during 1996 on a volumetric equivalent basis) was natural gas. 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 6).
F-7
Note 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements for the year ended December 31,
1996 include the accounts of the Company and its wholly-owned subsidiaries.
The Company's interests in the Moxa Arch investment programs (the 1992 Moxa
Arch Drilling Program, the 1993 Moxa Arch Drilling Program and the Moxa Arch
1992 Offset Drilling Program) 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.
For the years ended December 31, 1995 and 1994, the combined accounts are
prepared using the historical costs and results of operations of the combined
predecessor entities as if such entities had always been combined.
Property and Equipment
The Company follows the full-cost method of accounting for oil and gas
properties. Accordingly, all costs associated with acquisition, exploration
and development of oil and gas reserves, including directly related internal
costs, are capitalized. The Company capitalized $3,065,000, $1,181,000 and
$127,000 of internal costs during 1996, 1995 and 1994, 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. If capitalized costs exceed this limit, the excess
is charged to depreciation, depletion and amortization.
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.
Management Fees
The Company manages three investment programs, which were formed during
1992-1994 to acquire and develop interests in certain drilling prospects. 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 $583,000, $602,000 and
$763,000 during 1996, 1995 and 1994, respectively. Such management fees have
been credited to oil and gas property costs.
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, 1996 and 1995, totaled $434,000
and $911,000, respectively. Interest costs for the year ended December 31,
1994, were not significant.
F-8
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. 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.
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 13).
Transactions that do not qualify for hedge accounting are accounted for
using the mark-to-market method. Under such method, the financial instruments
are reflected at market value at the end of the period with resulting
unrealized gains and losses recorded as assets and liabilities in the
consolidated financial statements. Changes in the market value of outstanding
financial instruments are recognized as gain or loss in the period of change.
Revenue Recognition
Revenue from oil and gas sales is recorded on an accrual basis as title
is transferred with deliveries at the wellhead.
Gas Balancing
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, 1996 and 1995 were
not significant. Additionally, gas imbalances are generally reflected as
adjustments to reported gas reserves and future cash flows in the supplemental
oil and gas disclosures.
Income Taxes
The Company accounts for income taxes under the provisions of Statement
of Financial Accounting Standards (SFAS) No. 109 - "Accounting for Income
Taxes," which provides for an asset and liability approach for accounting for
income taxes. Under this approach, deferred tax assets and liabilities are
recognized based on anticipated future tax consequences, using currently
enacted tax laws, attributable to differences between financial statement
carrying amounts of assets and liabilities and their respective tax bases.
Deferred tax assets are reduced by a valuation allowance when, based upon
management's estimate, it is more likely than not that a portion of the
deferred tax assets will not be realized in a future period.
The earnings for the years ended December 31, 1995 and 1994 were not
subject to corporate income taxes as the Company was a combination of
nontaxpaying entities, including Subchapter S, limited liability corporations,
partnership and joint venture entities and individual interest. Accordingly,
earnings were directly taxable to the individual owners. The pro forma
provision for income tax is an estimate of the Company's income taxes that
would have been provided in accordance with SFAS No. 109, if the Company were
a taxable entity during the periods presented (See Note 5).
Stock-Based Compensation
The Company accounts for employee stock-based compensation using the
intrinsic value method prescribed by Accounting Principles Board (APB) Opinion
No. 25, "Accounting for Stock Issued to Employees." Accordingly, the adoption
F-9
of SFAS No. 123, "Accounting for Stock-Based Compensation" in 1996 had no
effect on the Company's results of operations.
Equity Distribution Payable
Undistributed production revenues for 1995, net of costs and expenses
through December 31, 1995 were estimated at $10.1 million for distribution to
the predecessor owners in 1996. This amount was accrued as an equity
distribution payable at December 31, 1995. Actual required distributions
totaled $13.5 million and were distributed in 1996.
Cash Equivalents
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents.
Pro Forma Net Income Per Share
Pro forma net income per share is based on the weighted average number of
shares of Common Stock outstanding. The computation assumes that the Company
was incorporated during the periods presented and presents the shares issued
in connection with the Combination as outstanding for all periods. The
effects of Common Stock equivalent shares (stock options) and restricted stock
were not material for the year ended 1996.
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 6 and 13).
Note 3 - DEBT
In December 1994, Belco Energy L.P. entered into a three-year revolving
credit facility with The Chase Manhattan Bank N.A. (the "Bank").
Semiannually, the Bank will make a determination of the Company's borrowing
base, determined solely at the discretion of the Bank. The Company may
request two additional borrowing base redeterminations per annum. At December
31, 1996 the Credit Facility was $30 million with a borrowing base of $15
million.
Principal outstanding, if any, is due and payable upon maturity in
December 1997 with interest due quarterly. The terms of the agreement provide
for interest at rates ranging from the prime rate plus .25 percent to .375
percent, or the Eurodollar Rate (ER) plus 1.75 percent to 1.875 percent. The
applicable margin over the prime rate or ER varies depending on the aggregate
advances outstanding as a percentage of the borrowing base. The unused
portions of the borrowing base are subject to a .25 percent commitment fee.
Covenants contained in the revolving credit agreement limit Belco Energy
L.P.'s ability to incur additional indebtedness, create liens on its assets
and prohibit speculative transactions in any commodities or futures market.
Belco Energy L.P. is also limited in its ability to make loans, investments or
guarantees and distributions of retained earnings. At December 31, 1996
restricted retained earnings totaled approximately $30 million. Additionally,
Belco Energy L.P. is required to maintain a minimum tangible net worth ($30
million) and certain ratios of leverage (not greater than 1.5:1) and interest
coverage (earnings before interest, taxes and depreciation, depletion and
F-10
amortization to interest expense of not less than 2.75:1). The Bank has the
ability in the event of default to perfect a security interest in certain of
the Company's properties.
The Company repaid all of its outstanding bank debt in March 1996 and as
of December 31, 1996, there was no outstanding balance. The credit facility
remains in effect to finance future obligations of the Company.
Note 4 - RELATED-PARTY TRANSACTIONS
The Company enters into a substantial portion of its Commodity Price Risk
Management Activities with Enron Capital & Trade Resources, a subsidiary of
Enron Corp. The Company's Chairman serves on the board of directors of Enron
Corp. These agreements were entered into in the ordinary course of business
of the Company and are on terms that the Company believes are no less
favorable than the terms of similar arrangements with third parties. Pursuant
to the terms of these agreements, (i) ECT has paid to the Company a net amount
of approximately $5,243,000 with respect to 1996, (ii) ECT has paid to the
Company a net amount of approximately $5,370,000 with respect to 1995 and
(iii) the Company paid to ECT a net amount of approximately $22,000 with
respect to 1994.
The Company's executive offices are leased from its Chairman and $250,000
was paid under such lease in 1996. Lease expense for the Company's executive
offices for the period from inception through 1995 was paid by the Chairman,
with no reimbursement. The Company has recorded an office space and service
expense and a corresponding capital contribution of approximately $250,000 and
$200,000 for the periods ended December 31, 1995 and 1994, respectively, based
on an estimated allocation of space occupied. The Company's remaining
commitment related to the office space and service charge is $250,000 per year
through 1999. Management believes the fee compares favorably to the terms
which might have been available from a non-affiliated party.
Additionally, from inception through March 31, 1996, the Company's
Chairman did not draw any compensation from the Company. The Company has
recorded salary and benefits expense and a corresponding capital contribution
of $150,000 for each of the periods ended December 31, 1995 and 1994, based on
estimates of time devoted to the Company and using expected 1996 compensation.
In 1996, the Chairman commenced receiving compensation.
Certain employees of the Company had an ownership interest in certain oil
and gas properties held by the Company as of December 31, 1995, and 1994. The
Company had receivables of $775,000, $834,000 and $126,000 as of December 31,
1996, 1995 and 1994, respectively, related to amounts loaned to employees in
connection with employee purchases of oil and gas interests. Such receivables
have been recorded as a reduction of equity in the consolidated balance
sheets, as such interests were exchanged for Common Stock in the Combination
(see Note 1). The Company also had payables of $102,000 and $81,000 to the
employees at December 31, 1995 and 1994, respectively, related to revenues
generated by the properties in which the employees had such ownership
interest.
In 1995, the Company engaged Midway Partners LLC (Midway) to serve as
advisor in connection with certain financial matters of the Company, including
the Combination and the potential initial public offering of the Company's
Common Stock. The Company's Senior Financial and Legal Advisor and General
Counsel is one of two managing partners and principals of Midway. In
connection with such engagement, the Company has paid Midway an advisory fee
of $50,000. In 1996, upon consummation of the offering, the Company paid
Midway an additional $200,000.
Note 5 - INCOME TAXES
Prior to March 29, 1996, the earnings of the Company were not subject to
corporate income taxes as the Company, prior to the Combination, was a
combination of non-taxpaying entities, including Subchapter S, limited
liability corporations, partnership and joint venture entities and individual
interests. Accordingly, taxable earnings were directly taxable to the
individual owners through the date of the Combination. As a result of the
Combination consummated on March 29, 1996, the Company became a taxpaying
entity and recorded, in the first quarter of 1996, a $30.1 million one-time,
F-11
non-cash charge to earnings to establish a deferred tax liability (discussed
further below). The historical provision for income taxes for the year ended
December 31, 1996 includes the one-time charge. The pro forma provision for
income taxes reflected in the Consolidated Statements of Operations for the
years ended December 31, 1996, 1995 and 1994 has been presented to reflect the
Company's income taxes under the assumption that the Company was a taxpaying
entity since its inception.
Although the effective date of the Exchange Agreement is January 1, 1996,
each owner of the Combined Assets will be required under existing federal
income tax rules and regulations to include in its taxable income, for all
periods ending on the date of or prior to the completion of the Combination
(March 29, 1996), its allocable portion of the taxable income attributable to
the Combined Assets and will be entitled to all tax benefits related to the
Combined Assets through the completion of the Combination on March 29, 1996.
Total provision for income taxes consists of the following:
Year Ended
December 31, 1996
-----------------
(In thousands)
Payable currently:
Federal. . . . . . . . . . . . . . . . . . . . . $ 6,345
State. . . . . . . . . . . . . . . . . . . . . . 92
-------
6,437
-------
Deferred: 39,967
-------
Total provision for income taxes. . . . . . . . . . . $46,404
=======
The differences between the statutory federal income taxes and the
Company's pro forma effective taxes is summarized as follows (in thousands):
Years Ended December 31,
1996 1995 1994
---- ---- ----
Statutory federal income taxes . . . . . . . . . . . $22,605 $14,906 $ 6,740
State income tax, net of federal benefit . . . . . . 80 115 50
Section 29 tax credits . . . . . . . . . . . . . . . (947) (909) (1,530)
Other. . . . . . . . . . . . . . . . . . . . . . . . 215 (260) (230)
------- ------- -------
Pro forma provision for income taxes . . . . . . . . $21,953 $13,852 $ 5,030
======= ======= =======
The principal components of the Company's net deferred income tax
liability at December 31, 1996 are as follows (in thousands):
1996
Deferred income tax assets
Commodity price risk management activities. . . . . . . . . ($1,494)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . (245)
-------
(1,739)
-------
Deferred income tax liabilities
Depreciation, depletion and amortization. . . . . . . . . . 41,159
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 547
--------
41,706
--------
Net deferred income tax liability. . . . . . . . . . . . . . . . $39,967
Section 29 Tax Credit
The natural gas production from wells drilled on certain of the Company's
properties in the Moxa Arch Trend and Golden Trend Field qualifies for the
Section 29 Tax Credit. The Section 29 Tax Credit is an income tax credit
against regular federal income tax liability with respect to sales of the
Company's production of natural gas produced from tight gas sand formations,
subject to a number of limitations. Fuels qualifying for the Section 29 Tax
Credit must be produced from a well drilled or a facility placed in service
after November 5, 1990 and before January 1, 1993, and be sold before January
1, 2003.
The basic credit, which is currently approximately $0.52 per MMBtu of
natural gas produced from tight sand reservoirs and approximately $1.03 per
MMBtu of natural gas produced from Devonian Shale, is computed by reference to
the price of crude oil and is phased out as the price of oil exceeds $23.50 in
1979 dollars (as adjusted for inflation) with complete phaseout if such price
exceeds $29.50 in 1979 dollars (as adjusted for inflation). Under this
formula, the commencement of phaseout would be triggered if the average price
for crude oil rose above approximately $45 per Bbl in current dollars. The
Company estimates that it generated approximately $0.9 million of Section 29
Tax Credits in 1996. The Section 29 Tax Credit may not be credited against
the alternative minimum tax, but under certain circumstances may be carried
over and applied against regular tax liability in future years. Therefore, no
assurances can be given that the Company's Section 29 Tax Credits will reduce
its federal income tax liability in any particular year. As production from
qualified wells decline, the production based tax credit will also decline.
Texas Severance Tax Abatement
Production from natural gas wells that have been certified as tight
formations or deep wells by the Texas Railroad Commission ("high cost gas
wells") and that are spudded or completed during the period from June 16, 1989
to September 1, 1996 qualify for an exemption from the 7.5% severance tax in
Texas on natural gas and natural gas liquids produced by such wells prior to
August 31, 2001. The natural gas production from wells drilled on certain of
the Company's properties in the Austin Chalk area qualify for this tax
reduction. In addition, high cost gas wells that are spudded or completed
during the period from September 1, 1996 to August 31, 2002 are entitled to
receive a severance tax reduction upon obtaining a high cost gas certification
from the Texas Railroad Commission within 180 days after first production.
The tax reduction is based on a formula composed of the statewide "median" (as
determined by the State of Texas from producer reports) and the producer's
actual drilling and completion costs. More expensive wells will receive a
greater amount of tax credit. This tax rate reduction remains in effect for
10 years or until the aggregate tax credits received equal 50% of the total
drilling and completion costs. The reduction in severance taxes for such
wells is reflected as a reduction in oil and gas operating expenses and an
increase in the standardized measure of discounted future net cash flows
relating to proved oil and gas reserves (See Note 13).
Note 6 - COMMODITY PRICE RISK MANAGEMENT ACTIVITIES AND FAIR VALUE OF
FINANCIAL INSTRUMENTS
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, 1996, the Company had entered
into hedging transactions with respect to a significant portion of its
estimated production for 1997 and to a lesser extent its estimated production
for 1998 and 1999. 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.
F-13
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, 1996:
Production Periods
----------------------------------------
1997 1998 1999 Total
----------------------------------------
Gas -
Price swaps - receive fixed price (thousand MMBtu) (1)(6) 14,305 3,665 -- 17,970
Average price, per MMBtu $ 2.10 $ 2.01 -- $ 2.08
Collars and options (thousand MMBtu) (2) 8,350 9,885 -- 18,235
Average floor price, per MMBtu $ 2.05 $ 1.92 -- $ 1.98
Average ceiling price, per MMBtu $ 2.44 $ 2.16 -- $ 2.29
Price swaps - pay fixed price (thousand MMBtu) (3) 8,777 1,070 -- 9,847
Average price, per MMBtu $ 2.20 $ 2.30 -- $ 2.21
Basis swaps (thousand MMBtu) (4)(5) 35,158 10,950 -- 46,108
Average basis differential, per MMBtu $ .20 $ .39 -- $ .25
Oil -
Price swaps - receive fixed price (MBbls) (1) 301 35 -- 336
Average price, per Bbl $ 18.49 $18.49 -- $ 18.49
Collars and options (MBbls) (2) 353 242 25 620
Average floor price, per Bbl $ 18.22 $17.21 $17.00 $ 17.78
Average ceiling price, per Bbl $ 21.16 $18.92 $18.50 $ 20.18
Price swaps - pay fixed price (MBbls) (3) 60 -- -- 60
Average price, per Bbl $ 21.70 -- -- $ 21.70
__________________
(1) For any particular swap transaction, the counterpart 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
the fixed-price payer on the swap. In these transactions, the
counterparty is required to make a payment to the Company in the
event that the NYMEX Reference Price for any settlement period is
greater than the swap price, and the Company is required to make a
payment to the counterparty in the event that the NYMEX Reference
Price for any settlement period is less than the swap price.
(4) Since most of the Company's gas is sold under spot contracts with
reference to Houston Ship Channel prices and substantially all of the
Company's hedge transactions are based on the NYMEX Reference
Price, the Company has entered into basis swaps that require the
counterparty to make a payment to the Company in the event that the
average NYMEX Reference Price per MMBtu for a reference period
exceeds the average price per MMBtu for gas delivered at the
Houston Ship Channel for such reference period by a stated
differential, and requires the Company to make a payment to the
counterparty in the event that the NYMEX Reference Price exceeds
the Houston Ship Channel price by less than a stated differential (or
in the event that the Houston Ship Channel price exceeds the NYMEX
Reference Price). The Company also sells its Wyoming gas at prices
based on the Northwest Pipeline Rocky Mountain Index and has
entered into basis swaps that require the counterparty to make a
payment to the Company in the event that the NYMEX Reference
Price per MMBtu for a reference period exceeds the Northwest
Pipeline Rocky Mountain Index Price by more than a stated
differential and requires the Company to make a payment to the
counterparty in the event that the NYMEX Reference Price exceeds
the Northwest Pipeline Rocky Mountain Index Price by less than a
stated differential (or in the event that the Northwest Pipeline Rocky
Mountain Index Price is greater than the NYMEX Reference Price).
(5) Does not include 3,650 thousand MMBtu of basis swaps in 1997 that
are extendable at the election of the counterparty.
(6) Does not include 1,825 and 8,205 thousand MMBtu of swaps in 1997
and 1998, respectively, that are extendable at the election of the
counterparty.
All of the above transactions were carried out in the over-the-counter
market, and not on the NYMEX, with financial counterparties having at least an
investment grade credit rating. All of these transactions provide solely for
financial settlements related to closing prices on the NYMEX.
In 1995 and 1994, a realized hedging gain of $9.5 million and $550,000,
respectively, was included in Commodity Price Risk Management Revenues. At
December 31, 1995, the Company had net deferred losses of $145,000 for settled
derivative contracts and net deferred premium costs of $86,000, relative to
future production periods. The current portion of these amounts are included
in other current assets and the long-term portion in other assets.
In 1996, a realized hedging loss of $83,000 was included in Commodity
Price Risk Management Revenues. At December 31, 1996, the Company had accrued
liabilities of $307,000 for settled derivative contracts and net deferred
premium costs of $465,000, relative to future production periods. These
amounts are included in Price Risk Management Activities as a current
liability and current asset, respectively.
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 1996
results of operations included an aggregate pre-tax loss of $5.9 million
related to these activities which included (1) net realized losses on
settlements totaling $3.9 million, (2) net premiums received totaling $7.4
million and (3) the unrealized loss resulting from net change in the value of
the Company's mark-to-market portfolio of price risk management activities for
the year ended December 31, 1996 of $9.4 million, all included in Commodity
Price Risk Management Revenues. As a result of the increase in oil and
natural gas prices which occurred in the fourth quarter, the Company recorded
a fourth quarter pre-tax loss of $8.4 million from Commodity Price Risk
Management Activities which included a $4.2 million ($2.77 million net of tax)
non-cash charge for unrealized losses related to mark-to-market accounting
requirements. At December 31, 1996, the Company's consolidated balance sheet
reflects $1.8 million and $11.2 million of price risk management assets and
liabilities, respectively, which includes primarily the mark-to-market
reserve. The Company had not entered into any financial instruments that did
not qualify for hedge accounting prior to 1996.
F-14
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, 1996, that do not qualify for hedge accounting:
Production Periods
----------------------------------------------
1997 1998 1999 Total
Gas - ----------------------------------------------
Straddles (thousand MMBtu) (1) 1,825 -- -- 1,825
Average price, per MMBtu $ 2.24 -- -- $ 2.24
Calls Sold (thousand MMBtu) (2) 11,260 10,950 -- 22,210
Average price, per MMBtu $ 2.04 $ 2.27 -- $ 2.15
Puts Sold (thousand MMBtu) (2) 5,360 1,093 -- 6,453
Average price, per MMBtu $ 1.98 $ 2.00 -- $ 1.98
Price swaps - pay fixed price
(thousand MMBtu) 5,430 -- -- 5,430
Average price, per MMBtu $ 1.99 -- -- $ 1.99
Oil -
Calls Sold (MBbls) (2) 301 68 6 375
Average price, per Bbl $ 22.41 $ 22.21 $ 22.00 $ 22.37
Puts Sold (MBbls) (2) -- 60 -- 60
Average price, per Bbl -- $ 19.75 -- $ 19.75
F-15
_______________________
(1) A straddle is a combination of a put sold and a call sold. The
Company is required to make a payment to the counterparty in the
event that the NYMEX Reference Price for any settlement period is
greater than the ceiling price or less than the floor price. The
Company receives a significant premium upon entering into such
contract.
(2) Calls sold or puts sold under written option contracts, in return for
a significant premium received by the Company upon initiation of
the contract, the Company is required to make a payment to the
counterparty in the event that the NYMEX Reference Price for any
settlement period is greater than the price of the call sold, or less
than the price of the put sold.
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, 1996 and 1995.
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, 1996 December 31, 1995
------------------ ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
(In thousands)
Cash and cash equivalents $43,473 $43,473 $1,556 $1,556
Long-term bank debt -- -- 22,000 22,000
Oil and gas commodity - Hedges 158 (8,555) 231 9,200
- Non-hedges (9,363) (9,363) -- --
The following methods and assumptions were used to estimate the fair
value of the financial instruments summarized in the above table. The
carrying values of trade receivables and trade payables included in the
accompanying consolidated balance sheets approximated market value at December
31, 1996 and 1995.
Cash and Cash Equivalents
The carrying amounts approximate fair value because of the short maturity
of those instruments.
Long-Term Debt
The fair value of the Company's debt is assumed to be the same as the
carrying value because the interest rate is variable and is reflective of
market rates.
Oil and Gas Commodity Financial Instruments
The estimated fair value of oil and gas commodity financial instruments
has been determined by using available market data and applying certain
valuation methodologies. In some cases, quotes of termination values were
available. Judgment is necessarily required in interpreting market data, and
the use of different market assumptions or estimation methodologies could
result in different estimates of fair value.
F-16
Note 7 - 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. The Programs have
invested $116.6 million in connection with the development of the Moxa Arch
Trend of Southwest Wyoming. Through October 30, 1996, the Company owned
approximately 55.20 percent of the 1992 Moxa Arch Drilling Program, 32.45
percent of the 1993 Moxa Arch Drilling Program, and 58.21 percent of the Moxa
Arch 1992 Offset Drilling Program. On October 31, 1996 the Company purchased
from certain third-party investors interests (the "Acquired Interests") in the
Belco Oil & Gas Corp. 1992, 1993 and 1992 Offset Moxa Arch Drilling Programs.
The effective date of the purchase was October 31, 1996 for financial
reporting purposes. The Acquired Interests represent incremental working
interests in the Company's natural gas wells in the Moxa Arch trend located in
Lincoln, Sweetwater and Uinta Counties, Wyoming. The Company paid aggregate
cash consideration of $9.9 million plus an 80% participation in potential
natural gas price increases (net of incremental production costs) associated
with production from the wells through July 31, 1999 (the "Price Participation
Right"). After the purchase, the Company's interest in these programs was
increased to 81.5% of the 1992 Moxa Arch Drilling Program, 74.0% of the 1993
Moxa Arch Drilling Program, and 80.5% of the Moxa Arch 1992 Offset Drilling
Program. The transaction was accounted for using the purchase method of
accounting.
The remaining third-party investors in the Programs may "put" their
interest to Belco annually through 2003, based upon a valuation by a
nationally recognized independent petroleum engineering firm of the discounted
net present value of the future net revenues from production of proved
reserves attributable to the interests. The put amount is to be calculated
based upon certain specified parameters including prices, discount factors and
reserve life. No investor under the Programs exercised the put right in 1996.
The Company is not obligated to repurchase in any one calendar year more than
30% of the interests originally acquired by the program investors (including,
for purposes of this calculation, the Company's interest). The Company's
purchase price under the put right has not been calculated given that no
investors have exercised such right. However, using reserve values presented
in Note 13, Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves (SEC basis using year-end prices and a 10%
discount rate), the maximum purchase price if all remaining investors
exercised the put option would not be material to the Company as of December
31, 1996.
Lease Commitments
At December 31, 1996, the Company had operating leases covering office
space. Minimum rental commitments under such operating leases are as follows
(in thousands):
Year ending December 31 --
1997 $ 354
1998 365
1999 250
--------
Total $ 969
========
For the years ended December 31, 1996, 1995 and 1994, total rental
expense was approximately $329,000, $317,000 and $200,000, respectively.
F-18
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 8 - CASH FLOW INFORMATION
The Company paid $4.0 million in income taxes during the 1996 period with
the remaining 1996 liability for such taxes due in the first quarter of 1997.
No income taxes were paid by the Company in 1995 and 1994 because the
applicable taxes were paid by the individual owners of the affiliated entities
and properties now included in the Company (See Note 5).
Note 9 - 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 1996 include $44.6 million, $37.7 million and $11.7
million in revenues received from three customers. Also, 1996 revenues
included net losses in the amount of $5.9 million related to Commodity Price
Risk Management Activities. Oil and gas sales for 1995 include $7.9 million,
$21.1 million, $17.2 million and $14.0 million in revenues received from four
customers. Also, 1995 revenues include commodity price risk management gains
totaling $9.5 million. Oil and gas sales for 1994 include $15.1 million, $7.6
million, $4.9 million and $9.7 million in revenues received from four
customers. No other customers individually accounted for 10 percent or more
of revenues.
Note 10 - EMPLOYEE BENEFIT PLAN
Retirement Plan
The Company adopted a 401(k) and savings plan for its employees on
January 1, 1995. The plan qualifies under Section 401(k) of the Internal
Revenue Code as a salary reduction plan. Under the plan, but subject to
certain limitations imposed under the Internal Revenue Code, eligible
employees are permitted to (a) defer receipt of up to 15 percent of their
compensation on a pre-tax basis (salary deferral contributions) or (b)
contribute up to 10 percent of their compensation to the plan on an after-tax
basis. The plan provides for a Company matching contribution in an amount
equal to 50 percent of a participant's salary deferral contributions that are
not in excess of 6 percent of such participant's compensation. The plan also
F-18
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 1996 and 1995, the Company incurred $62,443 and $37,293,
respectively, in connection with this plan.
Performance Unit Plan
In 1996, Belco adopted a performance unit plan which is a long-term
incentive compensation plan to be administered by the Stock Option Committee
of the Board of Directors. All employees of the Company are eligible to
receive an award of performance units under the plan. A performance unit has
a performance period that is four consecutive calendar years beginning with
and including the calendar year in which the performance unit is granted. The
value of a performance unit will be determined based on the ranking of the
Company's return on Common Stock during an applicable performance period
compared to the return on the shares of Common Stock of certain companies with
which the Company competes; however, the maximum value is $2.00 per unit.
While payments with respect to performance units will normally be made at the
end of the four-year performance period, pro-rated payments may also be made
at an earlier time in the event a participant's employment with the Company is
involuntarily terminated without cause or is terminated by reason of
retirement, death or disability. Payments with respect to performance units
will be made in a single sum and may be made in cash, Common Stock or a
combination thereof as the Stock Option Committee in its sole discretion may
determine. During 1996, the Company granted 250,000 performance units. As of
December 31,1996 the Company has made no cash payments in connection with this
plan.
Note 11 - CAPITAL STOCK
Exchange Agreement and Public Equity Offering On March 29, 1996, the
Exchange Agreement was consummated resulting in the issuance of 25,000,000
shares to the Predecessor Owners (See Note 1). In addition, on March 29,
1996, the Company completed its initial public offering issuing 6,500,000
shares at $19 per share. Net proceeds totaled $113.1 million after offering
costs of $10.4 million.
Stock Incentive Plans
On March 25, 1996, the Company adopted a Stock Incentive Plan (the Plan)
under which options for shares of Belco's Common Stock may be granted to
officers and employees for up to 2,250,000 shares of Common Stock. Under the
Plan, options granted may either be incentive stock options or non-qualified
stock options with a maximum term of 10 years and are granted at no less than
the fair market of the stock at the date of grant. Options vest 20% per year
until fully vested five years from the date of grant.
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.
F-19
A summary of the status of the Company's plans (the Plans) as of December
31,1996 and the changes during the year then ended is presented below:
Number of Weighted Average
Options Exercise Price
---------
Outstanding at beginning of year. . . . . . . . . . . . -- $ --
Granted. . . . . . . . . . . . . . . . . . . . . . 409,000 20.91
Exercised. . . . . . . . . . . . . . . . . . . . . -- --
Forfeited. . . . . . . . . . . . . . . . . . . . . (8,000) 20.09
Expired. . . . . . . . . . . . . . . . . . . . . . -- --
---------
Outstanding at end of year. . . . . . . . . . . . . . . 401,000 $ 20.91
Exercisable at end of year. . . . . . . . . . . . . . . -- $ --
========= ==========
Available for grant at end of year. . . . . . . . . . . 1,929,700
Weighted average fair value of options granted during ---------
the year. . . . . . . . . . . . . . . . . . . . . . . $ 12.73
---------
The following table summarizes information about stock options
outstanding at December 31, 1996:
Options Outstanding Options Exercisable
------------------------------------------------------------------------------------------
Weighted
Number Average Weighted Number Weighted
Outstanding at Remaining Average Exercisable at Average
Range of Prices 12/31/96 Contractual Life Exercise Price 12/31/96 Exercise Price
- -------------------------------------------------------------------------------------------------------------
$19.00 310,000 9.25 $19.00 -- $ --
$24.06-32.68 91,000 9.56 27.40 -- --
------- -----------
401,000 9.31 $20.91 -- $ --
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
and pro forma earnings per share would have been reduced to the pro forma
amounts indicated below (in thousands, except for per share amounts):
Pro Forma Net Income As Reported $42,633
Pro Forma 42,117
Pro Forma Earnings Per Share As Reported $ 1.42
Pro Forma $ 1.40
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: risk-free interest rate of 6.74 percent, expected
volatility of 31.0 percent, expected lives of 7.5 years and no dividend yield.
The pro forma amounts shown above may not be representative of future results
since this is the first year for the Plans.
Under the Stock Incentive Plan, participants may be granted stock
without cost (restricted stock). During 1996, 77,300 shares of restricted
stock were issued under the Plan. 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 1996, $227,000 was charged to expense relating to
the Plan.
F-20
Note 12 - SUPPLEMENTAL QUARTERLY FINANCIAL DATA (IN THOUSANDS, EXCEPT PER
SHARE AMOUNTS):
Quarters
-----------------------------------------------------
First Second Third Fourth
-----------------------------------------------------
1996 (Unaudited)
Revenues $ 28,610 $ 31,555 $ 28,027 $ 28,204
========== ========== ========== ========
Costs and Expenses $ 12,118 $ 12,837 $ 13,206 $ 13,649
========== ========== ========== ========
Pro Forma Net Income $ 11,066 $ 12,354 $ 9,782 $ 9,431
========== ========== ========== ========
Pro Forma Net Income Per Share $ 0.44 $ 0.39 $ 0.31 $ 0.30
========== ========== ========== ========
1995
Revenues $ 15,701 $ 19,456 $ 20,728 $ 22,715
========== ========== ========== ========
Costs and Expenses $ 7,070 $ 8,910 $ 9,015 $ 11,016
========== ========== ========== ========
Pro Forma Net Income $ 5,783 $ 7,066 $ 7,848 $ 8,040
========== ========== ========== ========
Pro Forma Net Income Per Share $ 0.23 $ 0.28 $ 0.31 $ 0.33
========== ========== ========== ========
The sum of the individual quarterly pro forma net income per share
amounts may not agree with year-to-date pro forma net income per share as
each period's computation is based on the weighted average number of
common shares outstanding during that period.
Note 13 - 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, 1996 and 1995 (in thousands):
1996 1995
-------- --------
Proved properties . . . . . . . . . . . . . . $237,150 $152,081
Unproved properties . . . . . . . . . . . . . 77,570 19,927
Total capitalized costs . . . . . . . . . . . 314,720 172,008
Less Accumulated depreciation, depletion and
amortization. . . . . . . . . . . . . . . . (86,490) (45,771)
Net capitalized costs . . . . . . . . . . . . $228,230 $126,237
Costs Not Being Amortized
The following table sets forth a summary of unproved oil and gas property
costs not being amortized at December 31, 1996, by the year in which such
costs were incurred (in thousands):
1996 1995 1994 1993 Total
-------- -------- -------- -------- --------
Leasehold and seismic. . . . . . . $ 57,568 $ 10,491 $ 8,085 $ 1,426 $ 77,570
F-21
Costs Incurred
The following table sets forth the costs incurred in oil and gas
acquisition, exploration and development activities as of December 31, 1996,
1995 and 1994 (in thousands):
1996 1995 1994
Property acquisitions costs
Proved. . . . . . . . . . . . . . . . . $ 9,871 $ -- $ --
Unproved. . . . . . . . . . . . . . . . 64,530 13,643 10,916
Exploration costs. . . . . . . . . . . . . . 17,444 2,382 1,727
Development costs. . . . . . . . . . . . . . 50,433 54,451 39,587
Capitalized interest . . . . . . . . . . . . 434 911 --
---------- -------- ---------
Total costs incurred. . . . . . . . . . $ 142,712 $ 71,387 $ 52,230
========== ======== =========
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, 1996, 1995 and 1994 (in thousands):
1996 1995 1994
Oil and gas revenues (including commodity -------- ------- -------
price risk management activities). . . . . . . . . . . $113,743 $78,247 $40,912
Costs and expenses
Lease operating expenses . . . . . . . . . . . . . 7,024 4,136 3,431
Production taxes . . . . . . . . . . . . . . . . . 823 1,688 2,079
Depreciation, depletion and amortization . . . . . 40,904 27,590 14,072
-------- ------- -------
Results of operations from producing activities before
income taxes . . . . . . . . . . . . . . . . . . . . . 64,992 44,833 21,330
Pro forma provision for income taxes. . . . . . . . . . 22,095 14,638 5,756
-------- ------- -------
Pro forma results of operations from producing
activities. . . . . . . . . . . . . . . . . . . . . . $ 42,897 $ 30,195 $15,574
======== ======== =======
Amortization rate per Mcf equivalent, recurring . . . . $ .73 $ .64 $ .65
======== ======== =======
Oil and Gas Reserve Information
The following summarizes the policies used by the Company in preparing
the accompanying oil and gas reserves and the changes in such 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, 1996 and 1995 are based on estimates prepared by Miller & Lents,
independent petroleum engineers. Such estimates have been prepared in
accordance with guidelines established by the Securities and Exchange
Commission (SEC). Reserve estimates for periods prior to December 31, 1995
were not prepared by an independent petroleum engineer. While reserve reports
for years ended prior to December 31, 1995 were not prepared
contemporaneously, they have been prepared by an in-house engineer on a basis
generally consistent with the Miller & Lents report. The Company used the
December 31, 1995 Miller & Lents estimates as an initial basis and adjusted
F-22
such data for actual production and extensions, discoveries and other
additions in 1994 to determine the relevant data for each of these periods.
The Company also calculated the reserve economics at the end of 1994 using oil
and gas prices in effect as of the end of the year.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
Company. The reserve data set forth herein represent only estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result,
estimates made by different engineers often vary. In addition, results of
drilling, testing and production subsequent to the date of an estimate may
justify revision of such estimates, and such revisions may be material.
Accordingly, reserve estimates are often different from the quantities of oil
and gas that are ultimately recovered.
The standardized measure of discounted future net cash flows from
production of proved reserves was developed by first estimating the quantities
of proved reserves and the future periods during which they are expected to be
produced based on year-end economic conditions. The estimated future cash
flows from proved reserves were then determined based on year-end prices,
except in those instances where fixed contracts provide for a higher or lower
amount. Estimates of future cash flows applicable to oil and gas commodity
hedges have been prepared by the Company and are reflected in future cash
flows from proved reserves with such estimates based on prices in effect as of
the date of the reserve report. Additionally, future cash flows were reduced
by estimated production costs, costs to develop and produce the proved
reserves, and when significant, certain abandonment costs, all based on
year-end economic conditions. Future net cash flows have been discounted by
10 percent in accordance with SEC guidelines.
The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's oil and gas reserves. An estimate of fair value would also take
into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.
Under SEC rules, companies that follow full-cost accounting methods are
required to make quarterly "ceiling test" calculations. Under this test,
proved oil and gas property costs may not exceed the present value of
estimated future net revenues from proved reserves, discounted at 10 percent,
as adjusted for related tax effects and deferred tax reserves. Application of
these rules during periods of relatively low oil and gas prices, even if of
short-term duration, may result in write-downs.
F-23
Standardized Measure of Discounted Future Net Cash Flows
Relating to Proved Oil and Gas Reserves
(In thousands)
December 31,
1996 1995 1994
Future cash inflows (2). . . . . . . . . . . . . . . . $1,071,550 $ 427,213 $ 244,782
Future production costs. . . . . . . . . . . . . . . . (253,159) (96,643) (55,364)
Future development costs . . . . . . . . . . . . . . . (71,061) (36,003) (8,655)
---------- --------- ---------
Future net inflows before income taxes (2) . . . . . . 747,330 294,567 180,763
Discount at 10% annual rate. . . . . . . . . . . . . . (331,800) (88,058) (70,978)
Discounted future net cash flows
before income taxes. . . . . . . . . . . . . . . . 415,530 206,509 109,785
Pro forma discounted future income taxes (1) . . . . . (134,957) (58,000) (29,000)
---------- --------- ---------
Standardized measure of discounted
future net cash flows. . . . . . . . . . . . . . . . $ 280,573 $ 148,509 $ 80,785
========== ========= =========
___________________
(1) The earnings of the Company were not subject to corporate income
taxes prior to March 29, 1996 as the Company was a combination
of nontaxpaying entities. Concurrent with the Exchange
Agreement (see Note 1), the Company became a taxable corporation.
The estimated pro forma income taxes as of December 31, 1995 and
1994, discounted at 10%, have been presented assuming the
Company was a taxable entity for all periods.
(2) Oil and gas commodity hedges included in future cash inflows
totaled ($60.8) million, $7.6 million and $14.0 million at December 31,
1996, 1995 and 1994, respectively, and such hedges included in
discounted future net cash flows before income taxes totaled ($55.2)
million, $7.2 million and $12.4 million at December 31, 1996, 1995 and
1994, respectively.
F-24
Changes in Standardized Measure of Discounted Future Net Cash Flows
(In thousands)
1996 1995 1994
Balance, beginning of year. . . . . . . . . . . . . . . . . . . . $ 148,509 $ 80,785 $ 61,108
Sales and transfers of oil and
gas produced, net of production costs. . . . . . . . . . . . . . (111,780) (72,423) (35,402)
Net change in sales price and production costs. . . . . . . . . . 145,133 11,390 (11,205)
Extensions and discoveries. . . . . . . . . . . . . . . . . . . . 153,920 104,549 38,812
Purchases of minerals in place. . . . . . . . . . . . . . . . . . 7,843 -- --
Changes in estimated future development costs . . . . . . . . . . 24,618 8,655 835
Revisions in quantities . . . . . . . . . . . . . . . . . . . . . 50,309 -- --
Accretion of discount . . . . . . . . . . . . . . . . . . . . . . 20,651 10,979 8,511
Other, principally revisions in estimates of timing of
production . . . . . . . . . . . . . . . . . . . . . . . . . . . (81,673) 33,574 23,126
Change in income taxes. . . . . . . . . . . . . . . . . . . . . . (76,957) (29,000) (5,000)
--------- -------- --------
Balance, End of year $ 280,573 $148,509 $ 80,785
========= ======== ========
F-25
Reserve Quantity Information
Proved Reserves
Oil Gas
(MBbls) (MMcf)
Balance at December 31, 1993 . . . . . . . . . . . . . 963 86,854
Purchases of minerals in place . . . . . . . . . . . -- --
Extensions, discoveries and other additions. . . . . 1,657 45,283
Revisions of previous estimates. . . . . . . . . . . -- --
Sales of minerals in place . . . . . . . . . . . . . -- --
Production . . . . . . . . . . . . . . . . . . . . . (691) (17,482)
----- -------
Balance at December 31, 1994 . . . . . . . . . . . . . 1,929 114,655
Purchases of minerals in place . . . . . . . . . . . -- --
Extensions, discoveries and other additions. . . . . 1,484 126,562
Revisions of previous estimates. . . . . . . . . . . -- --
Sales of minerals in place . . . . . . . . . . . . . -- --
Production . . . . . . . . . . . . . . . . . . . . . (961) (37,047)
----- -------
Balance at December 31, 1995 . . . . . . . . . . . . . 2,452 204,170
Purchases of minerals in place . . . . . . . . . . . 162 21,993
Extensions, discoveries and other additions. . . . . 1,411 87,319
Revisions of previous estimates. . . . . . . . . . . 96 22,799
Sales of minerals in place . . . . . . . . . . . . . -- --
Production . . . . . . . . . . . . . . . . . . . . . (794) (51,289)
----- -------
Balance at December 31, 1996 . . . . . . . . . . . . . 3,327 284,992
===== =======
Proved Developed Reserves
December 31, 1993. . . . . . . . . . . . . . . . . . . 938 86,223
December 31, 1994. . . . . . . . . . . . . . . . . . . 1,793 100,113
December 31, 1995. . . . . . . . . . . . . . . . . . . 1,838 140,725
December 31, 1996. . . . . . . . . . . . . . . . . . . 2,070 184,904
F-26
EX-11.1
Belco Oil & Gas Corp.
Computation of Earnings Per Share
(In thousands, except per share data)
Weighted Average Calculation: 1996 1995 1994
Pro forma Net Income . . . . . . . . . . . . . . . . . . . . $42,633 $28,737 $14,226
======= ======= =======
Weighted average common shares outstanding . . . . . . . . . 29,986 25,000 25,000
======= ======= =======
Pro forma Net Income Per Share . . . . . . . . . . . . . . . $ 1.42 $ 1.15 $ 0.57
======= ======= =======
Primary Calculation:
Shares issued in connection with the combination and
assumed outstanding for all periods . . . . . . . . . . . . 25,000 25,000 25,000
Weighted average shares and equivalent shares outstanding:
Issued in connection with the public offering . . . . . 4,986 -- --
Restricted stock, treasury stock method . . . . . . . . 9 -- --
Stock options, treasury stock method. . . . . . . . . . 44 -- --
------ ------- -------
Weighted average common and common equivalent
shares outstanding. . . . . . . . . . . . . . . . . . . . . 30,039 25,000 25,000
====== ======= =======
Pro forma Net Income . . . . . . . . . . . . . . . . . . . . $42,633 $28,737 $14,226
======= ======= =======
Pro forma Net Income
Per Share - Primary . . . . . . . . . . . . . . . . . . $ 1.42 $ 1.15 $ 0.57
======= ======= =======
The difference between primary and fully diluted earnings per share is not
significant.
EXHIBIT 21.1
SUBSIDIARIES OF BELCO OIL & GAS CORP., a Nevada corporation
dated December 31, 1996:
BELCO OPERATING CORP., a Delaware corporation
BELCO ENERGY L.P., a Delaware limited partnership
BELCO FINANCE CO., a Wyoming corporation
BOG WYOMING LLC, a Wyoming limited liability company
GIN LANE CO., a Delaware corporation
FORTUNE CORP., a Texas corporation
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation
of our report included in this Form 10-K, into Belco Oil & Gas Corp.'s
previously filed Registration Statement on Form S-8 No. 33-03552.
/s/ Arthur Anderson
___________________________________
ARTHUR ANDERSEN LLP
March 25, 1997
EXHIBIT 23.2
Miller and Lents, Ltd.
The firm of Miller and Lents, Ltd., as independent oil and gas
consultants, prepared a report dated February 25, 1997, for Belco Oil & Gas
Corp. regarding the proved reserves of Belco Oil & Gas Corp. as of December
31, 1996. We hereby consent to all references to our firm included as a part
of the Form 10-K, and the incorporation by reference of the Form 10-K into
Belco Oil & Gas Corp.'s Registration Statement on Form S-8 (Registration No.
333-03552).
Miller and Lents, Ltd. has no interests in Belco Oil & Gas Corp. or in
any of its affiliated companies or subsidiaries and is not to receive any such
interest as payment for such report and has no director, officer, or employee
employed or otherwise connected with Belco Oil & Gas Corp. We are not
employed by Belco Oil & Gas Corp. on a contingent basis.
MILLER AND LENTS, LTD.
/s/ P. G. Von Tungeln
By: ________________________
P. G. Von Tungeln
President
Houston, Texas
March 25, 1997
BELCO OIL & GAS CORP.
Form 10-K
Table of Contents
Page
PART I
Item 1. - BUSINESS . . . . . . . . . . . . . . . . . . . . . . .2
Overview. . . . . . . . . . . . . . . . . . . . . . . . . .2
Recent Developments . . . . . . . . . . . . . . . . . . . .2
Primary Operating Areas . . . . . . . . . . . . . . . . . .4
Costs Incurred and Drilling Results . . . . . . . . . . . .7
Acreage . . . . . . . . . . . . . . . . . . . . . . . . . .9
Productive Well Summary . . . . . . . . . . . . . . . . . .9
Marketing . . . . . . . . . . . . . . . . . . . . . . . . 10
Production Sales Contracts. . . . . . . . . . . . . . . . 10
Price Risk Management Transactions. . . . . . . . . . . . 11
Texas Severance Tax Abatement . . . . . . . . . . . . . . 12
Louisiana Severance Tax Abatement . . . . . . . . . . . . 12
Section 29 Tax Credit . . . . . . . . . . . . . . . . . . 13
Regulation. . . . . . . . . . . . . . . . . . . . . . . . 13
Title to Properties . . . . . . . . . . . . . . . . . . . 17
Employees . . . . . . . . . . . . . . . . . . . . . . . . 17
Facilities. . . . . . . . . . . . . . . . . . . . . . . . 18
Forward Looking Information and Risk Factors. . . . . . . 18
Certain Definitions . . . . . . . . . . . . . . . . . . . 21
Item 2 - PROPERTIES. . . . . . . . . . . . . . . . . . . . . . 22
Oil and Gas Reserves. . . . . . . . . . . . . . . . . . . 22
Item 3 - LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . 24
Item 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS . 24
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 - 1996 Compared to 1995 . . . . . . 28
Results of Operations - 1995 Compared to 1994 . . . . . . 30
Liquidity and Capital Resources . . . . . . . . . . . . . 30
Commodity Price Risk Management Transactions. . . . . . . 32
Environmental Matters . . . . . . . . . . . . . . . . . . 32
Information Regarding Forward Looking Statements. . . . . 32
Item 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA . . . . . 33
Item 9 - CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE . . . . . . . . 33
PART III
Item 10 -DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. . 33
Item 11 - EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . 35
Item 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT . . . . . . . . . . . . . . . . .35
Item 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . 35
PART IV
Item 14 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . .36