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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, 1997
[ ] 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 77252-2504
HOUSTON, TEXAS (ZIP CODE)
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 297-5000
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS: ON WHICH REGISTERED:
Common Stock, $1 par value New York Stock Exchange
Pacific Stock Exchange
Preferred Stock Purchase Rights New York Stock Exchange
Pacific Stock Exchange
5 1/2% Convertible Subordinated New York Stock Exchange
Notes due March 15, 2004
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
5 1/2% Convertible Subordinated Notes due June 15, 2006
8 3/4% Senior Subordinated Notes due May 15, 2007
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ].
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the 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 $890,078,498 as of March 13, 1998 (based on $30.1875 per share,
the last sale price of the Common Stock as reported on the New York Stock
Exchange Composite Tape on such date).
37,554,982 shares of the registrant's Common Stock were outstanding as of
March 13, 1998.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Company's definitive Proxy Statement respecting the annual
meeting of shareholders to be held on April 28, 1998 (to be filed not later than
120 days after December 31, 1997) are incorporated by reference in Part III of
this Form 10-K.
FORWARD LOOKING STATEMENTS
The statements included or incorporated by reference in this Report on Form
10-K for the year ended December 31, 1997 (this "Annual Report") include
"forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended. All statements included herein or therein other than
statements of historical fact are forward-looking statements. When used herein
or therein, the words "anticipate," "estimate," "expect," "objective,"
"projection," "forecast," "goal," and similar expressions are intended to
identify forward-looking statements. Such forward-looking statements include,
without limitation, the statements herein and therein regarding the timing of
future events regarding the Company's operations both domestically and in
Thailand, and the statements set forth herein under the caption "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" regarding the Company's
anticipated future financial position and cash requirements. Although the
Company believes that the expectations reflected in such forward-looking
statements are reasonable, it can give no assurance that such expectations will
prove to have been correct. Important factors that could cause actual results to
differ materially from the Company's expectations ("Cautionary Statements")
are disclosed in this Annual Report and in other filings by the Company with the
Securities and Exchange Commission (the "Commission") including, without
limitation, in connection with such forward-looking statements. All subsequent
written and oral forward-looking statements attributable to the Company or
persons acting on its behalf are expressly qualified in their entirety by the
Cautionary Statements.
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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, onshore in selected areas in
New Mexico, Texas and Louisiana, and internationally in the Gulf of Thailand. As
of December 31, 1997, the Company had interests in 101 lease blocks offshore
Louisiana and Texas, approximately 237,000 gross acres onshore in the United
States and approximately 734,000 gross acres offshore in the Kingdom of
Thailand. Unless otherwise specifically identified, the information set forth in
this Annual Report, including production rates and the number of wells,
platforms and blocks, is presented on a gross basis, rather than net to the
Company.
In recent years, the Company has concentrated its efforts in selected areas
where it believes that its expertise, competitive acreage position, or ability
to quickly take advantage of new opportunities offer the possibility of superior
rates of return. As of January 1, 1998, six significant operating areas, of
which three are located in the Gulf of Mexico and one each in South Texas, New
Mexico and Thailand, accounted for approximately 82% of the Company's estimated
proved natural gas reserves, approximately 90% of the Company's estimated proved
oil, condensate and natural gas liquids reserves, approximately 80% of the
Company's natural gas production and 89% of the Company's oil, condensate and
natural gas liquids production for 1997. Reserves, as estimated by Ryder Scott
Petroleum Engineers, Houston Texas ("Ryder Scott"), and production data, as
estimated by the Company, for the six significant operating areas are shown in
the following table. No other producing area accounted for more than 3% of the
Company's estimated proved reserves as of January 1, 1998.
SIGNIFICANT OPERATING AREA 1997 AVERAGE NET
NET PROVED RESERVES(A) DAILY PRODUCTION
------------------------------------------ ------------------------------------------
NATURAL GAS LIQUIDS(B) NATURAL GAS LIQUIDS(B)
-------------------- -------------------- -------------------- --------------------
MMCF % MBBLS % MCF % BBLS %
--------- --------- --------- --------- --------- --------- --------- ---------
DOMESTIC OFFSHORE
Eugene Island................... 27,182 6.8 7,607 13.1 23,334 13.5 4,673 24.5
Main Pass....................... 14,570 3.6 3,830 6.6 7,104 4.1 2,777 14.6
East Cameron.................... 30,199 7.5 1,006 1.7 53,893 31.2 3,242 17.0
DOMESTIC ONSHORE
New Mexico...................... 20,578 5.1 11,287 19.4 9,151 5.3 4,008 21.0
South Texas..................... 52,724 13.1 1 0.0 11,484 6.6 0 0.0
INTERNATIONAL
Kingdom of Thailand.. 184,768 46.0 28,783 49.5 37,733 19.0 2,421 14.0
TOTAL NET
PROVED
RESERVES(A)
%
-----------
DOMESTIC OFFSHORE
Eugene Island................... 10.7
Main Pass....................... 5.0
East Cameron.................... 4.8
DOMESTIC ONSHORE
New Mexico...................... 11.8
South Texas..................... 7.0
INTERNATIONAL
Kingdom of Thailand.. 47.6
- ------------
(a) Net proved reserves and total net proved reserves are each as of January 1,
1998. Units of measurement used in this table include: thousand cubic feet
("Mcf"), million cubic feet ("MMcf"), barrels ("Bbls") and thousand
barrels ("MBbls").
(b) "Liquids," includes oil, condensate and natural gas liquids.
DOMESTIC OFFSHORE OPERATIONS
Historically, the Company's interests have been concentrated in the Gulf of
Mexico, where approximately 59% of the Company's domestic proved reserves and
31% of its total proved reserves are now located. During 1997, approximately 65%
of the Company's natural gas production and approximately 59% of its oil and
condensate production was from its domestic offshore properties, contributing
approximately 62% of the Company's consolidated oil and gas revenues. Three
offshore producing areas, Eugene Island, Main Pass and East Cameron, account for
approximately 18% of the Company's net proved natural gas
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reserves and approximately 21% of the Company's proved crude oil, condensate and
natural gas liquids reserves. See ";Significant Domestic Offshore Operating
Areas during 1997."
LEASE ACQUISITIONS
The Company has participated, either on its own or with other companies, in
bidding on and acquiring interests in federal and state leases offshore in the
Gulf of Mexico since December 1970. As a result of such sales and subsequent
activities, as of December 31, 1997, the Company owned interests in 93 federal
leases and 8 state leases offshore Louisiana and Texas. Federal leases generally
have primary terms of five, eight or ten years, depending on water depth, and
state leases generally have terms of three or five years, depending on location,
in each case subject to extension by development and production operations.
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. During 1997, the Company was successful in acquiring
interests in 19 lease blocks through federal Outer Continental Shelf oil and gas
lease sales and 1 lease block by assignment from a third party. The Department
of the Interior has announced its intention to hold two lease sales during 1998
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
offshore 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 leasehold properties in areas where
additional low-risk drilling or improved production methods by the Company can
provide attractive rates of return.
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 1997 were approximately $86,300,000, or 9% lower than the Company's domestic
offshore capital and exploration expenditures of approximately $94,400,000
(excluding approximately $2,000,000 of net property acquisitions) for 1996 and
128% higher than the Company's domestic offshore capital and exploration
expenditures of approximately $37,800,000 (excluding approximately $650,000 of
net property acquisitions) for 1995. The decrease in the Company's domestic
offshore capital and exploration expenditures for 1997, compared with 1996,
resulted primarily from a decrease in drilling activity and in construction and
installation of offshore platforms, pipelines and other facilities, which was
partially offset by the increased costs to the Company (and the entire oil and
gas industry generally) because of price increases by the oil and gas services,
construction and supply industries due to the shortage of skilled workers and
the comparative scarcity of certain equipment, such as drilling rigs, and
critical materials, such as certain types of steel pipe. The increase in the
Company's domestic offshore capital and exploration expenditures for 1997,
compared to 1995, resulted primarily from increased drilling activity and
increased costs associated with the construction and installation of offshore
platforms, pipelines and other facilities and the increase in prices discussed
above. 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 significantly influence
(but not always control) decisions regarding development and operations on most
of the leases in which it has a working interest even though it may not
4
be the operator of a particular lease. The Company was the operator on all or a
portion of 30 of the 101 offshore leases in which it has an interest on December
31, 1997.
Platforms and related facilities are installed on an offshore lease 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. Over the last three years, the gross cost of
production platforms and related facilities to the joint ventures in which the
Company has varying net interests has ranged from approximately $3,000,000 to
approximately $16,500,000. 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. For example, during
1997, the Company and its joint venture partners approved construction of a
platform located on Viosca Knoll Block 823 which will be located in
approximately 1200 feet of water. This platform, together with its related
pipelines and other facilities, is currently estimated to have a gross cost of
approximately $127,000,000 (approximately $13,700,000 net to the Company's
current working interest).
SIGNIFICANT DOMESTIC OFFSHORE OPERATING AREAS DURING 1997
EUGENE ISLAND
A significant portion of the Company's reserves and a substantial part of
its production are located in the Eugene Island area 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 10 blocks
in the Eugene Island area. These blocks comprise eight fields containing 64 oil
and gas wells producing from multiple reservoirs and horizons. During 1997, the
Company participated in the drilling of eight wells in the Eugene Island
operating area.
The Eugene Island Block 330 field is one of the Company's most significant
producing assets. This 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 12 wells producing primarily natural gas
and 34 wells producing primarily oil on the block. The Company and its joint
venture partners drilled six new wells which added significant new reserves in
this field during 1997.
MAIN PASS
The Company's 12 lease blocks in the Main Pass area, including two acquired
in 1997, are located near the mouth of the Mississippi River in the Gulf of
Mexico and include leases in which the Company has held an interest since 1974.
The majority of the Company's production from the Main Pass area comes from a
field that includes Main Pass Blocks 72, 73 and 72/74 which was unitized in
1982. The Company's working interest in this field is 35%. This field contains
20 producing oil wells and nine producing natural gas wells from three platforms
operated by the Company's joint venture partner and is located in 125 feet of
water. The Company participated in the drilling of 3 exploratory wells in the
Main Pass area during 1997.
EAST CAMERON
The first leasehold interest acquired by the Company 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 five offshore blocks
in this area which contain two fields and 19 producing gas wells. Two of the
five blocks were awarded to the Company and its joint venture partners during
1997 and have yet to be fully evaluated.
During 1997, the Company and its partners were active in the East Cameron
Block 334/335 field. In February 1997, the Company and one of its joint venture
partners completed construction of the East Cameron "E" platform and commenced
production from two wells. Following mechanical problems in one of these wells
which caused it to be shut in, production was restored in the first week of
January 1998. The
5
Company and its joint venture partners completed construction of a sixth
platform during 1997, known as the "F" platform. Production from the well
served by this platform, in which the Company holds a 42% interest, commenced in
December 1997.
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 area of southeastern New Mexico, West Texas and Northwest
Texas, and in the onshore Gulf Coast areas of South Texas, East Texas and South
Louisiana. See ";Significant Domestic Onshore Operating Areas During 1997."
LEASE ACQUISITIONS
Commencing in 1995 and continuing into 1997, the Company has increased its
activities in the onshore Gulf Coast areas of East Texas and South Louisiana
through its participation in several large proprietary 3-D seismic surveys, in
connection with which the Company typically purchases an option to acquire an
interest in the acreage covered by the 3-D seismic survey. As it has in recent
years, in 1997 the Company also successfully participated in various onshore
federal and state lease sales and acquired interests in prospective acreage from
private individuals. As of December 31, 1997, the Company held interests in
approximately 237,000 gross (113,000 net) acres onshore in the United States, an
increase of approximately 12% from year end 1996.
EXPLORATION AND DEVELOPMENT
The Company's primary drilling objective in the Permian Basin is the Brushy
Canyon (Delaware) formation which generally produces oil from depths of 6,000 to
9,000 feet. Since the Company began exploring in the Brushy Canyon (Delaware)
formation in October 1989, it has participated in drilling 357 wells in the
Permian Basin, West and Northwest Texas areas through December 31, 1997,
including 58 wells in 1997.
The Company's primary drilling activity in East Texas has been in the
Cotton Valley formation reef play. In Southeast Louisiana, the Company
participated in drilling 11 wells in 1997 to test various Hackberry formation
and Yegua formation prospects, all of which were identified on proprietary 3-D
seismic surveys that the Company and its industry partners have acquired since
1995. The Company also actively explores for oil and gas onshore in South Texas.
In total, the Company participated in the drilling of 25 wells in the onshore
Gulf Coast areas of South Texas, East Texas and South Louisiana, including 14
exploratory wells (principally in East Texas and South Louisiana) and 11
developmental wells (principally in the Lopeno Field in South Texas). See ";
Significant Domestic Onshore Operating Areas During 1997; South Texas."
Domestic onshore reserves as of December 31, 1997, accounted for approximately
41% of the Company's domestic proved reserves and approximately 21% of its total
proved reserves. During 1997, approximately 16% of the Company's natural gas
production and 27% of its oil and condensate production was from its domestic
onshore properties, contributing approximately 20% of the Company's consolidated
oil and gas revenues.
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 own onshore properties using
independent contractors.
The Company's domestic onshore capital and exploration expenditures were
approximately $60,000,000 (excluding approximately $1,700,000 of net property
acquisitions) for 1997, or 28% higher than the Company's domestic onshore
capital and exploration expenditures of approximately $47,000,000 (excluding
approximately $3,800,000 of net property acquisitions) for 1996 and 82% higher
than the Company's domestic onshore capital and exploration expenditures of
approximately $33,000,000 (excluding approximately $7,800,000 of net property
acquisitions) for 1995. The increase in the Company's domestic onshore capital
and exploration expenditures for 1997, compared to 1996 and 1995, resulted
primarily from increased drilling activity in South Texas, East Texas and South
Louisiana and, to a lesser extent, by the increased costs to the Company (and
the entire oil and gas industry generally) because of
6
price increases by the oil and gas services, construction and supply industries
due to the shortage of skilled workers and the comparative scarcity of certain
equipment, such as drilling rigs and critical materials, such as certain types
of steel pipe.
SIGNIFICANT DOMESTIC ONSHORE OPERATING AREAS DURING 1997
NEW MEXICO
The Company believes that during the past five 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 79,000 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
typically range from 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.
Since the Company began exploring in the Brushy Canyon (Delaware) formation
in the southeastern New Mexico portion of the Permian Basin in October 1989, it
has participated through December 31, 1997, in the drilling of, among others, 94
wells in the Sand Dunes field where the Company's working interest ranges from
4% to 100%, 27 wells in the East Loving field where the Company's working
interest ranges from 33% to 98%, 60 wells in the Livingston Ridge field where
the Company's working interest ranges from 25% to 100%, 61 wells in the Red Tank
field where the Company's working interest ranges from 89% to 100%, 31 wells in
the Cedar Canyon field where the Company's working interest ranges from 38% to
100% (including 15 during 1997), 15 wells in the Lost Tank field where the
Company's working interest ranges from 50% to 100% (including 12 during 1997),
and 3 wells in the Poker Lake Field where the Company's working interest ranges
from 60% to 100%. The oil fields in this area are generally developed on a 40
acre spacing pattern. The Company anticipates drilling additional locations in
certain of these and other fields in southeastern New Mexico during 1998
including, in particular, an aggressive drilling program in the Cedar Canyon and
Lost Tank fields.
SOUTH TEXAS
The Company has increased its activity in South Texas in recent years,
where it is currently active in two fields, both of which primarily produce
natural gas. The most significant of these two fields is the Lopeno Field, which
is located within 40 miles of the border with Mexico. The Company acquired its
initial interest in the Lopeno Field in 1983. The Company currently has
interests in over 7,800 gross acres containing 29 producing wells, with working
interests generally averaging approximately 50%. The Lopeno Field produces from
over 20 upper Wilcox sandstone reservoirs ranging in depth up to 12,500 feet.
Based in part on a 3-D seismic survey acquired over the field in 1994, the
Company and its joint venture partners commenced an active development drilling
program in the fourth quarter of 1995. In 1997, the Company drilled seven
successful wells in the Lopeno Field and currently plans to drill an additional
nine wells in this field during 1998.
INTERNATIONAL OPERATIONS
The Company has conducted international exploration activities since the
late 1970's in numerous oil and gas areas throughout the world. Currently, the
Company maintains an office in Bangkok, Thailand from which it directs field
operations in the Gulf of Thailand on its Block B8/32 Concession (the "Thailand
Concession") through its wholly owned subsidiary Thaipo Limited ("Thaipo").
As a result of its acquisition in 1995 and March 1997 of portions of the
original interest of Maersk Oil (Thailand) Ltd., a former joint venture partner
that owned a 31.67% interest in the Thailand Concession, the Company has
increased its ownership interest in the Thailand Concession so that it currently
owns, directly or indirectly, a 46.34% working interest in the entire Thailand
Concession. In addition, Thaipo has been elected by its joint
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venture partners, Thai Romo Ltd., Palang Sophon Limited and B8/32 Partners Ltd,
and designated by the government of Thailand, as the operator of the Thailand
Concession. As of December 31, 1997, the Company's proved reserves located in
the Kingdom of Thailand accounted for approximately 48% of the Company's total
proved reserves. During 1997, approximately 19% of the Company's natural gas
production and 14% of its oil and condensate production came from its operations
on the Thailand Concession, contributing approximately 14% of the Company's
consolidated oil and gas revenues.
EXPLORATION AND DEVELOPMENT
The Company's international capital and exploration expenditures were
approximately $88,300,000 (excluding approximately $28,600,000 of net property
acquisitions) for 1997, or 37% higher than the Company's international capital
and exploration expenditures of approximately $64,400,000 for 1996 and 152%
higher than the Company's international capital and exploration expenditures of
approximately $35,000,000 (excluding approximately $4,200,000 of net property
acquisitions) for 1995. The increase in the Company's international capital and
exploration expenditures for 1997, compared to 1996 and 1995, resulted primarily
from increased platform and facilities construction costs related to initial
development of the Benchamas Field, increased drilling activity and, to a lesser
extent, by the increased costs to the Company (and the entire oil and gas
industry generally) because of price increases by the oil and gas services,
construction and supply industries due to the shortage of skilled workers and
the comparative scarcity of certain equipment, such as drilling rigs, and
certain critical materials, such as certain types of steel pipe. Substantially
all of the Company's international capital and exploration expenditures for 1997
were related to the Company's license in the Kingdom of Thailand. In addition,
the Company continues to evaluate other international opportunities that are
consistent with the Company's international exploration strategy.
Platforms are installed on the Thailand Concession in fields where, in the
judgment of Thaipo and its joint venture partners, 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 and the area where the platform would be located has been designated a
production area by the Thai government. See "; Contractual Terms Governing the
Thailand Concession and Related Production." Platforms are used to accommodate
both development drilling and additional exploratory drilling. Over the last
three years, the gross cost of the first four production platforms and related
facilities in the Tantawan Field has averaged approximately $20,000,000.
Platform costs vary and more (or less) expensive platforms could be required in
the future depending on, among other factors, the number of slots, water depth,
currents, and sea floor conditions. See "; Significant International Operating
Areas During 1997; Tantawan Field."
SIGNIFICANT INTERNATIONAL OPERATING AREAS DURING 1997
TANTAWAN FIELD
In August 1995, at the request of Thaipo and its joint venture partners,
the government of Thailand designated a portion of the Thailand Concession
comprising approximately 68,000 acres as the Tantawan production area. The
Tantawan production area has been named the Tantawan Field. Through March 13,
1998, 19 exploration and 29 development wells have been drilled in the Tantawan
Field. Initial production from the Tantawan Field commenced on February 1, 1997,
from wells located on two platforms. Currently, there are 34 wells producing
from four platforms. The Company is currently planning to install a fifth
platform in the Tantawan Field from which production is currently expected to
commence in the second half of 1999. Additional drilling in order to maintain
field delivery capacity is currently planned to commence in the third quarter of
1998 from existing platforms, following which wells will be drilled at the
location of the proposed platform.
Oil and gas production from the Tantawan Field is gathered through
pipelines from the platforms into a Floating Production, Storage and Offloading
system (an "FPSO") named the "Tantawan Explorer." The FPSO is a converted
oil tanker with a capacity of slightly less than 1,000,000 Bbls, that is moored
in the Tantawan Field, on which hydrocarbon processing, separation, dehydration,
compression, metering and
8
other production related equipment is installed. Following processing on board
the FPSO, natural gas produced from the field is delivered to the Petroleum
Authority of Thailand ("PTT") through an export pipeline. Oil and condensate
produced from the field is stored on board the FPSO and transferred to shore by
oil tanker. The FPSO and its processing equipment is leased from a third party
under a bareboat charter by Tantawan Services, LLC, an affiliate of Thaipo. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources." Thaipo and its joint venture
partners pay a processing fee to Tantawan Services, LLC, to process the
production from the Tantawan Field through the FPSO.
BENCHAMAS FIELD AND THE MALIWAN PRODUCTION AREA
In July 1997, the government of Thailand designated another portion of the
Thailand Concession comprising approximately 102,000 acres of the Benchamas and
Pakakrong production area as the Benchamas Field. This area currently includes
at least two discrete geologic structures which were previously designated as
the Benchamas and Pakakrong areas, respectively. In September 1997, the
government of Thailand designated an additional 91,000 acres of the Thailand
Concession as the Maliwan production area. Through March 13, 1998, 15
exploration wells have been drilled in the Benchamas Field and four exploration
wells have been drilled in the Maliwan production area. Current development
plans call for the staged development of these fields, with the Benchamas Field
to be brought on production first. The Benchamas Field development plan
currently contemplates the initial installation of three production platforms,
with natural gas and oil from these platforms delivered by undersea pipeline to
a central processing and compression platform where the oil, condensate and
natural gas will be processed and separated. The natural gas will then be sold
to PTT and delivered into export pipelines for transportation to shore, while
the oil and condensate produced from the field will be stored on board a
converted oil tanker known as a Floating Storage and Offloading system (an
"FSO") for sale and ultimate transfer to shore by oil tanker. The FSO will be
moored in the Benchamas Field. Its capacity will be approximately 1,400,000 Bbls
of oil, or slightly more than the FPSO. The field's current development plan
calls for initial production to commence in the third quarter of 1999. During
1998, Thaipo and its joint venture partners currently plan to continue
delineation drilling in the Benchamas Field and to conduct additional
exploratory drilling in the Maliwan production area.
OTHER AREAS
In addition to the above mentioned fields, Thaipo and its joint venture
partners have identified other potentially promising areas on the Thailand
Concession. Since acquiring their interest in the Thailand Concession, Thaipo
and its joint venture partners have acquired 3-D seismic surveys covering
approximately 673,650 acres of the Thailand Concession, including 221,650 acres
during the fourth quarter of 1997 over what is known as the Jarmjuree area.
Interpretation of the Jarmjuree 3-D seismic survey commenced in the first
quarter of 1998 and is ongoing. In addition to the ongoing interpretation of
this recently acquired 3-D seismic data, Thaipo has proposed to its joint
venture partners that the joint venture conduct an exploratory drilling program
during 1998 to initially evaluate the Chongko area which is located on trend to
the south of the Maliwan production area and to also evaluate prospects
developed from the interpretation of the Jarmjuree 3-D seismic survey.
CONTRACTUAL TERMS GOVERNING THE THAILAND CONCESSION AND RELATED PRODUCTION
The Thailand Concession was granted in August 1991. The original
exploratory term of the concession agreement governing those portions of the
Thailand Concession not designated as a production area expired on July 31,
1997. However, on application from Thaipo and its joint venture partners, the
government of Thailand agreed in a supplemental concession agreement to extend
the exploratory term for those portions of the Thailand Concession that have not
yet been designated a production area (currently comprising approximately
474,000 acres) until July 31, 2000. In exchange, the Company and its joint
venture partners committed to, among other things, an additional work program
which includes the drilling of two wells and the acquisition of 148,000 acres of
3-D seismic data during the remainder of the exploratory term.The Company
currently believes that this work commitment will be satisfied during the
ordinary course of the
9
Company's operations on the Thailand Concession during 1998. For those portions
of the Thailand Concession that have been designated as production areas the
initial production period term is 20 years, which is also subject to extension,
generally for a term of ten years. See also " -- Miscellaneous; Sales."
Currently, the Tantawan, Maliwan, and Benchamas and Pakakrong areas have been
designated as production areas. Subject to governmental approval, other portions
of the Thailand Concession may be designated production areas in the future.
Production resulting from the Thailand Concession is subject to a royalty
ranging from 5% to 15% of oil and gas sales, plus certain fixed U.S. dollar
amounts payable at specified cumulative production levels. Revenue from
production in Thailand is also subject to income taxes and other similar
governmental charges including a Special Remuneratory Benefit tax ("SRB").
On November 7, 1995, Thaipo and its joint venture partners announced the
signing of a thirty-year gas sales agreement with PTT, initially governing gas
production from the Tantawan Field. On November 12, 1997, Thaipo and its joint
venture partners entered into an amendment to the gas sales agreement to include
the reserves and anticipated gas production from the Benchamas Field (as so
amended, the "Gas Sales Agreement"). The terms of the Gas Sales Agreement
currently include a minimum daily contract quantity ("DCQ") of 85 MMcf per
day, which the Company currently anticipates will continue until the Benchamas
Field commences production at which time the DCQ will, subject to certain
exceptions, be based on a percentage of the remaining proved reserves, but in
any event, will not be less than 125 MMcf per day. The DCQ is the minimum daily
volume that PTT has agreed to take, or pay for if not taken under the agreement.
Likewise, Thaipo and its joint venture partners are subject to certain penalties
if they are unable to meet the DCQ, principal among which is a decrease in sales
price of up to 25% of the then current sales price. For production during the
month of February 1998, the Company estimates that the gas sales price under the
Gas Sales Agreement formula was approximately 84 Thai Baht per Mcf. This price
is subject to automatic semi-annual adjustments based upon a formula which takes
into account, among other things, changes in: Singapore fuel oil prices; the
U.S. Department of Commerce Bureau of Labor Statistics Oilfield Machinery and
Tool Index; the Thai wholesale producer price index; and the U.S./Thai currency
exchange rate. However, the Gas Sales Agreement provides for adjustment on a
more frequent basis in the event that certain indices and factors on which the
price is based fluctuate outside a given range. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Results of
Operations; Operating Costs and Expenses; Foreign Currency Transaction Loss,
and -- Liquidity and Capital Resources; Other Matters; Southeast Asia Economic
Issues."
MISCELLANEOUS
OTHER ASSETS
The Company and a subsidiary, Pogo Offshore Pipeline Co., own interests in
eight pipelines (excluding field gathering pipelines) through which offshore
hydrocarbon production is transported. In addition, the Company owns
approximately 19% interest in a cryogenic gas processing plant near Erath,
Louisiana, which entitles it to process up to 186 MMcf of natural gas and 5,478
Bbls of natural gas liquids per day. The plant is not currently operating at
full capacity.
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"). As of December 31, 1997, Pogo Gulf Coast had interests in 5
federal offshore leases. 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.
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
10
may have to await the construction or expansion of pipeline capacity before
production from that area can be marketed. The Company's domestic offshore
properties are generally located in areas where a pipeline infrastructure is
well developed and there is adequate availability in such pipelines to handle
the Company's current and projected future production.
The Company's Thailand Concession is traversed by two major (34 inches and
36 inches in diameter, respectively) natural gas pipelines that are owned and
operated by PTT and which come within approximately 25 miles of the Tantawan
Field (and are slightly closer to the Benchamas Field). Thaipo and its joint
venture partners in the Tantawan Field signed a long term gas sales contract
with PTT in November 1995 which has since been amended to include production
from the Benchamas Field. All oil and condensate production from the Tantawan
field is initially stored aboard the FPSO and is then sold to various third
parties, including PTT, on a tanker load by tanker load basis at prices based on
then current world oil prices, typically with reference to the Malaysian Tapis
crude oil benchmark price. The buyer is responsible for sending a tanker to off
load the oil and condensate it has purchased. It is currently anticipated that
crude oil and condensate production from the Benchamas Field, when it commences
production, will be initially stored aboard the FSO and sold in the same manner.
See "-- International Operations; Contractual Terms Governing the Thailand
Concession and Related Production."
The marketing of domestic 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 domestic 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 price
that is then currently available. Other than any futures contracts which may
exist from time to time, and which are referred to in "-- Miscellaneous;
Competition and Market Conditions," and the Gas Sales Agreement with PTT for
production from the Tantawan and Benchamas Fields (see "-- International
Operations; Contractual Terms Governing the Thailand Concession and Related
Production"), 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.
Enron Corp. and its affiliates and PTT, who purchased $57,965,000 (20% of the
Company's consolidated gross revenues) and $30,108,000 (11% of the Company's
consolidated gross revenues) of the Company's oil and gas production during
1997, respectively, were the Company's only customers to which sales exceeded
10% of its 1997 revenues. The oil and gas sold to Enron Corp. and its affiliates
was sold under a number of short term, generally month to month, contracts.
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. Should natural
gas prices fall in the future, the Company may again elect to curtail certain
quantities of its natural gas production. 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 never 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
11
effect of price declines, such transactions could effectively limit the
Company's participation in price increases for the covered period, which
increases could be significant. As of March 13, 1998, the Company was not a
party to any natural gas futures contracts or crude oil swap agreements. When
the Company does engage in such 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 and helicopter 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 and of installing production facilities
and pipelines is often uncertain. The Company's drilling operations may be
curtailed, delayed or canceled as a result of numerous factors, including title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery or availability of material, equipment and
fabrication yards. 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
in any other areas outside the United States in which the Company may choose to
do business, are subject to the various risks inherent in foreign operations.
These risks may include, among other things, 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,
renegotiation of contracts with governmental entities, changes in laws and
policies governing operations of foreign-based companies and other uncertainties
arising out of foreign government sovereignty over the Company's international
operations. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Results of Operations; Operating Costs and
Expenses; Foreign Currency Transaction Loss," and " -- Liquidity and Capital
Resources; Other Matters; Southeast Asia Economic Issues." The Company's
international operations may also be adversely affected by laws and policies of
the United States affecting foreign trade, taxation and investment. In addition,
in the event of a dispute arising from foreign operations, the Company may be
subject to the exclusive jurisdiction of foreign courts or may not be successful
in subjecting foreign persons to the jurisdiction of the courts of the United
States. 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.
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.
12
ACREAGE
The following table shows the Company's interest in developed and
undeveloped oil and gas acreage as of December 31, 1997:
DEVELOPED ACREAGE UNDEVELOPED ACREAGE
(A) (B)
-------------------- --------------------
GROSS NET GROSS NET
--------- --------- --------- ---------
DOMESTIC ONSHORE
Louisiana...................... 2,475 598 36,074 10,895
New Mexico..................... 21,021 12,591 58,410 42,932
Texas.......................... 12,084 4,346 103,100 40,769
Other.......................... 3,200 333 238 55
--------- --------- --------- ---------
Total Domestic Onshore.... 38,780 17,868 197,822 94,651
--------- --------- --------- ---------
DOMESTIC OFFSHORE
Louisiana (State).............. 7,942 3,255 1,508 753
Louisiana (Federal) (c)........ 186,422 61,378 152,879 56,061
Texas (Federal)................ 40,320 10,251 56,905 16,530
--------- --------- --------- ---------
Total Domestic Offshore... 234,684 74,854 211,292 73,344
--------- --------- --------- ---------
TOTAL DOMESTIC............ 273,464 92,722 409,114 167,995
--------- --------- --------- ---------
INTERNATIONAL
Kingdom of Thailand............ 260,407 120,682 473,733 219,530
--------- --------- --------- ---------
TOTAL COMPANY............. 533,871 213,404 882,847 387,525
========= ========= ========= =========
- ------------
(a) "Developed acreage" consists of lease acres spaced or assignable to
production (including acreage held by production) on which wells have been
drilled or completed to a point that would permit production of commercial
quantities of oil or natural gas. "Developed acreage" in Thailand includes
all acreage designated as production area by the Thai government, which
currently includes the Tantawan, Maliwan, Benchamas and Pakakrong production
areas.
(b) "Undeveloped acreage" includes acreage under lease or subject to lease or
purchase options that the Company currently expects to exercise. Less than
1% of the Company's total domestic offshore net undeveloped acreage is under
leases that have terms expiring in 1998 (unless otherwise extended) and
another approximately 1% of total domestic offshore net undeveloped acreage
will expire in 1999 (unless otherwise extended). Approximately 7% of the
Company's total domestic onshore net undeveloped acreage is under leases
that have terms expiring in 1998 (unless otherwise extended) and another
approximately 15% of total domestic onshore net undeveloped acreage will
expire in 1999 (unless otherwise extended). The Company's total
international net undeveloped acreage must be relinquished to the Thai
government on July 31, 2000, unless designated as a production area or
unless the exploration term is extended. See "-- International Operations;
Contractual Terms Governing the Thailand Concession and Related
Production."
(c) The Company also owns overriding royalty interests in one federal lease
offshore Louisiana totaling 5,000 gross acres (1,250 net acres).
PRODUCTIVE WELLS AND DRILLING ACTIVITY
The following table shows the Company's interest in productive oil and
natural gas wells as of December 31, 1997. For purposes of this table
"productive wells" are defined as wells producing hydrocarbons and 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 currently installed production facilities).
This table does not include exploratory or developmental wells which have
located commercial quantities of oil or natural gas but which are not capable of
commercial production without the installation of material production facilities
or which, for a variety of reasons, the Company does not currently believe will
be placed on production.
13
NATURAL
OIL WELLS (A) GAS WELLS (A)
----------------- -----------------
GROSS NET GROSS NET
----- --------- ----- ---------
Offshore United States............... 129 33.3 113 33.8
Onshore United States................ 339 214.4 91 33.1
Kingdom of Thailand.................. -- -- 34 15.8
----- --------- ----- ---------
TOTAL........................... 468 247.7 238 82.7
===== ========= ===== =========
- ------------
(a) One or more completions in the same bore hole are counted as one well. The
data in the above table includes five gross (.6 net) oil wells and 45 gross
(20.4 net) natural 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 or when electric logs run
to evaluate such wells indicate the presence of commercial hydrocarbons and the
Company currently intends to complete such wells. 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.
1997 1996 1995
--------------------- -------------------- --------------------
SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY
---------- ----- ---------- ---- ---------- ----
GROSS WELLS:
Offshore United States
Exploratory..................... 4.0 1.0 4.0 2.0 7.0 4.0
Development..................... 12.0 3.0 17.0 3.0 3.0 1.0
Onshore United States
Exploratory..................... 18.0 12.0 12.0 4.0 8.0 1.0
Development..................... 50.0 3.0 39.0 1.0 47.0 1.0
Offshore Kingdom of Thailand
Exploratory..................... 18.0 1.0 7.0 -- 3.0 --
Development..................... 12.0 -- 16.0 -- 7.0 --
---------- ----- ---------- ---- ---------- ----
TOTAL...................... 114.0 20.0 95.0 10.0 75.0 7.0
========== ===== ========== ==== ========== ====
1997 1996 1995
--------------------- -------------------- --------------------
SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY
---------- ----- ---------- ---- ---------- ----
NET WELLS:
Offshore United States
Exploratory..................... 1.21 .25 1.7 1.5 3.0 1.6
Development..................... 4.15 1.05 4.9 1.5 1.0 0.4
Onshore United States
Exploratory..................... 11.27 7.40 6.5 0.9 4.6 1.0
Development..................... 30.18 1.41 24.4 0.7 31.3 0.1
Offshore Kingdom of Thailand
Exploratory..................... 8.34 .46 2.4 -- 1.1 --
Development..................... 5.11 -- 7.4 -- 3.2 --
---------- ----- ---------- ---- ---------- ----
TOTAL...................... 60.26 10.57 47.3 4.6 44.2 3.1
========== ===== ========== ==== ========== ====
14
As of December 31, 1997, the Company was participating in the drilling of 3
gross (1.1 net) offshore domestic wells, 6 gross (4.2 net) onshore wells and 1
gross (0.5 net) wells offshore the Kingdom of Thailand.
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.
1997 1996 1995
--------- --------- ---------
Located in the United States
Natural Gas (Mcf per day).. 147,200 107,700 121,000
========= ========= =========
Liquid Hydrocarbons (Bbls
per day)
Crude Oil and
Condensate............ 13,712 11,968 11,786
Natural Gas Liquids
(a)................... 2,923 2,173 1,998
--------- --------- ---------
Total Domestic
Liquid
Hydrocarbons.... 16,635 14,141 13,784
========= ========= =========
Located in the Kingdom of
Thailand
Natural Gas (Mcf per
day)....................... 37,700 -- --
========= ========= =========
Liquid Hydrocarbons (Bbls
per day)
Crude Oil and
Condensate............ 2,421 -- --
========= ========= =========
- ------------
(a) Natural Gas Liquids includes sales attributable to both the Company's
leasehold and plant ownership interests.
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."
1997 1996 1995
--------- --------- ---------
SALES PRICES:
Located in the United States
Natural Gas (per Mcf)...... $ 2.50 $ 2.40 $ 1.63
Crude Oil and Condensate
(per Bbl)............... $ 19.49 $ 22.12 $ 17.80
Natural Gas Liquids (per
Bbl).................... $ 12.89 $ 14.92 $ 11.10
Located in the Kingdom of
Thailand
Natural Gas (per Mcf)...... $ 1.93 -- --
Crude Oil and Condensate
(per Bbl)............... $ 18.60 -- --
PRODUCTION (LIFTING) COSTS (A):
Located in the United States
Natural Gas, Crude Oil,
Condensate
and Natural Gas Liquids
(per Mcf equivalent).... $ .49 $ .53 $ .47
Located in the Kingdom of
Thailand
Natural Gas, Crude Oil and
Condensate (per Mcf
equivalent)(b).......... $ 1.12 -- --
- ------------
(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.
(b) The major contributing factor to lifting costs are lease operating expenses.
A substantial portion of the Company's lease operating expenses in the
Kingdom of Thailand relate to lease payments made by a subsidiary of the
Company in connection with its bareboat charter of the FPSO, which amounted
to $10,200,000 during 1997. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources; Capital Requirements; Other Material Long-Term Commitments."
15
RESERVES
The following table sets forth information as to the Company's net proved
and proved developed reserves as of December 31, 1997, 1996, and 1995, and the
present value as of such dates (based on an annual discount rate of 10%) of the
estimated future net revenues from the production and sale of those reserves, as
estimated by Ryder Scott in accordance with criteria prescribed by the
Commission.
AS OF DECEMBER 31,
----------------------------------
1997 1996 1995
---------- ---------- ----------
TOTAL PROVED RESERVES:
Oil, condensate, and natural gas
liquids (MBbls)
Located in the United
States.................. 29,382 28,270 26,185
Located in the Kingdom of
Thailand................ 28,783 21,332 18,997
---------- ---------- ----------
Total Company......... 58,165 49,602 45,182
========== ========== ==========
Natural Gas (MMcf)
Located in the United
States.................. 216,720 215,946 196,454
Located in the Kingdom of
Thailand................ 184,768 144,998 131,607
---------- ---------- ----------
Total Company......... 401,488 360,944 328,061
========== ========== ==========
Present value of estimated
future net revenues, before
income taxes (in thousands)
(a)
Located in the United
States.................. $ 406,161 $ 773,127 $ 400,845
Located in the Kingdom of
Thailand................ 56,620 181,418 131,630
---------- ---------- ----------
Total Company......... $ 462,781 $ 954,545 $ 532,475
========== ========== ==========
TOTAL DEVELOPED RESERVES:
Oil, condensate, and natural gas
liquids (MBbls)
Located in the United
States.................. 26,168 25,898 22,488
Located in the Kingdom of
Thailand................ 6,982 5,192 --
---------- ---------- ----------
Total Company......... 33,150 31,090 22,488
========== ========== ==========
Natural Gas (MMcf)
Located in the United
States.................. 179,972 192,034 164,679
Located in the Kingdom of
Thailand................ 59,760 45,998 --
---------- ---------- ----------
Total Company......... 239,732 238,032 164,679
========== ========== ==========
Present value of estimated
future net revenues, before
income taxes (in thousands)
(a)
Located in the United
States.................. $ 377,530 $ 710,871 $ 359,984
Located in the Kingdom of
Thailand................ 36,692 69,062 --
---------- ---------- ----------
Total Company......... $ 414,222 $ 779,933 $ 359,984
========== ========== ==========
- ------------
(a) The Company believes, for the reasons set forth in succeeding paragraphs,
that the present value of estimated future net revenues set forth in this
Annual Report and calculated in accordance with Commission guidelines are
not necessarily indicative of the true present value of the Company's
reserves and, due to the fact that essentially all of the Company's domestic
natural gas production is currently sold on the spot market, whereas all of
the Company's Thai natural gas production is sold pursuant to a long term
gas sales contract, such estimates of future net revenues from the Company's
domestic and Thai reserves are, accordingly, not useful for comparative
purposes. See the discussion on the following pages for the prices used in
making these calculations.
Natural gas liquids comprise approximately 7% of the Company's total proved
liquids reserves and approximately 11% of the Company's proved developed liquids
reserves. All hydrocarbon liquid reserves
16
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 non-associated, 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, (i) pressure maintenance, (ii) cycling, and (iii)
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:
(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.
In computing future revenues from gas reserves attributable to the
Company's domestic interests, prices in effect at December 31, 1997 were used,
including current market prices, contract prices and fixed and determinable
price escalations where applicable. In accordance with Commission guidelines,
the 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 domestic gas sold under contract, the
contract gas price including fixed and determinable escalations, exclusive of
inflation
17
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 domestic interests, prices in effect at December 31, 1997 were used
and these prices were held constant to depletion of the properties. The future
revenues are adjusted to reflect the Company's net revenue interest in these
reserves as well as any ad valorem and other severance taxes but do not include,
unless otherwise noted, any provisions for corporate income taxes.
In computing future revenues from the Company's gas reserves attributable
to the Company's interests in the Kingdom of Thailand, the current contract
price under the Gas Sales Agreement was used, without giving effect to any of
the adjustments provided for in the Gas Sales Agreement, due to their
indeterminate nature as of December 31, 1997, in accordance with Commission
guidelines. In computing future revenues from liquids attributable to the
Company's interests in the Kingdom of Thailand, a price was used which the
Company believes approximates the price that the Company would have received for
its production from the Thailand Concession based upon the world market price
for Tapis benchmark crude on December 31, 1997, and this price was held constant
until depletion of the Company's reserves in the Kingdom of Thailand. The future
revenues are adjusted to reflect the Company's net revenue interest in these
reserves and the Company's obligations under the Thailand Concession, including
the payment of SRB and applicable production bonuses, but does not include,
unless otherwise noted, any provisions for U.S. or Thai corporate income or
other taxes.
In accordance with Commission guidelines, the prices used by Ryder Scott to
calculate the present value of estimated future net revenues are determined on a
well by well or field by field basis, as applicable, as described above and were
held constant over the productive life of the reserves. The initial weighted
average prices used by Ryder Scott were as follows:
AS OF DECEMBER 31,
-------------------------------
1997 1996 1995
--------- --------- ---------
INITIAL WEIGHTED AVERAGE PRICE (in
U.S. dollars):
Oil, condensate, and natural gas
liquids (per Bbl)
Located in the United
States..................... $ 16.60 $ 24.06 $ 19.10
Located in the Kingdom of
Thailand................... $ 16.00 $ 24.56 $ 18.71
Natural Gas (per Mcf)
Located in the United
States..................... $ 2.30 $ 3.93 $ 2.08
Located in the Kingdom of
Thailand................... $ 1.83 $ 2.09 $ 2.02
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. Accumulated gas production imbalances, if any, have
been taken into account.
Production data used to arrive at the estimates set forth above includes
estimated production for the last few months of 1997. 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
18
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, which revisions may be material. Accordingly,
reserve estimates 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 U.S. governmental regulatory authorities and agencies,
including the Federal Energy Regulatory Commission ("FERC") and the Federal
Trade Commission and, with respect to reserves located in Thailand, the Kingdom
of Thailand's Department of Mineral Resources and PTT, which the Company
considers a quasi-governmental authority. 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 by Ryder Scott in
accordance with Commission guidelines because of the nature of the various
reports required. The major differences generally 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. During 1997, no estimates by the Company of its total proved net oil and
gas reserves were filed with or included in reports to any governmental
authority or agency other than the Commission and, with respect to reserves
relating to the Company's properties located in Thailand, the Kingdom of
Thailand's Department of Mineral Resources and PTT.
GOVERNMENT REGULATION
The Company's operations are affected from time to time in varying degrees
by political developments and governmental laws and regulations. Rates of
production of oil and gas have for many years been subject to governmental
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 will be taken into account in computing the
Company's alternative minimum tax.
19
ENVIRONMENTAL MATTERS
Domestic oil and gas operations are subject to extensive federal 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." The recent trend towards
stricter standards in environmental legislation and regulation may continue, and
this could increase costs to the Company and others in the industry. Oil and gas
lessees are subject to liability for the costs of clean-up of pollution
resulting from a lessee's operations, and may also be subject to 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 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.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder
impose a variety of regulations on "responsible parties" related to the
prevention of oil spills and liability for damages resulting from such spills in
United States waters. A "responsible party" includes the owner or operator of
a facility or vessel, or the lessee or permittee of the area in which an
offshore facility is located. The OPA assigns liability to each responsible
party for oil removal costs and a variety of public and private damages. While
liability limits apply in some circumstances, a party cannot take advantage of
liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of a federal safety, construction or
operating regulation. If the party fails to report a spill or cooperate fully in
the cleanup, liability limits likewise do not apply. Few defenses exist to the
liability imposed by the OPA.
The OPA also imposes ongoing requirements on responsible parties, including
proof of financial responsibility to cover at least some costs in a potential
spill. For tank vessels, including mobile offshore drilling rigs, the OPA
imposes on owners, operators and charterers of the vessels, an obligation to
maintain evidence of financial responsibility of up to $10,000,000 depending on
gross tonnage. With respect to offshore facilities, proof of greater levels of
financial responsibility may be applicable. For offshore facilities that have a
worst case oil spill potential of more than 1,000 barrels (which includes many
of the Company's offshore producing facilities), certain amendments to the OPA
that were enacted in 1996 provide that the amount of financial responsibility
that must be demonstrated for most facilities ranges from $10,000,000 to
$35,000,000, depending upon location, with higher amounts, up to $150,000,000 in
certain limited circumstances. The Company believes that it currently has
established adequate proof of financial responsibility for its offshore
facilities at no significant increase in expense over recent prior years.
However, the Company cannot predict whether these financial responsibility
requirements under the OPA amendments will result in the imposition of
substantial additional annual costs to the Company in the future or otherwise
materially adversely effect the Company. The impact, however, should not be any
more adverse to the Company than it will be to other similarly situated or less
capitalized owners or operators in the Gulf of Mexico.
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 laws and 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. Such laws
could have a significant impact on the operating costs of the Company, as well
as the oil and gas industry in general. Federal, state and local initiatives to
further
20
regulate the disposal of oil and gas wastes are also pending in certain states,
and these initiatives could have a similar impact on the Company.
The Company is asked to comment on the costs it incurred during the prior
year on capital expenditures for environmental control facilities and the amount
it anticipates incurring during the coming year. The Company believes that, in
the course of conducting its oil and gas operations, many of the costs
attributable to environmental control facilities would have been incurred absent
environmental regulations as prudent, safe oilfield practice. During 1997, the
Company incurred capital expenditures of approximately $610,000 for
environmental control facilities, primarily relating to the installation of
certain environmental control facilities on two platforms installed in the Gulf
of Thailand. The Company currently has budgeted approximately $1,630,000 for
expenditures involving environmental control facilities during 1998, including,
among other things, two salt water disposal facilities in New Mexico and
environmental control equipment for three platforms in the Gulf of Thailand and
two platforms in the Gulf of Mexico.
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 and other matters.
The effect of these laws and regulations, as well as other regulations that
could be promulgated by the jurisdictions in which the Company has production,
could be to limit the number of wells that could be drilled on the Company's
properties and to limit the allowable production from the successful wells
completed on the Company's properties, thereby limiting the Company's revenues.
The Minerals Management Service of the Department of the Interior (the
"MMS") administers the oil and gas leases held by the Company on federal
onshore lands and offshore tracts in the Outer Continental Shelf. The MMS holds
a royalty interest in these federal leases on behalf of the federal government.
While the royalty interest percentage is fixed at the time that the lease is
entered into, from time to time the MMS changes or reinterprets the applicable
regulations governing its royalty interests, and such action can indirectly
affect the actual royalty obligation that the Company is required to pay. In a
letter dated May 3, 1993, the MMS announced a reinterpretation of its right to
collect royalty payments from producers on certain settlements in which such
producers and pipeline companies were involved a number of years ago. The MMS
reinterpretation has been challenged in court by various producers and trade
groups representing them. On August 27, 1996, in INDEPENDENT PETROLEUM
ASSOCIATION OF AMERICA, ET AL. V. BABBIT ET AL., Nos. 95-5210 etc., the United
States Court of Appeals for the District of Columbia Circuit held that the May
3, 1993, reinterpretation was invalid and unenforceable. Unless and until this
or other similar cases are resolved in favor of the MMS' reinterpretation of its
regulations, it is unlikely that the Company or other producers will be legally
required to pay royalties on such settlement agreements. The Company was
involved in several settlement agreements with pipelines that could be subject
to the MMS' new reinterpretation. The MMS has reviewed the Company's and other
producers' settlement agreements, to determine whether it believes any
additional royalty payments may be due and has asserted that additional
royalties may be due in connection with two of the Company's settlement
agreements. Based upon existing case law, the Company has asserted through the
administrative appeals process, and continues to believe, that it does not owe
any additional royalties beyond what it has previously paid. However, in the
event that the MMS is able to successfully assert that additional royalty is due
from the Company in connection with settlement agreements to which the Company
is a party, the Company does not currently believe that such additional
assessment will have a material adverse impact on the financial position or
results of operations of the Company.
Recently the MMS and various state and municipal authorities have attempted
to collect alleged underpayment of royalties from various integrated oil
companies in connection with sale transactions between exploration and
production affiliates and pipeline affiliates of the same company. The Company
has not been named in any of these collection efforts, a fact that the Company
believes is primarily due to its never having sold any oil or gas production
from one of its affiliates to another. The Company does not believe that it has
any material liability for underpayment of royalty in connection with affiliate
transactions, including those described above.
21
The FERC has recently embarked on regulatory initiatives relating to its
jurisdiction over rates for natural gas gathering services provided by
interstate pipelines and to the availability of market-based and other
alternative rate mechanisms to such pipelines for transmission and storage
services. Among the FERC initiatives is the creation of a pilot program to
determine the effect on rates of lifting price caps on the rates for
interruptible transportation, short-term firm transportation, and for
transportation using capacity released by the firm transportation customers of
interstate pipelines. In addition, the FERC has announced and implemented a
policy allowing pipelines and transportation customers to negotiate rates above
the otherwise applicable maximum lawful cost-based rates on the condition that
the pipelines alternatively offer so-called recourse rates equal to the maximum
lawful cost-based rates. This negotiated/recourse rate policy has been
challenged in the United States Court of Appeals for the District of Columbia,
and the appeal remains pending. With respect to gathering services, the FERC has
issued orders declaring that certain facilities owned by interstate pipelines
primarily perform a gathering function, and may be transferred to affiliated and
non-affiliated entities that are not subject to the FERC's rate jurisdiction.
These orders have been generally upheld on appeal to the courts. The Company
cannot predict the ultimate outcome of these developments, nor the effect of
these developments on transportation rates. Inasmuch as the rates for these
pipeline services can affect the gas prices received by the Company for the sale
of its production, the FERC's actions may have an impact on the Company.
However, the impact should not be substantially different on the Company than it
will on other similarly situated gas producers and sellers.
EMPLOYEES
As of March 1, 1998, the Company had 137 full-time employees and its
subsidiary Thaipo employed an additional 23 individuals. 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.
ITEM 3. LEGAL PROCEEDINGS.
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. See "Business -- Government
Regulation; Other Laws and Regulations."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.
Not Applicable.
22
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 March 13, 1998, 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 52 1991
and Chief Executive Officer
Stuart P. Burbach.................... Executive Vice President -- 45 1998
Exploration
Kenneth R. Good...................... Executive Vice President 60 1998
Jerry A. Cooper...................... Senior Vice President and 49 1998
Western Division Manager
R. Phillip Laney..................... Senior Vice President and Manager 57 1998
of Worldwide New Ventures
John O. McCoy, Jr.................... Senior Vice President and 46 1998
Chief Administrative Officer
J. D. McGregor....................... Senior Vice President -- Sales 53 1998
Bruce E. Archinal.................... Vice President and Onshore 45 1997
Division Manager
David R. Beathard.................... Vice President -- Engineering 39 1997
Stephen R. Brunner................... Vice President -- Operations 39 1997
Frank Davis III...................... Vice President -- Land 51 1997
John W. Elsenhans.................... Vice President and Chief 45 1998
Financial Officer
Thomas E. Hart....................... Vice President and Controller 55 1988
Ronald B. Manning.................... Vice President and 44 1995
General Counsel
Gerald A. Morton..................... Vice President--Law and 39 1997
Corporate Secretary
23
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, who joined the Company in 1979, served as President
and Chief Operating Officer of the Company since 1990; Mr. Burbach served as
Vice President and Offshore Division Manager since rejoining the Company in
1991; Mr. Good, who joined the Company in 1977, served as Corporate Senior Vice
President of the Company since 1996 and prior thereto served as the Company's
Senior Vice President -- Land and Budgets since 1991; Mr. Cooper, who joined the
Company in 1979, served as Vice President and Western Division Manager for the
Company since 1991; Mr. Laney, who joined the Company in 1977, served as Vice
President and International Exploration Manager for the Company since 1991; Mr.
McCoy, who joined the Company in 1978, served as Vice President and Chief
Administrative Officer of the Company since 1989; Mr. McGregor, who joined the
Company in 1981, served as Vice President -- Sales since 1988; Mr. Archinal, who
joined the Company in 1982, served as the Company's Onshore Division Manager
since 1994 and prior thereto served as Offshore Division Exploration Manager for
the Company since 1991; Mr. Beathard, who joined the Company in 1982, served as
Manager of Petroleum Engineering for the Company since 1991; Mr. Brunner served
as Resident Manager of the Company's Thailand operations since 1995, prior to
which he was an Operations Manager for the Company since joining in 1994 and
prior thereto held various positions in the energy industry, the most recent of
which was as Operations Manager for Zilkha Energy since 1991; Mr. Davis who
joined the Company in 1978, served as Land Manager for the Company since 1991;
Mr. Elsenhans, who joined the Company in 1991, served as Vice
President -- Finance and Treasurer for the Company since 1995, and prior thereto
was Director, Corporate Finance for the Company since 1991; Mr. Hart was
Controller for the Company since joining the Company in 1977; Mr. Manning, who
joined the Company in 1987, was Corporate Secretary and an Associate General
Counsel for the Company since 1990; and Mr. Morton was an Associate General
Counsel for the Company since 1993 and prior thereto was an attorney with the
law firm of Weil, Gotshal & Manges since 1988.
24
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 Common Stock trades under the symbol PPP. The Common
Stock is also listed on the Pacific Stock Exchange.
LOW HIGH
---- -----
1996
1st Quarter............................. 24 3/8 34 3/4
2nd Quarter............................. 31 3/8 38 1/4
3rd Quarter............................. 32 1/4 38 3/4
4th Quarter............................. 35 3/4 48 3/8
1997
1st Quarter............................. 33 3/8 49 7/8
2nd Quarter............................. 33 1/2 41 3/8
3rd Quarter............................. 37 7/8 45 3/8
4th Quarter............................. 27 44 9/16
As of March 13, 1998, there were 2,891 holders of record of the Company's
Common Stock.
In each of 1996 and 1997, the Company paid four quarterly dividends of
$0.03 per share on its Common Stock. However, the declaration and payment of
future dividends will depend upon, among other things, the Company's future
earnings and financial condition, liquidity and capital requirements, the
general economic and regulatory climate and other factors deemed relevant by the
Company's Board of Directors.
Pursuant to the Company's revolving credit agreement with its banks under
which the Company has borrowed funds, and the Indenture relating to the
Company's 8 3/4% Senior Subordinated Notes due 2007 (the "2007 Notes") 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
apply any funds, property or assets to the purchase, redemption, sinking fund or
other retirement of its capital stock, if the aggregate amount of all such
dividends, purchases, and redemptions would exceed an amount determined based on
the consolidated income of the Company and its consolidated subsidiaries plus
the proceeds of the issuance of capital stock from and after a specified date
set forth in each respective agreement or, in the case of the revolving credit
agreement, if the net worth of the Company is negative. As of December 31, 1997,
$28,657,000 was available for dividends under this limitation in the Indenture
relating to the 2007 Notes, the agreement currently having the most restrictive
covenant.
25
ITEM 6. SELECTED FINANCIAL DATA.
FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
FINANCIAL DATA
(Expressed in thousands, except per
share data)
Revenues:
Crude oil and condensate........... $ 112,603 $ 96,908 $ 76,557 $ 65,141 $ 64,042
Natural gas........................ 158,500 94,589 72,032 99,093 66,173
Natural gas liquids................ 13,748 11,867 8,097 9,189 7,288
Other, net......................... 349 778 773 133 (950)
--------- --------- --------- --------- ---------
Oil and gas revenues............... 285,200 204,142 157,459 173,556 136,553
Interest on tax refund............. -- -- -- -- 2,322
Gains (losses) on sales............ 1,100 (165) 100 52 679
--------- --------- --------- --------- ---------
Total............................ $ 286,300 $ 203,977 $ 157,559 $ 173,608 $ 139,554
========= ========= ========= ========= =========
Income before extraordinary item..... $ 37,116 $ 33,581 $ 9,230 $ 27,374 $ 25,061
Extraordinary losses................. -- (821) -- (307) --
--------- --------- --------- --------- ---------
Net income........................... $ 37,116 $ 32,760 $ 9,230 $ 27,067 $ 25,061
========= ========= ========= ========= =========
Per share data:
Income before extraordinary item --
Basic (restated for 1996 and
prior years).................... $ 1.11 $ 1.01 $ 0.28 $ 0.84 $ 0.78
Diluted (restated for 1996 and
prior years).................... $ 1.06 $ 0.97 $ 0.28 $ 0.82 $ 0.76
Cash dividends..................... $ 0.12 $ 0.12 $ 0.12 $ 0.06 $ --
Price range of common stock:
High............................. $ 49.88 $ 48.38 $ 29.00 $ 24.25 $ 21.00
Low.............................. $ 27.00 $ 24.38 $ 16.00 $ 15.63 $ 9.75
Weighted average number of common
shares outstanding.................. 33,421 33,203 32,893 32,663 32,160
Long-term debt at year end........... $ 348,179 $ 246,230 $ 163,249 $ 149,249 $ 130,539
Shareholders' equity at year end..... $ 146,106 $ 107,282 $ 71,708 $ 64,037 $ 33,803
Total assets at year end............. $ 676,617 $ 479,242 $ 338,177 $ 298,826 $ 239,774
PRODUCTION (SALES) DATA
Net daily average and weighted
average price:
Natural gas (Mcf per day).......... 181,700 107,700 121,000 144,800 91,700
Price (per Mcf).................. $ 2.39 $ 2.40 $ 1.63 $ 1.88 $ 1.98
Crude oil-condensate (Bbl. per
day).............................. 15,927 11,968 11,786 11,100 9,851
Price (per Bbl.)................. $ 19.37 $ 22.12 $ 17.80 $ 16.08 $ 17.81
Natural gas liquids (Bbl. per
day).............................. 2,923 2,173 1,998 2,222 1,678
Price (per Bbl.)................. $ 12.89 $ 14.92 $ 11.10 $ 11.33 $ 11.90
CAPITAL EXPENDITURES
(Expressed in thousands)
Oil and gas:
Domestic Offshore --
Exploration...................... $ 18,700 $ 16,800 $ 13,300 $ 2,800 $ 4,600
Development...................... 59,800 73,900 17,800 44,100 33,700
Purchase of reserves............. 900 -- -- 32,600 --
Domestic Onshore --
Exploration...................... 18,100 10,400 8,800 6,800 5,200
Development...................... 38,400 27,800 22,400 23,700 24,300
Purchase of reserves............. 1,700 -- 7,900 -- --
International --
Exploration...................... 21,700 8,500 5,500 5,100 4,600
Development...................... 62,500 54,700 24,400 -- --
Purchase of reserves............. 29,300 -- 4,200 -- --
--------- --------- --------- --------- ---------
Total oil and gas.................. 251,100 192,100 104,300 115,100 72,400
Other................................ 4,000 1,600 500 1,200 200
--------- --------- --------- --------- ---------
Total.............................. $ 255,100 $ 193,700 $ 104,800 $ 116,300 $ 72,600
========= ========= ========= ========= =========
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
RESULTS OF OPERATIONS
INCOME AND REVENUE DATA
NET INCOME
The Company reported net income for 1997 of $37,116,000 or $1.11 per share
($40,198,000 or $1.06 per share on a diluted basis) compared to net income for
1996 of $32,760,000 or $0.99 per share ($35,843,000 or $0.95 per share on a
diluted basis) and net income for 1995 of $9,230,000 or $0.28 per share (on both
a basic and a diluted basis). The Company recorded an extraordinary loss of
$821,000 during the second quarter of 1996 related to the early retirement of
the Company's 8% Convertible Subordinated Debentures, due 2005 (the "8%
Debentures") with the proceeds from the Company's issuance on June 18, 1996, of
its 5 1/2% Convertible Subordinated Notes, due 2006 (the "2006 Notes").
Earnings per common share are based on the weighted average number of
common and common equivalent shares outstanding for 1997 of 33,421,000
(38,064,000 on a diluted basis), compared to 33,203,000 (37,920,000 on a diluted
basis) for 1996 and 32,893,000 (33,490,000 on a diluted basis) for 1995. The
yearly increases in the weighted average number of common shares outstanding
resulted primarily from the issuance of shares of Common Stock upon the exercise
of stock options pursuant to the Company's stock option plans. Earnings per
common share computations on a diluted basis primarily reflect additional common
shares issuable upon the assumed conversion of the Company's 5 1/2% Convertible
Subordinated Notes, due 2004 (the "2004 Notes") in 1996 and 1997 (the only
convertible securities of the Company that were dilutive during the applicable
periods) and the elimination of related interest requirements, as adjusted for
applicable federal income taxes. In addition, the number of common shares
outstanding in the diluted computation is also adjusted, in accordance with the
Financial Accounting Standards Board's Statement of Financial Accounting
Standards No. 128 ("SFAS 128"), to include dilutive shares that are assumed to
have been issued by the Company in connection with options exercised during the
year, less treasury shares that are assumed to have been purchased by the
Company from the option proceeds. SFAS 128 was adopted by the Company in 1997,
resulting in a restatement of the earnings per share calculations for 1996,
1995, and all preceding years.
REVENUES
TOTAL REVENUES
The Company's total revenues for 1997 were $286,300,000, an increase of
approximately 40% from total revenues of $203,977,000 for 1996, and an increase
of approximately 82% from total revenues of $157,559,000 for 1995. The increase
in the Company's total revenues for 1997, compared to 1996, resulted primarily
from the substantial increase in the Company's natural gas and liquid
hydrocarbon (including crude oil, condensate and natural gas liquid ("NGL"))
production, which was only partially offset by a decline in the average price
that the Company received for its liquid hydrocarbon production and, to a much
lesser extent, the average price that the Company received for its natural gas
production. The increase in the Company's total revenues for 1997, compared to
1995, resulted primarily from the substantial increases in the Company's natural
gas production, the average price that the Company received for its natural gas
production, the Company's liquid hydrocarbon production and, to a lesser extent,
the average price that the Company received for its liquid hydrocarbon
production.
27
OIL AND GAS REVENUES
The Company's oil and gas revenues for 1997 were $285,200,000, an increase
of approximately 40% from oil and gas revenues of $204,142,000 for 1996, and an
increase of approximately 81% from oil and gas revenues of $157,459,000 for
1995. The following table reflects an analysis of variances in the Company's oil
and gas revenues between 1997 and the previous two years:
1997 COMPARED TO
---------------------
1996 1995
--------- ----------
(IN THOUSANDS)
Increase (decrease) in oil and gas
revenues resulting from variances
in:
Natural Gas
Price........................... $ (394) $ 33,466
Production...................... 64,305 53,002
--------- ----------
63,911 86,468
--------- ----------
Crude oil and condensate
Price........................... (12,064) 6,767
Production...................... 27,759 29,279
--------- ----------
15,695 36,046
--------- ----------
NGL and other, net................... 1,452 5,227
--------- ----------
Increase (decrease) in oil and gas
revenues........................... $ 81,058 $ 127,741
========= ==========
NATURAL GAS PRICES. Prices per Mcf that the Company received for its
natural gas production during 1997 averaged $2.39 per Mcf. The average price
that the Company received for its natural gas production in 1997 was
approximately equal to the average price that the Company had received during
1996 of $2.40 per Mcf, but was a substantial increase (of approximately 47%)
from the average price of $1.63 that it received during 1995.
DOMESTIC PRICES. Prices that the Company received for its domestic natural
gas production during 1997 averaged $2.50 per Mcf, an increase of approximately
4% from an average price of $2.40 per Mcf that the Company received for its
domestic natural gas production during 1996, and an increase of approximately
53% from an average price of $1.63 that the Company received for its natural gas
production during 1995.
THAILAND PRICES. The Company's Tantawan Field located in the Kingdom of
Thailand commenced production of natural gas and liquid hydrocarbons in February
1997. During 1997, the price that the Company received under the Gas Sales
Agreement averaged approximately 60 Thai Baht per Mcf. The price that the
Company receives under the Gas Sales Agreement would normally adjust on a
semi-annual basis. However, the Gas Sales Agreement provides for adjustment on a
more frequent basis in the event that certain indices and factors on which the
price is based fluctuate outside a given range. See "Business -- International
Operations; Contractual Terms Governing the Thailand Concession and Related
Production." Due to the volatility of the Thai Baht and the current economic
difficulties in the Kingdom of Thailand and throughout Southeast Asia, the price
that the Company receives under the Gas Sales Agreement has been adjusted on
almost a monthly basis since July 1997. As a result of these adjustments, during
December 1997 the price that the Company received under the Gas Sales Agreement
for its production from the Thailand Concession averaged approximately 68 Thai
Baht per Mcf. However, the increases that the Company has received in the Thai
Baht price for its natural gas production from the Thailand Concession have not
been sufficient to completely ameliorate, in U.S. dollar terms, the decline of
the Thai Baht against the U.S. dollar. The Company cannot predict when, if ever,
the adjustments provided for in the Gas Sales Agreement will completely
recompense the Company for the decline of the Thai Baht against the U.S. dollar.
However, the Company anticipates that should the Thai economy stabilize and
recover, the volatility of the value of the Thai Baht against the U.S. dollar
will decline and the adjustments to the gas sales price under the Gas Sales
28
Agreement resulting from changes to the indices and other factors will gradually
restore, at least in part, the gas sales price (in U. S. dollar terms) to the
relative value it had prior to the devaluation of the Thai Baht which commenced
in July 1997. See "Operating Costs and Expenses; Foreign Currency Transaction
Loss", "-- Liquidity and Capital Resources; Other Matters; Southeast Asia
Economic Issues" and "Business -- International Operations; Contractual Terms
Governing the Thailand Concession."
NATURAL GAS PRODUCTION. The Company's natural gas production for 1997
averaged 181.7 MMcf per day, an increase of approximately 69% from average
production of 107.7 MMcf per day during 1996, and an increase of approximately
50% from average production of 121 MMcf per day during 1995.
DOMESTIC PRODUCTION. The Company's domestic natural gas production for
1997 averaged 147.2 MMcf per day, an increase of approximately 37% from average
production of 107.7 MMcf per day during 1996, and an increase of approximately
22% from average production of 121 MMcf per day during 1995. The increase in the
Company's average domestic natural gas production for 1997, compared to 1996 and
1995, was related in large measure to production from the Company's East Cameron
Block 334 "E" platform, which commenced production in April 1997, and, to a
lesser extent, the results of successful drilling in the Company's Lopeno Field
in South Texas and its Eugene Island Block 261 field, that was only partially
offset by the anticipated natural decline in deliverability from certain of the
Company's properties. As of March 13, 1998, the Company was not a party to any
future natural gas sales contracts.
THAILAND PRODUCTION. The Company commenced production from its Tantawan
Field early in February 1997. Following a field startup phase which ended on
March 15, 1997, production from the Tantawan Field stabilized. During 1997, the
Company's share of natural gas production from the Tantawan Field averaged
approximately 37.7 MMcf per day.
CRUDE OIL AND CONDENSATE PRICES. Prices received by the Company for its
crude oil and condensate production averaged $19.37 per Bbl during 1997, a
decrease of approximately 12% compared to an average of $22.12 per Bbl during
1996, and an increase of approximately 9% compared to an average price of $17.80
per Bbl that the Company received during 1995.
DOMESTIC PRICES. Prices that the Company received for its domestic crude
oil and condensate production during 1997 averaged $19.49 per Bbl, a decrease of
approximately 12% from an average price of $22.12 per Bbl that the Company
received for its domestic crude oil and condensate production during 1996, and
an increase of approximately 9% from an average price of $17.80 per Bbl that the
Company received for its crude oil and condensate production during 1995.
THAILAND PRICES. Since the inception of production from the Tantawan
Field, crude oil and condensate has been stored on the FPSO until an economic
quantity was accumulated for offloading and sale. The first such sale of crude
oil and condensate from the Tantawan Field occurred in July 1997. The average
price that the Company recorded for its crude oil and condensate production
stored on the FPSO during 1997 was $18.60 per Bbl. Prices that the Company
receives for such production are based on world benchmark prices, which are
denominated in U.S. dollars, and are currently expected on future crude oil
sales to be paid in U.S. dollars.
CRUDE OIL AND CONDENSATE PRODUCTION. The Company's crude oil and
condensate production for 1997 averaged 15,927 Bbls per day, an increase of
approximately 33% from 11,968 Bbls per day for 1996, and an increase of
approximately 35% from 11,786 Bbls per day for 1995.
DOMESTIC PRODUCTION. The Company's domestic crude oil and condensate
production for 1997 averaged 13,711 Bbls per day, an increase of approximately
15% from 11,968 Bbls per day for 1996, and an increase of approximately 16% from
11,786 Bbls per day for 1995. The increase in the Company's crude oil and
condensate production for 1997, compared to 1996 and 1995, resulted primarily
from increased condensate production from wells located in the Gulf of Mexico
and, to a lesser extent, increased crude oil production from certain of the
Company's onshore properties, which was only partially offset by the natural
decline in deliverability from certain of the Company's more mature properties.
As of March 13, 1998, the Company was not a party to any crude oil swap
agreements.
29
THAILAND PRODUCTION. The Company commenced production from its Tantawan
Field early in February 1997. Following a field startup phase which ended on
March 15, 1997, production from the Tantawan Field stabilized. During 1997, the
Company's share of crude oil and condensate production from the Tantawan Field
averaged approximately 2,421 Bbls per day.
NGL PRODUCTION AND "OTHER" NET REVENUE ITEMS. The Company's oil and gas
revenues, and its total liquid hydrocarbon production, reflect the production
and sale by the Company of NGL, which are liquid products that are extracted
from natural gas production. In addition, the Company's oil and gas revenues for
1997, 1996 and 1995 also reflect adjustments for various miscellaneous items.
The Company's NGL and other, net revenues for 1997 increased $1,452,000 from
those reported in 1996, and $5,227,000 from those reported in 1995. The increase
in NGL and other, net revenues in 1997, compared with 1996, primarily related to
an increase in the Company's NGL production that was partially offset by a
decrease in the average price that the Company received for such NGL production.
The increase in NGL and other, net revenues in 1997, compared with 1995,
primarily related to an increase in the Company's NGL production and, to a
lesser extent, an increase in the price that the Company received for its NGL
production.
TOTAL LIQUID HYDROCARBON PRODUCTION. The Company's average liquid
hydrocarbon (including crude oil, condensate and NGL) production during 1997 was
18,851 Bbls per day, an increase of approximately 33% from an average total
liquids production of 14,141 Bbls per day for 1996, and an increase of
approximately 37% from an average total liquids production of 13,784 Bbls per
day for 1995.
OPERATING COSTS AND EXPENSES
LEASE OPERATING EXPENSES
Lease operating expenses for 1997 were $63,501,000, an increase of
approximately 69% from lease operating expenses of $37,628,000 for 1996, and an
increase of approximately 81% from lease operating expenses of $35,071,000 for
1995.
DOMESTIC LEASE OPERATING EXPENSES. The Company's domestic lease operating
expenses for 1997 were $43,934,000, an increase of approximately 17% from
domestic lease operating expenses of $37,628,000 for 1996, and an increase of
approximately 25% from domestic lease operating expenses of $35,071,000 for
1995. The increase in domestic lease operating expenses for 1997, compared to
1996 and 1995, resulted primarily from increased costs to the Company (and the
entire offshore oil industry) because of an increasing shortage of qualified
offshore service contractors, which has permitted such contractors to increase
the costs of their services significantly in the last year, increased expenses
related to the leasing of certain equipment in the Gulf of Mexico, a year to
year increase in the level of the Company's operating activities, including
increased operating costs related to additional properties brought on production
and an increased ownership interest in certain properties as a result of the
acquisition of such interests.
THAILAND LEASE OPERATING EXPENSES. The Company's lease operating expenses
in Thailand for 1997 were $19,567,000. Prior to the commencement of production
in the Tantawan Field on February 1, 1997, there were no lease operating
expenses incurred by the Company in Thailand as defined by generally accepted
accounting principles. A substantial portion of the Company's lease operating
expenses in the Kingdom of Thailand relate to lease payments made by a
subsidiary of the Company in connection with its bareboat charter of the FPSO,
which amounted to $10,200,000 during 1997. See "-- Liquidity and Capital
Resources; Capital Requirements; Other Material Long-Term Commitments."
GENERAL AND ADMINISTRATIVE EXPENSES
General and administrative expenses for 1997 were $21,412,000, an increase
of approximately 19% from general and administrative expenses of $18,028,000 for
1996, and an increase of approximately 31% from general and administrative
expenses of $16,400,000 for 1995. The increase in general and administrative
expenses for 1997, compared to 1996 and 1995, was primarily related to salary
and benefit expenses incurred in connection with the increase in the Company's
work force in its Bangkok, Thailand office as a result of the Company's
increased activities there.
30
EXPLORATION EXPENSES
Exploration expenses consist primarily of delay rentals and geological and
geophysical costs which are expensed as incurred. Exploration expenses for 1997
were $10,530,000, a decrease of approximately 37% from exploration expenses of
$16,777,000 for 1996, and an increase of approximately 41% from exploration
expenses of $7,468,000 for 1995. The decrease in exploration expenses for 1997,
compared to 1996, resulted primarily from the incurrence of costs associated
with conducting several 3-D seismic surveys by the Company on its leases in
South Louisiana, East Texas and the Permian Basin during 1996 for which no
similar costs of their magnitude were incurred during the comparative periods,
although such costs were partially offset in 1997 by the costs associated with
conducting the Jarmjuree 3-D seismic survey in the Gulf of Thailand and by
increased seismic data acquisition in the Gulf of Mexico. The increase in
exploration expenses for 1997, compared to 1995, resulted primarily from
increased geophysical activity by the Company, including the costs of conducting
and processing the Jarmjuree 3-D seismic survey. In addition, exploration
expenses attributable to increased delay rental expense resulting from the
Company's acquisition of additional prospective oil and gas acreage during 1997,
as compared to 1996 and 1995, served to offset the decrease in exploration
expenses for 1997, compared to 1996, and to increase the exploration expenses
incurred during 1997, compared to 1995. The Company does not currently expect
its exploration expenses in 1998 to increase significantly over those incurred
during 1997.
DRY HOLE AND IMPAIRMENT EXPENSES
Dry hole and impairment expenses relate to costs of unsuccessful wells
drilled along with impairments due to decreases in expected reserves from
producing wells. The Company's dry hole and impairment expenses for 1997 were
$9,631,000, an increase of approximately 12% from dry hole and impairment costs
of $8,579,000 for 1996, and an increase of approximately 44% from dry hole and
impairment costs of $6,703,000 for 1995.
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSES
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. Proved properties
are reviewed whenever events or changes in circumstances indicate that the value
of such property on the Company's books may not be recoverable. 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
based on capitalized costs as determined in the preceding paragraph, plus future
costs to abandon offshore wells and platforms, and is determined on a cost
center by cost center basis using the units of production method. The Company
generally creates cost centers on a field by field basis for oil and gas
activities in the Gulf of Mexico and the Gulf of Thailand. Generally, the
Company established cost centers on the basis of an oil or gas trend or play for
its oil and gas activities onshore in the United States. The Company's DD&A
expense for 1997 was $103,157,000, an increase of approximately 67% from DD&A
expenses of $61,857,000 for 1996, and an increase of approximately 51% from DD&A
expenses of $68,489,000 for 1995. The increase in the Company's DD&A expenses
for 1997, compared to 1996 and 1995, resulted primarily from an increase in the
Company's natural gas and liquid hydrocarbon production and, to a lesser extent,
an increase in the Company's composite DD&A rate.
The composite DD&A rate for all of the Company's producing fields for 1997
was $0.95 per equivalent Mcf ($5.68 per equivalent barrel), an increase of
approximately 9% from a composite DD&A rate of $0.87 per equivalent Mcf ($5.20
per equivalent barrel) for 1996, and an increase of approximately 3% from a
composite DD&A rate of $0.91 per equivalent Mcf ($5.47 per equivalent barrel)
for 1995. The increase in the composite DD&A rate for all of the Company's
producing fields for 1997, compared to 1996 and 1995, resulted primarily from an
increased percentage of the Company's production coming from
31
certain of the Company's fields that have DD&A rates that are higher than the
Company's recent historical composite rate and a corresponding decrease in the
percentage of the Company's production coming from fields that have DD&A rates
that are lower than the Company's recent historical composite DD&A rate.
Management currently anticipates that this trend will continue for the
foreseeable future, resulting in generally increasing DD&A rates. The Company
produced 107,605,000 equivalent Mcf (17,934,000 equivalent Bbls) in 1997, an
increase of approximately 53% from the 70,472,000 equivalent Mcf (11,745,000
equivalent Bbls) produced in 1996, and an increase of approximately 45% from the
74,337,000 equivalent Mcf (12,389,000 equivalent Bbls) produced in 1995.
INTEREST
INTEREST CHARGES. The Company incurred interest charges for 1997 of
$21,886,000, an increase of approximately 66% from interest charges of
$13,203,000 for 1996, and an increase of approximately 96% from interest charges
of $11,167,000 for 1995. The increase in the Company's interest charges for
1997, compared to 1996 and 1995, resulted primarily from an increase in the
average amount of the Company's outstanding debt and, to a lesser extent,
increased average interest rates on the debt outstanding (resulting primarily
from the issuance of the 2007 Notes on May 22, 1997, which bear interest at an
8 3/4% annual interest rate) and increased expenses related to amortization of
debt issuance expenses resulting from the issuance of the 2006 Notes in 1996.
CAPITALIZED INTEREST EXPENSE. Capitalized interest for 1997 was $6,175,000
an increase of approximately 46% from capitalized interest of $4,244,000 for
1996, and an increase of approximately 237% from capitalized interest of
$1,834,000 for 1995. The increase in capitalized interest for 1997, compared to
1996 and 1995, resulted primarily from the requirement to capitalize interest
expense attributable to capital expenditures on non-producing properties,
principally capital expenditures related to the Company's development of the
Tantawan Field and the East Cameron Block 334 "E" platform during the first
quarter of 1997 and its development of the Benchamas Field commencing in 1997,
which substantially exceeded the Company's capital expenditures on non-producing
properties (principally the Tantawan Field) during 1996 and 1995. To a lesser
extent, the increase in capitalized interest expense is also attributable to an
increase in the rate used to compute the interest that was capitalized. The
Company expects its capitalized interest costs to increase in the future,
primarily as a result of the requirement to capitalize interest expense
attributable to capital expenditures incurred in connection with its development
of the Benchamas Field in the Gulf of Thailand. See "Business -- International
Operations; Significant International Operating Areas During 1997; Benchamas
Field and the Maliwan Production Area".
FOREIGN CURRENCY TRANSACTION LOSS
The Company incurred a foreign currency transaction loss of $7,604,000
during 1997. No comparable losses were incurred in 1996 or 1995. The foreign
currency transaction loss resulted from the devaluation against the U.S. dollar
of cash and other monetary assets and liabilities denominated in Thai Baht that
were on the Company's subsidiary's financial statements during 1997. In early
July 1997, the government of the Kingdom of Thailand announced that the value of
the Thai Baht would be set against the U.S. dollar and other currencies under a
"managed float" program arrangement. Since that time the value of the Thai
Baht has generally declined, although in recent weeks it has shown some sign of
stabilizing. During the last two weeks of the month of February 1998, the Thai
Baht traded in a range of approximately 43 to 48 Thai Baht to the U.S. dollar.
The Company cannot predict what the Thai Baht to U.S. dollar exchange rate may
be in the future. Moreover, it is anticipated that this exchange rate will
remain volatile.
INCOME TAX EXPENSE
Income tax expense for 1997 was $18,091,000, a decrease of approximately 4%
from income tax expense of $18,800,000 for 1996, and an increase of
approximately 270% from income tax expense of $4,891,000 for 1995. The decrease
in income tax expense for 1997, compared to 1996, resulted primarily from the
foreign currency transaction loss discussed in the preceding paragraph, which
was partially offset by increased taxable income. The increase in income tax
expense for 1997, compared to 1995, resulted primarily from increased taxable
income.
32
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The Company's Consolidated Statement of Cash Flows for the year ended
December 31, 1997, reflects net cash provided by operating activities of
$150,732,000. In addition to the net cash provided by operating activities, the
Company received net proceeds of $96,835,000 from the issuance of the 2007 Notes
on May 22, 1997, $3,874,000 from the exercise of stock options and $387,000 from
the sale of certain non-strategic properties and had net borrowings of
$2,000,000 under its revolving credit agreement and uncommitted money market
credit lines with certain banks.
During 1997, the Company invested $197,326,000 of such cash flow in capital
projects during 1997, purchased certain oil and gas properties for $31,234,000
and paid $4,012,000 ($0.03 per share for four quarters) in cash dividends to
holders of the Company's Common Stock. Of the $197,326,000 invested in capital
projects, $56,961,000 was applicable to 1996 projects and $140,365,000 was
applicable to 1997 capital projects. As of December 31, 1997, the Company had
$19,646,000 in cash and cash investments.
FUTURE CAPITAL REQUIREMENTS
The Company's capital and exploration budget for 1998, which does not
include any amounts which may be expended for the purchase of proved reserves or
any interest which may be capitalized resulting from projects in progress, has
been established by the Company's Board of Directors at $230,000,000, an
increase of approximately 6% from the Company's capital and exploration
expenditures (excluding purchased reserves and interest capitalized) of
$217,729,000 for 1997, an increase of approximately 12% over capital and
exploration expenditures (excluding purchased reserves and interest capitalized)
of $206,207,000 for 1996, and an increase of approximately 135% over capital and
exploration expenditures (excluding purchased reserves and interest capitalized)
of approximately $97,910,000 for 1995.
In addition to anticipated capital and exploration expenses, other material
1998 cash requirements that the Company currently anticipates include ongoing
operating, general and administrative, income tax, interest expense and the
payment of dividends on its Common Stock, including a $0.03 per share dividend
on its Common Stock paid on February 27, 1998, to stockholders of record on
February 13, 1998. The Company currently anticipates that cash provided by
operating activities and funds available under its Credit Agreement and
uncommitted money market credit lines will be sufficient to fund the Company's
ongoing expenses, its 1998 capital and exploration budget and anticipated future
dividend payments. The declaration and payment of future dividends will depend
upon, among other things, the Company's future earnings and financial condition,
liquidity and capital requirements, the general economic and regulatory climate
and other factors deemed relevant by the Company's Board of Directors.
OTHER MATERIAL LONG-TERM COMMITMENTS
As of February 9, 1996, Tantawan Services, LLC ("TS"), a company that is
currently a wholly owned subsidiary of the Company, entered into a Bareboat
Charter Agreement (the "Charter") with Tantawan Production B.V. for the
charter of the FPSO for use in the Tantawan Field. See
"Business -- International Operations." The term of the Charter is for a
period ending July 31, 2008, subject to extension. In addition, TS has a
purchase option on the FPSO throughout the term of the Charter. TS has also
contracted with another company, SBM Marine Services Thailand Ltd., to operate
the FPSO on a reimbursable basis throughout the initial term of the Charter.
Performance of both the Charter and the agreement to operate the FPSO are
non-recourse to TS and the Company. However, performance is secured by a
negative pledge on any hydrocarbons stored on the FPSO and is guaranteed by each
of the working interest holders in the Tantawan Field, including Thaipo.
Thaipo's guarantee is limited to its percentage interest in the Tantawan Field
(currently 46.34%). The Charter currently provides for an estimated charter hire
commitment of $24,000,000 per year ($11,122,000 net to Thaipo).
33
CAPITAL STRUCTURE
CREDIT AGREEMENT AND UNCOMMITTED CREDIT LINES
Effective August 1, 1997, the Company entered into an amended and restated
credit agreement (as so amended and restated, "Credit Agreement"). The Credit
Agreement provides for an unsecured $250,000,000 revolving/term credit facility
which will be fully revolving until July 1, 2000, after which the balance will
be due in eight quarterly term loan installments, commencing October 31, 2000.
The amount that may be borrowed under the Credit Agreement may not exceed a
borrowing base which is composed of both domestic and Thai properties less, in
certain circumstances, the present value of interest payments on the 2007 Notes.
The domestic borrowing base is determined semi-annually by the lenders in
accordance with the Credit Agreement, based primarily on the discounted present
value of future net revenues from the Company's domestic oil and gas reserves.
The portion of the borrowing base which is composed of properties located in the
Kingdom of Thailand is also determined semi-annually, but may, at the lenders'
discretion, be redetermined once more during each semi-annual period. As of
March 13, 1998, the Company's total borrowing base, including both domestic and
Thai properties, exceeded $250,000,000. The Credit Agreement is governed by
various financial and other covenants, including requirements to maintain
positive working capital (excluding current maturities of debt) and a fixed
charge coverage ratio, and limitations on indebtedness, creation of liens, the
prepayment of subordinated debt, the payment of dividends, mergers and
consolidations, investments and asset dispositions. See "Market for the
Registrant's Common Stock and Related Security Holder Matters." In addition,
the Company is prohibited from pledging borrowing base properties as security
for other debt. Borrowings under the Credit Agreement currently bear interest at
a base (prime) rate or LIBOR plus 5/8%, at the Company's option. A commitment
fee on the unborrowed amount under the Credit Agreement is also charged. The
commitment fee is currently 0.25% per annum on the unborrowed amount under the
Credit Agreement that is designated as "active" and 0.10% per annum on the
unborrowed amount under the Credit Agreement that is designated as "inactive."
Of the $250,000,000 that is currently available under the Credit Agreement
(subject to borrowing base limitations), $125,000,000 is designated as
"active" and $125,000,000 is designated as "inactive."
As of March 13, 1998, the Company had also entered into separate letter
agreements with two banks under which one of the banks may provide a $10,000,000
uncommitted money market line of credit and the other bank may provide a
$20,000,000 uncommitted money market line of credit. Each line of credit is on
an as available or offered basis and neither bank has an obligation to make any
advances under its respective line of credit. Although loans made under these
letter agreements are for a maximum term of 30 days, they are reflected as
long-term debt on the Company's balance sheet because the Company currently has
the ability and intent to reborrow such amounts under its Credit Agreement. Both
letter agreements permit either party to terminate such letter agreement at any
time. Under its Credit Agreement, the Company is currently limited to incurring
a maximum of $20,000,000 of additional senior debt, which would include debt
incurred under these lines of credit. Further, the 2007 Notes also restrict the
incurrence of additional senior indebtedness. See "; 2007 Notes." As of March
1, 1998, indebtedness in the amount of $56,000,000 was outstanding under the
Credit Agreement and the two letter agreements.
2007 NOTES
On May 22, 1997, the Company issued $100,000,000 principal amount of 2007
Notes. The proceeds from the issuance of the 2007 Notes were used to repay
amounts outstanding under the Credit Agreement, and to purchase short-term cash
investments. The 2007 Notes bear interest at a rate of 8 3/4%, payable semi-
annually in arrears on May 15 and November 15 of each year, commencing November
15, 1997. The 2007 Notes are general unsecured senior subordinated obligations
of the Company and are subordinated in right of payment to the Company's senior
indebtedness, which currently includes the Company's obligations under its bank
revolving credit agreement and its unsecured credit lines, but are senior in
right of payment to its subordinated indebtedness, which currently includes the
2006 Notes and the 2004 Notes. The Company, at its option, may redeem the 2007
Notes in whole or in part, at any time on or after May 15, 2002, at a redemption
price of 104.375% of their principal value and decreasing percentages
thereafter. No
34
sinking fund payments are required on the 2007 Notes. The 2007 Notes are
redeemable at the option of any holder, upon the occurrence of a change of
control (as defined in the indenture governing the 2007 Notes), at 101% of their
principal amount. The indenture governing the 2007 Notes also imposes certain
covenants on the Company that are customary for senior subordinated indebtedness
generally, including covenants limiting: incurrence of indebtedness including
senior indebtedness; restricted payments; the issuance and sales of restricted
subsidiary capital stock; transactions with affiliates; liens; disposition of
proceeds of assets sales; non-guarantor restricted subsidiaries; dividends and
other payment restrictions affecting restricted subsidiaries; and mergers,
consolidations and the sale of assets.
2004 NOTES
The Company's 2004 Notes were called for redemption on March 16, 1998, at a
price equal to 103.30% of their principal amount. Prior thereto, holders of all
but $95,000 principal amount of the 2004 Notes chose to convert their 2004 Notes
into Common Stock at a conversion price of $22.188 per common share, rather than
receive cash for their 2004 Notes resulting in the issuance of 3,879,726 shares
of Common Stock.
2006 NOTES
The outstanding principal amount of 2006 Notes was $115,000,000 as of
December 31, 1997. The 2006 Notes are convertible into Common Stock at $42.185
per share, subject to adjustment upon the occurrence of certain events. The 2006
Notes will be redeemable at the option of the Company, in whole or in part, at
any time on or after June 15, 1999, at a redemption price of 103.85% of their
principal amount and decreasing percentages thereafter. No sinking fund payments
are required on the 2006 Notes. The 2006 Notes are redeemable at the option of
the holder, upon the occurrence of a repurchase event (a change of control and
other circumstances as defined in the indenture governing the 2006 Notes), at
100% of the principal amount.
OTHER MATTERS
INFLATION
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 U.S. dollar is running much below the general
annual inflation rates experienced in the past. While the Company, like other
companies, continues to be affected by fluctuations in the purchasing power of
the U.S. dollar, such effect is not currently considered significant.
SOUTHEAST ASIA ECONOMIC ISSUES
A substantial portion of the Company's oil and gas operations are conducted
in Southeast Asia, and a substantial portion of its natural gas and liquid
hydrocarbon production are sold there. In recent months, Southeast Asia in
general, and the Kingdom of Thailand in particular, have experienced severe
economic difficulties which have been characterized by sharply reduced economic
activity, illiquidity, highly volatile foreign currency exchange rates and
unstable stock markets. The government of the Kingdom of Thailand and other
governments in the region are currently acting to address these issues. However,
the economic difficulties currently being experienced in Thailand, together with
the volatility of the Thai Baht against the U.S. dollar, will continue to have a
material impact on the Company's operations in the Kingdom of Thailand, together
with the prices that the Company receives for its oil and natural gas production
there. See "-- Results of Operations; Income and Revenue Data" and
"-- Results of Operations; Operating Costs and Expenses; Foreign Currency
Transaction Loss."
All of the Company's current natural gas production from the Thailand
Concession is committed under a long term Gas Sales Agreement to PTT at a price
denominated in Thai Baht which is determined in accordance with a formula that
is intended to ameliorate, at least in part, any decline in the purchasing power
of the Thai Baht against the U.S. dollar. See "Business -- International
Operations; Contractual Terms Governing the Thailand Concession" and
"Business -- Miscellaneous; Sales." Although the
35
Company currently believes that PTT will honor its commitments under the Gas
Sales Agreement, a failure by PTT to honor such commitments could have a
material adverse effect on the Company.
The Company's crude oil and condensate production from the Thailand
Concession is sold on a tanker load by tanker load basis. Prices that the
Company receives for such production are based on world benchmark prices, which
are denominated in U.S. dollars, and are currently expected on future crude oil
sales to be paid in U.S. dollars. See "Business -- International Operations;
Contractual Terms Governing the Thailand Concession and Related Production" and
"Business -- Miscellaneous; Sales." The Company believes that the current
economic difficulties in Southeast Asia have resulted in a decreased demand for
petroleum products in the region, which has contributed to the recent general
decline in crude oil and condensate prices throughout the world. This price
decline has had an adverse effect on all oil and gas companies that sell their
production on the world spot markets, including the Company, without regard to
where their respective production is located.
YEAR 2000 ISSUE
Many computer software systems, as well as certain hardware, were
structured to utilize a two-digit date field meaning that they may not be able
to properly recognize dates in the year 2000. This could result in significant
system failures. The Company has a process in place to identify potential year
2000 problems and implement solutions. The Company has addressed the year 2000
issue in those areas where replacement systems have been installed for other
business reasons. Where existing systems are expected to remain in place beyond
1999, the Company is implementing systems changes utilizing a combination of
internal and external resources. In addition, the Company intends to communicate
with its major suppliers and others with whom it conducts business to determine
that they will be able to resolve the year 2000 issue. While the Company
believes it will be able to resolve the year 2000 issue, if it is unable to
complete the required systems changes or if those with whom the Company conducts
business are unsuccessful in implementing solutions, the year 2000 issue could
have an adverse impact on the Company's operations and revenues. Based upon
current estimates, the Company believes that it will not incur material costs
during 1998 and 1999 to implement the necessary changes to existing systems.
These costs are being expensed as they are incurred.
36
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1997
POGO PRODUCING COMPANY AND SUBSIDIARIES
HOUSTON, TEXAS
37
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,
1997 and 1996, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1997. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Pogo Producing Company and
subsidiaries as of December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 13, 1998
38
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
----------------------------------
1997 1996 1995
---------- ---------- ----------
(EXPRESSED IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
Revenues:
Oil and gas..................... $ 285,200 $ 204,142 $ 157,459
Gains (losses) on sales......... 1,100 (165) 100
---------- ---------- ----------
Total...................... 286,300 203,977 157,559
---------- ---------- ----------
Operating Costs and Expenses:
Lease operating................. 63,501 37,628 35,071
General and administrative...... 21,412 18,028 16,400
Exploration..................... 10,530 16,777 7,468
Dry hole and impairment......... 9,631 8,579 6,703
Depreciation, depletion and
amortization.................. 103,157 61,857 68,489
---------- ---------- ----------
Total...................... 208,231 142,869 134,131
---------- ---------- ----------
Operating Income..................... 78,069 61,108 23,428
Interest:
Charges......................... (21,886) (13,203) (11,167)
Income.......................... 453 232 26
Capitalized..................... 6,175 4,244 1,834
Foreign Currency Transaction Loss.... (7,604) -- --
---------- ---------- ----------
Income Before Taxes and Extraordinary
Item............................... 55,207 52,381 14,121
---------- ---------- ----------
Income Tax Expense................... (18,091) (18,800) (4,891)
---------- ---------- ----------
Income Before Extraordinary Item..... 37,116 33,581 9,230
Extraordinary Loss on Early
Extinguishment of Debt, net of
taxes.............................. -- (821) --
---------- ---------- ----------
Net Income........................... $ 37,116 $ 32,760 $ 9,230
========== ========== ==========
Earnings per Share (restated for 1996
and 1995):
Basic
Before extraordinary
item.................... $ 1.11 $ 1.01 $ 0.28
Extraordinary item......... -- (0.02) --
---------- ---------- ----------
Net income................. $ 1.11 $ 0.99 $ 0.28
========== ========== ==========
Diluted
Before extraordinary
item.................... $ 1.06 $ 0.97 $ 0.28
Extraordinary item......... -- (0.02) --
---------- ---------- ----------
Net income................. $ 1.06 $ 0.95 $ 0.28
========== ========== ==========
Dividends per Common Share........... $ 0.12 $ 0.12 $ 0.12
========== ========== ==========
The accompanying notes to consolidated financial statements are an integral part
hereof.
39
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
--------------------------
1997 1996
------------ ------------
(EXPRESSED IN THOUSANDS)
ASSETS
Current Assets:
Cash and cash investments....... $ 19,646 $ 3,054
Accounts receivable............. 39,540 30,031
Other receivables............... 46,951 35,027
Inventory -- product............ 713 --
Inventories -- tubulars......... 8,334 6,165
Other........................... 4,087 641
------------ ------------
Total current assets....... 119,271 74,918
------------ ------------
Property and Equipment:
Oil and gas, on the basis of
successful efforts accounting
Proved properties being
amortized.............. 1,321,817 1,079,523
Unevaluated properties and
properties under
development, not being
amortized.............. 110,231 111,192
Other, at cost.................. 12,619 8,773
------------ ------------
1,444,667 1,199,488
Less -- accumulated
depreciation, depletion, and
amortization, including $6,004
and $4,822 respectively,
applicable to other property... 917,363 814,623
------------ ------------
527,304 384,865
------------ ------------
Other................................ 30,042 19,459
------------ ------------
$ 676,617 $ 479,242
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable -- operating
activities..................... $ 13,639 $ 7,676
Accounts payable -- investing
activities..................... 90,833 56,961
Accrued interest payable........ 3,130 1,957
Accrued payroll and related
benefits....................... 1,938 1,490
Other........................... 632 163
------------ ------------
Total current
liabilities............ 110,172 68,247
Long-Term Debt....................... 348,179 246,230
Deferred Federal Income Tax.......... 57,502 46,321
Deferred Credits..................... 14,658 11,162
------------ ------------
Total liabilities.......... 530,511 371,960
------------ ------------
Shareholders' Equity:
Preferred stock, $1 par;
2,000,000 shares authorized.... -- --
Common stock, $1 par;
100,000,000 shares authorized,
and 33,552,702 and 33,321,381
shares issued, respectively.... 33,553 33,321
Additional capital.............. 144,848 139,337
Retained earnings (deficit)..... (31,971) (65,075)
Treasury stock and other, at
cost........................... (324) (301)
------------ ------------
Total shareholders'
equity................. 146,106 107,282
------------ ------------
$ 676,617 $ 479,242
============ ============
The accompanying notes to consolidated financial statements are an integral part
hereof.
40
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
-------------------------------
1997 1996 1995
--------- --------- ---------
(EXPRESSED IN THOUSANDS)
Cash flows from operating activities:
Cash received from customers..... $ 272,004 $ 195,931 $ 164,065
Federal income taxes received.... 7,037 -- 6,000
Operating, exploration, and
general and administrative
expenses paid.................. (86,445) (74,512) (56,997)
Interest paid.................... (20,713) (12,960) (11,036)
Federal income taxes paid........ (19,500) 12,500) (6,000)
Other............................ (1,651) (3,061) 301
--------- --------- ---------
Net cash provided by
operating activities...... 150,732 92,898 96,333
--------- --------- ---------
Cash flows from investing activities:
Capital expenditures............. (197,326) (172,032) (96,403)
Purchase of proved reserves...... (31,234) -- (11,921)
Proceeds from the sale of
property and tubular stock..... 387 100 100
--------- --------- ---------
Net cash used in investing
activities................ (228,173) (171,932) (108,224)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from issuance of new
debt........................... 100,000 115,000 --
Borrowings under senior debt
agreements..................... 502,000 208,000 199,000
Payments under senior debt
agreements..................... (500,000) (201,000) (182,000)
Proceeds from exercise of stock
options........................ 3,874 3,378 1,717
Payment of cash dividends on
common stock................... (4,012) (3,979) (3,946)
Debt issue expenses paid......... (3,165) (3,116) --
Purchase of 8% debentures due
2005........................... -- (40,699) (450)
Principal payments of other
long-term debt obligations..... -- -- (871)
--------- --------- ---------
Net cash provided by
financing activities...... 98,697 77,584 13,450
--------- --------- ---------
Effect of exchange rate changes on
cash............................... (4,664) 23 --
--------- --------- ---------
Net increase (decrease) in cash and
cash investments................... 16,592 (1,427) 1,559
Cash and cash investments at the
beginning of the year.............. 3,054 4,481 2,922
--------- --------- ---------
Cash and cash investments at the end
of the year........................ $ 19,646 $ 3,054 $ 4,481
========= ========= =========
Reconciliation of net income to net
cash provided by operating
activities:
Net income....................... $ 37,116 $ 32,760 $ 9,230
Adjustments to reconcile net
income to net cash provided by
operating activities
Extraordinary losses on
early extinguishments of
debt, net of taxes........ -- 821 --
Foreign currency transaction
loss...................... 7,604 -- --
(Gains) losses on sales..... (1,100) 165 (100)
Depreciation, depletion and
amortization.............. 103,157 61,857 68,489
Dry hole and impairment..... 9,631 8,579 6,703
Interest capitalized........ (6,175) (4,244) (1,834)
Increase in deferred income
tax....................... 12,999 7,175 5,592
Change in assets and
liabilities:
(Increase) decrease in
accounts receivable... (12,483) (8,211) 7,095
Increase in
inventory -- product... (713) -- --
(Increase) decrease in
other current
assets................ (6,470) 81 23
Increase in other
assets................ (7,418) (5,228) (1,187)
Increase (decrease) in
accounts payable...... 8,998 (2,079) 1,942
Increase in accrued
interest payable...... 1,173 243 131
Increase in accrued
payroll and related
benefits.............. 448 251 2
Increase in other
current liability..... 469 60 63
Increase in deferred
credits............... 3,496 668 184
--------- --------- ---------
Net cash provided by operating
activities......................... $ 150,732 $ 92,898 $ 96,333
========= ========= =========
The accompanying notes to consolidated financial statements are an integral part
hereof.
41
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
TREASURY
RETAINED STOCK SHARE-
SHARES COMMON ADDITIONAL EARNINGS AND HOLDERS'
OUTSTANDING STOCK CAPITAL (DEFICIT) OTHER EQUITY
----------- ------- ---------- --------- -------- ---------
(DOLLARS EXPRESSED IN THOUSANDS)
BALANCE AT DECEMBER 31, 1994......... 32,810,261 $32,826 $ 130,675 $ (99,140) $ (324) $ 64,037
Net income........................... -- -- -- 9,230 -- 9,230
Exercise of stock options............ 181,136 181 2,206 -- -- 2,387
Dividends ($0.12 per common share)... -- -- -- (3,946) -- (3,946)
----------- ------- ---------- --------- -------- ---------
BALANCE AT DECEMBER 31, 1995......... 32,991,397 33,007 132,881 (93,856) (324) 71,708
Net income........................... -- -- -- 32,760 -- 32,760
Foreign currency translation gain.... -- -- -- -- 23 23
Exercise of stock options............ 274,714 274 4,924 -- -- 5,198
Shares issued in connection with the
Long-Term Incentive Plan........... 5,896 6 246 -- -- 252
Shares issued in connection with the
conversion of --
8% Debentures................... 32,898 33 1,267 -- -- 1,300
2004 Notes...................... 901 1 19 -- -- 20
Dividends ($0.12 per common share)... -- -- -- (3,979) -- (3,979)
----------- ------- ---------- --------- -------- ---------
BALANCE AT DECEMBER 31, 1996......... 33,305,806 33,321 139,337 (65,075) (301) 107,282
Net income........................... -- -- -- 37,116 -- 37,116
Foreign currency translation loss.... -- -- -- -- (23) (23)
Exercise of stock options............ 229,024 230 5,461 -- -- 5,691
Shares issued in connection with the
conversion of 2004 Notes........... 2,297 2 50 -- -- 52
Dividends ($0.12 per common share)... -- -- -- (4,012) -- (4,012)
----------- ------- ---------- --------- -------- ---------
BALANCE AT DECEMBER 31, 1997......... 33,537,127 $33,553 $ 144,848 $ (31,971) $ (324) $ 146,106
=========== ======= ========== ========= ======== =========
The accompanying notes to consolidated financial statements are an integral part
hereof.
42
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS --
Pogo Producing Company was incorporated in 1970. Pogo Producing Company and
its subsidiaries (the "Company") are 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 and internationally in the Gulf
of Thailand. The Company has interests in 101 lease blocks offshore Louisiana
and Texas, approximately 237,000 gross acres onshore in the United States and
approximately 734,000 gross acres offshore in the Kingdom of Thailand.
USE OF ESTIMATES --
The preparation of these financial statements require the use of certain
estimates by management in determining the Company's assets, liabilities,
revenues and expenses. Depreciation, depletion and amortization of oil and gas
properties and the impairment of oil and gas properties are determined using
estimates of proved oil and gas reserves. 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. 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.
PRINCIPLES OF CONSOLIDATION --
The consolidated financial statements include the accounts of Pogo
Producing Company and its subsidiary and affiliated companies, after elimination
of all significant intercompany transactions. Majority owned subsidiaries are
fully consolidated. Minority owned subsidiaries or affiliates are pro rata
consolidated in the same manner as the Company, and the oil and gas industry
generally, accounts for its operating or working interest in oil and gas joint
ventures.
PRIOR-YEAR RECLASSIFICATIONS --
Certain prior-year amounts have been reclassified to conform with the
current year presentation.
FOREIGN CURRENCY --
The U. S. Dollar is the functional currency for all areas of operations of
the Company. Accordingly, monetary assets and liabilities and items of income
and expense denominated in a foreign currency are remeasured to U. S. dollars at
the rate of exchange in effect at the end of each month and the resulting gains
or losses on foreign currency transactions are included in the consolidated
statements of income for the period.
INVENTORY -- PRODUCT
Crude oil and condensate from the Company's Tantawan field located in the
Kingdom of Thailand is produced into a floating production, storage and off
loading ("FPSO") system and sold periodically as an economic barge quantity is
accumulated. The product inventory at December 31, 1997 consists of
approximately 43,000 barrels of crude oil and condensate, net to the Company's
interest, and is carried at its estimated net realizable value of $16.67 per
barrel.
INVENTORY -- TUBULARS
Tubular Inventories consist primarily of goods used in the Company's
operations and are stated at the lower of average cost or market value.
43
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
INTEREST CAPITALIZED --
Interest costs related to financing major oil and gas projects in progress
are capitalized until the projects are evaluated or until production commences
if the projects are evaluated as successful.
EARNINGS PER SHARE --
In 1997, the Company adopted the Financial Accounting Standards Board's
Statement of Financial Accounting Standards No. 128, Earnings Per Share ("SFAS
128"). Prior years have been restated in conformity with the provisions of SFAS
128. Earnings per common share (basic earnings per share) are based on the
weighted average number of shares of common stock outstanding during the
periods. Earnings per common share and potential common share (diluted earnings
per share) consider the effect of dilutive securities as set out below in
thousands, except per share amounts.
FOR THE YEAR ENDED
DECEMBER 31, 1997
------------------------------
INCOME SHARES PER SHARE
------- ------ ---------
BASIC EARNINGS PER SHARE............. $37,116 33,421 $ 1.11
Effect of potential dilutive
securities:
Shares assumed issued from the
exercise of options to
purchase common shares, net of
treasury shares assumed
purchased from the proceeds,
at the average market price
for the period................ -- 758 --
Interest expense avoided, net of
taxes, and shares issued from
the assumed conversion at
$22.188 per share of the 2004
Notes......................... 3,082 3,885
------- ------ ---------
DILUTED EARNINGS PER SHARE........... $40,198 38,064 $ 1.06
======= ====== =========
Antidilutive securities:
Shares assumed not issued from
options to purchase common
shares as the exercise prices
are above the average market
price for the period.......... -- 471 $ 40.82
Interest expense incurred, net
of taxes, and shares not
issued related to the assumed
non-conversion at $42.185 per
share of the 2006 Notes....... $ 4,111 2,726 $ 1.51
44
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEAR ENDED DECEMBER 31,
1996
--------------------------------
INCOME(A) SHARES PER SHARE
--------- ------ ---------
BASIC EARNINGS PER SHARE............. $33,581 33,203 $ 1.01
Effect of potential dilutive
securities:
Shares issued from the assumed
exercise of options to
purchase common shares, net of
treasury shares assumed
purchased from the proceeds,
at the average market price
for the period................ -- 831 --
Interest expense avoided, net of
taxes, and shares issued from
the assumed conversion at
$22.188 per share of the 2004
Notes......................... 3,083 3,886
--------- ------ ---------
DILUTED EARNINGS PER SHARE........... $36,664 37,920 $ 0.97
========= ====== =========
(a) Computed on income before
extraordinary item
Antidilutive securities:
Shares assumed not issued from
options to purchase common
shares as the exercise prices
are above the average market
price for the period.......... -- 20 $ 40.94
Interest expense incurred, net
of taxes, and shares not
issued related to the assumed
non-conversion at $39.50 per
share of the 8% Debentures,
retired on
June 28, 1996................. $ 1,179 521 $ 2.26
Interest expense incurred, net of
taxes, and shares not issued
related to the assumed
non-conversion at $42.185 per share
of the 2006 Notes.................. $ 2,238 1,472 $ 1.52
FOR THE YEAR ENDED DECEMBER
31, 1995
------------------------------
INCOME SHARES PER SHARE
------- ------ ---------
BASIC EARNINGS PER SHARE............. $ 9,230 32,893 $ 0.28
Effect of potential dilutive
securities:
Shares issued from the assumed
exercise of options to
purchase common shares, net of
treasury shares assumed
purchased from the proceeds,
at the average market price
for the period................ -- 597 --
------- ------ ---------
DILUTED EARNINGS PER SHARE........... $ 9,230 33,490 $ 0.28
======= ====== =========
Antidilutive securities:
Shares assumed not issued from
options to purchase common
shares as the exercise prices
are above the average market
price for the period.......... -- 598 $ 22.13
Interest expense incurred, net
of taxes, and shares not
issued related to the assumed
non-conversion at $39.50 per
share of the 8% Debentures.... $ 2,229 1,085 $ 2.05
Interest expense incurred, net
of taxes, and shares not
issued related to the assumed
non-conversion at $22.188 per
share of the 2004 Notes....... $ 3,083 3,887 $ 0.79
45
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1997, the Company had taken approximately
3,751 MMcf of natural gas less than it was entitled to based on its interest in
those properties, and approximately 1,757 MMcf more than its entitlement on
other properties placing the Company at year end in a net under-delivered
position of approximately 1,994 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. Proved properties are reviewed
whenever events or changes in circumstances indicate that the value of such
property on the Company's books may not be recoverable. 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 based on the capitalized costs as determined
above, plus future costs to abandon offshore wells and platforms, and is on a
cost center by cost center basis using the units of production method. The
Company generally creates cost centers on a field by field basis for oil and gas
activities in the Gulf of Mexico and the Gulf of Thailand. Generally, the
Company establishes cost centers on the basis of an oil or gas trend or play for
its oil and gas activities onshore in the United States.
Other properties are depreciated using 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 Statements of Cash Flows.
Certain such noncash transactions are disclosed in the Consolidated Statements
of Shareholders' Equity relating to shares issued in connection with the
Long-Term Incentive Plan and the conversion of debentures into Common Stock in
1996 and 1997.
COMMITMENTS AND CONTINGENCIES --
The Company has commitments for operating leases for office space in
Houston, Midland and Bangkok and commitments for an operating lease and
operating expenses related to a floating production, storage and off-loading
vessel (FPSO) in the Gulf of Thailand. Rental expense for office space was
$1,440,000 in 1997, $1,054,000 in 1996, and $861,000 in 1995. Expenses for the
FPSO lease and related
46
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
operating costs were $14,809,000 in 1997. Future minimum office and FPSO lease
expenses and related FPSO operating expense payments (in thousands of dollars)
at December 31, 1997 are as follows:
1998................................. $ 17,826
1999................................. 17,830
2000................................. 17,758
2001................................. 17,758
2002................................. 16,611
Thereafter........................... 91,352
(2) INCOME TAXES
The components of income (loss) before income taxes for each of the three
years in the period ended December 31, 1997, are as follows (expressed in
thousands):
1997 1996 1995
--------- --------- ---------
United States........................ $ 62,953 $ 56,380 $ 16,899
Foreign.............................. (7,746) (3,999) (2,778)
--------- --------- ---------
Total........................... $ 55,207 $ 52,381 $ 14,121
========= ========= =========
The components of federal income tax expense (benefit) for each of the
three years in the period ended December 31, 1997, are as follows (expressed in
thousands):
1997 1996 1995
--------- --------- ---------
United States, current............... $ 16,000 $ 12,500 $ --
United States, deferred(a)........... 5,964 7,162 5,602
Foreign, deferred.................... (3,873) (862) (711)
--------- --------- ---------
Total........................... $ 18,091 $ 18,800 $ 4,891
========= ========= =========
- ------------
(a) Excludes $443,000 of deferred tax benefit on extraordinary loss of
$1,264,000 in 1996.
Total federal income tax expense (benefit) for each of the three years in
the period ended December 31, 1997, 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):
1997 1996 1995
--------- --------- ---------
Federal statutory income tax rate.... 35.0% 35.0% 35.0%
Increases (reductions) resulting
from:
Statutory depletion in excess of
tax basis....................... (0.2) (0.2) (2.2)
Foreign taxes................... (2.1) 1.1 1.6
Other........................... 0.1 -- 0.2
--------- --------- ---------
32.8% 35.9% 34.6%
========= ========= =========
Deferred income taxes are determined based upon the differences between the
financial statement and tax basis of the Company's assets and liabilities using
enacted tax rates in effect for the years in which the differences are expected
to reverse. Deferred tax assets are recognized if it is more likely than not
that the
47
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
future tax benefit will be realized. The principal components of the Company's
deferred income tax assets and liabilities include the following at December 31,
1997 and 1996 (expressed in thousands):
DECEMBER 31,
--------------------------
1997 1996
------------ ------------
Deferred tax liabilities:
Intangible drilling costs,
capitalized and amortized for
financial statement purposes
and deducted for income tax
purposes...................... $ 204,218 $ 184,981
Charges to property and
equipment, expensed for
financial statement purposes,
and capitalized and amortized
for income tax purposes....... 12,203 8,089
Interest charges, capitalized
and amortized for financial
statement purposes and
deducted for income tax
purposes...................... 19,762 21,046
------------ ------------
236,183 214,116
Deferred tax asset:
Differences in depletion and
depreciation rates used for
tangible assets for financial
and income tax purposes....... (178,681) (167,795)
------------ ------------
Net deferred tax liability........... $ 57,502 $ 46,321
============ ============
(3) LONG-TERM DEBT
Long-term debt and the amount due within one year at December 31, 1997 and
1996, consists of the following (dollars expressed in thousands):
DECEMBER 31,
----------------------
1997 1996
---------- ----------
Senior debt --
Bank revolving credit agreement
debt:
LIBO Rate based loans,
borrowings at December
31, 1997 and 1996 at
average interest rates
of 6.52% and 6.59%,
respectively............ $ 47,000 $ 22,000
Prime rate based loans,
borrowing at December
31, 1996 at an interest
rate of 8.25%........... -- 13,000
---------- ----------
Total bank revolving
credit agreement
debt............... 47,000 35,000
Uncommitted credit lines
with banks, borrowing at
December 31, 1996 at an
average interest rate of
7.0%.................... -- 10,000
---------- ----------
Total senior debt.................... 47,000 45,000
---------- ----------
Subordinated debt --
8 3/4% Senior subordinated
notes, due 2007 (issued
May 22, 1997)................. 100,000 --
5 1/2% Convertible subordinated
notes, due 2004............... 86,179 86,230
5 1/2% Convertible subordinated
notes, due 2006............... 115,000 115,000
---------- ----------
Total subordinated debt.............. 301,179 201,230
---------- ----------
Total debt........................... 348,179 246,230
---------- ----------
Amount due within one year -- ....... -- --
---------- ----------
Long-term debt....................... $ 348,179 $ 246,230
========== ==========
48
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Effective August 1, 1997, the Company entered into an amended and restated
credit agreement (as so amended and restated, the "Credit Agreement"). The
Credit Agreement provides for an unsecured $250,000,000 revolving/term credit
facility which will be fully revolving until July 1, 2000, after which the
balance will be due in eight quarterly term loan installments, commencing
October 31, 2000. The amount that may be borrowed under the Credit Agreement may
not exceed a borrowing base which is composed of both domestic and Thai
properties less, in certain circumstances, the present value of interest
payments on the 2007 Notes. The domestic borrowing base is determined
semiannually by the lenders in accordance with the Credit Agreement, based
primarily on the discounted present value of future net revenues from the
Company's domestic oil and gas reserves. The portion of the borrowing base which
composed of properties located in the Kingdom of Thailand is also determined
semiannually, but may, at the lenders' discretion, be redetermined once more
during each semiannual period. The value of this portion of the borrowing base
is determined by the lenders applying their usual and customary criteria for oil
and gas evaluation. As of January 1, 1998, the Company's total borrowing base,
including both domestic and Thai properties, exceeded $250,000,000. The Credit
Agreement is governed by various financial and other covenants, including
requirements to maintain positive working capital (excluding current maturities
of debt) and fixed charge coverage ratio, and limitations on indebtedness,
creation of liens, the prepayment of subordinated debt, the payment of
dividends, mergers and consolidation, investments and asset dispositions. In
addition, the Company is prohibited from pledging borrowing base properties as
security for other debt. Borrowings under the Credit Agreement currently bear
interest at a base (prime) rate or LIBOR plus 5/8%, at the Company's option. A
commitment fee on the unborrowed amount under the Credit Agreement is also
charged. The commitment fee is currently 0.25% per annum on the unborrowed
amount under the Credit Agreement that is designated as "active" and 0.10% per
annum on the unborrowed amount under the Credit Agreement that is designated as
"inactive." Of the $250,000,000 that is currently available under the Credit
Agreement (subject to borrowing base limitations), $125,000,000 is designated as
"active" and $125,000,000 is designated as "inactive".
The Company has also entered into separate letter agreements with two banks
under which one of the banks may provide a $10,000,000 uncommitted money market
line of credit and the other bank may provide a $20,000,000 uncommitted money
market line of credit. Each line of credit is on an as available or offered
basis and neither bank has an obligation to make any advances under its
respective line of credit. Although loans made under these letter agreements are
for a maximum term of 30 days, they will be reflected as long-term on the
Company's balance sheet because the Company has the ability and intent to
reborrow such amounts under its Credit Agreement. Both letter agreements permit
either party to terminate such letter agreement at any time.
On May 22, 1997, the Company issued $100,000,000 of 8 3/4% Senior
Subordinated Notes due 2007 (the "2007 Notes"). The proceeds from the issuance
of the 2007 Notes were used to repay amounts outstanding under the Company's
bank revolving credit agreement, and to purchase short-term cash investments.
The 2007 Notes bear interest at a rate of 8 3/4%, payable semiannually in
arrears on May 15 and November 15 of each year, commencing November 15, 1997.
The 2007 Notes are general unsecured senior subordinated obligations of the
Company and are subordinated in right of payment to the Company's senior
indebtedness, which currently includes the Company's obligations under its bank
revolving credit agreement and its unsecured credit lines, but are senior in
right of payment to its subordinated indebtedness, which currently includes the
2006 Notes and the 2004 Notes. The Company, at its option, may redeem the 2007
Notes in whole or in part, at any time on or after May 15, 2002, at a redemption
price of 104.375% of their principal value and decreasing percentages
thereafter. No sinking fund payments are required on the 2007 Notes. The 2007
Notes are redeemable at the option of any holder, upon the occurrence of a
change of control (as defined in the indenture governing the 2007 Notes), at
101% of their principal amount. The indenture governing the 2007 Notes also
imposes certain covenants on the Company that are customary for senior
subordinated indebtedness generally, including covenants limiting: incurrence of
indebtedness
49
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
including senior indebtedness; restricted payments; the issuance and sales of
restricted subsidiary capital stock; transactions with affiliates; liens;
disposition of proceeds of asset sales; non-guarantor restricted subsidiaries;
dividends and other payment restrictions affecting restricted subsidiaries; and
mergers, consolidations and the sale of assets. As of December 31, 1997,
$28,657,000 was available for dividends under this limitation, which is
currently the Company's most restrictive such covenant.
The 5 1/2% Convertible Subordinated Notes, due 2004 (the "2004 Notes")
are convertible into Common Stock at $22.188 per share subject to adjustment
upon the occurrence of certain events. The 2004 Notes will be redeemable at the
option of the Company, in whole or in part, at any time on or after March 15,
1998, at a redemption price of 103.3% and decreasing percentages thereafter. No
sinking fund is provided. The 2004 Notes are redeemable at the option of the
holder, upon the occurrence of a repurchase event (a change in control and other
circumstances, as defined), at 100% of the principal amount. On February 12,
1998, the Company announced its intent to redeem the 2004 Notes on March 16,
1998 at an amount equal to 103.3% of their principal amount plus accrued
interest. Holders may elect to convert the principal or any integral multiple of
a 2004 Note into common stock at $22.188 per share until close of business on
March 13, 1998.
The 5 1/2% Convertible Subordinated Notes, due 2006 (the "2006 Notes")
are convertible into Common Stock at $42.185 per share subject to adjustment
upon the occurrence of certain events. The 2006 Notes will be redeemable at the
option of the Company, in whole or in part, at any time on or after June 15,
1999, at a redemption price of 103.85% and decreasing percentages thereafter. No
sinking fund is provided. The 2006 Notes are redeemable at the option of the
holder, upon the occurrence of a repurchase event (a change in control and other
circumstances, as defined), at 100% of the principal amount.
Current maturities and sinking fund requirements during the next five years
in connection with the above long-term debt are none in 1998 and 1999,
$7,050,000 in 2000, $25,850,000 in 2001 and $14,100,000 in 2002. All of the
current maturities reflected above are related to the retirement of the
Company's bank debt. The Company has established a history of refinancing its
bank debt before scheduled maturity payments commence and expects to do so again
before the amortization of bank debt commences in 2000.
50
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(4) GEOGRAPHIC SEGMENT REPORTING
During 1997, the Company adopted the Financial and Accounting Standard's
Board's Statement of Financial Accounting Standards No. 131, Disclosures about
Segments of an Enterprise and Related Information ("SFAS 131"). Information
concerning the Company's revenues and long-lived assets as required by SFAS 131
is as follows (in thousands of dollars):
LONG-LIVED
REVENUES ASSETS
---------- -----------
AS OF AND FOR THE YEAR ENDED DECEMBER
31, 1997
United States................... $ 245,458 $ 366,638
Kingdom of Thailand............. 39,393 160,666
---------- -----------
$ 284,851 $ 527,304
========== ===========
AS OF AND FOR THE YEAR ENDED DECEMBER
31, 1996
United States................... $ 203,364 $ 295,108
Kingdom of Thailand............. -- 89,757
---------- -----------
$ 203,364 $ 384,865
========== ===========
AS OF AND FOR THE YEAR ENDED DECEMBER
31, 1995
United States................... $ 156,729 $ 232,527
Kingdom of Thailand............. -- 29,306
---------- -----------
$ 156,729 $ 261,833
========== ===========
(5) SALES TO MAJOR CUSTOMERS
The Company is an oil and gas exploration and production company that
generally sells its oil and gas to numerous customers on a month-to-month basis.
Sales to the following customers exceeded 10% of revenues during any one of the
three years indicated (expressed in thousands):
1997 1996 1995
--------- --------- ---------
Enron Corp. and affiliates........... $ 57,965 $ 58,101 $ 42,895
Petroleum Authority of Thailand
(PTT).............................. $ 30,108 $ -- $ --
Coastal Gas Marketing Company........ $ -- $ 18,376 $ 18,117
(6) CREDIT RISK
Substantially all of the Company's accounts receivable at December 31, 1997
and 1996, result from oil and gas sales and joint interest billings to other
companies in the oil and gas industry. This concentration of customers and joint
interest owners may impact the Company's overall credit risk, either positively
or negatively, in that these entities may be similarly affected by industry-wide
changes in economic or other conditions. Such receivables are generally not
collateralized. Historically, credit losses incurred by the Company on
receivables generally have not been material. No known material credit losses
were experienced during 1997 or 1996.
A substantial portion of the Company's oil and gas operations are conducted
in Southeast Asia, and a substantial portion of its natural gas and liquid
hydrocarbon production are sold there. In recent months, Southeast Asia in
general, and the Kingdom of Thailand in particular, have experienced severe
economic difficulties which have been characterized by sharply reduced economic
activity, illiquidity, highly volatile foreign currency exchange rates and
unstable stock markets. The government of the Kingdom of Thailand and other
governments in the region are currently acting to address these issues. However,
the economic difficulties currently being experienced in Thailand, together with
the volatility of the Thai Baht against the
51
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
U.S. dollar, will continue to have a material impact on the Company's operations
in the Kingdom of Thailand, together with the prices that the Company receives
for its oil and natural gas production there.
All of the Company's current natural gas production from its Thailand
operations committed under a long term Gas Sales Agreement to PTT at a price
denominated in Thai Baht. The Company's crude oil and condensate production from
its Thailand operations is sold on a tanker load by tanker load basis. Prices
that the Company receives for such production are based on world benchmark
prices, which are denominated in U.S. dollars, and are currently expected on
future crude oil sales to be paid in U.S. dollars. The Company believes that the
current economic difficulties in Southeast Asia have resulted in a decreased
demand for petroleum products in the region, which has contributed to the recent
general decline in crude oil and condensate prices throughout the world.
(7) EMPLOYEE BENEFITS
As permitted by SFAS No. 123, the Company applies APB Opinion No. 25 and
related interpretations in accounting for its stock option plans. Since the
exercise price of the options granted is equal to the quoted market price of the
Company's stock at the date of grant, no compensation cost has been recognized
for its stock option plans. Had compensation costs been determined based on the
fair value at the grant dates for awards made in 1997, 1996, and 1995 consistent
with the methods of SFAS No. 123, the Company's net income and earnings per
share would have been reduced to the pro forma amounts indicated below (in
thousands, except for per share amounts):
1997 1996 1995
--------- --------- ---------
Net income:
As reported..................... $ 37,116 $ 32,760 $ 9,230
Pro forma....................... $ 34,220 $ 31,194 $ 8,619
Earnings per share:
As reported (restated for 1996
and 1995) -- Basic............ $ 1.11 $ 0.99 $ 0.28
As reported (restated for 1996
and 1995) -- Diluted.......... $ 1.06 $ 0.95 $ 0.28
Pro forma -- Basic.............. $ 1.04 $ 0.94 $ 0.26
Pro forma -- Diluted............ $ 0.99 $ 0.91 $ 0.26
The fair value of grants was estimated on the date of grant using the Black
Scholes option pricing model with the following weighted-average assumptions
used in 1997, 1996, and 1995, respectively: risk-free interest rates of 6.10%,
6.25%, and 6.00%, expected volatility of 34.63%, 39.15%, and 41.78%, dividend
yields of 0.29%, 0.34%, and 0.54%, and an expected life of the options of 4
years in each of the years 1997, 1996, and 1995.
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, up to a maximum allowed by law ($10,000 for
1998), and the Company will then match the employee's contribution on a dollar
for dollar basis up to 6% of the employee's salary. 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. Amounts 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 $588,000 to the savings plan in 1997, $471,000 in
1996, and $277,000 in 1995.
The Company's stock option plans authorize the granting of options to key
employees and non-employee directors 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 of grant and, if not exercised,
52
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
expire 10 years from the date of grant. In 1996, the Company adopted the
Financial Accounting Standards Board's Statement of Financial Accounting
Standards No. 123, Accounting for Stock-Based Compensation ("SFAS No. 123").
As permitted by SFAS No. 123, the Company elected to continue to account for
employee stock-based compensation using the intrinsic value method prescribed by
Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to
Employees. Accordingly, the adoption of SFAS No. 123 had no effect on the
Company's results of operations in 1996 and 1997. A summary of the status of the
Company's plans as of December 31, 1997, 1996, and 1995, and changes during the
years ended on those dates is presented below:
WEIGHTED
AVERAGE
NUMBER OF EXERCISE
OPTIONS PRICE
--------- --------
Outstanding, December 31, 1994 1,387,537 $11.72
Granted......................... 389,000 $22.34
Exercised....................... (181,136) $ 9.48
Forfeited or expired............ (20,000) $14.88
---------
Outstanding, December 31, 1995....... 1,575,401 $14.56
=========
Exercisable, December 31, 1995....... 1,006,686 $10.87
=========
Available for grant, December 31,
1995............................... 1,719,893
=========
Weighted-average fair value of
options granted during 1995........ $ 8.77
Outstanding, December 31, 1995....... 1,575,401 $14.56
Granted......................... 406,500 $34.59
Exercised....................... (274,714) $12.30
---------
Outstanding, December 31, 1996....... 1,707,187 $19.70
=========
Exercisable, December 31, 1996....... 1,077,658 $14.31
=========
Available for grant, December 31,
1996............................... 1,313,393
=========
Weighted-average fair value of
options granted during 1996........ $13.56
Outstanding, December 31, 1996....... 1,707,187 $19.70
Granted......................... 480,400 $40.49
Exercised....................... (229,024) $16.83
---------
Outstanding, December 31, 1997....... 1,958,563 $25.13
=========
Exercisable, December 31, 1997....... 1,196,803 $18.15
=========
Available for grant, December 31,
1997............................... 832,993
=========
Weighted-average fair value of
options granted during 1997........ $14.63
53
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes information about stock options outstanding
at December 31, 1997:
OPTIONS OUTSTANDING
---------------------------------------
WEIGHTED OPTIONS EXERCISABLE
AVERAGE -----------------------
REMAINING WEIGHTED WEIGHTED
CONTRACTUAL AVERAGE AVERAGE
RANGE OF NUMBER LIFE EXERCISE NUMBER EXERCISE
OPTION PRICES OUTSTANDING (DAYS) PRICE EXERCISABLE PRICE
- ------------------------------------- ------------ ----------- -------- ----------- --------
$4.38........................... 92,750 12 $ 4.38 92,750 $ 4.38
$5.56 to $8.06.................. 349,361 1,107 $ 6.83 349,361 $ 6.83
$15.13 to $19.13................ 156,046 2,014 $16.46 156,046 $16.46
$20.31 to $23.88................ 484,838 2,620 $22.15 381,827 $22.17
$30.56 to $34.88................ 325,001 3,143 $33.91 102,319 $33.93
$35.13 to $38.94................ 82,667 3,150 $36.18 56,000 $36.03
$40.56 to $44.38................ 465,900 3,483 $40.80 58,500 $41.20
$48.75.......................... 2,000 3,306 $48.75 -- --
------------ -----------
Total........................... 1,958,563 2,493 $25.13 1,196,803 $18.15
============ ===========
54
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, 1997, 1996, and 1995.
1997 1996 1995
---------- --------- ---------
Actuarial present value (discounted
at 7%, 7 1/4%, and
7 1/4%, respectively) of benefit
obligations:
Accumulated benefit
obligations --
Vested..................... $ 7,355 $ 6,408 $ 5,488
Non-vested................. 1,536 1,138 1,173
---------- --------- ---------
Total accumulated benefit
obligations................ 8,891 7,546 6,661
Projected salary increases
(escalated at 5 1/2%, 5% and
5%, respectively) and other
changes....................... 2,329 1,804 1,734
---------- --------- ---------
Projected benefit obligations
for service rendered to
date.......................... 11,220 9,350 8,395
Plan assets at fair value, primarily
listed securities with an expected
long-term rate of return of 9 1/2%,
8 1/2% and 8 1/2%, respectively.... 31,312 24,181 19,089
---------- --------- ---------
Plan assets in excess of projected
benefit obligations................ 20,092 14,831 10,694
Unrecognized:
Net overfunding being recognized
over 15 years................. (336) (440) (543)
Net gain arising from the
difference between actual
experience and that assumed... (13,134) (9,335) (5,989)
Prior service cost.............. (300) (343) (387)
---------- --------- ---------
Accrued retirement plan asset........ $ 6,322 $ 4,713 $ 3,775
========== ========= =========
Retirement plan cost (benefit) for
1997, 1996, and 1995 included the
following components:
Service cost, benefits accruing
each year with proration for
future salary increases....... $ 746 $ 621 $ 480
Interest cost on projected
benefit obligations..... 707 604 535
Actual return on plan
assets..................... (2,286) (1,615) (1,182)
Net amortization and
deferral................... (775) (548) (333)
---------- --------- ---------
Accrued retirement plan cost
(benefit)..................... $ (1,608) $ (938) $ (500)
========== ========= =========
Although the Company has no obligation to do so, the Company currently
provides full medical benefits to its retired employees and dependents. For
current employees, the Company assumes all or a portion of post retirement
medical and term life insurance costs based on the employee's age and length of
service with the Company. The post retirement medical plan has no assets and is
currently funded by the Company on a pay-as-you-go basis.
55
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following is an analysis (in thousands of dollars) of the annual
expense and activity in the deferred cost and benefits obligation accounts for
1995, 1996 and 1997. The computation assumes that future increases in medical
costs will trend down from 8.1% to 5% per year over the next 7 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 post retirement benefit
cost for 1997 by $170,000 and the accumulated post retirement benefit obligation
as of December 31, 1997 by $1,104,000.
ANNUAL DEFERRED BENEFIT
EXPENSE COSTS OBLIGATION
------- -------- ----------
Balance at January 1, 1995.............. $3,349 $ (5,487)
Amortization of transition costs over 14
years representing the average
remaining service period of eligible
employees............................. $ 304 (304) 304
Amortization of net gain from earlier
periods............................... (69) (69)
Service cost, including interest........ 241
Interest cost on transition
obligation............................ 399
-------
1995 expense............................ $ 875 (875)
=======
Current benefits paid................... 145
Unrecognized net gain................... 541
-------- ----------
Balance at December 31, 1995............ 3,045 (5,441)
Amortization of transition costs over 14
years................................. $ 304 (304) 304
Amortization of net gain from earlier
periods............................... (41) (41)
Service cost, including interest........ 268
Interest cost on transition
obligation............................ 387
-------
1996 expense............................ $ 918 (918)
=======
Current benefits paid................... 94
Unrecognized net gain................... 107
-------- ----------
Balance at December 31, 1996............ 2,741 (5,895)
Amortization of transition costs over 14
years................................. $ 305 (305) 305
Amortization of net gain from earlier
periods............................... (26) (26)
Service cost, including interest........ 459
Interest cost on transition
obligation............................ 427
-------
1997 expense............................ $ 1,165 (1,165)
=======
Current benefits paid................... 99
Unrecognized net loss................... (224)
--------
Balance at December 31, 1997............ $2,436
========
Plan assets at fair value...............
----------
Funded status at December 31, 1997
(discounted at 7%).................... $ (6,906)
==========
The accumulated postretirement benefit obligation (in thousands of dollars)
at December 31, 1997 is attributable to the following groups:
Retirees and beneficiaries.............. $1,951
Dependents of retirees.................. 978
Fully eligible active employees......... 802
Active employees, not fully eligible.... 3,175
----------
$6,906
==========
56
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(8) 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
Fair value is carrying value as no cash equivalents or cash investments are
included in the balances as of December 31, 1997 and 1996.
DEBT
INSTRUMENT BASIS OF FAIR VALUE ESTIMATE
- --------------------------------------------------------------------------
Bank revolving credit agreement...... Fair value is carrying value as of
December 31, 1997 and 1996 based on
the market value interest rates.
Uncommitted credit lines with
banks.............................. Fair value is carrying value as of
December 31, 1997 and 1996 based on
the market value interest rates.
2007 Notes........................... Fair value is 102.5% of carrying
value as of December 31, 1997 based
on a quoted market value.
2004 Notes........................... Fair value is 140.38% and 166%, of
carrying value as of December 31,
1997 and 1996, respectively, based on
quoted market values.
2006 Notes........................... Fair value is 93.5% and 120%, of
carrying value as of December 31,
1997 and 1996, respectively, based on
quoted market values.
The carrying value and estimated fair value of the Company's financial
instruments at December 31, 1997 and 1996 (in thousands of dollars) are as
follows:
1997 1996
-------------------------- --------------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
------------ ------------ ------------ ------------
Cash and cash investments............ $ 19,646 $ 19,646 $ 3,054 $ 3,054
Debt:
Bank revolving credit
agreement..................... (47,000) (47,000) (35,000) (35,000)
Uncommitted credit lines with
banks......................... -- -- (10,000) (10,000)
2007 Notes...................... (100,000) (102,500) -- --
2004 Notes...................... (86,179) (120,978) (86,230) (143,142)
2006 Notes...................... (115,000) (107,525) (115,000) (138,000)
The Company occasionally enters into forward and futures contracts to
minimize the impact of oil and gas price fluctuations. However, the Company does
not consider its forward and futures contracts to be financial instruments since
these contracts require or permit settlement by the delivery of the underlying
commodity. Gains and losses on these activities are recognized in revenues when
the hedged production occurs. No such contracts were outstanding as of December
31, 1997 or 1996.
57
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)
1997
-----------------------------------
Revenues............................. $ 284,851 $245,458 $ 39,393
Lease operating expense.............. (63,501) (43,934) (19,567)
Exploration expense.................. (10,530) (6,242) (4,288)
Dry hole and impairment expense...... (9,631) (9,631) --
Depreciation, depletion and
amortization expense............... (101,273) (84,443) (16,830)
--------- -------- ----------
Pretax operating results............. 99,916 101,208 (1,292)
Income tax (expense) benefit......... (30,353) (32,390) 2,037
--------- -------- ----------
Operating results.................... $ 69,563 $ 68,818 $ 745
========= ======== ==========
1996
-----------------------------------
Revenues............................. $ 204,142 $204,131 $ 11
Lease operating expense.............. (37,628) (37,628) --
Exploration expense.................. (16,777) (14,247) (2,530)
Dry hole and impairment expense...... (8,579) (8,834) 255
Depreciation, depletion and
amortization expense............... (61,033) (60,932) (101)
--------- -------- ----------
Pretax operating results............. 80,125 82,490 (2,365)
Income tax (expense) benefit......... (27,905) (28,767) 862
--------- -------- ----------
Operating results.................... $ 52,220 $ 53,723 $ (1,503)
========= ======== ==========
1995
-----------------------------------
Revenues............................. $ 157,459 $157,536 $ (77)
Lease operating expense.............. (35,071) (35,071) --
Exploration expense.................. (7,468) (6,111) (1,357)
Dry hole and impairment expense...... (6,703) (6,703) --
Depreciation, depletion and
amortization expense............... (67,831) (67,798) (33)
--------- -------- ----------
Pretax operating results............. 40,386 41,853 (1,467)
Income tax (expense) benefit......... (13,623) (14,334) 711
--------- -------- ----------
Operating results.................... $ 26,763 $ 27,519 $ (756)
========= ======== ==========
58
UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED)
The following table sets forth the Company's capitalized costs (expressed
in thousands) incurred for oil and gas producing activities during the years
indicated.
1997 1996 1995
---------- ---------- ----------
Capitalized costs incurred:
Property acquisition -- United
States........................ $ 14,492 $ 5,927 $ 14,864
Property acquisition -- Kingdom
of Thailand................... 28,617 -- 4,171
Exploration -- United States.... 24,016 20,651 14,562
Exploration -- Kingdom of
Thailand...................... 21,187 8,317 5,418
Development -- United States.... 95,768 99,464 39,461
Development -- Kingdom of
Thailand...................... 60,996 53,564 23,994
Interest capitalized -- United
States........................ 3,331 4,244 1,834
Interest capitalized -- Kingdom
of Thailand................... 2,748 -- --
---------- ---------- ----------
$ 251,155 $ 192,167 $ 104,304
========== ========== ==========
Provision for depreciation, depletion
and amortization:
United States................... $ 85,104 $ 61,033 $ 67,798
Kingdom of Thailand............. 16,830 101 33
---------- ---------- ----------
$ 101,934 $ 61,134 $ 67,831
========== ========== ==========
59
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. The
definitions and assumptions that served as the basis for the discussions under
the caption "Item 1. Business -- Exploration and Production Data -- Reserves"
should be referred to in connection with the following information.
ESTIMATES OF PROVED RESERVES
TOTAL COMPANY UNITED STATES KINGDOM OF THAILAND
----------------------- ----------------------- -----------------------
OIL OIL OIL
CONDENSATE CONDENSATE CONDENSATE
& NATURAL NATURAL & NATURAL NATURAL & NATURAL NATURAL
GAS LIQUIDS GAS GAS LIQUIDS GAS GAS LIQUIDS GAS
(BBLS.) (MMCF) (BBLS.) (MMCF) (BBLS.) (MMCF)
----------- -------- ----------- -------- ----------- --------
Proved Reserves as of December 31,
1994................................. 33,861,612 242,890 26,187,240 186,151 7,674,372 56,739
Revisions of previous
estimates...................... 496,849 21,800 363,213 16,592 133,636 5,208
Extensions, discoveries and other
additions...................... 11,901,880 78,434 4,267,871 35,058 7,634,009 43,376
Purchase of properties........... 4,015,131 30,054 460,156 3,770 3,554,975 26,284
Sale of properties............... (15,144) (748) (15,144) (748) -- --
Estimated 1995 production........ (5,078,326) (44,369) (5,078,326) (44,369) -- --
----------- -------- ----------- -------- ----------- --------
Proved Reserves as of December 31,
1995............................... 45,182,002 328,061 26,185,010 196,454 18,996,992 131,607
Revisions of previous
estimates...................... (499,595) (30,034) 3,374,647 3,022 (3,874,242) (33,056)
Extensions, discoveries and other
additions...................... 9,810,363 102,039 3,601,333 55,592 6,209,030 46,447
Purchase of properties........... -- -- -- -- -- --
Sale of properties............... -- -- -- -- -- --
Estimated 1996 production........ (4,890,588) (39,122) (4,890,588) (39,122) -- --
----------- -------- ----------- -------- ----------- --------
Proved Reserves as of December 31,
1996............................... 49,602,182 360,944 28,270,402 215,946 21,331,780 144,998
Revisions of previous
estimates...................... 1,033,664 (16,860) 2,194,936 (5,582) (1,161,272) (11,278)
Extensions, discoveries and other
additions...................... 9,316,407 92,063 4,649,856 49,651 4,666,551 42,412
Purchase of properties........... 5,175,501 30,319 409,428 8,919 4,766,073 21,400
Sale of properties............... (6,155) (1,864) (6,155) (1,864) -- --
Estimated 1997 production........ (6,957,246) (63,114) (6,136,957) (50,350) (820,289) (12,764)
----------- -------- ----------- -------- ----------- --------
Proved Reserves as of December 31,
1997............................... 58,164,353 401,488 29,381,510 216,720 28,782,843 184,768
=========== ======== =========== ======== =========== ========
Proved developed reserves as of:
December 31, 1994................ 24,669,755 178,518 24,669,755 178,518 -- --
December 31, 1995................ 22,487,608 164,679 22,487,608 164,679 -- --
December 31, 1996................ 31,090,407 238,032 25,898,414 192,034 5,191,993 45,998
December 31, 1997................ 33,149,612 239,732 26,167,519 179,972 6,982,093 59,760
60
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
--------- --------- -----------
(EXPRESSED IN THOUSANDS)
1997
---------------------------------------
Future gross revenues................ $1,801,254 $1,002,609 $ 798,645
Future production costs:
Lease operating expense......... (604,665) (269,505) (335,160)
Future development and abandonment
costs.............................. (401,970) (155,179) (246,791)
--------- --------- -----------
Future net cash flows before income
taxes.............................. 794,619 577,925 216,694
Discount at 10% per annum............ (331,838) (171,764) (160,074)
--------- --------- -----------
Discounted future net cash flow
before income taxes................ 462,781 406,161 56,620
Future income taxes, net of discount
at 10% per annum................... (113,316) (93,386) (19,930)
--------- --------- -----------
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves........ $ 349,465 $ 312,775 $ 36,690
========= ========= ===========
1996
---------------------------------------
Future gross revenues................ $2,318,113 $1,491,057 $ 827,056
Future production costs:
Lease operating expense......... (504,899) (259,501) (245,398)
Future development and abandonment
costs.............................. (310,839) (126,086) (184,753)
--------- --------- -----------
Future net cash flows before income
taxes.............................. 1,502,375 1,105,470 396,905
Discount at 10% per annum............ (547,830) (332,343) (215,487)
--------- --------- -----------
Discounted future net cash flow
before income taxes................ 954,545 773,127 181,418
Future income taxes, net of discount
at 10% per annum................... (268,505) (212,906) (55,599)
--------- --------- -----------
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves........ $ 686,040 $ 560,221 $ 125,819
========= ========= ===========
1995
---------------------------------------
Future gross revenues................ $1,495,320 $ 873,578 $ 621,742
Future production costs:
Lease operating expense......... (415,829) (208,477) (207,352)
Future development and abandonment
costs.............................. (247,019) (119,821) (127,198)
--------- --------- -----------
Future net cash flows before income
taxes.............................. 832,472 545,280 287,192
Discount at 10% per annum............ (299,997) (144,435) (155,562)
--------- --------- -----------
Discounted future net cash flow
before income taxes................ 532,475 400,845 131,630
Future income taxes, net of discount
at 10% per annum................... (155,330) (104,864) (50,466)
--------- --------- -----------
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves........ $ 377,145 $ 295,981 $ 81,164
========= ========= ===========
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.
61
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL
AND GAS RESERVES -- UNAUDITED -- (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. These cost estimates are subject to some
uncertainty, particularly those estimates relating to the Company's
properties located in the Kingdom of Thailand.
The standardized measure of discounted future net cash flows does not
purport to present the fair market value of the Company's oil and gas reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves 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 and the Kingdom of Thailand, as noted.
YEAR ENDED DECEMBER 31, 1997
------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
--------- --------- ----------
(EXPRESSED IN THOUSANDS)
Beginning balance.................... $ 686,040 $ 560,221 $ 125,819
Revisions to prior years' proved
reserves:
Net changes in prices and
production costs.............. (473,086) (344,493) (128,593)
Net changes due to revisions in
quantity estimates............ (18,624) 9,619 (28,243)
Net changes in estimates of
future development costs...... (83,170) (75,649) (7,521)
Accretion of discount........... 95,455 77,313 18,142
Changes in production rate...... (2,907) 8,568 (11,475)
Other........................... (28,225) (13,086) (15,139)
--------- --------- ----------
Total revisions............ (510,557) (337,728) (172,829)
New field discoveries and extensions,
net of future production and
development costs.................. 79,258 76,687 2,571
Purchases of properties.............. 10,189 5,899 4,290
Sales of properties.................. (6,069) (6,069) --
Sales of oil and gas produced, net of
production costs................... (221,350) (201,524) (19,826)
Previously estimated development
costs incurred..................... 156,764 95,768 60,996
Net change in income taxes........... 155,190 119,521 35,669
--------- --------- ----------
Net change in standardized
measure of discounted
future net cash flows.... (336,575) (247,446) (89,129)
--------- --------- ----------
Ending balance....................... $ 349,465 $ 312,775 $ 36,690
========= ========= ==========
62
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL
AND GAS RESERVES -- UNAUDITED -- (CONTINUED)
YEAR ENDED DECEMBER 31, 1996
------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
--------- --------- ----------
(EXPRESSED IN THOUSANDS)
Beginning balance....................... $ 377,145 $ 295,981 $ 81,164
Revisions to prior years' proved
reserves:
Net changes in prices and production
costs.............................. 304,233 289,182 15,051
Net changes due to revisions in
quantity estimates................. 6,717 53,708 (46,991)
Net changes in estimates of future
development costs.................. (132,685) (79,791) (52,894)
Accretion of discount................. 53,248 40,085 13,163
Changes in production rate............ (59,714) (35,762) (23,952)
Other................................. (12,760) (2,831) (9,929)
--------- --------- ----------
Total revisions.................... 159,039 264,591 (105,552)
New field discoveries and extensions,
net of future production and
development costs..................... 275,738 173,962 101,776
Sales of oil and gas produced, net of
production costs...................... (165,736) (165,736) --
Previously estimated development costs
incurred.............................. 153,028 99,464 53,564
Net change in income taxes.............. (113,174) (108,041) (5,133)
--------- --------- ----------
Net change in standardized
measure of discounted future
net cash flows................ 308,895 264,240 44,655
--------- --------- ----------
Ending balance.......................... $ 686,040 $ 560,221 $ 125,819
========= ========= ==========
YEAR ENDED DECEMBER 31, 1995
------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
--------- --------- ----------
(EXPRESSED IN THOUSANDS)
Beginning balance....................... $ 290,069 $ 257,266 $ 32,803
Revisions to prior years' proved
reserves:
Net changes in prices and production
costs.............................. 34,004 69,988 (35,984)
Net changes due to revisions in
quantity estimates................. 29,630 26,109 3,521
Net changes in estimates of future
development costs.................. (8,632) (36,721) 28,089
Accretion of discount................. 38,298 33,087 5,211
Changes in production rate............ (14,754) (15,792) 1,038
Other................................. (4,393) (432) (3,961)
--------- --------- ----------
Total revisions.................... 74,153 76,239 (2,086)
New field discoveries and extensions,
net of future production and
development costs..................... 105,172 71,701 33,471
Purchases of properties................. 29,299 5,160 24,139
Sales of properties..................... (969) (969) --
Sales of oil and gas produced, net of
production costs...................... (121,615) (121,615) --
Previously estimated development costs
incurred.............................. 63,455 39,461 23,994
Net change in income taxes.............. (62,419) (31,262) (31,157)
--------- --------- ----------
Net change in standardized
measure of discounted future
net cash flows................ 87,076 38,715 48,361
--------- --------- ----------
Ending balance.......................... $ 377,145 $ 295,981 $ 81,164
========= ========= ==========
63
QUARTERLY RESULTS -- UNAUDITED
Summaries of the Company's results of operations by quarter for the years
1997 and 1996 are as follows:
QUARTER ENDED
------------------------------------------
MAR. 31 JUNE 30 SEPT. 30 DEC. 31
--------- --------- --------- ---------
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS)
1997
Revenues............................. $ 61,314 $ 76,740 $ 77,177 $ 71,069
Gross profit(a)...................... $ 27,776 $ 23,953 $ 27,648 $ 20,104
Net income........................... $ 12,818 $ 9,174 $ 7,386 $ 7,738
Earnings per share(b):
Basic........................... $ 0.38 $ 0.27 $ 0.22 $ 0.23
Diluted......................... $ 0.36 $ 0.26 $ 0.21 $ 0.22
1996
Revenues............................. $ 48,052 $ 51,543 $ 48,233 $ 56,149
Gross profit(a)...................... $ 17,004 $ 20,011 $ 16,845 $ 25,276
Income before extraordinary loss..... $ 6,265 $ 8,937 $ 6,971 $ 11,408
Extraordinary loss on early
extinguishment of debt............. -- $ (821) -- --
Net income........................... $ 6,265 $ 8,116 $ 6,971 $ 11,408
Earnings per share(b):
Basic --
Income before extraordinary
loss..................... $ 0.19 $ 0.27 $ 0.21 $ 0.34
Extraordinary loss......... -- $ (0.02) -- --
Net income................. $ 0.19 $ 0.25 $ 0.21 $ 0.34
Diluted --
Income before extraordinary
loss..................... $ 0.19 $ 0.26 $ 0.20 $ 0.32
Extraordinary loss......... -- $ (0.02) -- --
Net income................. $ 0.19 $ 0.24 $ 0.20 $ 0.32
- ------------
(a) Represents revenues less lease operating, exploration, dry hole and
impairment, and depreciation depletion and amortization expenses.
(b) Restated for September 30, 1997, and all prior periods
ITEM 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURES.
Not applicable.
64
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
28, 1998, to be filed within 120 days of December 31, 1997 pursuant to
Regulation 14A under the Securities Exchange Act of 1934, as amended (the
Company's "1998 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 1998
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 1998 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 1998 Proxy Statement is incorporated herein by
reference.
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
1. Financial Statements and Supplementary Data:
PAGE
----
Report of Independent Public
Accountants.................... 38
Consolidated statements of
income....................... 39
Consolidated balance sheets... 40
Consolidated statements of
cash flows..................... 41
Consolidated statements of
shareholders' equity........... 42
Notes to consolidated
financial statements........... 43
Unaudited supplementary
financial data................. 58
2. Financial Statement Schedules:
All Financial Statement Schedules have been 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 e(a), Annual
Report on Form 10-K for the year ended December 31, 1997, File No. 1-7792).
*3(a)(i) -- 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 January 27, 1998.
65
*4(a) -- Amended and Restated Credit Agreement dated as of August 1, 1997 among Pogo Producing
Company, certain commercial lending institutions, Bank of Montreal as the Agent and Banque
Paribas as the Co-Agent. (Exhibit 4(a), Quarterly Report on Form 10-Q for the quarter
ended, June 30, 1997, File No. 1-7792).
*4(b) -- Indenture dated as of June 15, 1996 to Fleet National Bank, as Trustee. (Exhibit 4(f),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1996, File No. 001-7792).
*4(c) -- Indenture dated as of May 15, 1997 between Pogo Producing Company and Fleet National Bank
(now State Street Bank & Trust Company as successor in interest under the Indenture) as
Trustee (Exhibit 4.3, Registration Statement on Form S-4, filed July 2, 1997, File No.
333-30613).
*4(d) -- Rights Agreement dated as of April 26, 1994 between Pogo Producing Company and Harris
Trust Company of New York, as Rights Agent. (Exhibit 4, Current Report on Form 8-K filed
April 26, 1994, File No. 1-7792).
*4(e) -- Certificate of Designations of Series A Junior Participating Preferred Stock of Pogo
Producing Company dated April 26, 1994. (Exhibit 4(d), Registration Statement on Form S-8
filed August 9, 1994, File No. 33-54969).
*4(f) -- Registration Rights Agreement, dated as of June 18, 1996, by and among the Company,
Goldman, Sachs & Co., Merrill Lynch & Co. and Merrill Lynch, Pierce, Fenner & Smith
Incorporated. (Exhibit 4(c), Registration Statement on Form S-3 filed September 13, 1996,
File No. 333-11927.)
*4(g) -- Registration Rights Agreement, dated May 22, 1997, among Pogo Producing Company, Merrill
Lynch & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated and Goldman, Sachs & Co.
(Exhibit 4.4, Registration Statement on Form S-4 filed July 2, 1997, File No. 333-30613.)
Pogo Producing Company agrees to furnish to the Commission upon request a copy of any
agreement defining the rights of holders of long-term debt of Pogo Producing 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 Pogo Producing Company and its subsidiaries on a consolidated
basis.
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (comprising Exhibits 10(a) through
10(d)(ii), inclusive)
*10(a) -- 1989 Incentive and Nonqualified Stock Option Plan of Pogo Producing Company, as amended
and restated effective January 25, 1994. (Exhibit 99, Definitive Proxy Statement on
Schedule 14A, filed March 22, 1994, File No. 1-7792).
*10(a)(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(a)(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(b) -- 1995 Long-Term Incentive Plan. (Exhibit 4(c), Registration Statement on Form S-8 filed May
22, 1996, File No. 333-04233).
*10(c)(1)(i) -- Executive Employment Agreement by and between Pogo Producing Company and Stuart P.
Burbach, dated February 1, 1996. (Exhibit 10(f)(1), Annual Report on Form 10-K for the
year ended December 31, 1995, File No. 001-7792).
*10(c)(1)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Stuart P. Burbach, dated effective February 1, 1997. (Exhibit
10(g)(1)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No.
001-7792).
66
10(c)(1)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Stuart P. Burbach, dated effective February 1, 1998.
*10(c)(2)(i) -- Executive Employment Agreement by and between Pogo Producing Company and Jerry A. Cooper,
dated February 1, 1996. (Exhibit 10(f)(2), Annual Report on Form 10-K for the year ended
December 31, 1995, File No. 001-7792).
*10(c)(2)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Jerry A. Cooper, dated effective February 1, 1997. (Exhibit
10(g)(2)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No.
001-7792).
10(c)(2)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Jerry A. Cooper, dated effective February 1, 1998.
*10(c)(3)(i) -- Executive Employment Agreement by and between Pogo Producing Company and Kenneth R. Good,
dated February 1, 1996.(Exhibit 10(f)(3), Annual Report on Form 10-K for the year ended
December 31, 1995, File No. 001-7792).
*10(c)(3)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Kenneth R. Good, dated effective February 1, 1997. (Exhibit
10(g)(3)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No.
001-7792).
10(c)(3)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Kenneth R. Good, dated effective February 1, 1998.
*10(c)(4)(i) -- Executive Employment Agreement by and between Pogo Producing Company and R. Phillip Laney,
dated February 1, 1996. (Exhibit 10(f)(4), Annual Report on Form 10-K for the year ended
December 31, 1995, File No. 001-7792).
*10(c)(4)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and R. Phillip Laney, dated effective February 1, 1997. (Exhibit
10(g)(4)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No.
001-7792).
10(c)(4)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and R. Phillip Laney, dated effective February 1, 1998.
*10(c)(5)(i) -- Executive Employment Agreement by and between Pogo Producing Company and John O. McCoy,
Jr., dated February 1, 1996.(Exhibit 10(f)(5), Annual Report on Form 10-K for the year
ended December 31, 1995, File No. 001-7792).
*10(c)(5)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and John O. McCoy, Jr., dated effective February 1, 1997. (Exhibit
10(g)(5)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No.
001-7792).
10(c)(5)(iii) -- Extension Agreement to Continue Executive Employment Agreement by
and between Pogo Producing Company and John O. McCoy, Jr., dated effective
February 1, 1998.
*10(c)(6)(i) -- Executive Employment Agreement by and between Pogo Producing Company and Paul G. Van
Wagenen, dated February 1, 1996. (Exhibit 10(f)(6), Annual Report on Form 10-K for the
year ended December 31, 1995, File No. 001-7792).
67
*10(c)(6)(ii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Paul G. Van Wagenen, dated effective February 1, 1997. (Exhibit
10(g)(6)(ii), Annual Report on Form 10-K for the year ended December 31, 1996, File No.
001-7792).
10(c)(6)(iii) -- Extension Agreement to Continue Executive Employment Agreement by and between Pogo
Producing Company and Paul G. Van Wagenen, dated effective February 1, 1998.
10(c)(7)(i) -- Executive Employment Agreement by and between Pogo Producing Company and Bruce E.
Archinal, dated as of February 1, 1998.
*10(d)(1) -- Excess Benefits Letter Agreement by and between Pogo Producing Company and Kenneth R.
Good, dated March 2, 1995. (Exhibit 10(g)(1), Annual Report on Form 10-K for the year
ended December 31, 1995, File No. 001-7792).
*10(d)(2) -- Excess Benefits Letter Agreement by and between Pogo Producing Company and Paul G. Van
Wagenen, dated March 2, 1995. (Exhibit 10(g)(2), Annual Report on Form 10-K for the year
ended December 31, 1995, File No. 001-7792).
*10(e) -- 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).
*10(f) -- Bareboat Charter Agreement by and between Tantawan Services, LLC and Tantawan Production
B.V., dated as of February 9, 1996. (Exhibit 10(j), Annual Report on Form 10-K for the
year ended December 31, 1995, File No. 001-7792).
*10(g)(i) -- Gas Sales Agreement dated November 7, 1995, among The Petroleum Authority of Thailand,
Thaipo, Limited, Thai Romo Ltd. and The Sophonpanich Co., Ltd. (Exhibit 10(k), Quarterly
Report on Form 10-Q for the quarter ended June 30, 1996, File No. 001-7792).
10(g)(ii) -- The First Amendment to the Gas Sales Agreement dated November 12, 1997, among The
Petroleum Authority of Thailand, B8/32 Partners Limited, Thaipo, Limited, Thai Romo
Limited and Palang Sophon Limited.
*21 -- List of Subsidiaries of Pogo Producing Company (Exhibit 21, Annual Report on Form 10-K for
the year ended December 31, 1995, File No. 001-7792).
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, 1997.
27.1 -- Financial Data Schedule.
27.2 -- Restated Financial Data Schedules for the 1997 Interim periods.
27.3 -- Restated Financial Data Schedules for the 1996 Annual period.
27.4 -- Restated Financial Data Schedule for the 1996 Interim periods.
27.5 -- Restated Financial Data Schedule for the 1995 Annual period.
- ------------
* Asterisk indicates exhibits incorporated by reference as shown.
(b) Reports on Form 8-K
None
68
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: March 17, 1998
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 March 17, 1998.
SIGNATURE 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/JOHN W. ELSENHANS Principal Financial
JOHN W. ELSENHANS Officer
VICE PRESIDENT AND
CHIEF FINANCIAL OFFICER
/s/THOMAS E. HART Principal Accounting
THOMAS E. HART Officer
VICE PRESIDENT AND CONTROLLER
/s/TOBIN ARMSTRONG* Director
TOBIN ARMSTRONG
/s/JACK S. BLANTON* Director
JACK S. BLANTON
/s/W. M. BRUMLEY, JR.* Director
W. M. BRUMLEY, JR.
/s/JOHN B. CARTER, JR.* Director
JOHN B. CARTER, JR.
/s/WILLIAM L. FISHER* Director
WILLIAM L. FISHER
/s/WILLIAM E. GIPSON* Director
WILLIAM E. GIPSON
69
SIGNATURES -- (CONTINUED)
/s/GERRIT W. GONG* Director
GERRIT W. GONG
/s/J. STUART HUNT* Director
J. STUART HUNT
/s/FREDERICK A. KLINGENSTEIN* Director
FREDERICK A. KLINGENSTEIN
/s/NICHOLAS R. PETRY* Director
NICHOLAS R. PETRY
/s/JACK A. VICKERS* Director
JACK A. VICKERS
*By: /s/THOMAS E. HART
THOMAS E. HART
ATTORNEY-IN-FACT
70