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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1993
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
COMMISSION FILE NO. 1-7792
POGO PRODUCING COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 74-1659398
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
5 GREENWAY PLAZA, P.O. BOX 2504
HOUSTON, TEXAS 77252-2504
ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
Registrant's telephone number, including area code:
(713) 297-5000
Securities registered pursuant to Section 12(b) of the Act:
TITLE OF EACH CLASS: NAME OF EACH EXCHANGE ON WHICH REGISTERED:
Common Stock, $1 par value New York Stock Exchange
Pacific Stock Exchange
8% Convertible Subordinated New York Stock Exchange
Debentures Due December 31, 2005
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by checkmark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Act of 1934 during
the preceeding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes /X/ No. / /.
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the Common Stock held by non-affiliates of the
registrant (treating all executive officers and directors of the registrant, for
this purpose, as if they may be affiliates of the registrant) was approximately
$561,037,000 as of February 24, 1994 (based on $19.00 per share, the last sale
price of the Common Stock as reported on the New York Stock Exchange Composite
Tape on such date).
32,542,952 shares of the registrant's Common Stock were outstanding as of
February 24, 1994.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Company's definitive Proxy Statement respecting the annual
meeting of shareholders to be held on April 26, 1994 (to be filed not later than
120 days after December 31, 1993) are incorporated by reference in Part III of
this Form 10-K.
PART I
ITEM 1. BUSINESS.
Pogo Producing Company (the 'Company'), incorporated in 1970, 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.
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 million cubic feet
('MMcf') per day of natural gas and 4,600 barrels ('Bbls') per day of oil,
condensate and natural gas liquids. The table in Item 2 of this Annual Report on
Form 10-K for the year ended December 31, 1993 (the 'Annual Report') summarizes
the Company's offshore leasehold interests, drilling activity, and platforms set
or announced as of December 31, 1993.
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
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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 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
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
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 'Properties -- 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 Annual Report 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 ('Association of Southeast Asian Nations') 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
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net importer of hydrocarbons at least through the year 2000, which should
provide an attractive 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 thousand cubic feet ('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.
4
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.
MISCELLANEOUS
OTHER ASSETS
The Company and a subsidiary, Pogo Offshore Pipeline Co., own minority
interests in three pipelines through which offshore oil production is
transported ashore. In addition, the Company owns an approximately 22% interest
in a cryogenic gas processing plant near Erath, Louisiana, which entitles it to
process up to 159,000 Mcf of gas per day. The plant is not operating at full
capacity.
SALES
The marketing of offshore oil and gas production is subject to the
availability of pipelines and other transportation, processing and refining
facilities as well as the existence of adequate markets. As a result, even if
hydrocarbons are discovered in commercial quantities, a substantial period of
time may elapse before commercial production commences. If pipeline facilities
in an area are insufficient, the Company must await the construction or
expansion of pipeline capacity before production from that area can be marketed.
The marketing of onshore oil and gas production is also subject to the
availability of pipelines, crude oil hauling and other transportation,
processing and refining facilities as well as the existence of adequate markets.
Generally, the Company's onshore domestic oil and gas production is located in
areas where commercial production of economic discoveries can be rapidly
effectuated.
Most of the Company's natural gas sales are currently made in the 'spot
market' for no more than one month at a time at then currently available prices.
Prices on the spot market fluctuate with demand. Crude oil and condensate
production is also generally sold one month at a time at the currently available
prices. Other than any futures contracts referred to in ' -- Miscellaneous;
Competition and Market Conditions,' the Company has no existing contracts that
require the delivery of fixed quantities of oil or natural gas other than on a
best efforts basis. See also 'Financial Statements and Supplementary
Data -- Note 4 to Notes to Consolidated Financial Statements and -- Unaudited
Supplementary Financial Data.'
COMPETITION AND MARKET CONDITIONS
The Company experiences competition from other oil and gas companies in all
phases of its operations, as well as competition from other energy related
industries. 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 Company's bank
credit facility. 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
5
Company's participation in price increases for the covered period, which
increases could be significant. The Company has entered into a contract with
another party for 1,000 Bbls per day of its crude oil production. The agreement
expires July 31, 1994, but may be extended through January 31, 1995 at such
party's option, for a contract price of $16.00 per barrel. At present, the
Company has no futures contracts or forward sales of natural gas in effect. When
the Company does engage in hedging activities, it may satisfy its obligations
with its own production or by the purchase (or sale) of third party production.
The Company may also cancel all delivery obligations by offsetting such
obligations with equivalent agreements, thereby effecting a purely cash
transaction.
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 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.
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. The Company
seeks to manage these risks by concentrating its international exploration
efforts in areas where the Company believes that the existing government is
stable and favorably disposed towards United States exploration and production
companies. The Company believes that the Kingdom of Thailand currently presents
favorable conditions in which to conduct international operations.
EXPLORATION AND PRODUCTION DATA
In the following data 'gross' refers to the total acres or wells in which
the Company has an interest and 'net' refers to gross acres or wells multiplied
by the percentage working interest owned by the Company.
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ACREAGE
The following table shows the Company's interest in developed and
undeveloped oil and gas acreage as of December 31, 1993:
DEVELOPED ACREAGE (A) UNDEVELOPED ACREAGE (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.
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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.
1993 1992 1991
SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY
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
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.
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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. See '-- Miscellaneous; Competition and
Market Conditions and Sales.'
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.
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 Company Petroleum Engineers, Houston, Texas ('Ryder
Scott') in accordance with criteria prescribed by the Securities and Exchange
Commission (the 'Commission'). The summary report of Ryder Scott on the reserve
estimates, which includes definitions and assumptions, is set forth as an
exhibit to this Annual Report and definitions, assumptions and descriptions of
methodology following the tables are based upon the Ryder Scott report.
AS OF DECEMBER 31,
1993 1992 1991
Total Proved Reserves:
Oil, condensate, and natural gas
liquids (thousands
of Bbls) --
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
(TABLE CONTINUED ON FOLLOWING PAGE)
9
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 (thousands
of Bbls)----------------------------------------------- 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.
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing conditions. Reservoirs are considered proved if
economic producibility is supported by actual production or formation tests. In
certain instances, proved reserves are assigned on the basis of a combination of
core analysis and electrical and other type logs which indicate the reservoirs
are analogous to reservoirs in the same field which are producing or have
demonstrated the ability to produce on a formation test. The area of a reservoir
considered proved includes (i) that portion delineated by drilling and defined
by fluid contacts, if any, and (ii) the adjoining portions not yet drilled that
can be reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir. Proved reserves are estimates of hydrocarbons to be
recovered from a given date forward. They may be revised as hydrocarbons are
produced and additional data becomes available. Proved natural gas reserves are
comprised of nonassociated, associated and dissolved gas. An appropriate
reduction in gas reserves has been made for the expected removal of liquids, for
lease and plant fuel and the exclusion of non-hydrocarbon gases if they occur in
significant quantities and are removed prior to sale. Reserves that can be
produced economically through the application of established improved recovery
techniques are included in the proved classification when these qualifications
are met: (i) successful testing by a pilot project or the operation of an
installed program in the reservoir provides support for the engineering analysis
on which the project or program was based, and (ii) it is reasonably certain the
project will proceed. Improved recovery includes all methods for supplementing
natural reservoir forces and energy, or otherwise increasing ultimate recovery
from a reservoir, including, (a) pressure maintenance, (b) cycling, and (c)
secondary recovery in its original sense. Improved recovery also includes the
enhanced recovery methods of thermal, chemical flooding, and the use of miscible
and immiscible displacement fluids. Estimates of proved reserves do not include
crude oil, condensate, natural gas, or natural gas liquids being held in
underground storage. Depending on the status of development, these proved
reserves are further subdivided into:
10
(i) 'developed reserves' which are those proved reserves reasonably
expected to be recovered through existing wells with existing equipment and
operating methods, including (a) 'developed producing reserves' which are
those proved developed reserves reasonably expected to be produced from
existing completion intervals now open for production in existing wells, and
(b) 'developed non-producing reserves' which are those proved developed
reserves which exist behind casing of existing wells which are reasonably
expected to be produced through these wells in the predictable future where
the cost of making such hydrocarbons available for production should be
relatively small compared to the cost of new wells; and
(ii) 'undeveloped reserves' which are those proved reserves reasonably
expected to be recovered from new wells on undrilled acreage, from existing
wells where a relatively large expenditure is required and from acreage for
which an application of fluid injection or other improved recovery technique
is contemplated where the technique has been proved effective by actual
tests in the area in the same reservoir. Reserves from undrilled acreage are
limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units are included only where it can be demonstrated with
reasonable certainty that there is continuity of production from the
existing productive formation.
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 which will definitely be developed
have been included in the proved undeveloped category.
The Company has interests in certain tracts which may have substantial
additional hydrocarbon quantities which cannot be classified as proved and are
not included herein. The Company has active exploratory and development drilling
programs which in all likelihood will result in the reclassification of
significant additional quantities to the proved category.
In computing future revenues from gas reserves attributable to the Company's
interests, prices in effect at December 31, 1993 were used, including current
market prices, contract prices and fixed and determinable price escalations
where applicable. In accordance with Commission guidelines, the future gas
prices that were used make no allowances for seasonal variations in gas prices
which are likely to cause future yearly average gas prices to be somewhat lower
than December gas prices. For gas sold under contract, the contract gas price
including fixed and determinable escalations, exclusive of inflation
adjustments, was used until the contract expires and then was adjusted to the
current market price for the area and held at this adjusted price to depletion
of the reserves. In computing future revenues from liquids attributable to the
Company's interest, prices in effect at December 31, 1993 were used and these
prices were held constant to depletion of the properties.
The estimates of future net revenue from the Company's domestic and Thailand
properties are based on existing law where the properties are located and are
calculated in accordance with Commission guidelines. Operating costs for the
leases and wells include only those costs directly applicable to the leases or
wells. When applicable, the operating costs include a portion of general and
administrative costs allocated directly to the leases and wells under terms of
operating agreements. Development costs are based on authorization for
expenditure for the proposed work or actual costs for similar projects. The
current operating and development costs were held constant throughout the life
of the properties. For properties located onshore, the estimates of future net
revenues and the present value thereof do not consider the salvage value of the
lease equipment or the abandonment cost of the lease since both are relatively
insignificant and tend to offset each other. The estimated net cost of
abandonment after salvage was considered for offshore properties where such
costs net of salvage are significant.
No deduction was made for indirect costs such as general and administrative
and overhead expenses, loan repayments, interest expenses, and exploration and
development prepayments. The accumulated gas production imbalances have been
taken into account.
11
Production data used to arrive at the estimates set forth above includes
estimated production for the last few months of 1993.
The future production rates from reservoirs now on production may be more or
less than estimated because of, among other reasons, mechanical breakdowns and
changes in market demand or allowables set by regulatory bodies. Properties
which are not currently producing may start producing earlier or later than
anticipated in the estimates of future production rates.
The future prices received by the Company for the sales of its production
may be higher or lower than the prices used in calculating the estimates of
future net revenues and the present value thereof as set forth herein, and the
operating costs and other costs relating to such production may also increase or
decrease from existing levels; however, such possible changes in prices and
costs were, in accordance with rules adopted by the Commission, omitted from
consideration in arriving at such estimates.
There are numerous uncertainties in estimating the quantity of proved
reserves and in projecting the future rates of production and timing of
development expenditures. Oil and gas reserve engineering must be recognized as
a subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact way, and estimates of other engineers might
differ materially from those of Ryder Scott, the Company's reserve engineers.
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 estimate may
justify revision of such estimate, and as a general rule, reserve estimates
based upon volumetric analysis are often different from the quantities of oil
and gas that are ultimately recovered.
The Company is periodically required to file estimates of its oil and gas
reserve data with various governmental regulatory authorities and agencies,
including the Federal Energy Regulatory Commission ('FERC') and the Federal
Trade Commission. In addition, estimates are from time to time furnished to
governmental agencies in connection with specific matters pending before such
agencies. The basis for reporting reserves to these agencies, in some cases, is
not comparable to that furnished above because of the nature of the various
reports required. The major differences include differences in the time as of
which such estimates are made, differences in the definition of reserves,
requirements to report in some instances on a gross, net or total operator basis
and requirements to report in terms of smaller geographical units. No estimates
by the Company of its total proved net oil and gas reserves, however, were filed
with or included in reports to any federal authority or agency other than the
Commission during 1993.
GOVERNMENT REGULATION
The Company's operations are affected from time to time in varying degrees
by political developments and federal and state laws and regulations. Rates of
production of oil and gas have for many years been subject to federal and state
conservation laws and regulations, and the petroleum industry has been subject
to federal and state tax laws dealing specifically with it.
FEDERAL INCOME TAX
The Company's operations are significantly affected by certain provisions of
the federal income tax laws applicable to the petroleum industry. The principal
provisions affecting the Company are those that permit the Company, subject to
certain limitations, to deduct as incurred, rather than to capitalize and
amortize, its domestic 'intangible drilling and development costs' and to claim
depletion on a portion of its domestic oil and gas properties based on 15% of
its oil and gas gross income from such properties (up to an aggregate of 1,000
Bbls per day of domestic crude oil and/or equivalent units of domestic natural
gas) even though the Company has little or no basis in such properties. Under
certain circumstances, however, a portion of such intangible drilling and
development costs and the percentage depletion allowed in excess of basis will
be tax preference items that
12
will be taken into account in computing the Company's alternative minimum tax.
See 'Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources.'
ENVIRONMENTAL MATTERS
Offshore oil and gas operations are subject to extensive federal and state
regulation and, with respect to federal leases, to interruption or termination
by governmental authorities on account of environmental and other considerations
including the Comprehensive Environmental Response Compensation and Liability
Act ('CERCLA') also known as the 'Superfund Law.' Regulations of the Department
of the Interior currently impose absolute liability upon the lessee under a
federal lease for the costs of clean-up of pollution resulting from a lessee's
operations, and such lessee may also be subject to possible legal liability for
pollution damages. The Company maintains insurance against costs of clean-up
operations, but is not fully insured against all such risks. A serious incident
of pollution may, as it has in the past, also result in the Department of the
Interior requiring lessees under federal leases to suspend or cease operation in
the affected area.
The Oil Pollution Act of 1990 (the 'OPA') and regulations thereunder impose
a variety of regulations on 'responsible parties' (which include owners and
operators of offshore facilities) related to the prevention of oil spills and
liability for damages resulting from such spills in United States waters. In
addition it imposes ongoing requirements on responsible parties, including proof
of financial responsibility to cover at least some costs in a potential spill.
On August 25, 1993, the Mineral Management Service (the 'MMS') published an
advance notice of its intention to adopt a rule under OPA that would require
owners and operators of offshore oil and gas facilities to establish
$150,000,000 in financial responsibility. Under the proposed rule, financial
responsibility could be established through insurance, guaranty, indemnity,
surety bond, letter of credit, qualification as a self-insurer or a combination
thereof. There is substantial uncertainty as to whether insurance companies or
underwriters will be willing to provide coverage under OPA because the statute
provides for direct lawsuits against insurers who provide financial
responsibility coverage, and most insurers have strongly protested this
requirement. The financial tests or other criteria that will be used to judge
self-insurance are also uncertain. The Company cannot predict the final form of
the financial responsibility rule that will be adopted by the MMS, but such rule
has the potential to result in the imposition of substantial additional annual
costs on the Company or otherwise materially adversely affect the Company. The
impact of the rule should not be any more adverse to the Company than it will be
to other similar owners or operators in the Gulf of Mexico.
The operators of the Company's properties have numerous applications pending
before the Environmental Protection Agency (the 'EPA') for National Pollution
Discharge Elimination System water discharge permits with respect to offshore
drilling and production operations. The issue generally involved is whether
effluent discharges from each facility or installation comply with the
applicable federal regulations. See 'Legal Proceedings' for a discussion of
other environmental matters.
The Company's onshore operations are subject to numerous United States
federal, state, and local laws and regulations controlling the discharge of
materials into the environment or otherwise relating to the protection of the
environment including CERCLA. Such regulations, among other things, impose
absolute liability on the lessee under a lease for the cost of clean-up of
pollution resulting from a lessee's operations, subject the lessee to liability
for pollution damages, may require suspension or cessation of operations in
affected areas, and impose restrictions on the injection of liquids into
subsurface aquifers that may contaminate groundwater. In addition, the recent
trend toward stricter standards in environmental legislation and regulation may
continue. For instance, legislation has been proposed in Congress from time to
time that would reclassify certain oil and gas production wastes as 'hazardous
wastes' which would make the reclassified exploration and production wastes
subject to much more stringent handling, disposal and clean-up requirements. If
such legislation were to be enacted, it could have a significant impact on the
operating costs of the
13
Company, as well as the oil and gas industry in general. State initiatives to
further regulate the disposal of oil and gas wastes are also pending in certain
states, and these various initiatives could have a similar impact on the
Company.
During 1993, the Company incurred capital expenditures of approximately
$750,000 for environmental control facilities, including two salt water disposal
facilities, one each in its Red Tank and Sand Dunes fields in New Mexico. The
Company currently has budgeted $987,000 for environmental control facilities,
including three salt water disposal facilities during 1994.
OTHER LAWS AND REGULATIONS
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, prevention, 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.
OTHER REGULATIONS AND LEGISLATIVE PROPOSALS
Prior to January 1, 1993 various aspects of the Company's natural gas
operations were subject to regulations by the FERC under the Natural Gas Act of
1938 (the 'NGA') and the Natural Gas Policy Act of 1978 (the 'NGPA') with
respect to 'first sales' of natural gas, including price controls and
certificate and abandonment authority regulations. However, as a result of the
enactment of the Natural Gas Decontrol Act of 1989, the remaining 'first sales'
restrictions imposed by the NGA and the NGPA terminated on January 1, 1993.
Commencing in late 1985, the FERC has issued a series of orders that have
had a major impact on natural gas pipeline operations, services and rates and
thus have significantly altered the marketing and price of natural gas. Order
636, issued in April 1992, requires each pipeline company, among other things,
to 'unbundle' its traditional wholesale services and create and make available
on an open and nondiscriminatory basis numerous constituent services (such as
gathering services, storage services, firm and interruptible transportation
services, and stand-by sales services) and to adopt a new rate making
methodology to determine appropriate rates for those services. To the extent the
pipeline company or its sales affiliate makes gas sales as a merchant in the
future, it will do so in direct competition with all other sellers pursuant to
private contracts; however, pipeline companies and their affiliates are not
required to remain 'merchants' of gas, and some of the interstate pipelines
companies have or will become 'transporters only.' In subsequent orders, the
FERC largely affirmed Order 636 and denied a stay of the implementation of the
new rules pending judicial review. In addition, the FERC has generally accepted
rate filings implementing Order 636 on essentially every interstate pipeline as
of the end of 1993. Order 636, as well as the FERC orders approving the
individual pipeline rate filings implementing Order 636, are the subject of
numerous appeals to the United States Courts of Appeals. The Company cannot
predict whether the latest orders will be affirmed on appeal or what the effects
will be on its business.
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.
ITEM 2. PROPERTIES.
The information appearing in Item 1 of this Annual Report is incorporated
herein by reference.
14
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.
SIGNIFICANT PRODUCING AREAS
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) %
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
DISCOUNTED
FUTURE
NET
REVENUES(B)
%
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%.
Set forth below are descriptions of certain of the Company's significant
producing areas. Contained in certain of these descriptions and elsewhere in
this Annual Report 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 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
15
Block 330 field has produced approximately 619 billion cubic feet ('Bcf') of
natural gas and 122 million barrels ('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 Block 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 in this field is currently being considered 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 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
16
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 33% to 98%; 43 wells in the
Livingston Ridge field where the Company's working interest ranges from 41% to
83%; and 8 wells in the Red Tank field where the Company's working interest
ranges from 89% 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.
17
DOMESTIC OFFSHORE PROPERTIES --
The following is a listing of Pogo's domestic offshore properties as of
December 31, 1993.
POGO EXPLORATORY DEVELOPMENT
WORKING WELLS PLATFORMS WELLS
INTEREST DRILLED OR SET OR DRILLED OR DATE
BLOCK % DRILLING ANNOUNCED DRILLING ACQUIRED
OFFSHORE TEXAS -- FEDERAL
Mustang Island
A-3 20.0 8-89
Matagorda Island
A-4 27.0 3 1 2 8-83
670 30.7 1 1 2 8-83
Brazos
A-104 10.8 1 1 8-89
Galveston
225 18.0 8-89
325 20.0 8-91
High Island/South Addition
A-515 25.0 2 1 11-79
High Island/East Addition/South Extension
A-323 1.8 4 1 17 6-73
A-325 9.9 7 2 9 6-73
A-355 13.2 1 1 5 5-74
A-356 20.0 1 1 4 5-74
TOTAL TEXAS 20 9 39
OFFSHORE LOUISIANA -- FEDERAL
West Cameron
63 20.0 3-91
97 20.0 3-90
196 (A) 3 1 2 5-83
202 39.3 3 1 2 11-82
252 80.0 1 Share 253 Platform 2 11-82
253 80.0 1 1 6 6-77
310 20.0 3-91
352 15.0 1 1 8 10-74
385 20.0 3-90
532 4.0 5 Share 533 Platform 3 12-72
533 4.0 2(B) 2 7 12-72
609 16.0 1 1 7 10-74
East Cameron
201 20.0 1 1 3-90
270 30.0 3 2 30 12-70
334 42.0 5(B) 1 10 12-70
335 42.0 3 2 23 6-73
(TABLE CONTINUED ON FOLLOWING PAGE)
DATE OR
LEASE ANTICIPATED
EFFECTIVE DATE OF
DATE PRODUCTION
OFFSHORE TEXAS -- FEDERAL
Mustang Island
11-1-89
Matagorda Island
10-1-83 9-89
10-1-83 10-89
Brazos
10-1-89 6-90
Galveston
10-1-89
11-1-91
High Island/South Addition
1-1-80 11-84
High Island/East Addition/South Exten
8-1-73 6-78
8-1-73 8-81
7-1-74 8-80
7-1-74 7-80
TOTAL TEXAS
OFFSHORE LOUISIANA -- FEDERAL
West Cameron
5-1-91
5-1-90
7-1-83 12-90
1-1-83 8-85
1-1-83 8-84
8-1-77 7-84
7-1-91
12-1-74 8-79
6-190
2-1-73 9-76
2-1-73 9-76
12-1-74 7-78
East Cameron
5-1-90 1994
1-1-71 2-73
2-1-71 8-77
8-1-73 9-77
(A) Block farmed out -- Over-riding Royalty Interest only
(B) Includes offset contribution well
18
POGO EXPLORATORY DEVELOPMENT
WORKING WELLS PLATFORMS WELLS
INTEREST DRILLED OR SET OR DRILLED OR DATE
BLOCK % DRILLING ANNOUNCED DRILLING ACQUIRED
Vermilion
175 70.0 1 1 5-91
188 70.0 Share 175 Platform 5-91
227 16.4 1 3-89
South Marsh Island
125 16.0 3 1 8 10-74
127 16.0 Share 128 Platform 3 10-74
128 16.0 6 3 62 3-74
160 25.0 2 1 4 9-80
188 25.0 5-92
Eugene Island
101 20.0 3-91
102 20.0 3-91
211 33.3 Share 212 Platform 3 5-83
212 33.3 1 1 3 5-83
256 69.2 5 1 7 12-70
261 66.7 2 1 15 10-74
295* 20.0 /100.0 7(B) 2 29 12-70
312 4.0 5 Share 333 Platform 7 3-74
318 20.0 1 3-91
330 35.0 (D) 10(B) 4 89 12-70
333 4.0 3 2 22 12-72
337 37.5 3 1 8 2-76
Ship Shoal
175 33.3 Share EI 212 Platform 2 5-83
240 30.0 1 1 3-89
255 30.0 3-89
256 30.0 3-90
South Timbalier
109 26.7 3-89
198 25.0 2 1 4 5-85
+214 25.0 (C) 1 Share 198 Platform 1 5-85
287 20.0 1 3-89
West Delta
59 20.0 3-90
South Pass
+33 6.0 (C) Share 49 Platform 2 10-74
49 4.8 5(B) 1 19 9-72
50 50.0 1 Share 49 Platform 7-93
+57 12.0 Share 57/58 Platform 3 11-76
+78 9.0 5 1 12 9-72
Mississippi Canyon
63 6.0 2 1 5 5-75
(TABLE CONTINUED ON FOLLOWING PAGE)
DATE OR
LEASE ANTICIPATED
EFFECTIVE DATE OF
DATE PRODUCTION
Vermilion
9-1-85 12-91
6-1-89
5-1-89
South Marsh Island
12-1-74 7-77
12-1-74 7-77
5-1-74 7-77
11-1-80 2-84
9-1-92
Eugene Island
5-1-91
5-1-91
7-1-83 1-87
7-1-83 1-87
2-1-71 10-79
12-1-74 10-79
2-1-71 2-73
5-1-74 7-77
6-1-91
1-1-71 4-73
2-1-73 7-77
3-1-76 6-85
Ship Shoal
7-1-83 7-88
6-1-89 1-95
7-1-89
5-1-90
South Timbalier
6-1-89
9-1-85 8-90
9-1-85 8-90
5-1-89
West Delta
6-1-90
South Pass
12-1-74 2-83
11-1-72 10-80
8-1-88 12-93
1-1-77 7-82
10-1-72 4-81
Mississippi Canyon
7-1-75 6-84
(B) Includes offset contribution well
(C) Block farmed in
(D) Pogo owns 30% in a small portion of the property
* Pogo owns 20% in rights below 3,000 feet and 100% in rights at 3,000 feet
and above in certain portions of the block. See -- 'Principal Properties;
Eugene Island'
(+) Represents portion of block
19
POGO EXPLORATORY DEVELOPMENT
WORKING WELLS PLATFORMS WELLS
INTEREST DRILLED OR SET OR DRILLED OR DATE
BLOCK % DRILLING ANNOUNCED DRILLING ACQUIRED
Main Pass
+30 25.0 (E) 2 1 8(F) 10-81
37 25.0 4 1 5 7-79
61 24.0 1 3-90
+72 14.0 1 Share 73 Platform 2 5-75
+72/74 14.0 4 2 43 11-76
73 14.0 4 1 16 10-74
123 30.0 2 1 3-90
131 33.0 5-92
TOTAL LOUISIANA 115 42 482
STATE LEASES
Offshore Louisiana
South Pass
+57/58 12.0 3 1 13 5-74
Main Pass
31 50.0 1 1 1 3-85
Breton Sound
2 100.0 2(F) 1 1 4-80
23 22.5 1 1 1 9-78
24 22.5 1 1 1 9-78
North Lighthouse Point
S/L340 50.0 1 3 5-84
TOTAL STATE LEASES 9 5 20
TOTAL DOMESTIC OFFSHORE 144 56 541
DATE OR
LEASE ANTICIPATED
EFFECTIVE DATE OF
DATE PRODUCTION
Main Pass
12-1-81 11-87
10-1-79 7-82
7-1-90
7-1-75 8-79
1-1-77 8-79
12-1-74 8-79
5-1-90 1-95
9-1-92
TOTAL LOUISIANA
STATE LEASES
Offshore Louisiana
South Pass
5-13-74 7-82
Main Pass
3-18-85 2-90
Breton Sound
9-15-80 8-87
9-18-78 7-84
9-18-78 7-84
North Lighthouse Point
5-1-84 10-84
TOTAL STATE LEASES
TOTAL DOMESTIC OFFSHORE
(E) Portion of block farmed out
(F) Includes one farmout well
(+) Represents portion of block
20
ITEM 3. LEGAL PROCEEDINGS.
In 1989, a large number of exploration and production companies, including
the Company, were circularized with Special Notice Letters in accordance with
CERCLA from the EPA regarding a particular waste disposal site in Louisiana
known as the 'Gulf Coast Vacuum Site' utilized by a trucking company. The EPA
subsequently developed a list based on its investigation showing the Company
bearing an approximate 1.4% responsibility for this site based on the trucking
company's shipping records. The Company utilized the trucking company to dispose
of salt water produced from a well in which the Company had an interest. The
Company, however, believes that none of this salt water was delivered to the
Gulf Coast Vacuum Site. In any event, the Company believes that the trucking
company shipped only oilfield waste for the Company which is exempt pursuant to
CERCLA and, further, that such shipments, if any, were sent to a properly
permitted waste disposal site. The Company has learned that the EPA has recently
entered a consent decree, the details of which have not been made public, with
parties that are believed to be responsible for a majority of the disposal
occurring at the site.
The Company is a party to various other legal proceedings consisting of
routine litigation incidental to its businesses, but believes that any potential
liabilities resulting from these proceedings are adequately covered by insurance
or are otherwise immaterial at this time.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.
Not Applicable.
ITEM S-K 401(B). EXECUTIVE OFFICERS OF REGISTRANT.
Executive officers of the Company are appointed annually to serve for the
ensuing year or until their successors have been elected or appointed. The
executive officers of the Company, their age as of February 1, 1994, and the
year each was elected to his present position are as follows:
YEAR
EXECUTIVE OFFICER EXECUTIVE OFFICE AGE ELECTED
Paul G. Van Wagenen----------------------- Chairman of the Board, President 48 1991
and Chief Executive Officer
Kenneth R. Good--------------------------- Senior Vice President -- 56 1991
Land and Budgets
D. Stephen Slack-------------------------- Senior Vice President, Chief 44 1988
Financial Officer and Treasurer
Stuart P. Burbach------------------------- Vice President and 41 1991
Offshore Division Manager
Jerry A. Cooper--------------------------- Vice President and 45 1990
Western Division Manager
Harvey L. Gold---------------------------- Vice President -- Engineering 58 1988
Thomas E. Hart---------------------------- Vice President and Controller 51 1988
R. Phillip Laney-------------------------- Vice President and 53 1991
International Division Manager
John O. McCoy, Jr.------------------------ Vice President and 42 1989
Chief Administrative Officer
J. D. McGregor---------------------------- Vice President -- Sales 49 1988
Sammie M. Shaw---------------------------- Vice President -- Operations 62 1992
Ronald B. Manning------------------------- Corporate Secretary and 40 1990
Associate General Counsel
Prior to assuming their present positions with the Company, the business
experience of each executive officer for more than the last five years was as
follows: Mr. Van Wagenen was President and
21
Chief Operating Officer of the Company since 1990, Senior Vice President and
General Counsel of the Company since 1986, Vice President and General Counsel of
the Company since 1982, and General Counsel of the Company since 1979; Mr. Good
was Vice President - Land of the Company since 1988 and Chief Landman of the
Company since 1977; Mr. Slack was Regional Manager of Chemical Bank of New
York's Southwest Energy and Minerals Division since 1982; Mr. Burbach was Vice
President of Norfolk Holding Inc. since 1986 and Exploration Manager for
Tricentrol Ltd. Canada and Tricentrol U.S. since 1981; Mr. Cooper was a Division
Landman for the Company since 1983 and a Landman for the Company since 1979; Mr.
Gold was Manager of Reservoir Engineering for the Company since 1977; Mr. Hart
was Controller for the Company since 1977; Mr. Laney was International
Exploration Manager for the Company since 1983 and Exploration Coordinator for
the Gulf Coast Division of the Company since 1977; Mr. McCoy was Director of
Personnel and Administration for the Company since 1978; Mr. McGregor was
Manager of Hydrocarbon Sales and Contracts for the Company since 1981; Mr. Shaw
was Operations Manager for the Company since 1981; Mr. Manning was an Associate
General Counsel for the Company since 1989 and prior thereto was an attorney
with the Federal Bureau of Investigation, and Chevron U.S.A., and Assistant to
the General Counsel of Primary Fuels, Inc.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER
MATTERS.
The following table shows the range of low and high sales prices of the
Company's Common Stock (the '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.
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.
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.
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
As of February 10, 1994, there were 4,216 holders of record of the Company's
Common Stock.
22
ITEM 6. SELECTED FINANCIAL DATA.
FOR THE YEAR ENDED DECEMBER 31,
1993 1992 1991 1990 1989
FINANCIAL DATA
(Expressed in thousands, except per
share 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 -- -- 22,499 --
Gains (losses) on sales---------- 679 1,702 44 (98) (173)
Total------------------------ $ 139,554 $ 140,830 $ 124,469 $ 154,820 $ 120,947
Income before extraordinary item----- $ 25,061 $ 18,495 $ 10,322 $ 44,036 $ 2,638
Extraordinary gains on purchase of
debt------------------------------- -- -- 1,336 -- --
Net income--------------------------- $ 25,061 $ 18,495 $ 11,658 $ 44,036 $ 2,638
Per share data:
Primary and fully diluted
earnings:
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
Price range of common stock:
High------------------------- $ 21.00 $ 13.88 $ 8.25 $ 10.13 $ 10.25
Low-------------------------- $ 9.75 $ 5.13 $ 4.63 $ 5.75 $ 4.00
Weighted average number of common and
common equivalent shares
outstanding------------------------ 32,860 27,929 27,611 26,029 24,157
Long-term debt at year end----------- $ 134,539 $ 129,260 $ 184,260 $ 217,000 $ 264,000
Production payment obligation at year
end-------------------------------- $ -- $ 24,854 $ 45,475 $ 46,893 $ 51,352
Shareholders' equity (deficit) at
year end--------------------------- $ 33,803 $ 5,648 $ (56,636) $ (68,429) $ (132,557)
Total assets at year end------------- $ 239,774 $ 206,347 $ 213,772 $ 244,226 $ 227,508
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 (Bbl. 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 (Bbl. per
day)
Leasehold ownership---------- 1,538 1,037 609 593 804
Plant ownership-------------- 140 144 54 104 144
Price (per Bbl.)--------- $ 11.90 $ 13.50 $ 14.21 $ 13.75 $ 10.16
CAPITAL EXPENDITURES(A)
(Expressed in thousands)
Oil and gas:
Domestic Offshore:
Exploration---------------------- $ 4,600 $ 1,700 $ 1,600 $ 2,900 $ 4,700
Development---------------------- 33,700 5,500 23,600 24,900 15,900
Purchase of reserves------------- -- 8,900 5,100 -- --
Domestic Onshore:
Exploration---------------------- 5,200 4,900 4,700 2,300 1,900
Development---------------------- 24,300 15,600 13,900 8,100 2,100
International Exploration---------- 4,600 1,400 -- -- --
Total oil and gas---------------- $ 72,400 $ 38,000 $ 48,900 $ 38,200 $ 24,600
Other-------------------------------- 200 600 2,400 -- 300
TOTAL---------------------------- $ 72,600 $ 38,600 $ 51,300 $ 38,200 $ 24,900
(a) Prior years have been restated to include interest capitalized and to
reflect non oil and gas (Other) capital expenditures as a separate category.
23
ITEM 7. 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 'Convertible Subordinated 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 'Item 8. Financial Statements and Supplementary Data.'
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 the Company
then began recovering again, averaging $1.75 per Mcf for 1992 and $1.98 per Mcf
for
24
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. See 'Business
-- Miscellaneous; Competition and Market Conditions.'
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 -- 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 barrel in 1993 compared
to $20.17 per barrel in 1992 and $20.98 per barrel 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 barrel
that the Company received for its production began to decline until, by December
1993, the average price per barrel for crude oil and condensate that the Company
received for its production averaged only $13.39 per barrel. 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. See 'Business
-- Miscellaneous; Competition and Market Conditions.'
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.
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.
25
'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 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 the Company's Convertible Subordinated 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 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.
26
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 above) and, to a
lesser extent, an increase in the composite DD&A rate. See 'Financial Statements
and Supplementary Data -- 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 an annual sinking fund requirement of $4,000,000 on the Company's 10.25%
Convertible Subordinated Notes due 1999 (the 'Convertible Subordinated Notes')
and ongoing operating, general and administrative, income tax,
27
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 are anticipated from increased taxable income,
increased tax rates and the utilization in 1993 and prior years of available tax
credits and tax loss carryforwards. 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.
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 'Market for
the Registrant's Common Stock and Related Security Holder Matters.' 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 Convertible Subordinated Notes was
$24,000,000 as of December 31, 1993. The Convertible Subordinated 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. In
addition, the Company is entitled to make optional sinking fund payments at par
in amounts up to $4,000,000 per year, with maximum optional sinking fund
payments at par of $12,000,000. The outstanding principal amount of the
Convertible Subordinated Debentures was $43,539,000 as of December 31, 1993. The
Convertible Subordinated 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 Convertible Subordinated
Debentures which it may tender in satisfaction of future sinking fund
requirements. See 'Financial Statements and Supplementary Data -- 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.
28
ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1993
POGO PRODUCING COMPANY AND SUBSIDIARIES
HOUSTON, TEXAS
29
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.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in Item 14(a)-2 are
presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the audit of
the basic financial statements and, in our opinion, fairly state in all material
respects the financial data required to be set forth therein in relation to the
basic financial statements taken as a whole.
ARTHUR ANDERSEN & CO.
Houston, Texas
February 8, 1994
30
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.
31
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.
32
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.
33
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
SHARE-
RETAINED HOLDERS'
SHARES COMMON ADDITIONAL EARNINGS TREASURY EQUITY
OUTSTANDING STOCK CAPITAL (DEFICIT) STOCK (DEFICIT)
(DOLLARS EXPRESSED IN THOUSANDS)
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
The accompanying notes to consolidated financial statements are an integral part
hereof.
34
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.
35
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%
36
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
37
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 $ -- $ --
38
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)
39
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.
ANNUAL DEFERRED BENEFITS
EXPENSE COSTS OBLIGATION
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)
40
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)
41
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
42
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 this Annual
Report and includes definitions and assumptions that served as the basis for the
discussion under the caption 'Item 1, Business -- Exploration and Production
Data; 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
43
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.
44
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.
YEAR ENDED DECEMBER 31, 1993
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
(EXPRESSED IN THOUSANDS)
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
45
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- (CONTINUED)
YEAR ENDED DECEMBER 31,
1992 1991
(EXPRESSED IN THOUSANDS)
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
46
QUARTERLY RESULTS
Summaries of Pogo's results of operations by quarter for the years 1993 and
1992 are as follows:
QUARTER ENDED
MAR. 31 JUNE 30 SEPT. 30 DEC. 31
(EXPRESSED IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
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.
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
Not applicable.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information regarding nominees and continuing directors in the Company's
definitive Proxy Statement for its annual meeting to be held on April 26, 1994,
to be filed within 120 days of December 31, 1993 pursuant to Regulation 14A
under the Securities Exchange Act of 1934, as amended (the Company's '1994 Proxy
Statement'), is incorporated herein by reference. See also Item S-K 401(b)
appearing in Part I of this Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION.
The information regarding executive compensation in the Company's 1994 Proxy
Statement, other than the information regarding the Compensation Committee
Report on Executive Compensation, is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information regarding ownership of the Company securities by management
and certain other beneficial owners in the Company's 1994 Proxy Statement is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information regarding certain relationships and related transactions
with management in the Company's 1994 Proxy Statement is incorporated herein by
reference.
47
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A) FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, FINANCIAL STATEMENT
SCHEDULES AND EXHIBITS
PAGE
1. Financial Statements and Supplementary Data:
Report of Independent Public Accountants----------------- 30
Consolidated statements of income------------------------ 31
Consolidated balance sheets------------------------------ 32
Consolidated statements of cash flows-------------------- 33
Consolidated statements of shareholders' equity---------- 34
Notes to consolidated financial statements--------------- 35
2. Financial Statement Schedules:
V --Property and Equipment for the Years Ended
December 31, 1993, 1992 and 1991------------------- S-1
VI --Reserves for Depreciation, Depletion and
Amortization of Property and Equipment For the
Years Ended December 31, 1993, 1992 and 1991------- S-1
X --Supplementary Income Statement Information For
the Years Ended December 31, 1993, 1992 and 1991--- S-2
Schedules other than those listed above are omitted
because they are not required, are not applicable
or the information required has been included
elsewhere herein.
3. Exhibits:
*3(a ) -- Restated Certificate of Incorporation
of Pogo Producing Company. (Exhibit
3(a), Annual Report on Form 10-K for
the year ended December 31, 1987,
File No. 0-5468).
*3(a)(1) -- Certificate of Designation,
Preferences and Rights of Preferred
Stock of Pogo Producing Company,
dated March 25, 1987. (Exhibit
3(a)(1), Annual Report on Form 10-K
for the year ended December 31, 1987,
File No. 0-5468).
*3(b) -- Bylaws of Pogo Producing Company, as
amended and restated through July 24,
1990. (Exhibit 3(a), Quarterly Report
on Form 10-Q for the quarter ended
June 30, 1990, File No. 0-5468).
*4(a)(i) -- Credit Agreement dated as of
September 23, 1992, among Pogo
Producing Company, the lenders party
thereto, Bank of Montreal as Agent,
and Banque Paribas as Co-Agent.
(Exhibit 10(a), Quarterly Report on
Form 10-Q for the quarter ended
September 30, 1992, File No. 1-7792).
4(a)(ii) -- First Amendment dated as of September
30, 1992 to Credit Agreement dated as
of September 23, 1992, among Pogo
Producing Company, the lenders party
thereto, Bank of Montreal as Agent,
and Banque Paribas as Co-Agent.
4(a)(iii) -- Second Amendment dated as of December
31, 1993 to Credit Agreement dated as
of September 23, 1992, among Pogo
Producing Company, the lenders party
thereto, Bank of Montreal as Agent,
and Banque Paribas as Co-Agent.
48
*4(b) -- Indenture dated as of October 15,
1980 to Chemical Bank, as Trustee.
(Exhibit 4, File No. 2-69428).
The Company agrees to furnish to the
Commission upon request a copy of any
agreement defining the rights of
holders of long-term debt of the
Company and all its subsidiaries for
which consolidated or unconsolidated
financial statements are required to
be filed under which the total amount
of securities authorized does not
exceed 10% of the total assets of the
Company and its subsidiaries on a
consolidated basis.
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
(comprising Exhibits 10(a) through 10(f)(14)(ii), inclusive)
*10(a) -- 1977 Stock Option Plan of Pogo
Producing Company, as amended as of
September 28, 1981 and July 24, 1984.
(Exhibit 10(a), Annual Report on Form
10-K for the year ended December 31,
1984, File No. 0-5468).
*10(a)(1) -- Form of Amended Nonqualified Stock
Option Agreement under 1977 Stock
Option Plan (with stock appreciation
rights and without employment
restrictions). (Exhibit 10(a)(1),
Annual Report on Form 10-K for the
year ended December 31, 1981, File
No. 0-5468).
*10(a)(2) -- Form of Amended Incentive Stock
Option Agreement under 1977 Stock
Option Plan (with stock option
appreciation rights and without
employment restrictions). (Exhibit
10(a)(2), Annual Report on Form 10-K
for the year ended December 31, 1981,
File No. 0-5468).
*10(a)(3) -- Form of Amended Nonqualified Stock
Option Agreement under 1977 Stock
Option Plan (without stock
appreciation rights and with
employment restrictions). (Exhibit
10(a)(3), Annual Report on Form 10-K
for the year ended December 31, 1981,
File No. 0-5468).
*10(a)(4) -- Form of Amended Incentive Stock
Option Agreement under 1977 Stock
Option Plan (without stock option
appreciation rights and with
employment restrictions). (Exhibit
10(a)(4), Annual Report on Form 10-K
for the year ended December 31, 1981,
File No. 0-5468).
*10(a)(5) -- Form of Amended Nonqualified Stock
Option Agreement under 1977 Stock
Option Plan (with stock appreciation
rights and with employment
restrictions). (Exhibit 10(a)(5),
Annual Report on Form 10-K for the
year ended December 31, 1981, File
No. 0-5468).
*10(a)(6) -- Form of Amended Incentive Stock
Option Agreement under 1977 Stock
Option Plan (with stock option
appreciation rights and with
employment restrictions). (Exhibit
10(a)(6), Annual Report on Form 10-K
for the year ended December 31, 1981,
File No. 0-5468).
*10(a)(7) -- Form of Amended Nonqualified Stock
Option Agreement under 1977 Stock
Option Plan (without stock
appreciation rights and without
employment restrictions). (Exhibit
10(a)(7), Annual Report on Form 10-K
for the year ended December 31, 1981,
File No. 0-5468).
*10(a)(8) -- Form of Amended Incentive Stock
Option Agreement under 1977 Stock
Option Plan (without stock option
appreciation rights and without
employment restrictions). (Exhibit
10(a)(8), Annual Report on Form 10-K
for the year ended December 31, 1981,
File No. 0-5468).
*10(b) -- 1981 Stock Option Plan of Pogo
Producing Company, as amended as of
July 24, 1984. (Exhibit 10(b), Annual
Report on Form 10-K for the year
ended December 31, 1984, File No.
0-5468).
*10(b)(1) -- Form of Stock Option Agreement under
1981 Nonqualified Stock Option Plan
(with stock appreciation rights).
(Exhibit 10(b)(1), Annual Report on
Form 10-K for the year ended December
31, 1981, File No. 0-5468).
*10(b)(2) -- Form of Stock Option Agreement under
1981 Nonqualified Stock Option Plan
(without stock appreciation rights).
(Exhibit 10(b)(2), Annual Report on
Form 10-K for the year ended December
31, 1981, File No. 0-5468).
49
*10(c) -- 1981 Incentive and Nonqualified Stock
Option Plan of Pogo Producing Com-
pany, as amended as of July 24, 1984.
(Exhibit 10(c), Annual Report on Form
10-K for the year ended December 31,
1984, File No. 0-5468).
*10(c)(1) -- Form of Stock Option Agreement under
1981 Incentive Stock Option Plan.
(Exhibit 10(c)(1), Annual Report of
Form 10-K for the year ended December
31, 1981, File No. 0-5468).
*10(d) -- 1989 Incentive and Nonqualified Stock
Option Plan of Pogo Producing Com-
pany, as amended and restated
effective January 22, 1991. (Exhibit
10(d), Annual Report on Form 10-K for
the year ended December 31, 1991,
file No. 0-5468).
*10(d)(1) -- Form of Stock Option Agreement under
1989 Incentive and Nonqualified Stock
Option Plan, as amended and restated
effective January 22, 1991. (Exhibit
10(d)(1), Annual Report on Form 10-K
for the year ended December 31, 1991,
File No. 0-5468).
*10(d)(2) -- Form of Director Stock Option
Agreement under 1989 Incentive and
Nonqualified Stock Option Plan, as
amended and restated effective
January 22, 1991. (Exhibit 10(d)(2),
Annual Report on Form 10-K for the
year ended December 31, 1991, File
No. 0-5468).
*10(e) -- Form of Letter Agreement respecting
treatment of options upon change in
control. (Exhibit 19(f), Quarterly
Report on Form 10-Q for the quarter
ended June 30, 1982. File No.
0-5468).
*10(f)(1) -- Employment Agreement by and between
Pogo Producing Company and Stuart P.
Burbach, dated February 1, 1992.
(Exhibit 19(a)(1), Quarterly Report
on Form 10-Q for the quarter ended
June 30, 1992, File No. 1-7792).
*10(f)(2)(i) -- Extension Agreement to Continue
Employment Agreement between Stuart
P. Burbach and Pogo Producing
Company, dated as of February 1,
1993. (Exhibit 10(f)(2), Annual
report on Form 10-K for the year
ended December 31, 1992, File No.
1-7792).
10(f)(2)(ii) -- Extension Agreement to Continue
Employment Agreement between Stuart
P. Burbach and Pogo Producing
Company, dated as of February 1,
1994.
*10(f)(3) -- Employment Agreement by and between
Pogo Producing Company and Jerry A.
Cooper, dated February 1, 1992.
(Exhibit 19(a)(2), Quarterly Report
on Form 10-Q for the quarter ended
June 30, 1992, File No. 1-7792).
*10(f)(4)(i) -- Extension Agreement to Continue
Employment Agreement between Jerry A.
Cooper and Pogo Producing Company,
dated as of February 1, 1993.
(Exhibit 10(f)(4), Annual report on
Form 10-K for the year ended December
31, 1992, File No. 1-7792).
10(f)(4)(ii) -- Extension Agreement to Continue
Employment Agreement between Jerry A.
Cooper and Pogo Producing Company,
dated as of February 1, 1994.
*10(f)(5) -- Employment Agreement by and between
Pogo Producing Company and Kenneth R.
Good, dated February 1, 1992.
(Exhibit 19(a)(3), Quarterly Report
on Form 10-Q for the quarter ended
June 30, 1992, File No. 1-7792).
*10(f)(6)(i) -- Extension Agreement to Continue
Employment Agreement between Kenneth
R. Good and Pogo Producing Company,
dated as of February 1, 1993.
(Exhibit 10(f)(6), Annual report on
Form 10-K for the year ended December
31, 1992, File No. 1-7792).
10(f)(6)(ii) -- Extension Agreement to Continue
Employment Agreement between Kenneth
R. Good and Pogo Producing Company,
dated as of February 1, 1994.
*10(f)(7) -- Employment Agreement by and between
Pogo Producing Company and R. Phillip
Laney, dated February 1, 1992.
(Exhibit 19(a)(4), Quarterly Report
on Form 10-Q for the quarter ended
June 30, 1992, File No. 1-7792).
*10(f)(8)(i) -- Extension Agreement to Continue
Employment Agreement between R.
Phillip Laney and Pogo Producing
Company, dated as of February 1,
1993. (Exhibit 10(f)(8), Annual
report on Form 10-K for the year
ended December 31, 1992, File No.
1-7792).
50
10(f)(8)(ii) -- Extension Agreement to Continue
Employment Agreement between R.
Phillip Laney and Pogo Producing
Company, dated as of February 1,
1994.
*10(f)(9) -- Employment Agreement by and between
Pogo Producing Company and John O.
McCoy, Jr., dated February 1, 1992.
(Exhibit 19(a)(5), Quarterly Report
on Form 10-Q for the quarter ended
June 30, 1992, File No. 1-7792).
*10(f)(10)(i) -- Extension Agreement to Continue
Employment Agreement between John O.
McCoy, Jr. and Pogo Producing
Company, dated as of February 1,
1993. (Exhibit 10(f)(10), Annual
report on Form 10-K for the year
ended December 31, 1992, File No.
1-7792).
10(f)(10)(ii) -- Extension Agreement to Continue
Employment Agreement between John O.
McCoy, Jr. and Pogo Producing
Company, dated as of February 1,
1994.
*10(f)(11) -- Employment Agreement by and between
Pogo Producing Company and D. Stephen
Slack, dated February 1, 1992.
(Exhibit 19(a)(6), Quarterly Report
on Form 10-Q for the quarter ended
June 30, 1992, File No. 1-7792).
*10(f)(12)(i) -- Extension Agreement to Continue
Employment Agreement between D.
Stephen Slack and Pogo Producing
Company, dated as of February 1,
1993. (Exhibit 10(f)(12), Annual
report on Form 10-K for the year
ended December 31, 1992, File No.
1-7792).
10(f)(12)(ii) -- Extension Agreement to Continue
Employment Agreement between D.
Stephen Slack and Pogo Producing
Company, dated as of February 1,
1994.
*10(f)(13) -- Employment Agreement by and between
Pogo Producing Company and Paul G.
Van Wagenen, dated February 1, 1992.
(Exhibit 19(a)(7), Quarterly Report
on Form 10-Q for the quarter ended
June 30, 1992, File No. 1-7792).
*10(f)(14)(i) -- Extension Agreement to Continue
Employment Agreement between Paul G.
Van Wagenen and Pogo Producing
Company, dated as of February 1,
1993. (Exhibit 10(f)(14), Annual
report on Form 10-K for the year
ended December 31, 1992, File No.
1-7792).
10(f)(14)(ii) -- Extension Agreement to Continue
Employment Agreement between Paul G.
Van Wagenen and Pogo Producing
Company, dated as of February 1,
1994.
*10(g) -- Undertaking by Pogo Producing Company
dated as of August 8, 1977. (Exhibit
10(e), Annual Report on Form 10-K for
the year ended December 31, 1980,
File No. 0-5468).
*10(h) -- Limited partnership agreement of Pogo
Gulf Coast, Ltd. (Exhibit 19,
Quarterly Report on Form 10-Q for the
quarter ended June 30, 1989, File No.
0-5468).
21 -- List of Subsidiaries of Pogo
Producing Company.
23(a) -- Consent of Independent Public
Accountants.
23(b) -- Consent of Independent Petroleum
Engineers.
24 -- Powers of Attorney from each Director
of Pogo Producing Company whose
signature is affixed to this Form
10-K for the year ended December 31,
1993.
28 -- Summary of Reserve Report of Ryder
Scott Company Petroleum Engineers
dated January 28, 1994 relating to
oil and gas reserves of Pogo
Producing Company.
* Asterisk indicates exhibits incorporated by reference as shown.
(B) REPORTS ON FORM 8-K
None
51
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
POGO PRODUCING COMPANY
(REGISTRANT)
By: /s/ PAUL G. VAN WAGENEN
PAUL G. VAN WAGENEN
CHAIRMAN OF THE BOARD, PRESIDENT
AND CHIEF EXECUTIVE OFFICER
Date: February 28, 1994
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES INDICATED ON FEBRUARY 28, 1994.
SIGNATURES TITLE
/s/ PAUL G. VAN WAGENEN Principal Executive
PAUL G. VAN WAGENEN Officer and Director
CHAIRMAN OF THE BOARD, PRESIDENT
AND CHIEF EXECUTIVE OFFICER
/s/ D. STEPHEN SLACK Principal Financial
D. STEPHEN SLACK Officer and Director
SENIOR VICE PRESIDENT, CHIEF
FINANCIAL OFFICER AND TREASURER
/s/ THOMAS E. HART Principal Accounting
THOMAS E. HART Officer
VICE PRESIDENT AND CONTROLLER
TOBIN ARMSTRONG* Director
TOBIN ARMSTRONG
JACK S. BLANTON* Director
JACK S. BLANTON
W. M. BRUMLEY, JR.* Director
W. M. BRUMLEY, JR.
JOHN B. CARTER, JR.* Director
JOHN B. CARTER, JR.
WILLIAM L. FISHER* Director
WILLIAM L. FISHER
WILLIAM E. GIPSON* Director
WILLIAM E. GIPSON
GERRITT W. GONG* Director
GERRITT W. GONG
J. STUART HUNT* Director
J. STUART HUNT
FREDERICK A. KLINGENSTEIN* Director
FREDERICK A. KLINGENSTEIN
NICHOLAS R. PETRY* Director
NICHOLAS R. PETRY
JACK A. VICKERS* Director
JACK A. VICKERS
*By: /s/ THOMAS E. HART
THOMAS E. HART
ATTORNEY-IN-FACT
52
SCHEDULE V & VI
POGO PRODUCING COMPANY AND SUBSIDIARIES
SCHEDULE V -- PROPERTY AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991
(EXPRESSED IN THOUSANDS)
BALANCE BALANCE
BEGINNING ADDITIONS RETIREMENT OTHER END OF
DESCRIPTION OF PERIOD AT COST OR SALES CHANGES PERIOD
1993:
Oil and gas---------------------- $ 875,154 $ 72,469 $ (120,893) $ (3,047) $ 823,683
Other---------------------------- 6,851 163 (48) (5) 6,961
Total---------------------------- $ 882,005 $ 72,632 $ (120,941) $ (3,052) $ 830,644
1992:
Oil and gas---------------------- $ 907,336 $ 37,963 $ (61,182) $ (8,963) $ 875,154
Other---------------------------- 6,680 589 -- (418) 6,851
Total---------------------------- $ 914,016 $ 38,552 $ (61,182) $ (9,381) $ 882,005
1991:
Oil and gas---------------------- $ 867,183 $ 48,905 $ (4,264) $ (4,488) $ 907,336
Other---------------------------- 9,270 2,416 (5,017) 11 6,680
Total---------------------------- $ 876,453 $ 51,321 $ (9,281) $ (4,477) $ 914,016
SCHEDULE VI -- RESERVES FOR DEPRECIATION, DEPLETION,
AND AMORTIZATION OF PROPERTY AND EQUIPMENT
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991
(EXPRESSED IN THOUSANDS)
CHARGED TO RETIREMENT
BALANCE PROFIT AND RENEWALS BALANCE
BEGINNING LOSS OR AND OTHER END OF
DESCRIPTION OF PERIOD INCOME REPLACEMENTS CHANGES PERIOD
1993:
Oil and gas---------------------- $ 713,396 $ 40,224 $ (120,160) $ 746 $ 634,206
Other---------------------------- 4,032 469 (49) 4,452
Total---------------------------- $ 717,428 $ 40,693 $ (120,209) $ 746 $ 638,658
1992:
Oil and gas---------------------- $ 730,835 $ 41,849 $ (60,887) $ 1,599 $ 713,396
Other---------------------------- 3,578 453 -- 1 4,032
Total---------------------------- $ 734,413 $ 42,302 $ (60,887) $ 1,600 $ 717,428
1991:
Oil and gas---------------------- $ 696,459 $ 36,970 $ (2,622) $ 28 $ 730,835
Other---------------------------- 7,148 551 (4,089) (32 ) 3,578
Total---------------------------- $ 703,607 $ 37,521 $ (6,711) $ (4 ) $ 734,413
S-1
SCHEDULE X
POGO PRODUCING COMPANY AND SUBSIDIARIES
SCHEDULE X -- SUPPLEMENTARY INCOME STATEMENT INFORMATION
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991
(EXPRESSED IN THOUSANDS)
1993 1992 1991
Maintenance and repairs-------------- $ 3,658 $ 4,435 $ 6,498
Taxes, other than payroll and income
taxes:
Severance, ad valorem, franchise
and other------------------------ $ 3,133 $ 2,423 $ 2,222
S-2