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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON SEPTEMBER 14, 1995
REGISTRATION NO. 33-61747
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SECURITIES AND EXCHANGE COMMISSION
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AMENDMENT NO. 2
TO
FORM S-3
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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CAIRN ENERGY USA, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 1311 23-2169839
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or organization) Classification Code Number) Identification Number)
MICHAEL R. GILBERT
PRESIDENT AND CHIEF EXECUTIVE OFFICER
CAIRN ENERGY USA, INC.
8235 DOUGLAS AVENUE, SUITE 1221
DALLAS, TEXAS 75225
(214) 369-0316
(Name, address, including zip code, and telephone number,
including area code, of registrant's principal executive offices and of agent
for service)
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Copies to:
MARK D. WIGDER, ESQ. LARRY JORDAN ROWE, ESQ. STEVEN A. COHEN, ESQ.
JENKENS & GILCHRIST, ROPES & GRAY HOLME ROBERTS & OWEN LLC
A PROFESSIONAL CORPORATION ONE INTERNATIONAL PLACE 1700 LINCOLN, SUITE 4100
1445 ROSS AVENUE, SUITE 3200 BOSTON, MASSACHUSETTS 02110 DENVER, COLORADO 80203
DALLAS, TEXAS 75202 (617) 951-7407 (303) 866-0238
(214) 855-4326
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after the effective date of this registration statement.
If the only securities being registered on this form are being offered pursuant
to dividend or interest reinvestment plans, please check the following box. / /
If any of the securities being registered on this form are to be offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered in connection with dividend or interest
reimbursement plans, check the following box. / /
If any of the securities being registered on this form are to be offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered in connection with dividend or interest
reimbursement plans, check the following box. / /
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CALCULATION OF REGISTRATION FEE
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PROPOSED MAXIMUM
OFFERING PRICE PROPOSED AMOUNT OF
TITLE OF EACH CLASS OF AMOUNT TO BE PER MAXIMUM AGGREGATE REGISTRATION
SECURITIES REGISTERED REGISTERED(1) SECURITY(2) OFFERING PRICE(2) FEE(3)
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Shares of Common Stock.................. 4,312,500 Shares $11.53125 $49,234,375 $16,977
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(1) Includes 562,500 shares that the Underwriters have the option to purchase
for over-allotments, if any.
(2) Estimated solely for the purpose of calculating the registration fee
pursuant to Rule 457(c) and based upon the average of the high and low
prices reported on the NASDAQ National Market on September 12, 1995.
(3) The Registrant has previously paid a registration fee in the amount of
$12,404 with respect to 3,162,500 shares based upon a bona fide estimated
maximum offering price per share of $11.375 per share, and pays $4,573
herewith with respect to the additional 1,150,000 shares registered hereby.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES
AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE
A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT
SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE
SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SECTION 8(A), MAY
DETERMINE.
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PROSPECTUS September 14, 1995
3,750,000 Shares
LOGO
Common Stock
LOGO
Of the 3,750,000 shares of common stock (the "Common Stock") of Cairn Energy
USA, Inc., a Delaware corporation (the "Company"), offered hereby (the
"Offering"), 1,000,000 shares are being sold by the Company and 2,750,000 shares
are being sold by Phemus Corporation, a Massachusetts corporation (the "Selling
Stockholder"). See "Selling Stockholder." The Company will not receive any of
the proceeds from the sale of shares by the Selling Stockholder. The Common
Stock is traded on the NASDAQ National Market ("NNM") under the symbol "CEUS."
The closing price for the Common Stock on the NNM on September 13, 1995 was
$11.50. See "Price Range of Common Stock."
SEE "RISK FACTORS" FOR A DESCRIPTION OF CERTAIN FACTORS RELEVANT TO AN
INVESTMENT IN THE COMMON STOCK OFFERED HEREBY.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
Price to Underwriting Proceeds to Proceeds to
Public Discount(1) Company(2) Selling Stockholder(2)
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Per Share.................... $11.25 $0.5625 $10.6875 $10.6875
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Total(3)..................... $42,187,500 $2,109,375 $10,687,500 $29,390,625
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(1) See "Underwriting" for information relating to indemnification of the
Underwriters.
(2) Before deducting expenses, estimated to be $64,000 payable by the Company
and $176,000 payable by the Selling Stockholder.
(3) The Company has granted the Underwriters a 30-day option to purchase up to
an aggregate of 562,500 additional shares of Common Stock from the Company
at the Price to Public, less the Underwriting Discount, solely to cover
over-allotments, if any. If the Underwriters exercise such option in full,
the total Price to Public, Underwriting Discount and Proceeds to Company
will be $48,515,625, $2,425,781, and $16,699,219, respectively.
The shares of Common Stock are offered by the several Underwriters, subject to
prior sale, when, as and if delivered to and accepted by the Underwriters and
subject to the right of the Underwriters to reject any order in whole or in
part. It is expected that delivery of the shares of Common Stock will be made
against payment therefor on or about September 18, 1995, at the offices of
S.G.Warburg & Co. Inc., New York, New York.
S.G.WARBURG & CO. INC.
HOWARD, WEIL, LABOUISSE, FRIEDRICHS
INCORPORATED
PETRIE PARKMAN & CO.
3
GULF OF MEXICO LEASES
[MAP]
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK OF
THE COMPANY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
IN CONNECTION WITH THIS OFFERING, CERTAIN UNDERWRITERS AND SELLING GROUP MEMBERS
(IF ANY) OR THEIR RESPECTIVE AFFILIATES MAY ENGAGE IN PASSIVE MARKET MAKING
TRANSACTIONS IN THE COMMON STOCK ON NASDAQ IN ACCORDANCE WITH RULE 10B-6A UNDER
THE SECURITIES EXCHANGE ACT OF 1934. SEE "UNDERWRITING".
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PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information and the consolidated financial statements appearing elsewhere in
this Prospectus and in the documents incorporated by reference into this
Prospectus.
THE COMPANY
BUSINESS AND STRATEGY
The Company explores for, develops and produces oil and gas, principally in the
shallow waters of the Outer Continental Shelf ("OCS") of the Gulf of Mexico. The
Company's strategy is to expand its reserve base and production principally
through exploration and associated development drilling. The OCS of the Gulf of
Mexico is a well-established area of oil and gas production where the Company's
management and staff have both experience and expertise and where the
application of advances in 3-D and 2-D seismic and computer-aided exploration
technology is particularly suited. The Company participates mainly on a non-
operating basis, thereby minimizing staffing requirements and overhead costs. As
a non-operator, the Company generally preserves its rights through operating and
other agreements to influence and in many instances initiate exploration and
development projects in which it is participating. Exploration and development
activities are directed by a small, experienced technical team which makes use
of extensive in-house computer capabilities.
The Company identifies exploratory prospects by (i) integrating 3-D and 2-D
seismic technology with information about surrounding geological features and
(ii) high-grading prospects that exhibit "bright spot" seismic anomalies by
using extensive computer-aided geophysical modeling and amplitude versus offset
analysis. The Company significantly increased its inventory of exploration
acreage through successful participation in the 1994 and 1995 OCS Gulf of Mexico
Lease Sales and through the Smith Acquisition (described below), which was
completed in October 1994. The Company currently has an inventory of 23
identified prospects, of which 20 are defined by 3-D seismic. The Company
believes that its existing properties, including its substantial inventory of
undeveloped acreage and identified prospects, provide significant future
exploration and development potential. The Company expects to spend
approximately $30 million on exploratory and development drilling, leasehold and
seismic costs from September 1995 through the first quarter of 1996.
From January 1, 1992 to January 1, 1995, the Company achieved an 81% success
rate on 27 gross exploratory wells and a 100% success rate on 18 gross
development wells. As a result of the Company's exploration success, the
Company's proved reserves more than doubled from 36.0 Bcfe to 74.8 Bcfe over
this period. Over the same period, the Company replaced 353% of production at an
average reserve replacement cost, including finding and development costs and
provision for abandonment, of $0.75 per Mcfe.
As a result of the Company's successful development programs, production during
the first six months of 1995 increased by 175% compared with the first six
months of 1994, and revenue increased by 139% despite a decline in average
realized gas prices to $1.65 per Mcf from $2.20 per Mcf. Eighty percent of the
Company's production during the first half of 1995 was gas. The Company's
average production costs decreased in the first half of 1995 to $0.24 per Mcfe
as compared with $0.53 per Mcfe in the first half of 1994. The Company believes
that its production and overhead costs per unit of production are among the
lowest of independent oil and gas producers.
DEVELOPMENT ACTIVITIES
EAST CAMERON BLOCKS 331/332. The Company's largest development project is on
East Cameron Blocks 331/332. These blocks are located 98 miles offshore
Louisiana in 240 feet of water. The Company purchased an interest in these
blocks in 1991 for $100,000 and in 1992 proposed the first exploratory well,
which proved to be the discovery well for the field. The field commenced
production in October 1994, and a total of nine wells have now been completed.
During the first six months of 1995, East Cameron
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Blocks 331/332 produced an average of 12.7 MMcf of gas per day and 793 Bbls of
oil per day net to the Company's interest, accounting for approximately 45.6% of
the Company's production for the period. At January 1, 1995, the Company's net
proved reserves in East Cameron Blocks 331/332 were 35.5 Bcfe with a Discounted
Present Value of approximately $44.7 million. The Company believes that there is
further exploration potential on these blocks. The Company owns a 40% interest
in the shallower zone of Block 331 and a 20% interest in the deeper zone of both
blocks. Approximately 80% of the gross proved reserves are located in the deeper
zone. Samedan Oil Company, a subsidiary of Noble Affiliates, is the operator of
these blocks.
VERMILION BLOCK 203. The Company acquired a 50% working interest in this block
in October 1994 as a part of the Smith Acquisition. The block is located 56
miles offshore Louisiana in 100 feet of water and contains two separate geologic
plays (shallow and deep) on the flank of a piercement salt dome. Four wells, all
of which have encountered hydrocarbons, have been drilled to the shallow
formations on the block. These wells have all been temporarily suspended pending
completion operations and a jacket structure has been installed. Management
expects that a deck and production facilities with a planned capacity of up to
50 MMcf of gas per day will be installed beginning in the third quarter of 1995.
First production from the block is expected in late 1995 or early 1996. The
block is operated by The Houston Exploration Company ("Houston Exploration").
MUSTANG ISLAND BLOCK 858. The block is located 12 miles offshore Texas in
approximately 90 feet of water. The Company acquired a 17.5% working interest in
this block as part of the Smith Acquisition. At the time of the acquisition, one
successful well had been drilled and suspended on the block, and in 1995 the
Company participated in two further successful exploration wells on the block. A
recent test of certain deeper sands flowed at a non-commercial rate, and no
further activity is planned targeting these deeper horizons. However,
development activities in the shallower horizons are proceeding. A jacket
structure has been set and a deck and production facilities with a planned
capacity of up to 50 MMcf of gas per day are under construction. First
production from the development is expected in late 1995 or early 1996. Houston
Exploration is the operator of this block.
OTHER DEVELOPMENT PROJECTS. The Company recently participated in development
projects on Matagorda Block 710, Main Pass Blocks 300/301 and Ship Shoal Block
251. These development projects all resulted from successful exploration by the
Company and its partners between January 1993 and November 1994. First
production from these projects was achieved in the last quarter of 1994 and the
first quarter of 1995. During the first six months of 1995, average net
production to the Company from these three projects was 9.0 MMcf of gas per day
and 347 Bbls of oil per day, accounting for approximately 33.9% of the Company's
production in the period. See "Business -- Offshore Properties."
EXPLORATION ACTIVITIES
VERMILION BLOCK 203 (DEEP PROSPECT). The deep prospect on this block targets
stratigraphic sections that are defined by the Company's 3-D seismic and are
similar to those currently being developed by another operator on the adjacent
block to the north (Vermilion Block 200). The operator of Block 200 has to date
drilled six wells and is currently drilling a seventh well. The Company's Block
203 deep prospect is located on the south flank of the same salt dome that
extends into Block 200. The planned deep well on Block 203 is expected to test a
similar section to that being developed on Block 200. However, the deep target
in Block 203 is structurally separated by several faults from the Block 200
development. There can be no assurance that productive zones will be encountered
at deeper levels on Block 203. Drilling of this high-potential exploratory well
is now scheduled for the second half of 1995. Houston Exploration is the
operator of Block 203.
EAST CAMERON BLOCKS 349/350/355/356. The East Cameron Blocks 349/350/355/356
prospect area is located 110 miles offshore Louisiana in 300 feet of water. The
Company's interests in Blocks 349 and 355 were acquired in the 1994 Gulf of
Mexico Central Area Lease Sale while the Company's interest in Block 356 was
acquired in a property swap in 1994. The Company's interest in Block 350 was
acquired recently in the 1995 Gulf of Mexico Central Area Lease Sale. In May
1995, the Company participated in a
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new field discovery on East Cameron Block 356. The field is located 6 miles
south of the Company's East Cameron Block 331/332 complex and was identified on
the Company's 3-D seismic, which covers both areas. The discovery well was
drilled to a depth of 7,669 feet and logged two hydrocarbon bearing Pleistocene
sands. The well is suspended pending completion operations and delineation of
further prospective structures on this four-block complex. The proved reserves
in the blocks appear sufficient to justify a platform. The Company expects four
additional exploratory wells to be drilled prior to design and fabrication of
platform and production facilities. Further drilling is expected to commence
early in the fourth quarter of 1995. The Company owns a 37.5% working interest
in all four blocks, which are operated by Enserch Exploration, Inc. ("Enserch").
MAIN PASS BLOCK 262. This block, located 60 miles offshore Louisiana in 280
feet of water, is a recent acquisition from the 1995 Gulf of Mexico Central Area
Lease Sale. The prospect is defined by 3-D seismic surveys and previous drilling
activity. An exploratory well drilled in 1990 encountered productive sand in a
shallow Pliocene reservoir, but was plugged and abandoned due to an absence of
3-D seismic. Management believes that subsequently-acquired 3-D seismic over the
block accurately delineates the potential size of the accumulation. A recent
well drilled on the adjacent block to the south (Main Pass Block 281) has
significant gas production from this same Pliocene reservoir. However, there can
be no assurance that productive zones will be encountered in Block 262. The 3-D
seismic data over this reservoir has delineated two additional prospective
accumulations on Main Pass Block 262, and the Company plans to commence drilling
in the fourth quarter of 1995. The Company owns a 33.3% working interest in
Block 262, which is operated by Canadian Occidental Petroleum Ltd.
SOUTH TIMBALIER BLOCK 249. This block, located 55 miles offshore Louisiana in
180 feet of water, lies directly northwest of a recent discovery by another
operator on South Timbalier Block 265. Development plans announced for Block 265
include the installation of two platforms with processing capacity of 150 MMcf
per day and 10,000 Bbls per day. The Company has identified two prospects on its
South Timbalier Block 249 that target similar stratigraphic sections as those
discovered in Block 265. However, there can be no assurance that productive
zones will be encountered in Block 249. Exploratory drilling on Block 249 is
planned for the first quarter of 1996. The Company currently owns a 50% working
interest in and is operator of this block, but may reduce its interest prior to
drilling an exploration well.
EXPLORATION ACREAGE
Over the last two years, the Company has made a strategic commitment to increase
its ownership of acreage in the OCS of the Gulf of Mexico. The Company was
successful in acquiring interests in 10 blocks in the 1994 OCS Gulf of Mexico
Lease Sales and 13 blocks in the 1995 Gulf of Mexico Central Area Lease Sale.
The Company currently holds interests in 37 undeveloped lease blocks, with total
net undeveloped leasehold interests of 68,992 acres in the OCS of the Gulf of
Mexico. On this leasehold, the Company has to date identified 23 prospects, of
which 20 are covered by 3-D seismic. The Company has an inventory of over 65
blocks of 3-D seismic and over 110,000 miles of 2-D seismic. The Company plans
to drill up to eight exploration wells during the second half of 1995 and up to
12 exploration wells during 1996.
SELLING STOCKHOLDER
Phemus Corporation (the "Selling Stockholder") is an indirect wholly-owned
subsidiary of the President and Fellows of Harvard College and was the sole
stockholder of Smith Offshore Exploration Company II ("Smith"). In October 1994
the Company consummated an agreement with Smith and the Selling Stockholder,
whereby the Company acquired (the "Smith Acquisition") substantially all of the
oil and gas assets of Smith (the "Smith Assets") in exchange for shares of
Common Stock and the assumption of certain liabilities related to the Smith
Assets. At the closing of the Smith Acquisition, 3,500,000 shares of Common
Stock were issued to Smith and an additional 1,000,000 shares of Common Stock
were placed in escrow, to be distributed to Smith or revert to the Company based
on certain valuation criteria that were to be applied to the Smith Assets. Under
the terms of the Smith Acquisition agreement, unless the Smith Assets had a
value (based upon the defined criteria) as of June 30, 1995 equal to at least
$22,350,000, the Selling
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Stockholder was required to return the 1,000,000 shares of the Company Common
Stock held in escrow and to pay $3.9 million to the Company. Simultaneously with
the closing of the Smith Acquisition, the Selling Stockholder purchased
2,000,000 shares of the Company's Common Stock at $7.50 per share from the
former principal stockholder of the Company.
On the basis of preliminary engineering valuations of the Smith Assets, the
Selling Stockholder and the Company agreed that the Selling Stockholder would
return to the Company the 1,000,000 shares of Common Stock held in escrow and
pay $3.9 million in cash to the Company. The return of the escrow shares and the
cash payment to the Company were effected in August 1995. The rate of drilling
activity on the Smith Assets has lagged significantly behind expectations at the
time of the Smith Acquisition. A total of seven wells were drilled on the Smith
Assets from the acquisition date to June 30, 1995, of which six wells were
successful. Further wells remain to be drilled on the Smith Assets. Although the
consideration paid for the Smith Assets has been fixed, the Company will
continue to receive value from participation in any reserve additions which may
be achieved in the future.
Upon the consummation of the Offering, the Selling Stockholder is expected to
own 2,750,000 shares of Common Stock representing approximately 16.2% of the
Company's outstanding Common Stock (15.7% if the Underwriters' over-allotment
option is exercised in full).
THE OFFERING
Common Stock offered by the
Company........................... 1,000,000 shares(1)
Common Stock offered by the Selling
Stockholder....................... 2,750,000 shares
Common Stock to be outstanding after
the Offering...................... 16,983,150 shares(1)(2)
Use of proceeds..................... The net proceeds to the Company from
the Offering of approximately
$10,687,500 ($16,699,219 if the
over-allotment is exercised in full)
will be used for general corporate
purposes, including participation in
the drilling of exploratory wells and
development activities. The Company
will not receive any proceeds from the
sale of the shares of Common Stock
being offered by the Selling
Stockholder.
NASDAQ symbol....................... CEUS
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(1) Does not include up to 562,500 shares of Common Stock that may be sold by
the Company pursuant to the Underwriters' over-allotment option.
(2) Excludes 800,000 shares of Common Stock reserved for issuance under the
Company's stock option plans, including 480,000 shares of Common Stock
subject to currently outstanding options.
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SUMMARY OIL AND GAS DATA
AS OF JANUARY 1,
---------------------------
1993 1994 1995
------- ------- -------
RESERVE DATA(1):
Net proved reserves:
Gas (MMcf)..................................................... 46,948 52,882 60,883
Oil and condensate (MBbls)..................................... 1,318 2,143 2,312
Total (MMcfe).......................................... 54,858 65,741 74,755
Pre-tax Discounted Present Value (in thousands).................. $55,503 $79,156 $78,844
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------ ---------------
1992 1993 1994 1994 1995
------ ------ ------ ------ ------
OPERATING DATA:
Net production:
Gas (MMcf)......................................... 6,159 5,226 3,940 2,070 5,257
Oil (MBbls)........................................ 130 116 100 54 220
Total (MMcfe).............................. 6,941 5,923 4,541 2,392 6,577
Average sales price:
Gas ($/Mcf)(2)..................................... $ 1.84 $ 2.18 $ 1.99 $ 2.20 $ 1.65
Oil ($/Bbl)........................................ $18.69 $16.04 $14.35 $13.19 $18.28
Average production cost
($/Mcfe)(3)........................................ $ 0.54 $ 0.65 $ 0.50 $ 0.53 $ 0.24
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(1) Estimates of the Company's net proved oil and gas reserves and related
revenue estimates as of January 1, 1993, 1994 and 1995 were prepared by the
Company and reviewed by Ryder Scott Company ("Ryder Scott"). See
"Investment Considerations -- Reliance on Estimates of Proved Reserves and
Future Net Revenues" and "Business -- Oil and Gas Reserves."
(2) Includes natural gas liquids.
(3) Includes direct lifting costs (labor, repairs and maintenance, materials and
supplies) and the administrative costs of production offices, insurance and
property and severance taxes.
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SUMMARY CONSOLIDATED FINANCIAL DATA
The following table sets forth certain financial data for the Company as of and
for each of the periods indicated. The following data should be read in
conjunction with "Selected Consolidated Financial Data" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
contained elsewhere in this Prospectus. Financial data as of and for the years
ended December 31, 1992, 1993 and 1994 is derived from the audited consolidated
financial statements of the Company.
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
----------------------------- ------------------
1992 1993 1994 1994 1995
------- -------- -------- ------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENTS OF OPERATIONS DATA:
Revenues:
Oil and gas................................ $14,035 $ 13,490 $ 9,494 $ 5,355 $ 12,808
Other...................................... 60 59 206 26 75
------- -------- -------- ------- -------
Total revenues..................... 14,095 13,549 9,700 5,381 12,883
Expenses:
Lease operating expenses and production
taxes................................... 3,766 3,826 2,274 1,278 1,563
Depreciation, depletion and amortization... 6,792 5,654 4,328 2,318 6,772
Administrative expense..................... 774 1,266 1,330 739 820
Interest................................... 1,193 1,045 1,114 445 1,357
------- -------- -------- ------- -------
Total expenses..................... 12,525 11,791 9,046 4,780 10,512
------- -------- -------- ------- -------
Income from operations....................... 1,570 1,758 654 601 2,371
Minority interest in net loss of Omni........ 245 -- -- -- --
Extraordinary item -- loss on early
extinguishment of debt..................... -- (284) -- -- --
------- -------- -------- ------- -------
Net income................................... $ 1,815 $ 1,474 $ 654 $ 601 $ 2,371
======= ======== ======== ======= =======
Net income per common and common equivalent
share...................................... $ 0.18 $ 0.13 $ 0.05 $ 0.05 $ 0.15
======= ======== ======== ======= =======
Weighted average common and common equivalent
shares outstanding......................... 10,048 11,260 13,259 12,463 15,970
======= ======== ======== ======= =======
STATEMENTS OF CASH FLOWS DATA:
Net cash provided by operating activities.... $ 8,472 $ 8,383 $ 6,353 $ 3,144 $ 4,710
Net cash provided by (used in) investing
activities:
Exploration, development and acquisition
expenditures............................ (7,702) (10,093) (20,782) (6,407) (17,066)
Other...................................... 128 574 3,574 160 1,680
Net cash provided by (used in) financing
activities................................. (212) 564 12,694 3,269 10,047
AS OF DECEMBER 31, AS OF
----------------------------- JUNE 30,
1992 1993 1994 1995
------- ------- ------- --------
(IN THOUSANDS)
BALANCE SHEET DATA:
Total assets.......................................... $46,100 $49,628 $89,181 $101,660
Working capital (deficit)............................. (1,029) 877 514 3,452
Advances from Cairn Energy PLC, noncurrent............ 2,609 -- -- --
Long-term debt, less current maturities............... 15,917 9,600 23,500 29,312
Stockholders' equity.................................. 22,893 37,890 61,798 64,271
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RISK FACTORS
In addition to other information in this Prospectus, the following factors
should be considered carefully in evaluating the Company and its business before
purchasing shares of Common Stock offered hereby.
ABILITY TO DISCOVER ADDITIONAL RESERVES AND DEVELOP EXISTING PROPERTIES
The Company's future success depends on its ability to find or acquire
additional oil and gas reserves that are economically recoverable. Except to the
extent that the Company conducts successful exploration or development
activities or acquires properties containing proved reserves, the Company's
proved reserves will generally decline as reserves are produced. There can be no
assurance that the Company will be able to discover additional commercial
quantities of oil and gas or that the Company will have success drilling
productive wells or acquiring properties at low finding costs. See
"Business -- Oil and Gas Reserves" and "Business -- Exploration Activity." As of
January 1, 1995, approximately 25% of the Company's proved reserves were
undeveloped and required development activities consisting primarily of
development drilling and recompletions. There can be no certainty regarding the
results of developing the Company's reserves.
ADEQUACY OF CASH FLOW
The Company believes that cash flows from operations combined with borrowings
under its credit facility will be sufficient to cover its currently planned
exploration and development expenditures. If substantially all the Company's
currently scheduled exploration prospects are successful, the Company will need
additional funds in order to conduct necessary development activities. No
assurance can be given that the Company will be able to obtain such funds if
needed or that it can obtain any such funds on favorable terms. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Capital Resources and Liquidity." If the Company cannot obtain
sufficient development funds, it may be required to reduce its interest in such
properties or to forego developing such reserves. In addition, the Company may
not be able to control development activities or the associated costs with
respect to properties operated by other parties.
RISK OF OIL AND GAS OPERATIONS
The Company's operations are subject to all the risks normally incident to the
operation and development of oil and gas properties and the drilling of oil and
gas wells, including encountering unexpected formations or pressures, blowouts,
cratering and fires, any of which could result in personal injury, loss of life,
environmental damage and other damage to the properties of the Company or
others. In addition, because the Company occasionally acquires interests in oil
and gas properties that have previously been operated by others, the Company may
be liable for any damage or pollution caused by any prior operations on such oil
and gas fields. See "Business -- Regulation -- Environmental." Moreover,
offshore operations are subject to a variety of operating risks peculiar to the
marine environment, such as hurricanes or other adverse weather conditions.
Offshore operations are also subject to more extensive governmental regulation
(including regulations that may, in certain circumstances, impose absolute
liability for environmental damage) and interruption or termination of business
activities by government authorities based on environmental or other
considerations. In accordance with customary industry practice, the Company is
not fully insured against these risks, nor are all such risks insurable.
Accordingly, there can be no assurance that the insurance the Company maintains
will be adequate to cover any losses or exposure for liability. See "Business --
Operational Hazards and Insurance."
INDUSTRY CONDITIONS; IMPACT ON THE COMPANY'S PROFITABILITY
The Company's revenues and profitability are substantially dependent on
prevailing prices for oil and gas. Historically, oil and gas prices and markets
have been volatile, and they are likely to continue to be volatile. Oil and gas
prices may fluctuate widely in response to relatively minor changes in the
supply and demand for oil and gas, market uncertainty and a variety of
additional factors that are beyond the Company's control. These factors may
include political conditions in the Middle East and elsewhere, the domestic and
foreign
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supply of oil and gas, the level of consumer demand, weather conditions,
government regulations, the price and availability of alternative fuels and
overall economic conditions. In addition, various other factors may adversely
affect the Company's ability to market its oil and gas production, including the
availability and capacity of gas gathering systems and pipelines, the effect of
federal and state regulation on production and transportation, general economic
conditions and changes in supply and demand.
Declines in oil and gas prices might, under certain circumstances, require a
write-down of the book value of the Company's oil and gas properties. If such
declines were severe enough, they could result in a reduction in the Company's
borrowing base under its credit facility, thereby potentially requiring the
Company to sell some of its properties under unfavorable market conditions or
seek additional equity capital. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Capital Resources and
Liquidity."
RELIANCE ON ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUES
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 in this Prospectus represent only estimates, and actual
quantities of oil and gas may differ considerably from the amounts set forth in
this Prospectus. In addition, the estimates of future net revenues from the
Company's proved reserves and the present value thereof are based on certain
assumptions about future production levels, prices and costs that may not prove
to be correct over time. See "Business -- Oil and Gas Reserves."
GOVERNMENT REGULATION
The Company's business is subject to federal, state and local laws and
regulations relating to the development, production, marketing and transmission
of oil and gas, as well as environmental and safety laws. Such laws and
regulations may impose absolute liability for environmental damage. The
requirements imposed by such laws and regulations are frequently changed, and
consequently, the Company cannot predict the ultimate cost of compliance with
such requirements. There is no assurance that such laws and regulations will not
adversely affect the Company's exploration for, or the production and marketing
of, oil and gas. See "Business -- Regulation."
COMPETITION
The exploration for and production of oil and natural gas is highly competitive.
In seeking to obtain desirable properties, leases and exploration prospects, the
Company faces competition from both major and independent oil and natural gas
companies, as well as from numerous individuals and drilling programs. Extensive
competition also exists in the market for natural gas produced by the Company.
Many of these competitors have financial and other resources substantially in
excess of those available to the Company and, accordingly, may be better
positioned to acquire and exploit prospects, hire personnel and market
production. In addition, many of the Company's larger competitors may be better
able to respond to factors that affect the demand for oil and natural gas
production such as changes in worldwide oil and natural gas prices and levels of
production, the cost and availability of alternative fuels and the application
of government regulations. See "Business -- Competition."
DEPENDENCE ON KEY PERSONNEL
To date, acquisition, exploration and development activities have depended
primarily upon the efforts of Michael R. Gilbert and Robert P. Murphy, the
Company's President and Vice President -- Exploration, respectively. While Mr.
Gilbert and Mr. Murphy are employed under contractual arrangements currently
extending through December 1997, the loss of either of them potentially could
have a material adverse effect on the Company's business and results of
operations. See "Management."
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UNITED STATES INCOME TAX; NON-UNITED STATES STOCKHOLDERS
The Company is, and likely will continue to be, a United States Real Property
Holding Corporation under Section 897 of the Internal Revenue Code of 1986, as
amended (the "Code"). Accordingly, a nonresident alien individual or foreign
corporation may be subject to United States income tax on any disposition of
Common Stock if such person beneficially owned more than 5% of the Common Stock
outstanding at any time during the five-year period ending on the date of such
disposition. United States income tax withholding obligations may apply to such
dispositions.
NON-OPERATOR STATUS
The Company generally is not the operator of the properties in which it owns
interests and generally does not directly control the exploration and
development operations or the associated costs of such operations conducted on
its properties. The Company seeks where possible, however, to preserve its
rights to propose exploration and development projects through operating and
other agreements giving it the ability to influence and in some instances
initiate exploration and development projects in which it is participating.
SHARES ELIGIBLE FOR FUTURE SALE
All outstanding shares of Common Stock, other than the shares held by the
Selling Stockholder and shares held by certain directors and officers of the
Company as of September 13, 1995, will be eligible for sale without restriction
under the Securities Act of 1933, as amended (the "Securities Act"). The
2,750,000 shares of Common Stock to be owned by the Selling Stockholder after
the Offering and an aggregate of 470,000 shares held by and issuable to
directors and officers (including 274,500 shares issuable upon exercise of
options exercisable within 60 days of September 13, 1995) will be eligible for
sale subject to the volume limitations of Rule 144 under the Securities Act. The
2,750,000 shares of Common Stock owned by the Selling Stockholder after the
Offering will not be eligible for sale under Rule 144 under the Securities Act
until October 10, 1996, two years after the closing date of the Smith
Acquisition.
As of September 13, 1995, options exercisable for an aggregate of 480,000 shares
of Common Stock were outstanding under the Company's 1993 Stock Option Plan and
Directors Stock Option Plan, of which an aggregate of 284,500 are exercisable
within 60 days of such date. See "Management -- 1993 Director's Stock Option
Plan" and "1993 Stock Option Plan." The Company has an effective registration
statement on Form S-8 under the Securities Act with respect to all shares
issuable under both plans and, accordingly, all such shares will be freely
tradeable when issued, subject to the volume limitations of Rule 144.
The Selling Stockholder is entitled, pursuant to a registration rights agreement
(the "Phemus Registration Rights Agreement"), to certain rights to have its
shares of Common Stock registered by the Company under the Securities Act for
offer and sale to the public. The Registration Statement, of which this
Prospectus is a part, has been filed in response to the Selling Stockholder
exercising a demand registration right under the Phemus Registration Rights
Agreement. See "Shares Eligible for Future Sale." The Selling Stockholder and
the Company and its officers, however, have agreed not to offer, sell, contract
to sell or otherwise dispose of any Common Stock for a period of 180 days after
the date of this Prospectus, other than transfers to wholly-owned affiliates,
without the prior written consent of S.G.Warburg & Co. Inc. No prediction can be
made as to the effect, if any, that future sales of shares, or the availability
of shares for future sales, will have on the market price of the Common Stock
prevailing from time to time. Sales of substantial amounts of Common Stock, or
the perception that such sales could occur, may adversely affect prevailing
market prices for the Common Stock. See "Principal Stockholders," "Selling
Stockholder," "Shares Eligible for Future Sale," "Description of Capital Stock"
and "Underwriting."
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THE COMPANY
The registrant, Cairn Energy USA, Inc., a Delaware corporation (the "Company"),
was incorporated on May 5, 1981 in Delaware as "Omni Exploration, Inc." On
September 29, 1992, Cairn Energy USA, Inc., an oil and gas exploration and
development company and wholly-owned subsidiary of Cairn Energy PLC, a Scottish
corporation, merged with and into the registrant with the registrant being the
survivor (the "Merger"). Pursuant to the Merger, the registrant changed its name
to "Cairn Energy USA, Inc." As used in this Prospectus, "Omni" refers to Omni
Exploration, Inc. prior to the Merger, "Cairn USA" refers to the corporation
prior to the Merger and the "Company" refers to the surviving corporation in the
Merger. Because Omni was the reporting company under the federal securities laws
and the surviving corporation in the Merger (but was not the survivor for
accounting purposes), all references to the Company prior to September 29, 1992
are to Omni, except for financial data and oil and gas information. As a result
of the accounting treatment of the Merger, all financial data and oil and gas
information of the Company prior to September 29, 1992 are the historical
financial data and oil and gas information of Cairn USA.
The Company's principal executive offices are located at 8235 Douglas Avenue,
Suite 1221, Dallas, Texas 75225 and its telephone number is (214) 369-0316.
USE OF PROCEEDS
The net proceeds to the Company from the Offering, after deducting estimated
expenses payable by the Company in connection with the Offering, of
approximately $10,623,500 ($16,635,219 if the over-allotment is exercised in
full) will be used for general corporate purposes, including participation in
the drilling of exploratory wells and development activities. The net proceeds
to the Selling Stockholder from the Offering, after deducting estimated expenses
payable by the Selling Stockholder in connection with the Offering, are expected
to be $29,214,625, and the Company will not receive any of such proceeds.
PRICE RANGE OF COMMON STOCK
The Common Stock is traded on the NNM under the symbol "CEUS." The following
table sets forth the range of quarterly high and low bid and ask prices for the
Common Stock from January 1, 1993 to July 29, 1993 and the high and low sales
prices for the Common Stock from July 30, 1993 to September 13, 1995.
BID ASK
-------------- --------------
YEAR HIGH LOW HIGH LOW
----------------------------------------------------------- ---- --- ---- ---
1993
First Quarter.............................................. 2 3/4 2 1/2 3 1/2 3 1/2
Second Quarter............................................. 5 1/2 2 3/4 6 1/4 3 3/4
Third Quarter (through July 29, 1993)...................... 5 1/2 4 3/4 6 1/4 5 1/2
HIGH LOW
---- ---
1993
Third Quarter (from July 30, 1993)........................................... $7 $4 3/4
Fourth Quarter............................................................... 6 1/2 4 15/16
1994
First Quarter................................................................ 7 5
Second Quarter............................................................... 8 1/4 5 3/4
Third Quarter................................................................ 8 1/4 7 1/4
Fourth Quarter............................................................... 8 3/8 6 3/4
1995
First Quarter................................................................ 8 3/4 7 3/8
Second Quarter............................................................... 11 8 1/2
Third Quarter (through September 13, 1995)................................... 12 10 3/8
The bid and ask prices for the Common Stock from May 11, 1993 to July 29, 1993
are based on bid and ask prices for the Common Stock as reported by the NASDAQ
Small-Cap Market. The bid and ask prices for
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the Common Stock from January 1, 1993 through May 10, 1993 were reported on the
OTC Bulletin Board. Since July 30, 1993, the Common Stock has traded on the NNM.
The high and low sales prices for the Common Stock after July 29, 1993 have been
reported by the NNM. The inter-dealer quotations prior to July 30, 1993 did not
necessarily represent actual transactions, and did not reflect any markups,
markdowns or commissions.
As of the date of this Prospectus the Company had 15,983,150 outstanding shares
of Common Stock held by 676 stockholders of record.
DIVIDEND POLICY
The Company's policy is to retain its earnings to support the growth of the
Company's business. Accordingly, the board of directors of the Company (the
"Board of Directors") has never declared dividends on the Common Stock and does
not plan to do so in the foreseeable future. Pursuant to the terms of the
Company's credit facility (the "INCC Credit Agreement") with Internationale
Nederlanden (U.S.) Capital Corporation ("INCC") and MeesPierson, N.V.
("MeesPierson"), the Company is not permitted to pay or declare any cash or
property dividends or otherwise make any distribution of capital. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and Note 3 of Notes to Consolidated Financial Statements.
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CAPITALIZATION
The following table sets forth the cash and cash equivalents and capitalization
of the Company as of June 30, 1995, as well as the pro forma cash and cash
equivalents and capitalization giving effect to the issuance of the 1,000,000
shares of Common Stock offered by the Company hereby (at an offering price of
$11.25 per share before deducting underwriting discounts and estimated offering
expenses) and application of the net proceeds therefrom. Estimated offering
expenses of $64,000 are reflected as a reduction of additional paid-in capital.
JUNE 30, 1995
--------------------
ACTUAL PRO FORMA
-------- ---------
(IN THOUSANDS)
Cash and cash equivalents............................................... $ 1,553 $ 12,177
======== =========
Long-term debt, less current portion.................................... $ 29,312 $ 29,312
Stockholders' equity:
Preferred Stock, $.01 par value -- 5,000,000 shares authorized; no
shares issued and outstanding historical and pro forma............. -- --
Common Stock, $.01 par value -- 30,000,000 shares authorized;
15,983,150 shares issued and outstanding historical; 16,983,150
shares issued and outstanding pro forma(1)......................... 160 170
Additional paid-in capital............................................ 78,085 88,699
Accumulated deficit................................................... (13,974) (13,974)
-------- ---------
Total stockholders' equity.................................... 64,271 74,895
-------- ---------
Total capitalization.......................................... $ 93,583 $ 104,207
======== =========
---------------
(1) Excludes 800,000 shares of Common Stock reserved for issuance under the
Company's stock option plans, including 480,000 shares subject to options
outstanding as of June 30, 1995. See "Shares Eligible for Future Sale."
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SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth consolidated financial data for the Company as of
the date and for the periods indicated.
The consolidated financial data as of and for the years ended December 31, 1990,
1991, 1992, 1993 and 1994 have been derived from the audited consolidated
financial statements of the Company. The financial data as of and for the
six-month periods ended June 30, 1994 and 1995 are derived from unaudited
consolidated financial statements of the Company. The unaudited consolidated
financial statements include all adjustments, consisting of normal recurring
accruals, which the Company considers necessary for a fair presentation of its
financial position as of such dates and the results of operations and cash flows
for such periods. Operating results for the six months ended June 30, 1995 are
not necessarily indicative of the results that may be expected for the entire
year ending December 31, 1995.
The selected financial data should be read in conjunction with the consolidated
financial statements of the Company, Management's Discussion and Analysis of
Financial Condition and Results of Operations and other financial information of
the Company included elsewhere herein.
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SELECTED CONSOLIDATED FINANCIAL DATA
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
---------------------------------------------------------- --------------------
1990 1991 1992 1993 1994 1994 1995
------- -------- ------- -------- -------- ------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENTS OF OPERATIONS DATA:
Revenues:
Oil and gas........................ $10,875 $ 11,443 $14,035 $ 13,490 $ 9,494 $ 5,355 $ 12,808
Other revenue...................... 59 94 60 59 206 26 75
------- -------- ------- -------- -------- ------- --------
Total revenues............... 10,934 11,537 14,095 13,549 9,700 5,381 12,883
Expenses:
Lease operating expenses and
production taxes................. 1,946 2,840 3,766 3,826 2,274 1,278 1,563
Depreciation, depletion and
amortization(1).................. 9,365 15,142 6,792 5,654 4,328 2,318 6,772
Administrative expense............. 694 951 774 1,266 1,330 739 820
Interest........................... 3,558 2,853 1,193 1,045 1,114 445 1,357
------- -------- ------- -------- -------- ------- --------
Total expenses............... 15,563 21,786 12,525 11,791 9,046 4,780 10,512
------- -------- ------- -------- -------- ------- --------
Income (loss) from operations........ (4,629) (10,249) 1,570 1,758 654 601 2,371
------- -------- ------- -------- -------- ------- --------
Minority interest in net loss of
Omni............................... -- -- 245 -- -- -- --
Extraordinary item -- loss on early
extinguishment of debt............. -- -- -- (284) -- -- --
------- -------- ------- -------- -------- ------- --------
Net income (loss).................... $(4,629) $(10,249) $ 1,815 $ 1,474 $ 654 $ 601 $ 2,371
======= ======== ======= ======== ======== ======= ========
Net income (loss) per common and
common equivalent share............ $ (1.16) $ (1.28) $ 0.18 $ 0.13 $ 0.05 $ 0.05 $ 0.15
======= ======== ======= ======== ======== ======= ========
Weighted average common and common
equivalent shares outstanding...... 3,996 7,992 10,048 11,260 13,259 12,463 15,970
======= ======== ======= ======== ======== ======= ========
STATEMENTS OF CASH FLOWS DATA:
Net cash provided by operating
activities....................... $ 5,089 $ 6,088 $ 8,472 $ 8,383 $ 6,353 $ 3,144 $ 4,710
Net cash provided by (used in)
investing activities:
Exploration, development and
acquisition expenditures......... (7,954) (6,211) (7,702) (10,093) (20,782) (6,407) (17,066)
Other.............................. 1,524 580 128 574 3,574 160 1,680
Net cash provided by (used in)
financing activities............... (788) (400) (212) 564 12,694 3,269 10,047
AS OF DECEMBER 31, AS OF
------------------------------------------------------- JUNE 30,
1990 1991 1992 1993 1994 1995
------- ------- ------- ------- ------- --------
(IN THOUSANDS)
BALANCE SHEET DATA:
Total assets....................................... $52,933 $43,503 $46,100 $49,628 $89,181 $101,660
Working capital (deficit).......................... 1,059 1,525 (1,029) 877 514 3,452
Advances from Cairn Energy PLC, noncurrent......... 1,104 2,609 2,609 -- -- --
Long-term debt, less current maturities............ 31,800 19,000 15,917 9,600 23,500 29,312
Stockholders' equity............................... 18,310 20,461 22,893 37,890 61,798 64,271
---------------
(1) The Company recorded additional depreciation, depletion and amortization
expense of $1.0 million and $5.6 million for the year ended December 31,
1990 and 1991, respectively, to reduce the carrying value of oil and gas
properties to the capitalized cost ceiling required under the full-cost
method of accounting.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of the consolidated results of operations and financial
condition of the Company for each of the years in the three-year period ended
December 31, 1994 and for the six-month periods ended June 30, 1995 and 1994
should be read in conjunction with the Company's Consolidated Financial
Statements and related notes thereto included elsewhere herein.
GENERAL
The Company follows the full-cost method of accounting for its investments in
oil and gas properties. The Company capitalizes all acquisition, exploration and
development costs incurred. Proceeds from sales of oil and gas properties are
credited to the full-cost pool. Capitalized costs of oil and gas properties are
amortized on an overall unit-of-production method using proved oil and gas
reserves as determined by independent petroleum engineers. Costs amortized
include all capitalized costs (less accumulated amortization); the estimated
future expenditures (based on current costs) to be incurred in developing proved
reserves; and estimated dismantlement, restoration, and abandonment costs. See
Note 2 of Notes to the Company's Consolidated Financial Statements.
RESULTS OF OPERATIONS
Six Months ended June 30, 1995 Compared with Six Months ended June 30, 1994
Revenues. Total revenues increased $7.5 million (139%) to $12.9 million for the
six months ended June 30, 1995, from $5.4 million for the six months ended June
30, 1994. The primary reason for the increase was new production from the
Company's interest in East Cameron Blocks 331/332, Matagorda Block 710 and Ship
Shoal Block 251 coupled with higher oil prices. Lower gas prices partially
offset the increased revenues from production.
Expenses. Total expenses increased $5.7 million (120%) to $10.5 million for the
six months ended June 30, 1995 from $4.8 million for the six months ended June
30, 1994. An increase in depreciation, depletion and amortization ("DD&A") is
the primary reason for the increase in expenses. DD&A increased $4.5 million
(192%) to $6.8 million for the six months ended June 30, 1995 from $2.3 million
for the same period in 1994 due to increased production coupled with an increase
in the depletion rate. Interest expense increased by $912,000 (205%) to $1.4
million for the six months ended June 30, 1995 from $445,000 for the six months
ended June 30, 1994 due to increased borrowing and higher average interest
rates. Lease operating expenses and production taxes increased $285,000 (22%) to
$1.6 million for the six months ended June 30, 1995 from $1.3 million for the
same period in 1994. Lease operating expenses increased because of increased
production. Reflected in the 1994 lease operating expenses amount are expenses
related to the Texas Panhandle properties that were sold in August 1994.
Production costs on a per unit basis decreased significantly because East
Cameron Blocks 331/332, Matagorda Block 710 and Ship Shoal Block 251 all have a
low per unit operating cost, while the Texas Panhandle properties sold in August
1994 had a high per unit operating cost. Administrative expenses increased
$81,000 (11%) to $820,000 for the six months ended June 30, 1995 from $739,000
for the same period in 1994 due primarily to an increase in legal, salary and
printing expenses partially offset by increased overhead capitalization relating
to technical staff associated with exploration activity.
Net Income. Net income increased $1.8 million (299%), or $0.10 per share to
$2.4 million, or $0.15 per share for the six months ended June 30, 1995 from
$601,000, or $0.05 per share for the same period in 1994. The primary reason for
the increase was new production.
1994 Compared with 1993
Revenues. Total revenues decreased $3.8 million (28%) to $9.7 million for 1994
from $13.5 million for 1993. The decrease in revenues was due principally to a
natural decline in production from the Company's
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properties coupled with lower product prices, and also to the sale of
non-strategic properties in both 1993 and 1994.
Expenses. Total expenses decreased $2.7 million (23%) to $9.1 million for 1994
from $11.8 million for 1993. Lease operating costs and production taxes
decreased $1.5 million (41%) to $2.3 million for 1994 compared with $3.8 million
for 1993 due primarily to reduced transportation fees on Galveston Blocks
343/363 coupled with the sale of certain producing properties whose associated
costs are reflected in 1993. Depreciation, depletion and amortization decreased
$1.3 million (23%) to $4.4 million for 1994 from $5.7 million for 1993. This
decrease was primarily due to lower production volumes in 1994. There was only a
nominal increase in general and administrative expenses due mainly to an
increase in the number of technical personnel. There was also a nominal increase
in interest expense due to an increase in outstanding debt.
Net Income. Net income of $654,000, or $0.05 per share, was generated for 1994,
compared with $1.5 million, or $0.13 per share, after an extraordinary charge of
$284,000, or $0.03 per share, in 1993. The extraordinary charge in 1993 was in
connection with the write-off of unamortized issuance costs attributable to the
Company's prior credit facility. The decrease in net income was primarily the
result of the decrease in revenues due to decreased production, partially offset
by decreased production and depletion expenses.
1993 Compared with 1992
Revenues. Total revenues decreased $0.6 million (4%) to $13.5 million for 1993
from $14.1 million for 1992. Revenues decreased primarily as a result of
decreases in the price for oil coupled with lower oil production. Although gas
production also decreased in 1993, the increase in the price for gas was
sufficient to maintain gas revenues at approximately the 1992 level.
Expenses. Total expenses decreased $0.7 million (6%) to $11.8 million for 1993
from $12.5 million for 1992. The decrease in expenses resulted primarily from a
reduction in depreciation, depletion and amortization expense of $1.1 million
(17%) to $5.7 million for 1993 from $6.8 million for 1992. This decrease was
primarily due to new reserve additions in 1993 that decreased depletion expense
for 1993. There was only a nominal increase in lease operating costs and
production taxes in 1993 compared to 1992 primarily due to well workovers.
General and administrative expenses increased $0.5 million (65%) to $1.3 million
in 1993 from $0.8 million in 1992. Contributing factors to this increase were
Delaware franchise taxes resulting from the Merger, increased payroll costs
associated with incentive bonuses related to increased reserves and employment
agreements for key personnel and the Company's public offering of Common Stock.
Expenses were also incurred for the first time in 1993 for stockholder related
costs such as printings of the annual and quarterly reports. Interest expense
was less in 1993 than 1992 by $0.2 million, or 15%, primarily due to lower
interest rates and the reduction of outstanding debt following the public
offering of Common Stock.
Net Income. Net income of $1.5 million, or $0.13 per share, after an
extraordinary charge of $284,000, or $0.03 per share, was generated for 1993,
compared to $1.8 million, or $0.18 per share, in 1992. The extraordinary charge
was in connection with the write-off of unamortized costs attributable to the
Company's prior credit facility. The decrease in net income was principally the
result of the decrease in revenues and the increase in general and
administrative expenses, partially offset by a decrease in depletion expense.
CAPITAL RESOURCES AND LIQUIDITY
At June 30, 1995, the Company had existing cash and cash investments of $1.6
million. Net cash provided by operating activities was $4.7 million for the six
months ended June 30, 1995 compared with $3.1 million for the same period in
1994. The primary reason for this increase in cash provided by operating
activities was higher results of operations (or earnings before depreciation,
depletion and amortization) partially offset by increased working capital
requirements. Net cash used in investing activities for the six months ended
June 30, 1995 was $15.4 million compared with $6.2 million for the same period
in 1994. This increase was principally due to expenditures for exploration and
development prospects.
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Net cash provided by financing activities for the first six months of 1995 was
$10.0 million compared with $3.3 million for the same period in 1994. The cash
provided by financing activities for the period consisted of borrowings under
the INCC Credit Agreement and the exercise of stock options, partially reduced
by financing costs.
At December 31, 1994, the Company had existing cash and cash investments of $2.2
million. Net cash provided by operating activities was $6.4 million for 1994,
compared with $8.4 million for 1993. The primary reason for this decrease in
cash provided by operating activities was lower results of operations (or
earnings before depreciation, depletion and amortization) offset by reduced
working capital requirements. Net cash used in investing activities for 1994 was
$17.2 million compared with $9.5 million in 1993. This increase was principally
due to expenditures for exploration and development prospects coupled with the
expenses related to the Smith Acquisition, partially offset by the proceeds from
the sales of certain producing properties.
Net cash provided by financing activities for 1994 was $12.7 million compared
with $0.6 million in 1993. The cash provided by financing activities during 1994
consisted of borrowings under the Company's credit facility, partially reduced
by financing costs. During 1993, the Company used net proceeds of a public
offering of Common Stock primarily to reduce outstanding indebtedness and redeem
preferred stock.
The Company's average net production for the quarter ended June 30, 1995 rose to
approximately 33.0 MMcf of gas per day and 1,604 Bbls of oil and condensate per
day compared with average per day production during the same quarter in 1994 of
10.2 MMcf of gas and 290 Bbls of oil and condensate. The average net production
for the six months ended June 30, 1995 was 29.0 MMcf of gas per day and 1,216
Bbls of oil and condensate per day compared with average per day production
during the same period in 1994 of 11.4 MMcf of gas and 296 Bbls of oil and
condensate.
The Company, together with various partners, bid on eighteen blocks at the 1995
Gulf of Mexico Central Area Lease Sale and were awarded 13 blocks. The Company's
net share of the lease bonuses paid on the blocks was $2.5 million. This amount
is consistent with the Company's expected expenditures for the lease sale. The
expenditures for the lease sale have been funded from cash flow from operations
and from amounts available under the Company's credit facility.
In June of 1995 the Company sold most of the properties which it owned in Texas,
Oklahoma, Kansas and Louisiana for $1.77 million. At January 1, 1995, the
properties had reserves of approximately 123 MBbls of oil and 2.1 Bcf of gas and
had a Discounted Present Value of $2.03 million. Proceeds from this transaction
were credited to the full-cost pool, resulting in no recognition of gain or loss
for accounting purposes.
In connection with the Smith Acquisition, the Company granted to the Selling
Stockholder certain demand and piggyback registration rights that generally are
at the Company's expense.
In general, because the Company's oil and gas reserves are depleted by
production, the success of its business strategy is dependent on a continuous
exploration and development program. Therefore, the Company's capital
requirements relate primarily to the acquisition of undeveloped leasehold
acreage and exploration and development activities. The Company's operating
needs and capital spending programs have been funded by borrowings under its
bank credit facilities, proceeds of a public offering of its Common Stock and
cash flow from operations. The Smith Acquisition is expected to result in
significant additional capital expenditures for exploration and development
activities for the remainder of 1995. The Company expects to continue with an
active exploration program and to drill up to eight exploration wells in the
second half of 1995. The Company expects capital expenditures during 1995 to
total approximately $43 million, which includes additional expenditures in the
amount of $3 million that have been accelerated as a result of the additional
funds to be raised in the Offering. At June 30, 1995, the Company's capital
resources consisted primarily of available borrowing capacity under the INCC
Credit Agreement and cash flow from operations.
Management believes that cash flow from operations along with the amount
available under the INCC Credit Agreement, the amount of $3.9 million received
in August 1995 from the Selling Stockholder in connection with the Smith
Acquisition and the proceeds of the Offering will be sufficient to finance the
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currently planned exploration and development expenditures. However, if the
Company is successful in substantially all of its currently scheduled
exploration prospects, additional funds may be required. Any resulting lack of
sufficient capital may require the Company to raise additional capital in public
or private equity or debt markets, to reduce its interest in such properties or
to forego developing such reserves. In addition, the Company does not act as
operator with respect to any of its properties. The Company may not be able to
control the development activities or the associated costs with respect to
properties operated by other parties.
Credit Facility. The Company has a $50 million credit facility (the "INCC Credit
Agreement") with INCC and MeesPierson, under which the current borrowing base is
$45 million. The INCC Credit Agreement is secured by substantially all of the
Company's assets. It contains financial covenants which require the Company to
maintain a ratio of current assets to current liabilities (excluding the current
portion of related debt) of no less than 1.0 to 1.0 and a tangible net worth of
not less than $40 million. The Company is currently in compliance with such
financial covenants. Outstanding borrowings accrue interest at either INCC's
fluctuating base rate or INCC's reserve adjusted Eurodollar rate plus 1.50%, at
the Company's option. On March 31, 1996, the borrowings outstanding under this
facility will be converted to a term loan that requires various quarterly
principal payments through December 31, 1998. Interest is payable quarterly on
any base rate borrowings and payable on maturity of any Eurodollar borrowings.
The INCC Credit Agreement does not permit the Company to pay or declare any cash
or property dividends or otherwise make any distribution of capital. The Company
is obligated to pay a quarterly fee equal to one-half of 1% per annum of the
unused portion of the borrowing base under the facility.
The Company's ability to borrow under the INCC Credit Agreement is dependent
upon the reserve value of its oil and gas properties. If the reserve value of
the Company's borrowing base declines, the amount available to the Company under
the INCC Credit Agreement will be reduced and, to the extent that the borrowing
base is less than the amount then outstanding under the INCC Credit Agreement,
the Company will be obligated to repay such excess amount on thirty-day's notice
from INCC or to provide additional collateral. INCC and MeesPierson have
substantial discretion in determining the reserve value of the borrowing base.
The following table illustrates the borrowing base, the outstanding borrowings
and the available borrowings under the Credit Facility at June 30, 1995.
BORROWING OUTSTANDING AVAILABLE
BASE BORROWINGS BORROWINGS
----------- ----------- -----------
Credit Facility............................... $45,000,000 $33,500,000 $11,500,000
=========== =========== ===========
Net Operating Losses. For federal income tax purposes, at December 31, 1994,
the Company had net operating losses ("NOLs") of approximately $38.0 million.
Those NOLs include approximately $10.3 million of estimated NOLs that carried
over to the Company from Smith as a result of the Smith Acquisition.
The Internal Revenue Code of 1986, as amended (the "Code") permits a corporation
to carryback NOLs from the year in which it is incurred to the immediately
preceding three years and then carryforward any unused portion of the NOLs up to
15 years. However, the Code contains a further limitation regarding a
corporation's use of its NOLs following a statutorily defined "change in
ownership". Generally, this limitation permits the corporation to use in each
year subsequent to the ownership change a prescribed amount of the NOLs
(hereinafter referred to as the annual limitation amount), subject however to
the general restriction that a corporation cannot carryforward NOLs more than 15
years.
The Company's NOLs of approximately $24.0 million which accumulated through
August 1993, are subject to an annual limitation of $2.1 million. From September
1993 through October 1994, the Company incurred additional NOLs of approximately
$3.0 million, and although a change in ownership occurred in October 1994, the
annual limitation attributable to such change in ownership exceeds the NOLs. The
estimated Smith NOLs of approximately $10.3 million to which the Company
succeeded in the Smith Acquisition are subject to an annual limitation that the
Company currently expects will be $1.0 million.
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The Company's NOLs accumulated through 1994 will expire principally in 2005
through 2009.
For alternative minimum tax purposes, NOLs may be further adjusted to determine
the allowable alternative tax NOLs, and the alternative tax NOLs can be used to
offset no more than 90% of alternative minimum taxable income. Accordingly, the
Company may owe an alternative minimum tax even though its NOLs otherwise
eliminated its regular tax liability.
CHANGES IN PRICES AND INFLATION
The Company's revenues and the value of its oil and gas properties have been and
will continue to be affected by changes in oil and gas prices. The Company's
ability to maintain its current borrowing capacity and to obtain additional
capital on attractive terms is also substantially dependent on oil and gas
prices. Oil and gas prices are subject to significant seasonal and other
fluctuations that are beyond the Company's ability to control or predict.
Although certain of the Company's costs and expenses are affected by the level
of inflation, inflation has not had a significant effect on the Company's
results of operations during 1992, 1993, 1994 or the first six months of 1995.
In an effort to reduce the effects of the volatility of the price of oil and gas
on the Company's operations, management has adopted a policy of hedging oil and
gas prices, usually when such prices are at or in excess of the prices
anticipated in the Company's operating budget, through the use of commodity
futures, options, forward contracts and swap agreements. Hedging transactions
are limited by the Board of Directors such that no transaction may fix an oil
and gas price for a term of more than 12 months, and the aggregate oil and gas
production covered by all transactions may not exceed 50% of the Company's
budgeted production for any 12-month period from the date of the transaction or
75% of the Company's budgeted production for any single month from the date of
the transaction. By hedging its oil and gas prices, the Company intends to
mitigate the risk of future declines in oil and gas prices. Under certain
contracts should oil or gas prices increase above the contract rate, the Company
will not participate in the higher prices for the production.
The Company has entered into three commodity swap transactions governed by the
terms of a Master Agreement with INCC (the "Master Agreement"). Under one swap
transaction the Company will receive a fixed price of $1.75 per MMBtu and pay a
floating price of Natural Gas -- NYMEX for the first nearby contract month for
5,000 MMBtu per day for the contract months July to September 1995. Under a
second commodity swap transaction the Company will receive a fixed price of
$1.7525 per MMBtu and pay a floating price of Natural Gas -- NYMEX for the first
nearby contract month for 5,000 MMBtu per day for the contract months September
1995 to February 1996. Under a third commodity swap transaction governed by the
terms of the Master Agreement the Company will receive a fixed price of $19.50
per barrel and pay a floating price of WTI -- NYMEX for the first nearby month
for 500 barrels per day for the period June 1 to September 30, 1995.
The Company has also contracted to sell 5,000 MMBtu per day to Coastal Gas
Marketing Company at a price of $1.70 per MMBtu for the period June 1, 1995 to
August 31, 1995.
Pursuant to the Master Agreement, the Company may enter into certain interest
rate hedging contracts. The Master Agreement authorizes the Company, subject to
certain limitations, to enter into transactions to fix the interest rates on
principal amounts of variable rate indebtedness of the Company. By hedging its
interest rate under its credit facility, the Company would intend to mitigate
the risk of future increases in interest rates. Should interest rates decrease
below the contract rate, the Company will not participate in the lower interest
rate for the portion of the credit facility under the hedging contract. The
Company currently has no interest rate hedging contracts in place.
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BUSINESS
GENERAL
The Company explores for, develops and produces oil and gas, principally in the
shallow waters of the OCS of the Gulf of Mexico. The Company's strategy is to
expand its reserve base and production principally through exploration and
associated development drilling. The OCS of the Gulf of Mexico is a well-
established area of oil and gas production where the Company's management and
staff have both experience and expertise and where the application of advances
in 3-D and 2-D seismic and computer-aided exploration technology is particularly
suited. The Company participates mainly on a non-operating basis, thereby
minimizing staffing requirements and overhead costs. As a non-operator the
Company generally preserves its rights through operating and other agreements to
influence and in many instances initiate exploration and development projects in
which it is participating. Exploration and development activities are directed
by a small, experienced technical team which makes use of extensive in-house
computer capabilities.
The Company identifies exploratory prospects by (i) integrating 3-D and 2-D
seismic technology with information about surrounding geological features and
(ii) high-grading prospects that exhibit "bright spot" seismic anomalies by
using extensive computer-aided geophysical modeling and amplitude versus offset
analysis. The Company significantly increased its inventory of exploration
acreage through successful participation in the 1994 and 1995 OCS Gulf of Mexico
Lease Sales and through the Smith Acquisition, which was completed in October
1994. The Company currently has an inventory of 23 identified prospects, of
which 20 are defined by 3-D seismic. The Company believes that its existing
properties, including its substantial inventory of undeveloped acreage and
identified prospects, provide significant future exploration and development
potential. The Company expects to spend approximately $30 million on exploratory
and development drilling, leasehold and seismic costs from September 1995
through the first quarter of 1996.
From January 1, 1992 to January 1, 1995, the Company achieved an 81% success
rate on 27 gross exploratory wells and a 100% success rate on 18 gross
development wells. As a result of the Company's exploration success, the
Company's proved reserves more than doubled from 36.0 Bcfe to 74.8 Bcfe over
this period. Over the same period, the Company replaced 353% of production at an
average reserve replacement cost, including finding and development costs and
provision for abandonment, of $0.75 per Mcfe.
As a result of the Company's successful development programs, production during
the first six months of 1995 increased by 175% compared with the first six
months of 1994, and revenue increased by 139%, despite a decline in average
realized gas prices to $1.65 per Mcf from $2.20 per Mcf. Eighty percent of the
Company's production during the first half of 1995 was gas. The Company's
average production costs decreased in the first half of 1995 to $0.24 per Mcfe
as compared with $0.53 per Mcfe in the first half of 1994. The Company believes
that its production and overhead costs per unit of production are among the
lowest of independent oil and gas producers.
OFFSHORE PROPERTIES
East Cameron Blocks 331/332. The Company's largest development project is on
East Cameron Blocks 331/332. These blocks are located 98 miles offshore
Louisiana in 240 feet of water. The Company purchased an interest in these
blocks in 1991 for $100,000, and in 1992 proposed the first exploratory well,
which proved to be the discovery well for the field. The field commenced
production in October 1994, and a total of nine wells have now been completed.
During the first six months of 1995, East Cameron Blocks 331/332 produced an
average of 12.7 MMcf of gas per day and 793 Bbls of oil per day net to the
Company's interest, accounting for approximately 45.6% of the Company's
production for the period. At January 1, 1995, the Company's net proved reserves
in East Cameron Blocks 331/332 were 35.5 Bcfe with a Discounted Present Value of
approximately $44.7 million. The Company believes that there is further
exploration potential on these blocks. The Company owns a 40% interest in the
shallower zone of Block 331 and a 20% interest in the deeper zone of both
blocks. Approximately 80% of the gross proved
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reserves are located in the deeper zone. Samedan Oil Company, a subsidiary of
Noble Affiliates, is the operator of these blocks.
Vermilion Block 203. This block is located 56 miles offshore Louisiana in 100
feet of water. The Company acquired a 50% working interest in this block as a
part of the Smith Acquisition. This prospect contains two separate geologic
plays (shallow and deep) on the flank of a piercement salt dome. Four wells, all
of which have encountered hydrocarbons, have been drilled to the shallow
formations on the block. These wells have all been temporarily suspended pending
completion operations and a jacket structure has been installed. Management
expects that a deck and production facilities with a planned capacity of up to
50 MMcf of gas per day will be installed on the jacket in the third quarter of
1995. First production from the block is expected in late 1995 or early 1996.
Further exploration includes a deep prospect on this block that targets
stratigraphic sections that are defined by the Company's 3-D seismic and are
similar to those currently being developed by another operator on the adjacent
block to the north (Vermilion Block 200). The operator of Block 200 has to date
drilled six wells and is currently drilling a seventh well. The Company's Block
203 deep prospect is located on the south flank of the same salt dome that
extends into Block 200. The planned deep well on Block 203 is expected to test a
similar section to that being developed on Block 200. However, the deep target
in Block 203 is structurally separated by several faults from the Block 200
development. There can be no assurance that productive zones will be encountered
at deeper levels on Block 203. Drilling of this high-potential exploratory well
is scheduled for the second half of 1995. Houston Exploration is the operator of
Block 203.
Mustang Island Block 858. This block is located 12 miles offshore Texas in
approximately 90 feet of water. The Company acquired a 17.5% working interest in
this block as part of the Smith Acquisition. At the time of the acquisition, one
successful well had been drilled and suspended on the block, and in 1995 the
Company participated in two further successful exploration wells on the block. A
recent test of certain deeper sands flowed at a non-commercial rate, and no
further activity is planned targeting these deeper horizons. However,
development activities in the shallower horizons are proceeding. A jacket
structure has been set and a deck and production processing facilities with a
planned capacity of up to 50 MMcf of gas per day are under construction. First
production from the development is expected in late 1995 or early 1996. Houston
Exploration is the operator of this block.
Matagorda Block 710. This block is located 28 miles offshore Texas in 150 feet
of water. In September 1993, the Company participated in a successful
exploratory gas well on the block. In June 1994 a second exploration well was
drilled and suspended, and a three slot platform was set over the 1993 discovery
well. In August 1994, a development well was drilled from this platform. After
flow testing at a non-commercial rate of approximately 2 Mcf of gas per day, the
development well was suspended for a possible future sidetrack. One additional
exploratory well was successfully drilled and completed in October 1994. On
December 16, 1994, production commenced from two wells in the field. Additional
exploratory drilling is expected on this block before the end of 1995. During
the first six months of 1995, this block produced an average of 2.8 MMcf of gas
per day and 4 Bbls of condensate per day net to the Company's interest. The
Company owns a 30% working interest in Matagorda Block 710, which is operated by
Murphy Exploration and Production Company.
Main Pass Blocks 300/301. These blocks are located 22 miles offshore Louisiana
in 200 feet of water. In January 1993, a successful exploration well was drilled
on Main Pass Block 301. In December 1993, a second successful exploration well
was drilled into a different geological structure on Main Pass Block 300. A
platform was installed in early August 1994. Both discovery wells and one
additional well have been completed, and production commenced in October 1994.
During the first six months of 1995, this block produced an average of 0.1 MMcf
of gas per day and 111 Bbls of condensate per day net to the Company's interest.
The Company owns a 15.3% working interest in Main Pass Blocks 300/301, which are
operated by Walter Oil & Gas Corporation.
Ship Shoal Block 251. This block is located 54 miles offshore Louisiana in 160
feet of water. A successful exploratory well was drilled on the block and was
suspended in April 1994. One additional exploratory well was successfully
drilled to and completed in a separate fault block in November 1994. In December
1994 a
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four pile production platform was installed with 100 MMcf of gas per day
production capacity. Production commenced from this field on February 13, 1995
and average production during the first six months of 1995 was 6.1 MMcf of gas
per day and 232 Bbls of condensate per day net to the Company's interest. The
Company believes that there is further exploration potential on this block. The
Company owns a 25% working interest in Ship Shoal Block 251, which is operated
by Union Pacific Resources Company ("UPRC").
East Cameron Blocks 349/350/355/356. The East Cameron Blocks 349/350/355/356
prospect area is located 110 miles offshore Louisiana in 300 feet of water. The
Company's interests in Blocks 349 and 355 were acquired in the 1994 Gulf of
Mexico Central Area Lease Sale while the Company's interest in Block 356 was
acquired in a property swap by the Company in 1994. The Company's interest in
Block 350 was acquired recently in the 1995 Gulf of Mexico Central Area Lease
Sale. In May 1995, the Company participated in a new field discovery on East
Cameron Block 356. The field is located 6 miles south of the Company's East
Cameron Block 331/332 complex and was identified on the Company's 3-D seismic,
which covers both areas. The discovery well was drilled to a depth of 7,669 feet
and logged two hydrocarbon bearing Pleistocene sands. The well is suspended
pending completion operations and delineation of further prospective structures
on this four-block complex. The identified reserves in the blocks well appear
sufficient to justify a platform. The Company expects four additional
exploratory wells to be drilled prior to design and fabrication of platform and
production facilities. Further drilling is expected to commence early in the
fourth quarter of 1995. The Company owns a 37.5% working interest in all four
blocks, which are operated by Enserch.
Main Pass Block 262. This block, located 60 miles offshore Louisiana in 280
feet of water, is a recent acquisition from the 1995 Gulf of Mexico Central Area
Lease Sale. The prospect is defined by 3-D seismic surveys and previous drilling
activity. An exploratory well drilled in 1990 encountered productive sand in a
shallow Pliocene reservoir, but was plugged and abandoned due to an absence of
3-D seismic. Management believes that subsequently-acquired 3-D seismic over the
block accurately delineates the potential size of the accumulation. A recent
well drilled on the adjacent block to the south (Main Pass Block 281) has
significant gas production from this same Pliocene reservoir. However, there can
be no assurance that productive zones will be encountered in Block 262. The 3-D
seismic data over this reservoir has delineated two additional prospective
accumulations on Main Pass Block 262, and the Company plans to commence drilling
in the fourth quarter of 1995. The Company owns a 33.3% working interest in
Block 262, which is operated by Canadian Occidental Petroleum Ltd.
South Timbalier Block 249. This block, located 55 miles offshore Louisiana in
180 feet of water, lies directly northwest of a recent discovery by another
operator on South Timbalier Block 265. Development plans announced for Block 265
include the installation of two platforms with processing capacity of 150 MMcf
per day and 10,000 Bbls per day. The Company has identified two prospects on its
South Timbalier Block 249 that target similar stratigraphic sections as those
discovered in Block 265. However, there can be no assurance that productive
zones will be encountered in Block 249. Exploratory drilling on Block 249 is
planned for the first quarter 1996. The Company currently owns a 50% working
interest in and is operator of this block, but may reduce its interest prior to
drilling an exploration well.
Galveston 343/363 Field. Galveston 343/363 field is located 13 miles offshore
Texas in 65 feet of water. The field is comprised of two adjacent federal lease
blocks operated by an affiliate of Seagull Energy Corp. ("Seagull"). Production
began in 1990. Natural gas and condensate are produced from eight wells on Block
343 and one well on Block 363, from sands at depths of 7,100 feet to 8,500 feet.
The wells on Block 343 produce through a four pile drilling and production
platform. The well on Block 363 produces through a separate satellite platform
that is tied by flowline to the Block 343 platform. Gas and condensate flow from
Block 343 to shore through a 16-inch pipeline. During the first half of 1995,
the average daily production net to the Company from this field was 3.7 MMcf of
gas and 19 Bbls of oil. Development drilling to establish production from proved
undeveloped locations in the field was initiated in 1993. One well was drilled
and completed in June 1993 and another well was drilled in July 1994 and is
currently producing. Production performance from the new well may lead to the
drilling of other infill wells. An
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exploration well to target certain deeper formations on the block is currently
being drilled. The Company owns a 12% working interest in Block 343 and an
11.25% working interest in Block 363.
West Cameron 76 Unit. West Cameron 76 Unit is comprised of portions of four
federal blocks, West Cameron Blocks 60, 61, 76 and 77, and is located 12 miles
offshore of Louisiana in 40 feet of water. The Company's interest in the unit
was purchased as part of the Smith Acquisition. When the interest was acquired
the unit was producing from three wells. In February a further exploration well
was drilled and is now being completed. Additional drilling is expected on this
unit. The Company owns a 2.625% working interest in the unit. It owns a 4.375%
working interest in the south quarters of West Cameron Blocks 76 and 77, which
are not included in the unit and are not producing. BHP Petroleum (Americas),
Inc. is the operator of these blocks.
Other Offshore Properties. The Company currently holds interests in 41
additional lease blocks offshore Texas and Louisiana, of which six are producing
leases. The Company plans to increase its exploration and development efforts on
the balance of these properties.
ONSHORE PROPERTIES
Appalachian Region Properties. The Company holds interests in 279 wells located
primarily in Venango and Crawford Counties in Pennsylvania. These wells,
operated by Lomak Petroleum, Inc., produce from multiple completions in
Silurian-aged Medina and other sands at depths of approximately 5,500 feet to
6,000 feet. The Company's working interests in these wells range from 4% to
100%, with an average of approximately 28%. The Company also holds a 20%
interest in the local field gathering system and the pipeline that takes
production from the wells in this area.
Other Onshore Properties. The Company holds various minor working and royalty
interests in additional wells in Texas and Oklahoma.
FIRST HALF 1995 EXPLORATION ACTIVITY
In 1995 to date, the Company has participated in the drilling of 12 exploration
wells in the OCS of the Gulf of Mexico.
Three exploration wells drilled by the Company to target certain shallow
formations on Vermilion Block 203 (one of the Smith Assets) all encountered
productive sand intervals as indicated by wireline log analysis. The three wells
were suspended pending completion operations. The Company expects completion
operations to begin in August 1995 with first production expected to begin late
in late 1995 or early 1996. It is expected that a well to target deeper
formations on the block will be spud prior to year-end 1995. The Company owns a
50% working interest in this block.
The Company participated in the drilling of two exploration wells on Mustang
Island Block 858 (one of the Smith Assets). A recent test of certain deeper
sands flowed at a non-commercial rate, and no further activity is planned
targeting these deeper horizons. Testing is now taking place in the shallow
horizons which were successfully tested in one of the wells. After testing is
complete, all three wells will be completed followed by installation of the deck
and facilities. A pipeline will then be laid with first production expected by
late 1995 or early 1996. The Company owns a 17.5% working interest in this
block.
On West Cameron Block 417, offshore Louisiana, an unsuccessful well was drilled
in January 1995. The Company owns a 40% working interest in this block, which is
operated by Enserch. On Ship Shoal Block 265, offshore Louisiana, the operator,
UPRC, plugged and abandoned an exploratory well drilled on that block. The
Company owns a 25% working interest in Ship Shoal Block 265. The Company
participated in a successful exploratory well on East Cameron Block 303 in
February, 1995 but an appraisal well drilled on the block crossed a fault and
was plugged and abandoned after failing to encounter hydrocarbon bearing sands.
Further appraisal drilling may take place later this year or during 1996. The
Company owns a 33.3% working interest in Block 303, which is operated by
Seagull. In May 1995 the Company participated in a successful exploration well
on East Cameron Block 356. The well was suspended after encountering
hydrocarbon-bearing sands based on wireline log analysis and formation test
information. Additional
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drilling is expected on this block later in the year. The Company owns a 37.5%
working interest in this block, which is operated by Enserch.
An exploration well drilled on Eugene Island Block 59 (one of the Smith Assets)
was unsuccessful and was plugged and abandoned. The Company will seek to clarify
the prospectivity of the block with the aid of a new 3-D survey. The Company
owns a 25% working interest in this block, which is operated by Tana Oil and Gas
Corporation. An exploration well drilled on West Cameron Block 77 (one of the
Smith Assets) was successful and is currently being completed. The Company has a
2.625% interest in the block, which is operated by BHP Petroleum (Americas) Inc.
The Company, together with partners, bid on eighteen blocks in the 1995 Gulf of
Mexico Central Area Lease Sale and were awarded 13 blocks.
In the fourth quarter of 1994, the Company, with two partners, underwrote a
non-exclusive 3-D seismic survey covering 42 blocks in the East Cameron Area
South Addition of the OCS, offshore Louisiana, including five blocks in which
the Company owned an interest. Delivery of the completed survey data was made in
the second quarter of 1995. The survey area includes six blocks in which the
Company acquired an interest in the 1995 Gulf of Mexico Central Area Lease Sale.
The Company has acquired over 100,000 miles of 2-D seismic data covering the
central portion of offshore Louisiana. This data will be used for prospect
generation for lease sales and enhanced data coverage over the Company's
existing leaseholds offshore Louisiana. The Company is also party to an
exploration agreement with UPRC that allows the Company access to UPRC's
extensive 2-D seismic database of the OCS of the Western Gulf of Mexico in
return for certain participation rights. The agreement extended through the 1995
Gulf of Mexico Western Area Lease Sale, which was held on September 13, 1995.
1994 EXPLORATION ACTIVITY
The Company participated in a total of eight offshore exploration wells in 1994.
Six of these wells were successful in finding commercial quantities of
hydrocarbons with two wells suspended pending further technical evaluation.
Successful exploratory wells were drilled on East Cameron Block 331 (1 well),
Ship Shoal Block 251 (2 wells), Matagorda Block 710 (1 well), Main Pass Block
301 (1 well), and Eugene Island Block 18 (1 well). Operations were suspended on
wells drilled on West Cameron Block 588 and Matagorda Block 710. Both suspended
wells showed the presence of hydrocarbons. The Company drilled three offshore
development wells during the year. Successful wells were drilled on East Cameron
Block 331 and Galveston Block 343. A development well on Matagorda Block 710 was
suspended for a possible sidetrack. The Company also had a small interest in a
successful exploration well drilled onshore during the year. The Company has
plans for further exploration in 1995 and early 1996. See "-- Offshore
Properties."
SALES OF PROPERTIES
In June 1995, the Company sold most of the properties which it owned in Texas
and Oklahoma for $1.77 million. At January 1, 1995, the properties had reserves
of approximately 123 MBbls of oil and 2.1 Bcf of gas and had a Discounted
Present Value of $2.03 million.
In 1994, the Company completed a number of property sale transactions that
reduced the number of its total oil and gas wells by 177 gross (150.21 net)
wells and the Company's total developed acreage by 25,115 gross (6,915 net)
acres. Transactions included the sale of: (i) onshore wells in Crockett County,
Texas for $275,000 as of January 1, 1994, (ii) interests in the Ewing Bank 947
Unit offshore Louisiana for $2,255,000 as of August 1, 1994, (iii) onshore
properties located in Hutchinson and Lipscomb Counties, Texas for $700,000 as of
August 1, 1994, and (iv) interests in three Eugene Island blocks offshore
Louisiana for $340,313 as of March 1, 1994. Proceeds from these transactions
were credited to the full-cost pool, resulting in no recognition of gain or
loss.
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OIL AND GAS RESERVES
The following table sets forth certain information regarding the Company's
proved oil and gas reserves. The following information is based on the Company's
estimated reserves as of January 1, 1995 as reviewed by Ryder Scott. Ryder Scott
is a nationally recognized firm of petroleum engineers specializing in
evaluations of oil and gas reserves.
PROVED RESERVES
------------------------------------------------------------
% OF TOTAL
NATURAL OIL AND DISCOUNTED DISCOUNTED
GROSS GAS CONDENSATE TOTAL PRESENT VALUE PRESENT
FIELD WELLS (MMCF) (MBBLS) (MMCFE) -------------- VALUE
------------------------------------ ----- ------- ---------- ------- (IN THOUSANDS) ----------
OFFSHORE:
East Cameron Blocks 331/332....... 12 25,848 1,612 35,520 $ 44,700 56.7%
Galveston Blocks 343/363.......... 11 6,530 24 6,674 6,984 8.9
Ship Shoal Block 251.............. 2 5,788 174 6,832 7,427 9.4
Matagorda Block 710............... 4 7,303 16 7,399 6,983 8.9
Main Pass Block 301............... 7 1,028 325 2,978 3,915 4.9
Other offshore.................... 31 4,507 38 4,735 2,825 3.6
---- ------- -------- ------ -------- -----
Total offshore............ 67 51,004 2,189 64,138 72,834 92.4
ONSHORE:
Appalachian region................ 279 3,219 -- 3,219 2,777 3.5
Texas............................. 51 5,542 61 5,908 1,980 2.5
Other onshore..................... 175 1,118 62 1,490 1,253 1.6
---- ------- -------- ------ -------- -----
Total onshore............. 505 9,879 123 10,617 6,010 7.6
---- ------- -------- ------ -------- -----
Total..................... 572 60,883 2,312 74,755 $ 78,844 100.0%
==== ======= ======== ====== ======== =====
The following table sets forth certain information as of January 1, 1995 (based
on the Company's estimated reserves as of January 1, 1995 as reviewed by Ryder
Scott) with respect to the Company's proved oil and gas reserves and the present
value (discounted at 10%) of estimated future net revenues before income taxes
as of the date indicated.
NATURAL OIL AND
GAS CONDENSATE DISCOUNTED
(MMCF) (MBBLS) PRESENT VALUE
------- ---------- --------------
(IN THOUSANDS)
Proved developed.............................................. 44,893 1,812 $ 63,810
Proved undeveloped............................................ 15,990 500 15,034
------ ----- -------
Total............................................... 60,883 2,312 $ 78,844
====== ===== =======
Since January 1, 1994, the Company has not filed any estimates of proved oil and
gas reserves with any federal authority or agency other than with the Securities
and Exchange Commission (the "Commission").
Ryder Scott reviewed as of January 1, 1995 a report prepared by the Company of
the net reserves attributable to the Company's oil and gas properties. The
Company used the results from the Ryder Scott reserve review letter (the
"Reserve Review Letter") as the Company's reserves estimates. The average prices
used in the computations were $1.72 per Mcf for gas (based on $1.62 per MMBtu)
and $15.67 per Bbl of oil. The results of the Reserve Review Letter conform to
the definition of proved reserves required by the Commission, which assumes no
change in economic conditions will occur in the future.
There are numerous uncertainties inherent in estimating quantities of proved
reserves, including many factors beyond the control of the Company. The reserve
data set forth in this Prospectus represents only estimates. Reservoir
engineering is a subjective process of estimating underground accumulations of
crude oil and natural gas that cannot be measured in an exact manner, 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
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result, estimates of different engineers often vary. In addition, results of
drilling, testing and production subsequent to the date of an estimate may
justify revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of crude oil and natural gas that are ultimately
recovered. The meaningfulness of such estimates is highly dependent upon the
accuracy of the assumptions upon which they were based. In general, the volume
of production from oil and gas properties owned by the Company declines as
reserves are depleted. Except to the extent the Company conducts successful
exploration and development activities or acquires additional properties
containing proved reserves, or both, the proved reserves of the Company will
decline as reserves are produced.
In accordance with Commission guidelines, the estimates of the Company's proved
reserves and Discounted Present Value of revenues therefrom are made using
current lease and well operating costs estimated by the Company. Lease operating
expenses for wells owned by the Company were estimated using a combination of
fixed and variable-by-volume costs consistent with the Company's experience in
the areas of such wells. For purposes of calculating future net revenues and the
Discounted Present Value thereof, operating costs exclude accounting and
administrative overhead expenses attributable to the Company's working interest
in wells operated under joint operating agreements, but include administrative
costs associated with production offices. The Discounted Present Value of proved
reserves set forth herein should not be construed as the current market value of
the estimated proved oil and gas reserves attributable to the Company's
properties.
DRILLING ACTIVITIES
The Company drilled, or participated in the drilling of, the following numbers
of total wells during the periods indicated.
SIX MONTHS
ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------------ ------------
1992 1993 1994 1995
------------ ------------ ------------ ------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---- ----- ----
Total Wells
Gas................................. 7 1.30 5 0.61 9 1.85 8 2.59
Oil................................. 10 0.56 8 1.20 1 .15 -- --
Dry................................. 2 0.31 3 0.68 -- -- 4 1.23
---- ---- ---- ---- ---- ---- ---- ----
Total....................... 19 2.17 16 2.49 10 2.00 12 3.82
==== ==== ==== ==== ==== ==== ==== ====
Development Wells
Gas................................. 2 0.10 2 0.14 3 .61 -- --
Oil................................. 10 0.56 1 0.01 -- -- --
Dry................................. -- -- -- -- -- -- -- --
---- ---- ---- ---- ---- ---- ---- ----
Total....................... 12 0.66 3 0.15 3 .61 -- --
==== ==== ==== ==== ==== ==== ==== ====
Exploratory Wells
Gas................................. 5 1.20 3 0.47 6 1.24 8 2.59
Oil................................. -- -- 7 1.19 1 .15 -- --
Dry................................. 2 0.31 3 0.68 -- -- 4 1.23
---- ---- ---- ---- ---- ---- ---- ----
Total....................... 7 1.51 13 2.34 7 1.39 12 3.82
==== ==== ==== ==== ==== ==== ==== ====
The information contained in the foregoing table should not be considered
indicative of future drilling performance, nor should it be assumed that there
is any necessary correlation between the number of productive wells drilled and
the amount of oil and gas that may ultimately be recovered by the Company. From
January 1, 1992 through June 30, 1995, the Company has drilled and completed 48
gross (8.26 net) productive wells.
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The Company owns no drilling rigs and 100% of its drilling activities are
conducted by independent contractors on a day-rate basis or under standard
drilling contracts. The Company currently has no drilling rigs under contract.
PRODUCTIVE WELL SUMMARY
The following table sets forth certain information regarding the Company's
ownership as of June 30, 1995 of productive wells in the areas indicated.
PRODUCTIVE WELLS
--------------------------------------------
GAS OIL TOTAL
------------- ------------ -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ---- ----- -----
Gulf of Mexico(1).............................. 71 13.24 7 1.21 78 14.45
Appalachian region............................. 275 77.64 4 1.62 279 79.26
Other onshore.................................. 6 1.75 -- -- 6 1.75
---- ----- ---- ---- ---- -----
Total................................ 352 92.63 11 2.83 363 95.46
==== ===== ==== ==== ==== =====
---------------
(1) A majority of these wells have completions in multiple pay zones.
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the production
volumes of, average sales prices received for, and average production costs
associated with, the Company's sales of oil and gas for the periods indicated.
SIX MONTHS
YEAR ENDED DECEMBER 31, ENDED JUNE 30,
------------------------ ---------------
1992 1993 1994 1994 1995
------ ------ ------ ------ ------
Net Production:
Gas (MMcf)................................. 6,159 5,226 3,940 2,070 5,257
Oil (MBbls)................................ 130 116 100 54 220
Total (MMcfe)...................... 6,941 5,922 4,541 2,394 6,577
Average Sales Price:
Gas ($/Mcf)(1)............................. $ 1.84 $ 2.18 $ 1.99 $ 2.20 $ 1.65
Oil ($/Bbl)................................ $18.69 $16.04 $14.35 $13.19 $18.28
Average Production Cost:
($/Mcfe)(2)................................ $ 0.54 $ 0.65 $ 0.50 $ 0.53 $ 0.24
---------------
(1) Includes natural gas liquids.
(2) Includes direct lifting costs (labor, repairs and maintenance, materials and
supplies) and the administrative costs of production offices, insurance and
property and severance taxes.
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DEVELOPMENT, EXPLORATION AND ACQUISITION EXPENDITURES
The following table sets forth certain information regarding the costs incurred
by the Company in its development, exploration and acquisition activities during
the periods indicated.
SIX MONTHS
ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------- ----------
1992 1993 1994 1995
------ ------- ------- ----------
(IN THOUSANDS)
Development Costs............................... $ 970 $ 1,106 $11,683 $ 5,453
Exploration Costs............................... 4,769 8,987 9,872 11,613
Acquisition Costs:
Proved Properties............................. 3,172 -- 1,405 --
Unproven Properties........................... -- -- 22,939 --
------ ------- ------- -------
Total Capital Expenditures............ $8,911 $10,093 $45,899 $ 17,066
====== ======= ======= =======
ACREAGE
The following table sets forth certain information regarding the Company's
developed and undeveloped leasehold acreage as of June 30, 1995. Acreage in
which the Company's interest is limited to royalty, overriding royalty and
similar interests is insignificant and, therefore, excluded.
DEVELOPED UNDEVELOPED TOTAL
---------------- ---------------- ----------------
GROSS NET GROSS NET GROSS NET
------- ------ ------- ------ ------- ------
Gulf of Mexico(1)......................... 116,401 19,995 179,014 68,992 295,415 88,987
Appalachian region........................ 10,043 2,764 -- -- 10,043 2,764
Other onshore............................. 3,200 1,029 15,170 1,896 18,370 2,925
------- ------ ------- ------ ------- ------
Total........................... 129,444 23,788 194,184 70,888 323,828 94,676
======= ====== ======= ====== ======= ======
---------------
(1) Includes acreage awarded in the Gulf of Mexico Central Area Lease Sale which
was held on May 10, 1995 with, in some cases, the award decisions by the
MMS being made after June 30, 1995.
MARKETS
General. The revenues generated from the Company's oil and gas operations are
highly dependent upon the prices of and the demand for its oil and gas
production. The prices received by the Company for its oil and gas production
depend upon numerous factors beyond the Company's control. Future decreases in
the prices of oil and gas would have an adverse effect on the Company's proved
reserves, revenues, profitability and cash flow.
Gas Sales. The Company sells substantially all of its gas production on the
spot market. Generally, the Company's gas production is sold under short-term
contracts. Total sales of gas accounted for 84.1% and 80.9% of the Company's
revenues during 1993 and 1994, respectively. The weighted average prices of the
gas sold by the Company under the various month-to-month spot gas contracts were
$2.18 and $1.99 per Mcf of natural gas during 1993 and 1994, respectively.
During 1993 and 1994, Dow Hydrocarbons and Resources, Inc. purchased gas
production from the Company that amounted to 32% and 21%, respectively, of the
Company's total revenues. In addition, during 1993 and 1994, Amoco Production
Co. purchased 0% and 20%, respectively, Walter Oil and Gas Corporation purchased
14% and 11%, respectively, and Mark Resources Corporation purchased 0% and 11%,
respectively, of such production. No other purchaser of the Company's gas
accounted for more than 10% of the Company's revenues during 1993 and 1994. If
any or all of the above companies cease purchasing gas from the Company, the
Company believes it would be able to replace such purchasers although no
assurances can be given as to the prices it could obtain from other parties.
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Oil Sales. Generally, the Company's oil production is sold to various
purchasers under short-term arrangements at prices negotiated by third parties,
but at prices no less than such purchasers' posted prices for the respective
areas less standard deductions. Total sales of oil accounted for 13.7% and 14.8%
of the Company's revenues during 1993 and 1994, respectively. No single
purchaser of oil from the Company accounted for more than 10% of the Company's
revenues for 1993 and 1994, respectively. The Company believes that the loss of
a purchaser of its oil would not have a material adverse effect on its results
of operations due to the availability of other purchasers for its oil.
COMPETITION
The exploration for and production of oil and natural gas is highly competitive.
In seeking to obtain desirable properties, leases and exploration prospects, the
Company faces competition from both major and independent oil and natural gas
companies, as well as from numerous individuals and drilling programs. Extensive
competition also exists in the market for natural gas produced by the Company.
Many of these competitors have financial and other resources substantially in
excess of those available to the Company and, accordingly, may be better
positioned to acquire and exploit prospects, hire personnel and market
production. In addition, many of the Company's larger competitors may be better
able to respond to factors that affect the demand for oil and natural gas
production such as changes in worldwide oil and natural gas prices and levels of
production, the cost and availability of alternative fuels and the application
of government regulations.
REGULATION
Oil and Gas Production. The Company's oil and gas exploration, production and
related operations are subject to extensive rules and regulations promulgated by
federal and state agencies. Failure to comply with such rules and regulations
can result in substantial penalties. The regulatory burden on the oil and gas
industry increases the Company's cost of doing business and affects its
profitability. Because such rules and regulations are frequently amended or
interpreted, the Company is unable to predict the future cost or impact of
complying with such laws.
All of the Company's offshore oil and gas leases are granted by the federal
government and are administered by the Mineral Management Service ("MMS"). Such
leases require compliance with detailed federal regulations and orders that
regulate, among other matters, drilling and operations and the calculation of
royalty payments to the federal government. Ownership interests in these leases
are generally restricted to United States citizens and domestic corporations.
Assignments of these leases or interests therein are subject to approval by the
MMS.
The federal authorities, as well as many state authorities, require permits for
drilling operations, drilling bonds and reports concerning operations and impose
other requirements relating to the exploration and production of oil and gas.
Such states also have statutes or regulations addressing conservation matters,
including provisions for the unitization or pooling of oil and gas properties,
the establishment of maximum rates of production from oil and gas wells and the
regulation of spacing, plugging and abandonment of such wells. The statutes and
regulations of the federal authorities, as well as many state authorities, limit
the rates at which oil and gas can be produced from the Company's properties.
Prior to January 1, 1993, the first sale of certain categories of natural gas
production was price 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 ("FERC"). However, under
the Natural Gas Wellhead Decontrol Act of 1989, all price controls of natural
gas under the NGPA were phased out effective 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 that remain subject to the FERC's jurisdiction. The stated purpose of
many of these regulatory changes is to promote competition among the various
sectors of the gas industry. The ultimate impact of the
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complex and overlapping rules and regulations issued by the FERC since 1985
cannot be predicted. In addition, many aspects of these regulatory developments
have not become final but are still pending judicial and FERC final decisions.
Environmental. The Company is subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. These laws and regulations may require the
acquisition of a permit before drilling commences, restrict the types,
quantities and concentration of various substances that can be released into the
environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands
and other protected areas and impose substantial liabilities for pollution
resulting from the Company's operations. Moreover, the recent trend toward
stricter standards in environmental legislation and regulation is likely to
continue. For instance, legislation has been proposed in Congress from time to
time that would reclassify certain oil and gas production wastes as "hazardous
wastes," which reclassification would make such wastes subject to much more
stringent handling, disposal and clean-up requirements. If such legislation were
to be enacted, it could have a significant impact on the operating costs of the
Company, as well as the oil and gas industry in general. It is not anticipated
that the Company will be required in the near future to expend amounts that are
material in relation to its total capital expenditure program by reason of
environmental laws and regulations, but because such laws and regulations are
frequently changed, the Company is unable to predict the ultimate cost of such
compliance.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose a
variety of regulations on "responsible parties" related to the prevention of oil
spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of the area in which an offshore facility is
located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. While liability limits apply
in some circumstances, a party cannot take advantage of liability limits if the
spill was caused by gross negligence or willful misconduct or resulted from
violation of a federal safety, construction or operating regulation. If the
party fails to report a spill or to cooperate fully in the cleanup, liability
limits likewise do not apply. Few defenses exist to the liability imposed by the
OPA.
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. On August 25, 1993, the MMS published an advance notice of its intention
to adopt a rule under the OPA that would require owners and operators of
offshore oil and gas facilities to establish $150 million in financial
responsibility. Under the proposed rule, financial responsibility could be
established through insurance, guaranty, indemnity, surety bond, letter of
credit, qualification as a self-insurer or a combination thereof. There is
substantial uncertainty as to whether insurance companies or underwriters will
be willing to provide coverage under the OPA because the statute provides for
direct lawsuits against insurers who provide financial responsibility coverage,
and most insurers have strongly protested this requirement. The financial tests
or other criteria that will be used to judge self-insurance are also uncertain.
The Company cannot predict the final form of the financial responsibility rule
that will be adopted by the MMS, but such rule has the potential to result in
the imposition of substantial additional annual costs on the Company or
otherwise materially adversely affect the Company. The impact of the rule should
not be any more adverse to the Company than it will be to other similarly
situated owners or operators in the Gulf of Mexico.
The OPA also imposes other requirements, such as the preparation of an oil spill
contingency plan. The Company has such a plan in place. Failure to comply with
ongoing requirements or inadequate cooperation during a spill event may subject
a responsible party to civil or criminal enforcement actions.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to have contributed to the release of a "hazardous substance"
into the environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that disposed or
arranged for the disposal of the hazardous substances and under CERCLA such
persons or companies would 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
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natural resources. 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.
OPERATIONAL HAZARDS AND INSURANCE
The Company maintains insurance of various types to cover its operations.
Ultimate limits provided under such policies are $50 million ($75 million in
certain cases). In addition, the Company maintains operator's extra expense
coverage that provides for care, custody and control of wells drilled or
completed by the Company. The occurrence of a significant adverse event, the
risks of which are not fully covered by insurance, could have a material adverse
affect on the Company's financial condition and results of operations. Moreover,
no assurance can be given that the Company will be able to maintain adequate
insurance in the future at rates it considers reasonable.
EMPLOYEES
At June 30, 1995, the Company had 16 employees. None of the Company's employees
is subject to a collective bargaining agreement. The Company considers its
relations with its employees to be good.
TITLE TO PROPERTIES
As is customary in the oil and gas industry, the Company performs a minimal
title investigation before acquiring undeveloped properties. The Company has
obtained title opinions on substantially all of its producing properties and
believes that it has satisfactory title to such properties in accordance with
standards generally accepted in the oil and gas industry. The Company's
properties are subject to customary royalty interests, liens incident to
operating agreements, liens for current taxes and other burdens that the Company
believes do not materially interfere with the use of or affect the value of such
properties. Substantially all of the Company's oil and gas properties are and
will continue to be mortgaged to secure borrowings under the Company's credit
facility. See "Management's Discussion and Analysis of Financial Conditions and
Results of Operations -- Capital Resources and Liquidity."
OFFICES
The Company leases approximately 6,100 square feet of office space in Dallas,
Texas under a lease that expires in October 1996. The Company considers its
office space adequate for its needs.
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MANAGEMENT
Information regarding the directors and executive officers of the Company as of
the date of the Prospectus is set forth below:
NAME AGE PRESENT POSITION(S) WITH THE COMPANY
------------------------------ --- ------------------------------------------------
Michael R. Gilbert............ 45 President, Chief Executive Officer and Director
J. Munro M. Sutherland........ 40 Senior Vice President, Chief Financial Officer,
Treasurer and Director
Robert P. Murphy.............. 36 Vice President -- Exploration
A. Allen Paul................. 52 Vice President -- Finance
Susan H. Rader................ 43 Secretary and Land Manager
William B. B. Gammell......... 42 Director
John C. Halsted............... 30 Director
Michael E. McMahon............ 47 Director
Jack O. Nutter, II............ 43 Director
R. Daniel Robins.............. 44 Director
Directors are elected at the annual meeting of stockholders and hold office
until the next annual meeting of stockholders, expected to be May 1996, and
until their successors have been elected and qualified, subject to the removal
provisions of the Company's bylaws. Each executive officer of the Company serves
at the pleasure of the Board of Directors.
Michael R. Gilbert has served as the President, Chief Executive Officer and a
Director of the Company since February 27, 1992. Mr. Gilbert was the President
and a Director of Cairn Energy USA, Inc. ("Cairn USA"), an oil and gas
exploration and development corporation, from Cairn USA's inception in March
1989 until the Merger. From 1982 to 1989, Mr. Gilbert served as Executive Vice
President of Canyon Oil and Gas Company, an oil and gas acquisition company and
a subsidiary of Slawson Companies, Inc., an oil and gas company ("Slawson").
J. Munro M. Sutherland has served as Senior Vice President, Chief Financial
Officer and Treasurer of the Company since November 1993. Mr. Sutherland has
been a director of the Company since June 1993. From 1988 to October 1993, Mr.
Sutherland was the Finance Director of Cairn Energy PLC, formerly the Company's
majority stockholder and an independent oil and gas exploration and production
company ("Cairn PLC"). He was a non-executive director of Cairn PLC from
November 1, 1993 until August 31, 1994. From 1986 to 1988, Mr. Sutherland served
as director of Cairn Energy Management Limited, an oil and gas management
company.
Robert P. Murphy joined Cairn USA in 1990 as an exploration geologist and became
the Company's Vice President -- Exploration in March 1993. From 1984 to 1990,
Mr. Murphy served as an exploration geologist for Enserch, an oil and gas
company. Mr. Murphy holds a M.S. in geology from The University of Texas at
Dallas.
A. Allen Paul has served as Vice President of the Company since September 1992
and from September 1992 to November 1993 was Treasurer of the Company. From
April 1990 to August 1992 Mr. Paul was Vice President -- Finance for Rosco
Wallcovering, Inc., a company specializing in the wholesale distribution of
wallpaper. From January 1986 to April 1990, Mr. Paul was a self-employed
certified public accountant. Prior to January 1986, Mr. Paul was employed in
various capacities with AMOCO Oil Co., Tesoro Petroleum Corp. and Hunt Energy
Corporation.
Susan H. Rader has served as Secretary and Land Manager of the Company since
September 1992. From Cairn USA's inception in March 1989 until the Merger in
September 1992, Ms. Rader served as Assistant Secretary and as Land Manager for
Cairn USA. Prior to March 1989, Ms. Rader was a land manager for Western Natural
Gas Company, an oil and gas company.
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William B. B. Gammell has served as Managing Director of Cairn PLC since 1988.
From 1986 to 1988, Mr. Gammell was a director of Cairn Energy Management
Limited, an oil and gas management company. Mr. Gammell has served as a director
of the Company since September 1992.
John C. Halsted has served as a director of the Company since 1994. Mr. Halsted
has been an associate of the Harvard Private Capital Group, which is an
affiliate of the Selling Stockholder, since 1993. From 1991 to 1993, Mr. Halsted
was an associate of Simmons & Company International, an investment banking firm.
Mr. Halsted received an M.B.A. from Harvard University in 1991.
Michael E. McMahon has served as a director of the Company since 1994. Mr.
McMahon is a Managing Director with Lehman Brothers. From January 1993 until
October 1994, he was a partner with Harvard Management Company, Inc., which is
an affiliate of the Selling Stockholder. From December 1989 through December
1992, Mr. McMahon was a Managing Director of Salomon Brothers. Mr. McMahon is
also a director of Triton Energy Corporation and Tejas Power Corporation.
Jack O. Nutter, II has served as a director of the Company since December 1987.
Since 1991, Mr. Nutter has also served as President of Nutter & Harris, a
governmental relations and business consulting firm. From 1988 to 1991, Mr.
Nutter served as the Senior Vice President of The Jefferson Group, a government
relations consulting firm. From 1981 to 1987, Mr. Nutter acted as general
counsel for Slawson. From 1983 to 1986, Mr. Nutter also served as President of
Canyon Oil & Gas Company, an oil and gas acquisition company and a subsidiary of
Slawson.
R. Daniel Robins has been Vice President of Marketing of The Coastal
Corporation, an integrated oil and gas company, since August 1994. From 1991 to
August 1994 he was the President of Prairie States Oil & Gas, Inc., a natural
gas marketing company. From 1986 to 1990, Mr. Robins served as Senior Vice
President of Gas Supply for Enron Corporation, a gas purchasing and
transportation company. Mr. Robins also serves as a paid gas marketing
consultant to the Company and receives approximately ten percent (10%) of his
annual compensation in consulting fees from the Company. Mr. Robins has served
as a director of the Company since February 1992.
BOARD COMMITTEES AND MEETINGS
Standing committees of the Company's Board of Directors are an audit committee
(the "Audit Committee") and compensation committee (the "Compensation
Committee"). The Audit Committee met once in 1994. The Compensation Committee
met three times in 1994 and took certain actions by unanimous written consent.
The Audit Committee's principal responsibilities consist of (i) recommending the
selection of independent auditors, (ii) reviewing the scope of the audit
conducted by such auditors and the audit itself and (iii) reviewing the
Company's internal audit activities and matters concerning financial reporting,
accounting and audit procedures, and policies generally. Current members of the
Audit Committee are Messrs. Nutter, Robins and Halsted.
The Compensation Committee makes recommendations to the Board of Directors
regarding compensation policies, including salaries, bonuses and other
compensation and administers the Company's employee stock option plans and
reviews and approves the granting of stock options. Current members of the
Compensation Committee are Messrs. Nutter, Robins, McMahon and Gammell.
The Company has no standing nominating committee.
The board of directors held seven regular or special meetings during 1994.
Various matters were approved during the last fiscal year by unanimous written
consent of the Company's Board of Directors. No director attended fewer than 75%
of the aggregate of (i) the total number of meetings of the Company's Board of
Directors held during such person's term as a director and (ii) the total number
of meetings held by all committees of the Company's board on which such director
served.
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DIRECTOR COMPENSATION
The members of the Company's Board of Directors and committees of the Board of
Directors who were not employees of the Company received $1,500 per regular or
special board meeting attended and $500 for each committee meeting attended. On
October 10, 1994, the Board of Directors approved, effective that date, an
increase in directors' fees for board meetings to $2,000 per regular or special
board meeting attended and $1,000 per telephonic board meeting attended.
1993 DIRECTORS STOCK OPTION PLAN
The Company has in effect the Cairn Energy USA, Inc. 1993 Directors Stock Option
Plan (the "1993 Directors Stock Option Plan"). The purpose of the 1993 Directors
Stock Option Plan is to attract and retain directors of the Company and to
extend to them the opportunity to acquire a proprietary interest in the Company
so that they will apply their best efforts for the benefit of the Company. The
1993 Directors Stock Option Plan authorizes the granting of nonstatutory stock
options to directors of the Company who are not and have not been employees of
the Company or any affiliated corporations except Cairn PLC (a "Nonemployee
Director"). At the beginning of each term, each Nonemployee Director
automatically receives a nonstatutory option to purchase 10,000 shares of Common
Stock at an exercise price equal to the last reported sales price per share of
the Common Stock on the last business day prior to the option's date of grant.
Each option is fully exercisable six months after the date of its grant and
expires five years after the date of its grant. A total of 150,000 shares of
Common Stock were reserved for issuance under the 1993 Directors Stock Option
Plan. Options to purchase 100,000 such shares have been granted. In 1995,
Messrs. Gammell, McMahon, Nutter and Robins were each granted options to
purchase 10,000 shares of Common Stock at an exercise price of $10.00 per share.
EMPLOYMENT AGREEMENTS
The Company has entered into employment agreements with Messrs. Michael R.
Gilbert, President and Chief Executive Officer of the Company, J. Munro M.
Sutherland, Senior Vice President, Chief Financial Officer and Treasurer and
Robert P. Murphy, Vice President -- Exploration of the Company.
Mr. Gilbert's employment agreement expires on December 31, 1997 and provides for
a base salary of $165,000 in 1995, $185,000 in 1996 and $200,000 in 1997. Mr.
Sutherland's employment agreement expires on October 31, 1996 and provides for a
base salary of $130,000 in 1995 and $135,000 in 1996. Mr. Murphy's employment
agreement expires on December 31, 1997 and provides for a base salary of
$105,000 in 1995, $125,000 in 1996 and $135,000 in 1997. Mr. Sutherland's
employment agreement also provides that the Company shall pay to Mr. Sutherland
deferred compensation ("Deferred Compensation") equal to $19,167 for each one
complete year of service under the agreement (commencing November 1, 1993) up to
a maximum of $57,501. The Deferred Compensation is payable to Mr. Sutherland in
three equal annual installments with the first installment due January 1, 1998.
Each employment agreement specifies that the services are to be rendered in
Dallas, Texas and provides the executive with certain benefits, such as health,
life and disability insurance and a car allowance, among other things. The Board
of Directors may also (but is not required to) supplement the executive's base
salary with a bonus in an amount, if any, that the board of directors shall
determine in its discretion.
If the Company terminates any of these employment agreements for "due cause,"
death or disability, the terminated executive would be entitled to all
compensation due him up to the date of his termination. If the Company
terminates any of these employment agreements without "due cause" or if an
executive terminates his employment agreement upon the occurrence of certain
specified events ("the Permitted Termination Events"), that executive would be
entitled to all compensation due him under the full term of the employment
agreement plus a severance payment (the "Severance Payment") in an amount equal
to one year's base salary at the date of termination. In addition, in the event
of termination under any of the circumstances set forth above (except for "due
cause"), Mr. Gilbert and Mr. Murphy would be entitled to receive the total of
all bonus compensation ("Bonus Compensation") allocated for such executive under
the Company's Incentive Bonus Program in prior fiscal years that remains unpaid
(notwithstanding the
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payment terms and vesting provisions of the Incentive Bonus Program) and in the
case of Mr. Sutherland the Deferred Compensation that remains unpaid
(notwithstanding the payment terms or the plan or arrangement).
Each executive may terminate his employment agreement if any one or more of the
following Permitted Termination Events occurs: (i) if there is a material
adverse alteration or diminution of the executive's position, duties,
responsibilities, reporting relationship, authority or status from those in
effect when the employment agreement was executed; (ii) if the executive is
required to perform a substantial portion of his service to the Company outside
the Dallas/Fort Worth metropolitan area; or (iii) if the Company breaches his
employment agreement.
If there is a change in control of the Company, and if, within the 24 months
following that change in control, any of the employment agreements is
terminated, either by the Company without "due cause" or by the executive upon
the occurrence of a Permitted Termination Event, the terminated executive would
be entitled to all compensation due him under his employment agreement, the
Severance Payment, if any, and an additional payment in the amount of one year's
base salary. In addition, Mr. Gilbert and Mr. Murphy would be entitled to
receive the total of all Bonus Compensation that remains unpaid and Mr.
Sutherland would be entitled to receive the Deferred Compensation that remains
unpaid. Any severance payments resulting from termination following a change in
control are limited so that the terminated executive does not incur an excise
tax and so that the Company receives a deduction under the Code for the
termination payment. Each employment agreement limits the aggregate amount of
all payments to a terminated executive to three times such executive's base
salary on the date of termination. Consummation of the Smith Acquisition and the
transactions pursuant to the Stock Purchase Agreement and related agreements
resulted in a "change of control" within the meaning of the employment
agreements. The Company does not expect the occurrence of events requiring
payment of compensation due to the change of control provisions.
Mr. Murphy's employment agreement also provides that if he terminates his
employment other than pursuant to his employment agreement or if the Company
terminates his employment for due cause or following a Permitted Termination
Event, Mr. Murphy would be restricted for one year from the date of such
termination from participating, whether as an employee or otherwise, in the
acquisition of any property or interest within the boundaries of a prospect or
proposal that the Company generates prior to such termination.
Messrs. Gilbert's and Sutherland's employment agreements exclude them from
participating in the Incentive Bonus Program.
1993 STOCK OPTION PLAN
The purpose of the 1993 Stock Option Plan is to attract and retain key employees
of the Company and to extend to them the opportunity to acquire a proprietary
interest in the Company so that they will apply their best efforts for the
benefit of the Company. The 1993 Stock Option Plan authorizes the granting of
incentive stock options and nonstatutory stock options to key employees,
including executive officers of the Company. The Company's Compensation
Committee administers the 1993 Stock Option Plan. The exercise price per share
for an option is determined in the discretion of the Compensation Committee;
provided, however, that the exercise price per share of incentive stock options
may not be less than the fair market value of the Common Stock on the date of
the grant. The exercise price for all options granted to date has been at the
fair market value of the Common Stock in the date of grant. Each option is
exercisable in such amount, at such intervals and on such terms as the
Compensation Committee determines in its sole discretion. However, no option may
be exercised during the six month period following the date of its grant or more
than 10 years after the date of its grant. A total of 650,000 shares of Common
Stock has been reserved for issuance under the 1993 Stock Option Plan of which
400,000 have been granted. No options have been granted under the 1993 Stock
Option Plan in 1995.
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401(K) PROFIT SHARING PLAN
The Company's 401(k) Profit Sharing Plan historically has provided for a Company
contribution, in cash, equal to 5% of eligible participant compensation. The
Board of Directors has approved an amendment to the Company's 401(k) Plan that
provides that, effective for 1995 and thereafter, instead of contributing cash,
such contribution will be made in the form of shares of Common Stock having a
value at the time of contribution (as determined under the 401(k) Plan) equal to
5% of eligible participant compensation.
PRINCIPAL STOCKHOLDERS
The following table sets forth certain information regarding the beneficial
ownership of Common Stock as of the date of this Prospectus, and as adjusted to
reflect the sale of Common Stock in the Offering by (i) each person known to the
Company to own beneficially more than 5% of the outstanding shares of Common
Stock; (ii) each director of the Company; (iii) the Company's chief executive
officer and each executive officer of the Company who earned in excess of
$100,000 in salary and bonus in 1994 (collectively, the "named Executive
Officers"); and (iv) all directors and executive officers of the Company as a
group.
AS OF SEPTEMBER 13, 1995 AFTER OFFERING
------------------------------------ ---------------------------
PERCENT OF PERCENT OF
CLASS SHARES CLASS
SHARES BENEFICIALLY BENEFICIALLY BENEFICIALLY BENEFICIALLY
NAME OF BENEFICIAL OWNER OR GROUP OWNED(1) OWNED OWNED(1) OWNED(2)
--------------------------------------------- ------------------- ------------ ------------ ------------
Phemus Corporation(3)........................ 5,500,000 34.4% 2,750,000 16.2%
Centennial Associates, L.P.(4)............... 871,500 5.5 871,500 5.1
Michael R. Gilbert........................... 119,400(5) * 119,400 *
J. Munro M. Sutherland....................... 62,000(6) * 62,000 *
Robert P. Murphy............................. 83,600(7) * 83,600 *
R. Daniel Robins............................. 12,000(8) * 12,000 *
Jack O. Nutter, II........................... 25,000(9) * 25,000 *
John C. Halsted.............................. 0 0
William B. B. Gammell........................ 0 0
Michael E. McMahon........................... 0 0
All directors and executive officers as a
group/10 persons........................... 303,000(10) 1.9% 303,000 1.8%
------------------------
* Less than 1%.
(1) Unless otherwise indicated, each person or group has sole voting and
investment power with respect to all such shares. Unless otherwise
indicated, the number of shares and percentage of ownership of Common Stock
for each of the named stockholders and all directors and executive officers
as a group assumes that shares of Common Stock that the stockholder or
directors and executive officers as a group may acquire within sixty days
of the date of this Prospectus are outstanding.
(2) Does not include up to 562,500 shares of Common Stock that may be sold by
the Company if the Underwriters exercise their over-allotment option in
full.
(3) The business address of Phemus Corporation is 600 Atlantic Avenue, Boston,
Massachusetts 02210-2203.
(4) Based on information provided in a Schedule 13D dated February 17, 1995
filed with the Commission. Includes shares held by a group comprised of
Centennial Associates, L.P., a Delaware limited partnership ("Centennial"),
Centennial Energy Partners, L.P., a Delaware limited partnership ("Energy")
and Joseph H. Reich & Co., Inc. ("JHR & Co."), a New York corporation.
Joseph H. Reich and Peter K. Seldin are general partners of Centennial and
Energy. Mr. Reich is the President, sole shareholder and sole director and
Mr. Seldin is the Vice President of JHR & Co. (i) Centennial owns
beneficially 460,000 shares of Common Stock, approximately 2.9% of the
shares outstanding, (ii) Energy owns beneficially 338,650 shares of Common
Stock, constituting approximately 2.1% of
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the shares outstanding, (iii) JHR & Co. owns beneficially 72,850 shares of
Common Stock, constituting approximately 0.5% of the shares outstanding,
such shares being held by it in a discretionary account managed by JHR &
Co. (the "Managed Account"), and (iv) Mr. Reich and Mr. Seldin are deemed
to each own beneficially 871,500 shares of Common Stock, representing the
aggregate shares held the entities named in (i) through (iii) above. Each
of Centennial and Energy has the power to vote and dispose of the shares of
Common Stock owned by it, which power may be exercised by Mr. Reich and Mr.
Seldin as the general partners of these partnerships. JHR & Co. has the
power to dispose of the shares of Common Stock held by it in the Managed
Account, which power may be exercised by Mr. Reich and Mr. Seldin as
executive officers of JHR & Co. Pursuant to an investment management
agreement, the Managed Account client retains the right to vote the shares
of Common Stock held in the Managed Account. No person other than each
respective record owner of the Common Stock is known to have the right to
receive or the power to direct the receipt of dividends from the proceeds
of the sale of the Common Stock. The business address of Centennial is 900
Third Avenue, New York, New York 10022.
(5) Includes 115,000 shares issuable pursuant to the exercise of stock options
exercisable within sixty days of the date of this Prospectus.
(6) Includes 47,000 shares issuable pursuant to the exercise of stock options
exercisable within sixty days of the date of this Prospectus.
(7) Includes 82,500 shares issuable pursuant to the exercise of stock options
exercisable within sixty days of the date of this Prospectus.
(8) Includes 10,000 shares issuable pursuant to the exercise of stock options
exercisable within sixty days of the date of this Prospectus.
(9) Includes 20,000 shares issuable pursuant to the exercise of stock options
exercisable within sixty days of the date of this Prospectus.
(10) Includes 300 shares of which an executive officer shares voting and
dispositive power with her mother. Includes the 274,500 shares issuable
pursuant to the exercise of stock options exercisable within sixty days of
the date of this Prospectus that are referenced in footnotes (5), (6), (7),
(8) and (9).
RECENT SALE OF SHARES BY CAIRN ENERGY PLC
Cairn Energy PLC completed a public sale of 2,623,000 shares of Common Stock on
June 19, 1995, at a price of $10 per share. The sale was made pursuant to a
registration statement filed on Form S-3 under the Securities Act. As a result
of this sale, Cairn Energy PLC is no longer a stockholder of the Company.
SELLING STOCKHOLDER
As of the date of this Prospectus, the Selling Stockholder owned 5,500,000
shares, or approximately 34.4% of the issued and outstanding shares of Common
Stock. After the Selling Stockholder's sale of 2,750,000 shares of Common Stock
in the Offering, the Selling Stockholder will hold 2,750,000 shares or
approximately 16.2% of the outstanding Common Stock (15.7% if the Underwriters'
over-allotment option is exercised in full).
The Selling Stockholder is an indirect wholly-owned subsidiary of the President
and Fellows of Harvard College and was the sole stockholder of Smith. In October
1994 the Company completed the Smith Acquisition, whereby the Company acquired
substantially all of the Smith Assets in exchange for shares of Common Stock and
the assumption of certain liabilities related to the Smith Assets. At the
closing of the Smith Acquisition, 3,500,000 shares of Common Stock were issued
to Smith and an additional 1,000,000 shares of Common Stock were placed in
escrow, to be distributed to Smith or revert to the Company based on certain
valuation criteria that were to be applied to the Smith Assets. Under the terms
of the Smith Acquisition agreement, unless the Smith Assets had a value (based
upon the defined criteria) as of June 30, 1995 equal to at least $22,350,000,
the Selling Stockholder was required to return 1,000,000 shares
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of the Company Common Stock held in escrow and to pay $3.9 million to the
Company. Simultaneously with the closing of the Smith Acquisition the Selling
Stockholder purchased 2,000,000 shares of the Company's Common Stock at $7.50
per share from the former principal stockholder of the Company.
On the basis of preliminary engineering valuations of the Smith Assets, the
Selling Stockholder and the Company agreed that the Selling Stockholder would
return to the Company the 1,000,000 shares of Common Stock held in escrow and
pay $3.9 million in cash to the Company. The return of the escrow shares and the
cash payment to the Company were effected in August 1995. The rate of drilling
activity on the Smith Assets has lagged significantly behind expectations at the
time of the Smith Acquisition. A total of seven wells were drilled on the Smith
Assets from the acquisition date to June 30, 1995, of which six wells were
successful. Further wells remain to be drilled on the Smith Assets. Although the
consideration paid for the Smith Assets has been fixed, the Company will
continue to receive value from participation in any reserve additions which may
be achieved in the future.
In connection with the Smith Acquisition, the Company granted the Selling
Stockholder certain registration rights with respect to its shares of Common
Stock pursuant to the Phemus Registration Rights Agreement. The registration of
the shares of Common Stock offered hereby by the Selling Stockholder has been
undertaken by the Company as a demand registration under the Phemus Registration
Rights Agreement. See "Shares Eligible for Future Sale."
SHARES ELIGIBLE FOR FUTURE SALE
As of the date of this Prospectus, there were 15,983,150 shares of Common Stock
outstanding. All outstanding shares of Common Stock, other than the shares held
by the Selling Shareholder and 274,500 shares held by or issuable to certain
directors and officers of the Company under options exercisable within 60 days
of the date of this Prospectus, will be eligible for sale without restriction
under the Securities Act. The shares of Common Stock held by such directors and
officers will be eligible for sale subject to the volume limitations of Rule 144
under the Securities Act because such shares are subject to an effective
registration statement under the Securities Act and they are held by
"affiliates" of the Company. The 2,750,000 shares of Common Stock to be owned by
the Selling Shareholders after the Offering will not be eligible for sale under
Rule 144 until October 10, 1996 and thereafter will continue to be subject to
the volume limitations under Rule 144 until such time as the Selling Stockholder
is no longer deemed an "affiliate" of the Company.
In general, under Rule 144 as currently in effect, a person (or persons whose
shares are required to be aggregated) who has beneficially owned shares for at
least two years, including an "affiliate" as that term is defined under the
Securities Act, is entitled to sell, within any three-month period, a number of
shares that does not exceed the greater of: (a) one percent of the then
outstanding shares of the Company's Common Stock or (b) an amount equal to the
average weekly reported volume of trading in such shares during the four
calendar weeks preceding such sale. A person (or persons whose shares are
required to be aggregated) who is not deemed an "affiliate" of the Company and
who has beneficially owned shares for at least three years is entitled to sell
such shares under Rule 144(k) without regard to these volume limitations and
certain other requirements of Rule 144.
Restricted shares also may be sold pursuant to a registration statement filed by
the Company under the Securities Act in the future or another exemption from
registration that might be available without compliance with the requirements of
Rule 144.
The Company has provided registration rights to the Selling Stockholder with
respect to shares it acquired from the Company in the Smith Acquisition and from
Cairn PLC under the Stock Purchase Agreement (the "Phemus Registrable
Securities"). Under the Phemus Registration Rights Agreement the Selling
Stockholder will have the right to two demand registrations, provided that a
registration is not within 180 days after the effective date of a registration
statement for an underwritten public offering of Company securities and that the
request covers at least the lesser of (i) 20% percent of the Phemus Registrable
Securities outstanding as of the closing of the Smith Acquisition, (ii) the
number of Phemus Registrable Securities whose aggregate
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offering price is expected to be at least $20,000,000, or (iii) 1,000,000 shares
of the Common Stock. The Company is not obligated to effect any Securities Act
registration (a) if the registration request is made within 180 days of the
effective date of an underwritten public offering of securities for the account
of the Company, (b) if the Company will be conducting an underwritten public
offering of equity securities (or securities convertible into equity securities)
within 90 days of such request, or (c) if the Board of Directors determines that
it would not be in the best interests of the Company and its stockholders for
such a registration to be filed at that time. The Company may not defer the
registration based on (b) or (c) above more than once in any 12 month period.
The Phemus Registration Rights Agreement was executed in connection with the
closing of the Smith Acquisition.
The Phemus Registration Rights Agreement also provides that the Selling
Stockholder has the right to request a registration of the Phemus Registrable
Securities on Form S-3 under the Securities Act at any time. The Company,
however, will not be obligated to effect any such registration if (i) Form S-3
is not available to the Company, (ii) the aggregate net offering proceeds (after
deduction of underwriting discounts and commissions) of the securities specified
in such request is not at least $2,000,000, (iii) the Company has already
effected two registrations on Form S-3 within the previous 12-month period, or
(iv) if the Board of Directors determines that it would not be in the best
interest of the Company and stockholders to effect such Form S-3 registration at
such time, in which event the Company would have the right to defer the filing
of the Form S-3 registration for up to 120 days after receiving the Phemus
registration request. The Company may not utilize a right due to the
circumstances in (iv) above more than once in any 12-month period. The
Registration Statement of which this Prospectus is a part has been filed in
response to the Selling Stockholder's first exercise of such a Form S-3
registration right under the Phemus Registration Rights Agreement.
The Phemus Registration Rights Agreement also provides that the Selling
Stockholder will have piggyback registration rights to include Phemus
Registrable Securities in certain Securities Act registrations filed by the
Company.
The Company will pay for all expenses, other than underwriting discounts and
commissions, relating to the registration of securities by the Selling
Stockholder under the Phemus Registration Rights Agreement. The Company will not
be required, however, to pay for any expenses of the registration of Phemus'
Registrable Securities on Form S-3 after the Selling Stockholder has
participated in four such registrations.
The Selling Stockholder and the Company and its officers have agreed that,
without the prior written consent of S.G.Warburg & Co. Inc., they will not sell
or otherwise dispose of any shares of Common Stock for a period of 180 days
after the date of this Prospectus, other than as gifts to family members and
transfers to wholly-owned affiliates. See "Underwriting."
No prediction can be made as to the effect, if any, that future sales of shares,
or the availability of shares for future sales, will have on the market price of
the Common Stock prevailing from time to time. Nevertheless, sales of
substantial amounts of Common Stock in the public market (including shares
issued upon the exercise of options that may be granted pursuant to an employee
stock option or other equity plan of the Company), or the perception that such
sales may occur, could adversely affect market prices for the Common Stock.
DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 30,000,000 shares of
Common Stock, par value $.01 per share, and 5,000,000 shares of Preferred Stock,
par value $.01 per share.
COMMON STOCK
As of the date of this Prospectus, there were 15,983,150 shares of Common Stock
outstanding and held of record by 676 stockholders.
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Holders of Common Stock are entitled to one vote for each share held on all
matters submitted to a vote of stockholders and do not have cumulative voting
rights. Accordingly, holders of a majority of the shares of Common Stock
entitled to vote in any election of directors may elect all of the directors
standing for election. Holders of Common Stock are entitled to receive ratably
such dividends, if any, as may be declared by the Board of Directors out of
funds legally available therefor, subject to any preferential dividend rights of
outstanding Preferred Stock. On the liquidation, dissolution or winding up of
the Company, the holders of Common Stock are entitled to receive ratably the net
assets of the Company available after the payment of all debts and other
liabilities and subject to the prior rights of any outstanding Preferred Stock.
Holders of Common Stock have no preemptive, subscription, redemption or
conversion rights. The outstanding shares of Common Stock are, including the
shares to be sold by the Selling Stockholder in the Offering, fully paid and
nonassessable. The rights, preferences and privileges of holders of Common Stock
are subject to, and may be adversely affected by, the rights of the holders of
shares of any series of Preferred Stock that the Company may designate and
execute in the future.
PREFERRED STOCK
The Board of Directors has the authority, without further action of the
stockholders of the Company, to issue up to an aggregate of 5,000,000 shares of
Preferred Stock in one or more series and to fix the designations, preferences,
rights and any qualifications, limitations or restrictions of the shares of each
such series, including the dividend rights, dividend rates, conversion rights,
voting rights, terms of redemption (including sinking fund provisions),
redemption price or prices, liquidation preferences and the number of shares
constituting any series.
The Board of Directors, without stockholder approval, can issue Preferred Stock
with voting and conversion rights that could adversely affect the voting power
of holders of Common Stock. The issuance of Preferred Stock may have the effect
of delaying, deferring or preventing a change in control of the Company. The
Company has no present plans to issue any shares of Preferred Stock after the
completion of the Offering, and none is outstanding.
TRANSFER AGENT AND REGISTRAR
The Transfer Agent and Registrar for the Company's Common Stock is Stock
Transfer Company of America, Inc.
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UNDERWRITING
Subject to the terms and conditions of the Underwriting Agreement entered into
by and among the Company, the Selling Stockholder and each of the Underwriters
named below (the "Underwriters"), the Underwriters have agreed to purchase from
the Company and the Selling Stockholder and the Company and the Selling
Stockholder have agreed to sell to the Underwriters the respective number of
shares of Common Stock set forth opposite their names.
NUMBER
UNDERWRITER OF SHARES
------------------------------------------------------------------------- ---------
S.G.Warburg & Co. Inc.................................................... 1,250,000
Howard, Weil, Labouisse, Friedrichs Incorporated......................... 1,250,000
Petrie Parkman & Co., Inc................................................ 1,250,000
The Underwriting Agreement provides that the obligations of the Underwriters to
pay for and accept delivery of the shares of Common Stock offered hereby are
subject to the approval of certain legal matters by its counsel and to certain
other conditions. The Underwriters are obligated to take and pay for all of the
shares of Common Stock offered hereby if any such shares are taken and all such
conditions are satisfied.
The Underwriters propose to offer part of the Common Stock directly to the
public at the Price to Public set forth on the cover page hereof and part to
certain dealers at such price, less a concession not in excess of $0.3375 per
share. The Underwriters may allow, and such dealers may reallow, a concession
not in excess of $0.10 per share to certain dealers.
Pursuant to the Underwriting Agreement, the Company has granted the Underwriters
an option, exercisable for 30 days from the date of this Prospectus, to purchase
up to an aggregate of 562,500 additional shares of Common Stock at the Price to
Public set forth on the cover page hereof, less underwriting discounts and
commissions. The Underwriters may exercise such option to purchase solely for
the purpose of covering over-allotments, if any, made in connection with the
sale of shares of Common Stock offered hereby. To the extent such option is
exercised, each Underwriter will become obligated, subject to certain
conditions, to purchase approximately the same percentage of such additional
shares as the number set forth next to such Underwriter's name in the preceding
table bears to the total number of shares of Common Stock offered by the
Underwriters hereby.
The Selling Stockholder and its affiliates and the Company and its officers have
agreed that, without the prior written consent of S.G.Warburg & Co. Inc., they
will not sell or otherwise dispose of any shares of Common Stock for a period of
180 days after the date of this Prospectus, other than transfers to wholly-owned
affiliates. See "Shares Eligible for Future Sale."
In connection with the Offering, certain Underwriters and selling group members
(if any) of their respective affiliates who are qualifying registered market
makers on NASDAQ, may engage in passive market making transactions in the Common
Stock on NASDAQ in accordance with Rule 10b-6A under the Securities Exchange Act
of 1934 during the two business day period before commencement of offers or
sales of the Common Stock. The passive market making transactions must comply
with applicable volume and price limits and be identified as such. In general, a
passive market maker may display its bid at a price not in excess of the highest
independent bid for the security; if all independent bids are lowered below the
passive market maker's bid, however, such bid must then be lowered when certain
purchase limits are exceeded.
The Company, the Selling Stockholder and the Underwriters have agreed to
indemnify each other against certain liabilities, including liabilities under
the Securities Act.
LEGAL MATTERS
The validity of the issuance of the Common Stock offered hereby will be passed
upon for the Company by Jenkens & Gilchrist, a Professional Corporation, Dallas,
Texas and for the Selling Stockholder by Ropes & Gray, Boston, Massachusetts.
Certain legal matters relating to this Offering will be passed upon for the
Underwriters by Holme Roberts & Owen LLC, Denver, Colorado.
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EXPERTS
The consolidated financial statements of the Company at December 31, 1993 and
1994 and for each of the three years in the period ended December 31, 1994
appearing in this Prospectus and Registration Statement have been audited by
Ernst & Young LLP, independent auditors, as set forth in their report thereon
appearing elsewhere herein and in the Registration Statement and are included in
reliance upon such report given upon the authority of such firm as experts in
accounting and auditing.
The audited financial statements of Smith that are included in the Company's
Prospectus dated October 11, 1994 and in the Company's Proxy Statement relating
to a special meeting of stockholders held on October 10, 1994 have been audited
by Arthur Andersen LLP, independent public accountants, as set forth in their
reports thereon, included therein and incorporated herein by reference in
reliance upon the authority of said firm as experts in giving said reports.
The Reserve Review Letter of Ryder Scott as set forth in this Prospectus and
incorporated by reference in this Prospectus has been included herein in
reliance upon the authority of that firm as an expert in petroleum engineering.
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance
therewith files reports, proxy statements and other information with the
Commission. Such reports, proxy statements and other information can be
inspected and copied at the public reference facilities maintained by the
Commission at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington,
D.C. 20549 and at the following Regional Offices of the Commission: The Chicago
Regional Office, Northwestern Atrium Center, 500 West Madison Street, Suite
1400, Chicago, Illinois 60661 and the New York Regional Office, 7 World Trade
Center, 12th Floor, New York, New York 10048, at prescribed rates. Such reports,
proxy statements and other information concerning the Company can also be
inspected at the offices of the National Association of Securities Dealers,
Inc., 1735 K Street, N.W., Washington, D.C. 20006.
ADDITIONAL INFORMATION
The Company has filed with the Commission a Registration Statement on Form S-3
under the Securities Act with respect to the Common Stock offered hereby. This
Prospectus does not contain all the information set forth in the Registration
Statement and the exhibits and schedules thereto. Such additional information
can be obtained from the Commission's principal office in Washington, D.C.
Statements in this Prospectus concerning provisions of documents filed with the
Registration Statement as exhibits are necessarily summaries of such documents,
and each statement is qualified in its entirety by reference to the copy of the
applicable document filed with the Commission.
DOCUMENTS INCORPORATED BY REFERENCE
The following documents or portions thereof filed by the Company are hereby
incorporated by reference in this Prospectus:
(i) the Company's Annual Report on Form 10-K for the year ended December
31, 1994, filed with the Commission on March 15, 1995, and Amendment
Number 1 on Form 10-K/A filed with the Commission on April 10, 1995;
(ii) the Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, filed with the Commission on May 2, 1995;
(iii) The Company's Quarterly Report on Form 10-Q for the quarter ended
June 30, 1995, filed with the Commission on August 3, 1995;
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(iv) the Company's Proxy Statement for its 1995 Annual Meeting, filed
with the Commission on April 4, 1995;
(v) the Financial Statements of Smith Offshore Exploration Company II and
the Pro Forma Combined Financial Statements contained in the
Company's Proxy Statement for its Special Meeting of Stockholders
held October 10, 1994, filed with the Commission on September 19,
1994;
(vi) the Financial Statements of Smith Offshore Exploration Company II
contained in the Prospectus dated October 11, 1994, filed with the
Commission on October 13, 1994, pursuant to Rule 424(b) and included
in the Company's Registration Statement on Form S-3 (Registration No.
33-84206); and
(vii) the description of the Common Stock set forth in the Registration
Statement on Form 8-A, filed with the Commission on January 29, 1982,
including any amendment or report filed for the purpose of updating
such description.
In addition, all documents subsequently filed by the Company pursuant to
Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this
Prospectus and prior to the termination of the Offering of Common Stock made
hereby shall be deemed to be incorporated by reference into this Prospectus and
to be a part hereof from the date of filing of such documents. Any statement
contained herein or in a document incorporated or deemed to be incorporated by
reference herein shall be deemed to be modified or superseded for the purposes
of this Prospectus to the extent that a statement contained herein or in any
subsequently filed document which is or is deemed to be incorporated by
reference herein modifies or supersedes such statement. Any such statement so
modified or superseded shall not be deemed, except as so modified or superseded,
to constitute a part of this Prospectus.
The Company will provide without charge to each person to whom a copy of this
Prospectus is delivered, upon oral or written request of such person, a copy of
any and all of the documents incorporated by reference herein (other than
exhibits and schedules to such documents, unless such exhibits or schedules are
specifically incorporated by reference into such documents). Such requests
should be directed to A. Allen Paul, Vice President-Finance, Cairn Energy USA,
Inc., 8235 Douglas Avenue, Suite 1221, Dallas, Texas 75225 or by telephone at
(214) 369-0316.
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GLOSSARY
2-D SEISMIC. The method by which an image of the earth's subsurface is created
through the interpretation of collected seismic data.
3-D SEISMIC. The method by which a three dimensional image of the earth's
subsurface is created through the interpretation of collected seismic data. 3-D
Seismic surveys allow for a more detailed understanding of the subsurface than
do conventional surveys and contribute significantly to field appraisal,
development and production.
AVO ANALYSIS. A geophysical technique that when applied under certain
conditions allows interpreters to distinguish gas bearing sands from other
bright spot causes such as hard streaks, wet sands and lignite.
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 natural gas equivalents using a conversion rate
of six thousand cubic feet of natural gas for each barrel of oil.
DEVELOPED ACREAGE. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
DEVELOPMENT WELL. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
DISCOUNTED PRESENT VALUE. A method of determining the present value of proved
reserves. Under the Commission method, the future net revenues before income
taxes from proved reserves are estimated assuming that oil and natural gas
prices and production costs remain constant. The resulting stream of revenues is
then discounted at the rate of 10% per year to obtain the present value.
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 drilled 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.
FARM-OUT/FARM-IN. An agreement pursuant to which the owner of a working
interest in an oil and gas lease delivers the contractual right to earn the
working interest or a portion thereof to another party who desires to drill on
the leased acreage. Generally, the assignee is required to drill one or more
wells in order to earn a working interest in the acreage. The assignor usually
retains a royalty or a working interest in the lease after payout. The assignor
is said to have "farmed-out" the acreage. The assignee is said to have
"farmed-in" the acreage.
FINDING COSTS. Expressed in dollars per Mcfe, an amount calculated by dividing
the amount of total capital expenditures by the amount of total reserves added
during the same period as a result of drilling activities, property
acquisitions, reserve revisions and improved recovery.
GROSS ACRES OR GROSS WELLS. The total acres or wells, as the case may be, in
which a working interest is owned.
MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons.
MCF. One thousand cubic feet.
MCFE. One thousand cubic feet of natural gas equivalents using a conversion
rate of six thousand cubic feet of natural gas for each barrel of oil.
MMBBLS. One million barrels of crude oil or other liquid hydrocarbons.
46
48
MMBTU. One million British thermal units.
MMCF. One million cubic feet.
MMCFE. One million cubic feet of natural gas equivalents using a conversion
rate of six thousand cubic feet of natural gas for each barrel of oil.
NET ACRES OR NET WELLS. The sum of the fractional working interests owned in
gross acres or gross wells.
PAY. An industry term used to describe reservoirs in the subsurface that
contain hydrocarbons.
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 and 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.
ROYALTY INTEREST. An interest in an oil and gas property entitling the owner to
a share of oil and gas production free of costs of production.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
WORKING INTEREST. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.
47
49
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Report of Independent Auditors......................................................... F-2
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1993 and 1994
and June 30, 1995 (unaudited)..................................................... F-3
Consolidated Statements of Operations for the years ended
December 31, 1992, 1993, and 1994 and the six months ended
June 30, 1994 and 1995 (unaudited)................................................ F-4
Consolidated Statements of Stockholders' Equity for the years
ended December 31, 1992, 1993, and 1994 and the six months
ended June 30, 1994 and 1995 (unaudited).......................................... F-5
Consolidated Statements of Cash Flows for the years ended
December 31, 1992, 1993, and 1994 and the six months ended
June 30, 1994 and 1995 (unaudited)................................................ F-6
Notes to Consolidated Financial Statements........................................... F-7
F-1
50
REPORT OF INDEPENDENT AUDITORS
Board of Directors
Cairn Energy USA, Inc.
We have audited the accompanying consolidated balance sheets of Cairn Energy
USA, Inc. (the Company), as of December 31, 1993 and 1994, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
each of the three years in the period ended December 31, 1994. 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 consolidated financial position of Cairn
Energy USA, Inc., at December 31, 1993 and 1994, and the consolidated results of
its operations and its cash flows for each of the three years in the period
ended December 31, 1994, in conformity with generally accepted accounting
principles.
ERNST & YOUNG LLP
February 17, 1995
F-2
51
CAIRN ENERGY USA, INC.
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
ASSETS
DECEMBER 31,
--------------------- JUNE 30,
1993 1994 1995
-------- -------- -----------
(UNAUDITED)
Current assets:
Cash and cash equivalents................................ $ 343 $ 2,182 $ 1,553
Accounts receivable...................................... 2,504 2,031 5,451
Receivable from Phemus Corporation....................... -- -- 3,900
Receivable from Cairn Energy PLC......................... -- 48 --
Prepaid expenses......................................... 168 136 625
-------- -------- --------
Total current assets............................. 3,015 4,397 11,529
Property and equipment, at cost:
Oil and gas properties, based on full-cost accounting.... 87,586 129,758 141,846
Other equipment.......................................... 508 564 638
-------- -------- --------
88,094 130,322 142,484
Less accumulated depletion, depreciation, and
amortization.......................................... 42,106 46,373 53,066
-------- -------- --------
45,988 83,949 89,418
Deferred charges, net of amortization...................... 625 835 713
-------- -------- --------
Total assets..................................... $ 49,628 $ 89,181 $ 101,660
======== ======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable......................................... $ 475 $ 1,286 $ 445
Accrued lease operating expenses......................... 694 528 666
Accrued well costs....................................... 647 1,701 2,456
Deferred revenue......................................... -- 152 67
Other accrued liabilities................................ 322 216 255
Current maturities of long-term debt..................... -- -- 4,188
-------- -------- --------
Total current liabilities........................ 2,138 3,883 8,077
Long-term debt............................................. 9,600 23,500 29,312
Contingencies (Notes 3, 7, and 8).......................... -- -- --
Stockholders' equity:
Preferred stock, $.01 par value: 5,000,000 shares
authorized............................................ -- -- --
Common stock, $.01 par value: 30,000,000 shares
authorized; shares issued and outstanding: December
31, 1993 -- 12,463,080 and December 31,
1994 -- 15,963,080 and June 30, 1995 -- 15,983,150.... 125 160 160
Additional paid-in capital................................. 54,764 77,983 78,085
Accumulated deficit........................................ (16,999) (16,345) (13,974)
-------- -------- --------
Total stockholders' equity....................... 37,890 61,798 64,271
-------- -------- --------
Total liabilities and stockholders' equity....... $ 49,628 $ 89,181 $ 101,660
======== ======== ========
See accompanying notes.
F-3
52
CAIRN ENERGY USA, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------ ------------------
1992 1993 1994 1994 1995
------- ------- ------ ------ -------
(UNAUDITED)
Revenues:
Oil and gas.............................. $14,035 $13,490 $9,494 $5,355 $12,808
Other.................................... 60 59 206 26 75
------- ------- ------ ------ -------
Total revenues................... 14,095 13,549 9,700 5,381 12,883
Expenses:
Lease operating expenses and
production taxes...................... 3,766 3,826 2,274 1,278 1,563
Depletion, depreciation, and
amortization.......................... 6,792 5,654 4,328 2,318 6,772
Administrative expense................... 774 1,266 1,330 739 820
Interest................................. 1,193 1,045 1,114 445 1,357
------- ------- ------ ------ -------
Total expenses................... 12,525 11,791 9,046 4,780 10,512
------- ------- ------ ------ -------
Income before minority interest and
extraordinary item....................... 1,570 1,758 654 601 2,371
Minority interest in net loss of Omni...... 245 -- -- -- --
------- ------- ------ ------ -------
Income before extraordinary item........... 1,815 1,758 654 601 2,371
Extraordinary item -- loss on early
extinguishment of debt................... -- (284) -- -- --
------- ------- ------ ------ -------
Net income................................. $ 1,815 $ 1,474 $ 654 $ 601 $ 2,371
======= ======= ====== ====== =======
Net income per common and common equivalent
share:
Income before extraordinary item......... $ .18 $ .16 $ .05 $ .05 $ .15
======= ======= ====== ====== =======
Net income............................... $ .18 $ .13 $ .05 $ .05 $ .15
======= ======= ====== ====== =======
Weighted average common and common
equivalent shares used in per share
computations............................. 10,048 11,260 13,259 12,463 15,970
======= ======= ====== ====== =======
See accompanying notes.
F-4
53
CAIRN ENERGY USA, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
PREFERRED STOCK COMMON STOCK ADDITIONAL TOTAL
--------------- --------------- PAID-IN ACCUMULATED STOCKHOLDERS'
SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT EQUITY
------ ------ ------ ------ ---------- ----------- -------------
Balance at
December 31, 1991...................... 200 $ 2 7,992 $ 80 $ 40,667 $ (20,288) $20,461
Adjustments to reflect shares held by
minority stockholders of Omni
following the merger with Omni...... -- -- 480 5 612 -- 617
Net income............................. -- -- -- -- -- 1,815 1,815
---- --- ------ ---- ------- -------- -------
Balance at
December 31, 1992...................... 200 2 8,472 85 41,279 (18,473) 22,893
Common stock issued for cash, net...... -- -- 4,000 40 17,093 -- 17,133
Redemption of preferred stock.......... (200) (2) -- -- (3,598) -- (3,600)
Other.................................. -- -- (9) -- (10) -- (10)
Net income............................. -- -- -- -- -- 1,474 1,474
---- --- ------ ---- ------- -------- -------
Balance at
December 31, 1993...................... -- -- 12,463 125 54,764 (16,999) 37,890
Common stock issued for oil and gas
assets of Smith..................... -- -- 3,500 35 23,219 -- 23,254
Net income............................. -- -- -- -- -- 654 654
---- --- ------ ---- ------- -------- -------
Balance at
December 31, 1994...................... -- -- 15,963 160 77,983 (16,345) 61,798
Exercise of stock options
(unaudited)......................... -- -- 20 -- 102 -- 102
Net income (unaudited)................. -- -- -- -- -- 2,371 2,371
---- --- ------ ---- ------- -------- -------
Balance at June 30, 1995 (unaudited)..... -- $ -- 15,983 $160 $ 78,085 $ (13,974) $64,271
==== === ====== ==== ======= ======== =======
See accompanying notes.
F-5
54
CAIRN ENERGY USA, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------- -------------------
1992 1993 1994 1994 1995
------- -------- -------- ------- --------
(UNAUDITED)
OPERATING ACTIVITIES
Net income................................ $ 1,815 $ 1,474 $ 654 $ 601 $ 2,371
Adjustments to reconcile net income to net
cash provided by operating activities:
Depletion, depreciation, and
amortization......................... 6,792 5,654 4,328 2,319 6,772
Amortization of loan costs.............. 97 130 188 91 177
Minority interest in net loss of Omni... (245) -- -- -- --
Extraordinary item...................... -- 284 -- -- --
Loss on disposal of other equipment..... 12 -- 35 -- --
Changes in operating assets and
liabilities:
Accounts receivable.................. 394 (40) 473 590 (3,420)
Note receivable...................... 5 54 -- -- --
Prepaid expenses..................... (61) 52 32 (113) (489)
Accounts payable..................... 79 37 811 370 (841)
Accrued liabilities.................. 47 922 (272) (994) 177
Deferred revenue..................... -- -- 152 -- (85)
Advances (repayments) from (to) Cairn
Energy PLC......................... (463) (184) (48) 280 48
------- -------- -------- ------- --------
Net cash provided by operating
activities.............................. 8,472 8,383 6,353 3,144 4,710
INVESTING ACTIVITIES
Exploration and development
expenditures............................ (5,739) (10,093) (20,501) (6,407) (17,066)
Acquisition of oil and gas assets of
Smith................................... -- -- (281) -- --
Acquisition of Omni....................... (1,963) -- -- -- --
Proceeds from sale of oil and gas
properties.............................. 149 747 3,727 276 1,833
Additions to other equipment.............. (37) (173) (157) (44) (153)
Proceeds from disposal of other
equipment............................... 16 -- 4 -- --
Other..................................... -- -- -- (72) --
------- -------- -------- ------- --------
Net cash used in investing activities..... (7,574) (9,519) (17,208) (6,247) (15,386)
FINANCING ACTIVITIES
Issuance of common stock.................. -- 17,133 -- -- 102
Redemption of preferred stock............. -- (3,600) -- -- --
Repayment of advances from Cairn
Energy PLC.............................. -- (2,608) -- -- --
Proceeds from long-term debt.............. 500 20,700 14,000 3,500 10,000
Reductions of long-term debt.............. (712) (30,335) (100) (100) --
Financing costs and other................. -- (726) (1,206) (131) (55)
------- -------- -------- ------- --------
Net cash provided by (used in) financing
activities.............................. (212) 564 12,694 3,269 10,047
Increase (decrease) in cash and cash
equivalents............................. 686 (572) 1,839 166 (629)
Cash and cash equivalents at beginning
of year................................. 229 915 343 343 2,182
------- -------- -------- ------- --------
Cash and cash equivalents at end of
year.................................... $ 915 $ 343 $ 2,182 $ 509 $ 1,553
======= ======== ======== ======= ========
Supplemental cash flow
information -- interest paid in cash.... $ 1,099 $ 941 $ 943 $ 376 $ 1,185
======= ======== ======== ======= ========
See accompanying notes.
F-6
55
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
1. BASIS OF PRESENTATION
On February 27, 1992, Cairn Energy USA, Inc. (Cairn), a wholly owned subsidiary
of Cairn Energy PLC, purchased from Lewex, Inc., all of its shares of Omni
Exploration, Inc. (Omni), an oil and gas exploration and production company.
Under the agreement, Cairn purchased 14,175,165 shares of Omni for $1,150,000
(the Cairn Purchase), among other things. This purchase gave Cairn approximately
64% ownership of Omni.
Effective September 29, 1992, Omni's stockholders approved amendments to Omni's
Certificate of Incorporation effecting a 1-for-1,000 reverse stock split (the
Reverse Stock Split) of Omni's common stock, par value $0.01 per share (Common
Stock), and a 70-for-1 forward stock split (the Forward Stock Split) of Common
Stock, effective immediately after the Reverse Stock Split. In addition, Omni's
stockholders approved the adoption of the Agreement and Plan of Merger dated as
of June 29, 1992 (the Merger Agreement), providing for the merger (the Merger)
of Cairn with and into Omni, with Omni being the surviving corporation. Upon
consummation of the Merger, Cairn Energy PLC received 7,992,260 shares of Common
Stock and 200,000 shares of new Series A Preferred Stock, par value $0.01 per
share, of Omni (the Series A Preferred Stock), resulting in Cairn Energy PLC
owning approximately 95% of the capital stock of Omni. Upon consummation of the
Merger, Omni's Certificate of Incorporation was amended to change Omni's name to
Cairn Energy USA, Inc. (the Company).
The Cairn Purchase, the Reverse Stock Split, the Forward Stock Split, and the
Merger have been accounted for as a purchase of Omni by Cairn. Accordingly, the
results of operations and financial position of the Company for periods and
dates prior to the Merger are the historical results of operations and financial
position of Cairn for such periods and dates. The aggregate purchase price of
approximately $1.9 million (consisting of cash used to effect the Cairn
Purchase, the Reverse Stock Split, the Merger, and the estimated fair value of
the shares held by the minority stockholders following the Merger) was allocated
to the net Omni assets acquired, principally oil and gas properties. All
historical share and per share amounts of Cairn for periods prior to the
effective date of the Merger have been retroactively adjusted to reflect the
shares issued to Cairn Energy PLC in the Merger.
The acquisition of Omni (for accounting purposes) did not have a material impact
on the Company's results of operations or financial position.
The consolidated financial statements include the accounts of the Company and
its wholly owned subsidiary. All intercompany accounts and transactions have
been eliminated in consolidation.
Cairn Energy PLC pays certain operating and administrative expenses for the
Company. Any of these payments that have not been reimbursed by the Company are
classified as "Advances from Cairn Energy PLC" in current liabilities. Amounts
reimbursed in excess of these payments are classified as "Receivable from Cairn
Energy PLC" in current assets.
The Company is engaged in the exploration for and production of oil and gas.
The financial information for the six-month periods ended June 30, 1994 and
1995, has not been audited but, in the opinion of management of the Company,
reflects all adjustments (consisting only of normal recurring adjustments)
necessary for a fair presentation of the Company's financial position at June
30, 1995, and the results of its operations and its cash flows for the six
months ended June 30, 1994 and 1995. Results of operations for interim periods
are not necessarily indicative of results of operations for the respective full
years.
F-7
56
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
2. SIGNIFICANT ACCOUNTING POLICIES
Property and Equipment
The Company follows the full-cost method of accounting for its investments in
oil and gas properties. The Company capitalizes all direct and certain indirect
costs associated with acquisition, exploration, and development costs of oil and
gas properties. Proceeds from sales of oil and gas properties are credited to
the full-cost pool. Capitalized costs of oil and gas properties are amortized on
a unit-of-production method using proved oil and gas reserves as determined by
independent petroleum engineers. Costs amortized include all capitalized costs
(less accumulated amortization); the estimated future expenditures (based on
current costs) to be incurred in developing proved reserves; and estimated
dismantlement, restoration, and abandonment costs. Estimated future abandonment,
dismantlement, and site restoration costs include costs to dismantle, relocate,
and dispose of the Company's offshore production platforms, gathering systems,
wells, and related structures. Such costs related to onshore properties, net of
estimated salvage values, are not expected to be significant.
The Company capitalized approximately $476,000, $615,000, $866,000, $430,000,
and $670,000 of internal costs during the years ended December 31, 1992, 1993,
1994, and the six months ended June 30, 1994 and 1995, respectively. Such
capitalized costs include salaries and related benefits of individuals directly
involved in the Company's acquisition, exploration, and development activities,
based on a percentage of their time devoted to such activities.
Under rules of the Securities and Exchange Commission (SEC) for the full-cost
method of accounting, the net carrying value of oil and gas properties is
limited to the sum of the present value (10% discount rate) of estimated future
net cash flows from proved reserves, based on period-end prices and costs, plus
the lower of cost or estimated fair value of unproved properties.
Furniture and equipment are depreciated on a straight-line basis based on the
estimated useful lives of the respective assets.
Cash and Cash Equivalents
Cash and cash equivalents include certificates of deposit or other highly liquid
investments with maturities of three months or less when purchased.
Deferred Charges
Deferred charges include loan costs that are amortized on a straight-line basis
over the terms of the respective loans. Accumulated amortization at December 31,
1993 and 1994, was $89,000 and $260,000, respectively.
Concentrations of Credit Risk
The Company operates exclusively in the oil and gas industry in the United
States. Accounts receivable terms are generally for 30 days. The Company does
not require collateral. Management periodically performs reviews as to the
creditworthiness of their customers. The Company has not sustained any
significant credit losses on sales of oil and gas.
Overhead Reimbursement Fees
Fees from overhead charges billed to working-interest owners, including the
Company, of $135,000, $429,000 and $192,000 for the years ended December 31,
1992, 1993, and 1994, respectively, have been
F-8
57
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
classified as a reduction of general and administrative expenses in the
accompanying consolidated statements of operations.
Gas Imbalances
The Company follows the sales method of accounting for gas imbalances, which
recognizes over and under lifts of gas when sold, to the extent sufficient gas
reserves or balancing agreements are in place.
Earnings (Loss) Per Common Share
Earnings (loss) per common share data is computed using the weighted average
number of common shares and dilutive common equivalent shares outstanding. For
purposes of these computations, the Series A Preferred Stock is classified as a
common stock equivalent. Fully diluted earnings per share data is not presented
because it would not differ from the amounts shown.
Reclassifications
Certain reclassifications have been made to prior years' amounts to conform to
current presentation.
3. ACQUISITION OF OIL AND GAS ASSETS OF SMITH OFFSHORE EXPLORATION II
On October 10, 1994, the Company purchased substantially all of the oil and gas
assets (the Assets) of Smith Offshore Exploration II (Smith) from Phemus
Corporation (Phemus), a subsidiary of the President and Fellows of Harvard
College and sole stockholder of Smith, in exchange for 4,500,000 shares of the
Company's common stock, subject to adjustment pursuant to the terms of the
Agreement, and the assumption of certain liabilities related to the Smith
Assets. The acquisition gives the Company interests in 22 additional blocks in
the Outer Continental Shelf of the Gulf of Mexico. The Agreement provided that
1,000,000 of the shares issued be placed in escrow (the Escrow Shares) at the
closing and, thereafter, the Escrow Shares and certain warrants to acquire up to
a maximum of 800,000 shares of Common Stock will be issued to Phemus or returned
to the Company based on a valuation of the Assets at a date to be selected prior
to June 30, 1995, but may be extended under certain circumstances until December
31, 1995.
In order for Phemus to receive all 1,000,000 Escrow Shares, this valuation must
be equal to or greater than $31,500,000. If the valuation is less than
$31,500,000, 100,000 of such Escrow Shares will be returned to the Company for
each $750,000 of value below $33,750,000 (rounded to the nearest $750,000 below
$33,750,000), and the balance will be released to Phemus. If the valuation is
less than $26,250,000, Smith and Phemus, jointly and severally, will be
obligated to pay the Company the amount by which $26,250,000 exceeds the
valuation, up to a maximum of $3,900,000. Accordingly, Phemus was not obligated
to pay the Company any additional amounts for any deficiency below a $22,350,000
valuation (the Minimum Valuation). If the valuation exceeds $36,000,000, the
Company will issue Phemus, in addition to the 4,500,000 shares, a warrant to
purchase additional shares of Common Stock in the amount of 100,000 shares of
Common Stock for each $750,000 of value of the Assets above $33,750,000, up to a
maximum of 400,000 shares. This warrant will be exercisable by the holder
thereof for three years and will provide for an exercise price of $3.75 per
share. If the valuation exceeds $45,000,000, the Company will issue an
additional warrant to Phemus to purchase an additional 400,000 shares at an
exercise price of $7.50 per share, during an exercise term of six months from
the date of issuance. The acquisition of Smith did not have a material effect on
the results of operations of the Company for 1994.
In conjunction with this transaction, the Company's principal shareholder, Cairn
Energy PLC, sold 2,000,000 shares of the Company's common stock to Phemus at a
price of $7.50 per share. Cairn Energy
F-9
58
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
PLC also sold 2,500,000 shares of Company common stock resulting in Cairn Energy
PLC reducing its ownership to approximately 17.5% of the Company's common stock.
On the basis of a preliminary valuation of the Smith properties as of June 30,
1995, by independent petroleum engineers reflecting a range of values below the
Minimum Valuation, Phemus and the Company have entered into an agreement
regarding the purchase price adjustment under the Smith Acquisition Agreement
pursuant to which Phemus has agreed to return the Escrow Shares to the Company
and to pay $3.9 million to the Company. Phemus' obligation to pay $3.9 million
to the Company is reflected as a receivable and a reduction of the cost of the
Smith properties in the Company's June 30, 1995, balance sheet. Such payment is
expected in August 1995. There was no adjustment in the Company's financial
statements for the return of the Escrow Shares because for financial accounting
purposes, the Escrow Shares were never recorded as having been issued.
The rate of drilling activity on the Smith properties lagged significantly
behind expectations at the time of the acquisition. A total of 7 wells were
drilled on the Smith properties from the acquisition date up to June 30, 1995
including one well which was drilling at June 30, 1995 and was suspended in
early July. Of these, 6 wells are successful and further wells remain to be
drilled on the Smith properties. Although the consideration paid for the Smith
properties has been fixed, the Company will continue to participate in any
further reserve additions that may be achieved in the future on the properties
acquired from Smith.
Management's internal estimate of the discounted present value of estimated
future cash flows before income tax of the proved reserves attributable to the
Smith properties as of August 1, 1995 is approximately $17.4 million, computed
in accordance with the Securities and Exchange Commission's definitions and
guidelines as set forth under Business -- Oil and Gas Reserves.
4. LONG-TERM DEBT
In May 1990, the Company negotiated a $25 million revolving credit agreement
with a bank that replaced an existing $30 million facility. The funds available
under this facility were used to refinance the Company's existing bank debt and
for general corporate purposes. The average interest rate on these borrowings
was 5.516% at December 31, 1992. Interest expense related to borrowings under
this revolving credit arrangement for the year ended December 31, 1993, was
$433,784.
On June 11, 1993, the Company entered into a new credit agreement (the ING
Credit Agreement) with Internationale Nederlanden Bank N.V. (ING) for the
establishment of two credit facilities, which together replaced the Company's
previous credit agreement. The Company recorded an extraordinary charge of
approximately $284,000 in 1993 in connection with the write-off of unamortized
issuance costs attributable to the previous credit facility. On September 8,
1993, ING assigned, with the consent of the Company, its rights, interests, and
obligations under the ING Credit Agreement to Internationale Nederlanden (U.S.)
Capital Corporation (INCC). As a result of the assignment, the ING Credit
Agreement became the INCC Credit Agreement. The INCC Credit Agreement was
subsequently amended on October 15, 1993, to reflect lower interest rates and
more favorable terms for the Company. The first credit facility (Facility A) was
a $17 million revolving line of credit, substantially all of the proceeds of
which were used to repay a portion of the outstanding borrowings under the
Company's previous credit agreement. Outstanding borrowings under Facility A
($9.5 million at December 31, 1993) accrued interest payable quarterly at either
ING's fluctuating base rate plus .25% or ING's reserve adjusted Eurodollar rate
plus 2.0%, at the Company's option.
The second facility (Facility B) was an $8 million revolving line of credit.
Facility B ($100,000 at December 31, 1993) also required mandatory prepayments
of principal based on the excess monthly cash
F-10
59
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
flows, as defined, from the Company's interest in East Cameron Blocks 331/332.
Outstanding borrowings under Facility B accrued interest payable quarterly at
either ING's fluctuating base rate plus 1.25% or ING's reserve adjusted
Eurodollar rate plus 3.0%, at the Company's option.
The INCC Credit Agreement was further amended on May 10, 1994. The second
amendment combined the two credit facilities into one facility, increased the
borrowing base from $25 to $30 million, and extended the term of the note.
Outstanding borrowings accrued interest at either INCC's fluctuating base rate
plus .25% or INCC's reserve adjusted Eurodollar rate plus 2.0%, at the Company's
option. On December 20, 1994, the INCC Credit Agreement was amended and restated
(the INCC Restated Credit Agreement) to reflect an increase in the maximum loan
amount to $50 million, to reflect lower interest rates, to extend the term of
the loan, and to include MeesPierson as a participant in the loan. The borrowing
base was established at $40 million. On April 19, 1995, the current borrowing
base was established at $45 million. The INCC Restated Credit Agreement is a
revolving line of credit secured by substantially all of the Company's assets.
It contains financial covenants which require the Company to maintain a ratio of
current assets to current liabilities (excluding the current portion of related
debt) of no less than 1.0 to 1.0 and a tangible net worth of not less than $40
million. The Company is currently in compliance with all such financial
covenants. At December 31, 1994, the Company had outstanding borrowings of $23.5
million under this facility. At June 30, 1995, the Company had outstanding
borrowings of $33.5 million under this facility. Outstanding borrowings accrue
interest at either INCC's fluctuating base rate or INCC's reserve adjusted
Eurodollar rate plus 1.50%, at the Company's option. On March 3, 1996, the
borrowings outstanding under this facility will be converted to a term loan that
requires various quarterly principal payments through December 31, 1998.
Interest is payable quarterly on any base rate borrowings and payable on
maturity of any Eurodollar borrowings. The weighted average interest rate on
borrowings under the facility at December 31, 1994, was 7.7%.
The INCC Restated Credit Agreement does not permit the Company to pay or declare
any cash or property dividends or otherwise make any distribution of capital.
The Company is obligated to pay a quarterly fee equal to one-half of 1% per
annum of the unused portion of the borrowing base under the facility.
The Company's ability to borrow under the INCC Restated Credit Agreement is
dependent upon the reserve value of its oil and gas properties. If the reserve
value of the Company's borrowing base declines, the amount available to the
Company under the INCC Restated Credit Agreement will be reduced and, to the
extent that the borrowing base is less than the amount then outstanding under
the INCC Restated Credit Agreement, the Company will be obligated to repay such
excess amount on 30-days' notice from INCC or to provide additional collateral.
INCC and MeesPierson have substantial discretion in determining the reserve
value of the borrowing base.
In May 1990, the Company combined the two promissory notes with Cairn Energy PLC
into one note for $13 million, with principal and interest at 10.61% due June 1,
1996. The Company also entered into an additional promissory agreement with
Cairn Energy PLC for $3 million, with principal and interest at 9.7% due May 20,
1996. In 1991, the Company used funds withdrawn under its revolving credit
agreement to repay Cairn Energy PLC $3.6 million. Effective December 31, 1991,
the unpaid balance of the Company's notes to Cairn Energy PLC ($12.4 million)
was converted to additional paid-in capital. Interest expense related to notes
payable to Cairn Energy PLC for the year ended December 31, 1991, was
$1,504,397.
At December 31, 1994, the future minimum principal payments on the Company's
long-term debt subsequent to December 31, 1995, were: $8.8 million in 1996; $8.8
million in 1997; and $5.9 million in 1998, based on borrowings outstanding at
December 31, 1994.
F-11
60
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
5. STOCKHOLDERS' EQUITY
The Company's Certificate of Incorporation provides that its Board of Directors
can designate and issue up to 5,000,000 shares of preferred stock, par value
$0.01 per share, in one or more series or classes with such dividend rate,
redemption provisions, liquidation preference, conversion provisions, and voting
rights as the board of directors might designate. In connection with the Merger
(Note 1), the Company issued 200,000 preferred shares designated as Series A
Preferred Stock to Cairn Energy PLC. Each share of Series A Preferred Stock was
convertible, at the holder's option, into 9.68 shares of Common Stock at any
time after September 29, 1993. The Series A Preferred Stock was redeemed in
accordance with its terms on August 9, 1993, at a redemption price of $18.00 per
share.
A public offering of 4,000,000 shares of Common Stock at an offering price of
$4.75 per share was closed on August 6, 1993. The net proceeds, aggregating
approximately $17.1 million, were used to repay $2.6 million of advances from
Cairn Energy PLC, to redeem the Series A Preferred Stock, and to reduce
borrowings under the Company's credit agreement (Note 4) by $10.6 million.
6. INCOME TAXES
In 1992, the Company changed its method of accounting for income taxes from the
deferred method to the liability method required by Financial Accounting
Standard No. 109, "Accounting for Income Taxes." Adoption of the new standard
had no effect on the Company's consolidated financial position at January 1,
1992, or on the consolidated results of its operations for the year then ended.
As permitted under the new rules, prior years' financial statements have not
been restated.
The reconciliation of income taxes computed at the U.S. federal statutory tax
rates to income tax expense for the years ended December 31, 1992, 1993, and
1994, is as follows (in thousands):
LIABILITY METHOD
-------------------------
1992 1993 1994
----- ----- -----
Income tax expense at statutory rate.............................. $ 617 $ 502 $ 222
Utilization of net operating loss................................. (617) (502) (222)
----- ----- -----
$ -- $ -- $ --
===== ===== =====
The computation of the net deferred tax asset (liability) at December 31, 1993
and 1994, follows (in thousands):
1993 1994
------- -------
Deferred tax liabilities:
Property and equipment................................................ $(2,411) $(7,298)
Deferred tax assets:
Net operating loss carryforward....................................... 8,477 12,641
Other................................................................. 45 15
------- -------
6,111 5,358
Less valuation allowance................................................ 6,111 5,358
------- -------
$ -- $ --
======= =======
At December 31, 1994, the Company had net operating loss carryforwards for
federal income tax purposes of approximately $38 million. The net operating
losses will expire principally in 2005 through 2009, if not previously utilized.
Utilization of approximately $2 million of net operating losses is subject to an
annual
F-12
61
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
limitation of $114,000 because of a change of control, as defined in the
Internal Revenue Code, of Omni. As a result of a change in control, as defined,
which occurred in 1993, due to certain changes in ownership of Cairn Energy PLC
and the Company, the Company estimates that utilization of $22 million of the
remaining net operating losses will be limited to approximately $2 million per
year. Utilization of approximately $10.3 million of net operating losses is
subject to an annual limitation of approximately $1 million per year due to the
change in control of Smith. The transactions in connection with the acquisition
of the oil and gas assets of Smith and sales of Common Stock by Cairn Energy PLC
caused a further change in ownership of the Company as defined in the Internal
Revenue Code. The Company's annual limitation due to this change in ownership
exceeds $5 million per year. As a result, the Company does not believe this
stock ownership change will cause any material adverse federal income tax
consequences. Additional net operating loss limitations may be imposed because
of subsequent changes in stock ownership of the Company.
7. EMPLOYEE BENEFIT PLANS
The Company sponsors a plan to provide retirement benefits under the provisions
of Section 401(k) of the Internal Revenue Code (the 401(k) Plan) for all
full-time employees. Employees may elect to contribute up to 15% of their
compensation. The Company matches 200% of the employee's contributions, up to 5%
of the employee's base salary. Benefits under the 401(k) Plan are limited to the
assets of the 401(k) Plan. The Company's contributions to the 401(k) Plan were
$49,768, $75,824, and $98,385 for the years ended December 31, 1992, 1993, and
1994, respectively.
Certain employees of the Company located in its Dallas headquarters are entitled
to participate in the Company's Employee Incentive Bonus Plan, which was adopted
in 1993 and revised in 1994. The Employee Incentive Bonus Plan rewards those
employees when the Company has added proved reserves for the year in excess of
its production for the year, but only when such additional reserves have a
finding and development cost less than $1.00 per Mcf. Under the Employee
Incentive Bonus Plan, the bonus cannot exceed $250,000 in the aggregate and is
allocated among the specified employees based upon preset percentages except
that individual bonuses can not exceed 50% of salary. Any bonus earned for the
year vests and is paid out to the employees in three equal annual installments,
subject to continued employment with the Company. Based on reserve additions,
the Company's employees were awarded bonuses in the aggregate amount of
$228,858, $106,875, and $242,028 for the years ended December 31, 1992, 1993,
and 1994, respectively, under the Employee Incentive Bonus Plan. Such bonuses
are being accrued over the respective vesting periods.
In May 1993, the Company's stockholders ratified the adoption of the 1993 Stock
Option Plan and the 1993 Directors' Stock Option Plan. The 1993 Stock Option
Plan authorizes the granting of incentive stock options and nonstatutory stock
options to key employees, including executive officers and directors of the
Company. The Company's Compensation Committee administers the 1993 Stock Option
Plan. Options granted under the 1993 Stock Option Plan may be either incentive
stock options or nonstatutory stock options, as determined in the discretion of
the Compensation Committee. The exercise price per share for an option shall be
any price determined by the Compensation Committee; provided, however, that the
exercise price per share of incentive stock options shall not be less than the
fair market value of the Common Stock on the date of the grant of the option.
Each option is exercisable in such amounts, at such intervals, and on such terms
as the Compensation Committee determines in its sole discretion. However, no
option shall be exercisable during the six-month period following the date of
its grant, and no option shall be exercisable more than 10 years after the date
of its grant. At December 31, 1994, a total of 400,000 (650,000 at June 30,
1995) shares of Common Stock has been reserved for issuance under the 1993 Stock
Option Plan.
F-13
62
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
The 1993 Directors' Stock Option Plan authorizes the granting of nonstatutory
stock options to directors of the Company who are not and have not been
employees of the Company or any affiliated corporations except Cairn Energy PLC
(a Nonemployee Director). On the date a Nonemployee Director begins each term
that he serves as a member of the Board of Directors, such Nonemployee Director
will automatically receive an option to purchase 10,000 shares of Common Stock.
The exercise price per share for an option granted under the 1993 Directors'
Stock Option Plan shall be the fair market value of the Common Stock on the date
of the grant. Each option is fully exercisable six months after the date of its
grant. However, no option may be exercised more than five years after the date
of its grant. A total of 150,000 shares of Common Stock have been reserved for
issuance under the 1993 Directors' Stock Option Plan.
Option transactions are summarized below:
NUMBER OF OPTION PRICE
SHARES RANGE
--------- ---------------
Outstanding at December 31, 1992................................... -- --
Granted.......................................................... 260,000 $5.125 - $5.75
-------
Outstanding (67,500 options exercisable) at
December 31, 1993................................................ 260,000 $5.125 - $5.75
Granted.......................................................... 200,000 $6.00 - $6.875
-------
Outstanding (171,000 options exercisable) at
December 31, 1994................................................ 460,000 $5.125 - $6.875
=======
8. LEGAL PROCEEDINGS AND CLAIMS
The Company is subject to certain legal proceedings and claims that arise in the
ordinary conduct of its business. In the opinion of management, the amount of
ultimate liability, if any, with respect to these actions, will not materially
affect the consolidated financial condition or results of operations of the
Company.
9. SUPPLEMENTARY INFORMATION
Capitalized Costs Related to Oil and Gas Producing Activities
The following table summarizes capitalized costs related to oil and gas
producing activities and the related amounts of accumulated depletion,
depreciation, and amortization (in thousands):
DECEMBER 31,
---------------------
1993 1994
-------- --------
Proved oil and gas properties................................. $ 87,454 $101,549
Unproven properties........................................... 132 28,209
Accumulated depletion, depreciation, and amortization......... (41,756) (46,012)
-------- --------
Net capitalized costs......................................... $ 45,830 $ 83,746
======== ========
At June 30, 1995, the carrying value of those of the Smith properties which were
held by the Company as proven properties was $19.7 million. The carrying value
of the unproven properties will be considered again in the future for any
possible impairment in the light of further drilling results on the properties.
The cost of unevaluated properties impaired by drilling results or other
economic events is transferred to the full cost pool and amortized.
F-14
63
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
Costs Incurred in Property Acquisition, Exploration, and Development Activities
The table below represents costs incurred in oil and gas producing activities
(in thousands):
YEAR ENDED DECEMBER 31,
------------------------------
1992 1993 1994
------ ------- -------
Acquisition of properties:
Proved.................................................... $3,172 $ - $ 1,405
Unproved.................................................. - - 22,939
Development costs........................................... 970 1,106 11,683
Exploration costs........................................... 4,769 8,987 9,872
------ ------- -------
$8,911 $10,093 $45,899
====== ======= =======
Results of Operations from Oil and Gas Producing Activities
The table below presents revenue and expenses related to oil and gas producing
activities (in thousands):
YEAR ENDED DECEMBER 31,
------------------------------
1992 1993 1994
------- ------- ------
Oil and gas sales............................................. $14,035 $13,490 $9,494
Expenses:
Operating costs............................................. 3,549 3,613 2,159
Production taxes............................................ 217 213 115
Depletion, depreciation, and amortization................... 6,710 5,551 4,255
------- ------- ------
10,476 9,377 6,529
------- ------- ------
Income from oil and gas producing activities.................. $ 3,559 $ 4,113 $2,965
======= ======= ======
Depletion rate per equivalent Mcf............................. $ .97 $ .94 $ .94
======= ======= ======
The Company's oil and gas production is sold to various purchasers. The
following table lists purchasers of the Company's natural gas which accounted
for more than 10% of total revenues for the years indicated:
YEAR ENDED DECEMBER 31,
---------------------------
1992 1993 1994
--- --- ---
Dow Hydrocarbons and Resources, Inc............................ 24% 32% 21%
Walter Oil and Gas Corporation................................. 17% 14% 11%
Mark Resources Corporation..................................... 10% -- 11%
Enron Gas Marketing, Inc....................................... 10% -- --
Amoco Production Co............................................ -- -- 20%
No single purchaser of crude oil from the Company accounted for more than 10% of
the Company's total revenues. Management believes that the loss of these
purchasers would not have a material impact on the Company's consolidated
financial condition or consolidated results of operations.
In an effort to reduce the effects of the volatility of the price of oil and gas
on the Company's operations, management has adopted a policy of hedging oil and
gas prices whenever such prices are in excess of the prices anticipated in the
Company's operating budget and profit plan through the use of commodity futures,
options, forwards, and swap agreements. Hedging transactions are limited by the
Board of Directors to 50%
F-15
64
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
of budgeted production for the succeeding 12 months and no more than 75% of
budgeted production in any one month.
During November 1994 the Company entered into a hedging transaction in the form
of a forward sale for the months of March through October 1995 for 100,000
MMBtus per month. In December 1994, the Company closed the forward sale
resulting in a gain of $152,000. This gain was deferred and will be recognized
over the period of the hedged production. The Company did not have any open
commodity positions at December 31, 1994.
In 1995, the Company has entered into three commodity swap transactions governed
by the terms of a Master Agreement with INCC (the Master Agreement). Under one
swap transaction the Company will receive a fixed price of $1.75 per MMBtu and
pay a floating price of Natural Gas -- NYMEX for the first nearby contract month
for 5,000 MMBtus per day for the contract months July to September 1995. Under a
second commodity swap transaction the Company will receive a fixed price of
$1.7525 per MMBtu and pay a floating price of Natural Gas-NYMEX for the first
nearby contract month for 5,000 MMBtus per day for the contract months August
1995 to January 1996. Under a third commodity swap transaction governed by the
terms of the Master Agreement the Company will receive a fixed price of $19.50
per barrel and pay a floating price of WTI-NYMEX for the first nearby month for
500 barrels per day for the period June 1 to September 30, 1995.
During 1995, the Company has also contracted to sell 5,000 MMBtus per day to
Coastal Gas Marketing Company at a price of $1.70 per MMBtu for the period June
1, 1995 to August 31, 1995.
Reserve Quantity Information (Unaudited)
All of the Company's reserves are located in the continental United States. The
Company's proved reserves were prepared by the Company and reviewed by Ryder
Scott Company, an independent petroleum engineering firm, at December 31, 1993
and 1994.
Proved reserves (developed and undeveloped) are estimated quantities of oil and
gas that geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known reservoirs under current economic
and operating conditions. The estimation of reserves is an interpretive process
that is subject to continuing revision as additional information becomes
available.
The Company's proved developed reserves are categorized as such based on the
availability of current production data, open-hole and cased-hole logs analyses,
and other productivity indications.
The estimation of proved undeveloped reserves was limited to direct offset
locations to existing wellbores and to geological formations that have shown to
be productive in the area.
F-16
65
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
The following is a reconciliation of the Company's estimated net quantities of
proved developed and undeveloped oil and gas reserves for the years ended
December 31, 1992, 1993, and 1994 (in thousands):
GAS OIL
(MCF) (BBL)
------ -----
Balance at December 31, 1991........................................... 32,986 509
Acquisitions of reserves in-place.................................... 5,740 306
Sales of reserves in-place........................................... (2) (1)
Revisions of previous estimates...................................... (1,672) 15
Extensions and discoveries........................................... 16,055 619
Production........................................................... (6,159) (130)
------ -----
Balance at December 31, 1992........................................... 46,948 1,318
Sales of reserves in-place........................................... (674) (26)
Revisions of previous estimates...................................... 547 60
Extensions and discoveries........................................... 11,287 907
Production........................................................... (5,226) (116)
------ -----
Balance at December 31, 1993........................................... 52,882 2,143
Acquisitions of reserves in-place.................................... 3,018 32
Sales of reserves in-place........................................... (2,902) (256)
Revisions of previous estimates...................................... (1,690) (34)
Extensions and discoveries........................................... 13,515 527
Production........................................................... (3,940) (100)
------ -----
Balance at December 31, 1994........................................... 60,883 2,312
====== =====
Proved developed reserves:
December 31, 1991.................................................... 26,433 390
December 31, 1992.................................................... 24,096 603
December 31, 1993.................................................... 20,637 525
December 31, 1994.................................................... 44,893 1,813
The Company's principal developed property is East Cameron Blocks 331/332 in the
Gulf of Mexico, which began production in the fourth quarter of 1994. The
estimated proved reserves for East Cameron Blocks 331/332 were approximately 192
and 174 billion equivalent cubic feet (Bcfe) at December 31, 1994, and December
31, 1993, respectively. As of December 31, 1994 and 1993, the Company's net
interest in the proved reserves of this property was approximately 35.5 Bcfe and
30.7 Bcfe, respectively. The Company's development expenditures for 1995 are
anticipated to be approximately $11 million, of which approximately $3.1 million
is designated for additional development of East Cameron Blocks 331/332.
Standardized Measure of Discounted Future Net Cash Flows from Estimated
Production of Proved Oil and Gas Reserves After Income Taxes (Unaudited)
In the opinion of the Company's management, no major discovery or adverse event
has occurred since December 31, 1994, that would cause a significant change in
proved reserve quantities as estimated at December 31, 1994. Reserves cannot be
measured exactly because reserve estimates involve subjective judgments. The
estimates must be reviewed periodically and adjusted to reflect additional
information gained from reservoir performance, new geological and geophysical
data, and economic changes. The values expressed are estimates only and may not
reflect realizable values or fair market values of the oil and gas ultimately
extracted and recovered. The estimated future net revenues may not accurately
reflect proceeds
F-17
66
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
of production to be received in the future from the sale of crude oil,
condensate, and natural gas currently owned. The present value of estimated
future net revenues does not necessarily reflect the actual costs that would be
incurred to acquire equivalent oil and gas reserves.
The following table sets forth a standardized measure of the discounted future
net cash flows attributable to the Company's proved oil and gas reserves. Future
cash inflows were computed by applying year-end oil and gas prices to the
estimated future production of proved reserves. The future production and
development costs represent the estimated future expenditures (based on current
costs) to be incurred in developing and producing the proved reserves, assuming
continuation of existing economic conditions. The timing of future development
costs is based on management's evaluation of the Company's projected cash flows
and financing resources. Future income tax expenses were computed by applying
statutory income tax rates to the difference between pretax net cash flows
relating to the Company's proved oil and gas reserves and the tax basis of
proved oil and gas properties and available net operating loss carryforwards and
statutory depletion, reduced by investment tax credits. Discounting the annual
net cash inflows at 10% illustrates the impact of timing on these future cash
inflows.
DECEMBER 31,
-----------------------
1993 1994
-------- --------
(IN THOUSANDS)
Future cash inflows................................................. $159,023 $142,871
Future production costs............................................. 27,465 22,255
Future development costs............................................ 17,873 14,517
-------- --------
Future net cash inflows before future income taxes.................. 113,685 106,099
Future income taxes................................................. 15,598 5,481
-------- --------
Future net cash inflows............................................. 98,087 100,618
Adjustments to discount future annual inflows at 10%................ 30,494 25,983
-------- --------
Standardized measure of discounted future net cash inflows.......... $ 67,593 $ 74,635
======== ========
The average price for natural gas in the above computations was $2.35 and $1.72
per Mcf at December 31, 1993 and 1994, respectively. The average price used for
crude oil in the above computations was $15.00 and $15.67 per barrel at December
31, 1993 and 1994, respectively.
F-18
67
CAIRN ENERGY USA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(INFORMATION SUBSEQUENT TO DECEMBER 31, 1994
AND FOR THE SIX MONTHS ENDED JUNE 30, 1994, IS UNAUDITED.)
Summary of Changes in the Standardized Measure of Discounted Future Net Cash
Flows from Estimated Production of Proved Oil and Gas Reserves After Income
Taxes (Unaudited)
The following table summarizes the principal factors comprising the changes in
the standardized measure of discounted future cash inflows (in thousands):
YEAR ENDED DECEMBER 31,
---------------------------------
1992 1993 1994
-------- ------- --------
Standardized measure at beginning of year................... $ 39,813 $48,161 $ 67,593
Sales and transfers, net of production costs................ (10,269) (9,664) (7,220)
Net change in sales prices and production costs............. (17,320) 145 (16,683)
Acquisitions of reserves in-place........................... 5,216 - 1,531
Extensions, discoveries, and improved recovery, net of
future production and development costs................... 38,419 31,999 19,495
Changes in estimated future development costs............... (5,411) (3,041) (7,085)
Development costs incurred during the period................ 970 1,106 11,683
Revisions of quantity estimates............................. (1,058) 1,047 (2,028)
Sales of reserves in place.................................. - (954) (6,119)
Accretion of discount....................................... 4,028 5,550 7,834
Net change in income taxes.................................. (6,281) (5,073) 7,354
Changes in production rates (timing) and other.............. 54 (1,683) (1,720)
-------- ------- --------
Standardized measure at end of year......................... $ 48,161 $67,593 $ 74,635
======== ======= ========
F-19
68
<Sk>
[RYDER SCOTT COMPANY LOGO]
FAX (713) 651-0849
1100 LOUISIANA SUITE 3800 HOUSTON, TEXAS 77002-5218 TELEPHONE (713) 651-9191
February 8, 1995
Cairn Energy USA
8235 Douglas Avenue, Suite 1221
Dallas, Texas 75225
Gentlemen:
At your request, we have reviewed the major properties in your
estimate of net proved hydrocarbon liquid and gas reserves attributable to
certain interests of Cairn Energy USA (referred to herein as Cairn) as of
January 1, 1995. These major properties constituted 95.6 percent of your
estimated net gas reserves and 98.0 percent of your estimated net oil and
condensate reserves.
The estimated total net reserve data attributable to Cairn's interest
in the properties are summarized below.
Estimated Net Reserve Data
Certain Leasehold and Royalty Interests of
CAIRN ENERGY USA
As of January 1, 1995
Hydrocarbon
Liquids Gas
Barrels MMCF
----------- -------
Proved Producing 710,451 28,035
Proved Non-Producing 1,102,165 16,858
--------- -------
Total Proved Developed 1,812,616 44,893
Proved Undeveloped 499,549 15,990
------- ------
TOTAL PROVED 2,312,165 60,883
The "Liquid" reserves shown above are comprised of crude oil and
condensate. All hydrocarbon liquid reserves are expressed in standard 42 gallon
barrels. All gas volumes are sales gas expressed in MMCF at the pressure and
temperature bases of the areas where the gas reserves are located. No attempt
has been made to quantify or otherwise account for any accumulated gas
imbalances.
Proved reserves of crude oil, condensate, natural gas, and
natural gas liquids are estimated quantities that geological and
engineering data demonstrate with reasonable certainty to be
recoverable in the future from known reservoirs under existing
conditions. Reservoirs are considered proved if economic producibility
is supported by actual production or formation tests. In certain
instances, proved reserves are assigned on the basis of a combination
of core analysis and electrical and other type logs which indicate the
reservoirs are analogous to reservoirs in the same field which are
producing or have demonstrated the ability to produce on a formation
test. The area of a reservoir considered proved includes (1) that
portion delineated by drilling and defined by fluid contacts, if any,
and (2) the adjoining
DENVER OFFICE: 600 SEVENTEENTH SUITE 900N DENVER, COLORADO 80202-5401
TELEPHONE (303) 623-9147 FAX (303) 623- 4258
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Cairn Energy USA
February 8, 1995
Page 2
portions not yet drilled that can be reasonably judged as economically
productive on the basis of available geological and engineering data.
In the absence of data on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the
reservoir. Proved reserves are estimates of hydrocarbons to be
recovered from a given date forward. They may be revised as
hydrocarbons are produced and additional data become available. Proved
natural gas reserves are comprised of non-associated, associated, and
dissolved gas. An appropriate reduction in gas reserves has been made
for the expected removal of natural gas liquids, for lease and plant
fuel, and the exclusion of non-hydrocarbon gases if they occur in
significant quantities and are removed prior to sale. Reserves that
can be produced economically through the application of improved
recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot
project or the operation of an installed program in the reservoir
provides support for the engineering analysis on which the project or
program was based, and (2) it is reasonably certain the project will
proceed. Improved recovery includes all methods for supplementing
natural reservoir forces and energy, or otherwise increasing ultimate
recovery from a reservoir, including (1) pressure maintenance, (2)
cycling, and (3) secondary recovery in its original sense. Improved
recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement
fluids. Estimates of proved reserves do not include crude oil, natural
gas, or natural gas liquids being held in underground storage.
Depending on the status of development, these proved reserves are
further subdivided into:
(i) "developed reserves" which are those proved reserves
reasonably expected to be recovered through existing
wells with existing equipment and operating methods, including
(a) "developed producing reserves" which are those proved
developed reserves reasonably expected to be produced from
existing completion intervals now open for production in
existing wells, and (b) "developed non-producing reserves"
which are those proved developed reserves which exist behind
the casing of existing wells which are reasonably expected to
be produced through these wells in the predictable future
where the cost of making such hydrocarbons available for
production should be relatively small compared to the cost of
a new well; and
(ii) "undeveloped reserves" which are those proved reserves
reasonably expected to be recovered from new wells on
undrilled acreage, from existing wells where a relatively
large expenditure is required, and from acreage for which an
application of fluid injection or other improved recovery
technique is contemplated where the technique has been proved
effective by actual tests in the area in the same reservoir.
Reserves from undrilled acreage are limited to those drilling
units offsetting productive units that are reasonably certain
of production when drilled. Proved reserves for other
undrilled units are included only where it can be demonstrated
with reasonable certainty that there is continuity of
production from the existing productive formation.
Review Procedure and Opinion
In performing our review, we have relied upon data furnished by Cairn
with respect to property interests owned by Cairn, and production from the
examined wells. These data were accepted as authentic and sufficient for
determining the reserves unless, during the course of our examination, a matter
of question came to our attention, in which case the data were not accepted
until all questions were satisfactorily resolved. Our review included such
tests and procedures as we considered necessary under the circumstances to
render the conclusions set forth herein.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
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Cairn Energy USA
February 8, 1995
Page 3
In our opinion, Cairn's estimates of future reserves and production
rates for the properties were prepared in accordance with generally accepted
procedures for the estimation of future reserves and production rates, and we
found no bias in the utilization and analysis of data in Cairn's estimates for
the properties. In general, we were in reasonable agreement with Cairn's
estimates of total remaining proved reserves for the properties which we
reviewed; however, in certain individual cases there was more than an
acceptable variance in Cairn's estimates and our estimates due to a difference
in interpretation of data or due to our having access to data which were not
available to Cairn when its reserve estimates were prepared.
Certain technical personnel of Cairn are responsible for the
preparation of reserve estimates on new properties and for the preparation of
revised estimates, when necessary, on old properties. These personnel assemble
the necessary data and maintain the data and work papers in an orderly manner.
We consulted with these technical personnel and had access to their work papers
and supporting data in the course of our review.
General
In the utilization of the reserve data presented herein,
consideration should be given to the following characterstics of estimates of
reserves and future production rates.
1. The reserves included in this report are estimates only and should
not be construed as being exact quantities. They may or may not
be actually recovered. Moreover, estimates of proved reserves may
increase or decrease as a result of future operations.
2. The future production rates from properties now on production may
be more or less than estimated because of changes in market
demand or allowables set by regulatory bodies. The effect of gas
curtailment has been considered in the estimate of future
production. Properties which are not currently producing may start
producing earlier or later than anticipated in our estimates of
their future production rates.
Neither we nor any of our employees have any interest in the
subject properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future net income
for the subject properties.
Very truly yours,
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/ JOHN R. WARNER
John R. Warner
Group Vice President
JRW/sw
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
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NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION IN CONNECTION WITH THE OFFERING OTHER
THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION
OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE
COMPANY OR THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO
SELL OR SOLICITATION OF ANY OFFER TO BUY BY ANYONE IN ANY JURISDICTION IN WHICH
SUCH OFFERS OR SOLICITATION IS NOT AUTHORIZED, OR IN WHICH THE PERSON MAKING
SUCH OFFER OR SOLICITATION IS NOT QUALIFIED TO DO SO OR TO ANY PERSON TO WHOM IT
IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE DELIVERY OF THIS
PROSPECTUS NOR ANY SALE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY
IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE
THE DATE HEREOF OR THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY
TIME SUBSEQUENT TO ITS DATE.
---------------------
TABLE OF CONTENTS
PAGE
----
Prospectus Summary..................... 3
Risk Factors........................... 9
The Company............................ 12
Use of Proceeds........................ 12
Price Range of Common Stock............ 12
Dividend Policy........................ 13
Capitalization......................... 14
Selected Consolidated Financial Data... 15
Management's Discussion and Analysis of
Financial Condition and Results of
Operations........................... 17
Business............................... 22
Management............................. 34
Principal Stockholders................. 38
Recent Sale of Shares by Cairn
Energy PLC........................... 39
Selling Stockholder.................... 39
Shares Eligible for Future Sale........ 40
Description of Capital Stock........... 41
Underwriting........................... 43
Legal Matters.......................... 43
Experts................................ 44
Available Information.................. 44
Additional Information................. 44
Documents Incorporated by Reference.... 44
Glossary............................... 46
Index to Financial Statements.......... F-1
Reserve Report Letter.................. A-1
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------------------------------------------------------
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3,750,000 SHARES
LOGO
COMMON STOCK
-----------------------
PROSPECTUS
-----------------------
S.G.WARBURG & CO. INC.
HOWARD, WEIL,
LABOUISSE, FRIEDRICHS
INCORPORATED
PETRIE PARKMAN & CO.
------------------------------------------------------
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72
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
The following table indicates the expenses to be incurred in connection with the
issuance and distribution of the securities described in this registration
statement, other than underwriting discounts and commissions. The Company will
pay all such expenses.
Securities and Exchange Commission Registration Fee....................... $ 16,977
National Association of Securities Dealers, Inc. Filing Fee............... 5,423
NASDAQ Stock Market Filing Fee............................................ 17,500
Blue Sky Fees and Expenses................................................ 2,500*
Accounting Fees and Expenses.............................................. 47,000*
Legal Fees and Expenses................................................... 55,000*
Printing and Engraving Fees and Expenses.................................. 95,000*
Miscellaneous............................................................. 600*
--------
Total........................................................... $240,000*
========
---------------
* Estimated.
ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
The Company has authority under the Delaware General Corporation Law, subject to
certain limitations, to indemnify its directors and officers against expenses
(including attorneys' fees), judgments, fines and certain settlements actually
and reasonably incurred by them in connection with any suit or proceeding to
which they are a party so long as they acted in good faith and in a manner
reasonably believed to be in or not opposed to the best interests of the
corporation, and, with respect to a criminal action or proceeding, so long as
they had no reasonable cause to believe their conduct was unlawful.
Reference is also made to the Company's Certificate of Incorporation, which
limits or eliminates a director's liability for monetary damages to the Company
or its stockholders for acts or omissions in the director's capacity as a
director, except that the Company's Certificate of Incorporation does not
eliminate or limit the liability of a director for (i) a breach of the
director's duty of loyalty to the Company or its stockholders, (ii) an act or
omission not in good faith that constitutes a breach of duty of the director to
the Company or an act or omission that involves intentional misconduct or a
knowing violation of the law, (iii) a transaction from which a director received
an improper benefit, whether or not the benefit resulted from an action taken
within the scope of the director's office, or (iv) an act or omission for which
the liability of a director is expressly provided for by an applicable statute.
In the case of an action by or in the right of the Company, indemnification is
precluded if such person has been adjudged to be liable, unless and only to the
extent that the Court of Chancery of the State of Delaware or the court in which
the action was brought shall determine that indemnification is proper. The
Company will advance amounts to an indemnified person on receipt of an
undertaking to repay the advance following any subsequent determination that the
indemnified person is not entitled to indemnification. Indemnification will be
provided unless it is determined to be improper (i) by a majority of
disinterested directors constituting a quorum or if no such quorum is
obtainable, a majority vote of a committee of two or more directors, (ii) by a
majority vote of a quorum of the outstanding shares of stock of all classes
entitled to vote for directors, voting as a single class, which quorum shall
consist of disinterested stockholders, (iii) by independent legal counsel in a
written opinion, or (iv) by a court of competent jurisdiction. The Company also
has the power to obtain insurance indemnifying officers and directors of the
Company against any liability which it may deem proper, whether or not the
Company would have the power to indemnify such officer or director pursuant to
the General Corporation Law of the State of Delaware. The Company has not
obtained such insurance.
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73
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) Exhibits:
*1.1 -- Form of Underwriting Agreement.
*1.2 -- Form of Agreement Among Underwriters.
2.1 -- Purchase and Sale Agreement dated July 12, 1994, by and among Smith Offshore
Exploration Company, II, Phemus Corporation, and Cairn Energy USA, Inc. (without
exhibits) (the exhibits and schedules to the Agreement have been omitted pursuant to
Item 601(b)(2) of Regulation S-K). Incorporated by reference from the Company's
Current Report on Form 8-K, dated July 12, 1994, filed with the Commission on July
27, 1994.
2.2 -- Common Stock Purchase Agreement dated July 12, 1994 by and between Cairn Energy PLC
and Phemus Corporation. Incorporated by reference from the Company's Current Report
on Form 8-K, dated July 12, 1994, filed with the Commission on July 27, 1994.
5.1 -- Opinion of Jenkens & Gilchrist, a Professional Corporation.
23.1 -- Consent of Ernst & Young LLP, Independent Auditors.
*23.2 -- Consent of Jenkens & Gilchrist, a Professional Corporation (included in opinion
Exhibit 5).
*23.3 -- Consent of Ryder Scott Company.
*23.4 -- Consent of Arthur Andersen LLP, Independent Public Accountants
*24.1 -- Power of Attorney (included on the signature page of the Registration Statement).
---------------
* Previously filed.
(b) Financial Statement Schedules:
See index to financial schedules on page F-1.
ITEM 17. UNDERTAKINGS.
A. The undersigned registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
registrant's annual report pursuant to section 13(a) or section 15(d) of the
Securities Exchange Act of 1934 that is incorporated by reference in the
registration statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
B. The undersigned registrant hereby undertakes to deliver or cause to be
delivered with the prospectus, to each person to whom the prospectus is sent or
given, the latest annual report to security-holders that is incorporated by
reference in the prospectus and furnished pursuant to and meeting the
requirements of Rule 14a-3 or Rule 14c-3 under the Securities Exchange Act of
1934; and, where interim financial information required to be presented by
Article 3 of Regulation S-X is not set forth in the prospectus, to deliver, or
cause to be delivered to each person to whom the prospectus is sent or given,
the latest quarterly report that is specifically incorporated by reference in
the prospectus to provide such interim financial information.
C. Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
registrant pursuant to the foregoing provisions, or otherwise, the registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities Act
and is, therefore, unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the registrant of expenses
incurred or paid by a director, officer or controlling person in the successful
defense of any action, suit or proceeding) is asserted by such director, officer
or controlling person in connection with the securities being registered, the
registrant will, unless in the opinion of its counsel the matter has been
settled by controlling precedent, submit to a court of appropriate jurisdiction
the question whether such indemnification by it is against public policy as
expressed in the Act and will be governed by the final adjudication of such
issue.
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74
D. The registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act of
1933, the information omitted from the form of prospectus filed as part of
this registration statement or in reliance upon Rule 430A and contained in
a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or
(4) or 497(h) under the Securities Act of 1933 shall be deemed to be part
of this registration statement as of the time it was declared effective.
(2) For the purpose of determining any liability under the Securities Act
of 1933, each post-effective amendment that contains a form of prospectus
shall be deemed to be a new registration statement relating to the
securities offered therein, and the offering of such securities at that
time shall be deemed to be the initial bona fide offering thereof.
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75
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
certifies that it has reasonable grounds to believe that it meets all of the
requirements for filing on Form S-3 and has duly caused this registration
statement to be signed on its behalf by the undersigned, thereunto duly
authorized, thereunto duly authorized, in the City of Dallas, and the State of
Texas, the 13th day of September, 1995.
CAIRN ENERGY USA, INC.
(Registrant)
By: /s/ MICHAEL R. GILBERT
------------------------------------
Michael R. Gilbert,
President and Chief Executive
Officer
POWER OF ATTORNEY
Know All Men By These Presents, that each person whose signature appears below
constitutes and appoints Michael R. Gilbert and J. M. M. Sutherland, and each of
them, each with full power to act without the other, his or her true and lawful
attorney-in-fact and agent, with full power and substitution, for him and in his
name, place and stead, in any and all capacities, to sign any or all amendments
to this Registration Statement, and to file the same, with all exhibits thereto,
and all other documents in connection therewith, with the Securities and
Exchange Commission, granting unto said attorney-in-fact and agent full power
and authority to do and perform each and every act and thing requisite and
necessary to be done in and about the premises, as fully to all intents and
purposes as he might or could do in person, hereby ratifying and confirming all
that said attorney-in-fact and agent, or his substitute, may lawfully do or
cause to be done by virtue thereof.
Pursuant to the requirements of the Securities Act of 1933, this registration
statement has been signed below by the following persons in the capacities and
on the dates indicated.
SIGNATURE TITLE DATE
---------------------------------------- ------------------------------- -------------------
/s/ MICHAEL R. GILBERT President, Chief Executive September 13, 1995
---------------------------------------- Officer and Director
Michael R. Gilbert (Principal Executive Officer)
/s/ J.M.M. SUTHERLAND* Senior Vice President, Chief September 13, 1995
---------------------------------------- Financial Officer, Treasurer,
J.M.M. Sutherland and Director (Principal
Financial Officer)
/s/ A. ALLEN PAUL* Vice President-Finance September 13, 1995
---------------------------------------- (Principal Accounting
A. Allen Paul Officer)
/s/ R. DANIEL ROBINS* Director September 13, 1995
----------------------------------------
R. Daniel Robins
/s/ JACK O. NUTTER, II* Director September 13, 1995
----------------------------------------
Jack O. Nutter, II
II-4
76
SIGNATURE TITLE DATE
---------------------------------------- ------------------------------- -------------------
/s/ WILLIAM B. B. GAMMELL* Director September 13, 1995
----------------------------------------
William B. B. Gammell
/s/ MICHAEL E. MCMAHON* Director September 13, 1995
----------------------------------------
Michael E. McMahon
/s/ JOHN C. HALSTED* Director September 13, 1995
----------------------------------------
John C. Halsted
*By: /s/ MICHAEL R. GILBERT
----------------------------------------
Michael R. Gilbert
Agent and Attorney-in-Fact
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INDEX TO EXHIBITS
SEQUENTIALLY
EXHIBIT NUMBERED
NO. DESCRIPTION PAGE
---------- ------------------------------------------------------------------------ ------------
*1.1 -- Form of Underwriting Agreement.
*1.2 -- Form of Agreement Among Underwriters.
2.1 -- Purchase and Sale Agreement dated July 12, 1994, by and among Smith
Offshore Exploration Company, II, Phemus Corporation, and Cairn
Energy USA, Inc. (without exhibits) (the exhibits and schedules to
the Agreement have been omitted pursuant to Item 601(b)(2) of
Regulation S-K). Incorporated by reference from the Company's Current
Report on Form 8-K, dated July 12, 1994, filed with the Commission on
July 27, 1994.
2.2 -- Common Stock Purchase Agreement dated July 12, 1994 by and between
Cairn Energy PLC and Phemus Corporation. Incorporated by reference
from the Company's Current Report on Form 8-K, dated July 12, 1994,
filed with the Commission on July 27, 1994.
5.1 -- Opinion of Jenkens & Gilchrist, a Professional Corporation.
23.1 -- Consent of Ernst & Young LLP, Independent Auditors.
*23.2 -- Consent of Jenkens & Gilchrist, a Professional Corporation (included
in opinion Exhibit 5).
*23.3 -- Consent of Ryder Scott Company.
*23.4 -- Consent of Arthur Andersen LLP, Independent Public Accountants
*24.1 -- Power of Attorney (included on the signature page of the Registration
Statement).
---------------
* Previously filed.