SEC FILE NO. 33-52425
FILED UNDER RULE 424(b)(1)
PROSPECTUS
$75,000,000
POGO PRODUCING COMPANY
5 1/2% CONVERTIBLE SUBORDINATED NOTES DUE 2004
The 5 1/2% Convertible Subordinated Notes due 2004 (the 'Notes') are
convertible at any time prior to maturity, unless previously redeemed, into
shares of common stock, par value $1 per share (the 'Common Stock') of Pogo
Producing Company (the 'Company'), at a conversion price of $22.188 per share,
subject to adjustment upon the occurrence of certain events. On March 16,
1994, the closing sale price of the Common Stock on the New York Stock Exchange
was $17 3/4 per share. The Common Stock is traded under the symbol 'PPP.'
Interest on the Notes is payable semi-annually on March 15 and September 15
of each year, commencing September 15, 1994. The Notes will mature on March 15,
2004 unless earlier redeemed or converted. The Notes will be redeemable at the
option of the Company, in whole or in part, at any time on or after March 15,
1998, at the redemption prices set forth herein plus accrued and unpaid interest
to the date of redemption. No sinking fund is provided for the Notes. The Notes
are redeemable at the option of the holder, upon the occurrence of a Repurchase
Event (as defined herein), at 100% of the principal amount thereof, plus accrued
interest. See 'Description of the Notes.'
The Notes will be unsecured obligations of the Company, will be subordinated
in right of payment to all existing and future Senior Indebtedness (as defined
herein) of the Company, and will be effectively subordinated to all indebtedness
and liabilities of subsidiaries of the Company. The Indenture with respect to
the Notes will not restrict the incurrence of any other indebtedness or
liabilities by the Company or its subsidiaries. See 'Description of the Notes.'
SEE 'INVESTMENT CONSIDERATIONS' FOR A DISCUSSION OF CERTAIN FACTORS THAT
SHOULD BE CONSIDERED IN EVALUATING AN INVESTMENT IN THE NOTES.
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.
<TABLE>
<CAPTION>
PRICE TO UNDERWRITING PROCEEDS TO
PUBLIC (1) DISCOUNT(2) COMPANY(1)(3)
<S> <C> <C> <C>
Per Note---------------------------------- 100% 2.5% 97.5%
Total(4)---------------------------------- $75,000,000 $1,875,000 $73,125,000
(1) Plus accrued interest, if any, from March 23, 1994.
(2) The Company has agreed to indemnify the several Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See 'Underwriting.'
(3) Before deducting expenses payable by the Company estimated at $350,000.
(4) The Company has granted the Underwriters a 30-day option to purchase up to
an additional $11,250,000 principal amount of Notes on the same terms set
forth above to cover over-allotments, if any. If the Underwriters exercise
such option in full, the Price to Public, Underwriting Discount and Proceeds
to Company would be $86,250,000, $2,156,250 and $84,093,750, respectively.
See 'Underwriting.'
</TABLE>
The Notes are being offered by the several Underwriters, subject to prior
sale, when, as and if issued to and accepted by the Underwriters, and certain
other conditions. The Underwriters reserve the right to withdraw, cancel or
modify such offer and to reject orders in whole or in part. It is expected that
delivery of the Notes will be made in New York, New York, on or about March 23,
1994.
MERRILL LYNCH & CO.
GOLDMAN, SACHS & CO.
PAINEWEBBER INCORPORATED
The date of this Prospectus is March 16, 1994.
<PAGE>
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
Securities and Exchange Commission (the 'Commission'). Such reports, proxy
statements and other information filed by the Company with the Commission may be
inspected and copied at the Public Reference Section of the Commission at Room
1024, 450 Fifth Street, N.W., Judiciary Plaza, Washington, D.C. 20549, and at
the following Regional Offices of the Commission: Chicago Regional Office,
Northwestern Atrium Center, 500 West Madison Street, Suite 1400, Chicago,
Illinois 60601-2511; and New York Regional Office, Seven World Trade Center, New
York, New York 10048. Copies of such material may also be obtained from the
Public Reference Section of the Commission at its principal office at Room 1024,
Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, at prescribed
rates. The Company's registration statements, reports, proxy statements and
other information may also be inspected at the offices of the New York Stock
Exchange, 20 Broad Street, New York, New York 10005 and the Pacific Stock
Exchange, 301 Pine Street, San Francisco, California 94104.
This Prospectus, which constitutes a part of a registration statement on
Form S-3 (the 'Registration Statement') filed by the Company with the Commission
under the Securities Act of 1933, as amended (the 'Securities Act'), omits
certain of the information set forth in the Registration Statement. Reference is
hereby made to the Registration Statement and to the exhibits thereto for
further information with respect to the Company and the securities offered
hereby. Statements contained herein concerning the provisions of such documents
are necessarily summaries of such documents, and each such statement is
qualified in its entirety by reference to the copy of the applicable document
filed with the Commission. Copies of the Registration Statement and the exhibits
thereto are on file at the offices of the Commission and may be obtained upon
payment of the fee prescribed by the Commission, or may be examined without
charge at the public reference facilities of the Commission described above.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The Company's Annual Report on Form 10-K for the year ended December 31,
1993 (the 'Annual Report') is incorporated herein by reference.
All documents filed by the Company pursuant to Section 13(a), 13(c), 14 or
15(d) of the Exchange Act subsequent to the date of this Prospectus and prior to
the termination of the offering of the Notes hereunder (the 'Offering') shall be
deemed to be incorporated by reference in this Prospectus and to be part hereof
from the date of filing of such documents. Any statement contained in a document
incorporated or deemed to be incorporated by reference shall be deemed to be
modified or superseded for purposes of this Prospectus to the extent that a
statement contained herein or in any other subsequently filed incorporated
document or in any accompanying prospectus supplement 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.
Copies of all documents incorporated herein by reference other than exhibits
to such documents (unless such exhibits are specifically incorporated by
reference) will be provided without charge to each person who receives a copy of
this Prospectus upon written or oral request to Gerald A. Morton, Associate
General Counsel, Pogo Producing Company, P.O. Box 2504, Houston, Texas
77252-2504 (telephone: (713) 297-5017).
IN CONNECTION WITH THE OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE NOTES OFFERED
HEREBY OR THE COMMON STOCK, OR EACH OF THEM, AT A LEVEL ABOVE THAT WHICH MIGHT
OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE
NEW YORK STOCK EXCHANGE, THE PACIFIC STOCK EXCHANGE, IN THE OVER-THE-COUNTER
MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY
TIME.
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PROSPECTUS SUMMARY
THIS SUMMARY IS QUALIFIED IN ITS ENTIRETY BY, AND SHOULD BE READ IN
CONJUNCTION WITH, THE MORE DETAILED INFORMATION AND FINANCIAL STATEMENTS
APPEARING ELSEWHERE OR INCORPORATED BY REFERENCE IN THIS PROSPECTUS. EXCEPT AS
OTHERWISE SPECIFIED, THE INFORMATION IN THIS PROSPECTUS ASSUMES NO EXERCISE OF
THE UNDERWRITERS' OVER-ALLOTMENT OPTION. SEE 'GLOSSARY OF OIL AND GAS TERMS' FOR
DEFINITIONS OF CERTAIN TERMS USED IN THIS PROSPECTUS. INVESTORS SHOULD CAREFULLY
CONSIDER THE INFORMATION SET FORTH UNDER THE CAPTION 'INVESTMENT
CONSIDERATIONS.'
THE COMPANY
Pogo Producing Company is an independent oil and gas exploration and
production company, based in Houston, Texas, with an extensive Gulf of Mexico
reserve and acreage position. The Company is also active in the Permian Basin of
New Mexico, and has a 31.7% working interest in a 2.6 million acre concession
license in the Gulf of Thailand. At December 31, 1993, the Company had interests
in 597 gross oil and gas wells. At January 1, 1994, the Company's proved
reserves, as estimated by Ryder Scott Company Petroleum Engineers ('Ryder
Scott'), totaled 28.3 MMBbls of oil, condensate and natural gas liquids and
232.9 Bcf of natural gas. See 'Business and Properties -- Reserves.'
The Company's business strategy is to maximize profitability and shareholder
value by (i) steadily increasing hydrocarbon production levels, leading to
increased revenues, cash flow, and earnings, (ii) expanding its hydrocarbon
reserves base, (iii) maintaining appropriate levels of debt and interest
expense, and controlling overhead and operating costs, and (iv) expanding
exploration and production activities into new and promising geographic areas
consistent with Company expertise.
To implement its business strategy, the Company currently is focusing
substantial attention and resources in the following geographic areas:
THE GULF OF MEXICO. Approximately 68% of the Company's proved oil and gas
reserves are located in the Gulf of Mexico. Most of these proved reserves are
concentrated in five significant producing areas, including eight fields in the
Eugene Island area located off the Louisiana coast. This concentration allows
the Company to closely manage costs and to develop detailed geologic and other
information relating to its properties. The Company believes that the Gulf of
Mexico will continue to provide the Company with substantial opportunities to
expand its hydrocarbon reserves and to increase its deliverability. The Company
is utilizing its extensive inventory of 3-D seismic data (covering 24 of the
Company's lease blocks and 81 other lease blocks in the Gulf of Mexico) and
conventional 2-D seismic data (approximately one-half million miles of which are
located in the Gulf of Mexico) to locate low risk exploration and development
projects. In addition to conventional vertical and deviated drilling, the
Company will also utilize horizontal drilling (the Company participated in seven
horizontal wells in 1993 alone) to accelerate development of its offshore
projects. To expand its reserves base and increase its deliverability, the
Company will rely on its 24 years of experience in the Gulf of Mexico, where it
holds an extensive acreage position. The Company currently holds interests in 76
offshore blocks, and will continue to evaluate and acquire additional acreage
with significant exploration and development potential. The Company, which
historically has not operated a substantial percentage of its offshore
properties, has assumed the operation of certain of its properties where the
Company believes that its technical expertise and ability to control overhead
and operating costs will enhance its economic interests. In its role as
operator, the Company recently used a 3-D seismic survey to pinpoint the
location of potentially recoverable shallow natural gas reserves on a portion of
its Eugene Island Block 295 field, and horizontal drilling technology, including
five horizontal wells, to optimize the exploitation of the field's shallow
natural gas reserves.
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NEW MEXICO. The Company continues to enjoy substantial success in its
efforts to increase liquids production from its properties in southeastern New
Mexico. The Company is currently one of the most active companies
drilling for oil and gas in the southeastern New Mexico portion
of the Permian Basin, where, from late 1989 through the end of
1993, the Company and its partners have drilled and completed as productive 151
consecutive wells, including 58 wells during 1993 alone. The Company has
achieved rapid cost recovery with respect to its New Mexico wells drilled to
date because of relatively low capital costs and high initial rates of
production. Due to its historical drilling success, its current undeveloped
acreage position and its commitment to additional drilling, the Company expects
its New Mexico operations to continue to be a source of significant reserves and
of liquids production. The Company's primary drilling objective in southeastern
New Mexico is the Brushy Canyon (Delaware) formation, which produces oil at
depths of approximately 6,000 to 9,000 feet. The Company's net revenue interest
portion of daily liquid hydrocarbon production in New Mexico averaged
approximately 3,700 Bbls during 1993, compared to approximately 2,050 Bbls per
day during 1992, an increase of approximately 80%.
THE GULF OF THAILAND. The Company has conducted international exploration
activities since the late 1970's in numerous oil and gas provinces in various
parts of the world. The Company pursues a strategy of evaluating potentially
high return prospects in areas of the world with a stable political and
financial climate, such as certain European and ASEAN ('Association of Southeast
Asian Nations') countries. Consistent with this strategy, in August 1991, the
Company and its joint venture partners were awarded a license to explore for oil
and gas on a 2.6 million acre concession, Block B8/32, in the Gulf of Thailand.
The concession is located in a basin on trend with several oil and gas fields
operated by Unocal Thailand Ltd. Through November 1993, Unocal Thailand Ltd. has
reported cumulative production from more than 700 wells in these fields totaling
approximately 2 trillion cubic feet of natural gas and 71 MMBbls of oil and
condensate. Following an initial evaluation of the Thailand concession area, the
Company and its joint venture partners drilled five exploratory wells on three
separately identified seismic structures. The first well drilled, the Tantawan
No. 1, successfully tested a large, complexly faulted, anticlinal structure with
production tests from five intervals resulting in calculated cumulative flow
rates of 6,260 Bbls of oil and condensate and 25,750 Mcf of natural gas per day.
During 1993, the Company and its joint venture partners shot, processed and
evaluated approximately 9,000 kilometers of new 3-D seismic data over and around
the Tantawan No. 1 well. In late 1993, the Company drilled the Tantawan No. 2
and the Tantawan No. 3 exploratory wells on the Tantawan structure. The Tantawan
No. 2 well successfully delineated a previously untested fault block to the east
of the Tantawan No. 1 well with production tests from six intervals resulting in
calculated cumulative flow rates of 70,300 Mcf of natural gas and 1,720 Bbls of
condensate per day. The Tantawan No. 3 well successfully delineated a third
untested fault block on the Tantawan structure located approximately two miles
north of the Tantawan No. 1 and No. 2 wells. Production tests from this third
Tantawan well were reported in January 1994, with production tests from five
intervals resulting in calculated cumulative flow rates of 40,660 Mcf of natural
gas and 8,684 Bbls of oil and condensate per day. As a result of its successful
exploration drilling program, the Company's Thailand concession now accounts for
approximately 14% of the Company's total estimated net proved reserves of
natural gas, approximately 19% of the Company's total estimated net proved
reserves of oil, condensate and natural gas liquids and approximately 16% of the
Company's total net proved oil and gas equivalent reserves. During 1994,
additional delineation wells on the Tantawan structure are planned. Based upon
the results of such drilling, the Company and its partners will agree upon the
type of development plan needed to commence production in this area. In
addition, in late 1993, the Company and its joint venture partners began
shooting and processing additional 3-D seismic data on a different portion of
Block B8/32. Following evaluation of this seismic data, additional exploratory
wells are expected to be drilled by the
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Company and its joint venture partners on as yet untested seismic structures
identified on Block B8/32.
While maintaining an active exploration and development program, the Company
also continues to focus on its strategy of maintaining appropriate levels of
debt and interest expense. The Company has reduced its total debt and production
payment obligations from $472,400,000 as of January 1, 1988, to $134,539,000 as
of December 31, 1993, a decrease of approximately 72%.
The reduction of total debt and production payment obligations has allowed
the Company to devote increased amounts of its cash flow toward exploration and
development of its premium property base. The Company's drilling successes have
resulted in increased equivalent oil and gas production during 1992 and 1993, as
compared to the prior five years, while simultaneously expanding its reserves
base. In 1992 and 1993, the Company replaced 143% and 204%, respectively, of its
total production of proved hydrocarbon reserves. The Company believes that the
increased liquidity and increased average maturity of its outstanding
indebtedness resulting from the Offering will provide the Company with
additional financial flexibility to pursue its business strategy and maximize
shareholder value. For 1994, the Company's Board of Directors has authorized
capital and exploration expenditures of $75,000,000, approximately equal to the
Company's capital and exploration expenditures of approximately $74,600,000 in
1993. See 'The Company,' 'Management's Discussion and Analysis of Financial
Condition and Results of Operations' and 'Business and Properties.'
<TABLE>
THE OFFERING
<S> <C>
Notes Offered------------------------ $75,000,000 principal amount of 5 1/2% Convertible
Subordinated Notes due 2004 (excluding $11,250,000 aggregate
principal amount of Notes subject to the Underwriters'
over-allotment option).
Interest Payment Dates--------------- March 15 and September 15 of each year, commencing September
15, 1994.
Conversion Rights-------------------- Convertible into Common Stock of the Company at the option
of the holder at any time before maturity (unless earlier
redeemed) at $22.188 per share (equivalent to a conversion
rate of approximately 45.069 shares per $1,000 principal
amount of Notes), subject to adjustment upon the occurrence
of certain events. See 'Description of the
Notes -- Conversion Rights.'
Ranking------------------------------ The Notes will be unsecured and subordinated to all existing
and future Senior Indebtedness of the Company and
effectively subordinated to all indebtedness and other
liabilities of subsidiaries of the Company. The Indenture
relating to the Notes contains no limitation on the
incurrence of indebtedness or other liabilities by the
Company or its subsidiaries. The Notes will rank PARI PASSU
with the Company's one other issue of convertible
subordinated indebtedness that will remain outstanding after
application of the proceeds of the Offering. See 'Use of
Proceeds,' 'Capitalization' and 'Description of the
Notes -- Subordination.'
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Optional Redemption------------------ The Notes are redeemable at the option of the Company, in
whole or in part, at any time on or after March 15, 1998, at
the redemption prices set forth herein plus accrued interest
to the date of redemption. Accrued and unpaid interest to
the redemption date shall be payable with respect to Notes
that are converted after a notice of redemption has been
mailed and prior to the redemption date. See 'Description of
the Notes -- Redemption at Option of Company.'
Repurchase at Holder's
Option----------------------------- Upon the occurrence of a Repurchase Event, each holder of
Notes shall have the right, at the holder's option, to
require the Company to repurchase such Notes at 100% of
their principal amount, plus accrued interest. The term
Repurchase Event is limited to certain transactions
involving a Change of Control (as defined herein) in which
(i) the market price of the Common Stock at the time of, and
the aggregate fair market value of the consideration
received in, such transaction is less than 105% of the
conversion price and (ii) the Notes become convertible into
securities other than publicly traded common stock. See
'Description of the Notes -- Certain Rights to Require
Repurchase of Notes.'
Use of Proceeds---------------------- The net proceeds from the Offering will be used to repay
certain indebtedness of the Company. See 'Use of Proceeds.'
Absence of Public Market------------- The Notes are a new issue for which there is currently no
public market. The Company does not intend to apply for
listing of the Notes on a securities exchange or for
quotation on the NASDAQ National Market. If an active public
market does not develop, the market price and liquidity of
the Notes may be adversely affected. See 'Investment
Considerations -- Absence of Public Market' and
'Underwriting.'
</TABLE>
For additional information concerning the Notes, see 'Description of the Notes.'
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SUMMARY FINANCIAL AND OPERATING DATA
The Summary Financial and Operating Data presented below for, and as of the
end of, each of the years in the five-year period ended December 31, 1993, are
derived from the consolidated financial statements of the Company and its
subsidiaries, which have been audited by independent public accountants. The
information presented under the captions 'Production (Sales) Data,' 'Selected
Ratios' and 'Reserve Data' is unaudited. This data should be read in conjunction
with the consolidated financial statements and related notes thereto and
'Management's Discussion and Analysis of Financial Condition and Results of
Operations' included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
1993 1992 1991 1990 1989
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AND UNIT
AMOUNTS, EXCEPT AS NOTED)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Total revenues----------------------- $ 139,554 $ 140,830 $ 124,469 $ 154,820(a) $ 120,947
Operating income--------------------- 50,533 47,141 37,239 72,940(a) 37,375
Net interest expense----------------- 10,505 18,645 24,309 30,700 36,352
Net income--------------------------- 25,061 18,495 11,658 44,036(a) 2,638
Primary and fully diluted earnings
per share-------------------------- $ 0.76 $ 0.66 $ 0.42 $ 1.69(a) $ 0.11
OTHER FINANCIAL DATA:
EBITDA(b)---------------------------- $ 96,381 $ 99,339 $ 81,637 $ 116,760(a) $ 87,384
Capital and exploration expenditures
(excluding capitalized
interest)-------------------------- 74,600 41,300 53,100 39,500 25,800
<CAPTION>
YEAR ENDED DECEMBER 31,
1993 1992 1991 1990 1989
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE
AND UNIT AMOUNTS)
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SELECTED RATIOS:
EBITDA/Net interest expense---------- 9.2 5.3 3.4 3.8 2.4
Ratio of earnings to fixed
charges(c)------------------------- 4.5 2.5 1.6 2.3 1.0
Long-term obligations/Total proved
reserves (BOE)(d)------------------ $ 1.95 $ 2.52 $ 4.22 $ 4.70 $ 5.49
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1993
ACTUAL AS ADJUSTED(E)
(EXPRESSED IN THOUSANDS)
<S> <C> <C>
BALANCE SHEET DATA:
Total assets--------------------- $ 239,774 $ 242,302
Long-term obligations, including
current portion---------------- 134,539 137,539
Shareholders' equity------------- 33,803 33,496
(a) In late 1990, the Company entered into a settlement agreement with the
Internal Revenue Service for a refund of $8,607,000 in taxes for taxable
years 1976 through 1985 which, together with accrued interest of
$20,395,000, resulted in a refund receivable of $29,002,000 through December
31, 1990. The refund and interest income, together with the reversal of
previously accrued interest expense of $2,104,000, contributed $22,499,000
to total revenues and $23,456,000 or $0.90 per share to earnings in 1990.
The refund along with additional accrued interest was received by the
Company on May 31, 1991.
(b) EBITDA represents income from continuing operations before provision for
income taxes, interest expense, interest income, interest capitalized,
depreciation and amortization, and dry hole and impairment costs. EBITDA is
presented as a measure of the Company's debt service ability, and not as an
alternative to (i) operating income (as determined in accordance with
generally accepted accounting principles) as an indicator of the Company's
operating performance, or (ii) cash flows from operating activities (as
determined in accordance with generally accepted accounting principles) as a
measure of liquidity.
(c) Income before taxes and extraordinary item plus fixed charges (net of
capitalized interest) divided by fixed charges. Fixed charges are defined as
interest expense plus the portion of rental expense representing interest.
(d) Long-term obligations include long-term debt (excluding current maturities)
and the non-current portion of the Eugene Island Block 330 production
payment obligation until such obligation was satisfied in 1993. Total proved
reserves are expressed on an energy equivalent basis. BOE means Bbls of oil
on an energy equivalent basis. See 'Glossary of Oil and Gas Terms.'
(e) Adjusted to give effect to the Offering and the use of proceeds therefrom.
</TABLE>
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<TABLE>
SUMMARY FINANCIAL AND OPERATING DATA -- (CONTINUED)
<CAPTION>
YEAR ENDED DECEMBER 31,
1993 1992 1991 1990 1989
(EXPRESSED IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
PRODUCTION (SALES) DATA:
Net daily average and weighted
average price:
Natural gas:
Mcf per day-------------------- 91,700 105,200 104,200 107,300 111,300
Price per Mcf------------------ $ 1.98 $ 1.75 $ 1.66 $ 1.89 $ 1.88
Crude oil-condensate:
Bbls per day------------------- 9,851 8,699 7,108 6,209 6,013
Price per Bbl------------------ $ 17.81 $ 20.17 $ 20.98 $ 23.84 $ 18.86
Natural gas liquids:
Bbls per day------------------- 1,678 1,181 663 697 948
Price per Bbl------------------ $ 11.90 $ 13.50 $ 14.21 $ 13.75 $ 10.16
RESERVE DATA:
Estimated proved reserves
Crude oil, condensate and natural
gas liquids (MBbls)------------ 28,268 22,556 18,818 19,090 17,658
Natural gas (MMcf)--------------- 232,866 207,068 202,735 217,500 234,112
Natural gas equivalent
(MMcfe)(f)--------------------- 402,474 342,404 315,643 332,040 340,060
Estimated future net revenues
before income taxes, discounted
at 10%------------------------- $ 403,840 $ 405,101 $ 349,754 $ 525,173 $ 441,917
(f) MMcfe means MMcf on an energy equivalent basis.
</TABLE>
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INVESTMENT CONSIDERATIONS
Prospective purchasers of the Notes offered hereby should carefully consider
the following factors, as well as the information contained elsewhere in this
Prospectus, before purchasing the Notes.
VOLATILITY OF OIL AND GAS MARKETS
The Company's profitability and cash flow are highly dependent upon the
prices of oil and natural gas, which historically have been seasonal, cyclical
and volatile. In general, prices of oil and gas are dependent upon numerous
factors beyond the control of the Company, including various weather, economic,
political and regulatory conditions. In the past, when natural gas prices in the
United States were lower than they are currently, the Company at times elected
to curtail certain quantities of its production capacity. Should natural gas
prices fall in the future, the Company may again elect to curtail certain
quantities of its natural gas production capacity. Any significant decline in
oil or gas prices could have a material adverse effect on the Company's
operations and financial condition and could, under certain circumstances,
result in a reduction in funds available under the Credit Agreement (as defined
herein) and the Company's ability to meet its debt service obligations. Because
it is impossible to predict future oil and gas price movements with any
certainty, the Company from time to time enters into contracts on a portion of
its production to hedge against the volatility in oil and gas prices. Such
hedging transactions historically have not exceeded 50% of the Company's total
oil and gas production on an energy equivalent basis for any given period. While
intended to limit the negative effect of price declines, such transactions could
effectively limit the Company's participation in price increases for the covered
period, which price increases could be significant. See ' -- Subordination of
Notes; Leverage and Debt Service' and 'Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources.'
ESTIMATES OF RESERVES AND FUTURE NET REVENUES
There are numerous uncertainties inherent in estimating the quantity of
proved oil and gas reserves and in projecting the future rates of production and
timing of development expenditures. Engineering of oil and gas reserves is a
subjective process of estimating underground accumulations of oil and gas that
cannot be measured precisely, and estimates of other engineers might differ
materially from those prepared by Ryder Scott, the independent engineering firm
retained by the Company. The accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Results of drilling, testing and production subsequent to the date
of the estimates may justify revisions of such estimates. Accordingly, reserve
estimates are generally different from the quantities of oil and gas that are
ultimately recovered. In addition, estimates of the Company's future net
revenues from proved reserves and the present value thereof are based on certain
assumptions regarding future oil and gas prices, production levels and operating
and development costs that may not prove to be correct. Any significant variance
in these assumptions could materially affect the estimated quantity of reserves
and future net revenues therefrom set forth in this Prospectus. See 'Business
and Properties -- Reserves.'
OPERATING AND UNINSURED RISKS
The Company's operations are subject to risks inherent in the exploration
for and production of oil and natural gas, such as blowouts, cratering,
explosions, uncontrollable flows of oil, natural gas or well fluids, fires,
pollution and other environmental risks. Offshore oil and gas operations are
subject to the additional hazards of marine operations, such as capsizing,
collision and adverse weather and sea conditions. These hazards could result in
substantial losses to the Company due to injury or loss of life, severe damage
to and destruction of property and equipment, pollution and other environmental
damage and suspension of operations. The Company carries insurance which it
believes is in
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accordance with customary industry practices, but is not fully insured against
all risks incident to its business.
Drilling activities are subject to numerous risks, including the risk that
no commercially productive hydrocarbon reserves will be encountered. The cost of
drilling, completing and operating wells is often uncertain. The Company's
drilling operations may be curtailed, delayed or canceled as a result of
numerous factors, including weather conditions, compliance with governmental
requirements and shortages or delays in the delivery of equipment. The
availability of a ready market for the Company's natural gas production depends
on a number of factors, including the demand for and supply of natural gas, the
proximity of natural gas reserves to pipelines, the capacity of such pipelines
and government regulations.
SUBORDINATION OF NOTES; LEVERAGE AND DEBT SERVICE
The Notes will be subordinated obligations of the Company and, as such, will
be subordinated to all of the Company's existing and future Senior Indebtedness.
After giving effect to the Offering and the application of proceeds therefrom,
approximately $19,000,000 principal amount of Senior Indebtedness will be
outstanding. The Company may incur additional Senior Indebtedness from time to
time in the future under the Credit Agreement or otherwise, and the Indenture
relating to the Notes will not restrict the incurrence of any other indebtedness
or liabilities by the Company or its subsidiaries. Upon any distribution of
assets, liquidation, dissolution, reorganization or any similar proceeding by or
relating to the Company, the holders of Senior Indebtedness of the Company would
be entitled to receive payment in full before the holders of the Notes would be
entitled to receive any payment. The terms and conditions of the subordination
provisions pertinent to the Notes are described in more detail in 'Description
of the Notes -- Subordination.'
Further, the Notes will be effectively subordinated to claims of holders of
any preferred stock and claims of creditors (other than the Company) of the
Company's subsidiaries, including trade creditors, secured creditors, taxing
authorities, creditors holding guarantees, and tort claimants. In the event of a
liquidation, reorganization, or similar proceeding relating to a subsidiary,
these persons generally would have priority as to the assets of such subsidiary
over the claims and equity interest of the Company and, thereby indirectly,
holders of the Company's indebtedness, including the Notes. As of December 31,
1993, there were no material outstanding liabilities of subsidiaries of the
Company, but such liabilities may be incurred in the future.
On a pro forma basis after giving effect to the Offering, as of December 31,
1993, the Company's long-term debt (including the current portion) would have
been $137,539,000 and shareholders' equity would have been $33,496,000, and thus
the Company may continue to be considered highly leveraged. See
'Capitalization.' The Company believes that its cash flow from operations,
together with the proceeds from the Offering, the funds available under the
Credit Agreement and its other sources of liquidity, will be adequate to meet
its anticipated requirements for working capital, capital expenditures, interest
payments and scheduled principal payments. See 'Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources.' However, the Company's ability to meet its debt service
obligations will be dependent upon its future performance, which, in turn, will
be subject to general economic conditions and to financial, business and other
factors affecting the operations of the Company, many of which are beyond its
control. Upon the occurrence of a Repurchase Event, the Company may be required,
subject to certain conditions, to purchase some or all of the outstanding Notes
at a price equal to 100% of the principal amount thereof, plus accrued interest.
There can be no assurance that the Company would have sufficient financial
resources at the time of such required purchase to enable it to purchase such
Notes. See 'Description of the Notes -- Certain Rights to Require Repurchase of
Notes.'
GOVERNMENT REGULATION AND ENVIRONMENTAL RISKS
The Company's business is subject to certain laws and regulations relating
to taxation, exploration for and development and production of oil and gas, and
environmental and safety matters in
10
<PAGE>
both the United States and the foreign countries in which the Company or any of
its subsidiaries operates or owns property. Various laws and regulations often
require permits for drilling wells and also cover spacing of wells, the
prevention of waste of oil and gas, including maintenance of certain gas/oil
ratios, rates of production and other matters. The effect of these statutes and
regulations, as well as other regulations that could be promulgated by the
jurisdictions in which the Company has production, could be to limit allowable
production from the Company's properties and thereby to limit its revenues.
The discharge of oil, natural gas or other pollutants into the air, soil or
water may give rise to liabilities to the government and third parties and may
require the Company to incur costs to remedy the discharge. Oil or natural gas
may be discharged in many ways, including from a well or drilling equipment at a
drill site, leakage from storage tanks, pipelines or other gathering and
transportation facilities and discharges resulting from damage to oil or natural
gas wells related to accidents during normal operations, as well as blowouts,
cratering and explosions. Discharged oil and gas may migrate through soil to
water supplies or adjoining properties, giving rise to additional liabilities. A
variety of laws and regulations govern the environmental aspects of oil and gas
production, transportation and processing and may, in addition to other laws,
impose liability in the event of discharges (whether or not accidental), for
failure to notify the proper authorities of a discharge and for
other failures to comply with those laws. For example, the Oil
Pollution Act of 1990 (the 'OPA') imposes a variety of
regulations related to the prevention of oil spills and liability
for damages resulting from such spills in United States waters. On August 25,
1993, the Department of the Interior's Mineral Management Service (the 'MMS')
published an advance notice of intention to adopt a rule under OPA requiring
operators such as the Company to establish $150,000,000 in financial
responsibility. 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. Environmental
laws may also affect the costs of the Company's acquisitions of oil and gas
properties. The Company does not believe that its environmental risks are
materially different from those of comparable companies in the oil and gas
industry. Nevertheless, no assurance can be given that environmental laws will
not, in the future, result in a curtailment of production or a material increase
in the costs of production, development or exploration or otherwise adversely
affect the Company's operations and financial condition. Pollution and similar
environmental risks generally are not fully insurable.
RISKS OF FOREIGN OPERATIONS
Ownership of property interests and production operations in Thailand and
other areas outside the United States are subject to the various risks inherent
in foreign operations. These risks include, among others, currency restrictions
and exchange rate fluctuations, loss of revenue, property and equipment as a
result of hazards such as expropriation, nationalization, war, insurrection and
other political risks, risks of increases in taxes and governmental royalties,
and renegotiation of contracts with governmental entities, as well as changes in
laws and policies governing operations of foreign-based companies.
ABSENCE OF PUBLIC MARKET
The Notes are a new issue for which there is currently no public market. The
Company does not intend to apply for listing of the Notes on any securities
exchange or for quotation on NASDAQ. The Company has been advised by the
Underwriters that, following the completion of the Offering, each of the
Underwriters presently intends to make a market in the Notes, although the
Underwriters are under no obligation to do so and may discontinue any market
making at any time without notice. No assurance can be given regarding the
liquidity of the trading market for the Notes or that an active trading market
for the Notes will develop. If an active public market does not develop, the
market price and liquidity of the Notes may be adversely affected.
See "Underwriting."
11
<PAGE>
THE COMPANY
GENERAL
The Company is an independent oil and gas exploration and production
company, based in Houston, Texas, with an extensive Gulf of Mexico reserve and
acreage position. The Company is also active in the Permian Basin of New Mexico,
and has a 31.7% working interest in a 2.6 million acre concession license in the
Gulf of Thailand. At December 31, 1993, the Company had interests in 597 gross
oil and gas wells. At January 1, 1994, the Company's proved reserves, as
estimated by Ryder Scott, totaled 28.3 MMBbls of oil, condensate and natural gas
liquids and 232.9 Bcf of natural gas. See 'Business and Properties -- Reserves.'
BUSINESS STRATEGY
The Company's business strategy is to maximize profitability and shareholder
value by (i) steadily increasing hydrocarbon production levels, leading to
increased revenues, cash flow, and earnings, (ii) expanding its hydrocarbon
reserves base, (iii) maintaining appropriate levels of debt and interest
expense, and controlling overhead and operating costs, and (iv) expanding
exploration and production activities into new and promising geographic areas
consistent with Company expertise.
To implement its business strategy, the Company currently is focusing
substantial attention and resources in the following geographic areas:
THE GULF OF MEXICO. Approximately 68% of the Company's proved oil and gas
reserves are located in the Gulf of Mexico. Most of these proved reserves are
concentrated in five significant producing areas, including eight fields in the
Eugene Island area located off the Louisiana coast. This concentration allows
the Company to closely manage costs and to develop detailed geologic and other
information relating to its properties. The Company believes that the Gulf of
Mexico will continue to provide the Company with substantial opportunities to
expand its hydrocarbon reserves and to increase its deliverability. The Company
is utilizing its extensive inventory of 3-D seismic data (covering 24 of the
Company's lease blocks and 81 other lease blocks in the Gulf of Mexico) and
conventional 2-D seismic data (approximately one-half million miles of which are
located in the Gulf of Mexico) to locate low risk exploration and development
projects. In addition to conventional vertical and deviated drilling, the
Company will also utilize horizontal drilling (the Company participated in seven
horizontal wells in 1993 alone) to accelerate development of its offshore
projects. To expand its reserves base and increase its deliverability, the
Company will rely on its 24 years of experience in the Gulf of Mexico, where it
holds an extensive acreage position. The Company currently holds interests in 76
offshore blocks, and will continue to evaluate and acquire additional acreage
with significant exploration and development potential. The Company, which
historically has not operated a substantial percentage of its offshore
properties, has assumed the operation of certain of its properties where the
Company believes that its technical expertise and ability to control overhead
and operating costs will enhance its economic interests. In its role as
operator, the Company recently used a 3-D seismic survey to pinpoint the
location of potentially recoverable shallow natural gas reserves on a portion of
its Eugene Island Block 295 field, and horizontal drilling technology, including
five horizontal wells, to optimize the exploitation of the field's shallow
natural gas reserves.
NEW MEXICO. The Company continues to enjoy substantial success in its
efforts to increase liquids production from its properties in southeastern New
Mexico. The Company is currently one of the most active companies drilling for
oil and gas in the southeastern New Mexico portion of the Permian Basin, where,
from late 1989 through the end of 1993, the Company and its partners have
drilled and completed as productive 151 consecutive wells, including 58 wells
during 1993 alone. The Company has achieved rapid cost recovery with respect to
its New Mexico wells drilled to date because of relatively low capital costs and
high initial rates of production. Due to its historical drilling success, its
current undeveloped acreage position and its significant budgetary commitment to
additional drilling, the Company expects its New Mexico operations to continue
to be a source of
12
<PAGE>
significant reserves and of liquids production. The Company's primary drilling
objective in southeastern New Mexico is the Brushy Canyon (Delaware) formation,
which produces oil at depths of approximately 6,000 to 9,000 feet. The Company's
net revenue interest portion of daily liquid hydrocarbon production in New
Mexico averaged approximately 3,700 Bbls during 1993, compared to approximately
2,050 Bbls per day during 1992, an increase of approximately 80%.
THE GULF OF THAILAND. The Company has conducted international exploration
activities since the late 1970's in numerous oil and gas provinces in various
parts of the world. The Company pursues a strategy of evaluating potentially
high return prospects in areas of the world with a stable political and
financial climate, such as certain European and ASEAN countries. Consistent with
this strategy, in August 1991, the Company and its joint venture partners were
awarded a license to explore for oil and gas on a 2.6 million acre concession,
Block B8/32, in the Gulf of Thailand. The concession is located in a basin on
trend with several oil and gas fields operated by Unocal Thailand Ltd. Through
November 1993, Unocal Thailand Ltd. has reported cumulative production from more
than 700 wells in these fields totaling approximately 2 trillion cubic feet of
natural gas and 71 MMBbls of oil and condensate. Following an initial evaluation
of the Thailand concession area, the Company and its joint venture partners
drilled five exploratory wells on three separately identified seismic
structures. The first well drilled, the Tantawan No. 1, successfully tested a
large, complexly faulted, anticlinal structure with production tests from five
intervals resulting in calculated cumulative flow rates of 6,260 Bbls of oil and
condensate and 25,750 Mcf of natural gas per day. During 1993, the Company and
its joint venture partners shot, processed and evaluated approximately 9,000
kilometers of new 3-D seismic data over and around the Tantawan No. 1 well. In
late 1993, the Company drilled the Tantawan No. 2 and the Tantawan No. 3
exploratory wells on the Tantawan structure. The Tantawan No. 2 well
successfully delineated a previously untested fault block to the east of the
Tantawan No. 1 well with production tests from six intervals resulting in
calculated cumulative flow rates of 70,300 Mcf of natural gas and 1,720 Bbls of
condensate per day. The Tantawan No. 3 well successfully delineated a third
untested fault block on the Tantawan structure located approximately two miles
north of the Tantawan No. 1 and No. 2 wells. Production tests from this third
Tantawan well were reported in January 1994, with production tests from five
intervals resulting in calculated cumulative flow rates of 40,660 Mcf of natural
gas and 8,684 Bbls of oil and condensate per day. As a result of its successful
exploration drilling program, the Company's Thailand concession now accounts for
approximately 14% of the Company's total estimated net proved reserves of
natural gas, approximately 19% of the Company's total estimated net proved
reserves of oil, condensate and natural gas liquids and approximately 16% of the
Company's total net proved oil and gas equivalent reserves. During 1994,
additional delineation wells on the Tantawan structure are planned. Based upon
the results of such drilling, the Company and its partners will agree upon the
type of development plan needed to commence production in this area. In
addition, in late 1993, the Company and its joint venture partners began
shooting and processing additional 3-D seismic data on a different portion of
Block B8/32. Following evaluation of this seismic data, additional exploratory
wells are expected to be drilled by the Company and its joint venture partners
on as yet untested seismic structures identified on Block B8/32.
While maintaining an active exploration and development program, the Company
also continues to focus on its strategy of maintaining appropriate levels of
debt and interest expense. The Company has reduced its total debt and production
payment obligations from $472,400,000 as of January 1, 1988, to $134,539,000 as
of December 31, 1993, a decrease of approximately 72%.
The reduction of total debt and production payment obligations has allowed
the Company to devote increased amounts of its cash flow toward exploration and
development of its premium property base. The Company's drilling successes have
resulted in increased equivalent oil and gas production during 1992 and 1993, as
compared to the prior five years, while simultaneously expanding its reserves
base. In 1992 and 1993, the Company replaced 143% and 204%, respectively, of its
total production of proved hydrocarbon reserves. The Company believes that the
increased liquidity and increased average maturity of its outstanding
indebtedness resulting from the Offering
13
<PAGE>
will provide the Company with additional financial flexibility to pursue its
business strategy and maximize shareholder value. For 1994, the Company's Board
of Directors has authorized capital and exploration expenditures of $75,000,000,
approximately equal to the Company's capital and exploration expenditures of
approximately $74,600,000 in 1993. See 'The Company,' 'Management's Discussion
and Analysis of Financial Condition and Results of Operations' and 'Business and
Properties.'
The Company's principal executive offices are located at 5 Greenway Plaza,
Suite 2700, Houston, Texas 77046. Its mailing address is P.O. Box 2504, Houston,
Texas 77252-2504. The telephone number is (713) 297-5000.
USE OF PROCEEDS
The net proceeds to the Company from the sale of the Notes offered hereby
are estimated to be approximately $72,775,000 (after deducting underwriting
discounts and expenses of the Offering), or approximately $83,743,750 if the
Underwriters' over-allotment option is exercised in full. The Company intends to
apply approximately $24,500,000 (including prepayment premiums) of the net
proceeds of the Offering to retire its 10.25% Convertible Subordinated Notes due
1999 (the '10.25% Notes'). The Company intends to apply the balance of the net
proceeds to repay outstanding Senior Indebtedness under the Credit Agreement
which, as of December 31, 1993, stood at $67,000,000 and bore interest at a
floating rate that was approximately 5 3/8%. The Company may borrow additional
amounts under the Credit Agreement or otherwise from time to time to fund
capital expenditures or for other corporate purposes. The Company believes that
the increased liquidity and increased average maturity of its outstanding
indebtedness resulting from the Offering will provide the Company with
additional financial flexibility to pursue its business strategy and maximize
shareholder value. Pending application of the proceeds of the Offering as
described above, a portion of such proceeds may be invested in short-term
instruments. See 'The Company,' 'Capitalization,' and 'Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources.'
14
<PAGE>
CAPITALIZATION
The following table sets forth the consolidated capitalization of the
Company and its subsidiaries at December 31, 1993 (assuming net proceeds of
$72,775,000, less the call premium on the early retirement of the 10.25% Notes
and excess cash). The table has also been adjusted to reflect the issuance
of the Notes offered hereby and the application of the net proceeds therefrom
as described under 'Use of Proceeds.' This table should be read in conjunction
with the Consolidated Financial Statements and related notes thereto included
elsewhere in this Prospectus.
DECEMBER 31, 1993
HISTORICAL AS ADJUSTED
(IN THOUSANDS)
Long-term debt (including current
portion):
Credit Agreement indebtedness------ $ 67,000 $ 19,000
5 1/2% Convertible Subordinated
Notes due 2004------------------- -- 75,000
10.25% Convertible Subordinated
Notes due 1999------------------- 24,000 --
8% Convertible Subordinated
Debentures due 2005-------------- 43,539 43,539
Total long-term debt------------- 134,539 137,539
Shareholders' equity:
Preferred stock, $1 par value;
2,000,000 shares authorized; no
shares issued and
outstanding-------------------- -- --
Common stock, $1 par value;
43,333,333 shares authorized;
32,449,197 shares issued--------- 32,449 32,449
Additional capital----------------- 125,919 125,919
Retained earnings (deficit)-------- (124,241) (124,548)(a)
Treasury stock, at cost------------ (324) (324)
Total shareholders' equity------- 33,803 33,496
Total capitalization----------------- $ 168,342 $ 171,035
(a) Adjusted to reflect the after-tax effect of the early redemption of
$16,000,000 of 10.25% Notes at 102.95% of their principal amount.
15
<PAGE>
PRICE RANGE OF COMMON STOCK AND DIVIDENDS
The following table shows the range of low and high sales prices of the
Company's Common Stock on the New York Stock Exchange composite tape where the
Company's Common Stock trades under the symbol PPP. The Company's Common Stock
is also listed on the Pacific Stock Exchange.
LOW HIGH
1992
1st Quarter---------------------- $ 5 1/8 $ 6 1/2
2nd Quarter---------------------- 5 1/8 6 3/8
3rd Quarter---------------------- 5 1/2 10 3/8
4th Quarter---------------------- 9 3/4 13 7/8
1993
1st Quarter---------------------- $ 9 3/4 $ 17 1/4
2nd Quarter---------------------- 16 1/8 21
3rd Quarter---------------------- 13 5/8 19 1/8
4th Quarter---------------------- 14 3/8 19 3/4
1994
1st Quarter (through March 16,
1994)-------------------------- $ 16 1/2 $ 21 5/8
The closing sale price of the Company's Common Stock on the New York Stock
Exchange as of a recent date is set forth on the cover page of this Prospectus.
DIVIDEND POLICY
The Board of Directors of the Company has not declared cash dividends on the
Company's Common Stock since the fourth quarter of 1986, and has no current
plans to pay dividends. See 'Description of Capital Stock.'
Pursuant to various agreements under which the Company has borrowed funds,
the Company may not, subject to certain exceptions, pay any dividends on its
capital stock or make any other distributions on shares of its capital stock
(other than dividends or distributions payable solely in shares of such capital
stock) or acquire for value any shares of its capital stock if (after giving
effect to the proposed payment, distribution, or acquisition) the aggregate
amount of all such payments, distributions or acquisitions on and after a
specified date would exceed an amount determined based on the consolidated
income or cash flow of the Company and its consolidated subsidiaries from and
after such date. As of December 31, 1993, $33,803,000 was available for
dividends under the most restrictive of such limitations.
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<PAGE>
SELECTED FINANCIAL AND OPERATING DATA
The selected financial data presented below for, and as of the end of, each
of the years in the five-year period ended December 31, 1993, are derived from
the consolidated financial statements of the Company and its subsidiaries, which
have been audited by independent public accountants. The information presented
under the caption 'Production (Sales) Data' and 'Other Financial Data and
Selected Ratios' is unaudited. This data should be read in conjunction with the
consolidated financial statements and related notes thereto and 'Management's
Discussion and Analysis of Financial Condition and Results of Operations'
included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
1993 1992 1991 1990 1989
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Crude oil and condensate----------- $ 64,042 $ 64,224 $ 54,420 $ 54,018 $ 41,396
Natural gas------------------------ 66,173 67,366 63,225 74,111 76,287
Natural gas liquids---------------- 7,288 5,833 3,442 3,496 3,516
Other, net------------------------- (950) 1,705 3,338 794 (79)
Oil and gas revenues------------- 136,553 139,128 124,425 132,419 121,120
Interest on tax refunds------------ 2,322(a) -- -- 22,499(a) --
Gains (losses) on sales------------ 679 1,702 44 (98) (173)
Total------------------------ 139,554 140,830 124,469 154,820 120,947
Operating costs and expenses:
Lease operating-------------------- 26,633 25,842 28,192 24,558 22,377
General and administrative--------- 14,550 13,129 14,555 13,458 11,829
Exploration------------------------ 2,455 3,102 2,408 2,029 2,078
Dry hole and impairment------------ 4,690 9,314 4,554 5,501 8,443
Depreciation, depletion and
amortization--------------------- 40,693 42,302 37,521 36,334 38,845
Total------------------------ 89,021 93,689 87,230 81,880 83,572
Operating income--------------------- 50,533 47,141 37,239 72,940 37,375
Interest:
Charges-------------------------- (10,956) (19,036) (24,946) (31,441) (37,458)
Income--------------------------- 14 191 1,686 1,244 1,615
Capitalized---------------------- 451 391 637 741 1,106
Income before income taxes and
extraordinary item----------------- 40,042 28,687 14,616 43,484 2,638
Income tax (expense) benefit--------- (14,981) (10,192) (4,294) 552 --
Income before extraordinary item----- 25,061 18,495 10,322 44,036 2,638
Extraordinary gain on purchase of
debt------------------------------- -- -- 1,336 -- --
Net income--------------------------- $ 25,061 $ 18,495 $ 11,658 $ 44,036 $ 2,638
Primary and fully diluted earnings
per share:
Before extraordinary item-------- $ 0.76 $ 0.66 $ 0.37 $ 1.69 $ 0.11
Extraordinary item--------------- -- -- 0.05 -- --
Net income----------------------- $ 0.76 $ 0.66 $ 0.42 $ 1.69 $ 0.11
(TABLE CONTINUED ON FOLLOWING PAGE)
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<PAGE>
SELECTED FINANCIAL AND OPERATING DATA -- (CONTINUED)
<CAPTION>
YEAR ENDED DECEMBER 31,
1993 1992 1991 1990 1989
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AND UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA (AT PERIOD END):
Total assets------------------------- $ 239,774 $ 206,347 $ 213,772 $ 244,226 $ 227,508
Long-term debt, excluding current
portion---------------------------- 130,539 129,260 184,260 217,000 264,000
Production payment obligation,
excluding current portion---------- -- 14,337 37,805 43,019 47,036
Shareholders' equity (deficit)------- 33,803 5,648 (56,636) (68,429) (132,557)
PRODUCTION (SALES) DATA:
Net daily average and weighted
average price:
Natural gas:
Mcf per day---------------------- 91,700 105,200 104,200 107,300 111,300
Price per Mcf-------------------- $ 1.98 $ 1.75 $ 1.66 $ 1.89 $ 1.88
Crude oil and condensate:
Bbls per day--------------------- 9,851 8,699 7,108 6,209 6,013
Price per Bbl-------------------- $ 17.81 $ 20.17 $ 20.98 $ 23.84 $ 18.86
Natural gas liquids:
Bbls per day--------------------- 1,678 1,181 663 697 948
Price per Bbl-------------------- $ 11.90 $ 13.50 $ 14.21 $ 13.75 $ 10.16
OTHER FINANCIAL DATA AND SELECTED
RATIOS:
Capital and exploration expenditures
(excludes capitalized interest)---- $ 74,600 $ 41,300 $ 53,100 $ 39,500 $ 25,800
EBITDA(b)---------------------------- $ 96,381 $ 99,339 $ 81,637 $ 116,760 $ 87,384
EBITDA/Net interest expense---------- 9.2 5.3 3.4 3.8 2.4
Ratio of earnings to fixed
charges(c)------------------------- 4.5 2.5 1.6 2.3 1.0
Long-term obligations/Total proved
reserves (BOE)(d)------------------ $ 1.95 $ 2.52 $ 4.22 $ 4.70 $ 5.49
(a) In late 1990, the Company entered into a settlement agreement with the
Internal Revenue Service (the 'IRS') for a refund of $8,607,000 in taxes for
taxable years 1976 through 1985 which, together with accrued interest of
$20,395,000, resulted in a refund receivable of $29,002,000 through December
31, 1990. The refund and interest income together with the reversal of
previously accrued interest expense of $2,104,000 contributed $23,456,000 or
$0.90 per share to earnings in 1990. The refund and the additional accrued
interest was received by the Company on May 31, 1991. In late 1993, the
Company recognized $2,322,000 of interest income related to a settlement
with the IRS for the refund of $998,000 in taxes for taxable years 1976
through 1984. The interest income contributed $1,509,000 or $0.05 per share
to earnings in 1993.
(b) EBITDA represents income from continuing operations before provision for
income taxes, interest expense, interest income, interest capitalized,
depreciation and amortization, and dry hole and impairment costs. EBITDA is
presented as a measure of the Company's debt service ability, and not as an
alternative to (i) operating income (as determined in accordance with
generally accepted accounting principles) as an indicator of the Company's
operating performance, or (ii) cash flows from operating activities (as
determined in accordance with generally accepted accounting principles) as a
measure of liquidity.
(c) Income before taxes and extraordinary item plus fixed charges (net of
capitalized interest) divided by fixed charges. Fixed charges are defined as
interest expense plus the portion of rental expense representing interest.
(d) Long-term obligations include long-term debt (excluding current maturities)
and the non-current portion of the Eugene Island Block 330 Production
Payment obligation until such obligation was satisfied in 1993. Total proved
reserves are expressed on an energy equivalent basis.
</TABLE>
18
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
The Company reported net income for 1993 of $25,061,000 or $0.76 per share
compared to net income for 1992 of $18,495,000 or $0.66 per share and net income
for 1991 of $11,658,000 or $0.42 per share. Included in net income for 1991 are
extraordinary gains of $1,336,000 or $0.05 per share in connection with
purchases at less than face value of the Company's 8% Convertible Subordinated
Debentures due 2005 (the '8% Debentures'). Earnings per common share are based
on the weighted average number of shares of common and common equivalent shares
outstanding for 1993 of 32,860,000 compared to 27,929,000 for 1992 and
27,611,000 for 1991. The increases in the weighted average number of common and
common equivalent shares outstanding for 1993 primarily related to the issuance
of 4,500,000 shares of Common Stock in December 1992 as set forth in the
Consolidated Statements of Shareholders' Equity included in the 'Financial
Statements' attached to, and forming a part of, this Prospectus.
The Company's total revenues for 1993 were $139,554,000, or approximately
equal to total revenues of $140,830,000 for 1992, and an increase of
approximately 12% from total revenues of $124,469,000 for 1991. The Company's
oil and gas revenues for 1993 were $136,553,000, a slight decrease of
approximately 2% from oil and gas revenues of $139,128,000 for 1992, and an
increase of approximately 10% from oil and gas revenues of $124,425,000 for
1991. The following table reflects an analysis of variances in the Company's oil
and gas revenues between 1993 and the previous two years:
1993 COMPARED TO
1992 1991
(IN THOUSANDS)
Increase (decrease) in oil and gas
revenues resulting from
variances in:
Natural gas
Price------------------------ $ 8,738 $ 11,984
Production------------------- (9,931) (9,036)
(1,193) 2,948
Crude oil and condensate
Price------------------------ (7,514) (8,209)
Production------------------- 7,332 17,831
(182) 9,622
Natural gas liquids
Price------------------------ (689) (560)
Production------------------- 2,144 4,406
1,455 3,846
Other, net----------------------- (2,655) (4,288)
Increase (decrease) in oil and gas
revenues--------------------------- $ (2,575) $ 12,128
Average natural gas prices received by the Company for the two years prior
to 1991 were relatively stable. Though seasonal variations were experienced, the
average annual prices received per Mcf were $1.88 for 1989 and $1.89 for 1990.
The industry's perceived ability to deliver more natural gas on a daily basis
than demanded by customers resulted in a decrease in the average annual price
for 1991 to $1.66 per Mcf. Prices of natural gas reached a low in February 1992,
when the Company's prices averaged only $1.13 per Mcf, during a time of
typically high winter prices, due, in part, to decreased demand resulting from a
milder than anticipated winter. The natural gas prices received by
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<PAGE>
the Company then began recovering again, averaging $1.75 per Mcf for
1992 and $1.98 per Mcf for 1993. Prices recovered after February 1992
due to late winter cold snaps which drew down natural gas storage
supplies and created demand in the spring and summer to
replenish storage facilities. In late August 1992, production in the
Gulf of Mexico was shut-in for approximately four days as a result of Hurricane
Andrew. This shut-in and decreased production from hurricane damage put upward
pressure on natural gas prices for the balance of the year. Natural gas prices
continued to strengthen in 1993, partially as a result of severe late winter
weather that drew down natural gas storage supplies which, coupled with
relatively high crude oil prices that inhibited fuel switching from natural gas
to residual heating oil at that time, created a substantial demand in the spring
and the summer to replenish depleted storage facilities and to supply natural
gas for the industrial and electric generation markets.
Natural gas production in 1993 averaged 91.7 MMcf per day, a decrease of
approximately 13% from average production of 105.2 MMcf per day in 1992, and a
decrease of approximately 12% from average production of 104.2 MMcf per day in
1991. The Company's decrease in natural gas production during 1993 compared to
prior periods was primarily related to decreased natural gas deliverability from
certain of the Company's Gulf of Mexico wells; production downtime due to
drilling, workover and maintenance operations designed to increase the Company's
deliverability; weather related problems and the exchange of properties
discussed in 'Business and Properties -- Domestic Offshore Acquisitions; Lease
Acquisitions' which temporarily reduced the Company's delivery capacity. The
Company anticipates that, as a result of its workover and drilling program, when
natural gas production commences from its new platform currently under
construction on Eugene Island Block 295 (which construction is scheduled,
weather permitting, to be completed during March 1994) the Company's natural gas
production will increase substantially from its average 1993 production rates.
Crude oil and condensate prices averaged $17.81 per Bbl in 1993 compared to
$20.17 per Bbl in 1992 and $20.98 per Bbl in 1991. Crude oil and condensate
prices were relatively stable during 1991, 1992 and the first six months of
1993. However, commencing in July 1993, the average price per Bbl that the
Company received for its production began to decline until, by December 1993,
the average price per Bbl for crude oil and condensate that the Company received
for its production averaged only $13.39 per Bbl. The decrease in the average
price that the Company receives for its crude oil and condensate production has
resulted primarily from a worldwide excess of crude oil supplies resulting from
increased production from both Organization of Petroleum Exporting Countries
('OPEC') and certain non-OPEC countries coupled with flat or only marginally
increased demand from consumer countries. The Company has entered into a crude
oil swap agreement with another party in which it swapped the floating market
price it would receive from purchasers of its crude oil for a fixed price of
$16.00 per Bbl on 1,000 Bbls per day of its production. The agreement expires
July 31, 1994, but may be extended through January 31, 1995, at the other
party's option.
Crude oil and condensate production for 1993 averaged 9,851 Bbls per day, an
increase of approximately 13% from 8,699 Bbls per day for 1992, and an increase
of approximately 39% from 7,108 Bbls per day for 1991. The increase in crude oil
and condensate production was a result of ongoing development programs both
offshore (primarily in the Eugene Island area) and onshore in several fields
located in Lea and Eddy counties of southeastern New Mexico.
Liquid products are often extracted from natural gas streams and sold
separately as natural gas liquids ('NGL'). The Company's NGL production averaged
1,678 Bbls per day for 1993, an increase of approximately 42% from an average of
1,181 Bbls per day for 1992 and an increase of approximately 153% from an
average of 663 Bbls per day for 1991. The Company's NGL production during 1993,
compared to prior periods, increased primarily as a result of extracting liquids
from several new high Btu content wells, increased ownership interest in plants,
and capital improvements which increased plant efficiency.
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The Company's total liquids production during 1993, including crude oil,
condensate and NGL, averaged 11,529 Bbls per day, an increase of approximately
17% from an average total liquids production of 9,880 Bbls per day for 1992,
and an increase of approximately 48% from an average total liquids production
of 7,771 Bbls per day for 1991.
'Other, net' revenues for 1993, 1992, and 1991 included, among others, the
following significant items:
1993 1992 1991
(IN THOUSANDS)
Offset of FERC Order 93A adjustments
against FERC Order 94A
obligations------------------------ $ -- $ 1,642 $ --
Natural gas sales contract
settlement------------------------- -- -- 2,750
Gains on retirement of debt---------- -- -- 646
Settlement of federal and state
royalty disputes------------------- (803) (65) --
Other, net--------------------------- (147) 128 (58)
$ (950) $ 1,705 $ 3,338
For 1993 and 1992, the Company made adjustments to its revenues to reflect
the settlement of certain litigation with the State of Louisiana regarding past
royalty disputes pertaining to the Company's offshore state leases. For 1992
additional adjustments were also made to reflect an agreement with the MMS to
allow the Company to offset Federal Energy Regulatory Commission ('FERC') Order
93A payments previously made by the Company on behalf of the MMS against FERC
Order 94A obligations due from the Company and the resulting overaccrual of
related interest expenses. For 1991, the Company recorded adjustments to reflect
the settlement of a dispute regarding a natural gas sales contract and the
purchase, at a discount, of certain of 8% Debentures on the open market.
Lease operating expenses for 1993 were $26,633,000, an increase of
approximately 3% from lease operating expenses of $25,842,000 for 1992, but a
decrease of approximately 6% from lease operating expenses of $28,192,000 for
1991. The increase in lease operating expenses for 1993, compared to 1992, was
primarily related to increased operating costs on existing properties, as well
as increased operating costs related to additional properties brought on
production in the second half of 1992. The increased operating costs were
partially offset by lower maintenance costs. The decrease in lease operating
expenses for 1993, compared to 1991, was primarily related to a decrease in
special maintenance projects and to a decrease in lifting costs.
General and administrative expenses for 1993 were $14,550,000, an increase
of approximately 11% from general and administrative expenses of $13,129,000 for
1992, but were essentially equal to general and administrative expenses of
$14,555,000 for 1991. The increase in general and administrative expenses for
1993, compared to 1992, was primarily related to increased business insurance
premiums resulting from the Company's increased drilling activity and insurance
premium rate increases resulting from the insurance industry's recent loss
experience in general, rather than losses specifically relating to the Company's
operations, as well as normal salary adjustments and a 4% increase in the
Company's work force resulting from increased activity.
Exploration expenses consist primarily of delay rentals and geological and
geophysical ('G&G') costs which are expensed as incurred. Exploration expenses
for 1993 were $2,455,000, a decrease of approximately 21% from exploration
expenses of $3,102,000 for 1992, and a slight increase of approximately 2% from
exploration expenses of $2,408,000 for 1991. The decline in exploration expenses
for 1993, compared to 1992, was primarily related to the costs of conducting a
G&G survey, primarily in 1992, on the Company's oil and gas concession in the
Kingdom of Thailand.
Dry hole and impairment expenses relate to costs of unsuccessful wells
drilled along with impairments to the associated unproved property costs and
impairments to previously proved property costs as a result of decreases in
expected reserves. The Company's dry hole and impairment
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expenses for 1993 were $4,690,000, a decrease of approximately 50% from dry
hole and impairment expenses of $9,314,000 for 1992, but a slight increase of
approximately 3% from dry hole and impairment expenses of $4,554,000 for 1991.
The Company accounts for its oil and gas activities using the successful
efforts method of accounting. Under the successful efforts method, lease
acquisition costs and all development costs are capitalized. Unproved properties
are reviewed quarterly to determine if there has been impairment of the carrying
value, with any such impairment charged to expense in the period. Exploratory
drilling costs are capitalized until the results are determined. If proved
reserves are not discovered, the exploratory drilling costs are expensed. Other
exploratory costs are expensed as incurred.
The provision for depreciation, depletion and amortization ('DD&A') is
determined on a field-by-field basis using the units of production method. The
Company's DD&A expense for 1993 was $40,693,000, a decrease of approximately 4%
from DD&A expenses of $42,302,000 for 1992, but an increase of approximately 8%
from DD&A expenses of $37,521,000 for 1991. The decreases in the Company's DD&A
expenses for 1993, compared to 1992, were primarily due to a decrease in natural
gas production. The increases in the Company's DD&A expenses for 1993, compared
to 1991, were primarily related to increased volumes produced (largely related
to the increased crude oil and condensate production discussed earlier) and, to
a lesser extent, an increase in the composite DD&A rate. See 'Financial
Statements -- Note 1 of Notes to Consolidated Financial Statements.'
Interest charges for 1993 were $10,956,000, a decrease of approximately 42%
from interest charges of $19,036,000 for 1992 and a decrease of approximately
56% from interest charges of $24,946,000 for 1991. The decrease in interest
expense for 1993, compared to 1992 and 1991, related primarily to the retirement
or refinancing of high cost debt at more favorable interest rates and the
reduction in total debt to $134,539,000 on December 31, 1993, from $158,114,000
(including the production payment obligation) on December 31, 1992, a decrease
of approximately 15%. In addition, interest expense has also been reduced, to a
limited extent, by decreases in applicable floating interest rates. As of
December 31, 1993, the Company had entered into swap agreements on $15,000,000
of its bank debt, $5,000,000 of which terminated in January 1994 and $10,000,000
of which terminates in July 1994. The swap agreements on the bank debt
effectively change the interest the Company pays on its bank debt from variable
rates to fixed rates which average 5.78% on the $15,000,000.
LIQUIDITY AND CAPITAL RESOURCES
The Consolidated Statement of Cash Flows for the year ended December 31,
1993 reflects net cash provided by operating activities of $83,144,000, proceeds
from sales of tubular stock and non-strategic properties of $2,713,000 and cash
received from stock options exercised of $2,026,000. The Company invested
$62,353,000 of such cash flow in capital projects during 1993. The Company
continued to reduce its total debt and production payment obligation from
$158,114,000 at December 31, 1992 to $134,539,000 at December 31, 1993, a
decrease of $23,575,000 or approximately 15% of the Company's combined debt and
Eugene Island 330 production payment obligation since the end of 1992, and a
decline of approximately 42% in its combined debt and Eugene Island 330
production payment obligation since the end of 1991. During 1993, the Company
retired its Eugene Island 330 production payment obligation. The Company's cash
and cash investments were $6,713,000 at December 31, 1993.
The Company's capital and exploration budget for 1994 has been established
by the Company's Board of Directors at $75,000,000, or approximately equal to
the Company's capital and exploration expenditures of approximately $74,600,000
for 1993, an increase of 82% over capital and exploration expenditures of
approximately $41,300,000 for 1992 and an increase of 41% over capital and
exploration expenditures of approximately $53,100,000 for 1991.
In addition to anticipated capital and exploration expenses as of December
31, 1993, other material 1994 cash requirements that the Company anticipates
include ongoing operating, general
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and administrative, income tax, and interest expenses. Cash requirements for
future payments of federal income taxes are expected to be greater
than those experienced in the immediate past. The increased
tax payments result from expected increases in taxable income,
increased tax rates and the utilization in 1993 and prior years
of available tax credits and net operating tax loss carry-forwards. The Company
currently anticipates that cash provided by operating activities and funds
available under its Credit Agreement will be sufficient to fund the Company's
ongoing expenses and the Company's 1994 capital and exploration budget. See 'Use
of Proceeds.'
As of December 31, 1993, the Company amended its bank credit agreement (the
'Credit Agreement'). The Credit Agreement currently provides for a $100,000,000
revolving/term credit facility which will be fully revolving until June 29,
1996, after which the balance will be due in eight quarterly term loan
installments, commencing July 31, 1996. The amount that may be borrowed under
the Credit Agreement may not exceed a borrowing base, determined semiannually by
the lenders in accordance with the Credit Agreement, based on the discounted
present value of certain of the Company's oil and gas reserves. The borrowing
base currently exceeds $100,000,000. The Credit Agreement is governed by various
financial and other covenants, including requirements to maintain positive
working capital and a specified fixed charge ratio and limitations on debt,
dividends, mergers and consolidations and asset dispositions. See 'Price Range
of Common Stock and Dividends.' Upon the occurrence or declaration of certain
events, the banks would be entitled to a security interest in the borrowing base
properties, which include substantially all of the Company's domestic
properties. Borrowings under the Credit Agreement bear interest at Base (Prime)
rate plus 1/4%, a certificate of deposit rate plus 1 7/8%, or LIBOR plus
1 3/4%, at the Company's option. A commitment fee of 1/2 of 1% per annum of the
unborrowed amount under the Credit Agreement is also due. As of December 31,
1993, indebtedness in the principal amount of $67,000,000 was outstanding under
the Credit Agreement.
The outstanding principal amount of the 10.25% Notes was $24,000,000 as of
December 31, 1993. The 10.25% Notes are convertible into Common Stock at $23.95
per share, subject to adjustment in certain circumstances, including stock
splits, and require annual sinking fund payments of $4,000,000 each April, with
a final maturity of April 1, 1999. A portion of the proceeds of the Offering
will be used to repay the 10.25% Notes in full. See 'Use of Proceeds.' The
outstanding principal amount of the 8% Debentures was $43,539,000 as of December
31, 1993. The 8% Debentures are convertible into Common Stock at $39.50 per
share, subject to adjustment in certain circumstances, including stock splits,
and are also subject to mandatory annual sinking fund requirements of $3,000,000
due each December, with a final maturity of December 31, 2005. The Company
currently has $4,460,000 face amount of 8% Debentures which it may tender in
satisfaction of future sinking fund requirements. See 'Financial
Statements -- Note 3 to Notes to Consolidated Financial Statements.'
OTHER MATTERS
Publicly held companies are asked to comment on the effects of inflation on
their business. Currently annual inflation in terms of the decrease in the
general purchasing power of the dollar is running much below the general annual
inflation rates of several years ago. While the Company, like other companies,
continues to be affected by fluctuations in the purchasing power of the dollar,
such effect is not currently considered significant.
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BUSINESS AND PROPERTIES
GENERAL
The Company was incorporated in 1970 and is engaged in oil and gas
exploration, development and production activities on its properties located
offshore in the Gulf of Mexico and onshore in the United States. The Company is
also engaged in exploration of its license concession in the Gulf of Thailand,
and is evaluating a development program in connection with its recently
announced oil and gas discoveries on that concession. The Company has interests
in 76 lease blocks offshore Louisiana and Texas, approximately 93,000 gross
acres onshore in the United States, approximately 2,635,000 gross acres offshore
in the Kingdom of Thailand, and approximately 1,965,000 gross acres in
Australia. The Company, which historically has not operated a substantial
percentage of its offshore properties, has assumed operatorship of certain of
its properties where the Company believes that its technical expertise and
ability to control overhead and operating costs will enhance its economic
interests.
DOMESTIC OFFSHORE OPERATIONS
Historically, the Company's interests have been concentrated in the Gulf of
Mexico, where approximately 81% of the Company's domestic proved reserves and
68% of its total proved reserves are now located. During 1993, approximately 75%
of the Company's natural gas equivalent production was from its domestic
offshore properties, contributing approximately 75% of consolidated oil and gas
revenues. Four offshore producing areas, Eugene Island, South Marsh Island, Main
Pass and East Cameron, account for approximately 52% of the Company's net proved
natural gas reserves and approximately 56% of the Company's proved crude oil,
condensate and natural gas liquids reserves. Eugene Island is the Company's
largest producing area with 1993 average net revenue interest production (net to
the Company's interest and net of royalty burdens) of 24 MMcf per day of natural
gas and 4,600 Bbls per day of oil, condensate and natural gas liquids.
LEASE ACQUISITIONS
The Company has participated with other companies in bidding on and
acquiring interests in federal leases offshore in the Gulf of Mexico since
December 1970. As a result of such sales and subsequent activities, the Company
owns interests in 70 federal leases offshore Louisiana and Texas. Federal leases
generally have primary terms of five years, subject to extension by development
and production operations. The Company also owns interests in six leases in
state waters offshore Louisiana.
As part of its strategy, the Company intends to continue an active lease
evaluation program in the Gulf of Mexico in order to identify exploration and
exploitation opportunities. The Department of the Interior has announced its
intention to hold two lease sales during 1994 covering federal acreage in the
Central and Western portions of the Gulf of Mexico; and it is anticipated that
various states will also hold sales covering state acreage from time to time. As
in the case of prior sales, the extent to which the Company participates in
future bidding will depend on the availability of funds and its estimates of
hydrocarbon deposits, operating expenses and future revenues which reasonably
may be expected from available lease blocks. Such estimates typically take into
account, among other things, estimates of future hydrocarbon prices, federal
regulations, and taxation policies applicable to the petroleum industry.
It is also the Company's objective to acquire certain producing properties
where additional low_risk drilling or improved production methods by the Company
can provide attractive rates of return. During 1993, the Company acquired a 50%
working interest in South Pass Block 50 and acquired an additional approximately
17% working interest in Ship Shoal Block 240. In late 1993, the Company effected
an exchange of working interests in certain federal offshore lease blocks with
another working interest owner in such blocks. As a result of this exchange, the
Company increased its working interest in the following five blocks: Eugene
Island 256 (from 41.5% to 69.2%), Eugene Island 295 (from 60% to 100% on 3,125
acres above 3,000 feet, from 12% to 20% on 1,875 acres
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above 3,000 feet and from 12% to 20% on all of the block below 3,000 feet),
Eugene Island 261 (from 43.3% to 66.6%) and West Cameron blocks 252 and 253
(from 24% to 80%). In exchange, the Company assigned various working interests
in 13 blocks to the other working interest owner. The Company effected the
exchange primarily because it believes that this exchange will result in
significant increased exploitation and exploration potential in the Eugene
Island and West Cameron areas. This exchange of working interests is also
consistent with the Company's strategy of increasing its working interest in its
core areas. In connection with this exchange, the Company became the operator
for the joint venture partners on certain of these blocks.
EXPLORATION AND DEVELOPMENT
The scope of exploration and development programs relating to the Company's
offshore interests is affected by prices for oil and gas, and by federal, state
and local legislation, regulations and ordinances applicable to the petroleum
industry. The Company's domestic offshore capital and exploration expenditures
for 1993 were approximately $39,000,000, or 122% higher than the Company's
domestic offshore capital and exploration expenditures of approximately
$17,600,000 for 1992 and 23% higher than the Company's domestic offshore capital
and exploration expenditures of approximately $31,700,000 for 1991. Development
and production related projects represented 86% of the Company's 1993 domestic
offshore capital and exploration expenditures. See 'Management's Discussion and
Analysis of Financial Condition and Results of Operations.'
Leases acquired by the Company and other participants in its bidding groups
are customarily committed, on a block-by-block basis, to separate operating
agreements under which the appointed operator supervises exploration and
development operations for the account and at the expense of the group. These
agreements usually contain terms and conditions which have become relatively
standardized in the industry. Major decisions regarding development and
operations typically require the consent of at least a majority (in working
interest) of the participants. Because the Company generally has a meaningful
working interest position, the Company believes it can influence decisions
regarding development and operations even though it may not be the operator of a
particular lease. The Company, which historically has not operated a substantial
portion of its offshore properties, has assumed the operation of certain of its
properties where the Company believes that its technical expertise and ability
to control overhead and operating costs will enhance its economic interest.
Platforms are installed on a block when, in the judgment of the lease
interest owners, the necessary capital expenditures are justified. A decision to
install a platform generally is made after the drilling of one or more
exploratory wells with contracted drilling equipment. Platforms are used to
accommodate both development drilling and additional exploratory drilling. In
recent years, the gross cost of production platforms to the joint ventures in
which the Company has varying net interests has been less than $11,000,000 per
platform. Platform costs vary and more expensive platforms could be required in
the future depending on, among other factors, the number of slots, water depth,
currents, and sea floor conditions. During 1993, the Company commenced
installation of an additional platform on Eugene Island Block 295 and announced
its intention to set a platform on Main Pass Block 123. See '-- Principal
Properties.'
In 1989, the Company entered into a limited partnership agreement as general
partner of Pogo Gulf Coast, Ltd., a Texas limited partnership ('Pogo Gulf
Coast'), in which the Company agreed to be responsible for investing as much as
$60,000,000 on behalf of Pogo Gulf Coast for acquisition and exploration in
state and federal waters in the Gulf of Mexico. As of December 31, 1993, Pogo
Gulf Coast had interests in 24 federal offshore leases, and had invested a total
of $41,750,000 of the aforementioned $60,000,000. The Company owns 40% of any
interest in properties acquired by the limited partnership. Unless otherwise
noted, the statistical data reported in this Prospectus reflect only the
Company's share of Pogo Gulf Coast's holdings.
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DOMESTIC ONSHORE OPERATIONS
The Company has onshore division staffs in Houston and Midland, Texas. Its
onshore activities are concentrated in known oil and gas provinces, principally
the Permian Basin of southeastern New Mexico and West Texas and the onshore Gulf
Coast area. As of December 31, 1993, the Company and its partners had drilled
and completed as productive 151 consecutive wells in Lea and Eddy Counties in
southeastern New Mexico, including 58 wells in 1993 alone. The Company's primary
drilling objective in southeastern New Mexico is the Brushy Canyon (Delaware)
formation which produces oil at depths of 6,000 to 9,000 feet. The Company's net
revenue interest portion of daily liquid hydrocarbon production in New Mexico
averaged approximately 3,700 Bbls during 1993, which represented approximately
32% of the Company's total average daily production of oil, condensate and
liquid plant products during 1993.
The Company generally conducts its onshore activities through joint ventures
and other interest-sharing arrangements with major and independent oil
companies. The Company operates many of its onshore properties using independent
contractors.
The Company's domestic onshore capital and exploration expenditures were
approximately $29,400,000 for 1993, or 44% higher than the Company's domestic
onshore capital and exploration expenditures of approximately $20,400,000 for
1992 and 56% higher than the Company's domestic onshore capital and exploration
expenditures of approximately $18,800,000 for 1991. Development and production
related projects represented 82% of the Company's 1993 domestic onshore capital
and exploration expenditures. As of December 31, 1993, the Company held leases
on 56,155 net acres onshore in the United States. Onshore reserves as of
December 31, 1993, accounted for approximately 19% of the Company's domestic
proved reserves and approximately 16% of its total proved reserves. During 1993,
approximately 25% of the Company's natural gas equivalent production was from
its domestic onshore properties, contributing approximately 25% of consolidated
oil and gas revenues.
INTERNATIONAL OPERATIONS
The Company has conducted international exploration activities since the
late 1970's in numerous oil and gas areas in various parts of the world. The
Company pursues a strategy of evaluating potentially high return prospects in
areas of the world with a stable political and financial climate such as certain
European and ASEAN countries. In 1988, the Company sold its United Kingdom
reserves which were located in the North Sea. Since that time, the Company has
analyzed several opportunities and has obtained a concession in the Kingdom of
Thailand and a concession in Australia. The Company's international capital and
exploration expenditures were approximately $6,000,000 for 1993, or 131% higher
than the Company's international capital and exploration expenditures of
approximately $2,600,000 for 1992. Substantially all of the Company's
international capital and exploration expenditures for 1993 were related to the
Company's license in the Kingdom of Thailand. However, the Company continues to
evaluate other international opportunities that are consistent with the
Company's international exploration strategy.
In 1990, the Company invited Rutherford/Moran Oil Company
('Rutherford/Moran'), Maersk Olie og Gas A/S ('Maersk') and Sophonpanich Co.,
Ltd. ('Sophonpanich') to join it in bidding for a concession license on Block
B8/32, a 2.6 million acre tract in the Gulf of Thailand. In August 1991, the
Company, Rutherford/Moran, Maersk and Sophonpanich were awarded a license from
the Kingdom of Thailand to explore for and produce oil and gas on the tract. The
Company's working interest in the concession is 31.67%. Maersk is the operator
with a similar 31.67% interest.
Exploration activities in Thailand are consistent with the Company's
objectives of expanding its international operations in areas that have
geological features which the Company believes may be favorable for hydrocarbon
accumulation, low entry costs, an acceptable political risk profile and
operational or other similarities with the Company's existing activities.
Thailand is expected to be a net importer of hydrocarbons at least through the
year 2000, which should provide an attractive
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market for hydrocarbons produced locally. The Company's acreage is located 150
miles south southeast of Bangkok in 250 feet of water and is on trend with
several producing oil and gas fields including, among others, the Erawan, Surat
and Satun fields. The tract is traversed by a major natural gas pipeline. The
Company understands that a contract has been entered into for construction of a
second, parallel pipeline owned by an entity controlled by the government of the
Kingdom of Thailand, with completion scheduled for early 1996. The Company
anticipates that by the time production can commence from this concession, there
should be ample transportation capacity available on these pipelines.
Following an initial evaluation of the Thailand concession area, the Company
and its joint venture partners drilled five exploratory wells on three
separately identified seismic structures. In October 1992, the first well
drilled, the Tantawan No. 1, successfully tested a large, complexly faulted,
anticlinal structure with production tests from five intervals in that well
resulting in calculated cumulative flow rates of 6,260 Bbls of oil and
condensate and 25,750 Mcf of natural gas per day. During 1993, the Company and
its joint venture partners shot, processed and evaluated approximately 9,000
kilometers of new 3-D seismic data over and around the Tantawan No. 1 well. In
late 1993, the Company drilled the Tantawan No. 2 and the Tantawan No. 3
exploratory wells on the Tantawan structure. The Tantawan No. 2 well
successfully delineated a previously untested fault block to the east of the
Tantawan No. 1 well with production tests from six intervals resulting in
calculated cumulative flow rates of 70,300 Mcf of natural gas and 1,720 Bbls of
condensate per day. The Tantawan No. 3 well successfully delineated a third
untested fault block on the Tantawan structure located approximately two miles
north of the Tantawan No. 1 and No. 2 wells. Production tests from this third
Tantawan well were reported in January 1994, with production tests from five
intervals resulting in calculated cumulative flow rates of 40,660 Mcf of natural
gas and 8,684 Bbls of oil and condensate per day.
As a result of its successful exploration drilling program, the Company's
Thailand concession now accounts for approximately 14% of the Company's total
estimated net proved reserves of natural gas, approximately 19% of the Company's
total estimated net proved reserves of oil, condensate and natural gas liquids
and approximately 16% of the Company's total net proved oil and gas equivalent
reserves. Additional delineation wells on the Tantawan structure are planned
during 1994. Based upon the results of such drilling, the Company and its
partners will agree upon the type of development plan needed to commence
production in this area. In addition, in late 1993, the Company and its joint
venture partners began shooting and processing additional new 3-D seismic data
in a different portion of Block B8/32. Following evaluation of this seismic
data, additional exploratory wells are expected to be drilled by the Company and
its joint venture partners on as yet untested seismic structures identified on
Block B8/32.
Production from the concession will be subject to a royalty ranging from 5%
to 15% of oil and gas sales, plus certain fixed dollar amounts payable at
specified cumulative production levels. Revenue from production in Thailand will
also be subject to income taxes and other governmental charges. As set forth in
the August 1991 concession, the exploratory term of the concession is for a
period of up to six years; provided, however, that after the expiration of four
years, a portion of the acreage in Block B8/32 must be relinquished by the
Company and its joint venture partners and removed from the concession license.
The Company must identify and release this acreage no later than August 1, 1995.
During the remainder of the concession's exploratory period, the Company and its
joint venture partners have certain work commitments involving the drilling of
four more exploratory wells or the expenditure of certain sums of money on
exploration activities. The Company anticipates, based on the joint venture's
current exploration budget and capital spending plans, that it and its joint
venture partners will satisfy the remainder of the concession's work commitments
by the middle of 1995. Following the commencement of production, the initial
production period of the concession is 20 years, subject to extension.
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The Company also holds interests in three Authority to Prospect ('ATP')
licenses in Australia. One ATP, in which the Company holds a 7.5% interest,
covers 480,000 acres and expires in February 1995 unless certain expenditures
are made. The Company has farmed out the other two ATP's to a third party and
retained a small carried interest. None of the ATP's requires material
expenditures by the Company.
PRINCIPAL PROPERTIES
As of January 1, 1994, approximately 81% of the Company's domestic proved
oil and gas equivalent reserves and approximately 68% of the Company's total
proved oil and gas equivalent reserves were located on properties in the Gulf of
Mexico. Five significant producing areas, of which four are located in the Gulf
of Mexico and the fifth is located in New Mexico, accounted for approximately
59% of the estimated proved natural gas reserves and approximately 74% of the
estimated oil, condensate and natural gas liquids reserves of the Company as of
January 1, 1994. These producing areas accounted for approximately 60% of
natural gas production and 90% of oil, condensate and natural gas liquids
production for 1993. Reserves and production data for the five principal
producing areas, as estimated by Ryder Scott, are shown in the following table.
No other major producing area accounted for more than 5% of the estimated
discounted future net revenues attributable to the Company's estimated proved
reserves as of January 1, 1994. However, the Company's Thailand concession,
which is currently not a producing property, accounts for approximately 14% of
the Company's total estimated net proved reserves of natural gas, approximately
19% of the Company's total estimated net proved reserves of oil, condensate and
natural gas liquids and approximately 16% of the Company's total net proved oil
and gas equivalent reserves.
<TABLE>
SIGNIFICANT PRODUCING AREAS
<CAPTION>
NET PROVED RESERVES 1993 AVERAGE NET
AS OF JANUARY 1, 1994 DAILY PRODUCTION
NATURAL GAS LIQUIDS(A) NATURAL GAS LIQUIDS(A)
(MMCF) % (MBBLS) % (MCF) % (BBLS) %
<S> <C> <C> <C> <C> <C> <C> <C> <C>
OFFSHORE
Eugene Island---------------------- 92,742 39.8% 10,448 37.0% 24,000 27.1% 4,600 39.8%
South Marsh Island----------------- 6,811 2.9 2,579 9.1 2,101 2.4 1,378 11.9
Main Pass-------------------------- 9,186 3.9 2,722 9.6 3,721 4.2 598 5.2
East Cameron----------------------- 12,423 5.3 75 0.3 13,852 15.6 76 0.7
ONSHORE
New Mexico
Lea/Eddy Counties---------------- 16,219 7.0 4,994 17.7 9,660 10.9 3,714 32.1
<CAPTION>
DISCOUNTED
FUTURE
NET
REVENUES(B)
%
<S> <C>
OFFSHORE
Eugene Island---------------------- 53.3%
South Marsh Island----------------- 5.1
Main Pass-------------------------- 4.5
East Cameron----------------------- 4.2
ONSHORE
New Mexico
Lea/Eddy Counties---------------- 9.9
(a) 'Liquids' includes oil, condensate and natural gas liquids.
(b) Before income taxes, discounted at 10%.
</TABLE>
Set forth below are descriptions of certain of the Company's significant
producing areas. Contained in certain of these descriptions and elsewhere in
this Prospectus are production rate test results with regard to certain wells
and fields in which the Company has an interest. Such production rate tests,
while accurate, are never indicative of actual sustained production rates.
EUGENE ISLAND
The Company's most significant reserves are in the Eugene Island area
located off the Louisiana coast in the Gulf of Mexico. The Eugene Island area
has been an important part of the Company's operations since the first lease in
that area was purchased in 1970 and production began in 1973. The Company
currently holds interests in 13 blocks in the Eugene Island area. These comprise
eight fields containing 90 gross oil and gas wells producing from multiple
reservoirs and horizons.
The Eugene Island Block 330 field is the Company's most significant asset,
with 28 productive Pleistocene horizons between 4,000 and 8,000 feet, containing
multiple reservoirs. The field, located
28
<PAGE>
in 245 feet of water, contains three drilling and production platforms in which
the Company holds a 35% working interest, as well as an additional platform in
which the Company holds a 30% working interest. There are currently 18 wells
producing primarily natural gas and 35 wells producing primarily oil on the
block. In 1993, a successful five well drilling program was completed in the
field which included one horizontal and four vertical wells. A multi-well
program off of the field's 'D' platform commenced in early January 1994. Since
initial production in 1973, the Eugene Island Block 330 field has produced
approximately 619 Bcf of natural gas and 122 MMBbls of oil and condensate (167
Bcf and 35 MMBbls, attributable to the Company's net revenue interest). Reserves
have been added to this field consistently since production commenced. These
increases have been derived from new exploratory horizons, infill drilling,
field expansions and higher than anticipated recovery efficiencies.
Another significant field to the Company is Eugene Island Block 295. In
production since 1973, this block has recorded gross production of over 387 Bcf
of natural gas and over 2.9 MMBbls of oil and condensate during its twenty-year
life. In August 1993, the Company effected an exchange of working interests in
Eugene Island Block 295 with another working interest owner in such block.
Pursuant to this exchange, the Company increased its working interest in Eugene
Island Block 295 to 100% on 3,125 acres above 3,000 feet, to 20% on 1,875 acres
above 3,000 feet and to 20% on all of the block below 3,000 feet. During the
fourth quarter of 1993, the Company successfully drilled and completed five
horizontal wells to exploit the natural gas potential located in certain shallow
reservoirs on this block in an area where it has a 100% working interest. These
five wells tested at a gross calculated cumulative daily flow rate of 100 MMcf
of natural gas per day, although platform compression capacity and lease burdens
dictate that ultimate net production volumes will be substantially less than
this amount. The Company completed construction of a production platform
over these wells and commenced initial production from the first of these wells
in late February 1994.
The Eugene Island 212 field consists of Eugene Island Blocks 211 and 212 and
Ship Shoal Block 175. The field contains eight productive horizons which have
four oil wells and one natural gas well producing from a platform set in 1985.
The Company and its partners drilled a successful infill development well in
this field during the second half of 1993.
SOUTH MARSH ISLAND
The Company currently owns five blocks in the South Marsh Island area,
located offshore Louisiana. Three of the leases were acquired in 1974, a fourth
in 1980 and the most recent in 1992. Three blocks contain a total of five
drilling and production platforms. These platforms currently have 44 oil and gas
wells producing from Pleistocene age sandstone reservoirs located at depths from
5,000 to 10,000 feet.
The South Marsh Island 128 field, in which the Company owns a 16% working
interest, comprises South Marsh Island Blocks 125, 127 and 128. This field
primarily produces oil, with 36 oil wells and six natural gas wells producing
from 20 separate reservoirs. The first four wells in a supplemental five-well
drilling program in this field were completed in 1993. The current drilling
program is based on the ongoing analysis of a 3-D seismic survey in conjunction
with a detailed reservoir study of the field.
The Company also owns a 25% working interest in the South Marsh Island Block
160 field which is producing from two oil wells at a depth of approximately
9,700 feet. A single platform was set on this block in 1983. A two-well drilling
program is currently being considered in this field as a result of recent
analysis of a 3-D seismic survey on the block.
MAIN PASS
The Company's nine blocks in the Main Pass area are located near the mouth
of the Mississippi River in the Gulf of Mexico and include leases purchased from
1974 to 1992. The primary drilling
29
<PAGE>
objectives in these fields are Pliocene and Miocene sandstone reservoirs with
productive formation depths from 5,000 to 12,000 feet. The Company's interests
in the Main Pass area include 57 producing oil and gas wells producing from six
platforms.
A field including Main Pass Blocks 72, 73 and 72/74 was unitized in 1982
with the Company's working interest at 14%. This field contains 33 oil wells and
11 natural gas wells operated by one of the Company's joint venture partners.
The field is located in 125 feet of water with 38 mapped horizons adjacent to
and surrounding a salt dome. These horizons contain over 150 separate reservoirs
between 5,000 and 12,000 feet. A successful three-well workover program in this
field was completed in 1992. Many of the producing reservoirs in this field have
consistently outperformed their initial recovery estimates. Based on the high
historical recovery efficiency, it is anticipated that some of the multiple
behind pipe reservoirs remaining will also outperform their existing reserve
estimates.
Main Pass Block 123 was acquired in the federal lease sale of 1990. Pogo
Gulf Coast, for which the Company is the general partner, has a 75% working
interest and is the operator on the block. Along with its non-operating joint
venture partner, Pogo Gulf Coast drilled two discovery wells on the block in
1993 and is currently planning additional drilling as well as the installation
of a production platform in late 1994.
EAST CAMERON
The original lease purchased by the Company and its partners in the East
Cameron area off the Texas/Louisiana border in the Gulf of Mexico commenced
production in February 1973. Presently, the Company has interests in 4 offshore
blocks in this area which contain three fields and 16 producing gas wells.
During 1992, the Company and its partners conducted a 3-D seismic survey of
the East Cameron Block 334/335 field area where the Company has a 42% working
interest. The Company currently anticipates commencing a multi-well drilling
program in this field during the first half of 1994.
NEW MEXICO
The Company considers southeastern New Mexico to be an area of significant
growth in both production and reserves as a result of recent exploration and
development activities. The Company believes that during the past four years it
has been one of the most active companies drilling for oil and natural gas in
the southeastern New Mexico (Lea and Eddy Counties) portion of the Permian Basin
where the Company has interests in over 50,000 gross acres. The Company's
primary drilling objective is the Brushy Canyon (Delaware) formation. Fields in
the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of
the Permian Basin are generally characterized by production from relatively
shallow depths (6,000 to 9,000 feet), multiple producing zones in most wells and
relatively high initial rates of production (frequently equaling the top field
allowables which range from of 142 Bbls to 230 Bbls per day, depending on the
depth of production from the field). The Company has achieved rapid cost
recovery with respect to its New Mexico wells drilled to date because of
relatively low capital costs and high initial rates of production.
Through December 31, 1993, the Company and its partners had drilled and
completed as productive 151 consecutive wells in Lea and Eddy Counties
including, among others, 52 wells in the Sand Dunes field where the Company's
working interest ranges from 4% to 89%; 27 wells in the East Loving field where
the Company's working interest ranges from 1.5% to 100%; 43 wells in the
Livingston Ridge field where the Company's working interest ranges from 25% to
100%; and 8 wells in the Red Tank field where the Company's working interest
ranges from 86% to 100%. The oil fields in this area are generally developed on
40 acre spacings. The Company anticipates drilling many additional locations in
these and other fields in southeastern New Mexico during 1994 and in future
years.
30
<PAGE>
RESERVES
The following table sets forth information as to the Company's net proved
and proved developed reserves as of December 31, 1993, 1992, and 1991, and the
present value as of such dates (based on an annual discount rate of 10%) of the
estimated future net revenues from the production and sale of those reserves, as
estimated by Ryder Scott in accordance with criteria prescribed by the
Commission. The summary report of Ryder Scott on the reserve estimates, which
includes definitions and assumptions, is set forth as an exhibit to the Annual
Report.
AS OF DECEMBER 31,
1993 1992 1991
Total Proved Reserves:
Oil, condensate, and natural gas
liquids (MBbls)
Located in the United States----- 22,843 19,979 18,818
Located in the Kingdom of
Thailand----------------------- 5,425 2,577 --
Total Company-------------------- 28,268 22,556 18,818
Natural Gas (MMcf)
Located in the United States----- 199,392 196,400 202,735
Located in the Kingdom of
Thailand----------------------- 33,474 10,668 --
Total Company-------------------- 232,866 207,068 202,735
Present value of estimated future
net revenues, before income taxes
(in thousands)
Located in the United States----- $386,674 $390,893 $349,754
Located in the Kingdom of
Thailand----------------------- 17,166 14,208 --
Total Company-------------------- $403,840 $405,101 $349,754
Proved Developed Reserves (all
located in the United States):
Oil, condensate, and natural gas
liquids (MBbls)---------------- 20,976 18,798 17,550
Natural Gas (MMcf)--------------- 183,139 175,523 188,090
Present value of estimated future
net revenues, before income
taxes (in thousands)----------- $375,287 $378,300 $337,524
Natural gas liquids comprise approximately 14% of the Company's total proved
liquids reserves and approximately 18% of the Company's proved developed liquids
reserves. All hydrocarbon liquid reserves are expressed in standard 42 gallon
Bbls. All gas volumes and gas sales are expressed in MMcf at the pressure and
temperature bases of the area where the gas reserves are located.
Because of the direct relationship between quantities of proved undeveloped
reserves and development plans, only reserves assigned to undeveloped locations
that will definitely be drilled and reserves assigned to the undeveloped
portions of secondary or tertiary projects that will definitely be developed
have been included as proved undeveloped reserves.
The Company has interests in certain tracts that may have substantial
additional hydrocarbon quantities which cannot be classified as proved. The
Company has active exploratory and development drilling programs which may
result in the reclassification of significant additional quantities as proved
reserves.
The Company does not believe that any other major discovery or other
favorable or adverse event causing a significant change in the estimated
quantities of proved reserves has occurred since January 1, 1994.
31
<PAGE>
ACREAGE
The following table shows the Company's interest in developed and
undeveloped oil and gas acreage as of December 31, 1993:
DEVELOPED UNDEVELOPED ACREAGE
ACREAGE (A) (B)
GROSS NET GROSS NET
ONSHORE
Arkansas------------------------- -- -- 118 20
Colorado------------------------- -- -- 7,963 7,963
Louisiana------------------------ 869 258 -- --
New Mexico----------------------- 14,013 6,950 36,317 29,161
Oklahoma------------------------- 3,840 374 -- --
Texas---------------------------- 11,677 4,541 17,849 6,853
Wyoming-------------------------- -- -- 120 35
Total Onshore---------------- 30,399 12,123 62,367 44,032
OFFSHORE
Louisiana (State)---------------- 7,804 2,964 -- --
Louisiana (Federal)(c)----------- 169,193 51,734 89,989 19,765
Texas (Federal)------------------ 46,080 7,971 17,280 3,340
Total Offshore--------------- 223,077 62,669 107,269 23,105
TOTAL DOMESTIC------------------- 253,476 74,792 169,636 67,137
INTERNATIONAL
Thailand (Offshore)-------------- -- -- 2,635,116 878,372
Australia (Onshore)-------------- -- -- 1,964,800 42,960
TOTAL INTERNATIONAL-------------- -- -- 4,599,916 921,332
TOTAL COMPANY------------------------ 253,476 74,792 4,769,552 988,469
(a) 'Developed acreage' consists of lease acres spaced or assignable to
production on which wells have been drilled or completed to a point that
would permit production of commercial quantities of oil and natural gas.
(b) Approximately 38% of the Company's total offshore net undeveloped acreage
is under leases that have terms expiring in 1994, if not held by
production, and another approximately 21% of offshore net undeveloped
acreage will expire in 1995 if not also held by production. Approximately
16% of onshore net undeveloped acreage is under leases that have terms
expiring in 1994, if not held by production, and another approximately
39% of onshore net undeveloped acreage will expire in 1995 if not also
held by production.
(c) The Company also owns overriding royalty interests in one federal lease
offshore Louisiana totaling 5,000 gross and 1,250 net acres.
32
<PAGE>
PRODUCTIVE WELLS AND DRILLING ACTIVITY
The following table shows the Company's interest in productive oil and
natural gas wells as of December 31, 1993. Productive wells are producing wells
plus wells 'capable of production' (e.g., natural gas wells waiting for pipeline
connections or necessary governmental certification to commence deliveries and
oil wells waiting to be connected to production facilities).
NATURAL GAS
OIL WELLS(A) WELLS(A)
GROSS NET GROSS NET
Offshore United States--------------- 199 36.6 170 46.8
Onshore United States---------------- 163 92.2 65 24.6
Total-------------------- 362 128.8 235 71.4
(a) One or more completions in the same bore hole are counted as one well. The
data in the above table includes 30 gross (5.8 net) oil wells and 16 gross
(5.8 net) gas wells with multiple completions.
The following table shows the number of successful gross and net exploratory
and development wells in which the Company has participated and the number of
gross and net wells abandoned as dry holes during the periods indicated. An
onshore well is considered successful upon the installation of permanent
equipment for the production of hydrocarbons. Successful offshore wells consist
of exploratory or development wells that have been completed or are 'suspended'
pending completion (which has been determined to be feasible and economic) and
exploratory test wells that were not intended to be completed and that
encountered commercially producible hydrocarbons. A well is considered a dry
hole upon reporting of permanent abandonment to the appropriate agency.
<TABLE>
<CAPTION>
1993 1992 1991
SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY
<S> <C> <C> <C> <C> <C> <C>
GROSS WELLS
Offshore United States
Exploratory---------------------- 5.0 1.0 -- 2.0 2.0 3.0
Development---------------------- 15.0 0 5.0 -- 13.0 --
Onshore United States
Exploratory---------------------- 3.0 4.0 4.0 2.0 2.0 4.0
Development---------------------- 61.0 1.0 34.0 -- 32.0 --
Offshore Kingdom of Thailand
Exploratory---------------------- 2.0 2.0 1.0 -- -- --
Total-------------------- 86.0 8.0 44.0 4.0 49.0 7.0
NET WELLS
Offshore United States
Exploratory---------------------- 1.7 0.1 -- 0.7 0.2 0.4
Development---------------------- 7.7 -- 1.5 -- 4.0 --
Onshore United States
Exploratory---------------------- 2.0 3.2 2.8 0.9 1.0 2.3
Development---------------------- 33.1 0.4 23.2 -- 18.2 --
Offshore Kingdom of Thailand
Exploratory---------------------- 0.6 0.6 0.3 -- -- --
Total-------------------- 45.1 4.3 27.8 1.6 23.4 2.7
</TABLE>
As of December 31, 1993, the Company was participating in the drilling of 4
gross (0.9 net) offshore domestic wells and 4 gross (2.7 net) onshore wells.
33
<PAGE>
PRODUCTION AND SALES
The following table summarizes the Company's average daily production, net
of all royalties, overriding royalties and other outstanding interests, for the
periods indicated. Natural gas production refers only to marketable production
of natural gas on an 'as sold' basis.
1993 1992 1991
Production Sales:
Natural Gas (Mcf per day)-------- 91,700 105,200 104,200
Crude Oil and Condensate (Bbls
per day)----------------------- 9,851 8,699 7,108
Natural Gas Liquids (Bbls per day):
Leasehold Ownership-------------- 1,538 1,037 609
Plant Ownership------------------ 140 144 54
Total------------------------ 1,678 1,181 663
The following table shows the average sales prices received by the Company
for its production and the average production (lifting) costs per unit of
production during the periods indicated.
1993 1992 1991
Sales Prices:
Natural Gas (per Mcf)------------ $ 1.98 $ 1.75 $ 1.66
Crude Oil and Condensate (per
Bbl)--------------------------- $ 17.81 $ 20.17 $ 20.98
Natural Gas Liquids (per Bbl)---- $ 11.90 $ 13.50 $ 14.21
Production (Lifting) Costs(a)
Natural Gas, Crude Oil,
Condensate and Natural Gas
Liquids (per equivalent Mcf of
Natural Gas)------------------- $ 0.45 $ 0.43 $ 0.51
(a) Production costs were converted to common units of measure on the basis of
relative energy content. Such production costs exclude all depletion and
amortization associated with property and equipment.
The Company has entered into a crude oil swap agreement with another party
in which it swapped the floating market price it received from purchasers of its
crude oil for a fixed price of $16.00 per barrel on 1,000 Bbls per day of its
production. The agreement expires July 31, 1994, but may be extended through
January 31, 1995, at the other party's option.
EMPLOYEES
As of December 31, 1993, the Company had 102 employees. None of the
Company's employees are presently represented by a union for collective
bargaining purposes. The Company considers its relations with its employees to
be excellent.
34
<PAGE>
MANAGEMENT
Set forth below is certain information concerning the executive officers and
directors of the Company as of February 15, 1994:
<TABLE>
<CAPTION>
NUMBER OF
YEARS OF
SERVICE WITH
NAME AGE POSITION COMPANY
<S> <C> <C> <C>
Paul G. Van Wagenen------------------ 48 Chairman of the Board, President and Chief 14
Executive Officer and Director
D. Stephen Slack--------------------- 44 Senior Vice President -- Finance, Chief 5
Financial Officer, Treasurer and Director
Tobin Armstrong---------------------- 70 Director 16
Jack S. Blanton---------------------- 66 Director 2
W. M. Brumley, Jr.------------------- 65 Director 23
John B. Carter, Jr.------------------ 69 Director 16
William L. Fisher-------------------- 61 Director 1
William E. Gipson-------------------- 69 Director 23
Gerrit W. Gong----------------------- 40 Director --
John Stuart Hunt--------------------- 72 Director 10
Frederick A. Klingenstein------------ 62 Director 6
Nicholas R. Petry-------------------- 75 Director 12
Jack A. Vickers---------------------- 68 Director 8
Kenneth R. Good---------------------- 56 Senior Vice President -- Land and Budgets 16
Stuart P. Burbach-------------------- 41 Vice President and Offshore Division Manager 6
Jerry A. Cooper---------------------- 45 Vice President and Western Division Manager 14
Harvey L. Gold----------------------- 58 Vice President -- Engineering 16
Thomas E. Hart----------------------- 51 Vice President and Controller 16
R. Phillip Laney--------------------- 53 Vice President and International Division 16
Manager
John O. McCoy, Jr.------------------- 42 Vice President and Chief Administrative 16
Officer
J. D. McGregor----------------------- 49 Vice President -- Sales 12
Sammie M. Shaw----------------------- 62 Vice President -- Operations 12
Ronald B. Manning-------------------- 40 Associate General Counsel and Corporate 6
Secretary
</TABLE>
Paul G. Van Wagenen became Chairman of the Board and Chief Executive Officer
of the Company in March 1991. He had previously been elected to the office of
President of the Company in October 1990. From 1986 to 1990, he served as Senior
Vice President and General Counsel of the Company and was elected a Director of
the Company in 1988. Mr. Van Wagenen joined the Company in 1979.
D. Stephen Slack has been Senior Vice President -- Finance of the Company
since 1988 and a Director of the Company since 1989. Mr. Slack was, from 1982
until 1988, Vice President and regional manager of the Southwest Energy and
Minerals Division of Chemical Bank of New York.
Tobin Armstrong has been engaged for more than five years in ranching. He
became a Director of the Company in 1977.
35
<PAGE>
Jack S. Blanton is President of Eddy Refining Company and Chairman of the
Board of Houston Endowment, Inc. He became a Director of the Company in
September 1991. Mr. Blanton also serves
as a Director for Ashland Oil, Inc., Texas Commerce Bancshares, Inc.,
Southwestern Bell Corporation, Baker Hughes Incorporated and Burlington
Northern, Inc.
W.M. Brumley, Jr., is a retired Senior Vice President -- Administration and
Accounting of the Company and has been a member of the Board of Directors for
more than five years. He became a Director of the Company in 1977.
John B. Carter, Jr., is Chairman of Houston National Bank. He was elected to
his current term as a Director in 1990. From 1987 to 1990, Mr. Carter was an
Advisory Director of the Company. Prior to 1987, Mr. Carter was Senior Vice
President -- Finance of the Company, a Director and a member of the Executive
Committee.
William L. Fisher is Director of the Bureau of Economic Geology and the
Director of the Geology Foundation at the University of Texas at Austin. Dr.
Fisher was formerly the Assistant Secretary -- Energy and Minerals of the U.S.
Department of the Interior. Dr. Fisher has been a Director of the Company since
February 1992. Dr. Fisher is also a Director of Diamond Shamrock, Inc.
William E. Gipson, formerly President and Chief Operating Officer of the
Company, is Chairman of Gas Investment, Inc. He has been a Director of the
Company since 1970.
Gerrit W. Gong is the Director for Asian Studies for the Center for
Strategic and International Studies, in Washington, D.C., and has served in that
capacity for more than the last five years. From 1987 to 1989 he also served as
special assistant to two U.S. Ambassadors to China. He was elected a Director of
the Company in May 1993.
John Stuart Hunt has been engaged for more than five years in managing his
personal investments. He became a Director of the Company in 1983. Mr. Hunt is
also a Director of Nomeco Oil & Gas Co. and SILCO, Inc.
Frederick A. Klingenstein has been Chairman of Klingenstein, Fields & Co.,
L.P., since January 1, 1989. He served as Chairman and Chief Executive Officer
of Wertheim Schroder & Co., Incorporated from 1972 until 1986 and as Co-chairman
and a Director of such firm from 1986 until 1988. Mr. Klingenstein has been a
Director of the Company since 1987.
Nicholas R. Petry is Chairman of the Board of Petry Company and Managing
Partner of N.G. Petry Construction Company and Mill Iron Ranches. He has been
engaged in such businesses for more than five years. He has served as a Director
of the Company since 1981. Mr. Petry is also a Director of First Bank System,
Inc.
Jack A. Vickers, as owner of the Vickers Companies, has been engaged for
more than five years in managing his investments. He became a Director of the
Company in 1985.
DESCRIPTION OF THE NOTES
The following description sets forth certain terms and provisions of the
Notes. The Notes will be issued under an Indenture (the 'Indenture') to be
entered into by the Company and Shawmut Bank Connecticut, National Association,
as trustee (the 'Trustee'), prior to the issuance of any such Notes, the form of
which is filed as an exhibit to the Registration Statement of which this
Prospectus is a part.
The terms of the Notes include those stated in the Indenture and those made
part of the Indenture by reference to the Trust Indenture Act of 1939, as
amended (the 'Trust Indenture Act'). The Notes are subject to all such terms,
and prospective purchasers of the Notes are referred to the Indenture and the
Trust Indenture Act for a statement of those terms. The statements under this
caption relating to the Notes are summaries and do not purport to be complete.
Such summaries use
36
<PAGE>
certain terms that are defined in the Indenture and are qualified in their
entirety by express reference to the Indenture. The article and section
references below are to articles and sections of the Indenture.
GENERAL
The Notes will be unsecured, subordinated obligations of the Company, will
be limited in aggregate principal amount to $75,000,000, or up to $86,250,000 if
the Underwriters exercise their over-allotment option in full, and will mature
on March 15, 2004, unless previously converted or redeemed. (Section 301)
The Company will pay interest on the Notes semi-annually following the
issuance thereof, at the rate per annum set forth on the cover of this
Prospectus, on March 15th and September 15th of each year, commencing September
15, 1994. Interest on the Notes will be paid to the persons who are registered
holders of the Notes (the 'Holders') at the close of business on the March 1st
and September 1st next preceding such interest payment date. Interest will be
computed on the basis of a 360-day year of twelve 30-day months. Principal (and
premium, if any) and interest will be payable, and the Notes may be presented
for conversion, exchange or registration of transfer, at the office or agency of
the Company maintained for such purposes in New York, New York, or at such other
office or agency as may be maintained by the Company for such purpose, except
that payment of interest may, at the option of the Company, be made by check
mailed on or before the due date to the address of the person entitled thereto
as it appears on the security register. The Notes are to be issued only in
registered form without coupons, in denominations of $1,000 or any integral
multiple thereof. (Sections 203, 301, 302, 305, 307, 310 and 1002) The Company
may maintain banking relationships in the ordinary course of business with the
Trustee or its affiliates.
CONVERSION RIGHTS
The Holder of any Note will have the right, at the Holder's option, to
convert the principal amount thereof (or any portion thereof that is an integral
multiple of $1,000) into shares of Common Stock at any time prior to maturity,
initially at the conversion price of $22.188 per share of Common Stock
(subject to adjustments as described below), except that if a Note
is called for redemption, the right to convert such called
Note will terminate at the close of business on the Business
Day (as such term is defined in the Indenture) immediately preceding
the redemption date. No payment of interest and no adjustment in
respect of dividends will be made upon the conversion of any Note, and the
Holder will lose any right to payment of interest on the Notes surrendered for
conversion; provided, however, that upon a call for redemption as described
herein by the Company, accrued and unpaid interest to the redemption date shall
be payable with respect to Notes that are converted after a notice of redemption
has been mailed and prior to the redemption date. Notes surrendered for
conversion during the period from the regular record date for an interest
payment to the corresponding interest payment date (except Notes called for
redemption as described herein) must be accompanied by payment of an amount
equal to the interest thereon which the Holder is to receive on such interest
payment date. No fractional shares will be issued upon conversion but, in lieu
thereof, an appropriate amount will be paid in cash by the Company based on the
reported last sale price for the shares of Common Stock on the day of
conversion. (Sections 1301, 1303 and 1305)
The conversion price will be subject to adjustment in certain events,
including: the issuance of stock as a dividend on the Common Stock; subdivisions
or combinations of the Common Stock; the issuance to all holders of Common Stock
of certain rights or warrants (expiring within 45 days after the record date for
determining stockholders entitled to receive them) to subscribe for or purchase
Common Stock at a price less than the current market price; or the distribution
to substantially all Holders of Common Stock of evidences of indebtedness of the
Company, cash (excluding quarterly cash dividends paid or to be paid on a
regular basis), other assets or rights or warrants to subscribe for or purchase
any securities (other than those referred to herein). No adjustment of the
conversion price will be required to be made until cumulative adjustments amount
to one percent or more of the
37
<PAGE>
then current conversion price; however, any adjustment not made will be carried
forward. (Section 1304)
The Company from time to time may decrease the conversion price by any
amount for any period of at least 20 days, in which case the Company shall give
at least 15 days notice to the Holders of the Notes of such decrease. The
Company may also, at its option, make such decreases in the conversion rate as
the Board of Directors of the Company deems advisable to avoid or diminish any
income tax to holders of Common Stock resulting from any dividend or
distribution of stock (or rights to acquire stock) or from any event treated as
such for income tax purposes. (Section 1304)
Generally, no gain or loss should be recognized for federal income tax
purposes upon the conversion of a Note into Common Stock (except to the extent
of cash received in lieu of fractional shares or with respect to accrued
interest). The Holder of a Note converted into Common Stock should generally
have a carryover basis in such shares and the holding period for the Common
Stock should include the holding period of the Note.
If the conversion price of the Notes is reduced (other than a reduction
pursuant to the antidilution provisions of the Indenture, provided such
provisions are deemed bona fide and reasonable under the circumstances), Holders
of Notes would be treated as receiving a deemed distribution for federal income
tax purposes that could, depending upon the then existing facts and
circumstances relating to the Common Stock and Notes, be subject to income
taxation. For example, a taxable deemed distribution is likely to occur if the
conversion price of the Notes is reduced in connection with the payment of cash
dividends to holders of Common Stock. Holders of Notes could therefore have
taxable income as a result of an event pursuant to which they received no cash
or property that could be used to pay the related income tax.
In case of any reclassification of the Common Stock, any consolidation of
the Company with, or merger of the Company into, any other person, any merger of
any person into the Company (other than a merger which does not result in any
reclassification, conversion, exchange or cancellation of outstanding shares of
Common Stock), any sale or other disposition of the assets of the Company
substantially as an entirety or any compulsory share exchange whereby the Common
Stock is converted into other securities, cash or other property, then provision
shall be made such that the Holder of Notes then outstanding shall have the
right thereafter, during the period such Notes shall be convertible, to convert
such Notes only into the kind and amount of securities, cash and other property
receivable upon such reclassification, consolidation, merger, sale, disposition
or share exchange by a holder of the number of shares of Common Stock into which
such Notes might have been converted immediately prior to such reclassification,
consolidation, merger, sale, disposition or share exchange. (Section 1306)
SUBORDINATION
Payment of the principal of and premium, if any, and interest on the Notes
will be subordinated in right of payment, as set forth in the Indenture, to the
prior payment in full of all Senior Indebtedness of the Company when due in
accordance with the terms thereof. Senior Indebtedness is defined in the
Indenture as the principal of, premium, if any, and unpaid interest (including,
without limitation, any interest accruing subsequent to the commencement of a
case or other proceeding under any bankruptcy or other similar law with respect
to the Company) on, and other obligations in respect of the following, whether
outstanding at the date of the Indenture or thereafter incurred or created: (a)
indebtedness of the Company for money borrowed (including purchase money
obligations) evidenced by notes or other written obligations, (b) indebtedness
of the Company evidenced by notes, debentures, bonds or other securities issued
under the provisions of an indenture or similar instrument, (c) indebtedness
secured by any mortgage, pledge, lien or other encumbrance existing on property
which is owned or held by the Company subject to such mortgage, pledge or
encumbrance, whether or not indebtedness secured thereby shall have been assumed
by the Company, (d) obligations of the Company as lessee under capitalized
leases and under leases of property made as part of
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any sale and leaseback transactions, (e) obligations of the Company in respect
of letters of credit issued for its account and 'swaps' of interest rates,
commodity prices or currencies (and other interest rate, commodity price or
foreign currency hedging agreements) to which the Company is a party,
(f) indebtedness of others of any of the kinds described in the preceding
clauses (a) through (e) assumed or guaranteed by the Company and (g) renewals,
extensions and refundings of, and indebtedness and obligations of a successor
person issued in exchange for or in replacement of, indebtedness or obligations
of the kinds described in the preceding clauses (a) through (f); provided,
however, that the following will not constitute Senior Indebtedness: (i) any
indebtedness or obligation which by its terms refers explicitly to the Notes and
states that such indebtedness or obligation shall not be senior in right of
payment thereto, (ii) any indebtedness or obligation of the Company in respect
of the Notes and (iii) any indebtedness or obligation of the Company to a
subsidiary. (Sections 101 and 1401) Notwithstanding the foregoing, all
indebtedness and obligations of the Company in respect of the 8% Debentures and
the 10.25% Notes shall rank PARI PASSU with the Notes and shall not constitute
Senior Indebtedness under the Indenture.
Upon the sale of the Notes and the application of the proceeds therefrom,
approximately $19,000,000 aggregate principal amount of Senior Indebtedness is
expected to be outstanding. See 'Use of Proceeds' and 'Capitalization.' There
are no restrictions on the incurrence of indebtedness, including Senior
Indebtedness, or other liabilities by the Company or its subsidiaries in the
Indenture.
By reason of such subordination, in the event of dissolution, insolvency,
bankruptcy or other similar proceeding, Holders of the Notes may recover less,
ratably, than holders of Senior Indebtedness and other general creditors of the
Company, and, upon any distribution of assets, the Holders of Notes will be
required to pay over their share of such distribution to the holders of Senior
Indebtedness until such Senior Indebtedness is paid in full. In addition, such
subordination may affect the Company's obligation to make principal and interest
payments with respect to the Notes if any Notes are declared due and payable
prior to their stated maturity, or in the event of any default in the payment of
principal of or premium, if any, or interest on any Senior Indebtedness, or in
the payment of any commitment or other fees in respect thereof, or in the event
of any default with respect to Senior Indebtedness that would permit
acceleration of the maturity thereof, or in the event a judicial proceeding is
pending with respect to any such Senior Indebtedness default. (Sections 1402,
1403 and 1404)
REDEMPTION AT OPTION OF COMPANY
The Notes are not redeemable prior to March 15, 1998. On and after March 15,
1998, the Notes are redeemable at the option of the Company, in whole or in
part, at any time during the 12-month periods beginning March 15 of the years
indicated at the following Redemption Prices (expressed as percentages of the
principal amount):
REDEMPTION
YEAR PRICE
1998------------------------------------------------------------- 103.30%
1999------------------------------------------------------------- 102.75
2000------------------------------------------------------------- 102.20
2001------------------------------------------------------------- 101.65
2002------------------------------------------------------------- 101.10
2003------------------------------------------------------------- 100.55
together in each case with accrued and unpaid interest to the date fixed for
redemption (subject to the right of Holders of record on the regular record date
to receive interest due on an interest payment date). (Sections 203, 1101 and
1108)
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Notes in any denomination equal to or larger than $1,000 may be redeemed in
whole or in part in multiples of $1,000. On and after the redemption date,
interest will cease to accrue on Notes or portions thereof called for
redemption. (Sections 1104 and 1107)
Accrued and unpaid interest to the redemption date shall be payable with
respect to Notes that are converted after a notice of redemption has been mailed
and prior to the redemption date. (Section 1303)
Notice of redemption will be mailed at least 30 but not more than 60 days
prior to the redemption date to each Holder of Notes to be redeemed at the
address appearing in the security register maintained by the Company. If less
than all the outstanding Notes are to be redeemed, the Trustee will select the
Notes (or a portion thereof equal to $1,000 or any integral multiple thereof) to
be redeemed by such method as the Trustee shall deem fair and appropriate.
(Sections 1104 and 1105)
CERTAIN RIGHTS TO REQUIRE REPURCHASE OF NOTES
In the event of any Change in Control (as hereafter defined) of the Company
which constitutes a Repurchase Event (as hereafter defined) occurring after the
initial date of issuance of the Notes, each Holder of Notes will have the right,
at the Holder's option, to require the Company to repurchase all or any part of
the Holder's Notes on a date (the 'Repurchase Date') selected by the Company
that is not more than 75 days after the date the Company gives notice of the
Repurchase Event as described below at a price (the 'Repurchase Price') equal to
100% of the principal amount thereof, together with accrued and unpaid interest
to the Repurchase Date. On or prior to the Repurchase Date, the Company shall
deposit with the Trustee or a Paying Agent an amount of money sufficient to pay
the Repurchase Price of the Notes which are to be repaid on or promptly
following the Repurchase Date. (Sections 1201 and 1203)
On or before the 15th day after the occurrence of a Repurchase Event, the
Company is obligated to mail to all Holders of Notes a notice of the occurrence
of such Repurchase Event, Repurchase Date, the date by which the repurchase
right must be exercised, the Repurchase Price and the procedures which the
Holder must follow to exercise this right. To exercise the Repurchase Right, the
Holder of Notes must deliver, on or before the close of business on the Business
Day next preceding the Repurchase Date, written notice to the Company (or an
agent designated by the Company for such purpose) and to the Trustee of the
Holder's intent to exercise such rights, together with the Notes with respect to
which the right is being exercised, duly endorsed for transfer. Such written
notice will be irrevocable. (Section 1202)
A 'Change in Control' shall occur when: (i) the Company's assets are sold or
otherwise disposed of substantially as an entirety to any person or related
group of persons in any one transaction or a series of related transactions;
(ii) there shall be consummated any consolidation or merger of the Company (A)
in which the Company is not the continuing or surviving corporation (other than
a consolidation or merger with a wholly owned subsidiary of the Company in which
all shares of Common Stock outstanding immediately prior to the effectiveness
thereof are changed into or exchanged for the same number of shares of common
stock of such subsidiary) or (B) pursuant to which the Common Stock would be
converted into cash, securities or other property, in each case, other than a
consolidation or merger of the Company in which the holders of the Common Stock
immediately prior to the consolidation or merger have, directly or indirectly,
at least a majority of the common stock of the continuing or surviving
corporation immediately after such consolidation or merger; or (iii) any person,
or any persons acting together which would constitute a 'group' for purposes of
Section 13(d) of the Exchange Act (other than the Company, any Subsidiary, any
employee stock purchase plan, stock option plan or other stock incentive plan or
program, retirement plan or automatic dividend reinvestment plan or any
substantially similar plan of the Company or any Subsidiary or any person
holding securities of the Company for or pursuant to the terms of any such
employee benefit plan), together with any affiliates thereof, shall acquire
beneficial ownership
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(as defined in Rule 13d-3 under the Exchange Act) of at least 50% of the total
voting power of all classes of capital stock of the Company entitled to vote
generally in the election of directors of the Company. (Section 1206)
A Change in Control as described above shall constitute a Repurchase Event
unless (i) the Current Market Price of the Common Stock on the date the Change
in Control shall have occurred is at least equal to 105% of the conversion price
of the Notes in effect immediately preceding the time of such Change in Control,
or (ii) all of the consideration (excluding cash payments for fractional shares)
in the transaction giving rise to such Change in Control to the holders of
Common Stock consists of shares of common stock that are, or immediately upon
issuance will be, listed on a national securities exchange or quoted on the
NASDAQ National Market, and as a result of such transaction the Notes become
convertible solely into such common stock, or (iii) the consideration in the
transaction giving rise to such Change in Control to the holders of Common Stock
consists of cash, securities that are, or immediately upon issuance will be,
listed on a national securities exchange or quoted on the NASDAQ National
Market, or a combination of cash and such securities and the aggregate fair
market value of such consideration (which, in the case of such securities, shall
be equal to the average of the daily Closing Prices of such securities during
the ten consecutive trading days commencing with the sixth trading day following
consummation of such transaction) is at least 105% of the conversion price of
the Notes in effect on the date immediately preceding the closing date of such
transaction. (Section 1206)
The right to require the Company to repurchase Notes as a result of the
occurrence of a Repurchase Event could create an event of default under Senior
Indebtedness of the Company, as a result of which any repurchase could, absent a
waiver, be blocked by the subordination provisions of the Notes. See
' -- Subordination.' Failure by the Company to repurchase the Notes when
required would result in an Event of Default (as herein defined) with respect to
the Notes whether or not such repurchase were permitted by the subordination
provisions. See '-- Defaults and Remedies.' The Company's ability to pay cash to
the Holders of Notes upon a repurchase might be limited by certain financial
covenants contained in the Company's Senior Indebtedness. In addition, there can
be no assurance that the Company would have sufficient financial resources at
the time of any such required purchase to enable it to purchase the Notes.
(Sections 501 and 1404)
In the event a Repurchase Event occurs and the Holders exercise their rights
to require the Company to repurchase Notes, the Company intends to comply with
applicable tender offer rules under the Exchange Act, including Rules 13e-4 and
14e-1, as then in effect, with respect to any such purchase.
The foregoing provisions would not necessarily afford Holders of Notes
protection in the event of highly leveraged or other transactions involving the
Company that may adversely affect Holders. In addition, the foregoing provisions
may discourage open market purchases of the Common Stock or a non-negotiated
tender or exchange offer for such stock and accordingly, may limit a
shareholder's ability to realize a premium over the market price of the Common
Stock in connection with any such transaction.
CONSOLIDATION, MERGER AND SALE OF ASSETS
The Company, without the consent of any Holders of Notes, may consolidate or
merge with or into any person, or convey, transfer, lease or otherwise dispose
of its assets substantially as an entirety to any person, and any person may
consolidate or merge with, or into, or transfer or lease its assets
substantially as an entirety to, the Company, provided that (i) the person (if
other than the Company) formed by such consolidation or into which the Company
is merged or which acquires or leases the assets of the Company substantially as
an entirety is organized and existing under the laws of the United States, any
state thereof or the District of Columbia, and assumes the Company's obligations
on the Notes and under the Indenture, (ii) after giving effect to such
transaction, no Event of Default
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and no event that, after notice or lapse of time or both, would become an Event
of Default, shall have happened and be continuing and (iii) certain procedural
conditions are met. (Article Eight)
DEFAULTS AND REMEDIES
The Indenture defines the following as Events of Default: default for 30
days in payment of interest on the Notes; default in payment of principal of or
premium, if any, on the Notes; default for more than 10 days after a Repurchase
Date in payment of the Repurchase Price; failure by the Company for 60 days
after written notice to it to comply with any of its other covenants in the
Indenture; default by the Company under any instrument or other evidence of
indebtedness of the Company for money borrowed, or under any guarantee of
payment by the Company for money borrowed, in an amount in excess of five
percent of Consolidated Net Tangible Assets (as defined below), unless such
default has been cured or waived; and certain events of bankruptcy, insolvency
or reorganization relative to the Company. (Section 501)
'Consolidated Net Tangible Assets' means the total amount of assets of the
Company and its Subsidiaries (less depreciation, depletion, valuation and other
reserves) after deducting (i) all current liabilities, (ii) all goodwill, trade
names, trademarks, patents, unamortized debt discount and expense and other like
intangibles and (iii) minority interests in the equity of Subsidiaries. (Section
101)
If an Event of Default occurs and is continuing, the Trustee or Holders of
at least 25% in aggregate principal amount of the Notes outstanding may declare
the principal of the Notes to be due and payable immediately, but under certain
conditions, such acceleration may be rescinded by the Holders of a majority in
principal amount of the Notes then outstanding. (Sections 502 and 513).
Holders of Notes may not enforce the Indenture except as provided in such
Indenture and except that, subject to any applicable subordination provisions,
nothing shall prevent the Holders of Notes from enforcing payment of the
principal of or premium, if any, or interest on, their Notes. The Trustee may
refuse to enforce the Indenture unless it receives reasonable security or
indemnity. Subject to certain limitations, Holders of a majority in aggregate
principal amount of the Notes may direct the Trustee in its exercise of any
trust or power under the Indenture. (Sections 507, 508, 512 and 603)
The Company will annually furnish the Trustee with an officers' certificate
with respect to compliance with the terms of the Indenture. (Section 1005)
MODIFICATION
Modification and amendment of the Indenture may be effected by the Company
and the Trustee with the consent of the Holders of a majority in aggregate
principal amount of the Notes then outstanding under the Indenture, provided
that no such modification or amendment may, without the consent of each Holder
affected thereby, (i) reduce the rate or change the time or place for payment of
principal, premium if any, or interest on any Note, (ii) reduce the principal of
or rate of interest thereon, or the premium, if any, payable upon the redemption
of, or change the fixed maturity of, any Note, (iii) make any Note payable in a
currency other than U.S. dollars, (iv) impair the right to institute suit for
the enforcement of any payment on or with respect to any such Note, (v) make any
change that adversely affects the right convert any Note or (vi) reduce the
amount of Notes whose Holders must consent to a modification or amendment or
waive compliance with certain provisions of the Indenture. The Indenture also
contains provisions permitting the Company and the Trustee to effect certain
minor modifications to the Indenture not adversely affecting the rights of
Holders of Notes in any material respect. (Sections 901 and 902)
GOVERNING LAW
The Notes and the Indenture provide that they are governed by the laws of
the State of New York, without regard to the principles of conflicts of laws.
(Section 112)
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CONCERNING THE TRUSTEE
The Indenture contains certain limitations on the rights of the Trustee,
should it become a creditor of the Company, to obtain payment of claims in
certain cases, or to realize on certain property received in respect of any such
claim as security or otherwise. The Trustee will be permitted
to engage in other transactions with the Company; provided, however, if it
acquires any conflicting interest and there exists a default with respect to the
Notes, it must eliminate such conflict or resign. (Sections 608 and 613)
The Holders of a majority in aggregate principal amount of all outstanding
Notes will have the right to direct the time, method and place of conducting any
proceeding for exercising any remedy or power available to the Trustee under the
Indenture, provided that such direction does not conflict with any rule of law
or with the Indenture and would not involve the Trustee in personal liability or
be unduly prejudicial to Holders of Notes not joining in such action (as
determined by the Trustee in good faith). (Section 512)
In case a default or an Event of Default under the Indenture shall occur and
be continuing and if it is known to the Trustee, the Trustee shall mail to each
Holder of Notes notice of the default or Event of Default within 90 days after
it occurs. Except in the case of a default or an Event of Default in payment of
the principal of, premium, if any, or interest on any Note, the Trustee may
withhold the notice if and so long as the Trustee in good faith determines that
withholding the notice is in the interest of Holders of Notes. Subject to such
provisions, when the Trustee incurs expenses or renders services after an Event
of Default, the expenses and the compensation for the services are intended to
constitute expenses of administration under any bankruptcy law. (Sections 602
and 607)
DESCRIPTION OF CAPITAL STOCK
AUTHORIZED AND OUTSTANDING CAPITAL STOCK
The authorized capital stock of the Company consists of 43,333,333 shares of
Common Stock, of which 32,433,622 shares were issued and outstanding as of
December 31, 1993; and 2,000,000 shares of preferred stock, par value $1 per
share (the 'Preferred Stock'), of which no shares are issued and outstanding.
The following summary description of the capital stock of the Company is
qualified in its entirety by reference to the Company's Restated Certificate of
Incorporation and Bylaws, copies of which are incorporated by reference as
exhibits to the Registration Statement of which this Prospectus is a part.
COMMON STOCK
Subject to any preferential rights of any outstanding shares of Preferred
Stock, the holders of the Common Stock are entitled to such dividends as may be
declared from time to time in the discretion of the Board of Directors out of
funds legally available therefor. See 'Price Range of Common Stock and
Dividends.' Holders of Common Stock are entitled to share ratably in the net
assets of the Company upon liquidation after payment or provision for all
liabilities and any preferential liquidation rights of any Preferred Stock then
outstanding. The rights of holders of Common Stock are subject to the rights of
holders of any Preferred Stock which may be issued in the future. The holders of
Common Stock have no preemptive rights to purchase additional shares of capital
stock of the Company. Shares of Common Stock are not subject to any redemption
or sinking fund provisions and are not convertible into any other securities of
the Company.
Each share of Common Stock entitles the holder thereof to one vote at all
meetings of the stockholders of the Company. The affirmative vote of the holders
of at least 80% of the outstanding shares of Common Stock is required (i) to
approve a merger, similar reorganization or certain other transactions involving
the Company if the other party already owns or controls five percent of the
outstanding Common Stock and the Board of Directors of the Company has not
approved the transaction; (ii) to approve an amendment to the Company's Restated
Certificate of Incorporation to alter or change the provision establishing a
'classified' Board of Directors of not less than three nor more than thirteen
members, elected one-third annually; and (iii) to amend the foregoing and
certain other provisions of the Restated Certificate of Incorporation.
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The Company's capital stock has noncumulative voting rights, meaning that
the holders of more than 50% of the voting power of the shares voting for the
election of directors can elect 100% of the directors if they choose to do so.
In such event, the holders of the remaining less-than-50% of the voting power of
the shares voting for the election of directors will not be able to elect any
directors.
PREFERRED STOCK
The Board of Directors of the Company is empowered, without approval of the
stockholders, to cause shares of Preferred Stock to be issued in one or more
series, with the number of shares of each series and the rights, preferences and
limitations of each series to be determined by it. Among the specific matters
that may be determined by the Board of Directors are the description and number
of shares to constitute each series, the annual dividend rate, whether such
dividends shall be cumulative, the time and price of redemption and the
liquidation preference applicable to the series, whether the series will be
subject to the operation of a 'sinking' or 'purchase' fund and, if so, the terms
and provisions thereof, whether the shares of such series shall be convertible
into shares of any other class or classes and the terms and provisions of such
conversion rights, and the voting powers, if any, of the shares of such series.
The Board of Directors may change the designation, rights, preferences,
descriptions and terms of, and the number of shares in, any series of which no
shares have theretofore been issued.
The issuance of one or more series of Preferred Stock could adversely affect
the voting power of the holders of the Common Stock and could have the effect of
discouraging or making more difficult any attempt by a person or group to obtain
control of the Company.
TRANSFER AGENTS AND REGISTRARS
The Transfer Agents and Registrars for the Common Stock are Harris Trust
Company of New York, New York, and Society National Bank, Houston, Texas.
DELAWARE LAW
The Company is subject to Section 203 of the Delaware General Corporation
Law. In general, Section 203 prevents an interested stockholder (defined
generally as any person owning 15% or more of the Company's outstanding voting
stock) from engaging in a business combination (as defined herein) with a
Delaware corporation for a period of three years from the date such person
becomes an interested stockholder, unless (i) before such person became an
interested stockholder, the board of directors of the corporation approved the
transaction in which the interested stockholder became an interested stockholder
or approved the business combination; (ii) upon consummation of the transaction
that resulted in the interested stockholder's becoming an interested
stockholder, the interested stockholder owned at least 85% of the voting stock
of the corporation outstanding at the time the transaction commenced (excluding
stock held by directors who are also officers of the corporation and by employee
stock plans that do not provide employees with the rights to determine
confidentially whether the shares held subject to the plan will be tendered in a
tender or exchange offer); or (iii) following the transaction in which such
person became an interested stockholder, the business combination is approved by
the board of directors of the corporation and authorized at a meeting of
stockholders by the affirmative vote of the holders of at least two-thirds of
the outstanding voting stock of the corporation not owned by the interested
stockholder. Under Section 203, the restrictions described above also do not
apply to certain business combinations proposed by an interested stockholder
following the announcement or notification of one of certain extraordinary
transactions involving the corporation and a person who had not been an
interested stockholder during the previous three years or who became an
interested stockholder with the approval of a majority of the corporation's
directors, if such extraordinary transaction is approved or not opposed by a
majority of the directors who were directors prior to any person becoming an
interested stockholder during the previous three years or who were recommended
for election or elected to succeed such directors by a majority of such
directors. By restricting the ability of the Company to engage in business
combinations with an interested person, the application of Section 203 to the
Company may provide a barrier to hostile or unwanted takeovers.
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UNDERWRITING
Subject to the terms and conditions set forth in a purchase agreement (the
'Purchase Agreement') among the Company and Merrill Lynch, Pierce, Fenner &
Smith Incorporated, Goldman, Sachs & Co. and PaineWebber Incorporated (the
'Underwriters'), the Company has agreed to sell to the Underwriters, and the
Underwriters have severally agreed to purchase, the principal amount of Notes
set forth opposite their respective names below (excluding the Notes subject to
the Underwriters' overallotment option):
PRINCIPAL
UNDERWRITER AMOUNT
Merrill Lynch, Pierce, Fenner & Smith
Incorporated-------------- $25,000,000
Goldman, Sachs & Co.----------------- 25,000,000
PaineWebber Incorporated------------- 25,000,000
Total--------------------- $75,000,000
The Purchase Agreement provides that, subject to the terms and conditions
set forth therein, the Underwriters will be obligated to purchase the entire
principal amount of the Notes offered hereby (other than those covered by the
over-allotment option described herein) if any such Notes are purchased.
The Company has granted to the Underwriters an option, exercisable for 30
days from the date of this Prospectus, to purchase up to an additional
$11,250,000 aggregate principal amount of the Notes at the initial public
offering price, less the underwriting discount, set forth on the cover page of
this Prospectus. The Underwriters may exercise such option solely to cover
over-allotments, if any, in the sale of the Notes.
The Company has been advised by the several Underwriters that they propose
to initially offer the Notes to the public at the public offering price set
forth on the cover page of this Prospectus, and to certain dealers at such price
less a concession not in excess of 1.5% of the principal amount thereof. The
Underwriters may allow, and such dealers may reallow, a discount not in excess
of .25% of the principal amount of the Notes to certain other dealers. After the
initial public offering of the Notes, the public offering price, concession and
discount may be changed by the Underwriters.
The Notes are a new issue for which there is currently no public market. The
Company does not intend to apply for listing of the Notes on any securities
exchange or for quotation on the NASDAQ National Market. The Company has been
advised by the Underwriters that, following the completion of the Offering, each
of the Underwriters presently intends to make a market in the Notes, as
permitted by applicable law and regulations. The Underwriters are under no
obligation, however, to do so and may discontinue any market-making activities
at any time without notice. No assurance can be given as to the liquidity of the
trading market for the Notes or that an active trading market for the Notes will
develop. If an active public market does not develop, the market price and
liquidity of the Notes may be adversely affected.
The Company has agreed that it will not offer, sell, contract to sell or
otherwise dispose of, or register under the Securities Act on behalf of another
person, any shares of Common Stock or preferred stock, any securities
convertible into or exercisable or exchangeable for shares of Common Stock or
any rights to acquire shares of Common Stock for a period of 90 days from the
date of the Prospectus without the written consent of the Underwriters, except
that the Company may, without such consent, (i) issue (A) shares of Common Stock
issuable upon conversion of the Notes, (B) shares of Common Stock issuable upon
conversion of the 10.25% Notes or the 8% Debentures, (C) shares of Common
Stock issuable pursuant to options or similar rights granted to directors,
officers or employees, and (D) shares of Common Stock issuable pursuant to any
other employee benefit plans of the Company or (ii) grant options pursuant to
existing stock option plans of the Company.
The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities arising under the Securities Act, and to
contribute to payments the Underwriters may be required to make in respect of
such liabilities.
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LEGAL OPINIONS
Certain legal matters in connection with the Notes being offered hereby will
be passed upon for the Company by Baker & Botts, L.L.P., Houston, Texas and for
the Underwriters by Vinson & Elkins L.L.P., Houston, Texas.
EXPERTS
The consolidated financial statements and schedules of the Company included
or incorporated by reference in this Prospectus and elsewhere in the
Registration Statement have been audited by Arthur Andersen & Co., independent
public accountants, as indicated in their reports with respect thereto, and are
included herein in reliance upon the authority of said firm as experts in giving
said reports.
The estimates of oil and gas reserves and discounted present values of
estimated future net revenues therefrom set forth herein are extracted from the
report of Ryder Scott attached as an exhibit to the Annual Report. Such
information is included herein in reliance upon the authority of said firm as
experts with respect to the matters contained in such report.
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GLOSSARY OF OIL AND GAS TERMS
The following are abbreviations and definitions of terms commonly used in
the oil and gas industry and in this Prospectus.
'Bcf' means billion cubic feet.
'Bbl' means barrel.
'Mcf' means thousand cubic feet.
'MMcf' means million cubic feet.
'MBbls' means thousand barrels.
'MMBbls' means million barrels.
'Deliverability' means a measure of the quantity of natural gas that a
natural gas well can produce into a pipeline against a specific contractual
back pressure.
'Development well' means a well drilled within areas already proved to be
productive.
'Energy equivalent basis' means equating natural gas based on relative
energy content, using the ratio of six Mcf of natural gas to one Bbl of
crude oil, condensate or natural gas liquids.
'Exploratory well' means a well drilled to find commercially productive
hydrocarbons in an unproved area.
'Gross' oil and gas wells or 'gross' acres are the total number of wells or
acres in which the Company has an interest, without regard to the size of
that interest.
'Net' oil and gas wells or 'net' acres are determined by multiplying gross
wells or acres by the Company's working interest in those wells or acres.
'Net revenue interest' means the percentage of production to which the owner
of a working interest is entitled. For example, the owner of a 100% working
interest in a well burdened only by a typical landowner's royalty would have
an 87.5% net revenue interest in that well.
'Proved Reserves' means estimated quantities of natural gas and crude oil,
condensate and natural gas liquids, on a net revenue interest basis, that
geological and engineering data demonstrate with reasonable certainty to be
recoverable in the future from known reservoirs under existing economic and
operating conditions.
'Royalty' means an interest in an oil and gas lease that gives the owner of
the interest the right to receive a portion of the production from the
leased acreage (or of the proceeds of the sale thereof), but does not
require the owner to pay any portion of the costs of drilling or operating
the wells on the leased acreage. Royalties may be either landowner's
royalties, which are reserved by the owner of the leased acreage at the time
the lease is granted, or overriding royalty interests, which are usually
reserved by a leasehold owner upon a transfer to a subsequent owner.
'Undeveloped acreage' means acreage on which wells have not been drilled or
completed for commercial production, whether or not such acreage contains
proved reserves.
'Working interest' means an interest in an oil and gas lease that gives the
owner of the interest the right to drill for and produce oil and gas on the
leased acreage and requires the owner to pay a share of the costs of
drilling and production operations. The share of production to which a
working interest owner is entitled will always be smaller than the share of
costs that the working interest owner is required to bear, with the balance
of the production accruing to the owners of royalties. See the definitions
of 'net revenue interest' and 'royalty' above. For example, the owner of
100% working interest in a lease burdened only by a typical landowner's
royalty would be required to pay 100% of the costs of a well but would be
entitled to retain 87.5% of the production. The remaining 12.5% would accrue
to the royalty owners.
'Workover' means operations on a producing well to restore or increase
production.
47
<PAGE>
INDEX TO FINANCIAL STATEMENTS
PAGE
Report of Independent Public
Accountants------------------ F-2
Consolidated Statements of
Income----------------------- F-3
Consolidated Balance
Sheets----------------------- F-4
Consolidated Statements of
Cash Flows------------------- F-5
Consolidated Statements of
Shareholders' Equity--------- F-6
Notes to Consolidated
Financial Statements--------- F-7
Unaudited Supplementary
Financial Data--------------- F-14
F-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Shareholders and Board of Directors of Pogo Producing Company:
We have audited the accompanying consolidated balance sheets of Pogo
Producing Company (a Delaware corporation) and subsidiaries as of December 31,
1993 and 1992, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1993. These financial statements and the schedules referred to below are the
responsibility of Pogo's management. Our responsibility is to express an opinion
on these financial statements and schedules 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 financial statements referred to above present fairly,
in all material respects, the financial position of Pogo Producing Company and
subsidiaries as of December 31, 1993 and 1992, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN & CO.
Houston, Texas
February 8, 1994
F-2
<PAGE>
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
1993 1992 1991
(EXPRESSED IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
Revenues:
Oil and gas---------------------- $ 136,553 $ 139,128 $ 124,425
Interest on tax refund----------- 2,322 -- --
Gains on sales------------------- 679 1,702 44
Total------------------------ 139,554 140,830 124,469
Operating Costs and Expenses:
Lease operating------------------ 26,633 25,842 28,192
General and administrative------- 14,550 13,129 14,555
Exploration---------------------- 2,455 3,102 2,408
Dry hole and impairment---------- 4,690 9,314 4,554
Depreciation, depletion and
amortization------------------- 40,693 42,302 37,521
Total------------------------ 89,021 93,689 87,230
Operating Income--------------------- 50,533 47,141 37,239
Interest:
Charges-------------------------- (10,956) (19,036) (24,946)
Income--------------------------- 14 191 1,686
Capitalized---------------------- 451 391 637
Income Before Taxes and Extraordinary
Item--------------------------------- 40,042 28,687 14,616
Income Tax Expense------------------- (14,981) (10,192) (4,294)
Income Before Extraordinary Item----- 25,061 18,495 10,322
Extraordinary Gains on Purchase of
Debt, net of tax------------------- -- -- 1,336
Net Income--------------------------- $ 25,061 $ 18,495 $ 11,658
Primary and Fully Diluted Earnings
per
Common Share:
Before extraordinary item-------- $0.76 $0.66 $0.37
Extraordinary item--------------- -- -- 0.05
Net income----------------------- $0.76 $0.66 $0.42
The accompanying notes to consolidated financial statements are an integral part
hereof.
F-3
<PAGE>
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
1993 1992
(EXPRESSED IN
THOUSANDS)
ASSETS
Current Assets:
Cash and cash investments-------- $ 6,713 $ 5,037
Accounts receivable-------------- 18,480 22,652
Other receivables---------------- 10,123 4,173
Federal income taxes and interest
receivable--------------------- 3,320 --
Inventories---------------------- 1,105 1,383
Other---------------------------- 727 367
Total current assets--------- 40,468 33,612
Property and Equipment:
Oil and gas, on the basis of
successful efforts accounting
Proved properties being
amortized------------------ 817,218 869,192
Unproved properties and
properties under
development, not being
amortized------------------ 6,465 5,962
Other, at cost------------------- 6,961 6,851
830,644 882,005
Less -- accumulated depreciation,
depletion, and amortization,
including $4,452 and $4,032,
respectively, applicable to
other property----------------- 638,658 717,428
191,986 164,577
Other-------------------------------- 7,320 8,158
$ 239,774 $ 206,347
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable----------------- $ 8,307 $ 9,899
Other payables------------------- 22,955 5,541
Current portion of long-term
debt--------------------------- 4,000 4,000
Current portion of production
payment------------------------ -- 10,517
Accrued interest payable--------- 1,202 1,122
Accrued payroll and related
benefits----------------------- 1,005 942
Other---------------------------- 122 142
Total current liabilities---- 37,591 32,163
Long-Term Debt----------------------- 130,539 129,260
Production Payment------------------- -- 14,337
Deferred Federal Income Tax---------- 29,724 17,435
Deferred Credits--------------------- 8,117 7,504
Total liabilities------------ 205,971 200,699
Shareholders' Equity:
Preferred stock, $1 par;
2,000,000 shares authorized---- -- --
Common stock, $1 par; 43,333,333
shares authorized, 32,449,197
and 32,103,864 shares issued,
respectively------------------- 32,449 32,104
Additional capital--------------- 125,919 122,846
Retained earnings (deficit)------ (124,241) (149,302)
Treasury stock, at cost---------- (324) --
Total shareholders'
equity--------------------- 33,803 5,648
$ 239,774 $ 206,347
The accompanying notes to consolidated financial statements are an integral part
hereof.
F-4
<PAGE>
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
1993 1992 1991
(EXPRESSED IN THOUSANDS)
Cash flows from operating activities:
Cash received from customers------- $ 141,012 $ 135,877 $ 125,029
Operating, exploration, and general
and administrative expenses
paid------------------------------ (45,051) (41,360) (46,746)
Interest paid---------------------- (10,912) (21,262) (26,701)
Payment of royalties and related
interest on FERC Order 94-A
refunds--------------------------- -- (4,872) --
Federal income taxes paid---------- (2,800) (1,500) (2,900)
Federal income taxes and interest
received-------------------------- -- -- 30,836
Settlement of natural gas sales
contract-------------------------- -- -- 3,300
Proceeds of life insurance
policy---------------------------- -- -- 2,568
Other------------------------------ 895 828 2,974
Net cash provided by
operating activities------- 83,144 67,711 88,360
Cash flows from investing activities:
Capital expenditures--------------- (62,353) (30,304) (51,284)
Purchase of proved reserves-------- -- (8,924) (5,077)
Proceeds from the sale of property
and tubular stock----------------- 2,713 4,017 2,150
Net cash used in investing
activities----------------- (59,640) (35,211) (54,211)
Cash flows from financing activities:
Net borrowings (payments) under
revolving credit agreements------- 8,000 (1,000) 17,000
Principal payments of other
long-term debt obligations-------- (7,000) (54,000) (42,000)
Principal payments of production
payment obligation---------------- (24,854) (20,621) (14,611)
Proceeds from exercise of stock
options--------------------------- 2,026 703 123
Proceeds from issuance of common
stock----------------------------- -- 43,313 --
Debt issue expenses paid----------- -- (1,100) --
Increase in production payment----- -- -- 13,193
Purchase of 8% debentures, due
2005------------------------------ -- -- (7,621)
Net cash used in financing
activities----------------- (21,828) (32,705) (33,916)
Net increase (decrease) in cash and
cash investments-------------------- 1,676 (205) 233
Cash and cash investments at the
beginning of the year--------------- 5,037 5,242 5,009
Cash and cash investments at the end
of the year------------------------- $ 6,713 $ 5,037 $ 5,242
Reconciliation of net income to net
cash provided by operating
activities:
Net income------------------------- $ 25,061 $ 18,495 $ 11,658
Adjustments to reconcile net income
to net cash provided by operating
activities --
Gains on purchase of 8%
debentures, due 2005:
Ordinary----------------------- -- -- (646)
Extraordinary, net of taxes---- -- -- (1,336)
Gains on sales------------------- (679) (1,702) (44)
Depreciation, depletion and
amortization-------------------- 40,693 42,302 37,521
Dry hole and impairment---------- 4,690 9,314 4,554
Interest capitalized------------- (451) (391) (637)
Change in assets and liabilities:
Decrease in United Kingdom tax
escrow deposit---------------- -- -- 2,083
(Increase) decrease in accounts
receivable-------------------- 4,172 (1,191) 4,799
(Increase) decrease in federal
income taxes and interest
receivable-------------------- (3,320) -- 29,002
Increase in other current
assets------------------------ (360) (27) (32)
(Increase) decrease in other
assets------------------------ 838 (3,515) 1,641
Increase (decrease) in accounts
payable----------------------- (1,592) 733 (1,322)
Increase (decrease) in accrued
interest payable-------------- 80 (2,480) (1,342)
Increase (decrease) in accrued
payroll and related
benefits---------------------- 63 (244) 375
Increase (decrease) in other
current liabilities----------- (20) (9) 62
Increase in deferred federal
income taxes------------------ 13,356 8,669 1,268
Increase (decrease) in deferred
credits----------------------- 613 (2,243) 756
Net cash provided by operating
activities-------------------------- $ 83,144 $ 67,711 $ 88,360
The accompanying notes to consolidated financial statements are an integral part
hereof.
F-5
<PAGE>
<TABLE>
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<CAPTION>
SHARE-
RETAINED HOLDERS'
SHARES COMMON ADDITIONAL EARNINGS TREASURY EQUITY
OUTSTANDING STOCK CAPITAL (DEFICIT) STOCK (DEFICIT)
(DOLLARS EXPRESSED IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1990--------- 27,428,652 $ 27,428 $ 83,598 $ (179,455) $ -- $ (68,429)
Net income--------------------------- -- -- -- 11,658 -- 11,658
Exercise of stock options------------ 28,170 29 106 -- -- 135
Balance at December 31, 1991--------- 27,456,822 27,457 83,704 (167,797) -- (56,636)
Net income--------------------------- -- -- -- 18,495 -- 18,495
Issuance of common stock------------- 4,500,000 4,500 38,368 -- -- 42,868
Exercise of stock options------------ 147,042 147 774 -- -- 921
Balance at December 31, 1992--------- 32,103,864 32,104 122,846 (149,302) -- 5,648
Net income--------------------------- -- -- -- 25,061 -- 25,061
Exercise of stock options------------ 345,308 345 3,072 -- -- 3,417
Acquisition of treasury stock at cost (15,575) -- -- -- (324) (324)
Conversion of debenture-------------- 25 -- 1 -- -- 1
Balance at December 31, 1993--------- 32,433,622 $ 32,449 $ 125,919 $ (124,241) $ (324) $ 33,803
</TABLE>
The accompanying notes to consolidated financial statements are an integral part
hereof.
F-6
<PAGE>
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION --
The consolidated financial statements include the accounts of Pogo Producing
Company and its wholly-owned subsidiaries (the 'Company'), after elimination of
all significant intercompany transactions.
INVENTORIES --
Inventories consist primarily of tubular goods used in the Company's
operations and are stated at the lower of average cost or market value.
INTEREST CAPITALIZED --
Interest costs related to financing major oil and gas projects in progress
are capitalized until the projects are evaluated.
EARNINGS PER SHARE --
Earnings per common and common equivalent share are based on weighted
average shares of Common Stock outstanding assuming exercise of dilutive stock
options. The 8% convertible subordinated debentures, due 2005 are common stock
equivalents and were anti-dilutive in all periods presented. The 10.25%
convertible subordinated notes, due 1999 are not common stock equivalents and
were anti-dilutive in all periods presented. The weighted average number of
common and common stock equivalent shares outstanding for primary earnings per
share was 32,860,000, 27,929,000, and 27,611,000 in 1993, 1992, and 1991,
respectively. The additional shares which would be assumed to be outstanding in
the fully diluted calculation are not sufficient to change the earnings per
share amounts reported in the primary calculation.
PRODUCTION IMBALANCES --
Owners of an oil and gas property often take more or less production from a
property than entitled to based on their ownership percentages in the property.
This results in a condition known in the industry as a production imbalance. The
Company follows the 'take' (cash) method of accounting for production
imbalances. Under this method, the Company recognizes revenues on production as
it is taken and delivered to its purchasers. The Company's crude oil imbalances
are not significant. At December 31, 1993, the Company had taken approximately
10,195 MMcf of natural gas less than it was entitled to based on its interest in
those properties, and approximately 7,295 MMcf more than its entitlement on
other properties placing the Company at year end in a net under-delivered
position of approximately 2,900 MMcf of natural gas based on its working
interest ownership in the properties.
OIL AND GAS ACTIVITIES AND DEPRECIATION, DEPLETION, AND AMORTIZATION --
The Company follows the successful efforts method of accounting for its oil
and gas activities. Under the successful efforts method, lease acquisition costs
and all development costs are capitalized. Unproved properties are reviewed
quarterly to determine if there has been impairment of the carrying value, with
any such impairment charged to expense in the period. Exploratory drilling costs
are capitalized until the results are determined. If proved reserves are not
discovered, the exploratory drilling costs are expensed. Other exploratory costs
are expensed as incurred. The provision for depreciation, depletion and
amortization is determined on a field-by-field basis using the units of
production method.
F-7
<PAGE>
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Other properties are depreciated on a straight-line method in amounts which
in the opinion of management are adequate to allocate the cost of the properties
over their estimated useful lives.
CONSOLIDATED STATEMENTS OF CASH FLOWS --
For the purpose of cash flows, the Company considers all highly liquid
investments with a maturity date of three months or less to be cash equivalents.
Significant transactions may occur which do not directly affect cash balances
and as such will not be disclosed in the Consolidated Statement of Cash Flows.
Certain such noncash transactions are disclosed in the Consolidated Statements
of Shareholders' Equity relating to the acquisition of treasury stock in
exchange for stock options exercised and the conversion of a debenture into
Common Stock. In addition, the Company exchanged its working interest in
thirteen Gulf of Mexico oil and gas properties for an increased working interest
in five other Gulf of Mexico oil and gas properties in a noncash 'like kind'
exchange. The oil and gas property and accumulated depreciation, depletion and
amortization accounts as reflected in the Consolidated Balance Sheets have been
adjusted to reflect the appropriate amounts to record the working interests
acquired and disposed of. The oil and gas reserves acquired and disposed of are
reflected as purchases and sales in the roll forward 'Estimates of Proved
Reserves' included in the 'Unaudited Supplementary Financial Data' included
elsewhere herein.
COMMITMENTS AND CONTINGENCIES --
The Company's rent expense was $868,000, $808,000, and $1,069,000 in 1993,
1992, and 1991, respectively. The Company has lease commitments for office space
of $809,000 per year in each year for 1994 through 1997 and $777,000 in 1998.
(2) INCOME TAXES
The components of federal income tax expense (benefit) for each of the three
years in the period ended December 31, 1993, are as follows (expressed in
thousands):
1993 1992 1991
United States
Current-------------------------- $ 2,800 $ 1,500 $ 2,900
Deferred (a)--------------------- 12,360 8,672 1,125
Foreign
Current-------------------------- (179) 20 269
Total------------------------ $ 14,981 $ 10,192 $ 4,294
(a) Excludes $688,000 of deferred taxes on a $2,024,000 extraordinary item in
1991.
Total federal income tax expense (benefit) for each of the three years in
the period ended December 31, 1993, differs from the amounts computed by
applying the statutory federal income tax rate to income before taxes as follows
(expressed as a percent of pretax income):
1993 1992 1991
Federal statutory income tax rate---- 35.0% 34.0% 34.0%
Increases (reductions) resulting
from:
Statutory depletion in excess of
tax basis---------------------- (0.4) (0.1) (0.9)
Foreign taxes-------------------- 2.9 1.4 1.8
Life insurance loan proceeds----- -- -- (5.9)
Other---------------------------- -- 0.2 0.4
37.5% 35.5% 29.4%
F-8
<PAGE>
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The deferred federal income tax provision is the result of the difference
between deferred tax liabilities determined at each balance sheet date. The
deferred tax liabilities are determined by applying current tax laws to
temporary differences in the recognition of revenue and expense for tax and
financial purposes. Temporary differences arise primarily from the amortization
of productive intangible drilling costs which are capitalized and amortized for
financial statement purposes but are deducted for income tax purposes and
differences in depreciation rates for tangible assets for financial and tax
reporting purposes.
As of December 31, 1993, the Company has general business credits of
approximately $1,400,000, which can be used to reduce future income taxes. In
addition, the Company has alternative minimum tax credits of approximately
$4,235,000 which can be used to reduce future regular income taxes payable.
(3) LONG-TERM DEBT
Long-term debt and the amount due within one year at December 31, 1993 and
1992, consists of the following (dollars expressed in thousands):
DECEMBER 31,
1993 1992
Senior debt --
Bank revolving credit agreements
debt:
Prime rate loans------------- $ 27,000 $ 9,000
LIBO Rate loans-------------- 40,000 50,000
Certificate of deposit rate
loans---------------------- -- --
Total senior debt-------------------- 67,000 59,000
Subordinated debt --
10.25% Convertible subordinated
notes, due 1999,
$4,000 annual sinking fund
requirement-------------------- 24,000 28,000
8% Convertible subordinated
debentures, due 2005,
$1,540 sinking fund requirement
in 1995 and a
$3,000 annual sinking fund
requirement thereafter--------- 43,539 46,260
Total subordinated debt-------------- 67,539 74,260
Total debt--------------------------- 134,539 133,260
Amount due within one year --
Current portion of long-term
debt, consisting of sinking
fund
requirement on 10.25% notes---- (4,000) (4,000)
Long-term debt----------------------- $ 130,539 $ 129,260
The bank revolving credit agreement entered into in December 1993, extends
to the Company a $100,000,000 revolving/term credit facility which will be fully
revolving until June 29, 1996 and will convert to a term loan with eight
quarterly installments commencing July 31, 1996. The amount that may be borrowed
under the facility may not exceed a borrowing base, determined semiannually by
the lenders based on the discounted present value of the Company's oil and gas
reserves and the provisions of the agreement. The borrowing base currently
exceeds $100,000,000. The agreement provides that total debt and total debt for
borrowed money, as defined, may not exceed $230,000,000 and $200,000,000,
respectively. The facility is governed by various financial covenants including
the maintenance of positive working capital (excluding current maturities of
debt), a fixed charge ratio, as defined, of 1.7 or greater, a $10,000,000 limit
on other senior debt, and a $10,000,000 limit on prepayment (without
refinancing) of subordinated debt in any one year and $20,000,000 in total
through July 31, 1996. Upon the occurrence of an event of default or certain
other specified events, the banks would be entitled to a security interest in
the borrowing base properties, which constitute substantially all of the
Company's domestic oil and gas properties. Borrowings under the facility bear
F-9
<PAGE>
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
interest at Base (Prime) rate plus 1/4%, a certificate of deposit rate plus
1 7/8%, or LIBOR plus 1 3/4%, at the Company's option. A commitment fee of 1/2
of 1% per annum of the unborrowed amount under the facility is also due. The
Company incurred commitment fees of $149,000 in 1993, $80,000 in 1992, and
$132,000 in 1991 under this and prior revolving credit agreements.
The 10.25% convertible notes are convertible into Common Stock at $23.95 per
share subject to adjustment under certain circumstances, including stock splits.
The convertible debentures are redeemable at the option of the Company at 103.7%
through April 1, 1994, at 102.95% through April 1, 1995, and decreasing
percentages thereafter, under certain market conditions, and are subject to
mandatory annual sinking fund requirements of $4,000,000 which commenced April
1, 1990. The sinking fund requirements will be sufficient to retire 90% of the
issue prior to maturity.
The 8% convertible debentures are convertible into Common Stock at $39.50
per share subject to adjustment under certain circumstances, including stock
splits. These convertible debentures are redeemable at the option of the Company
at 102.8% through December 30, 1994, and decreasing percentages thereafter, and
are subject to mandatory annual sinking fund requirements of $3,000,000 which
commenced December 31, 1990. Such requirements will be sufficient to retire 75%
of the issue prior to maturity. To date, the Company has purchased $13,740,000
principal amount of the bonds at less than face value resulting in ordinary
gains of $646,000 and $902,000 in 1991 and 1990, respectively, on the bonds
purchased in satisfaction of sinking fund requirements in those years, and a
$1,336,000 extraordinary gain (net of taxes) in 1991 on the bonds purchased in
excess of current sinking fund requirements. The Company currently has
$4,460,000 face amount of the bonds purchased in excess of current sinking fund
requirements which may be tendered in satisfaction of future sinking fund
requirements. The Company elected to make the December 31, 1993 sinking fund
payment in cash.
Current maturities and sinking fund requirements during the next five years
in connection with the above long-term debt are $4,000,000 in 1994, $5,540,000
in 1995, $27,100,000 in 1996, $40,500,000 in 1997 and $20,400,000 in 1998.
Included in the current maturities reflected above are $20,100,000 in 1996,
$33,500,000 in 1997, and $13,400,000 in 1998 relative to bank debt. The Company
has established a history of refinancing its bank debt before scheduled
maturities and expects to do so again before the amortization of bank debt
commences in 1996.
In 1993, the Company entered into interest rate swap agreements on
$15,000,000 of its bank debt, $5,000,000 of which terminated in January, 1994
and $10,000,000 of which terminates in July, 1994. The swap agreements
effectively change the interest rates from variable to fixed rates which average
5.78% on the $15,000,000.
(4) SALES TO MAJOR CUSTOMERS
The Company is an oil and gas exploration and production company that until
recently sold its production to relatively few customers. As a result of recent
changes in the natural gas industry, the Company, like many other producers, now
sells its natural gas to numerous customers on a month-to-month basis. The
Company no longer has a significant amount of its natural gas reserves committed
to long-term (multiple year) contracts at higher than prevailing market prices.
Sales to the following customers exceeded 10 percent of oil and gas revenues
during the years indicated (expressed in thousands):
1993 1992 1991
Scurlock Oil Company----------------- $ 38,510 $ 39,729 $ 38,554
United Gas Pipeline Company---------- $ -- $ -- $ 21,074
Enron Corp--------------------------- $ 16,437 $ -- $ --
F-10
<PAGE>
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(5) EMPLOYEE BENEFITS
A total of 2,353,069 shares of Common Stock are reserved for issuance to key
employees and non-employee directors under the Company's stock option plans. The
stock option plans authorize the granting of options at prices equivalent to the
market value at the date of grant. Options generally become exercisable in three
annual installments commencing one year after the date granted and, if not
exercised, expire 10 years from the date of grant. At January 1, 1993, 1,544,484
shares were issuable under stock options outstanding. Options for 291,500 shares
were granted during 1993 at prices ranging from $15.13 to $19.00 per share.
During 1993, 345,308 options were exercised at prices ranging from $4.38 to
$16.25 per share and no options were cancelled. At December 31, 1993, options to
purchase 1,490,676 shares were outstanding (1,098,815 were exercisable) at
prices ranging from $4.38 to $19.00.
The Company has a tax-advantaged savings plan in which all salaried
employees may participate. Under such plan, a participating employee may
allocate up to 10% of his salary, and the Company makes matching contributions
of up to 6% thereof. Funds contributed by the employee and the matching funds
contributed by the Company are held in trust by a bank trustee in six separate
funds. Funds contributed by the employee and earnings and accretions thereon may
be used to purchase shares of Common Stock, invest in a money market fund or
invest in four stock, bond, or blended stock and bond mutual funds according to
instructions from the employee. Matching funds contributed to the savings plan
by the Company are invested only in Common Stock. The Company contributed
$125,000 to the savings plan in 1993, $288,000 in 1992, and $265,000 in 1991.
A trusteed retirement plan has been adopted by the Company for its salaried
employees. The benefits are based on years of service and the employee's average
compensation for five consecutive years within the final ten years of service
which produce the highest average compensation. The Company makes annual
contributions to the plan in the amount of retirement plan cost accrued or the
maximum amount which can be deducted for federal income tax purposes. The
following table sets forth the plan's funded status (in thousands of dollars) as
of December 31, 1993, 1992, and 1991.
1993 1992 1991
Actuarial present value (discounted
at 7 1/2, 8 1/4, and 8 1/2%,
respectively) of benefit
obligations:
Accumulated benefit
obligations --
Vested----------------------- $ 4,019 $ 3,120 $ 2,997
Nonvested-------------------- 717 701 657
Total accumulated benefit
obligations------------------ 4,736 3,821 3,654
Projected salary increases
(escalated at 6%) and other
changes------------------------ 1,500 2,653 2,441
Projected benefit obligations for
service rendered to date------- 6,236 6,474 6,095
Plan assets at fair value, primarily
listed securities with an expected
long-term rate of return of
8 1/4%----------------------------- 13,481 13,830 13,505
Plan assets in excess of projected
benefit obligations---------------- 7,245 7,356 7,410
Unrecognized:
Net overfunding being recognized
over 15 years------------------ (750) (853) (957)
Net gain arising from the
difference between actual
experience and that assumed---- (3,209) (3,956) (4,438)
Prior service cost--------------- (473) (41) (45)
Accrued retirement plan asset-------- $ 2,813 $ 2,506 $ 1,970
(TABLE CONTINUED ON FOLLOWING PAGE)
F-11
<PAGE>
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1993 1992 1991
Retirement plan cost (benefit) for
1993, 1992, and 1991 included the
following components:
Service cost, benefits accruing
each year with proration for
future salary increases-------- $ 611 $ 514 $ 501
Interest cost on projected
benefit obligations------------ 524 451 508
Actual return on plan assets----- (1,164) (1,141) (3,882)
Net amortization and deferral---- (278) (360) 2,853
Accrued retirement plan cost
(benefit)---------------------- $ (307) $ (536) $ (20)
Effective January 1, 1992, the Company adopted the provisions of the
Statement of Financial Accounting Standards No. 106, 'Employers' Accounting for
Postretirement Benefits Other Than Pensions.' The Company currently provides
full medical benefits to its retired employees and dependents. For current
employees, the Company assumes all or a portion of postretirement medical and
term life insurance costs based on the employee's age and length of service with
the Company. The postretirement medical plan has no assets and is currently
funded by the Company on a pay-as-you-go basis.
The following is an analysis (in thousands of dollars) of the annual expense
and activity in the deferred cost and benefits obligation accounts for 1992 and
1993. The computation assumes that future increases in medical costs will trend
down from 13% to 7% per year over the next 12 years for purposes of estimating
future costs. The medical cost trend rate assumption has a significant effect on
the amounts reported. Increasing the assumed medical cost trend rate by one
percent in each year would increase the aggregate of service and interest cost
components of net periodic postretirement benefits cost for 1993 by $164,000 and
the accumulated postretirement benefits obligation as of December 31, 1993 by
$1,171,000.
<TABLE>
<CAPTION>
ANNUAL DEFERRED BENEFITS
EXPENSE COSTS OBLIGATION
<S> <C> <C> <C>
Transition obligation at January 1, 1992------------------------------ $ 4,263 $ (4,263)
Amortization of transition cost over 14 years representing the average
remaining service period of eligible employees---------------------- $ 305 (305) 305
Service cost, including interest-------------------------------------- 303
Interest cost on transition obligation-------------------------------- 362
1992 expense---------------------------------------------------------- $ 970 (970)
Current benefits paid------------------------------------------------- 170
Balance at December 31, 1992------------------------------------------ 3,958 (4,758)
Amortization of transition costs over 14 years------------------------ $ 305 (305) 305
Service cost, including interest-------------------------------------- 368
Interest cost on transition obligation-------------------------------- 407
1993 expense---------------------------------------------------------- $ 1,080 (1,080)
Current benefits paid------------------------------------------------- 246
Unrecognized loss----------------------------------------------------- (1,400)
Balance at December 31, 1993------------------------------------------ $ 3,653
Plan assets at fair value--------------------------------------------- --
Funded status at December 31, 1993 (discounted at 7 1/2%)------------- $ (6,687)
</TABLE>
F-12
<PAGE>
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The accumulated postretirement benefit obligation (in thousands of dollars)
at December 31, 1993 is attributable to the following groups:
Retirees and beneficiaries------------------- $ 2,739
Dependents of retirees----------------------- 1,188
Fully eligible active employees-------------- 577
Active employees, not fully eligible--------- 2,183
$ 6,687
(6) FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value.
CASH AND CASH INVESTMENTS
The carrying value approximates fair value because of the short maturity of
these investments.
DEBT
INSTRUMENT BASIS OF FAIR VALUE ESTIMATE
Bank revolving credit agreement
debt------------------------------- Fair value is carrying value based on
recent 1993 renegotiation with banks
10.25% Convertible subordinated
notes, due 1999-------------------- Fair value is 103.7% of carrying value
based on the redemption premium at
December 31, 1993
8% Convertible subordinated
debentures, due 2005--------------- Fair value is 99.5% of carrying value
based on the quoted market price for
this publicly traded debt at
December 31, 1993
The estimated fair value of the Company's financial instruments (in
thousands of dollars) are as follows:
CARRYING FAIR
VALUE VALUE
Cash and cash investments------------ $ 6,713 $ 6,713
Debt--------------------------------- (134,539) (135,209)
F-13
<PAGE>
UNAUDITED SUPPLEMENTARY FINANCIAL DATA
OIL AND GAS PRODUCING ACTIVITIES
The results of operations from oil and gas producing activities excludes
non-oil and gas revenues, general and administrative expenses, interest charges,
interest income and interest capitalized. United States income tax expense was
determined by applying the statutory rates to pretax operating results with
adjustments for permanent differences. Kingdom of Thailand tax expense was
determined by applying the statutory tax rate to Thailand taxable income.
UNITED KINGDOM OF
TOTAL STATES THAILAND
(EXPRESSED IN THOUSANDS)
1993
Oil and gas revenues----------------- $ 136,553 $ 136,525 $ 28
Lease operating expense-------------- (26,633) (26,633) --
Exploration expense------------------ (2,455) (1,060) (1,395)
Dry hole and impairment expense------ (4,690) (2,737) (1,953)
Depreciation, depletion and
amortization expense--------------- (40,224) (40,193) (31)
Pretax operating results------------- 62,551 65,902 (3,351)
Income tax (expense) benefit--------- (22,712) (22,891) 179
Operating results-------------------- $ 39,839 $ 43,011 $ (3,172)
1992
Oil and gas revenues----------------- $ 139,128 $ 139,128 $ --
Lease operating expense-------------- (25,842) (25,842) --
Exploration expense------------------ (3,102) (1,876) (1,226)
Dry hole and impairment expense------ (9,314) (9,314) --
Depreciation, depletion and
amortization expense--------------- (41,849) (41,834) (15)
Pretax operating results------------- 59,021 60,262 (1,241)
Income tax expense------------------- (20,510) (20,490) (20)
Operating results-------------------- $ 38,511 $ 39,772 $ (1,261)
1991
Oil and gas revenues----------------- $ 124,425 $ 124,425 $ --
Lease operating expense-------------- (28,192) (28,192) --
Exploration expense------------------ (2,408) (2,261) (147)
Dry hole and impairment expense------ (4,554) (4,554) --
Depreciation, depletion and
amortization expense--------------- (36,970) (36,965) (5)
Pretax operating results------------- 52,301 52,453 (152)
Income tax expense------------------- (17,725) (17,698) (27)
Operating results-------------------- $ 34,576 $ 34,755 $ (179)
The following table sets forth Pogo's capitalized costs (expressed in
thousands) incurred for oil and gas producing activities during the years
indicated.
1993 1992 1991
Capitalized costs incurred:
Property acquisition (United
States)------------------------ $ 1,520 $ 11,578 $ 7,697
Exploration --
United States---------------- 8,267 3,865 3,546
Kingdom of Thailand---------- 4,583 1,412 --
Development --
United States---------------- 57,648 20,717 37,025
Kingdom of Thailand---------- -- -- --
Interest capitalized (United
States)------------------------ 451 391 637
$ 72,469 $ 37,963 $ 48,905
Provision for depreciation,
depletion, and amortization:
United States---------------- $ 40,193 $ 41,834 $ 36,965
Kingdom of Thailand---------- 31 15 5
$ 40,224 $ 41,849 $ 36,970
F-14
<PAGE>
UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED)
The following information regarding estimates of the Company's proved oil
and gas reserves, which are located offshore in United States waters of the Gulf
of Mexico, onshore in the United States and offshore in the Kingdom of Thailand
is based on reports prepared by Ryder Scott Company Petroleum Engineers. Their
summary report dated January 28, 1994 is set forth as an exhibit to the Annual
Report and includes definitions and assumptions as set forth therein and which
serve as the basis for the discussion under the caption 'Business and
Properties-- Reserves.'Such definitions and assumptions should be referred to
in connection with the following information.
ESTIMATES OF PROVED RESERVES
OIL,
CONDENSATE AND
NATURAL GAS
LIQUIDS NATURAL GAS
(BBLS.) (MMCF)
Proved reserves (located in the
United States) as of
December 31, 1990------------------ 19,090,376 217,500
Revisions of previous
estimates---------------------- 782,707 3,531
Extensions, discoveries, and
other additions---------------- 1,612,983 16,157
Purchase of properties----------- 263,495 4,913
Sales of properties-------------- (5) (4)
Estimated 1991 production-------- (2,931,465) (39,362)
Proved reserves (located in the
United States) as of
December 31, 1991------------------ 18,818,091 202,735
Revisions of previous
estimates---------------------- 1,721,385 20,284
Extensions, discoveries, and
other additions (including
2,576,907 barrels and 10,668
MMcf located in the Kingdom of
Thailand)---------------------- 5,486,273 19,126
Purchase of properties----------- 335,750 10,237
Sales of properties-------------- (194,606) (4,733)
Estimated 1992 production-------- (3,611,105) (40,581)
Proved reserves (located in the
United States except for 2,576,907
barrels and 10,668 MMcf located in
the Kingdom of Thailand) as of
December 31, 1992------------------ 22,555,788 207,068
Revisions of previous
estimates---------------------- 342,022 1,148
Extensions, discoveries, and
other additions (including
2,847,906 barrels and 22,806
MMcf located in the
Kingdom of Thailand)----------- 9,764,408 55,626
Purchase of properties----------- 182,610 13,192
Sales of properties-------------- (356,514) (11,849)
Estimated 1993 production-------- (4,219,873) (32,319)
Proved reserves (located in the
United States except for 5,424,813
barrels and 33,474 MMcf located in
the Kingdom of Thailand) as of
December 31, 1993------------------ 28,268,441 232,866
Proved developed reserves (located in
the United States) as of:
December 31, 1990---------------- 17,841,751 202,471
December 31, 1991---------------- 17,549,830 188,090
December 31, 1992---------------- 18,798,149 175,523
December 31, 1993---------------- 20,976,194 183,139
F-15
<PAGE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES
1993
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
(EXPRESSED IN THOUSANDS)
Future gross revenues---------------- $ 869,783 $ 744,201 $ 125,582
Future production costs:
Lease operating expense---------- (186,464) (158,934) (27,530)
Future development and abandonment
costs------------------------------ (133,258) (79,735) (53,523)
Future net cash flows before income
taxes------------------------------ 550,061 505,532 44,529
Discount at 10% per annum------------ (146,221) (118,858) (27,363)
Discounted future net cash flow
before income taxes---------------- 403,840 386,674 17,166
Future income taxes, net of discount
at 10% per annum------------------- (103,580) (98,788) (4,792)
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves-------- $ 300,260 $ 287,886 $ 12,374
1992
Future gross revenues---------------- $ 856,238 $ 791,865 $ 64,373
Future production costs:
Lease operating expense---------- (179,721) (173,355) (6,366)
Future development and abandonment
costs------------------------------ (105,843) (80,887) (24,956)
Future net cash flows before income
taxes------------------------------ 570,674 537,623 33,051
Discount at 10% per annum------------ (165,573) (146,730) (18,843)
Discounted future net cash flow
before income taxes---------------- 405,101 390,893 14,208
Future income taxes, net of discount
at 10% per annum------------------- (97,444) (91,848) (5,596)
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves-------- $ 307,657 $ 299,045 $ 8,612
1991
Future gross revenues---------------- $ 725,360 $ 725,360 $ --
Future production costs:
Lease operating expense---------- (163,262) (163,262) --
Future development and abandonment
costs------------------------------ (67,671) (67,671) --
Future net cash flows before income
taxes------------------------------ 494,427 494,427 --
Discount at 10% per annum------------ (144,673) (144,673) --
Discounted future net cash flow
before income taxes---------------- 349,754 349,754 --
Future income taxes, net of discount
at 10% per annum------------------- (76,423) (76,423) --
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves-------- $ 273,331 $ 273,331 $ --
The standardized measure of discounted future net cash flows from the
production of proved reserves is developed as follows:
1. Estimates are made of quantities of proved reserves and the future
periods in which they are expected to be produced based on year end economic
conditions.
F-16
<PAGE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- (CONTINUED)
2. The estimated future gross revenues from proved reserves are priced on
the basis of year end prices, except in those instances where fixed and
determinable natural gas price escalations are covered by contracts.
3. The future gross revenue streams are reduced by estimated future costs
to develop and to produce the proved reserves, as well as certain abandonment
costs based on year end cost estimates, and the estimated effect of future
income taxes.
The standardized measure of discounted future net cash flows does not
purport to present the fair market value of Pogo's oil and gas reserves. An
estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs, a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows. All amounts are related to changes
in reserves located in the United States unless otherwise noted.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1993
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
(EXPRESSED IN THOUSANDS)
<S> <C> <C> <C>
Beginning balance-------------------- $ 307,657 $ 299,045 $ 8,612
Revisions to prior years' proved
reserves:
Net changes in prices and
production costs--------------- (41,775) (34,842) (6,933)
Net changes due to revisions
in quantity estimates------------ 4,066 4,066 --
Net changes in estimates of
future development costs------- 662 (871) 1,533
Accretion of discount------------ 40,510 39,089 1,421
Changes in production rate------- 5,134 6,728 (1,594)
Other---------------------------- 2,278 3,935 (1,657)
Total revisions-------------- 10,875 18,105 (7,230)
New field discoveries and extensions,
net of future production and
development costs:----------------- 39,247 29,059 10,188
Purchases of properties-------------- 22,516 22,516 --
Sales of properties------------------ (19,633) (19,633) --
Sales of oil and gas produced, net of
production costs------------------- (110,870) (110,870) --
Previously estimated development
costs incurred--------------------- 56,604 56,604 --
Net change in income taxes----------- (6,136) (6,940) 804
Net change in
standardized measure of
discounted future net
cash flows------------- (7,397) (11,159) 3,762
Ending balance----------------------- $ 300,260 $ 287,886 $ 12,374
</TABLE>
F-17
<PAGE>
<TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- (CONTINUED)
<CAPTION>
YEAR ENDED DECEMBER 31,
1992 1991
(EXPRESSED IN THOUSANDS)
<S> <C> <C>
Beginning balance-------------------- $ 273,331 $ 400,937
Revisions to prior years' proved
reserves:
Net changes in prices and
production costs--------------- 38,348 (174,464)
Net changes due to revisions in
quantity estimates------------- 42,829 9,940
Net changes in estimates of
future development costs------- (21,015) (28,740)
Accretion of discount------------ 34,975 52,517
Changes in production rate------- (5,733) (6,518)
Other---------------------------- 6,607 (7,404)
Total revisions-------------- 96,011 (154,669)
New field discoveries and extensions,
net of future production and
development costs:
United States---------------- 29,552 28,286
Kingdom of Thailand---------- 14,208 --
Purchases of properties-------------- 13,870 6,827
Sales of properties------------------ (7,430) (7)
Sales of oil and gas produced, net of
production costs------------------- (111,581) (92,895)
Previously estimated development
costs incurred--------------------- 20,717 37,039
Net change in income taxes:
United States---------------- (15,425) 47,813
Kingdom of Thailand---------- (5,596) --
Net change in
standardized measure of
discounted future net
cash flows------------- 34,326 (127,606)
Ending balance----------------------- $ 307,657 $ 273,331
</TABLE>
F-18
<PAGE>
QUARTERLY RESULTS
Summaries of Pogo's results of operations by quarter for the years 1993 and
1992 are as follows:
<TABLE>
<CAPTION>
QUARTER ENDED
MAR. 31 JUNE 30 SEPT. 30 DEC. 31
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1993
Revenues----------------------------- $ 34,681 $ 34,533 $ 37,210 $ 33,130
Gross profit(a)---------------------- $ 17,331 $ 15,391 $ 17,903 $ 14,458
Net income--------------------------- $ 7,160 $ 5,596 $ 7,161 $ 5,144
Earnings per share
(primary and fully diluted)-------- $ 0.22 $ 0.17 $ 0.22 $ 0.16
1992
Revenues----------------------------- $ 28,347 $ 34,072 $ 34,907 $ 43,504
Gross profit(a)---------------------- $ 7,147 $ 12,646 $ 16,165 $ 24,312
Net income (loss)-------------------- $ (1,216) $ 3,276 $ 5,535 $ 10,900
Earnings (loss) per share
(primary and fully diluted)-------- $ (0.04) $ 0.12 $ 0.20 $ 0.38
(a) Represents revenues less lease operating, exploration, dry hole and
impairment, and depreciation, depletion and amortization expenses.
</TABLE>
F-19
<PAGE>
NO DEALER, SALESPERSON OR OTHER INDIVIDUAL HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS NOT CONTAINED IN THIS PROSPECTUS IN
CONNECTION WITH THE OFFERING COVERED BY THIS PROSPECTUS. IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATIONS 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 A SOLICITATION OF AN OFFER TO BUY, THE NOTES IN ANY JURISDICTION
WHERE, OR TO ANY INDIVIDUAL WHOM, IT IS UNLAWFUL TO MAKE SUCH OFFER OR
SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE AN IMPLICATION THAT THERE HAS
NOT BEEN ANY CHANGE IN THE FACTS SET FORTH IN THIS PROSPECTUS OR IN THE AFFAIRS
OF THE COMPANY SINCE THE DATE HEREOF.
TABLE OF CONTENTS
PAGE
Available Information---------------- 2
Incorporation of Certain Documents by
Reference-------------------------- 2
Prospectus Summary------------------- 3
Investment Considerations------------ 9
The Company-------------------------- 12
Use of Proceeds---------------------- 14
Capitalization----------------------- 15
Price Range of Common Stock and
Dividends-------------------------- 16
Selected Financial and Operating
Data------------------------------- 17
Management's Discussion and Analysis
of Financial Condition and Results
of Operations---------------------- 19
Business and Properties-------------- 24
Management--------------------------- 35
Description of the Notes------------- 36
Description of Capital Stock--------- 43
Underwriting------------------------- 45
Legal Opinions----------------------- 46
Experts------------------------------ 46
Glossary of Oil and Gas Terms-------- 47
Index to Financial Statements-------- F-1
$75,000,000
LOGO
POGO PRODUCING COMPANY
5 1/2% CONVERTIBLE
SUBORDINATED NOTES DUE 2004
PROSPECTUS
MERRILL LYNCH & CO.
GOLDMAN, SACHS & CO.
PAINEWEBBER INCORPORATED
MARCH 16, 1994
