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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, 1996
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Commission File No. 1-7792
POGO PRODUCING COMPANY
(Exact name of registrant as specified in its charter)
Delaware 74-1659398
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5 Greenway Plaza, P.O. Box 2504
Houston, Texas 77252-2504
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 297-5000
Securities registered pursuant to Section 12(b) of the Act:
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 Notes New York Stock Exchange
due March 15, 2004
Securities registered pursuant to Section 12(g) of the Act:
5 1/2% Convertible Subordinated Notes due June 15, 2006
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 $1,114,690,911 as of March 10, 1997 (based on $36.50 per share,
the last sale price of the Common Stock as reported on the New York Stock
Exchange Composite Tape on such date).
33,361,089 shares of the registrant's Common Stock were outstanding as of
March 10, 1997.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Company's definitive Proxy Statement respecting the annual
meeting of shareholders to be held on April 22, 1997 (to be filed not later
than 120 days after December 31, 1996) are incorporated by reference in Part
III of this Form 10-K.
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FORWARD LOOKING STATEMENTS
The statements included or incorporated by reference in this Report on Form
10-K for the year ended December 31, 1996 (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"). 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.
i
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, 1996, the Company had interests in 86 lease blocks offshore
Louisiana and Texas, approximately 212,000 gross acres onshore in the United
States and approximately 1,300,000 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 rationalized its asset base and
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, 1997, seven significant operating areas, of which four are located
in the Gulf of Mexico and one each in New Mexico, South Texas and Thailand,
accounted for approximately 90% of the estimated proved natural gas reserves
and approximately 93% of the estimated proved oil, condensate and natural gas
liquids reserves of the Company. Six of these operating areas also accounted
for approximately 73% of natural gas production and 88% of oil, condensate and
natural gas liquids production for 1996. The seventh operating area, the Gulf
of Thailand, did not commence production until February 1, 1997. Reserves, as
estimated by Ryder Scott Petroleum Engineers, Houston Texas ("Ryder Scott"),
and production data, as estimated by the Company, for the seven 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, 1997.
Significant Operating Areas
1996 Average Net
Net Proved Reserves (a) Daily Production
---------------------------- ----------------------------- Total Net
Natural Gas Liquids(b) Natural Gas Liquids(b) Proved
-------------- ------------- ------------ -------------- Reserves (a)
(MMcf) % (MBbls) % (Mcf) % (Bbls) % %
------- ----- ------- ---- ------ ---- ------- ---- ------------
DOMESTIC OFFSHORE
Eugene Island 40,911 11.3% 8,378 16.9% 27,800 25.7% 4,701 33.2% 13.8%
East Cameron 44,293 12.3 1,015 2.0 11,587 10.7 94 0.7 7.7
Main Pass 16,970 4.7 4,573 9.2 7,828 7.2 2,209 15.6 6.7
South Pass 16,200 4.5 1,229 2.5 15,302 14.2 661 4.7 3.6
DOMESTIC ONSHORE
New Mexico 21,687 6.0 9,639 19.4 11,842 11.0 4,752 33.5 12.1
South Texas -- Lopeno 40,843 11.3 -- -- 4,902 4.5 -- -- 6.2
INTERNATIONAL
Kingdom of Thailand(c) 144,998 40.2 21,332 43.0 N/A -- N/A -- 41.5
- ----------------------
(a) Net proved reserves and total net proved reserves each as of January 1,
1997. Total net reserves are calculated on an energy equivalent basis using
a ratio of six Mcf equal to one Bbl of oil. 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.
(c) Initial production from the Tantawan Field commenced on February 1, 1997.
After giving effect to the Company's March 1997 acquisition of its
proportionate share of the shares of Maersk Oil (Thailand) Ltd., the
Company's net proved reserves of natural gas and hydrcarbon liquids located
in the Kingdom of Thailand would have been 166,160 MMcf and 26,163 MBbls,
respectively, on a pro forma basis on January 1, 1997. This would have
equated to 46% of the Company's total net proved hydrocarbon reserves, 43%
of net proved natural gas reserves, and 48% of net proved liquids on a pro
forma basis as of January 1, 1997, while the respective percentages of the
Company's domestic hydrocarbon reserves as a percentage of the Company's
total net proved reserves would have been proportionately reduced.
1
DOMESTIC OFFSHORE OPERATIONS
Historically, the Company's interests have been concentrated in the Gulf of
Mexico, where approximately 66% of the Company's domestic proved reserves and
38% of its total proved reserves are now located. During 1996, approximately
82% of the Company's natural gas production and 67% of its oil and condensate
production was from its domestic offshore properties, contributing
approximately 72% of consolidated oil and gas revenues. Four offshore
producing areas, Eugene Island, East Cameron, Main Pass and South Pass, account
for approximately 33% of the Company's net proved natural gas reserves and
approximately 31% of the Company's proved crude oil, condensate and natural gas
liquids reserves. See "Significant Domestic Offshore Operating Areas during
1996."
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, 1996, the Company owned interests in 77 federal
leases and 9 state leases offshore Louisiana and Texas. Federal leases
generally have primary terms of five years and state leases generally have
terms of three years, 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 1996, the Company was successful in
acquiring interests in ten lease blocks through federal Outer Continental Shelf
oil and gas lease sales. The Department of the Interior has announced its
intention to hold two lease sales during 1997 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 1996 were approximately $92,400,000 (excluding approximately $2,000,000 of
net property acquisitions), or 144% 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 and 91% higher
than the Company's domestic offshore capital and exploration expenditures of
approximately $48,400,000 for 1994 (excluding approximately $32,600,000 of net
property acquisitions). The increase in the Company's domestic offshore
capital and exploration expenditures for 1996, 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. The increase in the Company's domestic offshore capital and
exploration expenditures for 1996, compared to 1994, resulted primarily from
increased costs associated with construction and installation of offshore
platforms, pipelines and other facilities. 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 be the
operator of a particular lease. The Company is currently the operator on all
or a portion of 26 of the 86 offshore leases in which it has an interest.
2
Platforms 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 to the joint
ventures in which the Company has varying net interests has averaged
approximately $7,000,000. 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. During 1996, the
Company installed, or substantially completed construction of, two new
platforms on East Cameron Block 334 and one new platform on Ship Shoal Block
240. See "Significant Domestic Offshore Operating Areas During 1996."
Significant Domestic Offshore Operating Areas During 1996
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 67 oil and gas wells producing from multiple reservoirs and
horizons. Through January 1997, the Company participated in the drilling of
six wells in the Eugene Island operating area, including three highly
successful wells in its Eugene Island 261 field where the Company has a 66.67%
working interest that added new reserves and production capacity, bringing the
total number of productive wells in this field to six.
The Eugene Island Block 330 field is one of the Company's most significant
producing assets. The field, located in 245 feet of water, contains three
drilling and production platforms in which the Company holds a 35% working
interest, as well as an additional platform in which the Company holds a 30%
working interest. There are currently 9 wells producing primarily natural gas
and 34 wells producing primarily oil on the block. Reserves have been added to
this field consistently since production commenced. These increases have been
derived from new exploratory horizons, infill drilling, field expansions and
higher than anticipated recovery efficiencies. The Company and its joint
venture partners currently plan to drill seven wells in this field 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 three offshore
blocks in this area which contain two fields and 15 producing gas wells.
During 1996, the Company and its partners were active in the East Cameron
Block 334/335 field. In August 1996, the Company and one of its joint venture
partners commenced production from the fourth platform to be installed in this
field. In addition, together with the same partner, the Company drilled two
additional wells and commenced construction of a fifth platform for this field
which has been installed and is currently scheduled to commence production in
the second quarter of 1997. Finally, during the fourth quarter of 1996, the
Company and its joint venture partners drilled another exploratory well into a
new untested fault block, the results of which the Company and its joint
venture partners are currently evaluating for a possible sixth platform in the
field.
Main Pass
The Company's 13 lease blocks in the Main Pass area, including one acquired
in 1996, 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 Company currently plans an active exploratory drilling program during 1997
to evaluate the new lease blocks that it acquired in the Main Pass Area. 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 26
producing oil wells and 6 producing natural gas wells from three platforms
operated by the Company's joint venture partner. The field is located in 125
feet of water. The Company plans to continue into 1997 its successful drilling
program that commenced in 1995 which has been based in part on the analysis of
a recent 3-D seismic survey over the field.
3
South Pass
The Company acquired its first leasehold interest in the South Pass area
off of the mouth of the Mississippi River in September 1972. In 1996, the
Company acquired an interest in three additional blocks in this area, bringing
the total number of blocks in the South Pass area in which the Company currently
owns an interest to ten, on which four production platforms have been set that
produce oil and gas from 25 wells. One of the Company's fields in the South Pass
area is located on South Pass Blocks 49 and 50. The Company holds a 50% working
interest in South Pass Block 50 and a 20% interest in South Pass Block 49. The
Company plans to drill additional wells in this field during 1997. Another field
in which the Company has an interest in the South Pass area is the South Pass
Block 78 field. Following analysis of a recently acquired 3-D seismic survey,
the Company and several of its joint venture partners drilled and completed four
highly deviated wells into previously unexplored reservoirs during late 1995 and
1996. The Company and its joint venture partners currently plan to drill an
additional well or wells in this field during 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 1996."
Lease Acquisitions
Commencing in 1995 and continuing in 1996, the Company increased its
activities in the onshore Gulf Coast areas of East Texas and South Louisiana.
In addition to participating in the acquisition of several large 3-D seismic
surveys, the Company acquired an interest in, or the right to acquire an
interest in, 22,395 gross acres in East Texas and South Louisiana. As it has in
recent years, in 1996 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, 1996, the Company held
interests in approximately 212,000 gross (103,000 net) acres onshore in the
United States, an increase of approximately 40% (9% net) from year end 1995.
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 299 wells
in the Permian Basin, West and Northwest Texas areas through December 31, 1996,
including 40 wells in 1996.
The Company is also active in exploring for oil and gas in several other
onshore Gulf Coast areas in Texas and Louisiana. In addition to the wells
drilled in the Permian Basin, during 1996 the Company participated in the
drilling of eight exploratory wells (principally in East Texas and South
Louisiana) and ten development wells (principally in the Lopeno Field in South
Texas). See "Significant Domestic Onshore Operating Areas During 1996."
During 1996, approximately 18% of the Company's natural gas production and 33%
of its oil and condensate production was from its domestic onshore properties,
contributing approximately 23% of 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 $43,000,000 (excluding approximately $3,800,000 of net property
acquisitions) for 1996, or 31% higher than the Company's domestic onshore
capital and exploration expenditures of approximately $32,950,000 (excluding
approximately $7,750,000 of net property acquisitions) for 1995 and 34% higher
than the Company's domestic onshore capital and exploration expenditures of
approximately $32,000,000 for 1994. The increase in the Company's domestic
onshore capital and exploration expenditures for 1996, compared to 1995 and
1994, resulted primarily from increased drilling activity in South Texas, East
Texas and South Louisiana, as well as increased exploration costs
4
associated with conducting, processing and interpreting 3-D seismic surveys.
Onshore reserves as of December 31, 1996, accounted for approximately 34% of the
Company's domestic proved reserves and approximately 20% of its total proved
reserves.
Significant Domestic Onshore Operating Areas During 1996
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 75,000 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 of 142 Bbls to 230 Bbls per day,
depending on the depth of production from the field). The Company has achieved
rapid cost recovery with respect to its New Mexico wells drilled to date
because of relatively low capital costs and high initial rates of production.
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, 1996, in the drilling of, among others,
92 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%, 57 wells in the Livingston Ridge field where
the Company's working interest ranges from 25% to 100%, 58 wells in the Red
Tank field where the Company's working interest ranges from 89% to 100%, 16
wells in the Cedar Canyon field where the Company's working interest ranges
from 38% to 100% (including nine during 1996), and 3 wells in the Lost Tank
field where the Company's working interest ranges from 50% to 100%. The oil
fields in this area are generally developed on a 40 acre spacing pattern. The
Company anticipates drilling many additional locations in these and other
fields in southeastern New Mexico during 1997 including, in particular, an
aggressive drilling program in the Cedar Canyon and Lost Tank fields.
Lopeno Field
The Lopeno Field is located in south Texas, within 40 miles of the Mexican
border. The Company acquired its initial interest in the Lopeno Field in 1983.
The Company currently has interests in over 7,800 gross acres containing 23
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. Following acquisition, processing and interpretation
of a 3-D seismic survey over the field, the Company and its joint venture
partners commenced an active development drilling program in the fourth quarter
of 1995, including the drilling of seven wells in 1996. The Company and its
joint venture partners currently plan to drill an additional seven wells in the
Lopeno Field during 1997.
INTERNATIONAL OPERATIONS
The Company has conducted international exploration activities since the
late 1970's in numerous oil and gas areas throughout the world. The Company
pursues a strategy of evaluating potentially high return prospects in areas of
the world with a stable political and financial climate such as certain
European and ASEAN ("Association of Southeast Asian Nations") countries.
Currently, the Company maintains an office in Bangkok, Thailand from which it
directs a field development project in the Gulf of Thailand on a portion of its
Block B8/32 Concession (the "Concession") through its wholly owned subsidiary,
Thaipo Limited ("Thaipo").
The Company's international capital and exploration expenditures were
approximately $64,400,000 for 1996, or 84% higher than the Company's
international capital and exploration expenditures of approximately $34,950,000
(excluding approximately $4,171,000 of net property acquisitions) for 1995 and
914% higher than the Company's international capital and exploration
expenditures of approximately $6,350,000 for 1994. Substantially all of the
Company's international capital and exploration expenditures for 1996 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.
5
Platforms are installed on the 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 Concession and Related Production." Platforms are used to accommodate
both development drilling and additional exploratory drilling. Over the last
two years, the gross cost of the first three production platforms in the
Tantawan Field (which includes the "C" platform being set in the first quarter
of 1997) 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 1996;
Tantawan Field."
Significant International Operating Areas During 1996
Tantawan Field
In August 1995, at the request of Thaipo and its two joint venture
partners, the government of Thailand designated a portion of the Concession
comprising approximately 68,000 acres as the Tantawan production area. The
Tantawan production area, of which Thaipo is the operator and has a 46.34%
working interest, has been named the Tantawan Field. Through March 1, 1997,
eleven exploration and twenty-three 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. Development drilling is due to
commence from a third platform that is currently being installed. A fourth
platform has been announced for the field and is currently under construction.
Oil and gas production from the field is gathered through pipelines from the
platforms into a Floating Production, Storage and Offloading system (an "FPSO")
named the "Tantawan Explorer." The FPSO Tantawan Explorer 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 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 and Pakakrong Fields
Exploration efforts also continue on those portions of the Concession
outside the Tantawan Field. Through March 1, 1997, fourteen exploration wells
have been drilled on the Concession outside of the Tantawan Field. This includes
nine wells, all of which encountered hydrocarbons, in the Benchamas Field and
two wells, which also encountered hydrocarbons, in the Pakakrong Field. In
January 1997, Thaipo and its joint venture partners formally requested that the
government of Thailand designate certain Concession areas outside the Tantawan
Field, including the Maliwan, North Benchamas, Benchamas and Pakakrong fields,
as production areas. The government is currently considering the request. In the
interim, Thaipo and its joint venture partners have commenced preliminary
planning for the development of these fields. In March 1997, the Company and its
joint venture partners in the Tantawan Field or their affiliates, acquired all
of the outstanding shares of Maersk Oil (Thailand) Ltd., a former joint venture
partner that owned 31.67% of those portions of the Concession not currently a
part of the Tantawan Field, including the Benchamas and Pakakrong Fields. With
this acquisition, the Company now indirectly owns a 46.34% working interest in
the entire Concession and its subsidiary Thaipo is the operator of the entire
Concession.
Other Areas on the Concession
In addition to the above mentioned fields, Thaipo and its joint venture
partners have identified other potentially promising areas on the Concession.
Since acquiring their interest in the Concession, Thaipo and its joint
6
venture partners have acquired 3-D seismic surveys covering approximately
452,000 acres of the Concession and are currently planning to acquire additional
3-D seismic data over other prospective portions of the Concession during 1997.
In addition to the ongoing interpretation of recently acquired 3-D seismic data,
Thaipo and its joint venture partners are currently engaged in an exploratory
drilling program evaluating the North Benchamas prospect, following which they
currently plan to test the Maliwan prospect.
Contractual Terms Governing the Concession and Related Production
As set forth in the August 1991 Concession agreement, the current
exploratory term of the Concession agreement expires on July 31, 1997, subject
to further extension as described below. At the end of the Concession
agreement's current exploration term on July 31, 1997, Thai petroleum law
permits the government to grant, upon application by a concessionaire, an
additional three year exploration term on up to fifty percent of the Concession
acreage that has not been previously designated as a production area or
returned to the government, subject to certain terms and conditions including
the agreement to undertake a work program and the payment of substantial fees
and rentals. The Company and its joint venture partners are currently
discussing with governmental authorities what the relevant work program, fees
and rentals may be for an extension of the current exploratory term.
Currently, the Company and its joint venture partners intend to apply to the
government for a three year extension of the exploratory term of the Concession
which would include the maximum amount of acreage permitted by applicable law.
For those portions of the Concession designated as production areas, which
currently includes the Tantawan Field and, subject to the governmental approval
discussed above, may include other portions of the Concession such as the
Maliwan, North Benchamas, Benchamas and Pakakrong fields, the initial
production period term is 20 years, which is also subject to extension. See
also "-- Miscellaneous; Sales."
Production resulting from the Concession (including the Tantawan production
area) is subject to a royalty ranging from 5% to 15% of oil and gas sales, plus
certain fixed dollar amounts payable at specified cumulative production levels.
Revenue from production in Thailand 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. Subsequently, Thaipo and its joint venture
partners reached an agreement in principle to amend this gas sales agreement to
include the reserves and anticipated gas production from the remainder of the
Concession, including the Benchamas Field. Initial terms of the agreement
include an initial minimum daily contract quantity ("DCQ") during the first
year of production of 75 MMcf per day with the DCQ rising to 85 MMcf per day in
the following year. The DCQ is the minimum daily volume that PTT has agreed to
take, or pay for if not taken under the agreement. Mutual agreement on
dedicated reserves would be renegotiated as and when the DCQ exceeds 125 MMcf
per day. Initial base gas prices start at approximately $2.00 per Mcf, subject
to semi-annual adjustments based upon a formula which takes into account, among
other things, changes in Singapore fuel oil prices, Thai wholesale prices and
the U.S./Thai currency exchange rate. In late 1996, Thaipo and its joint
venture partners signed a memorandum of understanding with PTT providing for
the sale of crude oil and condensate to PTT at prices which fluctuate, based
upon posted world prices, and which take into account the anticipated high
quality of the production from Tantawan Field, and the field's close proximity
to Thai markets.
MISCELLANEOUS
Other Assets
The Company and a subsidiary, Pogo Offshore Pipeline Co., own interests in
seven pipelines (excluding field gathering pipelines) through which offshore
hydrocarbon production is transported. In addition, the Company owns an
approximately 19.3% 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, 1996, Pogo Gulf Coast had interests in 5
federal offshore leases. The Company owns 40% of any interest in properties
acquired by the limited part-
7
nership. 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 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 concession in Thailand 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 and Pakakrong Fields).
Thaipo and its joint venture partners in the Tantawan Field signed a long term
gas sales contract with PTT in November 1995 covering production from the
Tantawan Field. In addition, in November 1996, Thaipo and its joint venture
partners entered into a memorandum of understanding which provides that oil and
condensate production from the Tantawan Field will initially be stored aboard
the FPSO, sold to PTT and transferred to shore by means of oil tankers. See "--
International Operations; Contractual Terms Governing the Concession and
Related Production."
The marketing of onshore oil and gas production is also subject to the
availability of pipelines, crude oil hauling and other transportation,
processing and refining facilities as well as the existence of adequate
markets. Generally, the Company's onshore domestic oil and gas production is
located in areas where commercial production of economic discoveries can be
rapidly effectuated.
Most of the Company's 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
currently available prices. 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 contract for production from the
Company's Concession in Thailand (see "-- International Operations; Contractual
Terms Governing the 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. See also "Financial Statements
and Supplementary Data -- Note 4 to Notes to Consolidated Financial Statements
and -- Unaudited Supplementary Financial Data."
Competition and Market Conditions
The Company experiences competition from other oil and gas companies in all
phases of its operations, as well as competition from other energy related
industries. The Company's profitability and cash flow are highly dependent
upon the prices of oil and natural gas, which historically have been seasonal,
cyclical and volatile. In general, prices of oil and gas are dependent upon
numerous factors beyond the control of the Company, including various weather,
economic, political and regulatory conditions. In the past, when natural gas
prices in the United States were lower than they are currently, the Company at
times elected to curtail certain quantities of its production. For example, in
the fourth quarter of 1994 the Company curtailed a small portion of its daily
natural gas production. As of March 1, 1997, the Company was not curtailing
any of its natural gas production as a result of low natural gas prices.
Should natural gas prices fall again 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 effect of price declines,
8
such transactions could effectively limit the Company's participation in price
increases for the covered period, which increases could be significant. As of
March 1, 1997, 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 weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment. The availability of a ready
market for the Company's natural gas production depends on a number of factors,
including the demand for and supply of natural gas, the proximity of natural
gas reserves to pipelines, the capacity of such pipelines and government
regulations.
Risks of Foreign Operations
Ownership of property interests and production operations in Thailand, and
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. 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. The Company believes that the Kingdom of Thailand currently
presents favorable conditions in which to conduct international operations.
EXPLORATION AND PRODUCTION DATA
In the following data "gross" refers to the total acres or wells in which
the Company has an interest and "net" refers to gross acres or wells multiplied
by the percentage working interest owned by the Company.
9
Acreage
The following table shows the Company's interest in developed and
undeveloped oil and gas acreage as of December 31, 1996:
Developed Acreage (a) Undeveloped Acreage (b)
--------------------- -----------------------
Gross Net Gross Net
----- --- ----- ---
DOMESTIC ONSHORE
Louisiana 869 209 28,072 9,373
New Mexico 21,246 11,882 54,354 39,119
Texas 13,676 4,987 90,597 37,452
Other 3,200 333 238 55
------- ------- --------- -------
Total Domestic Onshore 38,991 17,411 173,261 85,999
------- ------- --------- -------
DOMESTIC OFFSHORE
Louisiana (State) 8,756 3,326 1,508 753
Louisiana (Federal)(c) 169,625 58,453 117,901 35,797
Texas (Federal) 46,080 11,819 17,280 8,640
------- ------- --------- -------
Total Domestic Offshore 224,461 73,598 136,689 45,190
------- ------- --------- -------
TOTAL DOMESTIC 263,452 91,009 309,950 131,189
------- ------- --------- -------
INTERNATIONAL
Thailand (Offshore) 67,995 31,510 1,283,561 406,461
------- ------- --------- -------
TOTAL COMPANY 331,447 122,519 1,593,511 537,650
======= ======= ========= =======
- ------------
(a) "Developed acreage" consists of lease acres spaced or assignable to
production on which wells have been drilled or completed to a point that
would permit production of commercial quantities of oil or natural gas.
(b) "Undeveloped acreage" includes acreage under lease or subject to lease or
purchase options that the Company currently expects to exercise.
Approximately 9% of the Company's total domestic offshore net undeveloped
acreage is under leases that have terms expiring in 1997 (unless otherwise
extended) and no domestic offshore undeveloped acreage will expire in 1998.
Approximately 5% of the Company's total domestic onshore net undeveloped
acreage is under leases that have terms expiring in 1997 (unless otherwise
extended) and another approximately 10% of total domestic onshore net
undeveloped acreage will expire in 1998 (unless otherwise extended). All of
the Company's international undeveloped acreage must be relinquished to the
Thai government in 1997 unless designated as a production area or unless the
exploration term is extended as discussed above. See "Business --
International Operations; Contractual Terms Governing the 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).
10
Drilling Activity and Productive Wells
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.
1996 1995 1994
--------------- --------------- ---------------
Successful Dry Successful Dry Successful Dry
---------- --- ---------- --- ---------- ---
GROSS WELLS:
Offshore United States
Exploratory 4.0 2.0 7.0 4.0 2.0 --
Development 17.0 3.0 3.0 1.0 25.0 2.0
Onshore United States
Exploratory 12.0 4.0 8.0 1.0 3.0 6.0
Development 39.0 1.0 47.0 1.0 51.0 3.0
Offshore Kingdom of Thailand
Exploratory 7.0 -- 3.0 -- 5.0 --
Development 16.0 -- 7.0 -- -- --
---- --- ---- --- ---- ----
Total 95.0 10.0 75.0 7.0 86.0 11.0
==== ==== ==== === ==== ====
1996 1995 1994
--------------- --------------- ---------------
Successful Dry Successful Dry Successful Dry
---------- --- ---------- --- ---------- ---
NET WELLS:
Offshore United States
Exploratory 1.7 1.5 3.0 1.6 0.6 --
Development 4.9 1.5 1.0 0.4 8.4 1.4
Onshore United States
Exploratory 6.5 0.9 4.6 1.0 2.8 3.6
Development 24.4 0.7 31.3 0.1 29.9 0.9
Offshore Kingdom of Thailand
Exploratory 2.4 -- 1.1 -- 1.6 --
Development 7.4 -- 3.2 -- -- --
---- --- ---- --- ---- ---
Total 47.3 4.6 44.2 3.1 43.3 5.9
==== === ==== === ==== ===
As of December 31, 1996, the Company was participating in the drilling of 3
gross (1.3 net) offshore domestic wells, 6 gross (4.2 net) onshore wells and 1
gross (0.3 net) wells offshore the Kingdom of Thailand.
11
The following table shows the Company's interest in productive oil and
natural gas wells as of December 31, 1996. Productive wells are producing
wells plus wells "capable of production" (e.g., natural gas wells waiting for
pipeline connections or necessary governmental certification to commence
deliveries and oil wells waiting to be connected to production facilities).
Natural
Oil Wells (a) Gas Wells (a)
-------------- -------------
Gross Net Gross Net
----- ----- ----- ----
Offshore United States 180 46.0 178 58.8
Onshore United States 285 183.4 84 35.2
Kingdom of Thailand(b) -- -- 9 4.2
--- ----- --- ----
Total 465 229.4 271 98.2
=== ===== === ====
- ----------
(a) One or more completions in the same bore hole are counted as one well. The
data in the above table includes 25 gross (6.7 net) oil wells and 14 gross
(5.7 net) natural gas wells with multiple completions.
(b) The number of wells set forth in this table as "capable of production" in
Thailand does not include 9 gross (4.2 net) wells that had been drilled and
were awaiting completion and connection at year end. All of such wells have
subsequently been completed as productive wells during the first two months
of 1997.
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.
1996 1995 1994
---- ---- ----
PRODUCTION SALES:
Natural Gas (Mcf per day) 107,700 121,000 144,800
======= ======= =======
Liquid Hydrocarbons (Bbls per day)
Crude Oil and Condensate 11,968 11,786 11,100
Natural Gas Liquids(a) 2,173 1,998 2,222
------- ------- -------
Total Liquid Hydrocarbons 14,141 13,784 13,322
======= ======= =======
- ----------
(a) Natural Gas Liquids production sales includes sales attributable to both the
Company's leasehold and plant ownership.
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."
1996 1995 1994
---- ---- ----
SALES PRICES:
Natural Gas (per Mcf) $ 2.40 $ 1.63 $ 1.88
Crude Oil and Condensate (per Bbl) $22.12 $17.80 $16.08
Natural Gas Liquids (per Bbl) $14.92 $11.10 $11.33
PRODUCTION (LIFTING) COSTS(a):
Natural Gas, Crude Oil, Condensate and
Natural Gas Liquids (per Mcf equivalent) $ 0.53 $ 0.47 $ 0.36
- ----------
(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.
12
Reserves
The following table sets forth information as to the Company's net proved
and proved developed reserves as of December 31, 1996, 1995, and 1994, and the
present value as of such dates (based on an annual discount rate of 10%) of the
estimated future net revenues from the production and sale of those reserves,
as estimated by Ryder Scott in accordance with criteria prescribed by the
Commission. The summary report of Ryder Scott on the reserve estimates, which
includes definitions and assumptions, is set forth as an exhibit to this Annual
Report and the definitions, assumptions and descriptions of methodology
following the tables are based upon the Ryder Scott report.
As of December 31,
---------------------------------
1996 1995 1994
-------- -------- -------
TOTAL PROVED RESERVES:
Oil, condensate, and natural gas
liquids (MBbls) --
Located in the United States 28,270 26,185 26,188
Located in the Kingdom of Thailand 21,332 18,997 7,674
-------- -------- --------
Total Company 49,602 45,182 33,862
======== ======== ========
Natural Gas (MMcf) --
Located in the United States 215,946 196,454 186,151
Located in the Kingdom of Thailand 144,998 131,607 56,739
-------- -------- --------
Total Company 360,944 328,061 242,890
======== ======== ========
Present value of estimated future net
revenues, before income taxes (in
thousands)(a) --
Located in the United States $773,127 $400,845 $330,868
Located in the Kingdom of Thailand 181,418 131,630 52,112
-------- -------- --------
Total Company $954,545 $532,475 $382,980
======== ======== ========
TOTAL DEVELOPED RESERVES:
Oil, condensate, and natural gas
liquids (MBbls) --
Located in the United States 25,898 22,488 24,670
Located in the Kingdom of Thailand 5,192 -- --
-------- -------- --------
Total Company 31,090 22,488 24,670
======== ======== ========
Natural Gas (MMcf) --
Located in the United States 192,034 164,679 178,518
Located in the Kingdom of Thailand 45,998 -- --
-------- -------- --------
Total Company 238,032 164,679 178,518
======== ======== ========
Present value of estimated future net
revenues, before income taxes (in
thousands)(a) --
Located in the United States $710,871 $359,984 $321,514
Located in the Kingdom of Thailand 69,062 -- --
-------- -------- --------
Total Company $779,933 $359,984 $321,514
======== ======== ========
- ----------
(a) The Company believes, for the reasons set forth in suceeding 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 not even useful for
comparative purposes.
13
Natural gas liquids comprise approximately 8% of the Company's total proved
liquids reserves and approximately 12% of the Company's proved developed
liquids reserves. All hydrocarbon liquid reserves are expressed in standard 42
gallon Bbls. All gas volumes and gas sales are expressed in MMcf at the
pressure and temperature basis of the area where the gas reserves are located.
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from
known reservoirs under existing conditions. Reservoirs are considered proved
if economic producibility is supported by actual production or formation tests.
In certain instances, proved reserves are assigned on the basis of a
combination of core analysis and electrical and other type logs which indicate
the reservoirs are analogous to reservoirs in the same field which are
producing or have demonstrated the ability to produce on a formation test. The
area of a reservoir considered proved includes (i) that portion delineated by
drilling and defined by fluid contacts, if any, and (ii) the adjoining portions
not yet drilled that can be reasonably judged as economically productive on the
basis of available geological and engineering data. In the absence of data on
fluid contacts, the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir. Proved reserves are estimates of
hydrocarbons to be recovered from a given date forward. They may be revised as
hydrocarbons are produced and additional data becomes available. Proved
natural gas reserves are comprised of nonassociated, associated and dissolved
gas. An appropriate reduction in gas reserves has been made for the expected
removal of liquids, for lease and plant fuel and the exclusion of
non-hydrocarbon gases if they occur in significant quantities and are removed
prior to sale. Reserves that can be produced economically through the
application of established improved recovery techniques are included in the
proved classification when these qualifications are met: (i) successful testing
by a pilot project or the operation of an installed program in the reservoir
provides support for the engineering analysis on which the project or program
was based, and (ii) it is reasonably certain the project will proceed.
Improved recovery includes all methods for supplementing natural reservoir
forces and energy, or otherwise increasing ultimate recovery from a reservoir,
including, (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.
The Company has interests in certain tracts which may have substantial
additional hydrocarbon quantities which cannot be classified as proved and are
not included herein. The Company has active exploratory and development
drilling programs which in all likelihood will result in the reclassification
of significant additional quantities to the proved category.
In computing future revenues from gas reserves attributable to the
Company's domestic interests, prices in effect at December 31, 1996 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
14
somewhat lower than December gas prices. For domestic gas sold under contract,
the contract gas price including fixed and determinable escalations, exclusive
of inflation adjustments, was used until the contract expires and then was
adjusted to the current market price for the area and held at this adjusted
price to depletion of the reserves. In computing future revenues from liquids
attributable to the Company's domestic interests, prices in effect at December
31, 1996 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 with PTT 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, 1996, in accordance with Commission
guidelines. In computing future revenues from liquids attributable to the
Company's interests in the Kingdom of Thailand, a price of $24.56 was used,
which the Company believes approximates the price that the Company would have
received for production from the Concession under the memorandum of
understanding with PTT on December 31, 1996, if production had been sold to PTT
on that date, 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 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.
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 1996. The future production
rates from reservoirs now on production may be more or less than estimated
because of, among other reasons, mechanical breakdowns and changes in market
demand or allowables set by regulatory bodies. Properties which are not
currently producing may start producing earlier or later than anticipated in
the estimates of future production rates.
The future prices received by the Company for the sales of its production
may be higher or lower than the prices used in calculating the estimates of
future net revenues and the present value thereof as set forth herein, and the
operating costs and other costs relating to such production may also increase
or decrease from existing levels; however, such possible changes in prices and
costs were, in accordance with rules adopted by the Commission, omitted from
consideration in arriving at such estimates.
There are numerous uncertainties in estimating the quantity of proved
reserves and in projecting the future rates of production and timing of
development expenditures. Oil and gas reserve engineering must be recognized
as a subjective process of estimating underground accumulations of oil and gas
that cannot be measured in an exact way, and estimates of other engineers might
differ materially from those of Ryder Scott, the Company's reserve engineers.
The accuracy of any reserve estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserve estimates are often
different from the quantities of oil and gas that are ultimately recovered.
15
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. In addition, estimates
are from time to time furnished to governmental agencies in connection with
specific matters pending before such agencies. The basis for reporting
reserves to these agencies, in some cases, is not comparable to that furnished
above because of the nature of the various reports required. The major
differences 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 1996, 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.
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.
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.
Regulations of the Department of the Interior currently impose absolute
liability upon the lessee under a federal lease for the costs of clean-up of
pollution resulting from a lessee's operations, and such lessee may also be
subject to possible legal liability for pollution damages. The Company
maintains insurance against costs of clean-up operations, but is not fully
insured against all such risks. A serious incident of pollution may, as it has
in the past, also result in the Department of the Interior requiring lessees
under federal leases to suspend or cease operation in the affected area.
The 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
16
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 ranging 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 that 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 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 an gas operations, many of the costs
attributable to environmental control facilities would have been incurred
absent environmental regulations as prudent, safe oilfield practice. During
1996, the Company incurred capital expenditures of approximately $1,971,000 for
environmental control facilities, primarily relating to the completion of two
salt water disposal facilities in New Mexico and the installation of certain
environmental control facilities on two platforms installed in the Gulf of
Thailand and on one platform installed in the Gulf of Mexico. The Company
currently has budgeted approximately $1,240,000 for expenditures involving
environmental control facilities during 1997, including, among other things,
two salt water disposal facilities and environmental control equipment for one
platform 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 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
17
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.
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 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 of 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. Many of these orders have been challenged on rehearing to the
FERC, and 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 December 31, 1996, the Company and its subisidiary Thaipo had 132
full-time employees, including eight in its Bangkok, Thailand office. 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.
18
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 1, 1997, 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
and Chief Executive Officer 51 1991
Kenneth R. Good Corporate Senior Vice President 59 1996
Stuart P. Burbach Vice President and
Offshore Division Manager 44 1991
Jerry A. Cooper Vice President and
Western Division Manager 48 1990
John W. Elsenhans Vice President -- Finance
and Treasurer 44 1995
Harvey L. Gold Vice President -- Engineering 61 1988
Thomas E. Hart Vice President and Controller 54 1988
R. Phillip Laney Vice President and
International Division Manager 56 1991
John O. McCoy, Jr. Vice President and
Chief Administrative Officer 45 1989
J. D. McGregor Vice President -- Sales 52 1988
Ronald B. Manning Vice President and General Counsel 43 1995
Sammie M. Shaw Vice President -- Operations 65 1992
Gerald A. Morton Corporate Secretary and
Associate General Counsel 38 1995
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. Good, who joined the
Company in 1977, served as Senior Vice President -- Land and Budgets since
1991; Mr. Burbach, who rejoined the Company in 1991, was Vice President of
Norfolk Holding Inc. from 1986 until rejoining the Company; Mr. Cooper served
in various positions since joining the Company in 1979; Mr. Elsenhans was
Director, Corporate Finance for the Company since 1991; Mr. Gold was Manager of
Reservoir Engineering for the Company since joining the Company in 1977; Mr.
Hart was Controller for the Company since joining the Company in 1977; Mr.
Laney, who joined the Company in 1977, served as International Exploration
Manager for the Company since 1983; Mr. McCoy served as Director of Personnel
and Administration for the Company since joining the Company in 1978; Mr.
McGregor was Manager of Hydrocarbon Sales and Contracts for the Company since
joining the Company in 1981; Mr. Manning, who joined the Company in 1987, was
Corporate Secretary and an Associate General Counsel for the Company since
1990; Mr. Shaw was Operations Manager for the Company since joining the Company
in 1981; 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.
19
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY
HOLDER MATTERS.
The following table shows the range of low and high sales prices of the
Company's Common Stock (the "Common Stock") on the New York Stock Exchange
composite tape where the Company's common stock trades under the symbol PPP.
The Company's common stock is also listed on the Pacific Stock Exchange.
Low High
--- ----
1995
1st Quarter 16 20 1/2
2nd Quarter 19 1/2 25 3/8
3rd Quarter 21 1/8 25
4th Quarter 19 3/8 29
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
As of March 10, 1997, there were 3,141 holders of record of the Company's
Common Stock.
In each of 1995 and 1996, the Company paid four quarterly dividends of
$0.03 per share on its Common Stock. In this regard, the Company reinstated the
practice of declaring a quarterly cash dividend commencing in the third quarter
of 1994. 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, the Company may not, subject to certain
exceptions, pay any dividends on its capital stock or make any other
distributions on shares of its capital stock (other than dividends or
distributions payable solely in shares of such capital stock) or 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 from and
after a specified date plus the proceeds of the issuance of capital stock after
the same specified date or if the net worth of the Company is negative. As of
December 31, 1996, $98,659,000 was available for dividends under this
limitation.
20
ITEM 6. SELECTED FINANCIAL DATA.
For the Year Ended December 31,
-----------------------------------------------------------------
1996 1995 1994 1993 1992
------- ------ ------ ------ --------
FINANCIAL DATA
(Expressed in thousands, except per share data)
Revenues:
Crude oil and condensate $ 96,908 $ 76,557 $ 65,141 $ 64,042 $ 64,224
Natural gas 94,589 72,032 99,093 66,173 67,366
Natural gas liquids 11,867 8,097 9,189 7,288 5,833
Other, net 778 773 133 (950) 1,705
-------- -------- -------- -------- --------
Oil and gas revenues 204,142 157,459 173,556 136,553 139,128
Interest on tax refunds -- -- -- 2,322 --
Gains (losses) on sales (165) 100 52 679 1,702
-------- -------- -------- -------- --------
Total $203,977 $157,559 $173,608 $139,554 $140,830
======== ======== ======== ======== ========
Income before extraordinary item $ 33,581 $ 9,230 $ 27,374 $ 25,061 $ 18,495
Extraordinary losses (821) -- (307) -- --
-------- -------- -------- -------- --------
Net income $ 32,760 $ 9,230 $ 27,067 $ 25,061 $ 18,495
======== ======== ======== ======== ========
Per share data:
Primary earnings:
Before extraordinary item $ 0.98 $ 0.28 $ 0.82 $ 0.76 $ 0.66
Extraordinary item (0.02) -- (0.01) -- --
-------- -------- -------- -------- --------
Net income $ 0.96 $ 0.28 $ 0.81 $ 0.76 $ 0.66
======== ======== ======== ======== ========
Price range of common stock:
High $ 48.38 $ 29.00 $ 24.25 $ 21.00 $ 13.88
Low $ 24.38 $ 16.00 $ 15.63 $ 9.75 $ 5.13
Weighted average number of common and
common equivalent shares
outstanding 34,034 33,490 33,352 32,860 27,929
Long-term debt at year end $246,230 $163,249 $149,249 $130,539 $129,260
Production payment obligation
at year end -- -- -- -- $ 24,854
Shareholders' equity at year end $107,282 $ 71,708 $ 64,037 $ 33,803 $ 5,648
Total assets at year end $479,242 $338,177 $298,826 $239,774 $206,347
PRODUCTION (SALES) DATA
Net daily average and weighted average
price:
Natural gas (Mcf per day) 107,700 121,000 144,800 91,700 105,200
Price (per Mcf) $ 2.40 $ 1.63 $ 1.88 $ 1.98 $ 1.75
Crude oil-condensate (Bbl per day) 11,968 11,786 11,100 9,851 8,699
Price (per Bbl) $ 22.12 $ 17.80 $ 16.08 $ 17.81 $ 20.17
Natural gas liquids (Bbl per day) 2,173 1,998 2,222 1,678 1,181
Price (per Bbl) $ 14.92 $ 11.10 $ 11.33 $ 11.90 $ 13.50
CAPITAL EXPENDITURES (Expressed in thousands)
Oil and gas:
Domestic Offshore --
Exploration $ 16,800 $ 13,300 $ 2,800 $ 4,600 $ 1,700
Development 73,900 17,800 44,100 33,700 5,500
Purchase of reserves -- -- 32,600 -- 8,900
Domestic Onshore --
Exploration 10,400 8,800 6,800 5,200 4,900
Development 27,800 22,400 23,700 24,300 15,600
Purchase of reserves -- 7,900 -- -- --
International --
Exploration 8,500 5,500 5,100 4,600 1,400
Development 54,700 24,400 -- -- --
Purchase of reserves -- 4,200 -- -- --
-------- -------- -------- --------- --------
Total oil and gas 192,100 104,300 115,100 72,400 38,000
Other 1,600 500 1,200 200 600
-------- -------- -------- -------- --------
Total $193,700 $104,800 $116,300 $ 72,600 $ 38,600
======== ======== ======== ======== ========
21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
RESULTS OF OPERATIONS
The Company reported net income for 1996 of $32,760,000 or $0.96 per share
($35,843,000 or $0.94 per share on a fully diluted basis) compared to net
income for 1995 of $9,230,000 or $0.28 per share (on both a primary and a fully
diluted basis) and net income for 1994 of $27,067,000 or $0.81 per share (on
both a primary and a fully diluted basis). The Company recorded extraordinary
losses of $307,000 during the second quarter of 1994 related to the early
retirement of the Company's 10.25% Convertible Subordinated Notes, due 1999
(the "10.25% Notes") with the proceeds from the Company's issuance on
March 16, 1994, of its 5-1/2% Convertible Subordinated Notes, due 2004 (the
"2004 Notes") and $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 1996 of 34,034,000
(37,951,000 on a fully diluted basis), compared to 33,490,000 (on both a primary
and a fully diluted basis) for 1995 and 33,352,000 (36,451,000 on a fully
diluted basis) for 1994. The yearly increases in the weighted average number of
common and common equivalent 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
fully diluted basis primarily reflect additional common shares issuable upon the
assumed conversion of the Company's 2004 Notes in 1994 and 1996 (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. Earnings applicable to common stock for 1994,
assuming full dilution, was $29,448,000. However, the dilution resulting from
the assumed conversion of the 2004 Notes in 1994 was not sufficient to change
reported earnings per share in 1994.
The Company's total revenues for 1996 were $203,977,000, an increase of
approximately 29% from total revenues of $157,559,000 for 1995, and an increase
of approximately 17% from total revenues of $173,608,000 for 1994. The
increase in the Company's total revenues for 1996, compared to 1995 and 1994,
resulted primarily from the substantial increase in prices that the Company
received for its natural gas and liquid hydrocarbon (including crude oil,
condensate and natural gas liquid ("NGL")) production volumes and, to a lesser
extent, an increase in the Company's liquid hydrocarbon production volumes,
which was only partially offset by a decline in the Company's natural gas
production volumes.
The Company's oil and gas revenues for 1996 were $204,142,000, an increase
of approximately 30% from oil and gas revenues of $157,459,000 for 1995, and an
increase of approximately 18% from oil and gas revenues of $173,556,000 for
1994. The following table reflects an analysis of variances in the Company's
oil and gas revenues between 1996 and the previous two years:
1996 Compared To
-----------------------
1995 1994
---- ----
(Expressed in thousands)
Increase (decrease) in oil and gas revenues
resulting from variances in:
Natural Gas
Price $ 33,907 $ 27,685
Production (11,350) (32,189)
-------- --------
22,557 (4,504)
-------- --------
Crude oil and condensate
Price 18,614 24,486
Production 1,737 7,281
-------- --------
20,351 31,767
-------- --------
Natural gas liquids ("NGL") and other, net 3,775 3,323
-------- --------
Total increase in oil and gas revenues $ 46,683 $ 30,586
======== ========
22
The average price that the Company received for its natural gas production
during 1996 averaged $2.40 per Mcf. The average price that the Company
received for its natural gas production in 1996 compared favorably with the
average price that the Company had received during the preceding two years of
$1.63 per Mcf for 1995 (an increase of approximately 47%) and $1.88 per Mcf for
1994 (an increase of approximately 28%). The Company's natural gas production
for 1996 averaged 107.7 MMcf per day, a decrease of approximately 11% from
average production of 121 MMcf per day in 1995, and a decrease of approximately
26% from average production of 144.8 MMcf per day for 1994. The decrease in
the Company's average natural gas production for 1996, compared to 1995 and
1994, resulted primarily from the difference between the high initial natural
gas production rates from horizontal wells drilled from the Company's Eugene
Island Block 295 "B" platform which commenced in late February 1994 and the
subsequent natural production decline from those reservoirs, the slowdown of
development drilling, workover and recompletion work on certain of the
Company's non-operated properties in the Gulf of Mexico, largely due to a
decrease in planned drilling by the operators of such properties and production
curtailments due to adverse weather conditions (and drilling and workover
operations on certain of the Company's properties), along with the natural
decline in deliverability from certain of the Company's more mature properties.
Those decreases were only partially offset by new and increased production from
the Company's continued offshore drilling and workover program. As of March 1,
1997, the Company was not a party to any natural gas futures contracts.
Crude oil and condensate prices received by the Company averaged $22.12 per
barrel in 1996, an increase of approximately 24% compared to an average of
$17.80 per barrel in 1995, and an increase of approximately 38% compared to an
average price of $16.08 per barrel that the Company received in 1994. Crude
oil and condensate production for 1996 averaged 11,968 Bbls per day, an
increase of approximately 2% from 11,786 Bbls per day for 1995, and an increase
of approximately 8% from 11,100 Bbls per day for 1994. The increase in the
Company's crude oil and condensate production for 1996, compared to 1995 and
1994, resulted primarily from ongoing development drilling and workover
programs in the Gulf of Mexico and in Lea and Eddy Counties of southeastern New
Mexico, which was only partially offset by the slowdown of development
drilling, workover and recompletion work on certain of the Company's
non-operated properties in the Gulf of Mexico, largely due to a decrease in
planned drilling by the operators of such properties and production
curtailments due to adverse weather conditions (and drilling and workover
operations on certain of the Company's properties), along with the natural
decline in deliverability from certain of the Company's more mature properties.
As of March 1, 1997, the Company was not a party to any crude oil swap
agreements.
Liquid products are often extracted from natural gas streams and sold
separately as NGL. In addition, the Company's oil and gas revenues for 1996,
1995 and 1994 also reflect adjustments for various miscellaneous items. The
Company's NGL and other, net revenues for 1996 increased $3,775,000 from those
reported in 1995, and $3,323,000 from those reported in 1994. The increase in
NGL and other, net revenues in 1996, compared with 1995 and 1994, primarily
related to an increase in the price that the Company received for its NGL
production volumes and, to a lesser extent, an increase in such production
volumes.
The Company's average liquid hydrocarbon (including crude oil, condensate
and NGL) production during 1996 was 14,141 Bbls per day, an increase of
approximately 3% from an average total liquids production of 13,784 Bbls per
day for 1995, and an increase of approximately 6% from an average total liquids
production of 13,322 Bbls per day for 1994.
The Company currently anticipates that its ongoing exploration and
development drilling program during 1996, both domestically and in the Gulf of
Thailand, should lead to substantially increased production during 1997. In
particular, the Company currently anticipates that production from its interest
in the Tantawan Field, which came on production in early February 1997, and two
wells drilled from the East Cameron Block 334 "E" platform should contribute a
substantial amount of new production to the Company's total natural gas and
liquid hydrocarbon production volumes by mid-1997. See "Business -- Domestic
Offshore Operations; Significant Offshore Operating Areas During 1996; East
Cameron, and -- International Operations; Significant International Operating
Areas During 1996; Tantawan Field."
Lease operating expenses for 1996 were $37,628,000, an increase of
approximately 7% from lease operating expenses of $35,071,000 for 1995, and an
increase of approximately 26% from lease operating expenses of $29,768,000 for
1994. The increase in lease operating expenses for 1996, compared to 1995 and
1994, resulted primarily from increased costs to the Company (and the entire
offshore oil industry) because of an increasing short-
23
age of qualified offshore service contractors, which has permitted such
contractors to increase the costs of their services significantly in the last
year, 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. To a lesser extent, lease
operating expenses for 1996, compared to 1995 and 1994, also increased as a
result of a general maintenance and repair program that was undertaken on many
of the Company's operated properties, for which no corresponding offsets of such
magnitude existed in the comparable prior periods.
General and administrative expenses for 1996 were $18,028,000, an increase
of approximately 10% from general and administrative expenses of $16,400,000
for 1995, and an increase of approximately 13% from general and administrative
expenses of $15,984,000 for 1994. The increase in general and administrative
expenses for 1996, compared to 1995 and 1994, was related to, among other
things, the costs associated with the establishment of a Company office in
Bangkok, Thailand in connection with the Company's development project and
other activities in the Gulf of Thailand, an increase in the number of Company
employees resulting from the Company's increased exploration and production
related activities and to normal salary and concomitant benefit expense
adjustments.
Exploration expenses consist primarily of delay rentals and geological and
geophysical costs which are expensed as incurred. Exploration expenses for
1996 were $16,777,000, an increase of approximately 125% from exploration
expenses of $7,468,000 for 1995, and an increase of approximately 219% from
exploration expenses of $5,257,000 for 1994. The increase in exploration
expenses for 1996, compared to 1995 and 1994, resulted primarily from increased
geophysical activity by the Company, including the costs of conducting and
processing certain proprietary 3-D seismic surveys on its domestic onshore and
offshore properties, as well as in the Gulf of Thailand, together with the cost
of acquiring several non-proprietary 3-D seismic surveys in the Gulf of Mexico.
In addition, a portion of the increase in exploration expenses was attributable
to increased delay rental expense resulting from the Company's acquisition of
additional prospective oil and gas acreage. While increases in the Company's
exploration expenses are a component of, and generally correlate fairly closely
with, increases in the Company's capital and exploration budget, the Company
does not currently expect its exploration expenses in 1997 to increase
significantly over those incurred in 1996.
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 1996 were
$8,579,000, an increase of approximately 28% from dry hole and impairment costs
of $6,703,000 for 1995, and an increase of approximately 21% from dry hole and
impairment costs of $7,088,000 for 1994.
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. 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's
DD&A expense for 1996 was $61,857,000, a decrease of approximately 10% from DD&A
expenses of $68,489,000 for 1995, and a decrease of approximately 2% from DD&A
expenses of $63,308,000 for 1994. The decrease in the Company's DD&A expenses
for 1996, compared to 1995, resulted primarily from a decrease in the Company's
composite DD&A rate and from a decrease in the Company's natural gas production.
The decreases in the Company's DD&A expenses for 1996, compared to 1994,
resulted primarily from a decrease in the Company's natural gas production,
partially offset by an increase in the Company's composite DD&A rate. The
composite DD&A rate for all of the Company's producing fields for 1996 was $0.87
per equivalent Mcf ($5.20 per equivalent barrel), a decrease of approximately 4%
from a composite DD&A rate of $0.91 per equivalent Mcf ($5.47 per equivalent
barrel) for 1995, but an increase of approximately 13% from a composite DD&A
rate of $0.77 per equivalent Mcf ($4.59 per equivalent barrel) for 1994. The
Company produced 70,472,000 equivalent Mcf (11,745,000 equivalent Bbls) in 1996,
a decrease of approximately 5% from the 74,337,000 equivalent Mcf (12,389,000
equivalent Bbls) produced in 1995, and a decrease of approximately 14% from the
82,008,000 equivalent Mcf (13,668,000 equivalent Bbls) produced in 1994. See
"Financial Statements and Supplementary Data --Note 1 of Notes to Consolidated
Financial Statements."
24
Interest charges for 1996 were $13,203,000, an increase of approximately
18% from interest charges of $11,167,000 for 1995, and an increase of
approximately 31% from interest charges of $10,104,000 for 1994. The increase in
the Company's interest charges for 1996, compared to 1995 and 1994, resulted
primarily from an increase in the amount of debt outstanding that was only
partially offset by, among other things, a decrease in the average interest rate
paid by the Company on its debt. Capitalized interest for 1996 was $4,244,000,
an increase of approximately 131% from capitalized interest of $1,834,000 for
1995, and an increase of approximately 474% from capitalized interest of
$739,000 for 1994. The increase in the amount of interest capitalized by the
Company in 1996, compared to 1995 and 1994, related primarily to the
capitalization of interest expenses resulting from the engineering, acquisition
and construction of facilities and equipment for the Company's Tantawan Field
and the Company's East Cameron 334/335 Block "D" platform (both of which
commenced in 1995) and the Company's East Cameron 334/335 Block "E" platform
(commencing in 1996). See "Business -- Domestic Offshore Operations; Significant
Offshore Operating Areas During 1996; East Cameron."
As of March 1, 1997, the Company was a party to an interest rate swap
agreement. The swap agreement, which terminates on March 10, 1998, effectively
changes the interest rate paid by the Company on $5,000,000 of debt from a
market based variable rate to a fixed rate of 7.2%.
Income tax expense for 1996 was $18,800,000, an increase of approximately
284% from income tax expense of $4,891,000 for 1995, and an increase of
approximately 21% from income tax expense of $15,517,000 for 1994. The
increase in income tax expense for 1996, compared to 1995 and 1994, resulted
primarily from increased pretax income.
LIQUIDITY AND CAPITAL RESOURCES
The Company's Consolidated Statement of Cash Flows for the year ended
December 31, 1996, reflects net cash provided by operating activities of
$92,898,000. In addition to the net cash provided by operating activities, the
Company also received $3,378,000 from the exercise of stock options, had net
borrowings of $7,000,000 under its revolving credit agreement and uncommitted
money market credit lines with certain banks and received net proceeds totaling
$111,884,000 from the offering of the 2006 Notes. The Company invested
$172,032,000 of such cash flow in capital projects during 1996, paid
$40,699,000 to redeem its 8% Debentures and paid $3,979,000 ($0.03 per share
for four quarters) in cash dividends to holders of the Company's common stock.
Of the $172,032,000 invested in capital projects, $35,254,000 was applicable to
1995 projects and $136,778,000 was applicable to 1996 capital projects. The
Company's total debt at December 31, 1996, was $246,230,000. As of December 31,
1996, the Company had $3,054,000 in cash and cash investments.
The Company's capital and exploration budget for 1996, 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 $210,000,000, an
increase of approximately 2% from the Company's capital and exploration
expenditures (excluding purchased reserves and interest capitalized) of
$206,267,000 for 1996, an increase of approximately 113% over capital and
exploration expenditures (excluding purchased reserves and interest
capitalized) of $98,560,000 for 1995, and an increase of approximately 139%
over capital and exploration expenditures (excluding purchased reserves and
interest capitalized) of approximately $88,300,000 for 1994.
In addition to anticipated capital and exploration expenditures, other
material 1997 cash requirements that the Company currently anticipates include
ongoing operating, general and administrative, income tax, and interest
expenses and the payment of dividends on its common stock, including a $0.03
per share dividend on its common stock paid on February 21, 1997, to
stockholders of record on February 7, 1997. The Company currently anticipates
that cash provided by operating activities, funds available under its Credit
Agreement, uncommitted money market credit lines and amounts that the Company
currently believes it can raise from external sources, will be sufficient to
fund the Company's ongoing expenses, acquisitions, its 1997 capital and
exploration budget and anticipated future dividend payments. In this regard,
the Company reinstated the practice of declaring a quarterly cash dividend
commencing in the third quarter of 1994. 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.
25
Effective June 1, 1995, the Company entered into an amended and restated
credit agreement (the "Credit Agreement") with the same banks that were parties
to the credit agreement that it superseded. The Credit Agreement provides for
an unsecured $150,000,000 revolving/term credit facility which will be fully
revolving until January 1, 1998, after which the balance will be due in eight
quarterly term loan installments, commencing April 30, 1998. However, 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 the amounts due under the Credit Agreement which commences in 1998. The
amount that may be borrowed under the Credit Agreement may not exceed a
borrowing base, determined semiannually by the lenders in accordance with the
Credit Agreement, based on the discounted present value of future net revenues
from certain of the Company's oil and gas reserves and the provisions of the
Credit Agreement. As of March 1, 1997, the borrowing base exceeded
$150,000,000. 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, a certificate
of deposit rate plus 1-1/8%, or LIBOR plus 1%, at the Company's option. A
commitment fee on the unborrowed amount under the Credit Agreement is also
charged. The commitment fee is 5/16 of 1% per annum on the unborrowed amount
under the Credit Agreement that is designated as "active" and 1/8 of 1% per
annum on the unborrowed amount under the Credit Agreement that is designated as
"inactive." Of the $150,000,000 that is currently available under the Credit
Agreement (subject to borrowing base limitations), $100,000,000 is designated
as "active" and $50,000,000 is designated as "inactive."
The Company has also entered into separate letter agreements with two banks
under which each bank may provide a $10,000,000 uncommitted money market line
of credit. The two lines of credit are 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 $10,000,000 of
additional senior debt, which would include debt incurred under these lines of
credit. As of December 31, 1996, indebtedness in the principal amount of
$45,000,000 was outstanding under the Credit Agreement and the two letter
agreements.
The outstanding principal amount of the 2004 Notes was $86,230,000 as of
December 31, 1996. 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%
of their principal amount and decreasing percentages thereafter. No sinking
fund payments are required on the 2004 Notes. The 2004 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
2004 Notes), at 100% of the principal amount.
The outstanding principal amount of the 2006 Notes was $115,000,000 as of
December 31, 1996. 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.
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 a 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. The Charter currently provides for an
estimated charter hire commitment of
26
$24,000,000 per year ($11,122,000 net to Thaipo), commencing upon its
installation in the field. 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%).
OTHER MATTERS
Publicly held companies are asked to comment on the effects of inflation on
their business. Currently annual inflation in terms of the decrease in the
general purchasing power of the dollar is running much below the general annual
inflation rates experienced in the past. While the Company, like other
companies, continues to be affected by fluctuations in the purchasing power of
the dollar, such effect is not currently considered significant.
27
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1996
POGO PRODUCING COMPANY AND SUBSIDIARIES
HOUSTON, TEXAS
28
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,
1996 and 1995, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1996. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant estimates made
by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Pogo Producing Company and
subsidiaries as of December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 3, 1997
29
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31,
------------------------------------
1996 1995 1994
--------- --------- ----------
(Expressed in thousands,
except per share amounts)
Revenues:
Oil and gas......................... $204,142 $157,459 $173,556
Gains (losses) on sales............. (165) 100 52
-------- -------- --------
Total............................ 203,977 157,559 173,608
-------- -------- --------
Operating Costs and Expenses:
Lease operating..................... 37,628 35,071 29,768
General and administrative.......... 18,028 16,400 15,984
Exploration......................... 16,777 7,468 5,257
Dry hole and impairment............. 8,579 6,703 7,088
Depreciation, depletion
and amortization................... 61,857 68,489 63,308
-------- -------- --------
Total............................ 142,869 134,131 121,405
-------- -------- --------
Operating Income....................... 61,108 23,428 52,203
Interest:
Charges............................. (13,203) (11,167) (10,104)
Income.............................. 232 26 53
Capitalized......................... 4,244 1,834 739
-------- -------- --------
Income Before Taxes and
Extraordinary Item.................... 52,381 14,121 42,891
-------- -------- --------
Income Tax Expense..................... (18,800) (4,891) (15,517)
-------- -------- --------
Income Before Extraordinary
Item.................................. 33,581 9,230 27,374
Extraordinary Losses on Early
Extinguishments of Debt,
Net of Taxes....................... (821) -- (307)
-------- -------- --------
Net Income............................. $ 32,760 $ 9,230 $ 27,067
======== ======== ========
Earnings per Common Share:
Primary
Before extraordinary item........ $ 0.98 $0.28 $ 0.82
Extraordinary item............... (0.02) -- (0.01)
-------- -------- --------
Net income.......................... $ 0.96 $0.28 $ 0.81
======== ======== ========
Fully diluted
Before extraordinary item........ $ 0.96 $0.28 $ 0.82
Extraordinary item............... (0.02) -- (0.01)
-------- -------- --------
Net income....................... $ 0.94 $0.28 $ 0.81
======== ======== ========
Dividends per Common Share............. $ 0.12 $0.12 $ 0.06
======== ======== ========
The accompanying notes to consolidated financial
statements are an integral part hereof.
30
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
-------------------------
1996 1995
----------- -----------
(Expressed in thousands)
ASSETS
Current Assets:
Cash and cash investments.......... $ 3,054 $ 4,481
Accounts receivable................ 30,031 21,820
Other receivables.................. 35,027 30,504
Inventories........................ 6,165 6,438
Other.............................. 641 722
---------- ----------
Total current assets............... 74,918 63,965
---------- ----------
Property and Equipment:
Oil and gas, on the basis of
successful efforts accounting
Proved properties being amortized.. 1,079,523 963,330
Unevaluated properties and
properties under development,
not being amortized............... 111,192 47,431
Other, at cost..................... 8,773 8,811
---------- ----------
1,199,488 1,019,572
Less--accumulated depreciation,
depletion, and amortization,
including $4,822 and $5,603
respectively, applicable to other
property.......................... 814,623 757,739
---------- ----------
384,865 261,833
---------- ----------
Other................................. 19,459 12,379
---------- ----------
$ 479,242 $ 338,177
---------- ----------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable................... $ 7,676 $ 10,007
Other payables..................... 56,961 35,254
Current portion of long-term debt.. -- 3,000
Accrued interest payable........... 1,957 1,714
Accrued payroll and related
benefits......................... 1,490 1,239
Other.............................. 163 103
---------- ----------
Total current liabilities....... 68,247 51,317
Long-Term Debt........................ 246,230 163,249
Deferred Federal Income Tax........... 46,321 41,409
Deferred Credits...................... 11,162 10,494
---------- ----------
Total liabilities............... 371,960 266,469
---------- ----------
Shareholders' Equity:
Preferred stock, $1 par; 2,000,000
shares authorized................. -- --
Common stock, $1 par; 100,000,000
shares authorized, 33,321,381
and 33,006,972 shares issued,
respectively...................... 33,321 33,007
Additional capital................. 139,337 132,881
Retained earnings
(deficit)......................... (65,075) (93,856)
Currency translation adjustment.... 23 --
Treasury stock, at cost............ (324) (324)
---------- ----------
Total shareholders' equity...... 107,282 71,708
---------- ----------
$ 479,242 $ 338,177
========== ==========
The accompanying notes to consolidated financial
statements are an integral part hereof.
31
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
---------------------------------------------
1996 1995 1994
--------- ---------- ----------
(Expressed in thousands)
Cash flows from operating activities:
Cash received from customers......................... $ 195,931 $ 164,065 $ 165,549
Federal income taxes and interest received........... -- 6,000 3,364
Operating, exploration, and general
and administrative expenses paid.................... (74,512) (56,997) (50,894)
Interest paid........................................ (12,960) (11,036) (9,620)
Federal income taxes paid............................ (12,500) (6,000) (7,500)
Settlement of natural gas transportation and
exchange imbalance.................................. -- -- (2,168)
Other................................................ (3,061) 301 542
--------- --------- ---------
Net cash provided by operating activities........ 92,898 96,333 99,273
--------- --------- ---------
Cash flows from investing activities:
Capital expenditures................................. (172,032) (96,403) (85,375)
Purchase of proved reserves.......................... -- (11,921) (32,578)
Proceeds from the sale of property and
tubular stock....................................... 100 100 52
--------- --------- ---------
Net cash used in investing activities............ (171,932) (108,224) (117,901)
--------- --------- ---------
Cash flows from financing activities:
Proceeds from issuance of new debt................... 115,000 -- 86,250
Net borrowings (payments) under revolving
credit agreements................................... 6,000 15,000 (53,000)
Net borrowings under uncommitted lines
of credit with banks................................ 1,000 2,000 7,000
Proceeds from exercise of stock options.............. 3,378 1,717 3,687
Purchase of 8% debentures due 2005................... (40,699) (450) (216)
Payment of cash dividends on common stock............ (3,979) (3,946) (1,966)
Debt issue expenses paid............................. (3,116) -- (2,446)
Principal payments of other long-term debt
obligations......................................... -- (871) (24,472)
--------- --------- ---------
Net cash provided by financing activities........ 77,584 13,450 14,837
--------- --------- ---------
Effect of exchange rate change.......................... 23 -- --
--------- --------- ---------
Net increase (decrease) in cash and cash
investments............................................ (1,427) 1,559 (3,791)
Cash and cash investments at the beginning of
the year............................................... 4,481 2,922 6,713
--------- --------- ---------
Cash and cash investments at the end of the year........ $ 3,054 $ 4,481 $ 2,922
========= ========= =========
Reconciliation of net income to net cash provided
by operating activities:
Net income........................................... $ 32,760 $ 9,230 $ 27,067
Adjustments to reconcile net income to net
cash provided by operating activities:
Extraordinary losses on early
extinguishments of debt, net of taxes............... 821 -- 307
(Gains) losses on sales.............................. 165 (100) (52)
Depreciation, depletion and amortization............. 61,857 68,489 63,308
Dry hole and impairment.............................. 8,579 6,703 7,088
Interest capitalized................................. (4,244) (1,834) (739)
Increase in deferred federal income taxes............ 7,175 5,592 8,374
Change in assets and liabilities:
(Increase) decrease in accounts receivable....... (8,211) 7,095 (10,435)
Decrease in federal income taxes and
interest receivable............................. -- -- 3,320
(Increase) decrease in other current assets...... 81 23 (18)
Increase in other assets......................... (5,228) (1,187) (1,426)
Increase (decrease) in accounts payable.......... (2,079) 1,942 (242)
Increase in accrued interest payable............. 243 131 381
Increase in accrued payroll and related
benefits........................................ 251 2 232
Increase (decrease) in other current
liabilities..................................... 60 63 (124)
Increase in deferred credits..................... 668 184 2,232
--------- --------- ---------
Net cash provided by operating activities............... $ 92,898 $ 96,333 $ 99,273
========= ========= =========
The accompanying notes to consolidated financial statements
are an integral part hereof.
32
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
Cumulative
Retained Foreign Share-
Shares Common Additional Earnings Treasury Currency holders'
Outstanding Stock Capital (Deficit) Stock Translation Equity
------------ ------- ---------- ----------- -------- ------------ --------
(Dollars expressed in thousands)
Balance at December 31, 1993........ 32,433,622 $32,449 $125,919 $(124,241) $(324) $-- $ 33,803
Net income.......................... -- -- -- 27,067 -- -- 27,067
Exercise of stock options........... 376,639 377 4,756 -- -- -- 5,133
Dividends ($0.06 per common share).. -- -- -- (1,966) -- -- (1,966)
---------- ------- -------- --------- ----- --- --------
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
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)
Foreign currency translation gain... -- -- -- -- -- 23 23
---------- ------- -------- --------- ----- --- --------
Balance at December 31, 1996........ 33,305,806 $33,321 $139,337 $ (65,075) $(324) $23 $107,282
========== ======= ======== ========= ===== === ========
The accompanying notes to consolidated financial
statements are an integral part hereof.
33
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, onshore in the United States and internationally in the Gulf of
Thailand. The Company has interests in 86 lease blocks offshore Louisiana and
Texas, approximately 212,000 gross acres onshore in the United States and
approximately 1,300,000 gross acres offshore in the Kingdom of Thailand.
Use of Estimates -
The preparation of these financial statements requires 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.
Inventories -
Inventories consist primarily of tubular goods used in the Company's
operations and are stated at the lower of average cost or market value.
Interest Capitalized -
Interest costs related to financing major oil and gas projects in progress
are capitalized until the projects are evaluated or until production commences
if the projects are evaluated as successful.
Earnings per Share -
Earnings per common and common equivalent share (primary earnings per share)
are based on the weighted average number of shares of Common Stock and common
equivalent shares outstanding during the periods. The dilutive effect of stock
options was considered in the earnings per share reported for the periods. The
8% Debentures (retired on June 28, 1996) were common stock equivalents and were
anti-dilutive in all periods in which they were outstanding. Earnings per common
and common equivalent share assuming full dilution (fully diluted earnings per
share) considered the 10.25% Notes (retired on April 18, 1994) which were anti-
dilutive in all periods in which they were outstanding, the 2004 Notes (issued
on March 16, 1994) which were dilutive for the portion of 1994 in which they
were outstanding (such dilution was not sufficient to change reported earnings
per share) and anti-dilutive for 1995, and dilutive in 1996, the 2006 Notes
(issued June 18, 1996) were anti-dilutive in the 1996 period they were
outstanding. Earnings per share are based on the following:
34
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
1996 1995 1994
------- ------ ------
(Expressed in thousands)
Earnings applicable to Common Stock:
Primary --
Income before extraordinary loss $33,581 $ 9,230 $27,374
Extraordinary loss (821) -- (307)
------- ------- -------
Net income $32,760 $ 9,230 $27,067
======= ======= =======
Fully diluted --
Income before extraordinary loss $36,664 $ 9,230 $29,755
Extraordinary loss (821) -- (307)
------- ------- -------
Net income $35,843 $ 9,230 $29,448
======= ======= =======
Weighted average number of Common Stock
and common equivalent shares outstanding:
Primary 34,034 33,490 33,352
Fully diluted 37,951 33,490 36,451
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, 1996, the Company had taken approximately
3,850 MMcf of natural gas less than it was entitled to based on its interest in
those properties, and approximately 1,963 MMcf more than its entitlement on
other properties placing the Company at year end in a net under-delivered
position of approximately 1,887 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. 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 determined on a cost
center by cost center basis using the units of production method.
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.
35
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Commitments and Contingencies -
The Company has commitments for operating leases for office space in
Houston, Midland and Bangkok and a commitment for an operating lease for a
floating production, storage and off-loading vessel (FPSO) in the Gulf of
Thailand. Rental expense for office space was $1,054,000 in 1996, $861,000 in
1995, and $819,000 in 1994. Lease payments for the FPSO will commence in 1997.
Future minimum lease payments (in thousands of dollars) at December 31, 1996
are as follows:
1997............................ $11,535
1998............................ 12,499
1999............................ 12,383
2000............................ 12,316
2001............................ 12,286
(2) INCOME TAXES
The components of income (loss) before income taxes for each of the three
years in the period ended December 31, 1996, are as follows (expressed in
thousands):
1996 1995 1994
------- ------- -------
United States........... $56,380 $16,899 $44,931
Foreign................. (3,999) (2,778) (2,040)
------- ------- -------
Total................ $52,381 $14,121 $42,891
======= ======= =======
The components of federal income tax expense (benefit) for each of the three
years in the period ended December 31, 1996, are as follows (expressed in
thousands):
1996 1995 1994
------- ------- -------
United States, current......... $12,500 $ -- $ 7,500
United States, deferred (a).... 7,162 5,602 8,374
Foreign, current............... (862) (711) (357)
------- ------- -------
Total....................... $18,800 $ 4,891 $15,517
======= ======= =======
(a) Excludes $443,000 and $165,000 in 1996 and 1994, respectively, of deferred
tax benefits on extraordinary losses of $1,264,000 and $472,000 in 1996 and
1994, respectively.
Total federal income tax expense (benefit) for each of the three years
in the period ended December 31, 1996, 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):
1996 1995 1994
---- ----- -----
Federal statutory income tax rate............... 35.0% 35.0% 35.0%
Increases (reductions) resulting from:
Statutory depletion in excess of tax basis... (0.2) (2.2) (0.1)
Foreign taxes................................ 1.1 1.6 0.9
Other........................................ -- 0.2 0.4
---- ---- ----
35.9% 34.6% 36.2%
==== ==== ====
36
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The deferred federal income tax provision is the result of the difference
between deferred tax liabilities determined at each balance sheet date. The
deferred tax liabilities are determined by applying current tax laws to
temporary differences in the recognition of revenue and expense for tax and
financial purposes. The principal components of the Company's deferred income
tax liability include the following at December 31, 1996 and 1995 (expressed in
thousands):
December 31,
------------------------------
1996 1995
---------- ----------
Temporary differences arise primarily from the following--
Intangible drilling costs, capitalized and amortized for
financial statement purposes and deducted for income
tax purposes................................................. $ 184,981 $ 168,753
Differences in depletion and depreciation rates used for
tangible assets for financial and income tax purposes........ (167,795) (100,491)
Charges to property and equipment, expensed for financial
statement purposes, and capitalized and amortized for
income tax purposes.......................................... 8,089 (47,915)
Interest charges, capitalized and amortized for financial
statement purposes and deducted for income tax purposes...... 21,046 21,062
--------- ---------
Deferred tax liability........................................ $ 46,321 $ 41,409
========= =========
(3) LONG-TERM DEBT
Long-term debt and the amount due within one year at December 31, 1996 and
1995, consists of the following (dollars expressed in thousands):
December 31,
---------------------------
1996 1995
--------- ---------
Senior debt -
Bank revolving credit agreement debt:
Prime rate based loans, borrowings at December 31, 1996
and 1995 at interest rates of 8.25% and 8.5%, respectively................ $ 13,000 $ 2,000
LIBO Rate based loans, borrowings at December 31, 1996 and 1995 at average
interest rates of 6.59% and 6.81%, respectively........................... 22,000 27,000
-------- --------
Total bank revolving credit agreement debt.............................. 35,000 29,000
Uncommitted credit lines with banks, borrowings at December 31, 1996
and 1995 at average interest rates of 7.0% and 6.8%, respectively........... 10,000 9,000
-------- --------
Total senior debt............................................................. 45,000 38,000
-------- --------
Subordinated debt --
5 1/2% Convertible subordinated notes, due 2004............................ 86,230 86,250
5 1/2% Convertible subordinated notes, due 2006............................ 115,000 --
8% Convertible subordinated debentures, due 2005,
retired on June 28, 1996.................................................. -- 41,999
-------- --------
Total subordinated debt....................................................... 201,230 128,249
-------- --------
Total debt.................................................................... 246,230 166,249
-------- --------
Amount due within one year --
Current portion of long-term debt, consisting of sinking fund requirements
on 8% Debentures.......................................................... -- (3,000)
-------- --------
Long-term debt................................................................ $246,230 $163,249
======== ========
37
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Effective June 1, 1995, the Company entered into an amended and restated
bank revolving credit agreement (the "Credit Agreement") which extends to the
Company an unsecured $150,000,000 revolving/term credit facility. The Credit
Agreement will be fully revolving until January 1, 1998 and will convert to a
term loan with eight quarterly installments commencing April 30, 1998. The
amount that may be borrowed under the Credit Agreement may not exceed a
borrowing base determined semiannually by the lenders in accordance with the
Credit Agreement based on the discounted present value of future net revenue
from certain of the Company's oil and gas reserves and the provisions of the
Credit Agreement. The borrowing base currently exceeds $150,000,000. The Credit
Agreement is governed by various financial covenants including requirements to
maintain positive working capital (excluding current maturities of debt) and a
fixed charge ratio, and limitations on indebtedness, creation of liens, the pre-
payment of subordinated debt, the payment of dividends, mergers and
consolidations, 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 bear interest at a base (prime) rate,
certificate of deposit rate plus 1-1/8%, or LIBOR plus 1%, at the Company's
option. A commitment fee on the unborrowed amount under the Credit Agreement is
also charged. The commitment fee is 5/16 of 1% per annum on the unborrowed
amount under the "active" portion of the Credit Agreement and 1/8 of 1% per
annum on the unborrowed amount of the "inactive" portion of the Credit
Agreement. Of the $150,000,000 that is currently available under the Credit
Agreement (subject to borrowing base limitations), $100,000,000 is designated as
"active" and $50,000,000 is designated as "inactive." The Company incurred
commitment fees of $271,000 in 1996, $352,000 in 1995, and $409,000 in 1994
under this and a prior revolving credit agreement.
The Company has also entered into separate letter agreements with two banks
under which each bank may provide a $10,000,000 uncommitted money market line of
credit. The two lines of credit are on an as available or offered basis and the
banks have no obligations to make any advances under the lines. Loans made
under the agreements are for a maximum term of 30 days and are reflected as
long-term debt as the Company has the intent and ability to reborrow such
amounts under its bank revolving credit agreement discussed above. The
agreements may be terminated at any time by the Company or either bank.
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 June 18, 1996 the Company issued $115,000,000 of 5-1/2% Convertible
Subordinated Notes due 2006 ("the 2006 Notes"). The 2006 Notes are convertible
into common stock of the Company at a price of $42.185 per share. The proceeds
from the issuance of the 2006 Notes were used to retire the Company's 8%
Convertible Subordinated Debentures due 2005 (the "8% Debentures"), to repay
amounts outstanding under the Company's bank revolving credit agreement and
uncommitted lines of credit with banks, and to purchase short-term cash
investments. 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 1997, $20,250,000 in
1998, $15,750,000 in 1999, $9,000,000 in 2000 and none in 2001. All of the
current maturities reflected above are related to 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 1998.
38
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(4) 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):
1996 1995 1994
------- ------- -------
Enron Corp. and affiliates......... $58,101 $42,895 $27,630
Coastal Gas Marketing Company...... $18,376 $18,117 $27,609
Scurlock Oil Company............... $ 240 $ 1,757 $21,134
(5) CREDIT RISK
Substantially all of the Company's accounts receivable at December 31, 1996
and 1995, 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 similarily 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 1996 or 1995.
(6) EMPLOYEE BENEFITS
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,
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 in 1996 had no effect on
the Company's results of operations. A summary of the status of the Company's
plans as of December 31, 1996, 1995, and 1994, and changes during the years
ended on those dates is presented below:
Weighted
Number Average
of Exercise
Options Price
--------- ----------
Outstanding, December 31, 1993 1,490,676 $ 9.32
Granted 291,000 $21.77
Exercised (376,639) $ 9.76
Forfeited or expired (17,500) $16.25
---------
Outstanding, December 31, 1994 1,387,537 $11.72
=========
Exercisable, December 31, 1994 957,455 $ 8.86
=========
Available for grant, December 31, 1994 2,088,893
=========
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
39
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Weighted
Number Average
of Exercise
Options Price
--------- ----------
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
The following table summarizes information about stock options outstanding
at December 31, 1996:
Options Outstanding Options Exercisable
----------------------------------- ----------------------
Weighted
Average
Remaining Weighted Weighted
Contractual Average Average
Range of Number Life Exercise Number Exercise
Option Prices Outstanding (days) Price Exercisable Price
- ------------- ------------ ----------- --------- ----------- ---------
$ 4.38 128,500 377 $ 4.38 128,500 $ 4.38
$ 5.56 to $ 8.06 376,512 1,484 $ 6.84 376,512 $ 6.84
$15.13 to $19.13 198,320 2,385 $16.21 197,653 $16.20
$20.31 to $23.88 597,355 2,973 $22.11 319,993 $22.18
$33.06 to $34.50 320,500 3,498 $33.94 -- --
$35.13 to $37.06 75,500 3,458 $36.03 55,000 $36.00
$44.00 to $44.38 10,500 3,598 $44.27 -- --
--------- ---------
Total 1,707,187 2,505 $19.70 1,077,658 $14.31
========= =========
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 fair
value at the grant dates for awards made in 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 of
dollars, except for per share amounts):
1996 1995
------- ------
Net income:
As reported $32,760 $9,230
Pro forma $31,301 $8,781
Earnings per share:
As reported -- Primary $ 0.96 $ 0.28
As reported -- Fully Diluted $ 0.94 $ 0.28
Pro forma -- Primary $ 0.92 $ 0.26
Pro forma -- Fully Diluted $ 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 1996 and 1995, respectively: risk-free interest rates of 6.25% and
6.00%, expected volatility of 39.15% and 41.78%, dividend yields of 0.34% and
0.54%, and an expected life of the options of 4 years in both 1996 and 1995.
40
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The Company has a tax-advantaged savings plan in which all salaried
employees may participate. Under such plan, a participating employee may
allocate up to 10% of his salary, and the Company makes matching contributions
of up to 6% thereof. Funds contributed by the employee and the matching funds
contributed by the Company are held in trust by a bank trustee in six separate
funds. 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
$471,000 to the savings plan in 1996, $277,000 in 1995 and $375,000 in 1994.
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, 1996, 1995, and 1994.
1996 1995 1994
------- -------- --------
Actuarial present value (discounted
at 7-1/4, 7-1/4, and 8-1/2%,
respectively) of benefit obligations:
Accumulated benefit obligations --
Vested............................................. $ 6,408 $ 5,488 $ 3,940
Non-vested......................................... 1,138 1,173 820
------- ------- -------
Total accumulated benefit obligations............ 7,546 6,661 4,760
Projected salary increases (escalated at 5%,
5% and 6%, respectively) and other changes......... 1,804 1,734 1,434
------- ------- -------
Projected benefit obligations for service
rendered to date.................................... 9,350 8,395 6,194
Plan assets at fair value, primarily listed
securities with an expected long-term rate of
return of 8-1/2%....................................... 24,181 19,089 13,988
------- ------- -------
Plan assets in excess of projected benefit
obligations............................................ 14,831 10,694 7,794
Unrecognized:
Net overfunding being recognized over 15 years....... (440) (543) (646)
Net gain arising from the difference between
actual experience and that assumed.................. (9,335) (5,989) (3,443)
Prior service cost................................... (343) (387) (430)
------- ------- -------
Accrued retirement plan asset........................... $ 4,713 $ 3,775 $ 3,275
======= ======= =======
Retirement plan cost (benefit) for 1996, 1995,
and 1994 included the following components:
Service cost, benefits accruing each year with
proration for future salary increases.............. $ 621 $ 480 $ 499
Interest cost on projected benefit obligations....... 604 535 476
Actual return on plan assets......................... (1,615) (1,182) (1,139)
Net amortization and deferral........................ (548) (333) (298)
------- ------- -------
Accrued retirement plan cost (benefit)............... $ (938) $ (500) $ (462)
======= ======= =======
Effective January 1, 1992, the Company adopted the provisions of the
Statement of Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions." The Company currently provides
full medical benefits to its retired employees and dependents. For current
employees, the Company assumes all or a portion of postretirement medical and
term life insurance costs based on the employee's age and length of service with
the Company. The postretirement medical plan has no assets and is currently
funded by the Company on a pay-as-you-go basis.
41
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 1994,
1995 and 1996. The computation assumes that future increases in medical costs
will trend down from 8.8% to 5% per year over the next 9 years for purposes of
estimating future costs. The medical cost trend rate assumption has a
significant effect on the amounts reported. Increasing the assumed medical cost
trend rate by one percent in each year would increase the aggregate of service
and interest cost components of net periodic postretirement benefit cost for
1996 by $130,000 and the accumulated postretirement benefit obligation as of
December 31, 1996 by $980,000.
Annual Deferred Benefit
Expense Costs Obligation
-------- --------- -----------
Balance at January 1, 1994...................................... $3,653 $(6,687)
Amortization of transition costs over 14 years
representing the average remaining service
period of eligible employe.es.................................. $ 304 (304) 304
Amortization of net loss from earlier periods................... 57 57
Service cost, including interest................................ 395
Interest cost on transition obligation.......................... 494
------
1994 expense.................................................... $1,250 (1,250)
======
Current benefits paid........................................... 126
Unrecognized net gain........................................... 1,963
------ -------
Balance at December 31, 1994.................................... 3,349 (5,487)
Amortization of transition costs over 14 years.................. $ 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
======
Plan assets at fair value....................................... --
-------
Funded status at December 31, 1996 (discounted at 7-1/4%)....... $(5,895)
=======
The accumulated postretirement benefit obligation (in thousands of dollars)
at December 31, 1996 is attributable to the following groups:
Retirees and beneficiaries................. $1,892
Dependents of retirees..................... 949
Fully eligible active employees............ 515
Active employees, not fully eligible....... 2,539
------
$5,895
======
42
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(7) 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, 1996 and 1995.
Debt
Instrument Basis of Fair Value Estimate
---------- ----------------------------
Bank revolving credit agreement Fair value is carrying value as of
December 31, 1996 and 1995, based on
the market value interest rates.
Uncommitted credit lines with banks Fair value is carrying value as of
December 31, 1996 and 1995, based on
the market value interest rates.
2004 Notes Fair value is 166% and 118%, of
carrying value as of December 31, 1996
and 1995, respectively, based on the
quoted market prices for this publicly
traded debt.
2006 Notes Fair value is 120% of carrying value as
of December 31, 1996, based on a Value
Line evaluation.
8% Debentures Fair value is 102.5% of carrying value
as of December 31, 1995, based on the
quoted market price for this publicly
traded debt.
The carrying value and estimated fair value of the Company's financial
instruments at December 31, 1996 and 1995 (in thousands of dollars) are as
follows:
1996 1995
--------------------- -------------------
Carrying Fair Carrying Fair
Value Value Value Value
---------- --------- --------- ---------
Cash and cash investments.............. $ 3,054 $ 3,054 $ 4,481 $ 4,481
Debt:
Bank revolving credit agreement..... (35,000) (35,000) (29,000) (29,000)
Uncommitted credit lines with banks. (10,000) (10,000) (9,000) (9,000)
2004 Notes.......................... (86,230) (143,142) (86,250) (101,775)
2006 Notes.......................... (115,000) (138,000) -- --
8% Debentures....................... -- -- (41,999) (43,049)
The Company occasionally enters into forward and futures contracts to
minimize the impact of oil and gas price fluctuations. However, such forward and
futures contracts are not 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, 1996 or 1995.
43
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
(8) EVENT SUBSEQUENT TO DATE OF AUDITOR'S REPORT (UNAUDITED)
On March 3, 1997, the Company completed the purchase of a 46.34% interest in
Maersk Oil (Thailand) Ltd. ("MOTL"). With this acquisition, the Company owns a
46.34% working interest in the entire B8/32 concession in the Gulf of Thailand.
The purchase on a pro-forma basis would have increased the Company's net proved
oil and gas reserves as of December 31, 1996, by the following amounts (all
dollar amounts are expressed in thousands):
Kingdom of Thailand
------------------------------------
Purchase of
As Reported MOTL Pro-Forma
----------- ----------- -----------
Proved Oil, Condensate and
Natural Gas Liquids (Bbls).... 21,331,780 4,830,747 26,162,527
Natural Gas (MMcf)............... 144,998 21,162 166,160
Future net cash flows before
income taxes.................. $ 396,905 $ 85,550 $ 482,455
Discounted future net cash flow
before income taxes........... $ 181,418 $ 23,534 $ 204,952
Total Company
-------------------------------------
Purchase of
As Reported MOTL Pro-Forma
----------- ----------- -----------
Proved Oil, Condensate and
Natural Gas Liquids (Bbls).... 49,602,182 4,830,747 54,432,929
Natural Gas (MMcf)............... 360,944 21,162 382,106
Future net cash flows before
income taxes.................. $ 1,502,375 $ 85,550 $ 1,587,925
Discounted future net cash flow
before income taxes........... $ 954,545 $ 23,534 $ 978,079
44
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)
1996
--------------------------------------
Oil and gas 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
--------------------------------------
Oil and gas 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)
======== ======== =======
1994
--------------------------------------
Oil and gas revenues $173,556 $173,518 $ 38
Lease operating expense (29,768) (29,768) -
Exploration expense (5,257) (3,931) (1,326)
Dry hole and impairment expense (7,088) (7,088) -
Depreciation, depletion and amortization expense (62,723) (62,690) (33)
------- ------- -------
Pretax operating results 68,720 70,041 (1,321)
Income tax (expense) benefit (24,262) (24,619) 357
-------- -------- -------
Operating results $ 44,458 $ 45,422 $ (964)
======== ======== =======
45
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.
1996 1995 1994
-------- ------- --------
Capitalized costs incurred:
Property acquisition - United States $ 5,927 $14,864 $ 36,354
Property acquisition - Kingdom of Thailand - 4,171 -
Exploration - United States 20,651 14,562 5,803
Exploration - Kingdom of Thailand 8,317 5,418 5,022
Development - United States 99,464 39,461 67,143
Development - Kingdom of Thailand 53,564 23,994 -
Interest capitalized 4,244 1,834 739
-------- ------- --------
$192,167 $104,304 $115,061
======== ======= ========
Provision for depreciation, depletion and amortization:
United States $ 61,033 $67,798 $ 62,690
Kingdom of Thailand 101 33 33
-------- ------- --------
$ 61,134 $67,831 $ 62,723
======== ======= ========
46
UNAUDITED SUPPLEMENTARY FINANCIAL DATA - (Continued)
The following information regarding estimates of the Company's proved oil
and gas reserves, which are located offshore in United States waters of the Gulf
of Mexico, onshore in the United States and offshore in the Kingdom of Thailand
is based on reports prepared by Ryder Scott Company Petroleum Engineers. Their
summary report dated February 28, 1997, is set forth as an exhibit to this
Annual Report on Form 10-K and includes definitions and assumptions that served
as the basis for the discussions under the caption "Item 1, Business -
Exploration and Production Data - Reserves." Such definitions and assumptions
should be referred to in connection with the following information.
The following information regarding the Company's Kingdom of Thailand oil
and gas reserves as of December 31, 1996 should be read in conjunction with Note
8 "Event Subsequent to Date of Auditor's Report (Unaudited)."
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, 1993 28,268,441 232,866 22,843,628 199,392 5,424,813 33,474
Revisions of previous estimates 1,286,984 (2,558) 1,286,984 (2,558) - -
Extensions, discoveries
and other additions 6,565,442 49,517 4,315,883 26,252 2,249,559 23,265
Purchase of properties 2,686,919 15,792 2,686,919 15,792 - -
Sale of properties (497) (109) (497) (109) - -
Estimated 1994 production (4,945,677) (52,618) (4,945,677) (52,618) - -
----------- ------- ---------- -------- ---------- -------
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
========== ======= ========== ======== ========== =======
Proved developed reserves
as of:
December 31, 1993 20,976,194 183,139 20,976,194 183,139 - -
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
47
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)
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
========== ========= =========
1994
---------------------------------------
Future gross revenues $ 985,888 $ 720,086 $ 265,802
Future production costs:
Lease operating expense (253,140) (192,834) (60,306)
Future development and abandonment costs (180,839) (86,684) (94,155)
---------- --------- ---------
Future net cash flows before income taxes 551,909 440,568 111,341
Discount at 10% per annum (168,929) (109,700) (59,229)
---------- --------- ---------
Discounted future net cash flow before income taxes 382,980 330,868 52,112
Future income taxes, net of discount at 10% per annum (92,911) (73,602) (19,309)
---------- --------- ---------
Standardized measure of discounted future net
cash flows relating to proved oil and gas reserves $ 290,069 $ 257,266 $ 32,803
========== ========= =========
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.
48
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, 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
Purchases of properties - - -
Sales of properties - - -
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
========= ========= =========
49
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES - UNAUDITED (CONTINUED)
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
========= ========= ========
Year Ended December 31, 1995
----------------------------------------------------
Total United Kingdom of
Company States Thailand
------------- -------------- ---------------
(Expressed in thousands)
Beginning balance $ 300,260 $ 287,886 $ 12,374
Revisions to prior years' proved reserves:
Net changes in prices and production costs (30,813) (44,948) 14,135
Net changes due to revisions in quantity estimates 5,947 5,947 -
Net changes in estimates of future development costs (45,370) (47,880) 2,510
Accretion of discount 40,384 38,667 1,717
Changes in production rate 1,162 (9,574) 10,736
Other 5,326 5,421 (95)
--------- --------- --------
Total revisions (23,364) (52,367) 29,003
New field discoveries and extensions, net
of future production and development costs 59,047 53,104 5,943
Purchases of properties 22,973 22,973 -
Sales of properties (4,114) (4,114) -
Sales of oil and gas produced, net of production costs (143,655) (143,655) -
Previously estimated development costs incurred 68,252 68,252 -
Net change in income taxes 10,670 25,187 (14,517)
--------- --------- --------
Net change in standardized measure
of discounted future net cash flows (10,191) (30,620) 20,429
--------- --------- --------
Ending balance $ 290,069 $ 257,266 $ 32,803
========= ========= ========
50
QUARTERLY RESULTS - UNAUDITED
Summaries of the Company's results of operations by quarter for the years
1996 and 1995 are as follows:
Quarter Ended
-----------------------------------------------
Mar. 31 June 30 Sept. 30 Dec. 31
---------- -------- ---------- --------
(Expressed in thousands, except per share amounts)
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:
Primary -
Income before extraordinary loss $ 0.19 $ 0.26 $ 0.21 $ 0.33
Extraordinary loss - $ (0.02) - -
Net income $ 0.19 $ 0.24 $ 0.21 $ 0.33
Fully diluted -
Income before extraordinary loss $ 0.19 $ 0.25 $ 0.20 $ 0.32
Extraordinary loss - $ (0.02) - -
Net income $ 0.19 $ 0.23 $ 0.20 $ 0.32
1995
Revenues $41,810 $41,738 $36,067 $37,044
Gross profit (a) $12,063 $13,562 $ 6,849 $ 7,354
Net income $ 3,431 $ 4,353 $ 722 $ 724
Earnings per share
(primary and fully diluted) $ 0.10 $ 0.13 $ 0.02 $ 0.02
- ----------------------
(a) Represents revenues less lease operating, exploration, dry hole and
impairment, and depreciation, depletion and amortization expenses.
Item 9. Disagreements on Accounting and Financial Disclosures.
Not applicable.
51
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 22, 1997,
to be filed within 120 days of December 31, 1996, pursuant to Regulation 14A
under the Securities Exchange Act of 1934, as amended (the Company's "1997 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 1997 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 1997 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 1997 Proxy Statement is incorporated herein by
reference.
52
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......... 29
Consolidated statements of income................ 30
Consolidated balance sheets...................... 31
Consolidated statements of cash flows............ 32
Consolidated statements of shareholders' equity.. 33
Notes to consolidated financial statements....... 34
Unaudited supplementary financial data........... 45
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.
*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 July 24, 1990. (Exhibit 3(a), Quarterly Report on
Form 10-Q for the quarter ended June 30, 1990,
File No. 0-5468).
*4(a) --Amended and Restated Credit Agreement dated as of June 1,
1995 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 September 30,
1995, File No. 1-7792).
*4(b) --Indenture dated as of June 15, 1996 to Fleet National
Bank, as Trustee. (Exhibit 4(f), Quarterly Report pm Form
10-Q for the quarter ended June 30, 1996,
File No. 001-7792).
*4(c) --Indenture dated as of March 23, 1994 to Shawmut Bank
Connecticut, National Association, as Trustee. (Exhibit
4(c), Annual Report on Form 10-K for the year ended
December 31, 1994, File No. 1-7792).
*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).
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.
53
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (comprising
Exhibits 10(a) through 10(h)(2), inclusive)
*10(a) --1977 Stock Option Plan of Pogo Producing Company, as
amended as of September 28, 1981 and July 24, 1984.
(Exhibit 10(a), Annual Report on Form 10-K for the year
ended December 31, 1984, File No. 0-5468).
*10(a)(1) --Form of Amended Nonqualified Stock Option Agreement under
1977 Stock Option Plan (with stock appreciation rights and
without employment restrictions). (Exhibit 10(a)(1),
Annual Report on From 10-K for the year ended December 31,
1981, File No. 0-5468).
*10(a)(2) --Form of Amended Incentive Stock Option Agreement under
1977 Stock Option Plan (with stock option appreciation
rights and without employment restrictions), (Exhibit
10(a)(2), Annual Report on Form 10-K for the year ended
December 31, 1981, File No. 0-5468).
*10(a)(3) --Form of Amended Nonqualified Stock Option Agreement under
1977 Stock Option Plan (without stock appreciation rights
and with employment restrictions). (Exhibit 10(a)(3),
Annual Report on Form 10-K for the year ended December 31,
1981, File No. 0-5468).
*10(a)(4) --Form of Amended Incentive Stock Option Agreement under
1977 Stock Option Plan (without stock option appreciation
rights and with employment restrictions). (Exhibit
10(a)(4), Annual Report on Form 10-K for the year ended
December 31, 1981, File No. 0-5468).
*10(a)(5) --Form of Amended Nonqualified Stock Option Agreement under
1977 Stock Option Plan (with stock appreciation rights and
with employment restrictions). (Exhibit 10(a)(5), Annual
Report on Form 10-K for the year ended December 31, 1981,
File No. 0-5468).
*10(a)(6) --Form of Amended Incentive Stock Option Agreement under
1977 Stock Option Plan (with stock option appreciation
rights and with employment restrictions). (Exhibit
10(a)(6), Annual Report on Form 10-K for the year ended
December 31, 1981, File No. 0-5468).
*10(a)(7) --Form of Amended Nonqualified Stock Option Agreement under
1977 Stock Option Plan (without stock appreciation rights
and without employment restrictions). (Exhibit 10(a)(7),
Annual Report on Form 10-K for the year ended December 31,
1981, File No. 0-5468).
*10(a)(8) --Form of Amended Incentive Stock Option Agreement under
1977 Stock Option Plan (without stock option appreciation
rights and without employment restrictions). (Exhibit
10(a)(8), Annual Report on Form 10-K for the year ended
December 31, 1981, File No. 0-5468).
*10(b) --1981 Stock Option Plan of Pogo Producing Company, as
amended as of July 24, 1984. (Exhibit 10(b), Annual Report
on Form 10-K for the year ended December 31, 1984, File
No. 0-5468).
*10(b)(1) --Form of Stock Option Agreement under 1981 Nonqualified
Stock Option Plan (with stock appreciation rights).
Exhibit 10(b)(1), Annual Report on Form 10-K for the year
ended December 31, 1981, File No. 0-5468).
*10(b)(2) --Form of Stock Option Agreement under 1981 Nonqualified
Stock Option Plan (without stock appreciation rights).
Exhibit 10(b)(2), Annual Report on Form 10-K for the year
ended December 31, 1981, File No. 0-5468).
*10(c) --1981 Incentive and Nonqualified Stock Option Plan of Pogo
Producing Company, as amended as of July 24, 1984.
(Exhibit 10(c), Annual Report on Form 10-K for the year
ended December 31, 1984, File No. 0-5468).
*10(c)(1) --Form of Stock Option Agreement under 1981 Incentive Stock
Option Plan. (Exhibit 10(c)(1), Annual Report of Form 10-K
for the year ended December 31, 1981, File No. 0-5468).
*10(d) --1989 Incentive and Nonqualified Stock Option Plan of Pogo
Producing 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).
54
*10(d)(1) --Form of Stock Option Agreement under 1989 Incentive and
Nonqualified Stock Option Plan, as amended and restated
effective January 22, 1991. (Exhibit 10(d)(1), Annual
Report on Form 10-K for the year ended December 31, 1991,
File No. 0-5468).
*10(d)(2) --Form of Director Stock Option Agreement under 1989
Incentive and Nonqualified Stock Option Plan as amended
and restated effective January 22, 1991. (Exhibit
10(d)(2), Annual Report on Form 10-K for the year ended
December 31, 1991, File No. 0-5468).
*10(e) --Form of Letter Agreement respecting treatment of options
upon change in control. (Exhibit 19(f), Quarterly Report
on Form 10-Q for the quarter ended June 30, 1982. File No.
0-5468).
*10(f) --1995 Long-Term Incentive Plan. (Exhibit 4(c), Registration
Statement on Form S-8 filed May 22, 1996, File No. 333-
04233).
*10(g)(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(g)(1)(ii) --Extension Agreement to Continue Executive Employment
Agreement by and between Pogo Producing Company and Stuart
P. Burbach, dated effective February 1, 1997.
*10(g)(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(g)(2)(ii) --Extension Agreement to Continue Executive Employment
Agreement by and between Pogo Producing Company and Jerry
A. Cooper, dated effective February 1, 1997.
*10(g)(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(g)(3)(ii) --Extension Agreement to Continue Executive Employment
Agreement by and between Pogo Producing Company and
Kenneth R. Good, dated effective February 1, 1997.
*10(g)(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(g)(4)(ii) --Extension Agreement to Continue Executive Employment
Agreement by and between Pogo Producing Company and R.
Phillip Laney, dated effective February 1, 1997.
*10(g)(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(g)(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.
*10(g)(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).
10(g)(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.
*10(h)(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(h)(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).
55
*10(i) --Undertaking by Pogo Producing Company dated as of August
8, 1977. (Exhibit 10(e), Annual Report on Form 10-K for
the year ended December 31, 1980, File No. 0-5468).
*10(j) --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(k) --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(l) --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).
*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, 1996.
27 --Financial Data Schedule.
99 --Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers dated February 28, 1997, relating to oil and gas
reserves of Pogo Producing Company.
- ----------
* Asterisk indicates exhibits incorporated by reference as shown.
(b) Reports on Form 8-K
None
56
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 20, 1997
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 20, 1997.
Signatures Title
/s/ PAUL G. VAN WAGENEN Principal Executive
-------------------------------- Officer and Director
Chairman of the Board, President
and Chief Executive Officer
/s/ JOHN W. ELSENHANS Principal Financial
-------------------------------- Officer
Vice President - Finance and
Treasurer
/s/ THOMAS E. HART Principal Accounting
-------------------------------- Officer
Vice President and Controller
TOBIN ARMSTRONG* Director
--------------------------------
JACK S. BLANTON* Director
--------------------------------
W. M. BRUMLEY, JR.* Director
--------------------------------
JOHN B. CARTER, JR.* Director
--------------------------------
WILLIAM L. FISHER* Director
--------------------------------
WILLIAM E. GIPSON* Director
--------------------------------
GERRIT W. GONG* Director
--------------------------------
J. STUART HUNT* Director
--------------------------------
FREDERICK A. KLINGENSTEIN* Director
--------------------------------
NICHOLAS R. PETRY* Director
--------------------------------
JACK A. VICKERS* Director
--------------------------------
*By: /s/ THOMAS E. HART
-----------------------------
Attorney-in-Fact
57