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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 1994
[ ] 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:
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Common Stock, $1 par value New York Stock Exchange
Pacific Stock Exchange
8% Convertible Subordinated New York Stock Exchange
Debentures due December 31, 2005
5 1/2% Convertible Subordinated New York Stock Exchange
Notes due March 15, 2004
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: NONE
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 $635,718,000 as of March 3, 1995 (based on $19.375 per share, the
last sale price of the Common Stock as reported on the New York Stock Exchange
Composite Tape on such date).
32,811,261 shares of the registrant's Common Stock were outstanding as of
March 3, 1995.
DOCUMENT INCORPORATED BY REFERENCE
Portions of the Company's definitive Proxy Statement respecting the annual
meeting of shareholders to be held on April 25, 1995 (to be filed not later than
120 days after December 31, 1994) are incorporated by reference in Part III of
this Form 10-K.
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PART I
ITEM 1. BUSINESS.
Pogo Producing Company (the "Company"), incorporated in 1970, is engaged in
oil and gas exploration, development and production activities on its properties
located offshore in the Gulf of Mexico and onshore in the United States. The
Company is also engaged in exploration of its license concession in the Gulf of
Thailand, and has proposed to its joint venture partners a development program
in connection with its oil and gas discoveries on that concession. The Company
has interests in 73 lease blocks offshore Louisiana and Texas, approximately
125,000 gross acres onshore in the United States and approximately 2,635,000
gross acres offshore in the Kingdom of Thailand.
DOMESTIC OFFSHORE OPERATIONS
Historically, the Company's interests have been concentrated in the Gulf of
Mexico, where approximately 81% of the Company's domestic proved reserves and
63% of its total proved reserves are now located. During 1994, approximately 82%
of the Company's natural gas equivalent production was from its domestic
offshore properties, contributing approximately 82% of consolidated oil and gas
revenues. Five offshore producing areas, Eugene Island, Main Pass, South Marsh
Island, South Pass and East Cameron, account for approximately 50% of the
Company's net proved natural gas reserves and approximately 56% of the Company's
proved crude oil, condensate and natural gas liquids reserves. Eugene Island is
the Company's largest producing area with 1994 average net revenue production
(net to the Company's interest and net of royalty burdens) of approximately 81
million cubic feet ("MMcf") per day of natural gas and 5,300 barrels ("Bbls")
per day of oil, condensate and natural gas liquids. The table in Item 2 of this
Annual Report on Form 10-K for the year ended December 31, 1994 (this "Annual
Report") summarizes the Company's offshore leasehold interests, drilling
activity, and platforms set or announced as of December 31, 1994.
Lease Acquisitions
The Company has participated with other companies in bidding on and
acquiring interests in federal leases offshore in the Gulf of Mexico since
December 1970. As a result of such sales and subsequent activities, the Company
owns interests in 67 federal leases offshore Louisiana and Texas. Federal leases
generally have primary terms of five years, subject to extension by development
and production operations. The Company also owns interests in six leases in
state waters offshore Louisiana.
As part of its strategy, the Company intends to continue an active lease
evaluation program in the Gulf of Mexico in order to identify exploration and
exploitation opportunities. During 1994, the Company was successful in acquiring
interests in three lease blocks, Vermilion 335, High Island A-451 and Galveston
Block A-215, 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 1995 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 properties
where additional low-risk drilling or improved production methods by the Company
can provide attractive rates of return. During 1994, the Company purchased
additional working interests in portions of eight federal lease blocks in the
South Pass, Mississippi Canyon, Main Pass and High Island areas of the Gulf of
Mexico. In addition, the Company participated in the drilling of two wells in
the South Marsh Island area which earned the Company working interests in two
lease blocks, South Marsh Island Blocks 141 and 161.
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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 1994 were approximately $48,700,000 (excluding approximately $32,600,000 of
net property acquisitions), or 20% higher than the Company's domestic offshore
capital and exploration expenditures of approximately $40,600,000 for 1993 and
453% higher than the Company's domestic offshore capital and exploration
expenditures of approximately $8,800,000 (excluding approximately $7,950,000 of
net property acquisitions) for 1992. Development and production related projects
represented 93% of the Company's 1994 domestic offshore capital and exploration
expenditures. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations."
Leases acquired by the Company and other participants in its bidding groups
are customarily committed, on a block-by-block basis, to separate operating
agreements under which the appointed operator supervises exploration and
development operations for the account and at the expense of the group. These
agreements usually contain terms and conditions which have become relatively
standardized in the industry. Major decisions regarding development and
operations typically require the consent of at least a majority (in working
interest) of the participants. Because the Company generally has a meaningful
working interest position, the Company believes it can influence decisions
regarding development and operations 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 21 of the 73
offshore leases in which it has an interest.
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. In
recent years, the gross cost of production platforms to the joint ventures in
which the Company has varying net interests has typically averaged approximately
$9,100,000 per platform. Platform costs vary and more expensive platforms could
be required in the future depending on, among other factors, the number of
slots, water depth, currents, and sea floor conditions. During 1994, the Company
completed the installation of an additional platform on Eugene Island Block 295,
installed three platforms in a new field on Ship Shoal Blocks 240/256, and
installed a platform on Main Pass Block 123. See "Properties -- Principal
Properties."
In 1989, the Company entered into a limited partnership agreement as
general partner of Pogo Gulf Coast, Ltd., a Texas limited partnership ("Pogo
Gulf Coast"), in which the Company agreed to be responsible for investing as
much as $60,000,000 on behalf of Pogo Gulf Coast for acquisition and exploration
in state and federal waters in the Gulf of Mexico. As of December 31, 1994, Pogo
Gulf Coast had interests in 16 federal offshore leases, and had invested a total
of approximately $55,500,000 for exploration and development of the properties
owned since the partnership began. The Company owns 40% of any interest in
properties acquired by the limited partnership. Unless otherwise noted, the
statistical data reported in this Annual Report reflect only the Company's share
of Pogo Gulf Coast's holdings.
DOMESTIC ONSHORE OPERATIONS
The Company has onshore division staffs in Houston and Midland, Texas. Its
onshore activities are concentrated in known oil and gas provinces, principally
the Permian Basin of southeastern New Mexico and West Texas and the onshore Gulf
Coast area. The Company's primary drilling objective in southeastern New Mexico
is the Brushy Canyon (Delaware) formation which 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 the drilling of 209
wells through December 31, 1994, including 58 wells in 1994. During the fourth
quarter of 1994, the Company's net revenue interest portion of daily liquid
hydrocarbon production in New Mexico averaged approximately 3,950 Bbls which
represented approximately 30% of the Company's total average daily production of
oil, condensate and liquid plant products during the fourth quarter of 1994.
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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 $32,000,000 for 1994, or 7% higher than the Company's domestic
onshore capital and exploration expenditures of approximately $29,800,000 for
1993 and 81% higher than the Company's domestic onshore capital and exploration
expenditures of approximately $17,650,000 (excluding approximately $950,000 of
net property acquisitions) for 1992. Development and production related projects
represented 74% of the Company's 1994 domestic onshore capital and exploration
expenditures. As of December 31, 1994, the Company held leases on 79,768 net
acres onshore in the United States. Onshore reserves as of December 31, 1994,
accounted for approximately 19% of the Company's domestic proved reserves and
approximately 14% of its total proved reserves. During 1994, approximately 18%
of the Company's natural gas equivalent production was from its domestic onshore
properties, contributing approximately 18% of consolidated oil and gas revenues.
INTERNATIONAL OPERATIONS
The Company has conducted international exploration activities since the
late 1970's in numerous oil and gas areas 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. The Company's
international capital and exploration expenditures were approximately $6,350,000
for 1994, or 6% higher than the Company's international capital and exploration
expenditures of approximately $6,000,000 for 1993 and 144% higher than the
Company's international capital and exploration expenditures of approximately
$2,600,000 for 1992. Substantially all of the Company's international capital
and exploration expenditures for 1994 were related to the Company's license in
the Kingdom of Thailand. However, the Company continues to evaluate other
international opportunities that are consistent with the Company's international
exploration strategy.
In August 1991, the Company, through its wholly owned subsidiary Thaipo
Limited, together with its joint venture partners, was awarded a license from
the Kingdom of Thailand to explore for and produce oil and gas on Block B8/32, a
2.6 million acre tract in the Gulf of Thailand. Following an initial evaluation
of the Thailand concession area, the Company and its joint venture partners have
drilled eight wells on a seismic structure on a portion of the concession named
Tantawan. In October 1992, the Tantawan No. 1 well was drilled. During 1993, the
Company and its joint venture partners shot, processed and evaluated
approximately 9,000 square kilometers of new 3-D seismic data over and around
the Tantawan No. 1 well. In late 1993, the Company drilled the Tantawan No. 2
and the Tantawan No. 3 wells on the Tantawan structure. In early 1994, an
additional two wells, the Tantawan No. 4 and the Tantawan No. 5 delineation
wells, were successfully drilled on the Tantawan area seismic structure. This
success was repeated in late 1994 with the drilling of three more delineation
wells on the Tantawan area seismic structure.
In March 1995, the Company reached an agreement with its partners in the
concession under which the Company currently anticipates that its working
interest in the Tantawan portion of the concession will increase from
approximately 31.7% to approximately 46.3%, upon approval of appropriate
governmental authorities in Thailand. The Company will also assume the duties of
operator on the Tantawan portion of the concession, which covers approximately
76,000 acres of the Block B8/32 license concession. Development activities on
the Tantawan portion of the concession are currently expected to commence in the
first half of 1995. Contingent upon availability of transportation and other
factors, the development program could lead to commencement of initial
production from reservoirs located on the Tantawan structure within 18 to 24
months. See "-- Miscellaneous; Sales;" and "Management's Discussion and Analysis
of Financial Condition and Results of Operations."
At December 31, 1994, the Company's Thailand concession accounted for
approximately 23% of the Company's total estimated net proved reserves of
natural gas and approximately 23% of its total estimated net proved reserves of
oil, condensate and natural gas liquids. If the anticipated increase in the
Company's working interest in the Tantawan portion of the concession had been
effective at that date, those percentages would have been approximately 30%. All
such proved reserves in Thailand are located on the Tantawan portion of the
concession and are currently classified as proved undeveloped.
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In addition to its continuing efforts on the Tantawan structure, the
Company and its joint venture partners have shot, processed and are currently
evaluating 10,500 square kilometers of new 3-D seismic data on a different
portion of Block B8/32. The Company and its partners currently plan to drill at
least four more wells on the non-Tantawan portion of the Thailand concession
during 1995. The Company's working interest in the non-Tantawan portion of the
concession, which is operated by one of its partners, remains at approximately
31.7%.
Any production resulting from the concession will be subject to a royalty
ranging from 5% to 15% of oil and gas sales, plus certain fixed dollar amounts
payable at specified cumulative production levels. Revenue from production in
Thailand will also be subject to income taxes and other governmental charges. As
set forth in the August 1991 concession, the exploratory term of the concession
is for a period of up to six years; provided, however, that after the expiration
of four years, a portion of the acreage in Block B8/32 must be relinquished by
the Company and its joint venture partners and removed from the concession
license. The Company must identify and release this acreage no later than August
1, 1995. During the concession's exploratory period, the Company and its joint
venture partners have certain work commitments involving the drilling of
exploratory wells or the expenditure of certain sums of money on exploration
activities. The Company and its joint venture partners have satisfied all of
these obligations. Following the commencement of production, the initial
production period of the concession is 20 years, subject to extension. See also
"-- Miscellaneous; Sales."
MISCELLANEOUS
Other Assets
The Company and a subsidiary, Pogo Offshore Pipeline Co., own minority
interests in three pipelines through which offshore oil production is
transported ashore. In addition, the Company owns an approximately 21% interest
in a cryogenic gas processing plant near Erath, Louisiana, which entitles it to
process up to 189 MMcf of gas per day. Currently, the plant is not operating at
full capacity.
Sales
The marketing of offshore oil and gas production is subject to the
availability of pipelines and other transportation, processing and refining
facilities as well as the existence of adequate markets. As a result, even if
hydrocarbons are discovered in commercial quantities, a substantial period of
time may elapse before commercial production commences. If pipeline facilities
in an area are insufficient, the Company 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 a major natural
gas pipeline that comes within approximately 25 miles of the Tantawan structure.
This pipeline is currently running at or near capacity. However, construction of
a second, parallel natural gas pipeline owned by an entity controlled by the
government of the Kingdom of Thailand has recently commenced, with completion
expected to occur during 1996. The Company is currently negotiating
transportation and sale arrangements with the Petroleum Authority of Thailand
for oil and gas expected to be produced from the Tantawan structure.
The marketing of onshore oil and gas production is also subject to the
availability of pipelines, crude oil hauling and other transportation,
processing and refining facilities as well as the existence of adequate markets.
Generally, the Company's onshore domestic oil and gas production is located in
areas where commercial production of economic discoveries can be rapidly
effectuated.
Most of the Company's natural gas sales are currently made in the "spot
market" for no more than one month at a time at then currently available prices.
Prices on the spot market fluctuate with demand. Crude oil and condensate
production is also generally sold one month at a time at the currently available
prices. Other than any futures contracts referred to in "-- Miscellaneous;
Competition and Market Conditions," the Company has no existing contracts that
require the delivery of fixed quantities of oil or natural gas other than
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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 February 1, 1995, the Company was not curtailing
any of its natural gas production as a result of low natural gas prices. Should
natural gas prices fall in the future, the Company may again elect to curtail
certain quantities of its natural gas production. Any significant decline in oil
or gas prices could have a material adverse effect on the Company's operations
and financial condition and could, under certain circumstances, result in a
reduction in funds available under the Company's bank credit facility. Because
it is impossible to predict future oil and gas price movements with any
certainty, the Company from time to time enters into contracts on a portion of
its production to hedge against the volatility in oil and gas prices. Such
hedging transactions, historically, have not exceeded 50% of the Company's total
oil and gas production on an energy equivalent basis for any given period. While
intended to limit the negative effect of price declines, such transactions could
effectively limit the Company's participation in price increases for the covered
period, which increases could be significant. The Company has entered into a
crude oil swap agreement with another party in which it had swapped the floating
market price it receives from purchasers of its crude oil for a fixed price of
$17.08 per barrel on 1,000 Bbls per day of the Company's production for a period
ending April 30, 1995. In addition, as of January 1, 1995, the Company had
entered into futures contracts with various parties on a portion of its daily
natural gas production through September 30, 1995 (commencing with contracts
totaling approximately 37 MMcf per day in January and decreasing on a quarterly
basis to approximately 15 MMcf per day) at varying prices ranging from
approximately $1.92 to $1.83 per thousand cubic feet ("Mcf"). 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.
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Risks of Foreign Operations
Ownership of property interests and production operations in Thailand and
other areas outside the United States are subject to the various risks inherent
in foreign operations. These risks include, among others, currency restrictions
and exchange rate fluctuations, loss of revenue, property and equipment as a
result of hazards such as expropriation, nationalization, war, insurrection and
other political risks, risks of increases in taxes and governmental royalties,
renegotiation of contracts with governmental entities, as well as changes in
laws and policies governing operations of foreign-based companies. The Company
seeks to manage these risks by concentrating its international exploration
efforts in areas where the Company believes that the existing government is
stable and favorably disposed towards United States exploration and production
companies. The Company believes that the Kingdom of Thailand currently presents
favorable conditions in which to conduct international operations.
EXPLORATION AND PRODUCTION DATA
In the following data "gross" refers to the total acres or wells in which
the Company has an interest and "net" refers to gross acres or wells multiplied
by the percentage working interest owned by the Company.
Acreage
The following table shows the Company's interest in developed and
undeveloped oil and gas acreage as of December 31, 1994:
DEVELOPED
ACREAGE(A) UNDEVELOPED ACREAGE(B)
------------------- ----------------------
GROSS NET GROSS NET
------- ------- ---------- --------
ONSHORE
Arkansas................................. -- -- 118 20
Colorado................................. 80 32 7,883 7,883
Louisiana................................ 869 209 537 537
New Mexico............................... 16,898 7,835 53,832 37,205
Oklahoma................................. 3,200 333 -- --
Texas.................................... 11,197 4,459 30,783 21,220
Wyoming.................................. -- -- 120 35
------- ------- ---------- --------
Total Onshore.................... 32,244 12,868 93,273 66,900
======= ====== ======== =======
OFFSHORE
Louisiana (State)........................ 7,804 2,964 -- --
Louisiana (Federal)(c)................... 176,067 58,670 59,989 13,989
Texas (Federal).......................... 46,080 10,860 17,280 6,912
------- ------- ---------- --------
Total Offshore................... 229,951 72,494 77,269 20,901
------- ------- ---------- --------
TOTAL DOMESTIC............................. 262,195 85,362 170,542 87,801
------- ------- ---------- --------
INTERNATIONAL
Thailand (Offshore)...................... -- -- 2,635,116 834,541
------- ------- ---------- --------
TOTAL COMPANY.............................. 262,195 85,362 2,805,658 922,342
======= ====== ======== =======
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(a) "Developed acreage" consists of lease acres spaced or assignable to
production on which wells have been drilled or completed to a point that
would permit production of commercial quantities of oil and natural gas.
(b) Approximately 16% of the Company's total offshore net undeveloped acreage is
under leases that have terms expiring in 1995, if not held by production,
and another approximately 29% of offshore net undeveloped acreage will
expire in 1996 if not also held by production. Approximately 19% of onshore
net undeveloped acreage is under leases that have terms expiring in 1995,
if not held by production, and another approximately 15% of onshore net
undeveloped acreage will expire in 1996 if not also held by production.
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(c) The Company also owns overriding royalty interests in one federal lease
offshore Louisiana totaling 5,000 gross and 1,250 net acres.
Productive Wells and Drilling Activity
The following table shows the Company's interest in productive oil and
natural gas wells as of December 31, 1994. Productive wells are producing wells
plus wells "capable of production" (e.g., natural gas wells waiting for pipeline
connections or necessary governmental certification to commence deliveries and
oil wells waiting to be connected to production facilities).
NATURAL GAS
OIL WELLS(A) WELLS(A)
--------------- --------------
GROSS NET GROSS NET
----- ----- ----- ----
Offshore United States................................ 185 45.6 166 51.7
Onshore United States................................. 210 120.0 67 25.7
----- ----- ----- ----
Total....................................... 395 165.6 233 77.4
==== ===== ==== ====
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(a) One or more completions in the same bore hole are counted as one well. The
data in the above table includes 30 gross (7.4 net) oil wells and 16 gross
(5.7 net) natural gas wells with multiple completions.
The following table shows the number of successful gross and net
exploratory and development wells in which the Company has participated and the
number of gross and net wells abandoned as dry holes during the periods
indicated. An onshore well is considered successful upon the installation of
permanent equipment for the production of hydrocarbons. 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.
1994 1993 1992
------------------- ------------------- ------------------
SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY
---------- ---- ---------- ---- ---------- ---
GROSS WELLS:
Offshore United States
Exploratory.................. 2.0 -- 5.0 1.0 -- 2.0
Development.................. 25.0 2.0 15.0 -- 5.0 --
Onshore United States
Exploratory.................. 3.0 6.0 3.0 4.0 4.0 2.0
Development.................. 51.0 3.0 61.0 1.0 34.0 --
Offshore Kingdom of Thailand
Exploratory.................. 5.0 -- 2.0 2.0 1.0 --
----- ---- ----- ---- ----- ---
Total................ 86.0 11.0 86.0 8.0 44.0 4.0
======= ==== ======= ==== ======= ===
NET WELLS:
Offshore United States
Exploratory.................. 0.6 -- 1.7 0.1 -- 0.7
Development.................. 8.4 1.4 7.7 -- 1.5 --
Onshore United States
Exploratory.................. 2.8 3.6 2.0 3.2 2.8 0.9
Development.................. 29.9 0.9 33.1 0.4 23.2 --
Offshore Kingdom of Thailand
Exploratory.................. 1.6 -- 0.6 0.6 0.3 --
----- ---- ----- ---- ----- ---
Total................ 43.3 5.9 45.1 4.3 27.8 1.6
======= ==== ======= ==== ======= ===
As of December 31, 1994, the Company was participating in the drilling of 4
gross (1.7 net) offshore domestic wells and 5 gross (1.8 net) onshore wells.
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Production and Sales
The following table summarizes the Company's average daily production, net
of all royalties, overriding royalties and other outstanding interests, for the
periods indicated. Natural gas production refers only to marketable production
of natural gas on an "as sold" basis.
1994 1993 1992
-------- ------- --------
Production Sales:
Natural Gas (Mcf per day)............................ 144,800 91,700 105,200
======= ====== =======
Crude Oil and Condensate (Bbls per day).............. 11,100 9,851 8,699
======= ====== =======
Natural Gas Liquids (Bbls per day):
Leasehold Ownership.................................. 2,075 1,538 1,037
Plant Ownership...................................... 147 140 144
-------- ------- --------
Total........................................ 2,222 1,678 1,181
======= ====== =======
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."
1994 1993 1992
------- ------- -------
Sales Prices:
Natural Gas (per Mcf).................................. $ 1.88 $ 1.98 $ 1.75
Crude Oil and Condensate (per Bbl)..................... $ 16.08 $ 17.81 $ 20.17
Natural Gas Liquids (per Bbl).......................... $ 11.33 $ 11.90 $ 13.50
Production (lifting) Costs(a)
Natural Gas, Crude Oil, Condensate and Natural Gas
Liquids (per equivalent Mcf of Natural Gas)......... $ 0.36 $ 0.45 $ 0.43
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(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.
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Reserves
The following table sets forth information as to the Company's net proved
developed and proved undeveloped reserves as of December 31, 1994, 1993, and
1992, and the present value as of such dates (based on an annual discount rate
of 10%) of the estimated future net revenues from the production and sale of
those reserves, as estimated by Ryder Scott Company Petroleum Engineers,
Houston, Texas ("Ryder Scott") in accordance with criteria prescribed by the
Securities and Exchange Commission (the "Commission"). The summary report of
Ryder Scott on the reserve estimates, which includes definitions and
assumptions, is set forth as an exhibit to this Annual Report and definitions,
assumptions and descriptions of methodology following the tables are based upon
the Ryder Scott report.
AS OF DECEMBER 31,
-----------------------------------
1994 1993 1992
--------- --------- ---------
Total Proved Reserves:
Oil, condensate, and natural gas liquids
(thousands of Bbls) --
Located in the United States.................. 26,188 22,843 19,979
Located in the Kingdom of Thailand............ 7,674 5,425 2,577
--------- --------- ---------
Total Company............................ 33,862 28,268 22,556
========= ========= =========
Natural Gas (MMcf)
Located in the United States.................. 186,151 199,392 196,400
Located in the Kingdom of Thailand............ 56,739 33,474 10,668
--------- --------- ---------
Total Company............................ 242,890 232,866 207,068
========= ========= =========
Present value of estimated future net revenues,
before income taxes (in thousands)
Located in the United States.................. $ 330,868 $ 386,674 $ 390,893
Located in the Kingdom of Thailand............ 52,112 17,166 $ 14,208
--------- --------- ---------
Total Company............................ $ 382,980 $ 403,840 $ 405,101
========= ========= =========
Proved Developed Reserves (all located in the
United States):
Oil, condensate, and natural gas liquids
(thousands of Bbls)........................... 24,670 20,976 18,798
Natural Gas (MMcf)............................... 178,518 183,139 175,523
Present value of estimated future net revenues,
before income taxes (in thousands)............ $ 321,514 $ 375,287 $ 378,300
Natural gas liquids comprise approximately 13% of the Company's total
proved liquids reserves and approximately 17% of the Company's proved developed
liquids reserves. All hydrocarbon liquid reserves are expressed in standard 42
gallon Bbls. All gas volumes and gas sales are expressed in MMcf at the pressure
and temperature bases of the area where the gas reserves are located.
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing conditions. Reservoirs are considered proved if
economic producibility is supported by actual production or formation tests. In
certain instances, proved reserves are assigned on the basis of a combination of
core analysis and electrical and other type logs which indicate the reservoirs
are analogous to reservoirs in the same field which are producing or have
demonstrated the ability to produce on a formation test. The area of a reservoir
considered proved includes (i) that portion delineated by drilling and defined
by fluid contacts, if any, and (ii) the adjoining portions not yet drilled that
can be reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir. Proved reserves are estimates of hydrocarbons to be
recovered from a given date forward. They may
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be revised as hydrocarbons are produced and additional data becomes available.
Proved natural gas reserves are comprised of nonassociated, associated and
dissolved gas. An appropriate reduction in gas reserves has been made for the
expected removal of liquids, for lease and plant fuel and the exclusion of
non-hydrocarbon gases if they occur in significant quantities and are removed
prior to sale. Reserves that can be produced economically through the
application of established improved recovery techniques are included in the
proved classification when these qualifications are met: (i) successful testing
by a pilot project or the operation of an installed program in the reservoir
provides support for the engineering analysis on which the project or program
was based, and (ii) it is reasonably certain the project will proceed. Improved
recovery includes all methods for supplementing natural reservoir forces and
energy, or otherwise increasing ultimate recovery from a reservoir, including,
(a) pressure maintenance, (b) cycling, and (c) secondary recovery in its
original sense. Improved recovery also includes the enhanced recovery methods of
thermal, chemical flooding, and the use of miscible and immiscible displacement
fluids. Estimates of proved reserves do not include crude oil, condensate,
natural gas, or natural gas liquids being held in underground storage. Depending
on the status of development, these proved reserves are further subdivided into:
(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 interests, prices in effect at December 31, 1994 were used, including
current market prices, contract prices and fixed and determinable price
escalations where applicable. In accordance with Commission guidelines, the
future gas prices that were used make no allowances for seasonal variations in
gas prices which are likely to cause future yearly average gas prices to be
somewhat lower than December gas prices. For gas sold under contract, the
contract gas price including fixed and determinable escalations, exclusive of
inflation adjustments, was used until the contract expires and then was adjusted
to the current market price for the area and held at this adjusted price to
depletion of the reserves. In computing future revenues from liquids
attributable to the Company's interest, prices in effect at December 31, 1994
were used and these prices were held constant to depletion of the properties.
With respect to the Company's Thailand properties, production was assumed to
commence in 1997, at sales prices that were estimated by the Company based in
part on reported sales prices for production from other producers in the area.
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
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the leases and wells under terms of operating agreements. Development costs are
based on authorization for expenditure for the proposed work or actual costs for
similar projects. The current operating and development costs were held constant
throughout the life of the properties. For properties located onshore, the
estimates of future net revenues and the present value thereof do not consider
the salvage value of the lease equipment or the abandonment cost of the lease
since both are relatively insignificant and tend to offset each other. The
estimated net cost of abandonment after salvage was considered for offshore
properties where such costs net of salvage are significant.
No deduction was made for indirect costs such as general and administrative
and overhead expenses, loan repayments, interest expenses, and exploration and
development prepayments. The accumulated gas production imbalances have been
taken into account.
Production data used to arrive at the estimates set forth above includes
estimated production for the last few months of 1994.
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.
The Company is periodically required to file estimates of its oil and gas
reserve data with various governmental regulatory authorities and agencies,
including the Federal Energy Regulatory Commission ("FERC") and the Federal
Trade Commission. In addition, estimates are from time to time furnished to
governmental agencies in connection with specific matters pending before such
agencies. The basis for reporting reserves to these agencies, in some cases, is
not comparable to that furnished above because of the nature of the various
reports required. The major differences include differences in the time as of
which such estimates are made, differences in the definition of reserves,
requirements to report in some instances on a gross, net or total operator basis
and requirements to report in terms of smaller geographical units. No estimates
by the Company of its total proved net oil and gas reserves, however, were filed
with or included in reports to any federal authority or agency other than the
Commission during 1994.
GOVERNMENT REGULATION
The Company's operations are affected from time to time in varying degrees
by political developments and federal and state laws and regulations. Rates of
production of oil and gas have for many years been subject to federal and state
conservation laws and regulations, and the petroleum industry has been subject
to federal and state tax laws dealing specifically with it.
Federal Income Tax
The Company's operations are significantly affected by certain provisions
of the federal income tax laws applicable to the petroleum industry. The
principal provisions affecting the Company are those that permit the
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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. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources."
Environmental Matters
Offshore oil and gas operations are subject to extensive federal regulation
and, with respect to federal leases, to interruption or termination by
governmental authorities on account of environmental and other considerations
including the Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA") also known as the "Superfund Law." Regulations of the Department
of the Interior currently impose absolute liability upon the lessee under a
federal lease for the costs of clean-up of pollution resulting from a lessee's
operations, and such lessee may also be subject to possible legal liability for
pollution damages. The Company maintains insurance against costs of clean-up
operations, but is not fully insured against all such risks. A serious incident
of pollution may, as it has in the past, also result in the Department of the
Interior requiring lessees under federal leases to suspend or cease operation in
the affected area.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose
a variety of regulations on "responsible parties" (which include owners and
operators of offshore facilities) related to the prevention of oil spills and
liability for damages resulting from such spills in United States waters. In
addition it imposes ongoing requirements on responsible parties, including proof
of financial responsibility to cover at least some costs in a potential spill.
On August 25, 1993, the Mineral Management Service (the "MMS") published an
advance notice of its intention to adopt a rule under OPA that would require
owners and operators of offshore oil and gas facilities to establish
$150,000,000 in financial responsibility. Under the proposed rule, financial
responsibility could be established through insurance, guaranty, indemnity,
surety bond, letter of credit, qualification as a self-insurer or a combination
thereof. There is substantial uncertainty as to whether insurance companies or
underwriters will be willing to provide coverage under OPA because the statute
provides for direct lawsuits against insurers who provide financial
responsibility coverage, and most insurers have strongly protested this
requirement. The financial tests or other criteria that will be used to judge
self-insurance are also uncertain. Recently, parties in congress and industry
have been raising substantial objections to the rules as proposed by the MMS.
Various proposals have been made to resolve the objections of industry while
satisfying environmental concerns. The Company cannot predict the final form of
the financial responsibility rule that will be adopted by the MMS, but such rule
has the potential to result in the imposition of substantial additional annual
costs on the Company or otherwise materially adversely affect the Company. The
impact of the rule, however, should not be any more adverse to the Company than
it will be to other similarly situated owners or operators in the Gulf of
Mexico.
The operators of the Company's properties have numerous applications
pending before the Environmental Protection Agency (the "EPA") for National
Pollution Discharge Elimination System water discharge permits with respect to
offshore drilling and production operations. The issue generally involved is
whether effluent discharges from each facility or installation comply with the
applicable federal regulations. See "Legal Proceedings" for a discussion of
other environmental matters.
The Company's onshore operations are subject to numerous United States
federal, state, and local laws and regulations controlling the discharge of
materials into the environment or otherwise relating to the protection of the
environment including CERCLA. Such regulations, among other things, impose
absolute liability on the lessee under a lease for the cost of clean-up of
pollution resulting from a lessee's operations, subject the lessee to liability
for pollution damages, may require suspension or cessation of operations in
affected areas, and impose restrictions on the injection of liquids into
subsurface aquifers that may contaminate groundwater. In addition, the recent
trend toward stricter standards in environmental legislation
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and regulation may continue. For instance, production wastes as "hazardous
wastes" which would make the reclassified exploration and production wastes
subject to more stringent handling, disposal and clean-up requirements. If such
legislation were to be enacted, it could have a significant impact on the
operating costs of the Company, as well as the oil and gas industry in general.
State 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 and gas operations, many of the costs
attributable to environmental control facilities would have been incurred absent
environmental regulations as prudent, safe oil field practice. During 1994, the
Company incurred capital expenditures of approximately $2,360,000 for
environmental control facilities, including the completion of four salt water
disposal facilities in New Mexico. The Company currently has budgeted
approximately $1,300,000 for environmental control facilities, including three
salt water disposal facilities during 1995.
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 allowable production from the Company's properties and thereby
to limit its revenues.
Other Regulations and Legislative Proposals
Prior to January 1, 1993 various aspects of the Company's natural gas
operations were subject to regulations by the FERC under the Natural Gas Act of
1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA") with
respect to "first sales" of natural gas including price controls and certificate
and abandonment authority regulations. However, as a result of the enactment of
the Natural Gas Decontrol Act of 1989, the remaining "first sales" restrictions
imposed by the NGA and the NGPA terminated on January 1, 1993.
Commencing in late 1985, the FERC has issued a series of orders that have
had a major impact on natural gas pipeline operations, services and rates and
thus have significantly altered the marketing and price of natural gas. Order
636, issued in April 1992, requires each pipeline company, among other things,
to "unbundle" its traditional wholesale services and create and make available
on an open and nondiscriminatory basis numerous constituent services (such as
gathering services, storage services, firm and interruptible transportation
services, and stand-by sales services) and to adopt a new rate making
methodology to determine appropriate rates for those services. To the extent the
pipeline company or its sales affiliate makes gas sales as a merchant in the
future, it will do so in direct competition with all other sellers pursuant to
private contracts; however, pipeline companies and their affiliates are not
required to remain "merchants" of gas, and some of the interstate pipelines
companies have or will become "transporters only." In subsequent orders, the
FERC largely affirmed Order 636 and denied a stay of the implementation of the
new rules pending judicial review. In addition, the FERC has generally accepted
rate filings implementing Order 636 on essentially every interstate pipeline as
of the end of 1994. Order 636, as well as the FERC orders approving the
individual pipeline rate filings implementing Order 636, are the subject of
numerous appeals to the United States Courts of Appeals. The Company cannot
predict whether the latest orders will be affirmed on appeal or what the effects
will be on its business.
EMPLOYEES
As of December 31, 1994, the Company had 108 employees. None of the
Company's employees are presently represented by a union for collective
bargaining purposes. The Company considers its relations with its employees to
be excellent.
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ITEM 2. PROPERTIES.
The information appearing in Item 1 of this Annual Report is incorporated
herein by reference.
PRINCIPAL PROPERTIES
As of January 1, 1995, approximately 81% of the Company's domestic proved
oil and gas equivalent reserves and approximately 63% of the Company's total
proved oil and gas equivalent reserves were located on properties in the Gulf of
Mexico. Six significant producing areas, of which five are located in the Gulf
of Mexico and the sixth is located in New Mexico, accounted for approximately
56% of the estimated proved natural gas reserves and approximately 72% of the
estimated oil, condensate and natural gas liquids reserves of the Company as of
January 1, 1995. These producing areas accounted for approximately 83% of
natural gas production and 94% of oil, condensate and natural gas liquids
production for 1994. Net proved reserves, as estimated by Ryder Scott, and
average net daily production data for the six significant producing areas are
shown in the following table. No other major producing area accounted for more
than 5% of the estimated discounted future net revenues attributable to the
Company's estimated proved reserves as of January 1, 1995. However, the
Company's Thailand concession, which is currently not a producing property,
accounts for approximately 23% of the Company's total estimated net proved
reserves of natural gas, approximately 23% of the Company's total estimated net
proved reserves of oil, condensate and natural gas liquids and approximately 23%
of the Company's total net proved oil and gas equivalent reserves.
SIGNIFICANT PRODUCING AREAS
NET PROVED RESERVES 1994 AVERAGE NET
AS OF JANUARY 1, 1995 DAILY PRODUCTION
------------------------------ ----------------------------- DISCOUNTED
FUTURE
NATURAL GAS LIQUIDS(A) NATURAL GAS LIQUIDS(A) NET
------------- -------------- ------------- ------------- REVENUES(B)
(MMCF) % (MBBLS) % (MCF) % (BBLS) % %
------ ---- ------- ---- ------ ---- ------ ---- -----------
OFFSHORE
Eugene Island............... 67,910 28.0% 9,416 27.8% 80,592 55.7% 5,269 39.6% 36.2%
Main Pass................... 14,932 6.1 5,264 15.5 5,225 3.6 1,367 10.3 11.4
South Marsh Island.......... 7,939 3.3 2,639 7.8 3,340 2.3 1,439 10.8 6.6
South Pass.................. 12,510 5.2 1,435 4.2 6,290 4.3 372 2.8 4.7
East Cameron................ 17,494 7.2 132 0.4 13,537 9.4 102 0.8 4.0
ONSHORE
New Mexico Lea/Eddy
Counties.................. 14,621 6.0 5,410 16.0 9,638 6.7 3,935 29.5 11.6
- ---------------
(a) "Liquids," includes oil, condensate and natural gas liquids.
(b) Before income taxes, discounted at 10%.
Set forth below are descriptions of certain of the Company's significant
producing areas. Unless otherwise specifically identified, the information set
forth in such descriptions, including the number of wells, platforms and blocks,
is presented on a gross, rather than a net to the Company basis.
Eugene Island
The Company's most significant reserves and 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 13 blocks in the Eugene Island area. These
blocks comprise eight fields containing 94 oil and gas wells producing from
multiple reservoirs and horizons.
The Eugene Island Block 330 field is the Company's most significant asset,
with 28 productive Pleistocene horizons between 4,000 and 8,000 feet, containing
multiple reservoirs. The field, located in 245 feet of water, contains three
drilling and production platforms in which the Company holds a 35% working
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interest, as well as an additional platform in which the Company holds a 30%
working interest. There are currently 17 wells producing primarily natural gas
and 36 wells producing primarily oil on the block. In 1994, a successful
drilling program off of the field's "D" platform resulted in the completion of
three oil wells and one high volume horizontal gas well. Since initial
production in 1973, the Eugene Island Block 330 field has produced approximately
641 billion cubic feet ("Bcf ") of natural gas and 127 million barrels
("MMBbls") of oil and condensate (173 Bcf and 37 MMBbls attributable to the
Company's net revenue interest). Reserves have been added to this field
consistently since production commenced. These increases have been derived from
new exploratory horizons, infill drilling, field expansions and higher than
anticipated recovery efficiencies.
Another significant field to the Company is the Eugene Island Block 295
field. On production since February 1973, this block has recorded gross
production of over 416 Bcf of natural gas and over 3.0 MMBbls of oil and
condensate during its twenty two-year life. In August 1993, the Company effected
an exchange of working interests in Eugene Island Block 295 with another working
interest owner in such block. Pursuant to this exchange, the Company increased
its working interest in Eugene Island Block 295 to 100% on 3,125 acres above
3,000 feet, to 20% on 1,875 acres above 3,000 feet and to 20% on all of the
block below 3,000 feet. During the fourth quarter of 1993, the Company
successfully drilled and completed five horizontal wells to exploit the natural
gas potential located in certain shallow reservoirs on this block in an area
where it has a 100% working interest. A platform was set and production
commenced from these wells in late February 1994. In September 1994, an
additional horizontal well was also drilled from this platform. Production from
this field is largely responsible for the substantial increase in the Company's
average daily production of natural gas from the Eugene Island area for 1994,
compared to 1993.
The Eugene Island Block 212 field consists of Eugene Island Blocks 211 and
212 and Ship Shoal Block 175. The field contains eight productive horizons which
have four oil wells and two natural gas wells producing from a platform set in
1985. The Company and its partners completed a successful three well workover
and recompletion program in this field during the fourth quarter of 1994.
Main Pass
The Company's nine blocks in the Main Pass area are located near the mouth
of the Mississippi River in the Gulf of Mexico and include leases purchased from
1974 to 1992. The primary drilling objectives in these fields are Pliocene and
Miocene sandstone reservoirs with productive formation depths from 5,000 to
12,000 feet. The Company's interests in the Main Pass area include 42 producing
oil and gas wells producing from six platforms.
A field including Main Pass Blocks 72, 73 and 72/74 was unitized in 1982
with the Company's working interest at 14%. In late 1994, the Company increased
its working interest in this field to 35% by purchasing another working interest
owner's interests in the field. This field contains 23 producing oil wells and 8
producing natural gas wells from three platforms operated by one of the
Company's joint venture partners. The field is located in 125 feet of water with
38 mapped horizons adjacent to and surrounding a salt dome. These horizons
contain over 150 separate reservoirs between 5,000 and 12,000 feet. A successful
10 well workover program in this field was completed in 1994. In addition, the
first three wells of a four well development program were drilled in 1994. The
Company currently plans to continue its workover program and drill six
additional wells in this field during 1995 based in part on the analysis of a
proprietary 3-D seismic survey over the field that the Company acquired rights
to in 1994.
Main Pass Block 123 was acquired in the federal lease sale of 1990. Pogo
Gulf Coast, for which the Company is the general partner, has a 75% working
interest and is the operator on the block. Along with its non-operating joint
venture partner, Pogo Gulf Coast drilled two discovery wells on the block in
1993. Subsequently, Pogo Gulf Coast drilled two additional wells on this block
in 1994. Installation of a platform and construction of a pipeline from the
platform to an existing main pipeline was completed in January 1995. Platform
start-up was completed and full production from this field commenced in February
1995.
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South Marsh Island
The Company currently owns interests in portions of seven blocks in the
South Marsh Island area, located offshore Louisiana. Three of the leases were
acquired in 1974, a fourth in 1980, a fifth in 1992 and portions of two more
leases were acquired in 1994 through farmins. Three blocks contain a total of
five drilling and production platforms. These platforms currently have 44 oil
and gas wells producing from Pleistocene age sandstone reservoirs located at
depths from 5,000 to 10,000 feet.
The South Marsh Island Block 128 field, in which the Company owns a 16%
working interest, comprises South Marsh Island Blocks 125, 127, 128 and 141.
This field primarily produces oil, with 32 oil wells and eight natural gas wells
producing from 20 separate reservoirs. In 1994, a five well drilling program in
this field was completed which resulted in increased oil and gas deliverability
and reserves. Additional drilling is currently planned for 1995. The wells that
were drilled in 1994 and those planned for 1995 have been based on the ongoing
analysis of a 3-D seismic survey in conjunction with a detailed reservoir study
of the field.
The Company also owns a 25% working interest in the South Marsh Island
Block 160 field which is producing from three oil wells at a depth of
approximately 9,700 feet. A single platform was set on this block in 1983. A
two-well drilling program in this field resulting from analysis of a 3-D seismic
survey covering the field was completed in the fourth quarter of 1994.
South Pass
The Company acquired its first South Pass area leasehold interest in
September 1972. The Company currently owns interests in portions of six blocks
in this area on which four production platforms have been set that produce oil
and gas from 27 wells which have been completed principally in Pleistocene,
Pliocene and Miocene reservoirs at depths ranging from approximately 4,000 to
14,800 feet.
The Company's most significant field in the South Pass area is located on
South Pass Blocks 49 and 50. The Company increased its working interest in South
Pass Bock 49 from 6% to 20% late in 1994. In addition, in late 1993, the Company
successfully completed the drilling of a highly deviated well into two
reservoirs on South Pass Block 50, in which the Company holds a 50% working
interest, from a platform located on South Pass Block 49 that substantially
increased the Company's production from this area.
East Cameron
Production commenced from the Company's first East Cameron area leasehold
interest in February 1973. Presently, the Company has interests in 3 offshore
blocks in this area which contain two fields and 13 producing gas wells.
During 1992, the Company and its partners conducted a 3-D seismic survey of
the East Cameron Block 334/335 field area where the Company has a 42% working
interest. Analysis of this 3-D seismic survey resulted in the drilling of four
successful development wells. As of February 1, 1995, an exploratory well was
also being drilled on East Cameron Block 334.
New Mexico
The Company considers southeastern New Mexico to be an area of significant
growth in both production and reserves as a result of recent exploration and
development activities. The Company believes that during the past four years it
has been one of the most active companies drilling for oil and natural gas in
the southeastern New Mexico (Lea and Eddy Counties) portion of the Permian Basin
where the Company has interests in over 70,000 gross acres. The Company's
primary drilling objective for crude oil is the Brushy Canyon (Delaware)
formation. Fields in the Brushy Canyon (Delaware) formation in the southeastern
New Mexico portion of the Permian Basin are generally characterized by
production from relatively shallow depths (6,000 to 9,000 feet), multiple
producing zones in most wells and relatively high initial rates of production
(frequently equaling the top field allowables which range from of 142 Bbls to
230 Bbls per day, depending on the depth of production from the field). The
Company has achieved rapid cost recovery with respect to its New Mexico wells
drilled to date because of relatively low capital costs and high initial rates
of production.
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Since the Company began exploring in the Brushy Canyon (Delaware) formation
in October 1989, it has participated in the drilling of 209 wells through
December 31, 1994, including, among others, 84 wells in the Sand Dunes field
where the Company's working interest ranges from 4% to 89%, 27 wells in the East
Loving field where the Company's working interest ranges from 33% to 98%, 45
wells in the Livingston Ridge field where the Company's working interest ranges
from 25% to 100%; and 29 wells in the Red Tank field where the Company's working
interest ranges from 89% to 100%. The oil fields in this area are generally
developed on a 40 acre spacing pattern. The Company anticipates drilling many
additional locations in these and other fields in southeastern New Mexico during
1995 and in future years.
DOMESTIC OFFSHORE PROPERTIES
The following is a listing of the Company's domestic offshore properties as
of December 31, 1994.
POGO EXPLORATORY DEVELOPMENT DATE OR
WORKING WELLS PLATFORMS WELLS LEASE ANTICIPATED
INTEREST DRILLED OR SET OR DRILLED OR DATE EFFECTIVE DATE OF
BLOCK % DRILLING ANNOUNCED DRILLING ACQUIRED DATE PRODUCTION
- ---------------------------------------------------------------------------------------------------------------------
OFFSHORE TEXAS -- FEDERAL
Matagorda Island
A-4 27.0 3 1 2 8-83 10-1-83 9-89
- ---------------------------------------------------------------------------------------------------------------------
670 30.7 1 1 2 8-83 10-1-83 10-89
- ---------------------------------------------------------------------------------------------------------------------
Brazos
A-104 10.8 1 1 8-89 10-1-89 6-90
- ---------------------------------------------------------------------------------------------------------------------
Galveston
A-215 50.0 1 8-94 12-1-94
- ---------------------------------------------------------------------------------------------------------------------
325 20.0 8-91 11-1-91
- ---------------------------------------------------------------------------------------------------------------------
High Island/South Addition
A-515 25.0 2 1 11-79 1-1-80 11-84
- ---------------------------------------------------------------------------------------------------------------------
High Island/East Addition/South Extension
A-323 1.8 4 1 17 6-73 8-1-73 6-78
- ---------------------------------------------------------------------------------------------------------------------
A-325 9.9 7 2 9 6-73 8-1-73 8-81
- ---------------------------------------------------------------------------------------------------------------------
A-355 33.3 1 1 5 5-74 7-1-74 7-80
- ---------------------------------------------------------------------------------------------------------------------
A-356 50.0 1 1 4 5-74 7-1-74 7-80
- ---------------------------------------------------------------------------------------------------------------------
A-451 50.0 1 1 8-94 12-1-94 1996
- ---------------------------------------------------------------------------------------------------------------------
TOTAL TEXAS 22 10 39
- ---------------------------------------------------------------------------------------------------------------------
OFFSHORE LOUISIANA -- FEDERAL
West Cameron
63 20.0 3-91 5-1-91
- ---------------------------------------------------------------------------------------------------------------------
97 20.0 1 3-90 5-1-90
- ---------------------------------------------------------------------------------------------------------------------
196 [A] 3 1 2 5-83 7-1-83 12-90
- ---------------------------------------------------------------------------------------------------------------------
202 39.3 3 1 2 11-82 1-1-83 8-85
- ---------------------------------------------------------------------------------------------------------------------
252 80.0 1 Share 253 Platform 2 11-82 1-1-83 8-84
- ---------------------------------------------------------------------------------------------------------------------
253 80.0 1 1 6 6-77 8-1-77 7-84
- ---------------------------------------------------------------------------------------------------------------------
310 20.0 3-91 7-1-91
- ---------------------------------------------------------------------------------------------------------------------
352 15.0 1 1 9 10-74 12-1-74 8-79
- ---------------------------------------------------------------------------------------------------------------------
385 20.0 3-90 6-1-90
- ---------------------------------------------------------------------------------------------------------------------
532 4.0 5 Share 533 Platform 3 12-72 2-1-73 9-76
- ---------------------------------------------------------------------------------------------------------------------
533 4.0 2[B] 2 7 12-72 2-1-73 9-76
- ---------------------------------------------------------------------------------------------------------------------
(footnotes at end of table)
17
19
POGO EXPLORATORY DEVELOPMENT DATE OR
WORKING WELLS PLATFORMS WELLS LEASE ANTICIPATED
INTEREST DRILLED OR SET OR DRILLED OR DATE EFFECTIVE DATE OF
BLOCK % DRILLING ANNOUNCED DRILLING ACQUIRED DATE PRODUCTION
- ---------------------------------------------------------------------------------------------------------------------
609 16.0 1 1 7 10-74 12-1-74 7.78
- ---------------------------------------------------------------------------------------------------------------------
East Cameron
270 30.0 3 2 30 12-70 1-1-71 1-73
- ---------------------------------------------------------------------------------------------------------------------
334 42.0 5[B] 1 11 12-70 2-1-71 8-77
- ---------------------------------------------------------------------------------------------------------------------
335 42.0 3 2 27 6-73 8-1-73 8-77
- ---------------------------------------------------------------------------------------------------------------------
Vermilion
175 70.0 1 1 5-91 9-1-85 12-91
- ---------------------------------------------------------------------------------------------------------------------
335 37.5 3-94 5-1-94
- ---------------------------------------------------------------------------------------------------------------------
South March Island
125 16.0 3 1 8 10-74 12-1-74 7-77
- ---------------------------------------------------------------------------------------------------------------------
127 16.0 Share 128 Platform 3 10-74 12-1-74 7-77
- ---------------------------------------------------------------------------------------------------------------------
128 16.0 6 3 62 3-74 5-1-74 7-77
- ---------------------------------------------------------------------------------------------------------------------
+141 16.0[C] Share 128 Platform 2 3-94 12-1-74 3-94
- ---------------------------------------------------------------------------------------------------------------------
160 25.0 2 1 5 9-80 11-1-80 2-84
- ---------------------------------------------------------------------------------------------------------------------
+161 25.0[C] Share 160 Platform 1 5-94 9-1-81 12-94
- ---------------------------------------------------------------------------------------------------------------------
188 25.0 5-92 9-1-92
Eugene Island
- ---------------------------------------------------------------------------------------------------------------------
101 20.0 3-91 5-1-91
- ---------------------------------------------------------------------------------------------------------------------
102 20.0 3-91 5-1-91
- ---------------------------------------------------------------------------------------------------------------------
211 33.3 Share 212 Platform 3 5-83 7-1-83 1-87
- ---------------------------------------------------------------------------------------------------------------------
212 33.3 1 1 3 5-83 7-1-83 1-87
- ---------------------------------------------------------------------------------------------------------------------
256 69.2 5 1 7 12-70 2-1-71 10-79
- ---------------------------------------------------------------------------------------------------------------------
261 66.7 2 1 17 10-74 12-1-74 10-79
- ---------------------------------------------------------------------------------------------------------------------
295* 20.0/100.0 7[B] 2 30 12-70 2-1-71 2-73
- ---------------------------------------------------------------------------------------------------------------------
312 4.0 5 Share 333 Platform 8 3-74 5-1-74 7-77
- ---------------------------------------------------------------------------------------------------------------------
318 20.0 1 3-91 6-1-91
- ---------------------------------------------------------------------------------------------------------------------
330 35.0[D] 10[B] 4 94 12-70 1-1-71 4-73
- ---------------------------------------------------------------------------------------------------------------------
333 4.0 3 2 22 12-72 2-1-73 7-77
- ---------------------------------------------------------------------------------------------------------------------
337 37.5 3 1 8 2-76 3-1-76 6-85
- ---------------------------------------------------------------------------------------------------------------------
Ship Shoal
175 33.3 Share EI 212 Platform 2 5-83 7-1-83 7-88
- ---------------------------------------------------------------------------------------------------------------------
240 30.0 2 2 3-89 6-1-89 12-94
- ---------------------------------------------------------------------------------------------------------------------
256 30.0 1 1 3-90 5-1-90 12-94
- ---------------------------------------------------------------------------------------------------------------------
South Timbalier
198 25.0 2 1 4 5-85 9-1-85 8-90
- ---------------------------------------------------------------------------------------------------------------------
+214 25.0[C] 1 Share 198 Platform 1 5-85 9-1-85 8-90
- ---------------------------------------------------------------------------------------------------------------------
West Delta
59 20.0 3-90 6-1-90
- ---------------------------------------------------------------------------------------------------------------------
South Pass
+33 15.9[C] Share 49 Platform 2 10-74 12-1-74 2-83
- ---------------------------------------------------------------------------------------------------------------------
49 15.9[G] 5[B] 1 19 9-72 11-1-72 10-80
- ---------------------------------------------------------------------------------------------------------------------
50 50.0 1 Share 49 Platform 7-93 8-1-88 12-93
- ---------------------------------------------------------------------------------------------------------------------
+57 12.0 Share 57/58 Platform 3 11-76 1-1-77 11-82
- ---------------------------------------------------------------------------------------------------------------------
+78 9.0 5 1 12 9-72 10-1-72 4-81
- ---------------------------------------------------------------------------------------------------------------------
(footnotes at end of table)
18
20
POGO EXPLORATORY DEVELOPMENT DATE OR
WORKING WELLS PLATFORMS WELLS LEASE ANTICIPATED
INTEREST DRILLED OR SET OR DRILLED OR DATE EFFECTIVE DATE OF
BLOCK % DRILLING ANNOUNCED DRILLING ACQUIRED DATE PRODUCTION
- ---------------------------------------------------------------------------------------------------------------------
Mississippi Canyon
63 20.0 2 1 5 5-75 7-1-75 6-84
- ---------------------------------------------------------------------------------------------------------------------
Main Pass
+30 25.0[E] 2 1 8[F] 10-81 12-1-81 12-87
- ---------------------------------------------------------------------------------------------------------------------
37 25.0 4 1 5 7-79 10-1-79 7-82
- ---------------------------------------------------------------------------------------------------------------------
61 24.0 1 3-90 7-1-90
- ---------------------------------------------------------------------------------------------------------------------
+72 35.3 1 Share 73 Platform 2 5-75 7-1-75 8-79
- ---------------------------------------------------------------------------------------------------------------------
+72/74 35.3 4 2 46 11-76 1-1-77 8-79
- ---------------------------------------------------------------------------------------------------------------------
73 35.3 4 1 16 10-74 12-1-74 8-79
- ---------------------------------------------------------------------------------------------------------------------
123 30.0 2 1 2 3-90 5-1-90 1-95
- ---------------------------------------------------------------------------------------------------------------------
131 33.33 5-92 9-1-92
- ---------------------------------------------------------------------------------------------------------------------
TOTAL LOUISIANA 115 43 506
- ---------------------------------------------------------------------------------------------------------------------
STATE LEASES
Offshore Louisiana
South Pass
+57/58 12.0 3 1 13 5-74 5-13-74 7-82
- --------------------------------------------------------------------------------------------------------------------
Main Pass
31 50.0 1 1 1 3-85 3-18-85 2-90
- ---------------------------------------------------------------------------------------------------------------------
Breton Sound
2 100.0 2[F] 1 1 4-80 9-15-80 8-87
- ---------------------------------------------------------------------------------------------------------------------
23 82.5 1 1 9-78 9-18-78 7-84
- ---------------------------------------------------------------------------------------------------------------------
24 22.5 1 1 1 9-78 9-18-78 7-84
- ---------------------------------------------------------------------------------------------------------------------
North Lighthouse Point
S/L 340 50.0 1 3 5-84 5-1-84 10-84
- ---------------------------------------------------------------------------------------------------------------------
TOTAL STATE LEASES 9 5 19
- ---------------------------------------------------------------------------------------------------------------------
TOTAL DOMESTIC OFFSHORE 146 58 564
- ---------------------------------------------------------------------------------------------------------------------
[A] Block farmed out -- Overriding Royalty Interest only
[B] Includes offset contribution well
[C] Block farmed in
[D] Pogo owns 35% in "A", "B", and "C" platform area and 30% in platform "D"
area
[E] Portion of block farmed out
[F] Includes one farmout well
[G] Pogo owns 20% in a non-unit area
* Pogo owns 20% in rights below 3,000 feet and 100% in rights at 3,000 feet
and above in certain portions of the block
[+] Represents portion of block
ITEM 3. LEGAL PROCEEDINGS.
In 1989, a large number of exploration and production companies, including
the Company, were circularized with Special Notice Letters in accordance with
CERCLA from the EPA regarding a particular waste disposal site in Louisiana
known as the "Gulf Coast Vacuum Site" utilized by a trucking company. The EPA
subsequently developed a list based on its investigation showing the Company
bearing an approximate 1% responsibility for this site based on the trucking
company's shipping records. The Company utilized the trucking company to dispose
of salt water produced from a well in which the Company had an interest. The
Company, however, believes that none of this salt water was delivered to the
Gulf Coast Vacuum Site. In any
19
21
event, the Company believes that the trucking company shipped only oilfield
waste for the Company which is exempt pursuant to CERCLA and, further, that such
shipments, if any, were sent to a properly permitted waste disposal site. The
Company has learned that the EPA has recently entered a consent decree, the
details of which have not been made fully public, with certain parties that are
believed to be responsible for a majority of the disposal occurring at the site.
The Company is a party to various other legal proceedings consisting of
routine litigation incidental to its businesses, but believes that any potential
liabilities resulting from these proceedings are adequately covered by insurance
or are otherwise immaterial at this time.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS.
Not Applicable.
ITEM S-K 401(B). EXECUTIVE OFFICERS OF REGISTRANT.
Executive officers of the Company are appointed annually to serve for the
ensuing year or until their successors have been elected or appointed. The
executive officers of the Company, their age as of February 1, 1995, 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 49 1991
Kenneth R. Good...................... Senior Vice President --
Land and Budgets 57 1991
D. Stephen Slack..................... Senior Vice President, Chief
Financial Officer and
Treasurer 45 1988
Stuart P. Burbach.................... Vice President and
Offshore Division Manager 42 1991
Jerry A. Cooper...................... Vice President and
Western Division Manager 46 1990
Harvey L. Gold....................... Vice President -- Engineering 59 1988
Thomas E. Hart....................... Vice President and Controller 52 1988
R. Phillip Laney..................... Vice President and
International Division
Manager 54 1991
John O. McCoy, Jr.................... Vice President and
Chief Administrative Officer 43 1989
J. D. McGregor....................... Vice President -- Sales 50 1988
Sammie M. Shaw....................... Vice President -- Operations 63 1992
Ronald B. Manning.................... Corporate Secretary and
Associate General Counsel 41 1990
Prior to assuming their present positions with the Company, the business
experience of each executive officer for more than the last five years was as
follows: Mr. Van Wagenen was President and Chief Operating Officer of the
Company since 1990, Senior Vice President and General Counsel of the Company
since 1986, Vice President and General Counsel of the Company since 1982, and
General Counsel of the Company since 1979; Mr. Good was Vice President -- Land
of the Company since 1988 and Chief Landman of the Company since 1977; Mr. Slack
was Regional Manager of Chemical Bank of New York's Southwest Energy and
Minerals Division since 1982; Mr. Burbach was Vice President of Norfolk Holding
Inc. since 1986 and Exploration Manager for Tricentrol Ltd. Canada and
Tricentrol U.S. since 1981; Mr. Cooper was a Division Landman for the Company
since 1983 and a Landman for the Company since 1979; Mr. Gold was Manager of
Reservoir Engineering for the Company since 1977; Mr. Hart was Controller for
the Company since 1977; Mr. Laney was International Exploration Manager for the
Company since 1983 and Exploration Coordinator
20
22
for the Gulf Coast Division of the Company since 1977; Mr. McCoy was Director of
Personnel and Administration for the Company since 1978; Mr. McGregor was
Manager of Hydrocarbon Sales and Contracts for the Company since 1981; Mr. Shaw
was Operations Manager for the Company since 1981; Mr. Manning was an Associate
General Counsel for the Company since 1989 and prior thereto was an attorney
with the Federal Bureau of Investigation, and Chevron U.S.A., and Assistant to
the General Counsel of Primary Fuels, Inc.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER
MATTERS.
The following table shows the range of low and high sales prices of the
Company's Common Stock (the "Common Stock") on the New York Stock Exchange
composite tape where the Company's common stock trades under the symbol PPP. The
Company's common stock is also listed on the Pacific Stock Exchange.
In 1994, the Company paid $0.06 per share in dividends on its Common Stock
since it commenced paying dividends in August 1994. 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, 1994, $64,037,000 was available for dividends under this
limitation.
LOW HIGH
--- ----
1993
1st Quarter.......................................................... 9 3/ 17 1/4
2nd Quarter.......................................................... 16 1/8 21
3rd Quarter.......................................................... 13 5/8 19 1/8
4th Quarter.......................................................... 14 3/8 19 3/4
1994
1st Quarter.......................................................... 15 5/8 21 1/2
2nd Quarter.......................................................... 15 5/8 24 1/4
3rd Quarter.......................................................... 19 5/8 23 5/8
4th Quarter.......................................................... 16 1/8 23 1/8
As of March 3, 1995, there were 3,815 holders of record of the Company's
Common Stock.
21
23
ITEM 6. SELECTED FINANCIAL DATA
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1994 1993 1992 1991 1990
-------- -------- -------- -------- --------
FINANCIAL DATA
(Expressed in thousands, except per share data)
Revenues:
Crude oil and condensate........................ $ 65,141 $ 64,042 $ 64,224 $ 54,420 $ 54,018
Natural gas..................................... 99,093 66,173 67,366 63,225 74,111
Natural gas liquids............................. 9,189 7,288 5,833 3,442 3,496
Other, net...................................... 133 (950) 1,705 3,338 794
-------- -------- -------- -------- --------
Oil and gas revenues............................ 173,556 136,553 139,128 124,425 132,419
Interest on tax refunds......................... -- 2,322 -- -- 22,499
Gains (losses) on sales......................... 52 679 1,702 44 (98)
-------- -------- -------- -------- --------
Total.................................... $173,608 $139,554 $140,830 $124,469 $154,820
========= ========= ========= ========= =========
Income before extraordinary item.................. $ 27,374 $ 25,061 $ 18,495 $ 10,322 $ 44,036
Extraordinary gains (losses)...................... (307) -- -- 1,336 --
-------- -------- -------- -------- --------
Net income........................................ $ 27,067 $ 25,061 $ 18,495 $ 11,658 $ 44,036
========= ========= ========= ========= =========
Per share data:
Primary and fully diluted earnings:
Before extraordinary item..................... $ 0.82 $ 0.76 $ 0.66 $ 0.37 $ 1.69
Extraordinary item............................ (0.01) -- -- 0.05 --
-------- -------- -------- -------- --------
Net income.................................... $ 0.81 $ 0.76 $ 0.66 $ 0.42 $ 1.69
========= ========= ========= ========= =========
Price range of common stock:
High.......................................... $ 24.25 $ 21.00 $ 13.88 $ 8.25 $ 10.13
Low........................................... $ 15.63 $ 9.75 $ 5.13 $ 4.63 $ 5.75
Weighted average number of common and common
equivalent shares outstanding................... 33,352 32,860 27,929 27,611 26,029
Long-term debt at year end........................ $149,249 $130,539 $129,260 $184,260 $217,000
Production payment obligation at year end......... $ -- $ -- $ 24,854 $ 45,475 $ 46,893
Shareholders' equity (deficit) at year end........ $ 64,037 $ 33,803 $ 5,648 $(56,636) $(68,429)
Total assets at year end.......................... $298,826 $239,774 $206,347 $213,772 $244,226
PRODUCTION (SALES) DATA
Net daily average and weighted average price:
Natural gas (Mcf per day)..................... 144,800 91,700 105,200 104,200 107,300
Price (per Mcf)............................. $ 1.88 $ 1.98 $ 1.75 $ 1.66 $ 1.89
Crude oil-condensate (Bbl. per day)........... 11,100 9,851 8,699 7,108 6,209
Price (per Bbl.)............................ $ 16.08 $ 17.81 $ 20.17 $ 20.98 $ 23.84
Natural gas liquids (Bbl. per day)
Leasehold ownership......................... 2,075 1,538 1,037 609 593
Plant ownership............................. 147 140 144 54 104
Price (per Bbl.)............................ $ 11.33 $ 11.90 $ 13.50 $ 14.21 $ 13.75
CAPITAL EXPENDITURES (Expressed in thousands)
Oil and gas:
Domestic Offshore --
Exploration................................... $ 2,800 $ 4,600 $ 1,700 $ 1,600 $ 2,900
Development................................... 44,100 33,700 5,500 23,600 24,900
Purchase of reserves.......................... 32,600 -- 8,900 5,100 --
Domestic Onshore --
Exploration................................... 6,800 5,200 4,900 4,700 2,300
Development................................... 23,700 24,300 15,600 13,900 8,100
International Exploration....................... 5,100 4,600 1,400 -- --
-------- -------- -------- -------- --------
Total oil and gas........................ 115,100 72,400 38,000 48,900 38,200
Other............................................. 1,200 200 600 2,400 --
-------- -------- -------- -------- --------
Total.................................... $116,300 $ 72,600 $ 38,600 $ 51,300 $ 38,200
========= ========= ========= ========= =========
22
24
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
RESULTS OF OPERATIONS
The Company reported net income for 1994 of $27,067,000 or $0.81 per share
(on both a primary and fully diluted basis) compared to net income for 1993 of
$25,061,000 or $0.76 per share (on both a primary and fully diluted basis) and
net income for 1992 of $18,495,000 or $0.66 per share (on both a primary and
fully diluted basis). Included in net income for 1994 is an extraordinary loss
of $307,000 (net of taxes) or $0.01 per share in connection with the retirement
of the Company's 10.25% Convertible Subordinated Notes, due 1999 (the "10.25%
Notes") on April 18, 1994. Earnings per common share are based on the weighted
average number of common and common equivalent shares outstanding for 1994 of
33,352,000 compared to 32,860,000 for 1993 and 27,929,000 for 1992. The
increases in the weighted average number of common and common equivalent shares
outstanding for 1993 resulted primarily from the issuance of 4,500,000 shares of
common stock in December 1992 as set forth in the Consolidated Statements of
Shareholders' Equity included in "Item 8. Financial Statements and Supplementary
Data." The increases in the weighted average number of common and common
equivalent shares outstanding for 1994 resulted 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
would reflect additional common shares issuable upon the assumed conversion of
the Company's 5 1/2% Convertible Subordinated Notes, due 2004 (the "5 1/2%
Notes") (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. However, the
dilution resulting from the assumed conversion of the 5 1/2% Notes was not
sufficient to change reported earnings per share.
The Company's total revenues for 1994 were $173,608,000, an increase of
approximately 24% from total revenues of $139,554,000 for 1993, and an increase
of approximately 23% from total revenues of $140,830,000 for 1992. The increase
in the Company's total revenues for 1994, compared to 1993 and 1992, resulted
primarily from increased natural gas, crude oil, condensate and natural gas
liquid ("NGL") production volumes. Partially offsetting volume increases were
substantial decreases in the prices that the Company received for its crude oil
and condensate production volumes. In addition, the Company's total revenues for
1993 and 1992 were positively affected by revenues from settlement of an issue
with the Internal Revenue Service and gains related to the sale of non-strategic
properties.
The Company's oil and gas revenues for 1994 were $173,556,000, an increase
of approximately 27% from oil and gas revenues of $136,553,000 for 1993, and an
increase of approximately 25% from oil and gas revenues of $139,128,000 for
1992. The following table reflects an analysis of variances in the Company's oil
and gas revenues between 1994 and the previous two years:
1994 COMPARED TO
--------------------
1993 1992
------- --------
(IN THOUSANDS)
Increase (decrease) in oil and gas revenues resulting from
variances in:
Natural Gas
Price...................................................... $(3,380) $ 4,850
Production................................................. 36,300 26,877
------- --------
32,920 31,727
------- --------
Crude oil and condensate
Price...................................................... (6,228) (13,029)
Production................................................. 7,327 13,946
------- --------
1,099 917
------- --------
Natural gas liquids
Price...................................................... (350) (937)
Production................................................. 2,251 4,293
------- --------
1,901 3,356
------- --------
Other, net.................................................... 1,083 (1,572)
------- --------
Increase in oil and gas revenues................................ $37,003 $ 34,428
======= ========
23
25
Average natural gas prices received by the Company for the two years prior
to 1994 were volatile and marked by non-seasonal as well as seasonal variations.
The average price per Mcf that the Company received for its natural gas
production increased during 1993, compared to 1992, averaging $1.75 per Mcf for
1992 and $1.98 per Mcf for 1993. Prices increased throughout 1993, partially as
a result of severe late winter weather that drew down natural gas storage
supplies which, coupled with relatively high crude oil prices that inhibited
fuel switching from natural gas to residual heating oil at that time, created a
substantial demand in the spring and the summer to replenish depleted storage
facilities and to supply natural gas for the industrial and electric generation
markets. Notwithstanding severe winter weather during January and February of
1994 that led to record low natural gas storage levels in March, rapid injection
of natural gas into storage coupled with a mild summer contributed to a
substantial decline in natural gas prices during the second half of 1994
resulting in the Company receiving an average price of $1.88 per Mcf for its
natural gas production during 1994 which, while it was 5% less than the average
price that the Company received in 1993, was still an increase of 7% over the
average price that the Company received in 1992. See "Business -- Miscellaneous;
Competition and Market Conditions." Natural gas production for 1994 averaged
144.8 MMcf per day, an increase of approximately 58% from average production of
91.7 MMcf per day in 1993, and an increase of approximately 38% from average
production of 105.2 MMcf per day for 1992. The increase in the Company's average
natural gas production for 1994, compared to 1993 and 1992, was related
primarily to natural gas production from the Company's Eugene Island Block
295"B" platform from which production commenced in late February 1994, and the
continued success of the Company's ongoing active offshore and onshore drilling
and workover programs, which was partially offset by a natural decline in
deliverability from some of the Company's more mature properties.
As of January 1, 1995, the Company had entered into futures contracts with
various parties on a portion of its daily natural gas production through
September 30, 1995 (commencing with contracts totaling approximately 37 MMcf per
day in January and decreasing on a quarterly basis to approximately 15 MMcf per
day) at varying prices ranging from approximately $1.92 to $1.83 per Mcf.
Crude oil and condensate prices received by the Company averaged $16.08 per
barrel in 1994 compared to $17.81 per barrel in 1993 and $20.17 per barrel in
1992. Crude oil and condensate prices were relatively stable during 1992 and the
first six months of 1993. However, commencing in July 1993, the average price
per barrel that the Company received for its production began dropping until, by
December 1993, the average price per barrel for crude oil and condensate that
the Company received for its production during that month averaged only $13.39
per barrel. However, the average price per barrel that the Company received for
its crude oil and condensate production began recovering in June 1994 and showed
gradual improvement throughout the remainder of the year. For the month of
December 1994, the average price per barrel that the Company received for its
crude oil and condensate production was $16.44. Crude oil and condensate
production for 1994 averaged 11,100 Bbls per day, an increase of approximately
13% from 9,851 Bbls per day for 1993, and an increase of approximately 28% from
8,699 Bbls per day for 1992. The increase in the Company's crude oil and
condensate production for 1994, compared to 1993 and 1992, resulted primarily
from ongoing development programs principally in the Main Pass, Eugene Island
and South Pass areas, together with the acquisition by the Company of additional
working interests in certain leases in the Main Pass area. See "Properties --
Principal Properties" and "Business -- Domestic Offshore Operations; Lease
Acquisitions."
As of February 1, 1995, the Company had entered into a crude oil swap
agreement with another party in which it had swapped the floating market price
it receives from purchasers of its crude oil for a fixed price of $17.08 per
barrel on 1,000 Bbls per day of the Company's production for a period ending
April 30, 1995. See "Business -- Miscellaneous; Sales."
Liquid products are often extracted from natural gas streams and sold
separately as NGL. The Company's NGL production averaged 2,222 Bbls per day for
1994, an increase of approximately 32% from an average of 1,678 Bbls per day for
1993 and an increase of approximately 88% from an average of 1,181 Bbls per day
for 1992. The increase in the Company's NGL production during 1994, compared to
1993 and 1992, resulted primarily from extracting liquids from several new high
Btu content wells and increased production generally.
24
26
The Company's total liquids production during 1994, including crude oil,
condensate and NGL, averaged 13,322 Bbls per day, an increase of approximately
16% from an average total liquids production of 11,529 Bbls per day for 1993,
and an increase of approximately 35% from an average total liquids production of
9,880 Bbls per day for 1992.
The Company's oil and gas revenues for 1994, 1993 and 1992 also reflect
adjustments for various miscellaneous items. For 1993 and 1992, the Company made
adjustments to its net income to reflect the settlement of certain litigation
with the State of Louisiana regarding past royalty disputes pertaining to the
Company's offshore state leases. For 1993, additional adjustments were also made
to reflect an agreement with the MMS to allow the Company to offset FERC Order
93A payments previously made by the Company on behalf of the MMS against FERC
Order 94A obligations due from the Company and the resulting overaccrual of
related interest expenses.
Lease operating expenses for 1994 were $29,768,000, an increase of
approximately 12% from lease operating expenses of $26,633,000 for 1993, and an
increase of approximately 15% from lease operating expenses of $25,842,000 for
1992. The increase in lease operating expenses for 1994, compared to 1993 and
1992, resulted primarily from increased operating activity on existing
properties, including increased operating costs related to additional properties
brought on production in 1994. However, primarily as a result of increased
production of natural gas, crude oil, condensate and NGLs by the Company during
1994, compared to 1993 and 1992, the Company's lease operating expenses were
only $0.36 per equivalent Mcf for 1994, a decrease of 20% from lease operating
expenses of $0.45 per equivalent Mcf for 1993, and a decline of approximately
16% from lease operating expenses of $0.43 per equivalent Mcf for 1992.
General and administrative expenses for 1994 were $15,984,000, an increase
of approximately 10% from general and administrative expenses of $14,550,000 for
1993, and an increase of approximately 22% from general and administrative
expenses of $13,129,000 for 1992. The increase in general and administrative
expenses for 1994, compared to 1993 and 1992, was related to, among other
things, 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 1994
were $5,257,000, an increase of approximately 114% from exploration expenses of
$2,455,000 for 1993, and an increase of approximately 69% from exploration
expenses of $3,102,000 for 1992. The increase in exploration expenses for 1994,
compared to 1993 and 1992, resulted primarily from increased geophysical
activity by the Company, including the costs of conducting and processing
several proprietary 3-D seismic surveys on Company leases in South Texas, West
Texas and the Gulf of Thailand, together with the cost of acquiring several
non-proprietary 3-D seismic surveys in the Gulf of Mexico.
Dry hole and impairment expenses relate to costs of unsuccessful wells
drilled along with impairments to the associated unproved property costs and
impairments to previously proved property costs as a result of decreases in
expected reserves. The Company's dry hole and impairment expenses for 1994 were
$7,088,000, an increase of approximately 51% from dry hole and impairment costs
of $4,690,000 for 1993, but a decrease of approximately 24% from dry hole and
impairment costs of $9,314,000 for 1992.
The Company accounts for its oil and gas activities using the successful
efforts method of accounting. Under the successful efforts method, lease
acquisition costs and all development costs are capitalized. Unproved properties
are reviewed quarterly to determine if there has been impairment of the carrying
value, with any such impairment charged to expense in the period. Exploratory
drilling costs are capitalized until the results are determined. If proved
reserves are not discovered, the exploratory drilling costs are expensed. Other
exploratory costs are expensed as incurred.
The provision for depreciation, depletion and amortization ("DD&A") is
based on the capitalized costs mentioned in the preceding paragraph plus future
costs to abandon offshore wells and platforms and is determined on a
field-by-field basis using the units of production method. The Company's DD&A
expense for 1994 was $63,308,000, an increase of approximately 56% from DD&A
expenses of $40,693,000 for 1993, and
25
27
an increase of approximately 50% from DD&A expenses of $42,302,000 for 1992. The
increases in the Company's DD&A expenses for 1994, compared to 1993 and 1992,
resulted primarily from increased volumes produced (largely related to the
increased natural gas production discussed above) and, to a lesser extent, an
increase in the composite DD&A rate. The composite DD&A rate for all of the
Company's producing fields for 1994 was $0.77 per equivalent Mcf ($4.59 per
equivalent barrel), an increase of approximately 12% from a composite DD&A rate
of $0.69 per equivalent Mcf ($4.11 per equivalent barrel) for 1993, and an
increase of 10% from a composite DD&A rate of $0.70 per equivalent Mcf ($4.17
per equivalent barrel) for 1992. The Company produced 82,008,000 equivalent Mcf
(13,668,000 equivalent barrels) in 1994, an increase of approximately 40% from
the 58,718,000 equivalent Mcf (9,786 equivalent barrels) produced in 1993, and
an increase of approximately 36% from the 60,189,000 equivalent Mcf (10,032,000
equivalent barrels) produced in 1992. See "Financial Statements and
Supplementary Data -- Note 1 of Notes to Consolidated Financial Statements ."
Interest charges for 1994 were $10,104,000, a decrease of approximately 8%
from interest charges of $10,956,000 for 1993, and a decrease of approximately
47% from interest charges of $19,036,000 for 1992. The decrease in interest
charges for 1994, compared to 1993 and 1992, was related primarily to decreased
debt issue amortization expenses, lower average interest rate levels on the debt
outstanding (as a result of refinancing certain debt discussed in "-- Liquidity
and Capital Resources" below), and, as compared to 1992, a decrease in the
amount of debt outstanding. These decreases in interest charges for 1994,
compared to 1993 and 1992, were partially offset by increased commitment fees
resulting from increased availability under the Company's bank revolving credit
facility and, as compared to 1993, an increase in debt outstanding. See
"Financial Statements and Supplementary Data -- Note 3 of Notes to Consolidated
Financial Statement."
Income tax expense for 1994 was $15,517,000, an increase of approximately
4% from income tax expense of $14,981,000 for 1993, and an increase of
approximately 52% from income tax expense of $10,192,000 for 1992. The increases
in income tax expense are related to increases in profitability and to the
effective tax rates of 36.2% in 1994, 37.5% in 1993 and 35.5% in 1992. The
variances in the effective tax rates are primarily related to the expenses
incurred by the Company's subsidiary in Thailand which are not included in the
Company's consolidated U.S. federal income tax returns.
LIQUIDITY AND CAPITAL RESOURCES
The Company's Consolidated Statement of Cash Flows for the year ended
December 31, 1994, reflects net cash provided by operating activities of
$99,273,000. In addition to the net cash provided by operating activities, the
Company also received $3,687,000 from the exercise of stock options. Other
significant cash receipts and disbursements during 1994 included the following.
The Company issued and sold $86,250,000 of 5 1/2% Notes in March 1994, and had
net borrowings of $7,000,000 under uncommitted money market credit lines with
certain banks. The Company invested $85,375,000 of such cash flow in capital
projects during 1994, purchased certain proved reserves for $32,578,000, prepaid
the remaining outstanding principal and prepayment fee on its 10.25% Notes
($24,472,000), made net payments of $53,000,000 on the Company's revolving
credit facility, paid $2,446,000 of issuance expenses in connection with its
offering of the 5 1/2% Notes and paid $1,966,000 ($0.06 per share) in dividends
to holders of the Company's common stock. Of the $85,375,000 invested in capital
projects, $22,955,000 was applicable to 1993 projects and $62,420,000 was
applicable to 1994 capital projects. The Company's total debt at December 31,
1994, was $150,531,000, an increase of approximately 12% from total debt of
$134,539,000 at December 31, 1993. The increase in the Company's total debt
resulted primarily from the purchase of certain proved reserves in the fourth
quarter of 1994. As of December 31, 1994, the Company had $2,922,000 in cash and
cash investments.
The Company's capital and exploration budget for 1995, 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, was
established by the Company's Board of Directors in January 1995, at
$100,000,000, an increase of approximately 13% from the Company's capital and
exploration expenditures (excluding purchased reserves and interest capitalized)
of $88,300,000 for 1994, an increase of approximately 34% over capital and
exploration expenditures (excluding capitalized interest) of $74,600,000 for
1993, and an increase of approximately 209% over capital and exploration
expenditures (excluding purchased reserves and interest capitalized) of
approximately $32,400,000 for 1992.
26
28
In addition to anticipated capital and exploration expenses, other material
1995 cash requirements that the Company currently anticipates include ongoing
operating, general and administrative, income tax, and interest expense, sinking
fund payments and the payment of dividends on its common stock, including a
$0.03 per share dividend on its common stock to be paid February 28, 1995, to
stockholders of record on February 10, 1995. The Company currently anticipates
that cash provided by operating activities and funds available under its Credit
Agreement and uncommitted money market credit lines will be sufficient to fund
the Company's ongoing expenses, its 1995 capital and exploration budget and
anticipated future dividend payments. In this regard, the Company reinstated the
practice of declaring a quarterly 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.
The Company's amended bank credit agreement (the "Credit Agreement")
currently provides for a $100,000,000 revolving/term credit facility which will
be fully revolving until June 29, 1996, after which the balance will be due in
eight quarterly term loan installments, commencing July 31, 1996. The amount
that may be borrowed under the Credit Agreement may not exceed a borrowing base,
determined semiannually by the lenders in accordance with the Credit Agreement
based on the discounted present value of certain of the Company's oil and gas
reserves. The borrowing base currently exceeds $100,000,000. The Credit
Agreement is governed by various financial and other covenants, including
requirements to maintain positive working capital (excluding current maturities
of debt), a fixed charge coverage ratio, and limitations on the prepayment
(without refinancing) of subordinated debt, the payment of dividends, mergers
and consolidations, and asset dispositions. See "Market for the Registrant's
Common Stock and Related Security Holder Matters." Upon the occurrence or
declaration of certain events, the banks would be entitled to a security
interest in the borrowing base properties, which include most of the Company's
domestic properties. Borrowings under the Credit Agreement currently bear
interest at a Base (Prime) rate, a certificate of deposit rate plus 1 5/8%, or
LIBOR plus 1 1/2%, at the Company's option. A commitment fee of 1/2 of 1% per
annum of the unborrowed amount under the Credit Agreement is also due.
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 intends 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, 1994, indebtedness in the principal amount of $21,000,000 was
outstanding under the Credit Agreement and the two letter agreements.
The outstanding principal amount of 5 1/2% Notes was $86,250,000 as of
December 31, 1994. The 5 1/2% Notes are convertible into Common Stock at $22.188
per share subject to adjustment upon the occurrence of certain events. The
5 1/2% 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 5 1/2% Notes. The 5 1/2% Notes are redeemable at
the option of the holder, upon the occurrence of a repurchase event (a change of
control as defined in the indenture governing the 5 1/2% Notes), at 100% of the
principal amount.
The outstanding principal amount of the 8% Convertible Subordinated
Debentures, due 2005 (the "8% Debentures") was $43,281,000 as of December 31,
1994. The 8% Debentures are convertible into Common Stock at $39.50 per share,
subject to adjustment in certain circumstances, including stock splits. The 8%
Debentures are redeemable at the option of the Company at 102.4% of their
principal amount through December 30, 1995, and decreasing percentages
thereafter, and are subject to mandatory annual sinking fund requirements of
$3,000,000, due each December, with a final maturity of December 31, 2005. The
sinking fund requirements for the 8% Debentures will be sufficient to retire all
but $15,000,000 of the issue prior to
27
29
maturity. The Company currently has purchased $1,718,000 face amount of 8%
Debentures which it may tender in satisfaction of future sinking fund
requirements. See "Financial Statements and Supplementary Data -- Note 3 to
Notes to Consolidated Financial Statements."
OTHER MATTERS
Publicly held companies are asked to comment on the effects of inflation on
their business. Currently annual inflation in terms of the decrease in the
general purchasing power of the dollar is running much below the general annual
inflation rates 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.
28
30
ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 1994
POGO PRODUCING COMPANY AND SUBSIDIARIES
HOUSTON, TEXAS
29
31
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,
1994 and 1993, and the related consolidated statements of income, shareholders'
equity and cash flows for each of the three years in the period ended December
31, 1994. These financial statements are the responsibility of Pogo'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, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
February 3, 1995
30
32
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31,
----------------------------------
1994 1993 1992
-------- -------- --------
(EXPRESSED IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
Revenues:
Oil and gas.............................................. $173,556 $136,553 $139,128
Interest on tax refund................................... -- 2,322 --
Gains on sales........................................... 52 679 1,702
-------- -------- --------
Total............................................ 173,608 139,554 140,830
-------- -------- --------
Operating Costs and Expenses:
Lease operating.......................................... 29,768 26,633 25,842
General and administrative............................... 15,984 14,550 13,129
Exploration.............................................. 5,257 2,455 3,102
Dry hole and impairment.................................. 7,088 4,690 9,314
Depreciation, depletion and amortization................. 63,308 40,693 42,302
-------- -------- --------
Total............................................ 121,405 89,021 93,689
-------- -------- --------
Operating Income........................................... 52,203 50,533 47,141
Interest:
Charges.................................................. (10,104) (10,956) (19,036)
Income................................................... 53 14 191
Capitalized.............................................. 739 451 391
-------- -------- --------
Income Before Taxes and Extraordinary Item................. 42,891 40,042 28,687
-------- -------- --------
Income Tax Expense......................................... (15,517) (14,981) (10,192)
-------- -------- --------
Income Before Extraordinary Item........................... 27,374 25,061 18,495
Extraordinary Loss on Early Extinguishment of Debt, net of
tax...................................................... (307) -- --
-------- -------- --------
Net Income................................................. $ 27,067 $ 25,061 $ 18,495
======== ======== ========
Primary and Fully Diluted Earnings per Common Share:
Before extraordinary item................................ $ 0.82 $ 0.76 $ 0.66
Extraordinary item....................................... (0.01) -- --
-------- -------- --------
Net income............................................... $ 0.81 $ 0.76 $ 0.66
======== ======== ========
Dividends per Common Share................................. $ 0.06 $ -- $ --
======== ======== ========
The accompanying notes to consolidated financial statements are an integral part
hereof.
31
33
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
DECEMBER 31,
--------------------
1994 1993
-------- --------
(EXPRESSED IN
THOUSANDS)
Current Assets:
Cash and cash investments............................................. $ 2,922 $ 6,713
Accounts receivable................................................... 28,915 18,480
Other receivables..................................................... 14,717 10,123
Federal income taxes and interest receivable.......................... -- 3,320
Inventories........................................................... 2,422 1,105
Other................................................................. 745 727
-------- --------
Total current assets.......................................... 49,721 40,468
-------- --------
Property and Equipment:
Oil and gas, on the basis of successful efforts accounting
Proved properties being amortized.................................. 913,865 817,218
Unproved properties and properties under development, not being
amortized......................................................... 6,890 6,465
Other, at cost........................................................ 8,268 6,961
-------- --------
929,023 830,644
Less -- accumulated depreciation, depletion, and amortization,
including
$5,040 and $4,452 respectively, applicable to other property....... 691,110 638,658
-------- --------
237,913 191,986
-------- --------
Other................................................................... 11,192 7,320
-------- --------
$298,826 $239,774
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable...................................................... $ 8,065 $ 8,307
Other payables........................................................ 26,497 22,955
Current portion of long-term debt..................................... 1,282 4,000
Accrued interest payable.............................................. 1,583 1,202
Accrued payroll and related benefits.................................. 1,237 1,005
Other................................................................. 40 122
-------- --------
Total current liabilities..................................... 38,704 37,591
Long-Term Debt.......................................................... 149,249 130,539
Deferred Federal Income Tax............................................. 36,487 29,724
Deferred Credits........................................................ 10,349 8,117
-------- --------
Total liabilities............................................. 234,789 205,971
-------- --------
Shareholders' Equity:
Preferred stock, $1 par; 2,000,000 shares authorized.................. -- --
Common stock, $1 par; 43,333,333 shares authorized, 32,825,836 and
32,449,197 shares issued, respectively............................. 32,826 32,449
Additional capital.................................................... 130,675 125,919
Retained earnings (deficit)........................................... (99,140) (124,241)
Treasury stock, at cost............................................... (324) (324)
-------- --------
Total shareholders' equity.................................... 64,037 33,803
-------- --------
$298,826 $239,774
======== ========
The accompanying notes to consolidated financial statements are an integral part
hereof.
32
34
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
-----------------------------------
1994 1993 1992
--------- -------- --------
(EXPRESSED IN THOUSANDS)
Cash flows from operating activities:
Cash received from customers...................................... $ 165,549 $141,012 $135,877
Federal income taxes and interest received........................ 3,364 -- --
Operating, exploration, and general and administrative expenses
paid............................................................ (50,894) (45,051) (41,360)
Interest paid..................................................... (9,620) (10,912) (21,262)
Payment of royalties and related interest on FERC Order 94-A
refunds......................................................... -- -- (4,872)
Federal income taxes paid......................................... (7,500) (2,800) (1,500)
Settlement of natural gas transportation and exchange imbalance... (2,168) -- --
Other............................................................. 542 895 828
--------- -------- --------
Net cash provided by operating activities.................. 99,273 83,144 67,711
--------- -------- --------
Cash flows from investing activities:
Capital expenditures.............................................. (85,375) (62,353) (30,304)
Purchase of proved reserves....................................... (32,578) -- (8,924)
Proceeds from the sale of property and tubular stock.............. 52 2,713 4,017
--------- -------- --------
Net cash used in investing activities...................... (117,901) (59,640) (35,211)
--------- -------- --------
Cash flows from financing activities:
Proceeds from issuance of new debt................................ 86,250 -- --
Net borrowings under uncommitted lines of credit with banks....... 7,000 -- --
Proceeds from exercise of stock options........................... 3,687 2,026 703
Net borrowings (payments) under revolving credit agreements....... (53,000) 8,000 (1,000)
Principal payments of other long-term debt obligations............ (24,472) (7,000) (54,000)
Principal payments of production payment obligation............... -- (24,854) (20,621)
Proceeds from issuance of common stock............................ -- -- 43,313
Debt issue expenses paid.......................................... (2,446) -- (1,100)
Payment of cash dividends on common stock......................... (1,966) -- --
Purchase of 8% debentures due 2005................................ (216) -- --
--------- -------- --------
Net cash provided by (used in) financing activities........ 14,837 (21,828) (32,705)
--------- -------- --------
Net increase (decrease) in cash and cash investments................ (3,791) 1,676 (205)
Cash and cash investments at the beginning of the year.............. 6,713 5,037 5,242
--------- -------- --------
Cash and cash investments at the end of the year.................... $ 2,922 $ 6,713 $ 5,037
========== ========= =========
Reconciliation of net income to net cash provided by operating
activities:
Net income........................................................ $ 27,067 $ 25,061 $ 18,495
Adjustments to reconcile net income to net cash provided by
operating activities............................................
Extraordinary loss on early extinguishment of debt, net of
tax........................................................... 307 -- --
Gains on sales.................................................. (52) (679) (1,702)
Depreciation, depletion and amortization........................ 63,308 40,693 42,302
Dry hole and impairment......................................... 7,088 4,690 9,314
Interest capitalized............................................ (739) (451) (391)
Increase in deferred federal income taxes....................... 8,374 13,356 8,669
Change in assets and liabilities:
(Increase) decrease in accounts receivable.................... (10,435) 4,172 (1,191)
(Increase) decrease in federal income taxes and interest
receivable................................................. 3,320 (3,320) --
Increase in other current assets.............................. (18) (360) (27)
(Increase) decrease in other assets........................... (1,426) 838 (3,515)
Increase (decrease) in accounts payable....................... (242) (1,592) 733
Increase (decrease) in accrued interest payable............... 381 80 (2,480)
Increase (decrease) in accrued payroll and related benefits... 232 63 (244)
Decrease in other current liabilities......................... (124) (20) (9)
Increase (decrease) in deferred credits....................... 2,232 613 (2,243)
--------- -------- --------
Net cash provided by operating activities........................... $ 99,273 $ 83,144 $ 67,711
========== ========= =========
The accompanying notes to consolidated financial statements are an integral part
hereof.
33
35
POGO PRODUCING COMPANY & SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
RETAINED SHAREHOLDERS'
SHARES COMMON ADDITIONAL EARNINGS TREASURY EQUITY
OUTSTANDING STOCK CAPITAL (DEFICIT) STOCK (DEFICIT)
--------- -------- ---------- --------- -------- -------------
(DOLLARS EXPRESSED IN THOUSANDS)
BALANCE AT DECEMBER 31, 1991..... 27,456,822 $ 27,457 $ 83,704 $(167,797) $ -- $ (56,636)
Net income....................... -- -- -- 18,495 -- 18,495
Issuance of common stock......... 4,500,000 4,500 38,368 -- -- 42,868
Exercise of stock options........ 147,042 147 774 -- -- 921
--------- -------- ---------- --------- -------- ---------
BALANCE AT DECEMBER 31, 1992..... 32,103,864 32,104 122,846 (149,302) -- 5,648
Net income....................... -- -- -- 25,061 -- 25,061
Exercise of stock options........ 345,308 345 3,072 -- -- 3,417
Acquisition of treasury stock, at
cost........................... (15,575) -- -- -- (324) (324)
Conversion of debenture.......... 25 -- 1 -- -- 1
--------- -------- ---------- --------- -------- ---------
BALANCE AT DECEMBER 31, 1993..... 32,433,622 32,449 125,919 (124,241) (324) 33,803
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
========== ======== ========= ========= ====== =========
The accompanying notes to consolidated financial statements are an integral part
hereof.
34
36
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation --
The consolidated financial statements include the accounts of Pogo
Producing Company and its wholly-owned subsidiaries (the "Company"), after
elimination of all significant intercompany transactions.
Inventories --
Inventories consist primarily of tubular goods used in the Company's
operations and are stated at the lower of average cost or market value.
Interest Capitalized --
Interest costs related to financing major oil and gas projects in progress
are capitalized until the projects are evaluated.
Earnings per Share --
Earnings per common and common equivalent share (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 are common stock equivalents and were anti-dilutive in all
periods. 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
and the 5 1/2% Notes (issued on March 16, 1994) which were dilutive for the
portion of 1994 in which they were outstanding, but such dilution was not
sufficient to change reported earnings per share. Earnings per share are based
on the following:
1994 1993 1992
------- ------- -------
(EXPRESSED IN THOUSANDS)
Earnings applicable to Common Stock:
Primary --
Income before extraordinary loss................... $27,374 $25,061 $18,495
Extraordinary loss................................. (307) -- --
------- ------- -------
Net income......................................... $27,067 $25,061 $18,495
======= ======= =======
Fully diluted --
Income before extraordinary loss................... $29,755 $25,061 $18,495
Extraordinary loss................................. (307) -- --
------- ------- -------
Net income......................................... $29,448 $25,061 $18,495
======= ======= =======
Weighted average number of Common Stock and common
equivalent shares outstanding:
Primary............................................ 33,352 32,860 27,929
Fully diluted...................................... 36,451 32,894 28,073
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, 1994, the
35
37
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company had taken approximately 4,873 MMcf of natural gas less than it was
entitled to based on its interest in certain properties, and approximately 1,994
MMcf more than its entitlement in certain other properties placing the Company
at year end in a net under-delivered position of approximately 2,879 MMcf of
natural gas based on its working interest ownership in the properties.
Oil and Gas Activities and Depreciation, Depletion, and Amortization --
The Company follows the successful efforts method of accounting for its oil
and gas activities. Under the successful efforts method, lease acquisition costs
and all development costs are capitalized. Unproved properties are reviewed
quarterly to determine if there has been impairment of the carrying value, with
any such impairment charged to expense in the period. Exploratory drilling costs
are capitalized until the results are determined. If proved reserves are not
discovered, the exploratory drilling costs are expensed. Other exploratory costs
are expensed as incurred. The provision for depreciation, depletion and
amortization is based on the capitalized costs mentioned above plus future costs
to abandon offshore wells and platforms and is determined on a field-by-field
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 the acquisition of treasury stock in 1993 in
exchange for stock options exercised and the conversion in 1993 of a debenture
into Common Stock. In addition, the Company in 1993, exchanged its working
interest in thirteen Gulf of Mexico oil and gas properties for an increased
working interest in five other Gulf of Mexico oil and gas properties in a
noncash "like kind" exchange. The oil and gas property and accumulated
depreciation, depletion and amortization accounts as reflected in the
Consolidated Balance Sheets have been adjusted to reflect the appropriate
amounts to record the working interests acquired and disposed of. The oil and
gas reserves acquired and disposed of are reflected as purchases and sales in
the "Estimates of Proved Reserves" roll forward included in the "Unaudited
Supplementary Financial Data" included elsewhere herein.
Commitments and Contingencies --
The Company's office rent expense was $819,000, $868,000, and $808,000 in
1994, 1993, and 1992, respectively. The Company has lease commitments for office
space of $822,000 in 1995, $1,039,000 in 1996 and 1997, $1,007,000 in 1998, and
$962,000 in 1999.
(2) INCOME TAXES
The components of income (loss) before income taxes for each of the three
years in the period ended December 31, 1994, are as follows (expressed in
thousands):
1994 1993 1992
------- ------- -------
United States........................................... $44,931 $43,749 $29,872
Foreign................................................. (2,040) (3,707) (1,185)
------- ------- -------
Total......................................... $42,891 $40,042 $28,687
======= ======= =======
36
38
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The components of federal income tax expense (benefit) for each of the
three years in the period ended December 31, 1994, are as follows (expressed in
thousands):
1994 1993 1992
------- ------- -------
United States, current.................................. $ 7,500 $ 2,800 $ 1,500
United States, deferred(a).............................. 8,374 12,360 8,672
Foreign, current........................................ (357) (179) 20
------- ------- -------
Total......................................... $15,517 $14,981 $10,192
======= ======= =======
- ---------------
(a) Excludes $165,000 of deferred tax benefits on a $472,000 extraordinary loss
in 1994.
Total federal income tax expense (benefit) for each of the three years in
the period ended December 31, 1994, 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):
1994 1993 1992
---- ---- ----
Federal statutory income tax rate............................ 35.0% 35.0% 34.0%
Increases (reductions) resulting from:
Statutory depletion in excess of tax basis................. (0.1) (0.4) (0.1)
Foreign taxes.............................................. 0.9 2.9 1.4
Other...................................................... 0.4 -- 0.2
---- ---- ----
36.2% 37.5% 35.5%
==== ==== ====
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, 1994 and 1993 (expressed in
thousands):
DECEMBER 31,
---------------------
1994 1993
-------- --------
Temporary differences arise primarily from the following --
Intangible drilling costs, capitalized and amortized for
financial statement purposes and deducted for income tax
purposes.................................................. $132,500 $112,135
Differences in depletion and depreciation rates used for
tangible assets for financial and income tax purposes..... (78,457) (56,136)
Charges to property and equipment, expensed for financial
statement purposes, and capitalized and amortized for
income tax purposes....................................... (35,266) (38,243)
Interest charges, capitalized and amortized for financial
statement purposes and deducted for income tax purposes... 17,710 16,800
Income tax carryforward credits.............................. -- (4,832)
-------- --------
Deferred tax liability....................................... $ 36,487 $ 29,724
======== ========
37
39
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(3) LONG-TERM DEBT
Long-term debt and the amount due within one year at December 31, 1994 and
1993, consists of the following (dollars expressed in thousands):
DECEMBER 31,
---------------------
1994 1993
-------- --------
Senior debt --
Bank revolving credit agreements debt:
Prime rate based loans, borrowings at December 31, 1993 at
an interest rate of 5.75%............................... $ -- $ 27,000
LIBO Rate based loans, borrowings at December 31, 1994 and
1993 at average interest rates of 7.63% and 5.20%,
respectively............................................ 14,000 40,000
-------- --------
Total bank revolving credit agreement debt........... 14,000 67,000
Uncommitted credit lines with banks, borrowings at December
31, 1994 at an average interest rate of 7.21%............. 7,000 --
-------- --------
Total senior debt.............................................. 21,000 67,000
-------- --------
Subordinated debt --
5 1/2% Convertible subordinated notes, due 2004.............. 86,250 --
8% Convertible subordinated debentures, due 2005, $1,282
sinking fund requirement in 1995 and a $3,000 annual
sinking fund requirement thereafter....................... 43,281 43,539
10.25% Convertible subordinated notes, due 1999, and retired
on April 18, 1994......................................... -- 24,000
-------- --------
Total subordinated debt........................................ 129,531 67,539
-------- --------
Total debt..................................................... 150,531 134,539
-------- --------
Amount due within one year --
Current portion of long-term debt, consisting of sinking fund
requirements on:
8% Debentures............................................. (1,282) --
10.25% Notes.............................................. -- (4,000)
-------- --------
Long-term debt................................................. $149,249 $130,539
======== ========
The bank revolving credit agreement entered into in December, 1993, extends
to the Company a $100,000,000 revolving/term credit facility which will be fully
revolving until June 29, 1996 and will convert to a term loan with eight
quarterly installments commencing July 31, 1996. The amount that may be borrowed
under the facility may not exceed a borrowing base, determined semiannually by
the lenders based on the discounted present value of the Company's oil and gas
reserves and the provisions of the agreement. The borrowing base currently
exceeds $100,000,000. The agreement provides that total debt and total debt for
borrowed money, as defined, may not exceed $230,000,000 and $200,000,000,
respectively. The facility is governed by various financial covenants including
the maintenance of positive working capital (excluding current maturities of
debt), a fixed charge ratio, as defined, of 1.7 or greater, a $10,000,000 limit
on other senior debt, and a $10,000,000 limit on prepayment (without
refinancing) of subordinated debt in any one year and $20,000,000 in total
through July 31, 1996. Upon the occurrence of an event of default or certain
other specified events, the banks would be entitled to a security interest in
the borrowing base properties, which constitute substantially all of the
Company's domestic oil and gas properties. Borrowings under the facility bear
interest at a Base (Prime) rate, certificate of deposit rate plus 1 5/8%, or
LIBOR plus 1 1/2%, at the Company's option. A commitment fee of 1/2 of 1% per
annum of the unborrowed amount under the facility is
38
40
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
also due. The Company incurred commitment fees of $409,000 in 1994, $149,000 in
1993, and $80,000 in 1992 under this and a prior revolving credit agreement.
The Company has entered into separate letter agreements with two banks
under which each bank may provide a $10,000,000 uncommitted line of credit. The
two $10,000,000 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
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 "5 1/2% Notes")
are convertible into Common Stock at $22.188 per share subject to adjustment
upon the occurrence of certain events. The 5 1/2% 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 5 1/2% Notes are redeemable at the option of
the holder, upon the occurrence of a repurchase event (a change in control, as
defined), at 100% of the principal amount.
The 8% convertible subordinated debentures, due 2005 (the "8% Debentures")
are convertible into Common Stock at $39.50 per share subject to adjustments
under certain circumstances, including stock splits. The 8% Debentures are
redeemable at the option of the Company at 102.4% through December 30, 1995, and
decreasing percentages thereafter, and are subject to mandatory annual sinking
fund requirements of $3,000,000 which commenced December 31, 1990. Such
requirements will be sufficient to retire all but $15,000,000 of the issue prior
to maturity. As of December 31, 1994, the Company has purchased $13,998,000
principal amount of the bonds at less than face value resulting in both ordinary
and extraordinary gains. The Company has tendered $12,000,000 principal amount
of the bonds to the trustee in satisfaction of sinking fund requirements and
$280,000 principal amount of the bonds have been called by the trustee. The
Company currently has $1,718,000 principal amount of bonds purchased in excess
of current sinking fund requirements which may be tendered in satisfaction of
future sinking fund requirements.
Current maturities and sinking fund requirements during the next five years
in connection with the above long-term debt are $1,282,000 in 1995, $9,300,000
in 1996, $13,500,000 in 1997, $7,200,000 in 1998 and $3,000,000 in 1999.
Included in the current maturities reflected above are $6,300,000 in 1996,
$10,500,000 in 1997, and $4,200,000 in 1998 relative to bank debt. The Company
has established a history of refinancing its bank debt before scheduled
maturities and expects to do so again before the amortization of bank debt
commences in 1996.
(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 percent of revenues during the
years indicated (expressed in thousands):
1994 1993 1992
------- ------- -------
Enron Corp. and its affiliate EOTT Energy Partners
L.P. ................................................. $27,630 $16,437 $ --
Coastal Gas Marketing Company (an affiliate of The
Coastal Corporation).................................. $27,609 $ 4,682 $ 3,830
Scurlock Permian Corp. (a subsidiary of Ashland Inc.)... $21,134 $38,510 $39,729
39
41
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(5) CREDIT RISK
Substantially all the Company's accounts receivable at December 31, 1994,
result from oil and gas sales and joint interest billings to other companies in
the oil and gas industry. This concentration of customers and joint interest
owners may impact the Company's overall credit risk, either positively or
negatively, in that these entities may be similarly affected by industry-wide
changes in economic or other conditions. Such receivables are generally not
collateralized. Historically, credit losses incurred by the Company on
receivables generally have not been material. No known material credit losses
were experienced during 1994.
(6) EMPLOYEE BENEFITS
A total of 3,476,430 shares of Common Stock are reserved for issuance to
key employees and non-employee directors under the Company's stock option plans.
The stock option plans authorize the granting of options at prices equivalent to
the market value at the date of grant. Options generally become exercisable in
three annual installments commencing one year after the date granted and, if not
exercised, expire 10 years from the date of grant. At January 1, 1994, 1,490,676
shares were issuable under stock options outstanding. Options for 291,000 shares
were granted during 1994 at prices ranging from $19.13 to $22.25 per share.
During 1994, 376,639 options were exercised at prices ranging from $4.38 to
$17.44 per share and options to purchase 17,500 shares at a price of $16.25 were
cancelled. At December 31, 1994, options to purchase 1,387,537 shares were
outstanding (902,455 were exercisable) at prices ranging from $4.38 to $22.25.
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
$375,000 to the savings plan in 1994, $125,000 in 1993, and $288,000 in 1992.
40
42
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A trusteed retirement plan has been adopted by the Company for its salaried
employees. The benefits are based on years of service and the employee's average
compensation for five consecutive years within the final ten years of service
which produce the highest average compensation. The Company makes annual
contributions to the plan in the amount of retirement plan cost accrued or the
maximum amount which can be deducted for federal income tax purposes. The
following table sets forth the plan's funded status (in thousands of dollars) as
of December 31, 1994, 1993, and 1992.
1994 1993 1992
------- ------- -------
Actuarial present value (discounted at 8 1/2, 7 1/2, and
8 1/4%, respectively) of benefit obligations:
Accumulated benefit obligations --
Vested............................................. $ 3,940 $ 4,019 $ 3,120
Non-vested......................................... 820 717 701
------- ------- -------
Total accumulated benefit obligations.............. 4,760 4,736 3,821
Projected salary increases (escalated at 6%) and other
changes............................................ 1,434 1,500 2,653
------- ------- -------
Projected benefit obligations for service rendered to
date............................................... 6,194 6,236 6,474
Plan assets at fair value, primarily listed securities
with an expected long-term rate of return of 8 1/2%... 13,988 13,481 13,830
------- ------- -------
Plan assets in excess of projected benefit
obligations........................................... 7,794 7,245 7,356
Unrecognized:
Net overfunding being recognized over 15 years........ (646) (750) (853)
Net gain arising from the difference between actual
experience and that assumed........................ (3,443) (3,209) (3,956)
Prior service cost.................................... (430) (473) (41)
------- ------- -------
Accrued retirement plan asset........................... $ 3,275 $ 2,813 $ 2,506
======= ======= =======
Retirement plan cost (benefit) for 1994, 1993, and 1992
included the following components:
Service cost, benefits accruing each year with
proration for future salary increases............ $ 499 $ 611 $ 514
Interest cost on projected benefit obligations..... 476 524 451
Actual return on plan assets....................... (1,139) (1,164) (1,141)
Net amortization and deferral...................... (298) (278) (360)
------- ------- -------
Accrued retirement plan cost (benefit)............. $ (462) $ (307) $ (536)
======= ======= =======
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
43
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
1992, 1993 and 1994. The computation assumes that future increases in medical
costs will trend down from 13% to 7% per year over the next 12 years for
purposes of estimating future costs. The medical cost trend rate assumption has
a significant effect on the amounts reported. Increasing the assumed medical
cost trend rate by one percent in each year would increase the aggregate of
service and interest cost components of net periodic postretirement benefit cost
for 1994 by $196,000 and the accumulated postretirement benefit obligation as of
December 31, 1994, by $897,000.
ANNUAL DEFERRED BENEFIT
EXPENSE COSTS OBLIGATION
------- -------- ----------
Transition obligation at January 1, 1992................. $4,263 $ (4,263)
Amortization of transition costs over 14 years
representing the average remaining service period of
eligible employees..................................... $ 305 (305) 305
Service cost, including interest......................... 303
Interest cost on transition obligation................... 362
-------
1992 expense............................................. $ 970 (970)
======
Current benefits paid.................................... 170
-------- ----------
Balance at December 31, 1992............................. 3,958 (4,758)
Amortization of transition costs over 14 years........... $ 305 (305) 305
Service cost, including interest......................... 368
Interest cost on transition obligation................... 407
-------
1993 expense............................................. $1,080 (1,080)
======
Current benefits paid.................................... 246
Unrecognized net loss.................................... (1,400)
-------- ----------
Balance at December 31, 1993............................. 3,653 (6,687)
Amortization of transition costs over 14 years........... $ 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
======
Plan assets at fair value................................ --
----------
Funded status at December 31, 1994 (discounted at
8 1/2%)................................................ $ (5,487)
========
The accumulated postretirement benefit obligation (in thousands of dollars)
at December 31, 1994 is attributable to the following groups:
Retirees and beneficiaries................................................. $ 2,234
Dependents of retirees..................................................... 1,014
Fully eligible active employees............................................ 833
Active employees, not fully eligible....................................... 1,406
-------
$ 5,487
=======
42
44
POGO PRODUCING COMPANY & SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(6) FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value
of each class of financial instruments for which it is practicable to estimate
that value.
Cash and Cash Investments
Fair value is carrying value as no cash equivalents or cash investments are
included in the balances as of December 31, 1994 and 1993.
Debt
INSTRUMENT BASIS OF FAIR VALUE ESTIMATE
---------- ----------------------------
Bank revolving credit agreement Fair value is carrying value as of December 31,
1994 and 1993, based on 1993 negotiations with the
lenders and the market value interest rates.
Uncommitted credit lines with banks Fair value is carrying value as of December 31,
1994 based on recent negotiations with the lenders
and the market value interest rates.
5 1/2% Notes Fair value is 94% of carrying value as of December
31, 1994 based on the quoted market price for this
publicly traded debt.
8% Debentures Fair value is 98.75% and 99.5%, of carrying value
as of December 31, 1994 and 1993, respectively,
based on the quoted market prices for this
publicly traded debt.
10.25% Notes Fair value is 103.7% of carrying value at December
31, 1993 based on the redemption premium.
The carrying value and estimated fair value of the Company's financial
instruments at December 31, 1994 and 1993 (in thousands of dollars) are as
follows:
1994 1993
-------------------- --------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
-------- -------- -------- --------
Cash and cash investments.................. $ 2,922 $ 2,922 $ 6,713 $ 6,713
Debt:
Bank revolving credit agreement.......... (14,000) (14,000) (67,000) (67,000)
Uncommitted credit lines with banks...... (7,000) (7,000) -- --
5 1/2% Notes............................. (86,250) (81,075) -- --
8% Debentures............................ (43,281) (42,740) (43,539) (43,321)
10.25% Notes............................. -- -- (24,000) (24,888)
43
45
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)
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)
======== ======== ========
1993
-----------------------------------
Oil and gas revenues................................ $136,553 $136,525 $ 28
Lease operating expense............................. (26,633) (26,633) --
Exploration expense................................. (2,455) (1,060) (1,395)
Dry hole and impairment expense..................... (4,690) (2,737) (1,953)
Depreciation, depletion and amortization expense.... (40,224) (40,193) (31)
-------- -------- ----------
Pretax operating results............................ 62,551 65,902 (3,351)
Income tax (expense) benefit........................ (22,712) (22,891) 179
-------- -------- ----------
Operating results................................... $ 39,839 $ 43,011 $ (3,172)
======== ======== ========
1992
-----------------------------------
Oil and gas revenues................................ $139,128 $139,128 $ --
Lease operating expense............................. (25,842) (25,842) --
Exploration expense................................. (3,102) (1,876) (1,226)
Dry hole and impairment expense..................... (9,314) (9,314) --
Depreciation, depletion and amortization expense.... (41,849) (41,834) (15)
-------- -------- ----------
Pretax operating results............................ 59,021 60,262 (1,241)
Income tax expense.................................. (20,510) (20,490) (20)
-------- -------- ----------
Operating results................................... $ 38,511 $ 39,772 $ (1,261)
======== ======== ========
44
46
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.
1994 1993 1992
-------- ------- -------
Capitalized costs incurred:
Property acquisition (United States)............... $ 36,354 $ 1,520 $11,578
Exploration --
United States................................... 5,803 8,267 3,865
Kingdom of Thailand............................. 5,022 4,583 1,412
Development (United States)........................ 67,143 57,648 20,717
Interest capitalized (United States)............... 739 451 391
-------- ------- -------
$115,061 $72,469 $37,963
======== ======= =======
Provision for depreciation, depletion and
amortization:
United States...................................... $ 62,690 $40,193 $41,834
Kingdom of Thailand................................ 33 31 15
-------- ------- -------
$ 62,723 $40,224 $41,849
======== ======= =======
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 3, 1995 is set forth as an exhibit to this 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.
ESTIMATES OF PROVED RESERVES
OIL,
CONDENSATE AND
NATURAL GAS
LIQUIDS NATURAL GAS
(BBLS.) (MMCF)
-------------- -----------
Proved reserves (located in the United States) as of
December 31, 1991........................................ 18,818,091 202,735
Revisions of previous estimates.......................... 1,721,385 20,284
Extensions, discoveries, and other additions (including
2,576,907 barrels and 10,668 MMcf located in the
Kingdom of Thailand).................................. 5,486,273 19,126
Purchase of properties................................... 335,750 10,237
Sales of properties...................................... (194,606) (4,733)
Estimated 1992 production................................ (3,611,105) (40,581)
-------------- -----------
Proved reserves (located in the United States except for
2,576,907 barrels and 10,668 MMcf located in the Kingdom
of Thailand) as of December 31, 1992..................... 22,555,788 207,068
Revisions of previous estimates.......................... 342,022 1,148
Extensions, discoveries, and other additions (including
2,847,906 barrels and 22,806 MMcf located in the
Kingdom of Thailand).................................. 9,764,408 55,626
Purchase of properties................................... 182,610 13,192
Sales of properties...................................... (356,514) (11,849)
Estimated 1993 production................................ (4,219,873) (32,319)
-------------- -----------
45
47
UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED)
OIL,
CONDENSATE AND
NATURAL GAS
LIQUIDS NATURAL GAS
(BBLS.) (MMCF)
-------------- -----------
Proved reserves (located in the United States except for
5,424,813 barrels and 33,474 MMcf located in the Kingdom
of Thailand) as of December 31, 1993..................... 28,268,441 232,866
Revisions of previous estimates.......................... 1,286,984 (2,558)
Extensions, discoveries, and other additions (including
2,249,559 barrels and 23,265 MMcf located in the
Kingdom of Thailand).................................. 6,565,442 49,517
Purchase of properties................................... 2,686,919 15,792
Sales of properties...................................... (497) (109)
Estimated 1994 production................................ (4,945,677) (52,618)
-------------- -----------
Proved reserves (located in the United States except for
7,674,372 barrels and 56,739 MMcf located in the Kingdom
of Thailand) as of December 31, 1994..................... 33,861,612 242,890
=========== =========
Proved developed reserves (located in the United States) as
of:
December 31, 1991........................................ 17,549,830 188,090
December 31, 1992........................................ 18,798,149 175,523
December 31, 1993........................................ 20,976,194 183,139
December 31, 1994........................................ 24,669,755 178,518
46
48
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)
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
========= ========= ========
1993
------------------------------------
Future gross revenues...................................... $ 869,783 $ 744,201 $125,582
Future production costs:
Lease operating expense.................................. (186,464) (158,934) (27,530)
Future development and abandonment costs................... (133,258) (79,735) (53,523)
--------- --------- ----------
Future net cash flows before income taxes.................. 550,061 505,532 44,529
Discount at 10% per annum.................................. (146,221) (118,858) (27,363)
--------- --------- ----------
Discounted future net cash flow before income taxes........ 403,840 386,674 17,166
Future income taxes, net of discount at 10% per annum...... (103,580) (98,788) (4,792)
--------- --------- ----------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves.................. $ 300,260 $ 287,886 $ 12,374
========= ========= ========
1992
------------------------------------
Future gross revenues...................................... $ 856,238 $ 791,865 $ 64,373
Future production costs:
Lease operating expense.................................. (179,721) (173,355) (6,366)
Future development and abandonment costs................... (105,843) (80,887) (24,956)
--------- --------- ----------
Future net cash flows before income taxes.................. 570,674 537,623 33,051
Discount at 10% per annum.................................. (165,573) (146,730) (18,843)
--------- --------- ----------
Discounted future net cash flow before income taxes........ 405,101 390,893 14,208
Future income taxes, net of discount at 10% per annum...... (97,444) (91,848) (5,596)
--------- --------- ----------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves.................. $ 307,657 $ 299,045 $ 8,612
========= ========= ========
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.
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.
47
49
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED --
(CONTINUED)
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 unless otherwise noted.
YEAR ENDED DECEMBER 31, 1994
------------------------------------
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
========= ========= ========
48
50
STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED --
(CONTINUED)
YEAR ENDED DECEMBER 31, 1993
------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
--------- --------- ----------
(EXPRESSED IN THOUSANDS)
Beginning balance.......................................... $ 307,657 $ 299,045 $ 8,612
Revisions to prior years' proved reserves:
Net changes in prices and production costs............... (41,775) (34,842) (6,933)
Net changes due to revisions in quantity estimates....... 4,066 4,066 --
Net changes in estimates of future development costs..... 662 (871) 1,533
Accretion of discount.................................... 40,510 39,089 1,421
Changes in production rate............................... 5,134 6,728 (1,594)
Other.................................................... 2,278 3,935 (1,657)
--------- --------- ----------
Total revisions.................................. 10,875 18,105 (7,230)
New field discoveries and extensions, net of future
production and development costs......................... 39,247 29,059 10,188
Purchases of properties.................................... 22,516 22,516 --
Sales of properties........................................ (19,633) (19,633) --
Sales of oil and gas produced, net of production costs..... (110,870) (110,870) --
Previously estimated development costs incurred............ 56,604 56,604 --
Net change in income taxes................................. (6,136) (6,940) 804
--------- --------- ----------
Net change in standardized measure of discounted
future net cash flows.......................... (7,397) (11,159) 3,762
--------- --------- ----------
Ending balance............................................. $ 300,260 $ 287,886 $ 12,374
========= ========= ========
YEAR ENDED DECEMBER 31, 1992
------------------------------------
TOTAL UNITED KINGDOM OF
COMPANY STATES THAILAND
--------- --------- ----------
(EXPRESSED IN THOUSANDS)
Beginning balance.......................................... $ 273,331 $ 273,331 $ --
Revisions to prior years' proved reserves:
Net changes in prices and production costs............... 38,348 38,348 --
Net changes due to revisions in quantity estimates....... 42,829 42,829 --
Net changes in estimates of future development costs..... (21,015) (21,015) --
Accretion of discount.................................... 34,975 34,975 --
Changes in production rate............................... (5,733) (5,733) --
Other.................................................... 6,607 6,607 --
--------- --------- ----------
Total revisions.................................. 96,011 96,011 --
New field discoveries and extensions, net of future
production and development costs......................... 43,760 29,552 14,208
Purchases of properties.................................... 13,870 13,870 --
Sales of properties........................................ (7,430) (7,430) --
Sales of oil and gas produced, net of production costs..... (111,581) (111,581) --
Previously estimated development costs incurred............ 20,717 20,717 --
Net change in income taxes................................. (21,021) (15,425) (5,596)
--------- --------- ----------
Net change in standardized measure of discounted
future net cash flows.......................... 34,326 25,714 8,612
--------- --------- ----------
Ending balance............................................. $ 307,657 $ 299,045 $ 8,612
========= ========= ========
49
51
QUARTERLY RESULTS -- UNAUDITED
Summaries of the Company's results of operations by quarter for the years
1994 and 1993 are as follows:
QUARTER ENDED
-----------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- ------- ------------ -----------
(EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1994
Revenues...................................... $ 37,892 $49,734 $ 46,452 $ 39,530
Gross profit(a)............................... $ 17,355 $21,782 $ 17,762 $ 11,288
Income before extraordinary loss.............. $ 7,278 $ 9,903 $ 7,433 $ 2,760
Extraordinary loss on early extinguishment of
debt........................................ -- $ (307) -- --
Net income.................................... $ 7,278 $ 9,596 $ 7,433 $ 2,760
Earnings per share:
Primary --
Income before extraordinary loss......... $ 0.22 $ 0.30 $ 0.22 $ 0.08
Extraordinary loss....................... -- $ (0.01) -- --
Net income............................... $ 0.22 $ 0.29 $ 0.22 $ 0.08
Fully diluted --
Income before extraordinary loss......... $ 0.22 $ 0.29 $ 0.22 $ 0.08
Extraordinary loss....................... -- $ (0.01) -- --
Net income............................... $ 0.22 $ 0.28 $ 0.22 $ 0.08
1993
Revenues...................................... $ 34,681 $34,533 $ 37,210 $ 33,130
Gross profit(a)............................... $ 17,331 $15,391 $ 17,903 $ 14,458
Net income.................................... $ 7,160 $ 5,596 $ 7,161 $ 5,144
Earnings per share
(primary and fully diluted)................. $ 0.22 $ 0.17 $ 0.22 $ 0.16
- ---------------
(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.
50
52
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
25, 1995, to be filed within 120 days of December 31, 1994 pursuant to
Regulation 14A under the Securities Exchange Act of 1934, as amended (the
Company's "1995 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 1995
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 1995 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 1995 Proxy Statement is incorporated herein by
reference.
51
53
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...................... 30
Consolidated statements of income............................. 31
Consolidated balance sheets................................... 32
Consolidated statements of cash flows......................... 33
Consolidated statements of shareholders' equity............... 34
Notes to consolidated financial statements.................... 35
2. Financial Statement Schedules:
All Financial Statement Schedules have been omitted because they are
not required, are not applicable or the information required has been
included elsewhere herein.
3. Exhibits:
* 3(a) -- Restated Certificate of Incorporation of Pogo Producing Company.
(Exhibit 3(a), Annual Report on Form 10-K for the year ended
December 31, 1987, File No. 0-5468).
* 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)(i) -- Credit Agreement dated as of September 23, 1992, among Pogo
Producing Company, the lenders party thereto, Bank of Montreal as
Agent, and Banque Paribas as Co-Agent. (Exhibit 10(a), Quarterly
Report on Form 10-Q for the quarter ended September 30, 1992, File
No. 1-7792).
* 4(a)(ii) -- First Amendment dated as of September 30, 1992 to Credit Agreement
dated as of September 23, 1992, among Pogo Producing Company, the
lenders party thereto, Bank of Montreal as Agent, and Banque
Paribas as Co-Agent. (Exhibit 4(a)(ii), Annual Report of Form 10-K
for the year ended December 31, 1993, File No. 1-7792).
* 4(a)(iii) -- Second Amendment dated as of December 31, 1993 to Credit Agreement
dated as of September 23, 1992, among Pogo Producing Company, the
lenders party thereto, Bank of Montreal as Agent, and Banque
Paribas as Co-Agent. (Exhibit 4(a)(iii), Annual Report of Form
10-K for the year ended December 31, 1993, File No. 1-7792).
4(a)(iv) -- Third Amendment dated as of June 1, 1994 to Credit Agreement dated
as of September 23, 1992, among Pogo Producing Company, the
lenders party thereto, Bank of Montreal as Agent, and Banque
Paribas as Co-Agent.
* 4(b) -- Indenture dated as of October 15, 1980 to Chemical Bank, as
Trustee. (Exhibit 4, File No. 2-69428).
52
54
4(c) -- Indenture dated as of March 23, 1994 to Shawmut Bank Connecticut,
National Association, as Trustee.
* 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).
Pogo Producing Company agrees to furnish to the Commission upon
request a copy of any agreement defining the rights of holders of
long-term debt of Pogo Producing Company and all its subsidiaries
for which consolidated or unconsolidated financial statements are
required to be filed under which the total amount of securities
authorized does not exceed 10% of the total assets of Pogo
Producing Company and its subsidiaries on a consolidated basis.
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (comprising Exhib-
its 10(a) through 10(f)(14)(ii), inclusive)
*10(a) -- 1977 Stock Option Plan of Pogo Producing Company, as amended as of
September 28, 1981 and July 24, 1984. (Exhibit 10(a), Annual
Report on Form 10-K for the year ended December 31, 1984, File No.
0-5468).
*10(a)(1) -- Form of Amended Nonqualified Stock Option Agreement under 1977
Stock Option Plan (with stock appreciation rights and without
employment restrictions). (Exhibit 10(a)(1), Annual Report on 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).
53
55
*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).
*10(d)(1) -- Form of Stock Option Agreement under 1989 Incentive and
Nonqualified Stock Option Plan, as amended and restated effective
January 22, 1991. (Exhibit 10(d)(1), Annual Report on Form 10-K
for the year ended December 31, 1991, File No. 0-5468).
*10(d)(2) -- Form of Director Stock Option Agreement under 1989 Incentive and
Nonqualified Stock Option Plan as amended and restated effective
January 22, 1991. (Exhibit 10(d)(2), Annual Report on Form 10-K
for the year ended December 31, 1991, File No. 0-5468).
*10(e) -- Form of Letter Agreement respecting treatment of options upon
change in control. (Exhibit 19(f), Quarterly Report on Form 10-Q
for the quarter ended June 30, 1982. File No. 0-5468).
*10(f)(1) -- Employment Agreement by and between Pogo Producing Company and
Stuart P. Burbach, dated February 1, 1992. (Exhibit 19(a)(1),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(2)(i) -- Extension Agreement to Continue Employment Agreement between
Stuart P. Burbach and Pogo Producing Company, dated as of February
1, 1993. (Exhibit 10(f)(2), Annual Report on Form 10-K for the
year ended December 31, 1992, File No. 1-7792).
*10(f)(2)(ii) -- Extension Agreement to Continue Employment Agreement between
Stuart P. Burbach and Pogo Producing Company, dated as of February
1, 1994. (Exhibit 10(f)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
54
56
10(f)(2)(iii) -- Extension Agreement to Continue Employment Agreement between
Stuart B. Burbach and Pogo Producing Company, dated as of February
1, 1995.
*10(f)(3) -- Employment Agreement by and between Pogo Producing Company and
Jerry A. Cooper, dated February 1, 1992. (Exhibit 19(a)(2),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(4)(i) -- Extension Agreement to Continue Employment Agreement between Jerry
A. Cooper and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(4), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(4)(ii) -- Extension Agreement to Continue Employment Agreement between Jerry
A. Cooper and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(4)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
10(f)(4)(iii) -- Extension Agreement to Continue Employment Agreement between Jerry
A. Cooper and Pogo Producing Company, dated as of February 1,
1995.
*10(f)(5) -- Employment Agreement by and between Pogo Producing Company and
Kenneth R. Good, dated February 1, 1992. (Exhibit 19(a)(3),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(6)(i) -- Extension Agreement to Continue Employment Agreement between Ken-
neth R. Good and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(6), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(6)(ii) -- Extension Agreement to Continue Employment Agreement between Ken-
neth R. Good and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(6)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
10(f)(6)(iii) -- Extension Agreement to Continue Employment Agreement between Ken-
neth R. Good and Pogo Producing Company, dated as of February 1,
1995.
*10(f)(7) -- Employment Agreement by and between Pogo Producing Company and R.
Phillip Laney, dated February 1, 1992. (Exhibit 19(a)(4),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(8)(i) -- Extension Agreement to Continue Employment Agreement between R.
Phillip Laney and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(8), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(8)(ii) -- Extension Agreement to Continue Employment Agreement between R.
Phillip Laney and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(8)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
10(f)(8)(iii) -- Extension Agreement to Continue Employment Agreement between R.
Phillip Laney and Pogo Producing Company, dated as of February 1,
1995.
*10(f)(9) -- Employment Agreement by and between Pogo Producing Company and
John O. McCoy, Jr., dated February 1, 1992. (Exhibit 19(a)(5),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
55
57
*10(f)(10)(i) -- Extension Agreement to Continue Employment Agreement between John
O. McCoy, Jr. and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(10), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(10)(ii) -- Extension Agreement to Continue Employment Agreement between John
O. McCoy, Jr. and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(10)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
10(f)(10)(iii) -- Extension Agreement to Continue Employment Agreement between John
O. McCoy, Jr. and Pogo Producing Company, dated as of February 1,
1995.
*10(f)(11) -- Employment Agreement by and between Pogo Producing Company and D.
Stephen Slack, dated February 1, 1992. (Exhibit 19(a)(6),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(12)(i) -- Extension Agreement to Continue Employment Agreement between D.
Stephen Slack and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(12), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(12)(ii) -- Extension Agreement to Continue Employment Agreement between D.
Stephen Slack and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(12)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
10(f)(12)(iii) -- Extension Agreement to Continue Employment Agreement between D.
Stephen Slack and Pogo Producing Company, dated as of February 1,
1995.
*10(f)(13) -- Employment Agreement by and between Pogo Producing Company and
Paul G. Van Wagenen, dated February 1, 1992. (Exhibit 19(a)(7),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(14)(i) -- Extension Agreement to Continue Employment Agreement between Paul
G. Van Wagenen and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(14), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(14)(ii) -- Extension Agreement to Continue Employment Agreement between Paul
G. Van Wagenen and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(14)(ii), Annual Report on Form 10-K for the
year ended December 31, 1992, File No. 1-7792).
10(f)(14)(iii) -- Extension Agreement to Continue Employment Agreement between Paul
G. Van Wagenen and Pogo Producing Company, dated as of February 1,
1995.
*10(g) -- Undertaking by Pogo Producing Company dated as of August 8, 1977.
(Exhibit 10(e), Annual Report on Form 10-K for the year ended
December 31, 1980, File No. 0-5468).
*10(h) -- Limited partnership agreement of Pogo Gulf Coast, Ltd. (Exhibit
19, Quarterly Report on Form 10-Q for the quarter ended June 30,
1989, File No. 0-5468).
21 -- List of Subsidiaries of Pogo Producing Company.
23(a) -- Consent of Independent Public Accountants.
56
58
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, 1994.
27 -- Financial Data Schedule.
28 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers dated February 3, 1995 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
57
59
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 7, 1995
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 7, 1995.
SIGNATURES TITLE
- ------------------------------------------ -----------------------------
/s/ PAUL G. VAN WAGENEN Principal Executive
- ------------------------------------------ Officer and Director
Paul G. Van Wagenen
Chairman of the Board, President
and Chief Executive Officer
/s/ D. STEPHEN SLACK Principal Financial
- ------------------------------------------ Officer and Director
D. Stephen Slack
Senior Vice President, Chief
Financial Officer and Treasurer
/s/ THOMAS E. HART Principal Accounting Officer
- ------------------------------------------
Thomas E. Hart
Vice President and
Controller
TOBIN ARMSTRONG* Director
- ------------------------------------------
Tobin Armstrong
JACK S. BLANTON* Director
- ------------------------------------------
Jack S. Blanton
W. M. BRUMLEY, JR.* Director
- ------------------------------------------
W. M. Brumley, Jr.
JOHN B. CARTER, JR.* Director
- ------------------------------------------
John B. Carter, Jr.
WILLIAM L. FISHER* Director
- ------------------------------------------
William L. Fisher
58
60
SIGNATURES TITLE
---------- -----
WILLIAM E. GIPSON* Director
- ------------------------------------------
William E. Gipson
GERRIT W. GONG* Director
- ------------------------------------------
Gerrit W. Gong
J. STUART HUNT* Director
- ------------------------------------------
J. Stuart Hunt
FREDERICK A. KLINGENSTEIN* Director
- ------------------------------------------
Frederick A. Klingenstein
NICHOLAS R. PETRY* Director
- ------------------------------------------
Nicholas R. Petry
JACK A. VICKERS* Director
- ------------------------------------------
Jack A. Vickers
*By: /s/ THOMAS E.HART
- ------------------------------------------
Thomas E. Hart
Attorney-in-Fact
59
61
INDEX TO EXHIBITS
EXHIBIT
NO.
* 3(a) -- Restated Certificate of Incorporation of Pogo Producing Company.
(Exhibit 3(a), Annual Report on Form 10-K for the year ended
December 31, 1987, File No. 0-5468).
* 3(a)(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)(i) -- Credit Agreement dated as of September 23, 1992, among Pogo
Producing Company, the lenders party thereto, Bank of Montreal as
Agent, and Banque Paribas as Co-Agent. (Exhibit 10(a), Quarterly
Report on Form 10-Q for the quarter ended September 30, 1992, File
No. 1-7792).
* 4(a)(ii) -- First Amendment dated as of September 30, 1992 to Credit Agreement
dated as of September 23, 1992, among Pogo Producing Company, the
lenders party thereto, Bank of Montreal as Agent, and Banque
Paribas as Co-Agent. (Exhibit 4(a)(ii), Annual Report of Form 10-K
for the year ended December 31, 1993, File No. 1-7792).
* 4(a)(iii) -- Second Amendment dated as of December 31, 1993 to Credit Agreement
dated as of September 23, 1992, among Pogo Producing Company, the
lenders party thereto, Bank of Montreal as Agent, and Banque
Paribas as Co-Agent. (Exhibit 4(a)(iii), Annual Report of Form
10-K for the year ended December 31, 1993, File No. 1-7792).
4(a)(iv) -- Third Amendment dated as of June 1, 1994 to Credit Agreement dated
as of September 23, 1992, among Pogo Producing Company, the
lenders party thereto, Bank of Montreal as Agent, and Banque
Paribas as Co-Agent.
* 4(b) -- Indenture dated as of October 15, 1980 to Chemical Bank, as
Trustee. (Exhibit 4, File No. 2-69428).
62
4(c) -- Indenture dated as of March 23, 1994 to Shawmut Bank Connecticut,
National Association, as Trustee.
* 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).
Pogo Producing Company agrees to furnish to the Commission upon
request a copy of any agreement defining the rights of holders of
long-term debt of Pogo Producing Company and all its subsidiaries
for which consolidated or unconsolidated financial statements are
required to be filed under which the total amount of securities
authorized does not exceed 10% of the total assets of Pogo
Producing Company and its subsidiaries on a consolidated basis.
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS (comprising Exhib-
its 10(a) through 10(f)(14)(ii), inclusive)
*10(a) -- 1977 Stock Option Plan of Pogo Producing Company, as amended as of
September 28, 1981 and July 24, 1984. (Exhibit 10(a), Annual
Report on Form 10-K for the year ended December 31, 1984, File No.
0-5468).
*10(a)(1) -- Form of Amended Nonqualified Stock Option Agreement under 1977
Stock Option Plan (with stock appreciation rights and without
employment restrictions). (Exhibit 10(a)(1), Annual Report on 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).
63
*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).
*10(d)(1) -- Form of Stock Option Agreement under 1989 Incentive and
Nonqualified Stock Option Plan, as amended and restated effective
January 22, 1991. (Exhibit 10(d)(1), Annual Report on Form 10-K
for the year ended December 31, 1991, File No. 0-5468).
*10(d)(2) -- Form of Director Stock Option Agreement under 1989 Incentive and
Nonqualified Stock Option Plan as amended and restated effective
January 22, 1991. (Exhibit 10(d)(2), Annual Report on Form 10-K
for the year ended December 31, 1991, File No. 0-5468).
*10(e) -- Form of Letter Agreement respecting treatment of options upon
change in control. (Exhibit 19(f), Quarterly Report on Form 10-Q
for the quarter ended June 30, 1982. File No. 0-5468).
*10(f)(1) -- Employment Agreement by and between Pogo Producing Company and
Stuart P. Burbach, dated February 1, 1992. (Exhibit 19(a)(1),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(2)(i) -- Extension Agreement to Continue Employment Agreement between
Stuart P. Burbach and Pogo Producing Company, dated as of February
1, 1993. (Exhibit 10(f)(2), Annual Report on Form 10-K for the
year ended December 31, 1992, File No. 1-7792).
*10(f)(2)(ii) -- Extension Agreement to Continue Employment Agreement between
Stuart P. Burbach and Pogo Producing Company, dated as of February
1, 1994. (Exhibit 10(f)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
64
10(f)(2)(iii) -- Extension Agreement to Continue Employment Agreement between
Stuart B. Burbach and Pogo Producing Company, dated as of February
1, 1995.
*10(f)(3) -- Employment Agreement by and between Pogo Producing Company and
Jerry A. Cooper, dated February 1, 1992. (Exhibit 19(a)(2),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(4)(i) -- Extension Agreement to Continue Employment Agreement between Jerry
A. Cooper and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(4), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(4)(ii) -- Extension Agreement to Continue Employment Agreement between Jerry
A. Cooper and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(4)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
10(f)(4)(iii) -- Extension Agreement to Continue Employment Agreement between Jerry
A. Cooper and Pogo Producing Company, dated as of February 1,
1995.
*10(f)(5) -- Employment Agreement by and between Pogo Producing Company and
Kenneth R. Good, dated February 1, 1992. (Exhibit 19(a)(3),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(6)(i) -- Extension Agreement to Continue Employment Agreement between Ken-
neth R. Good and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(6), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(6)(ii) -- Extension Agreement to Continue Employment Agreement between Ken-
neth R. Good and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(6)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
10(f)(6)(iii) -- Extension Agreement to Continue Employment Agreement between Ken-
neth R. Good and Pogo Producing Company, dated as of February 1,
1995.
*10(f)(7) -- Employment Agreement by and between Pogo Producing Company and R.
Phillip Laney, dated February 1, 1992. (Exhibit 19(a)(4),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(8)(i) -- Extension Agreement to Continue Employment Agreement between R.
Phillip Laney and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(8), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(8)(ii) -- Extension Agreement to Continue Employment Agreement between R.
Phillip Laney and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(8)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
10(f)(8)(iii) -- Extension Agreement to Continue Employment Agreement between R.
Phillip Laney and Pogo Producing Company, dated as of February 1,
1995.
*10(f)(9) -- Employment Agreement by and between Pogo Producing Company and
John O. McCoy, Jr., dated February 1, 1992. (Exhibit 19(a)(5),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
65
*10(f)(10)(i) -- Extension Agreement to Continue Employment Agreement between John
O. McCoy, Jr. and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(10), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(10)(ii) -- Extension Agreement to Continue Employment Agreement between John
O. McCoy, Jr. and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(10)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
10(f)(10)(iii) -- Extension Agreement to Continue Employment Agreement between John
O. McCoy, Jr. and Pogo Producing Company, dated as of February 1,
1995.
*10(f)(11) -- Employment Agreement by and between Pogo Producing Company and D.
Stephen Slack, dated February 1, 1992. (Exhibit 19(a)(6),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(12)(i) -- Extension Agreement to Continue Employment Agreement between D.
Stephen Slack and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(12), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(12)(ii) -- Extension Agreement to Continue Employment Agreement between D.
Stephen Slack and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(12)(ii), Annual Report on Form 10-K for the
year ended December 31, 1993, File No. 1-7792).
10(f)(12)(iii) -- Extension Agreement to Continue Employment Agreement between D.
Stephen Slack and Pogo Producing Company, dated as of February 1,
1995.
*10(f)(13) -- Employment Agreement by and between Pogo Producing Company and
Paul G. Van Wagenen, dated February 1, 1992. (Exhibit 19(a)(7),
Quarterly Report on Form 10-Q for the quarter ended June 30, 1992,
File No. 1-7792).
*10(f)(14)(i) -- Extension Agreement to Continue Employment Agreement between Paul
G. Van Wagenen and Pogo Producing Company, dated as of February 1,
1993. (Exhibit 10(f)(14), Annual Report on Form 10-K for the year
ended December 31, 1992, File No. 1-7792).
*10(f)(14)(ii) -- Extension Agreement to Continue Employment Agreement between Paul
G. Van Wagenen and Pogo Producing Company, dated as of February 1,
1994. (Exhibit 10(f)(14)(ii), Annual Report on Form 10-K for the
year ended December 31, 1992, File No. 1-7792).
10(f)(14)(iii) -- Extension Agreement to Continue Employment Agreement between Paul
G. Van Wagenen and Pogo Producing Company, dated as of February 1,
1995.
*10(g) -- Undertaking by Pogo Producing Company dated as of August 8, 1977.
(Exhibit 10(e), Annual Report on Form 10-K for the year ended
December 31, 1980, File No. 0-5468).
*10(h) -- Limited partnership agreement of Pogo Gulf Coast, Ltd. (Exhibit
19, Quarterly Report on Form 10-Q for the quarter ended June 30,
1989, File No. 0-5468).
21 -- List of Subsidiaries of Pogo Producing Company.
23(a) -- Consent of Independent Public Accountants.
66
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, 1994.
27 -- Financial Data Schedule.
28 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers dated February 3, 1995 relating to oil and gas reserves
of Pogo Producing Company.
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* Asterisk indicates exhibits incorporated by reference as shown.